ML101900267: Difference between revisions

From kanterella
Jump to navigation Jump to search
(Created page by program invented by StriderTol)
(StriderTol Bot change)
 
(5 intermediate revisions by the same user not shown)
Line 2: Line 2:
| number = ML101900267
| number = ML101900267
| issue date = 06/29/2010
| issue date = 06/29/2010
| title = McGuire, Units 1 & 2 and Catawba, Units 1 & 2 - License Amendment Request to Revise Reactor Trip System and Engineered Safety Feature Actuation System Technical Specifications
| title = License Amendment Request to Revise Reactor Trip System and Engineered Safety Feature Actuation System Technical Specifications
| author name = Repko R T
| author name = Repko R
| author affiliation = Duke Energy Carolinas, LLC
| author affiliation = Duke Energy Carolinas, LLC
| addressee name =  
| addressee name =  
Line 12: Line 12:
| document type = Letter, License-Application for Facility Operating License (Amend/Renewal) DKT 50, Technical Specification, Amendment
| document type = Letter, License-Application for Facility Operating License (Amend/Renewal) DKT 50, Technical Specification, Amendment
| page count = 98
| page count = 98
| project =
| stage = Request
}}
}}


=Text=
=Text=
{{#Wiki_filter:REGIS T. REPKO Vice President r4tEnergy, McGuire Nuclear Station Duke Energy MG01VP / 12700 Hagers Ferry Rd.Huntersville, NC 28078 980-875-4111 980-875-4809 fax regis. repko@duke-energy.
{{#Wiki_filter:REGIS T. REPKO Vice President r4tEnergy,                                                                       McGuire Nuclear Station Duke Energy MG01VP / 12700 Hagers Ferry Rd.
com June 29, 2010 10 CFR 50.90 U.S. Nuclear Regulatory Commission Washington, D.C. 20555-0001 ATTENTION:
Huntersville, NC 28078 980-875-4111 980-875-4809 fax regis.repko@duke-energy.com June 29, 2010                                                                     10 CFR 50.90 U.S. Nuclear Regulatory Commission Washington, D.C. 20555-0001 ATTENTION: Document Control Desk Duke Energy Carolinas, LLC (Duke Energy)
Document Control Desk Duke Energy Carolinas, LLC (Duke Energy)McGuire Nuclear Station, Units 1 and'2 Docket Nos. 50-369 and 50-370 Catawba Nuclear Station, Units 1 and 2 Docket Nos. 50-413 and 50-414  
McGuire Nuclear Station, Units 1 and'2 Docket Nos. 50-369 and 50-370 Catawba Nuclear Station, Units 1 and 2 Docket Nos. 50-413 and 50-414


==SUBJECT:==
==SUBJECT:==
License Amendment Request to Revise Reactor Trip System and Engineered Safety Feature Actuation System Technical Specifications Pursuant to 10 CFR 50.90, enclosed is a Duke Energy License Amendment Request (LAR) for the McGuire Nuclear Station Renewed Facility Operating Licenses and Technical Specifications (TS) and the Catawba Nuclear Station Renewed Facility Operating Licenses and TS. The proposed LAR revises the Reactor Trip System (RTS) Instrumentation TS 3.3.1 and the Engineered Safety Feature Actuation System (ESFAS) Instrumentation TS 3.3.2 for both the McGuire and Catawba Nuclear Stations; to reflect the results of updated setpoint calculations.
License Amendment Request to Revise Reactor Trip System and Engineered Safety Feature Actuation System Technical Specifications Pursuant to 10 CFR 50.90, enclosed is a Duke Energy License Amendment Request (LAR) for the McGuire Nuclear Station Renewed Facility Operating Licenses and Technical Specifications (TS) and the Catawba Nuclear Station Renewed Facility Operating Licenses and TS. The proposed LAR revises the Reactor Trip System (RTS) Instrumentation TS 3.3.1 and the Engineered Safety Feature Actuation System (ESFAS) Instrumentation TS 3.3.2 for both the McGuire and Catawba Nuclear Stations; to reflect the results of updated setpoint calculations.
The proposed LAR affects TS Table 3.3.1-1, "Reactor Trip System Instrumentation" and TS Table 3.3.2-1, "Engineered Safety Feature Actuation System Instrumentation." Applicable aspects of Technical Specification Task Force Traveler TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions," are incorporated in the scope of the proposed changes.Implementation of the proposed license amendment will impact the Updated Final Safety Analysis Report (UFSAR) for both stations.
The proposed LAR affects TS Table 3.3.1-1, "Reactor Trip System Instrumentation" and TS Table 3.3.2-1, "Engineered Safety Feature Actuation System Instrumentation." Applicable aspects of Technical Specification Task Force Traveler TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions," are incorporated in the scope of the proposed changes.
The necessary UFSAR revisions will be submitted in accordance with 10 CFR 50.71 (e).Duke Energy requests approval of this LAR within one calendar-year of tlhe submittal date.Amendment implementation will be accomplished within 60 days of NRC approval.L)www, duke-energy.
Implementation of the proposed license amendment will impact the Updated Final Safety Analysis Report (UFSAR) for both stations. The necessary UFSAR revisions will be submitted in accordance with 10 CFR 50.71 (e).
com U.S. Nuclear Regulatory Commission June 29, 2010 Page 2 Enclosure 1 provides a description of the proposed change and the technical justification, an evaluation of significant hazards consideration pursuant to 10 CFR 50.92(c), and the following attachments:
Duke Energy requests approval of this LAR within one calendar-year of tlhe submittal date.
Attachments 1 a and lb provide the existing TS pages marked-up to show the proposed changes for the McGuire and Catawba Nuclear Stations, respectively.
Amendment implementation will be accomplished within 60 days of NRC approval.
Retyped (clean) TS pages will be provided to the NRC immediately prior to issuance of the approved amendment.
L) www, duke-energy.com
Attachments 2a and 2b provide the existing Bases pages marked-up to show the proposed changes for the McGuire and Catawba Nuclear Stations, respectively.
 
These pages are provided for information only.This submittal contains no additional regulatory commitments.
U.S. Nuclear Regulatory Commission June 29, 2010 Page 2 Enclosure 1 provides a description of the proposed change and the technical justification, an evaluation of significant hazards consideration pursuant to 10 CFR 50.92(c), and the following attachments:
Attachments 1a and lb provide the existing TS pages marked-up to show the proposed changes for the McGuire and Catawba Nuclear Stations, respectively. Retyped (clean) TS pages will be provided to the NRC immediately prior to issuance of the approved amendment.
Attachments 2a and 2b provide the existing Bases pages marked-up to show the proposed changes for the McGuire and Catawba Nuclear Stations, respectively. These pages are provided for information only.
This submittal contains no additional regulatory commitments.
In accordance with Duke Energy's administrative procedures and Quality Assurance Program, this LAR has been reviewed and approved by the McGuire and Catawba Plant Operations Review Committees.
In accordance with Duke Energy's administrative procedures and Quality Assurance Program, this LAR has been reviewed and approved by the McGuire and Catawba Plant Operations Review Committees.
Pursuant to 10 CFR 50.91, a copy of this LAR is being sent to the designated officials of the States of North Carolina and South Carolina.-If there are any questions or if additional information is needed, please contact Mr. M. K. Leisure at (980) 875-5171.Sincerely, Regis T. Repko Enclosure U.S. Nuclear Regulatory Commission June 29, 2010 Page 3 xc with enclosure':
Pursuant to 10 CFR 50.91, a copy of this LAR is being sent to the designated officials of the States of North Carolina and South Carolina.
L. A. Reyes Regional Administrator, Region II U.S. Nuclear Regulatory Commission Marquis One Tower 245 Peachtree Center Ave., NE Suite 1200 Atlanta, GA 30303-1257 J. B. Brady NRC Senior Resident Inspector McGuire Nuclear Station G. A. Hutto III NRC Senior Resident Inspector Catawba Nuclear Station J. H. Thompson (addressee only)NRC Project Manager U.S. Nuclear Regulatory Commission Mail Stop 0-8 G9A 11555 Rockville Pike Rockville, MD 20852-2738 W. L. Cox Il1, Section Chief Division of Environmental Health Radiation Protection Section 1645 Mail Service Center Raleigh, NC 27699-1645 S. E. Jenkins, Manager Radioactive and Infectious Waste Management Division of Waste Management South Carolina Department of Health and Environmental Control 2600 Bull St.Columbia, SC 29201 U.S. Nuclear Regulatory Commission June 29, 2010 Page 4-Regis T. Repko affirms that he is the person who subscribed his name to the foregoing statement, and that all the matters and facts set forth herein are true and correct to the best of his knowledge.
-Ifthere are any questions or if additional information is needed, please contact Mr. M. K. Leisure at (980) 875-5171.
Regis ,Vi uire Nuclear Station Subscribed and sworn to me: Date 7~Notary Public es: ( -] ,. //' 40 1%Date My commission expir U.S. Nuclear Regulatory Commission June 29, 2010 ENCLOSURE 1 Evaluation of the Proposed Change  
Sincerely, Regis T. Repko Enclosure
 
U.S. Nuclear Regulatory Commission June 29, 2010 Page 3 xc with enclosure':
L. A. Reyes Regional Administrator, Region II U.S. Nuclear Regulatory Commission Marquis One Tower 245 Peachtree Center Ave., NE Suite 1200 Atlanta, GA 30303-1257 J. B. Brady NRC Senior Resident Inspector McGuire Nuclear Station G. A. Hutto III NRC Senior Resident Inspector Catawba Nuclear Station J. H. Thompson (addressee only)
NRC Project Manager U.S. Nuclear Regulatory Commission Mail Stop 0-8 G9A 11555 Rockville Pike Rockville, MD 20852-2738 W. L. Cox Il1,Section Chief Division of Environmental Health Radiation Protection Section 1645 Mail Service Center Raleigh, NC 27699-1645 S. E. Jenkins, Manager Radioactive and Infectious Waste Management Division of Waste Management South Carolina Department of Health and Environmental Control 2600 Bull St.
Columbia, SC 29201
 
U.S. Nuclear Regulatory Commission June 29, 2010 Page 4
-Regis T. Repko affirms that he is the person who subscribed his name to the foregoing statement, and that all the matters and facts set forth herein are true and correct to the best of his knowledge.
Regis         ,Vi                   uire Nuclear Station Subscribed and sworn to me:
Date 7
                            *            ~Notary Public My commission expir es:     (   -]     ,.
                                          //'     40 1%
Date t*
 
U.S. Nuclear Regulatory Commission June 29, 2010 ENCLOSURE 1 Evaluation of the Proposed Change


==Subject:==
==Subject:==
License Amendment Request to Revise Technical Specification 3.3.1, "Reactor Trip System (RTS) Instrumentation" and Technical Specification 3.3.2, "Engineered Safety Feature Actuation System (ESFAS) Instrumentation" 1. DESCRIPTION
License Amendment Request to Revise Technical Specification 3.3.1, "Reactor Trip System (RTS) Instrumentation" and Technical Specification 3.3.2, "Engineered Safety Feature Actuation System (ESFAS) Instrumentation"
: 2. PROPOSED CHANGE 3. BACKGROUND
: 1.         DESCRIPTION
: 4. TECHNICAL ANALYSIS 5. REGULATORY ANALYSIS 5.1 No Significant Hazards Consideration
: 2.         PROPOSED CHANGE
: 3.         BACKGROUND
: 4.         TECHNICAL ANALYSIS
: 5.         REGULATORY ANALYSIS 5.1   No Significant Hazards Consideration 5.2  Applicable Regulatory Requirements/Criteria 5.3  Precedents
: 6.        ENVIRONMENTAL CONSIDERATION
: 7.        REFERENCES ATTACHMENTS:
la.        McGuire  Units 1 and 2 Technical Specification Page Markups lb.        Catawba  Units 1 and 2 Technical Specification Page Markups 2a.        McGuire  Units 1 and 2 Bases Page Markups (Information Only) 2b.        Catawba  Units 1 and 2 Bases Page Markups (Information Only)
 
U.S. Nuclear Regulatory Commission                                                      Enclosure 1 June 29, 2010                                                                          Page 2 of 32
: 1. DESCRIPTION This evaluation supports a request to amend Renewed Facility Operating Licenses NPF-9 and NPF-17 for McGuire Nuclear Station Units 1 and 2, respectively, and Renewed Facility Operating Licenses NPF-35 and NPF-52 for Catawba Nuclear Station Units 1 and 2, respectively.
The proposed changes would revise McGuire and Catawba Technical Specification (TS) 3.3.1, "Reactor Trip System Instrumentation," and TS 3.3.2, "Engineered Safety Feature Actuation System Instrumentation," to reflect the results of updated setpoint calculations.
: 2. PROPOSED CHANGE Specifically, the proposed changes would revise the McGuire Nuclear Station Units 1 and 2 and Catawba Nuclear Station Units 1 and 2 Technical Specification Tables 3.3.1-1 and 3.3.2-1 as follows:
McGuire Nuclear Station ALLOWABLE VALUE McGuire TS Table 3.3.1-1 FUNCTION                      Current
                                                                .. Current'      LProposE Proposed 8.a    Pressurizer Pressure - Low                        > 1935 psig          ->1939 psig 8.b    Pressurizer Pressure - High                        < 2395 psig          _<2390 psig' 9      Pressurizer Water Level - High                          <-93%              _<92.7%
10.a    Reactor Coolant Flow - Low - Single Loop              > 87%              - 87.6%
10.b    Reactor Coolant Flow - Low - Two Loops                  _>
87%              _ 87.6%
12    Underfrequency RCPs                                  > 55.9 Hz          >  56.3 Hz 13    Steam Generator (SG) Water Level - Low                  >15%                  16%
Low 16.a    Reactor Trip System Interlocks- Intermediate      > 4E-1 1 amp      > 4.8E-1 1 amp Range Neutron Flux, P-6 16.e    Reactor Trip System Interlocks - Turbine                5 11%
* 10.7%
Impulse Pressure, P-13
 
U.S. Nuclear Regulatory Commission                                                          Enclosure 1 June 29, 2010                                                                              Page 3 of 32 McGuire TS Table 3.3.2-1 FUNCTION                              ALLOWABLE VALUE Current        ,Proposed 1 .d    Safety Injection - Pressurizer Pressure - Low          >  1835 psig        1840 psig Low 4.d(1)    Steam Line Isolation - Steam Line Pressure -            > 755 psig        >  766 psig Low                                                      -
4.d(2)    Steam Line Isolation - Steam Line Pressure -              < 120 psi          < 110 psi Negative Rate - High                                      -
5.a(2)    Turbine Trip and Feedwater Isolation -
Turbine Trip - SG Water Level - High High                  < 85.6%            < 84.7%
(P-14) 5.b(2)    Turbine Trip and Feedwater Isolation -
Feedwater Isolation - SG Water Level - High                5 85.6%            < 84.7%
High (P-14) 5.b(4)    Turbine Trip and Feedwater Isolation -                    >  551 OF          551.84 OF Feedwater Isolation - Tavg - Low 6.b    Auxiliary Feedwater- SG Water Level - Low                    > 15%            > 16%
Low 8.b    ESFAS Interlocks - Pressurizer Pressure,                <1965 psig        <1960 psig P-1 1 8.c    ESFAS Interlocks - Tavg - Low Low, P-1 2                  >_551 OF        >551.84 OF In addition, two new lettered footnotes, designated () and (k), would be added to Table 3.3.1-1, and two new lettered footnotes, designated (f) and (g), would be added to Table 3.3.2-1. The new Table 3.3.1-1 footnotes would apply to the cross-referenced CHANNEL OPERATIONAL TEST (COT) and CHANNEL CALIBRATION requirements listed in the "SURVEILLANCE REQUIREMENTS (SR)" column of the Table for Functions 8.a, 8.b, 9, 10.a, 1.b, 12, and 13, specifically the SR 3.3.1.7 and 3.3.1.10 entries. The new footnotes would read as follows:
(j)  If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.
(k)  The instrument channel setpoint shall be reset to a value that is within the as-left.
tolerance around the Nominal Trip Setpoint (NTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the NTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (field setting) to confirm channel performance. The methodologies used to determine the as-found and the as-left tolerances are specified in the UFSAR.
The new Table 3.3.2-1 footnotes would apply to the cross-referenced CHANNEL OPERATIONAL TEST (COT) and CHANNEL CALIBRATION requirements listed in the "SURVEILLANCE REQUIREMENTS" column of the Table for Functions 1.d, 4.d(1), 4.d(2),
5.a(2), 5.b(2), 5.b(4), and 6.b, specifically the SR 3.3.2.5 and 3.3.2.8 entries. The new footnotes, (f) and (g) are identical to the proposed new Table 3.3.1-1 footnotes (j) and (k),
respectively.


===5.2 Applicable===
U.S. Nuclear Regulatory Commission                                                    Enclosure 1 June 29, 2010                                                                        Page 4 of 32 These new footnotes are consistent with Technical Specification Task Force Traveler TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions," Revision 4.
In addition to the above-mentioned footnotes, a footnote would be added to Table 3.3.1-1 for the Allowable Value entry for Function 16.a, "Reactor Trip System Interlocks - Intermediate Range Neutron Flux, P-6." This footnote would read as follows:
A    The > 4E-1 1 amp Allowable Value, which applies to the Westinghouse-supplied compensated ion chamber Intermediate Range neutron detectors, is non-conservative. The compensated ion chamber neutron detectors are being replaced with Thermo Scientific-supplied fission chamber neutron detectors. Until the replacement occurs, an Allowable Value of > 4.8E-1 1 amp applies.
This footnote will provide proper coordination with the Duke Energy license amendment application dated July 1, 2009, which was submitted to support plant modifications to the Nuclear Instrumentation System. This license amendment application included a proposed revision to the Allowable Value for the P-6 function.
Catawba Nuclear Station atawba ITSTable,3.3.1.1 FUNCTION                        ALLOWABLE VALUE.
CaTTl31Current                                                  Proposed 2.a    Power Range Neutron Flux - High                  _ 110.9% RTP      _ 110.3% RTP 2.b    Power Range Neutron Flux - Low
* 27.1% RTP          26.3% RTP 6      Overtemperature AT                                  < 4.3%  RTP (Unit 1)      <3.97% RTP
                                                                < 4.5%  RTP      (Units 1&2)
(Unit 2) 8.a    Pressurizer Pressure - Low                          >1938    psig    >1939
                                                                >_ 198pi                99psig 8.b    Pressurizer Pressure - High                        < 2399 psig      < 2390 psig 9      Pressurizer Water Level - High                        < 93.8%          < 92.7%
10.a    Reactor Coolant Flow - Low - Single Loop              > 89.7%          > 90.5%
10.b    Reactor Coolant Flow - Low - Two Loops                > 89.7%            > 90.5%
12      Underfrequency RCPs                                  > 55.9 Hz          >  56.2 Hz 13    Steam Generator (SG) Water Level - Low                  > 9%              > 10%
Low                                                    (Unit 1)          (Unit 1)
                                                                  > 35.1%          > 36.1%
(Unit 2)          (Unit 2) 16.a    Reactor Trip System Interlocks - Intermediate      > 6E-1 1 amp      6.9E-1 1 amp Range Neutron Flux, P-6 16.f    Reactor Trip System Interlocks -Turbine            5 12.2% RTP      <5 10.7% RTP Impulse Pressure, P-13


Regulatory Requirements/Criteria
U.S. Nuclear Regulatory Commission                                                          Enclosure 1 June 29, 2010                                                                              Page 5 of 32 ALLOWABLE VALUE Catawba TS Table 3.3.2-1 FUNCTION                            Current        Proposed 1 .c    Safety Injection - Containment Pressure - High            < 1.4 psig        < 1.3 psig 1 .d    Safety Injection - Pressurizer Pressure - Low                1839 psig        1840 psig 3.b(3)    Containment Isolation - Phase B Isolation -              <3.2 psig            3.1 psig Containment Pressure - High High 4.c    Steam Line Isolation- Containment Pressure -              <3.2 psig            3.1 psig High High 4.d(1)    Steam Line Isolation - Steam Line Pressure -              > 744 psig        >  766 psig Low                                                        -
4.d(2)    Steam Line Isolation - Steam Line Pressure -            < 122.8 psi        <110.1 psi Negative Rate - High                                      -
5.a(2)    Turbine Trip and Feedwater Isolation -                      < 85.6%            < 84.6%
Turbine Trip - SG Water Level - High-High                    (Unit 1)          (Unit 1)
(P-14)                                                      < 78.9%            < 77.8%
(Unit 2),          (Unit 2) 5.b(2)    Turbine Trip and Feedwater Isolation -                      < 85.6%            < 84.6%
Feedwater Isolation - SG Water Level - High                  (Unit 1)          (Unit 1)
High (P-14)                                                < 78.9%            < 77.8%
(Unit 2)          (Unit 2) 5.b(4)    Turbine Trip and Feedwater Isolation -                      > 561 OF          562.88 OF Feedwater Isolation - Tavg - Low 6.b    Auxiliary Feedwater - SG Water Level - Low                    > 9%              > 10%
Low                                                        (Unit 1)          (Unit 1)
                                                                        >35.1%            >36.1%
(Unit 2)          (Unit 2) 8.b      ESFAS Interlocks - Pressurizer Pressure,                > 1944 psig        > 1946 psig P-11                                                          and              and
                                                                    <1966 psig        <1960 psig 8.c      ESFAS Interlocks - Tavg - Low Low, P-12                      >550 OF          551.88 OF In addition, two new lettered footnotes, designated (I) and (m), would be added to Table 3.3.1-1, and two new lettered footnotes, designated (f) and (g), would be added to Table 3.3.2-1. The new Table 3.3.1-1 footnotes would apply to the cross-referenced CHANNEL OPERATIONAL TEST and CHANNEL CALIBRATION requirements listed in the "SURVEILLANCE REQUIREMENTS" column of the Table for Functions 2.a, 2.b, 6, 8.a, 8.b, 9, 10.a, 10.b, 12, and 13, specifically the SR 3.3.1.7, 3.3.1.8, 3.3.1.10, and 3.3.1.11 entries. The new footnotes would read as follows:
(I)  If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.
(m)  The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Nominal Trip Setpoint (NTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the NTSP are acceptable provided that the as-found and as-left


===5.3 Precedents===
U.S. Nuclear Regulatory Commission                                                       Enclosure 1 June 29, 2010                                                                           Page 6 of 32 tolerances apply to the actual setpoint implemented in the Surveillance procedures (field setting) to confirm channel performance. The methodologies used to determine the as-found and the as-left tolerances are specified in the UFSAR.
: 6. ENVIRONMENTAL CONSIDERATION
The new Table 3.3.2-1 footnotes would apply to the cross-referenced CHANNEL OPERATIONAL TEST (COT) and CHANNEL CALIBRATION requirements listed in the "SURVEILLANCE REQUIREMENTS" column of the Table for Functions 1 .c, 1 .d, 3.b(3), 4.c, 4.d(1), 4.d(2), 5.a(2), 5.b(2), 5.b(4), and 6.b, specifically the SR 3.3.2.5 and 3.3.2.9 entries. The new footnotes, (f) and (g) are identical to the proposed new Table 3.3. 1-1 footnotes (I) and (m),
: 7. REFERENCES ATTACHMENTS:
respectively.
la. McGuire Units 1 and 2 Technical Specification Page Markups lb. Catawba Units 1 and 2 Technical Specification Page Markups 2a. McGuire Units 1 and 2 Bases Page Markups (Information Only)2b. Catawba Units 1 and 2 Bases Page Markups (Information Only)
These new footnotes are consistent with Technical Specification Task Force Traveler TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions," Revision 4.
U.S. Nuclear Regulatory Commission June 29, 2010 Enclosure 1 Page 2 of 32 1. DESCRIPTION This evaluation supports a request to amend Renewed Facility Operating Licenses NPF-9 and NPF-17 for McGuire Nuclear Station Units 1 and 2, respectively, and Renewed Facility Operating Licenses NPF-35 and NPF-52 for Catawba Nuclear Station Units 1 and 2, respectively.
In addition to the above-mentioned footnotes, an additional footnote would be added to Table 3.3.1-1 for the Allowable Value entry for Function 16.a, "Reactor Trip System Interlocks -
The proposed changes would revise McGuire and Catawba Technical Specification (TS) 3.3.1,"Reactor Trip System Instrumentation," and TS 3.3.2, "Engineered Safety Feature Actuation System Instrumentation," to reflect the results of updated setpoint calculations.
Intermediate Range Neutron Flux, P-6." This footnote would read as follows:
: 2. PROPOSED CHANGE Specifically, the proposed changes would revise the McGuire Nuclear Station Units 1 and 2 and Catawba Nuclear Station Units 1 and 2 Technical Specification Tables 3.3.1-1 and 3.3.2-1 as follows: McGuire Nuclear Station ALLOWABLE VALUE McGuire TS Table 3.3.1-1 FUNCTION Current LProposE..Current' Proposed 8.a Pressurizer Pressure -Low > 1935 psig -> 1939 psig 8.b Pressurizer Pressure -High < 2395 psig _< 2390 psig'9 Pressurizer Water Level -High <- 93% _< 92.7%1 0.a Reactor Coolant Flow -Low -Single Loop > 87% -87.6%10.b Reactor Coolant Flow -Low -Two Loops _> 87% _ 87.6%12 Underfrequency RCPs > 55.9 Hz > 56.3 Hz 13 Steam Generator (SG) Water Level -Low > 15% 16%Low 16.a Reactor Trip System Interlocks-Intermediate
A     The > 6E-1 1 amp Allowable Value, which applies to the Westinghouse-supplied compensated ion chamber Intermediate Range neutron detectors, is non-conservative. The compensated ion chamber neutron detectors are being replaced with Thermo Scientific-supplied fission chamber neutron detectors. Until the replacement occurs, an Allowable Value of > 6.9E-1 1 amp applies.
> 4E-1 1 amp > 4.8E-1 1 amp Range Neutron Flux, P-6 16.e Reactor Trip System Interlocks
This footnote will provide proper coordination with the Duke Energy license amendment application dated July 1, 2009, which was submitted to support plant modifications to the Nuclear Instrumentation System. This license amendment application included a proposed revision to the Allowable Value for the P-6 interlock function.
-Turbine 5 11%  10.7%Impulse Pressure, P-13 U.S. Nuclear Regulatory Commission June 29, 2010 Enclosure 1 Page 3 of 32 McGuire TS Table 3.3.2-1 FUNCTION ALLOWABLE VALUE Current ,Proposed 1 .d Safety Injection
Further Discussion Attachments 1a and lb provide marked-up versions of the Technical Specifications for McGuire and Catawba, respectively, showing the proposed changes.
-Pressurizer Pressure -Low > 1835 psig 1840 psig Low 4.d(1) Steam Line Isolation
Duke Energy will make conforming changes to the Technical Specification Bases in accordance with TS 5.5.14, "Technical Specifications (TS) Bases Control Program." Attachments 2a and 2b provide the affected TS Bases markups for McGuire and Catawba, respectively. These Bases markups are included for information only.
-Steam Line Pressure -> 755 psig > 766 psig Low -4.d(2) Steam Line Isolation
: 3. BACKGROUND Reactor Trip System The RTS initiates a unit shutdown, based on the values of selected unit parameters, to protect against violating the core fuel design limits and Reactor Coolant System (RCS) pressure boundary during anticipated operational occurrences (AOOs) and to assist the Engineered Safety Features (ESF) Systems in mitigating accidents.
-Steam Line Pressure -< 120 psi < 110 psi Negative Rate -High -5.a(2) Turbine Trip and Feedwater Isolation
-Turbine Trip -SG Water Level -High High < 85.6% < 84.7%(P-14)5.b(2) Turbine Trip and Feedwater Isolation
-Feedwater Isolation
-SG Water Level -High 5 85.6% < 84.7%High (P-14)5.b(4) Turbine Trip and Feedwater Isolation
-> 551 OF 551.84 OF Feedwater Isolation
-Tavg -Low 6.b Auxiliary Feedwater-SG Water Level -Low > 15% > 16%Low 8.b ESFAS Interlocks
-Pressurizer Pressure, <1965 psig <1960 psig P-1 1 8.c ESFAS Interlocks
-Tavg -Low Low, P-1 2>_ 551 OF >551.84 OF In addition, two new lettered footnotes, designated
() and (k), would be added to Table 3.3.1-1, and two new lettered footnotes, designated (f) and (g), would be added to Table 3.3.2-1. The new Table 3.3.1-1 footnotes would apply to the cross-referenced CHANNEL OPERATIONAL TEST (COT) and CHANNEL CALIBRATION requirements listed in the "SURVEILLANCE REQUIREMENTS (SR)" column of the Table for Functions 8.a, 8.b, 9, 10.a, 1.b, 12, and 13, specifically the SR 3.3.1.7 and 3.3.1.10 entries. The new footnotes would read as follows: (j) If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.(k) The instrument channel setpoint shall be reset to a value that is within the as-left.tolerance around the Nominal Trip Setpoint (NTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable.
Setpoints more conservative than the NTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (field setting) to confirm channel performance.
The methodologies used to determine the as-found and the as-left tolerances are specified in the UFSAR.The new Table 3.3.2-1 footnotes would apply to the cross-referenced CHANNEL OPERATIONAL TEST (COT) and CHANNEL CALIBRATION requirements listed in the"SURVEILLANCE REQUIREMENTS" column of the Table for Functions 1.d, 4.d(1), 4.d(2), 5.a(2), 5.b(2), 5.b(4), and 6.b, specifically the SR 3.3.2.5 and 3.3.2.8 entries. The new footnotes, (f) and (g) are identical to the proposed new Table 3.3.1-1 footnotes (j) and (k), respectively.
U.S. Nuclear Regulatory Commission June 29, 2010 Enclosure 1 Page 4 of 32 These new footnotes are consistent with Technical Specification Task Force Traveler TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions," Revision 4.In addition to the above-mentioned footnotes, a footnote would be added to Table 3.3.1-1 for the Allowable Value entry for Function 16.a, "Reactor Trip System Interlocks
-Intermediate Range Neutron Flux, P-6." This footnote would read as follows: A The > 4E-1 1 amp Allowable Value, which applies to the Westinghouse-supplied compensated ion chamber Intermediate Range neutron detectors, is non-conservative.
The compensated ion chamber neutron detectors are being replaced with Thermo Scientific-supplied fission chamber neutron detectors.
Until the replacement occurs, an Allowable Value of > 4.8E-1 1 amp applies.This footnote will provide proper coordination with the Duke Energy license amendment application dated July 1, 2009, which was submitted to support plant modifications to the Nuclear Instrumentation System. This license amendment application included a proposed revision to the Allowable Value for the P-6 function.Catawba Nuclear Station atawba ITSTable,3.3.1.1 FUNCTION ALLOWABLE VALUE.Ca TTl31Current Proposed 2.a Power Range Neutron Flux -High _ 110.9% RTP _ 110.3% RTP 2.b Power Range Neutron Flux -Low  27.1% RTP 26.3% RTP 6 Overtemperature AT < 4.3% RTP (Unit 1) <3.97% RTP< 4.5% RTP (Units 1&2)(Unit 2)8.a Pressurizer Pressure -Low >1938 psig >1939>_ 198pi 99psig 8.b Pressurizer Pressure -High < 2399 psig < 2390 psig 9 Pressurizer Water Level -High < 93.8% < 92.7%10.a Reactor Coolant Flow -Low -Single Loop > 89.7% > 90.5%1 0.b Reactor Coolant Flow -Low -Two Loops > 89.7% > 90.5%12 Underfrequency RCPs > 55.9 Hz > 56.2 Hz 13 Steam Generator (SG) Water Level -Low > 9% > 10%Low (Unit 1) (Unit 1)> 35.1% > 36.1%(Unit 2) (Unit 2)16.a Reactor Trip System Interlocks
-Intermediate
> 6E-1 1 amp 6.9E-1 1 amp Range Neutron Flux, P-6 16.f Reactor Trip System Interlocks -Turbine 5 12.2% RTP <5 10.7% RTP Impulse Pressure, P-13 U.S. Nuclear Regulatory Commission June 29, 2010 Enclosure 1 Page 5 of 32 ALLOWABLE VALUE Catawba TS Table 3.3.2-1 FUNCTION Current Proposed 1 .c Safety Injection
-Containment Pressure -High < 1.4 psig < 1.3 psig 1 .d Safety Injection
-Pressurizer Pressure -Low 1839 psig 1840 psig 3.b(3) Containment Isolation
-Phase B Isolation
-<3.2 psig 3.1 psig Containment Pressure -High High 4.c Steam Line Isolation-Containment Pressure -<3.2 psig 3.1 psig High High 4.d(1) Steam Line Isolation
-Steam Line Pressure -> 744 psig > 766 psig Low -4.d(2) Steam Line Isolation
-Steam Line Pressure -< 122.8 psi <110.1 psi Negative Rate -High -5.a(2) Turbine Trip and Feedwater Isolation
-< 85.6% < 84.6%Turbine Trip -SG Water Level -High-High (Unit 1) (Unit 1)(P-14) < 78.9% < 77.8%(Unit 2), (Unit 2)5.b(2) Turbine Trip and Feedwater Isolation
-< 85.6% < 84.6%Feedwater Isolation
-SG Water Level -High (Unit 1) (Unit 1)High (P-14) < 78.9% < 77.8%(Unit 2) (Unit 2)5.b(4) Turbine Trip and Feedwater Isolation
-> 561 OF 562.88 OF Feedwater Isolation
-Tavg -Low 6.b Auxiliary Feedwater
-SG Water Level -Low > 9% > 10%Low (Unit 1) (Unit 1)>35.1% >36.1%(Unit 2) (Unit 2)8.b ESFAS Interlocks
-Pressurizer Pressure, > 1944 psig > 1946 psig P-11 and and<1966 psig <1960 psig 8.c ESFAS Interlocks
-Tavg -Low Low, P-12 > 550 OF 551.88 OF In addition, two new lettered footnotes, designated (I) and (m), would be added to Table 3.3.1-1, and two new lettered footnotes, designated (f) and (g), would be added to Table 3.3.2-1. The new Table 3.3.1-1 footnotes would apply to the cross-referenced CHANNEL OPERATIONAL TEST and CHANNEL CALIBRATION requirements listed in the "SURVEILLANCE REQUIREMENTS" column of the Table for Functions 2.a, 2.b, 6, 8.a, 8.b, 9, 10.a, 10.b, 12, and 13, specifically the SR 3.3.1.7, 3.3.1.8, 3.3.1.10, and 3.3.1.11 entries. The new footnotes would read as follows: (I) If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.(m) The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Nominal Trip Setpoint (NTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable.
Setpoints more conservative than the NTSP are acceptable provided that the as-found and as-left U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 6 of 32 tolerances apply to the actual setpoint implemented in the Surveillance procedures (field setting) to confirm channel performance.
The methodologies used to determine the as-found and the as-left tolerances are specified in the UFSAR.The new Table 3.3.2-1 footnotes would apply to the cross-referenced CHANNEL OPERATIONAL TEST (COT) and CHANNEL CALIBRATION requirements listed in the"SURVEILLANCE REQUIREMENTS" column of the Table for Functions 1 .c, 1 .d, 3.b(3), 4.c, 4.d(1), 4.d(2), 5.a(2), 5.b(2), 5.b(4), and 6.b, specifically the SR 3.3.2.5 and 3.3.2.9 entries. The new footnotes, (f) and (g) are identical to the proposed new Table 3.3. 1-1 footnotes (I) and (m), respectively.
These new footnotes are consistent with Technical Specification Task Force Traveler TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions," Revision 4.In addition to the above-mentioned footnotes, an additional footnote would be added to Table 3.3.1-1 for the Allowable Value entry for Function 16.a, "Reactor Trip System Interlocks  
-Intermediate Range Neutron Flux, P-6." This footnote would read as follows: A The > 6E-1 1 amp Allowable Value, which applies to the Westinghouse-supplied compensated ion chamber Intermediate Range neutron detectors, is non-conservative.
The compensated ion chamber neutron detectors are being replaced with Thermo Scientific-supplied fission chamber neutron detectors.
Until the replacement occurs, an Allowable Value of > 6.9E-1 1 amp applies.This footnote will provide proper coordination with the Duke Energy license amendment application dated July 1, 2009, which was submitted to support plant modifications to the Nuclear Instrumentation System. This license amendment application included a proposed revision to the Allowable Value for the P-6 interlock function.Further Discussion Attachments 1 a and lb provide marked-up versions of the Technical Specifications for McGuire and Catawba, respectively, showing the proposed changes.Duke Energy will make conforming changes to the Technical Specification Bases in accordance with TS 5.5.14, "Technical Specifications (TS) Bases Control Program." Attachments 2a and 2b provide the affected TS Bases markups for McGuire and Catawba, respectively.
These Bases markups are included for information only.3. BACKGROUND Reactor Trip System The RTS initiates a unit shutdown, based on the values of selected unit parameters, to protect against violating the core fuel design limits and Reactor Coolant System (RCS) pressure boundary during anticipated operational occurrences (AOOs) and to assist the Engineered Safety Features (ESF) Systems in mitigating accidents.
The following describes particular aspects of the RTS that are pertinent to this license amendment application:
The following describes particular aspects of the RTS that are pertinent to this license amendment application:
U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 7 of 32 Power Range Neutron Flux -High The Power Range Neutron Flux-High trip Function ensures'that protection is provided, from all power levels, against a positive reactivity excursion leading to Departure from Nucleate Boiling (DNB) during power operations.
 
These can be caused by rod withdrawal or reductions in RCS temperature.
U.S. Nuclear Regulatory Commission                                                       Enclosure 1 June 29, 2010                                                                           Page 7 of 32 Power Range Neutron Flux - High The Power Range Neutron Flux-High trip Function ensures'that protection is provided, from all power levels, against a positive reactivity excursion leading to Departure from Nucleate Boiling (DNB) during power operations. These can be caused by rod withdrawal or reductions in RCS temperature.
Power Range Neutron Flux -Low The Power Range Neutron Flux-Low trip Function ensures that protection is provided against a positive reactivity excursion from low power or subcritical conditions.
Power Range Neutron Flux - Low The Power Range Neutron Flux-Low trip Function ensures that protection is provided against a positive reactivity excursion from low power or subcritical conditions. This Function may be manually blocked by the operator when two out of four power range channels are greater than approximately 10% Rated Thermal Power (RTP) (P-10 setpoint). This Function is automatically unblocked when three out of four power range channels are below the P-10 setpoint. Above the P-10 setpoint, positive reactivity additions are mitigated by the Power Range Neutron Flux-High trip Function.
This Function may be manually blocked by the operator when two out of four power range channels are greater than approximately 10% Rated Thermal Power (RTP) (P-10 setpoint).
OvertemperatureAT The Overtemperature AT trip Function is provided to ensure that the design limit Departure from Nucleate Boiling Ratio (DNBR) is met. The inputs to the Overtemperature AT trip include pressurizer pressure, coolant temperature, axial power distribution, and reactor power as indicated by loop AT, assuming full reactor coolant flow. Protection from violating the DNBR limit is assured for those transients that are slow with respect to delays from the core to the measurement system. The function monitors both variation in power and flow since a decrease in flow has the same effect on AT as a power increase. The Overtemperature AT trip Function uses each loop's AT as a measure of reactor power and is compared with a setpoint that is automatically varied with the following parameters:
This Function is automatically unblocked when three out of four power range channels are below the P-10 setpoint.
Reactor Coolant Average Temperature: The Trip Setpoint is varied to correct for changes in coolant density and specific heat capacity with changes in coolant temperature; Pressurizer Pressure: The Trip Setpoint is varied to correct for changes in system pressure; and, Axial Power Distribution-f(AI): The Trip Setpoint is varied to account for imbalances in the axial power distribution as detected by the Nuclear Instrumentation System (NIS) upper and lower power range detectors. If axial peaks are greater than the design limit, as indicated by the difference between the upper and lower NIS power range detectors, the Trip Setpoint is reduced in accordance with Note 1 of Table 3.3.1-1.
Above the P-10 setpoint, positive reactivity additions are mitigated by the Power Range Neutron Flux-High trip Function.Overtemperature AT The Overtemperature AT trip Function is provided to ensure that the design limit Departure from Nucleate Boiling Ratio (DNBR) is met. The inputs to the Overtemperature AT trip include pressurizer pressure, coolant temperature, axial power distribution, and reactor power as indicated by loop AT, assuming full reactor coolant flow. Protection from violating the DNBR limit is assured for those transients that are slow with respect to delays from the core to the measurement system. The function monitors both variation in power and flow since a decrease in flow has the same effect on AT as a power increase.
This Function also provides a signal to generate a turbine runback prior to reaching the Trip Setpoint. A turbine runback will reduce turbine power and reactor power. A reduction in power will normally alleviate the Overtemperature AT condition and may prevent a reactor trip.
The Overtemperature AT trip Function uses each loop's AT as a measure of reactor power and is compared with a setpoint that is automatically varied with the following parameters:
PressurizerPressure- Low The Pressurizer Pressure - Low trip Function ensures that protection is provided against
Reactor Coolant Average Temperature:
 
The Trip Setpoint is varied to correct for changes in coolant density and specific heat capacity with changes in coolant temperature; Pressurizer Pressure:
U.S. Nuclear Regulatory Commission                                                         Enclosure 1 June 29, 2010                                                                             Page 8 of 32 violating the DNBR limit due to low pressure. This trip Function is automatically enabled on increasing power by the P-7 interlock. The P-7 interlock, "Low Power Reactor Trips Block," is actuated by input from either the P-10 interlock, "Power Range Neutron Flux," or the, P-13 interlock, "Turbine Impulse Pressure." The P-10 interlock is actuated at approximately 10%
The Trip Setpoint is varied to correct for changes in system pressure; and, Axial Power Distribution-f(AI):
power, as determined by the Nuclear Instrumentation System (NIS) power range detectors. The P-13 interlock is described below. On decreasing power, this trip Function is automatically blocked below P-7. Below the P-7 setpoint, power distributions that would cause Departure from Nucleate Boiling (DNB) concerns are unlikely.
The Trip Setpoint is varied to account for imbalances in the axial power distribution as detected by the Nuclear Instrumentation System (NIS) upper and lower power range detectors.
PressurizerPressure- High The Pressurizer Pressure - High trip Function ensures that protection is provided against overpressurizing the RCS. This trip Function operates in conjunction with the pressurizer relief and safety valves to prevent RCS overpressure conditions.
If axial peaks are greater than the design limit, as indicated by the difference between the upper and lower NIS power range detectors, the Trip Setpoint is reduced in accordance with Note 1 of Table 3.3.1-1.This Function also provides a signal to generate a turbine runback prior to reaching the Trip Setpoint.
PressurizerWater Level - High The Pressurizer Water Level - High trip Function provides a backup signal for the Pressurizer Pressure - High trip and also provides protection against water relief through the pressurizer safety valves. These valves are designed to pass steam in order to achieve their design energy removal rate. A reactor trip is actuated prior to the pressurizer becoming water solid. This trip Function is automatically enabled on increasing power by the P-7 interlock. On decreasing power, this trip Function is automatically blocked below P-7. Below the P-7 setpoint, transients that could raise the pressurizer water level will be slow and the operator will have sufficient time to evaluate unit conditions and take corrective actions.
A turbine runback will reduce turbine power and reactor power. A reduction in power will normally alleviate the Overtemperature AT condition and may prevent a reactor trip.Pressurizer Pressure -Low The Pressurizer Pressure -Low trip Function ensures that protection is provided against U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 8 of 32 violating the DNBR limit due to low pressure.
Reactor Coolant Flow - Low (Single Loop)
This trip Function is automatically enabled on increasing power by the P-7 interlock.
The Reactor Coolant Flow - Low (Single Loop) trip Function ensures that protection is provided against violating the DNBR limit due to low flow in one or more RCS loops, while avoiding reactor trips due to normal variations in loop flow. Above the P-8 setpoint, which is approximately 48% rated thermal power (RTP) as measured by the NIS power range detectors, a loss of flow in any RCS loop will actuate a reactor trip. Below the P-8 setpoint, a loss of flow in two or more loops is required to actuate a reactor trip because of the lower power level and the greater margin to the design limit DNBR.
The P-7 interlock, "Low Power Reactor Trips Block," is actuated by input from either the P-10 interlock, "Power Range Neutron Flux," or the, P-13 interlock, "Turbine Impulse Pressure." The P-10 interlock is actuated at approximately 10%power, as determined by the Nuclear Instrumentation System (NIS) power range detectors.
Reactor Coolant Flow - Low (Two Loops)
The P-13 interlock is described below. On decreasing power, this trip Function is automatically blocked below P-7. Below the P-7 setpoint, power distributions that would cause Departure from Nucleate Boiling (DNB) concerns are unlikely.Pressurizer Pressure -High The Pressurizer Pressure -High trip Function ensures that protection is provided against overpressurizing the RCS. This trip Function operates in conjunction with the pressurizer relief and safety valves to prevent RCS overpressure conditions.
The Reactor Coolant Flow - Low (Two Loops) trip Function ensures that protection is provided against violating the DNBR limit due to low flow in two or more RCS loops while avoiding reactor trips due to normal variations in loop flow. Above the P-7 setpoint and below the P-8 setpoint, a loss of flow in two or more loops will initiate a reactor trip. Below the P-7 setpoint, all reactor trips on low flow are automatically blocked since power distributions that would cause a DNB concern at this low power level are unlikely. Above the P-7 setpoint, the reactor trip on low flow in two or more RCS loops is automatically enabled. Above the P-8 setpoint, a loss of flow in any one loop will actuate a reactor trip because of the higher power level and the reduced margin to the design limit DNBR.
Pressurizer Water Level -High The Pressurizer Water Level -High trip Function provides a backup signal for the Pressurizer Pressure -High trip and also provides protection against water relief through the pressurizer safety valves. These valves are designed to pass steam in order to achieve their design energy removal rate. A reactor trip is actuated prior to the pressurizer becoming water solid. This trip Function is automatically enabled on increasing power by the P-7 interlock.
Underfrequency Reactor Coolant Pumps (RCPs)
On decreasing power, this trip Function is automatically blocked below P-7. Below the P-7 setpoint, transients that could raise the pressurizer water level will be slow and the operator will have sufficient time to evaluate unit conditions and take corrective actions.Reactor Coolant Flow -Low (Single Loop)The Reactor Coolant Flow -Low (Single Loop) trip Function ensures that protection is provided against violating the DNBR limit due to low flow in one or more RCS loops, while avoiding reactor trips due to normal variations in loop flow. Above the P-8 setpoint, which is approximately 48% rated thermal power (RTP) as measured by the NIS power range detectors, a loss of flow in any RCS loop will actuate a reactor trip. Below the P-8 setpoint, a loss of flow in two or more loops is required to actuate a reactor trip because of the lower power level and the greater margin to the design limit DNBR.Reactor Coolant Flow -Low (Two Loops)The Reactor Coolant Flow -Low (Two Loops) trip Function ensures that protection is provided against violating the DNBR limit due to low flow in two or more RCS loops while avoiding reactor trips due to normal variations in loop flow. Above the P-7 setpoint and below the P-8 setpoint, a loss of flow in two or more loops will initiate a reactor trip. Below the P-7 setpoint, all reactor trips on low flow are automatically blocked since power distributions that would cause a DNB concern at this low power level are unlikely.
The Underfrequency RCPs reactor trip Function ensures that protection is provided against
Above the P-7 setpoint, the reactor trip on low flow in two or more RCS loops is automatically enabled. Above the P-8 setpoint, a loss of flow in any one loop will actuate a reactor trip because of the higher power level and the reduced margin to the design limit DNBR.Underfrequency Reactor Coolant Pumps (RCPs)The Underfrequency RCPs reactor trip Function ensures that protection is provided against U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 9 of 32 violating the DNBR limit due to a loss of flow in two or more RCS loops from a major network frequency disturbance.
 
An underfrequency condition will slow down the pumps, thereby reducing their coastdown time following a pump trip. The proper coastdown time is required so that reactor heat can be removed immediately after a reactor trip. The frequency of each RCP bus is monitored.
U.S. Nuclear Regulatory Commission                                                         Enclosure 1 June 29, 2010                                                                             Page 9 of 32 violating the DNBR limit due to a loss of flow in two or more RCS loops from a major network frequency disturbance. An underfrequency condition will slow down the pumps, thereby reducing their coastdown time following a pump trip. The proper coastdown time is required so that reactor heat can be removed immediately after a reactor trip. The frequency of each RCP bus is monitored. Above the P-7 setpoint, a loss of frequency detected on two or more RCP buses will initiate a reactor trip. This trip Function will generate a reactor trip before the Reactor Coolant Flow-Low (Two Loops) Trip Setpoint is reached. Time delays are incorporated into the Underfrequency RCPs channels to prevent reactor trips due to momentary electrical power transients. Below the P-7 setpoint, all reactor trips on loss of flow are automatically blocked since power distributions that would cause a DNB concern at this low power level are unlikely.
Above the P-7 setpoint, a loss of frequency detected on two or more RCP buses will initiate a reactor trip. This trip Function will generate a reactor trip before the Reactor Coolant Flow-Low (Two Loops) Trip Setpoint is reached. Time delays are incorporated into the Underfrequency RCPs channels to prevent reactor trips due to momentary electrical power transients.
Above the P-7 setpoint, the reactor trip on loss of flow in two or more RCS loops is automatically enabled.
Below the P-7 setpoint, all reactor trips on loss of flow are automatically blocked since power distributions that would cause a DNB concern at this low power level are unlikely.Above the P-7 setpoint, the reactor trip on loss of flow in two or more RCS loops is automatically enabled.Steam Generator Water Level -Low-Low The SG Water Level -Low-Low trip Function ensures that protection is provided against a loss of heat sink and actuates the Auxiliary Feedwater (AFW) System prior to uncovering the Steam Generator (SG) tubes. The SGs are the heat sink for the reactor. In order to act as a heat sink, the SGs must contain a minimum amount of water. A narrow range low-low level in any SG is indicative of a loss of heat sink for the reactor. This Function also performs the ESFAS function of starting the AFW pumps on low-low SG level.Reactor Trip System Interlock, Intermediate Range Neutron Flux, P-6 The Intermediate Range Neutron Flux, P-6 interlock is actuated when any Intermediate Range channel goes approximately one decade above the minimum channel reading. If both channels drop below the setpoint, the permissive will automatically be defeated.
Steam GeneratorWater Level - Low-Low The SG Water Level - Low-Low trip Function ensures that protection is provided against a loss of heat sink and actuates the Auxiliary Feedwater (AFW) System prior to uncovering the Steam Generator (SG) tubes. The SGs are the heat sink for the reactor. In order to act as a heat sink, the SGs must contain a minimum amount of water. A narrow range low-low level in any SG is indicative of a loss of heat sink for the reactor. This Function also performs the ESFAS function of starting the AFW pumps on low-low SG level.
On increasing power, the P-6 interlock allows the manual block of the NIS Source Range, Neutron Flux reactor trip.This prevents a premature block of the source range trip and allows the operator to ensure that the intermediate range is OPERABLE prior to leaving the source range. When the source range trip is blocked, the high voltage to the detectors is also removed. On decreasing power, the P-6 interlock automatically energizes the NIS source range detectors and enables the NIS Source Range Neutron Flux reactor trip.Reactor Trip System Interlock, Turbine Impulse Pressure, P-13 The Turbine Impulse Pressure, P-13 interlock is actuated when the pressure in the first stage of the high pressure turbine is greater than approximately 10% of the rated full power pressure.Engqineered Safety Features Actuation System The ESFAS initiates necessary safety systems, based on the values of selected unit parameters, to protect against violating core design limits and the Reactor Coolant System (RCS) pressure boundary, and to mitigate accidents.
Reactor Trip System Interlock, Intermediate Range Neutron Flux, P-6 The Intermediate Range Neutron Flux, P-6 interlock is actuated when any Intermediate Range channel goes approximately one decade above the minimum channel reading. If both channels drop below the setpoint, the permissive will automatically be defeated. On increasing power, the P-6 interlock allows the manual block of the NIS Source Range, Neutron Flux reactor trip.
This prevents a premature block of the source range trip and allows the operator to ensure that the intermediate range is OPERABLE prior to leaving the source range. When the source range trip is blocked, the high voltage to the detectors is also removed. On decreasing power, the P-6 interlock automatically energizes the NIS source range detectors and enables the NIS Source Range Neutron Flux reactor trip.
Reactor Trip System Interlock, Turbine Impulse Pressure,P-13 The Turbine Impulse Pressure, P-13 interlock is actuated when the pressure in the first stage of the high pressure turbine is greater than approximately 10% of the rated full power pressure.
Engqineered Safety Features Actuation System The ESFAS initiates necessary safety systems, based on the values of selected unit parameters, to protect against violating core design limits and the Reactor Coolant System (RCS) pressure boundary, and to mitigate accidents.
The following describes particular aspects of the ESFAS that are pertinent to this license amendment application:
The following describes particular aspects of the ESFAS that are pertinent to this license amendment application:
Safety Injection, Containment Pressure -High This signal provides protection against a Steam Line Break (SLB) inside containment, a Loss of U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 10 of 32 Coolant Accident (LOCA), and a feedwater line break inside containment.
Safety Injection, Containment Pressure- High This signal provides protection against a Steam Line Break (SLB) inside containment, a Loss of
Safety Injection, Pressurizer Pressure -Low-Low (McGuire)Safety Injection, Pressurizer Pressure -Low (Catawba)This signal provides protection against: the inadvertent opening of a steam generator (SG) relief or safety valve; an SLB; a spectrum of rod cluster control assembly ejection accidents (rod ejection);
 
the inadvertent opening of a pressurizer relief or safety valve; a LOCA; and a SG Tube Rupture. This signal may be manually blocked by the operator below the P-1 1 setpoint.Automatic Safety Injection (SI) actuation below this pressure setpoint is then performed by the Containment Pressure-High signal. The P-1 1 interlock is described below.Containment Isolation, Phase B Isolation, Containment Pressure -High High Containment Isolation provides isolation of the containment atmosphere, and all process systems that penetrate containment, from the environment.
U.S. Nuclear Regulatory Commission                                                       Enclosure 1 June 29, 2010                                                                         Page 10 of 32 Coolant Accident (LOCA), and a feedwater line break inside containment.
This Function is necessary to prevent or limit the release of radioactivity to the environment in the event of a large break LOCA. There are two separate Containment Isolation signals, Phase A and Phase B. Phase A isolation isolates all automatically isolable process lines, except component cooling water (CCW) and nuclear service water system (NSWS). The Phase B signal isolates CCW and NSWS.Steam Line Isolation, Containment Pressure -High High This Function actuates closure of the Main Steam Isolation Valves in the event of a LOCA or an SLB inside containment to maintain three unfaulted SGs as a heat sink for the reactor, and to limit the mass and energy release to containment.
Safety Injection, PressurizerPressure- Low-Low (McGuire)
Steam Line Isolation, Steam Line Pressure -Low Steam Line Pressure -Low provides closure of the Main Steam Isolation Valves (MSIVs) in the event of an SLB to maintain three unfaulted SGs as a heat sink for the reactor, and to limit the'mass and energy release to containment.
Safety Injection, PressurizerPressure- Low (Catawba)
This Function provides closure of the MSIVs in the.event of a feed line break to ensure a supply of steam for the turbine driven AFW pump. This signal may be manually blocked by the operator below the P-1 1 setpoint.
This signal provides protection against: the inadvertent opening of a steam generator (SG) relief or safety valve; an SLB; a spectrum of rod cluster control assembly ejection accidents (rod ejection); the inadvertent opening of a pressurizer relief or safety valve; a LOCA; and a SG Tube Rupture. This signal may be manually blocked by the operator below the P-1 1 setpoint.
Below P-1 1, an inside containment SLB will be terminated by automatic actuation via Containment Pressure -High-High signal. Stuck valve transients and outside containment SLBs will be terminated by the Steam Line Pressure -Negative Rate-High signal for Steam Line Isolation below P-1 1 when Steam Line Isolation Steam Line Pressure -Low has been manually blocked.Steam Line Isolation, Steam Line Pressure -Negative Rate -High Steam Line Pressure -Negative Rate -High provides closure of the MSIVs for an SLB When less than the P-1 1 setpoint, to maintain at least one unfaulted SG~as a heat sink for the reactor, and to limit the mass and energy release to containment.
Automatic Safety Injection (SI) actuation below this pressure setpoint is then performed by the Containment Pressure-High signal. The P-1 1 interlock is described below.
When the operator manually blocks the Steam Line Pressure -Low main steam isolation signal when less than the P-1 1 setpoint, the Steam Line Pressure -Negative Rate -High signal is automatically enabled.Turbine Trip, Steam Generator Water Level -High-High (P-14)This signal prevents damage to the turbine due to water in the steam lines. The ESFAS SG U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 11 of 32 water level instruments provide input to the SG Water Level Control System. The setpoints are based on percent of narrow range instrument span.Feedwater Isolation, Steam Generator Water Level -High-High (P- 14)This signal provides protection against excessive feedwater flow. The ESFAS SG water level instruments provide input to the SG Water Level Control System. The setpoints are based on percent of narrow range instrument span.Feedwater Isolation, RCS Tavg -Low, Coincident with Reactor Trip (P-4)This signal provides protection against excessive cooldown, which could subsequently introduce a positive reactivity excursion after a plant trip.Auxiliary Feedwater Initiation, Steam Generator Water Level- Low-Low SG Water Level -Low-Low provides protection against a loss of heat sink. A feed line break, inside or outside of containment, or a loss of main feedwater (MFW), would result in a loss of SG water level. SG Water Level -Low-Low provides input to the SG Level Control System.The setpoints are based on percent of narrow range instrument span. SG Water Level -Low-Low in any operating SG will cause the motor driven AFW pumps to start. The system is aligned so that upon a start of the pump, water immediately begins to flow to the SGs. SG Water Level -Low-Low in any two operating SGs will cause the turbine driven pumps to start.ESFAS Interlock, Pressurizer Pressure, P-Il The P-1 1 interlock permits a normal unit cooldown and depressurization without actuation of SI or main steam line isolation.
Containment Isolation, Phase B Isolation, Containment Pressure- High High Containment Isolation provides isolation of the containment atmosphere, and all process systems that penetrate containment, from the environment. This Function is necessary to prevent or limit the release of radioactivity to the environment in the event of a large break LOCA. There are two separate Containment Isolation signals, Phase A and Phase B. Phase A isolation isolates all automatically isolable process lines, except component cooling water (CCW) and nuclear service water system (NSWS). The Phase B signal isolates CCW and NSWS.
With two-out-of-three pressurizer pressure channels less than the P-1 1 setpoint, the operator can manually block the Pressurizer Pressure -Low SI signal and the Steam Line Pressure -Low steam line isolation signal.When the Steam Line Pressure -Low steam line isolation signal is manually blocked, a main steam isolation signal on Steam Line Pressure -Negative Rate -High is enabled. This provides protection for an SLB by closure of the MSIVs. With two-out-of-three pressurizer pressure channels above the P-1 1 setpoint, the Pressurizer Pressure -Low SI signal and the Steam Line Pressure -Low steam line isolation signal are automatically enabled. The operator can also enable these trips by use of the respective manual reset buttons. When the Steam Line Pressure -Low steam line isolation signal is enabled, the main steam isolation on Steam Line Pressure -Negative Rate-High is disabled.ESFAS Interlock, Tavg -Low-Low, P-12 On increasing reactor coolant temperature, the P-12 interlock provides an arming signal to the Steam Dump System. On a decreasing temperature, the P-12 interlock removes the arming signal to the Steam Dump System to prevent an excessive cooldown of the RCS due to a malfunctioning Steam Dump System.
Steam Line Isolation, Containment Pressure- High High This Function actuates closure of the Main Steam Isolation Valves in the event of a LOCA or an SLB inside containment to maintain three unfaulted SGs as a heat sink for the reactor, and to limit the mass and energy release to containment.
U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 12 of 32 4. TECHNICAL ANALYSIS Setpoint Calculation Changes Introduction Setpoint calculations were updated, resulting in the need for changes to associated values listed in TS Table 3.3.1-1, "Reactor Trip System Instrumentation," and TS Table 3.3.2-1, "Engineered Safety Features Actuation System Instrumentation," as described in Section 2 above. These setpoint calculations were performed in accordance with Duke Energy Engineering Directives Manual (EDM)-1 02, "Instrument Setpoint/Uncertainty Calculations," Revision 3. The methodology described in EDM-102 is consistent with the intent of Instrument Society of America (ISA) Standard RP67.04-1994 Part II, "Methodologies for the Determination of Setpoints for Nuclear Safety Related Instrumentation." Basic Methodology  
Steam Line Isolation, Steam Line Pressure- Low Steam Line Pressure - Low provides closure of the Main Steam Isolation Valves (MSIVs) in the event of an SLB to maintain three unfaulted SGs as a heat sink for the reactor, and to limit the' mass and energy release to containment. This Function provides closure of the MSIVs in the.
-EDM- 102 The loop uncertainty methodology is primarily based on the "Square-Root-Sum-of-the-Squares" (SRSS) technique for combination of random-independent uncertainty terms. Random-dependent and bias uncertainty terms must be addressed through a combination of the SRSS and/or algebraic techniques.
event of a feed line break to ensure a supply of steam for the turbine driven AFW pump. This signal may be manually blocked by the operator below the P-1 1 setpoint. Below P-1 1, an inside containment SLB will be terminated by automatic actuation via Containment Pressure - High-High signal. Stuck valve transients and outside containment SLBs will be terminated by the Steam Line Pressure - Negative Rate-High signal for Steam Line Isolation below P-1 1 when Steam Line Isolation Steam Line Pressure - Low has been manually blocked.
Steam Line Isolation, Steam Line Pressure- Negative Rate - High Steam Line Pressure - Negative Rate - High provides closure of the MSIVs for an SLB When less than the P-1 1 setpoint, to maintain at least one unfaulted SG~as a heat sink for the reactor, and to limit the mass and energy release to containment. When the operator manually blocks the Steam Line Pressure - Low main steam isolation signal when less than the P-1 1 setpoint, the Steam Line Pressure - Negative Rate - High signal is automatically enabled.
Turbine Trip, Steam GeneratorWater Level - High-High (P-14)
This signal prevents damage to the turbine due to water in the steam lines. The ESFAS SG
 
U.S. Nuclear Regulatory Commission                                                   Enclosure 1 June 29, 2010                                                                     Page 11 of 32 water level instruments provide input to the SG Water Level Control System. The setpoints are based on percent of narrow range instrument span.
Feedwater Isolation, Steam GeneratorWater Level - High-High (P- 14)
This signal provides protection against excessive feedwater flow. The ESFAS SG water level instruments provide input to the SG Water Level Control System. The setpoints are based on percent of narrow range instrument span.
Feedwater Isolation, RCS Tavg - Low, Coincident with Reactor Trip (P-4)
This signal provides protection against excessive cooldown, which could subsequently introduce a positive reactivity excursion after a plant trip.
Auxiliary Feedwater Initiation, Steam GeneratorWater Level- Low-Low SG Water Level - Low-Low provides protection against a loss of heat sink. A feed line break, inside or outside of containment, or a loss of main feedwater (MFW), would result in a loss of SG water level. SG Water Level - Low-Low provides input to the SG Level Control System.
The setpoints are based on percent of narrow range instrument span. SG Water Level - Low-Low in any operating SG will cause the motor driven AFW pumps to start. The system is aligned so that upon a start of the pump, water immediately begins to flow to the SGs. SG Water Level - Low-Low in any two operating SGs will cause the turbine driven pumps to start.
ESFAS Interlock, PressurizerPressure,P-Il The P-1 1 interlock permits a normal unit cooldown and depressurization without actuation of SI or main steam line isolation. With two-out-of-three pressurizer pressure channels less than the P-1 1 setpoint, the operator can manually block the Pressurizer Pressure - Low SI signal and the Steam Line Pressure - Low steam line isolation signal.
When the Steam Line Pressure - Low steam line isolation signal is manually blocked, a main steam isolation signal on Steam Line Pressure - Negative Rate - High is enabled. This provides protection for an SLB by closure of the MSIVs. With two-out-of-three pressurizer pressure channels above the P-1 1 setpoint, the Pressurizer Pressure - Low SI signal and the Steam Line Pressure - Low steam line isolation signal are automatically enabled. The operator can also enable these trips by use of the respective manual reset buttons. When the Steam Line Pressure - Low steam line isolation signal is enabled, the main steam isolation on Steam Line Pressure - Negative Rate-High is disabled.
ESFAS Interlock, Tavg - Low-Low, P-12 On increasing reactor coolant temperature, the P-12 interlock provides an arming signal to the Steam Dump System. On a decreasing temperature, the P-12 interlock removes the arming signal to the Steam Dump System to prevent an excessive cooldown of the RCS due to a malfunctioning Steam Dump System.
 
U.S. Nuclear Regulatory Commission                                                     Enclosure 1 June 29, 2010                                                                       Page 12 of 32
: 4. TECHNICAL ANALYSIS Setpoint Calculation Changes Introduction Setpoint calculations were updated, resulting in the need for changes to associated values listed in TS Table 3.3.1-1, "Reactor Trip System Instrumentation," and TS Table 3.3.2-1, "Engineered Safety Features Actuation System Instrumentation," as described in Section 2 above. These setpoint calculations were performed in accordance with Duke Energy Engineering Directives Manual (EDM)-1 02, "Instrument Setpoint/Uncertainty Calculations," Revision 3. The methodology described in EDM-102 is consistent with the intent of Instrument Society of America (ISA) Standard RP67.04-1994 Part II, "Methodologies for the Determination of Setpoints for Nuclear Safety Related Instrumentation."
Basic Methodology - EDM-102 The loop uncertainty methodology is primarily based on the "Square-Root-Sum-of-the- Squares" (SRSS) technique for combination of random-independent uncertainty terms. Random-dependent and bias uncertainty terms must be addressed through a combination of the SRSS and/or algebraic techniques.
The over-all methodology requires identification of applicable sources of instrument uncertainty, and categorization of each as a random-independent (x,y), random-dependent (w,u), and bias/abnormal distribution (vt) terms. The magnitude of each term is then combined to determine the "Total Loop Uncertainty" (TLU) as depicted below. The "+" and "-" convention represents the positive or negative uncertainty limits within the measured setpoint or indication.
The over-all methodology requires identification of applicable sources of instrument uncertainty, and categorization of each as a random-independent (x,y), random-dependent (w,u), and bias/abnormal distribution (vt) terms. The magnitude of each term is then combined to determine the "Total Loop Uncertainty" (TLU) as depicted below. The "+" and "-" convention represents the positive or negative uncertainty limits within the measured setpoint or indication.
+ TLU=+{x 2 + y 2 + (w + u)2}1/2 +v + t-TLU=-{x 2 + y 2 + (w + u)2}1/2 -v -t The treatment of bias/abnormal distribution terms requires additional discussion.
                                + TLU=+{x 2 + y2 + (w + u)2}1 /2 +v + t
Bias terms are typically based on conservative estimates and are predictable.
                                - TLU=-{x 2 + y2 + (w + u) 2}1 /2 - v - t The treatment of bias/abnormal distribution terms requires additional discussion. Bias terms are typically based on conservative estimates and are predictable. Bias terms would normally be applied only in an additive manner, to the respective "+" or "-" TLU component. Biases of unknown direction would be applied in an additive manner to both the -TLU and +TLU determinations. Application of a non-reoccurring bias term shall not be applied so as to decrease a TLU value. Proper application of a bias would normally result in reduced margin for the setpoint limit of interest. Terms that have an abnormal distribution cannot have the SSRS technique applied with normally distributed terms and must therefore be added as a limit of error in both directions.
Bias terms would normally be applied only in an additive manner, to the respective  
"+" or "-" TLU component.
Biases of unknown direction would be applied in an additive manner to both the -TLU and +TLU determinations.
Application of a non-reoccurring bias term shall not be applied so as to decrease a TLU value. Proper application of a bias would normally result in reduced margin for the setpoint limit of interest.
Terms that have an abnormal distribution cannot have the SSRS technique applied with normally distributed terms and must therefore be added as a limit of error in both directions.
Evaluation of setpoint acceptability requires comparison of the total loop uncertainty against the operational ranges and the protected limits (process, analytical, and/or safety limits). This setpoint relationship is based on guidance in Regulatory Guide (RG) 1.105, "Instrument Setpoints for Safety-Related Systems." The typical reactor protection and/or safeguard setpoint relationship, depicting a high process setpoint, is depicted as follows:
Evaluation of setpoint acceptability requires comparison of the total loop uncertainty against the operational ranges and the protected limits (process, analytical, and/or safety limits). This setpoint relationship is based on guidance in Regulatory Guide (RG) 1.105, "Instrument Setpoints for Safety-Related Systems." The typical reactor protection and/or safeguard setpoint relationship, depicting a high process setpoint, is depicted as follows:
U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 13 of 32 Safety Limit (SL)Analytical Limit (AL)Tech Spec Allowable Value (AV)Nominal Setpoint Range of Normal Operation Safety Limits (SL) are the values chosen to reasonably protect the integrity of physical barriers that guard against the uncontrolled release of radioactivity.
 
Analytical Limits (AL) typically are values utilized in the safety analyses, which were specifically chosen to allow the equipment time to act and prevent exceeding the Safety Limits.The Allowable Value (AV) represents an acceptable benchmark (specified by Technical Specifications) for which periodic calibrations/checks must fall within to ensure operability.
U.S. Nuclear Regulatory Commission                                                        Enclosure 1 June 29, 2010                                                                          Page 13 of 32 Safety Limit (SL)
When a channel "As-found" condition is determined to be less conservative than the AV, the channel must be declared inoperable.
Analytical Limit (AL)
The AV determination is based on expected uncertainty influences for the portion of the loop tested. Uncertainty magnitudes must be representative of the surveillance interval duration.
Tech Spec Allowable Value (AV)
Examples of typical uncertainty influences, which may be measured during testing, are reference accuracy, calibration uncertainty, representative uncertainty for temperature variations between
Nominal Setpoint Range of Normal Operation Safety Limits (SL) are the values chosen to reasonably protect the integrity of physical barriers that guard against the uncontrolled release of radioactivity. Analytical Limits (AL) typically are values utilized in the safety analyses, which were specifically chosen to allow the equipment time to act and prevent exceeding the Safety Limits.
The Allowable Value (AV) represents an acceptable benchmark (specified by Technical Specifications) for which periodic calibrations/checks must fall within to ensure operability.
When a channel "As-found" condition is determined to be less conservative than the AV, the channel must be declared inoperable. The AV determination is based on expected uncertainty influences for the portion of the loop tested.
In summary, the proposed changes will not involve a significant increase in the probability or consequences of an accident previously evaluated.
In summary, the proposed changes will not involve a significant increase in the probability or consequences of an accident previously evaluated.
: 2. Does the proposed amendment create the possibility of a new or different kind of accident from any accident previously evaluated?
: 2. Does the proposed amendment create the possibility of a new or different kind of accident from any accident previously evaluated?
Response:
Response: No No new accident scenarios, failure mechanisms, or single failures are introduced as a result of any of the proposed changes. The RTS and ESFAS are not capable by itself of initiating any accident. No physical changes to the overall plant are being proposed. No changes to the overall manner in which the plant is operated are being proposed. The proposed changes do not introduce any new failure modes.
No No new accident scenarios, failure mechanisms, or single failures are introduced as a result of any of the proposed changes. The RTS and ESFAS are not capable by itself of initiating any accident.
Therefore, none of the proposed changes will create the possibility of a new or different kind of accident from any accident previously evaluated.
No physical changes to the overall plant are being proposed.
: 3. Does the proposed amendment involve a significant reduction in a margin of safety?
No changes to the overall manner in which the plant is operated are being proposed.
Response: No Margin of safety is related to the confidence in the ability of the fission product barriers to perform their intended functions. These barriers include the fuel cladding, the reactor coolant system pressure boundary, and the containment barriers. The proposed changes will not have any impact on these barriers. Plant actuation features and Nominal Trip Setpoints will be unchanged and will actuate prior to exceeding any analytical limits. No accident mitigating equipment will be adversely impacted. Therefore, existing safety margins will be preserved. None of the proposed changes will involve a significant reduction in a.margin of safety.
The proposed changes do not introduce any new failure modes.Therefore, none of the proposed changes will create the possibility of a new or different kind of accident from any accident previously evaluated.
Based on the above, it is concluded that the proposed amendment presents no significant hazards consideration under the standards set forth in 10 CFR 50.92 (c), and accordingly, a finding of "no significant hazards consideration" is justified.
: 3. Does the proposed amendment involve a significant reduction in a margin of safety?Response:
5.2    Applicable Regulatory Req uirements/Criteria The regulatory bases and guidance documents associated with the systems discussed in this amendment application include:
No Margin of safety is related to the confidence in the ability of the fission product barriers to perform their intended functions.
10 CFR 50.36(c)(1)(ii)(A), states in part, "Limiting safety system settings for nuclear reactors are settings for automatic protective devices related to those
These barriers include the fuel cladding, the reactor coolant system pressure boundary, and the containment barriers.
The proposed changes will not have any impact on these barriers.
Plant actuation features and Nominal Trip Setpoints will be unchanged and will actuate prior to exceeding any analytical limits. No accident mitigating equipment will be adversely impacted.
Therefore, existing safety margins will be preserved.
None of the proposed changes will involve a significant reduction in a.margin of safety.Based on the above, it is concluded that the proposed amendment presents no significant hazards consideration under the standards set forth in 10 CFR 50.92 (c), and accordingly, a finding of "no significant hazards consideration" is justified.


===5.2 Applicable===
U.S. Nuclear Regulatory Commission                                                      Enclosure 1 June 29, 2010                                                                          Page 30 of 32 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."
10 CFR 50 Appendix A General Design Criteria (GDC)-10, Reactordesign, requires that the reactor core and associated coolant, control, and protection systems be designed with appropriate margin to assure that specified acceptable fuel design limits are not exceeded during any condition of normal operation, including the effects of anticipated operational occurrences.
GDC-13, Instrumentation and control, requires that instrumentation be provided to monitor variables and systems over their anticipated ranges for normal operation, for anticipated operational occurrences, and for accident conditions as appropriate to assure adequate safety, including those variables and systems that can affect the fission process, the integrity of the reactor core, the reactor coolant pressure boundary, and the containment and its associated systems.
GDC-20, Protectionsystem functions, requires that the protection system be designed (1) to initiate automatically the operation of appropriate systems including the reactivity control systems, to assure that specified acceptable fuel design limits are not exceeded as a result of anticipated operational occurrences, and (2) to sense accident conditions and to initiate the operation of systems and components important to safety.
The proposed amendment will not change the RTS or ESFAS instrumentation design such that compliance with any of the above regulatory requirements would come into question. All of the proposed Allowable Value changes are conservative based on updated-setpoint calculations.
In addition to the above regulatory requirements, Regulatory Guide (RG) 1.105, Revision 3, "Setpoints for Safety-Related Instrumentation," provides regulatory guidance pertinent to the updated instrument setpoint calculations performed in support of this license amendment application. Regulatory Guide 1.105 endorses Instrument Society of America (ISA) Standard S67.04-1994 Part I, subject to four listed exceptions and clarifications. The four listed exceptions and clarifications, taken verbatim from RG 1.105 (as shown in italics), and discussions of each, as applicable to this license amendment application, are as follows:
RG 1.105 Regulatory Position C.1 Section 4 of ISA-S67.04-1994 specifies the methods, but not the criterion, for combining uncertaintiesin determining a trip setpoint and its allowable values.
The 95/95 tolerance limit is an acceptable criterion for uncertainties. That is, there is a 95% probability that the constructed limits contain 95% of the      -
populationof interest for the surveillance interval selected.
A 95/95 tolerance is used to establish acceptable uncertainty values for the instrument strings. At the McGuire and Catawba Nuclear Stations, this is assured by means of the calculation methods, instrument string calibration, and setpoint


Regulatory Req uirements/Criteria The regulatory bases and guidance documents associated with the systems discussed in this amendment application include: 10 CFR 50.36(c)(1)(ii)(A), states in part, "Limiting safety system settings for nuclear reactors are settings for automatic protective devices related to those U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 30 of 32 variables having significant safety functions.
U.S. Nuclear Regulatory Commission                                                         Enclosure 1 June 29, 2010                                                                           Page 31 of 32 verification.
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." 10 CFR 50 Appendix A General Design Criteria (GDC)-10, Reactor design, requires that the reactor core and associated coolant, control, and protection systems be designed with appropriate margin to assure that specified acceptable fuel design limits are not exceeded during any condition of normal operation, including the effects of anticipated operational occurrences.
RG 1.105 Regulatory Position C.2 Sections 7 and 8 of Part 1 of ISA-S67.04-1994 reference several industry codes and standards. If a referenced standardhas been incorporatedseparately into the NRC's regulations, licensees and applicants must comply with that standardas set forth in the regulation. If the referenced standardhas been endorsed in a regulatoryguide, the standardconstitutes a method acceptable to the NRC staff of meeting a regulatoryrequirement as describedin the regulatoryguide. If a referenced standardhas been neither incorporatedinto the NRC's regulations nor endorsed in a regulatory guide, licensees and applicants may considerand use the information in the referenced standardif appropriatelyjustified, consistent with current regulatorypractice.
GDC-13, Instrumentation and control, requires that instrumentation be provided to monitor variables and systems over their anticipated ranges for normal operation, for anticipated operational occurrences, and for accident conditions as appropriate to assure adequate safety, including those variables and systems that can affect the fission process, the integrity of the reactor core, the reactor coolant pressure boundary, and the containment and its associated systems.GDC-20, Protection system functions, requires that the protection system be designed (1) to initiate automatically the operation of appropriate systems including the reactivity control systems, to assure that specified acceptable fuel design limits are not exceeded as a result of anticipated operational occurrences, and (2) to sense accident conditions and to initiate the operation of systems and components important to safety.The proposed amendment will not change the RTS or ESFAS instrumentation design such that compliance with any of the above regulatory requirements would come into question.
The setpoint calculation revisions supporting the proposed Technical Specification changes were performed in accordance with Duke Energy Engineering Directives Manual (EDM)-102, "Instrument Setpoint/Uncertainty Calculations," Revision 3. The methodology described in EDM-1 02 is appropriately justified and is consistent with industry practice.
All of the proposed Allowable Value changes are conservative based on updated-setpoint calculations.
RG 1.105 Regulatory Position C.3 Section 4.3 of ISA-$67.04-1994 states that the limiting safety system setting (LSSS) may be maintainedin technical specificationsor appropriateplant procedures. However, 10 CFR 50.36 states that the technical specifications will include items in the categories of safety limits, limiting safety system settings (LSSS), and limiting control settings. Thus, the LSSS may not be maintained in plant procedures. Rather, the LSSS must be specified as a technical-specification-definedlimit in orderto satisfy the requirements of 10 CFR 50.36. The LSSS should be developed in accordance with the setpoint methodology set forth in the standard,with the LSSS listed in the technical specifications.
In addition to the above regulatory requirements, Regulatory Guide (RG) 1.105, Revision 3, "Setpoints for Safety-Related Instrumentation," provides regulatory guidance pertinent to the updated instrument setpoint calculations performed in support of this license amendment application.
Regulatory Guide 1.105 endorses Instrument Society of America (ISA) Standard S67.04-1994 Part I, subject to four listed exceptions and clarifications.
The four listed exceptions and clarifications, taken verbatim from RG 1.105 (as shown in italics), and discussions of each, as applicable to this license amendment application, are as follows: RG 1.105 Regulatory Position C.1 Section 4 of ISA-S67.04-1994 specifies the methods, but not the criterion, for combining uncertainties in determining a trip setpoint and its allowable values.The 95/95 tolerance limit is an acceptable criterion for uncertainties.
That is, there is a 95% probability that the constructed limits contain 95% of the -population of interest for the surveillance interval selected.A 95/95 tolerance is used to establish acceptable uncertainty values for the instrument strings. At the McGuire and Catawba Nuclear Stations, this is assured by means of the calculation methods, instrument string calibration, and setpoint U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 31 of 32 verification.
RG 1.105 Regulatory Position C.2 Sections 7 and 8 of Part 1 of ISA-S67.04-1994 reference several industry codes and standards.
If a referenced standard has been incorporated separately into the NRC's regulations, licensees and applicants must comply with that standard as set forth in the regulation.
If the referenced standard has been endorsed in a regulatory guide, the standard constitutes a method acceptable to the NRC staff of meeting a regulatory requirement as described in the regulatory guide. If a referenced standard has been neither incorporated into the NRC's regulations nor endorsed in a regulatory guide, licensees and applicants may consider and use the information in the referenced standard if appropriately justified, consistent with current regulatory practice.The setpoint calculation revisions supporting the proposed Technical Specification changes were performed in accordance with Duke Energy Engineering Directives Manual (EDM)-102, "Instrument Setpoint/Uncertainty Calculations," Revision 3. The methodology described in EDM-1 02 is appropriately justified and is consistent with industry practice.RG 1.105 Regulatory Position C.3 Section 4.3 of ISA-$67.04-1994 states that the limiting safety system setting (LSSS) may be maintained in technical specifications or appropriate plant procedures.
However, 10 CFR 50.36 states that the technical specifications will include items in the categories of safety limits, limiting safety system settings (LSSS), and limiting control settings.
Thus, the LSSS may not be maintained in plant procedures.
Rather, the LSSS must be specified as a technical-specification-defined limit in order to satisfy the requirements of 10 CFR 50.36. The LSSS should be developed in accordance with the setpoint methodology set forth in the standard, with the LSSS listed in the technical specifications.
In accordance with Section 4.3 of Part 1 of ISA S67.04-1994, the purpose of the LSSS is to assure that protective action is initiated before the process conditions reach the analytical limit. In addition, the LSSS may be the Allowable Value, the trip setpoint, or both. Consistent with NRC guidance, the LSSS are specified in the McGuire Nuclear Station and Catawba Nuclear Station Technical Specifications in the "Allowable Value" column of Technical Specification Table 3.3. 1-1, "Reactor Trip System Instrumentation".
In accordance with Section 4.3 of Part 1 of ISA S67.04-1994, the purpose of the LSSS is to assure that protective action is initiated before the process conditions reach the analytical limit. In addition, the LSSS may be the Allowable Value, the trip setpoint, or both. Consistent with NRC guidance, the LSSS are specified in the McGuire Nuclear Station and Catawba Nuclear Station Technical Specifications in the "Allowable Value" column of Technical Specification Table 3.3. 1-1, "Reactor Trip System Instrumentation".
RG 1.105 Regulatory Position C.4 ISA-$67.04-1994 provides a discussion on the purpose and application of an allowable value. The allowable value is the limiting value that the trip setpoint can have when tested periodically, beyond which the instrument channel is considered inoperable and corrective action must be taken in accordance with the technical specifications.
RG 1.105 Regulatory Position C.4 ISA-$67.04-1994 provides a discussion on the purpose and application of an allowable value. The allowable value is the limiting value that the trip setpoint can have when tested periodically, beyond which the instrument channel is considered inoperableand corrective action must be taken in accordancewith the technical specifications. The allowable value relationship to the setpoint methodology and testing requirementsin the technical specificationsmust be documented.
The allowable value relationship to the setpoint methodology and testing requirements in the technical specifications must be documented.
 
U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 32 of 32 The Allowable Value relationship to the setpoint methodology and testing requirements in the Technical Specifications is documented in the setpoint calculation.
U.S. Nuclear Regulatory Commission                                                         Enclosure 1 June 29, 2010                                                                             Page 32 of 32 The Allowable Value relationship to the setpoint methodology and testing requirements in the Technical Specifications is documented in the setpoint calculation. The setpoint calculation is maintained as part of plant records.
The setpoint calculation is maintained as part of plant records.5.3 Precedents None.Conclusion In conclusion, based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.6. ENVIRONMENTAL CONSIDERATION A review has determined that the proposed amendment would change a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, or would change an inspection or surveillance requirement.
5.3   Precedents None.
However, the proposed amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amounts of any effluents that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure.Accordingly, the proposed amendment meets the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22(c)(9).
Conclusion In conclusion, based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.
Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.
: 6. ENVIRONMENTAL CONSIDERATION A review has determined that the proposed amendment would change a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, or would change an inspection or surveillance requirement. However, the proposed amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amounts of any effluents that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure.
Accordingly, the proposed amendment meets the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22(c)(9). Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.
: 7. REFERENCES
: 7. REFERENCES
: 1. Technical Specification Task Force (TSTF) Standard Technical Specification Change Traveler, TSTF-493, Revision 4, "Clarify Application of Setpoint Methodology for LSSS Functions."
: 1. Technical Specification Task Force (TSTF) Standard Technical Specification Change Traveler, TSTF-493, Revision 4, "Clarify Application of Setpoint Methodology for LSSS Functions."
U.S. Nuclear Regulatory Commission June 29, 2010 ATTACHMENT la McGuire Units I and 2 Technical Specification Page Markups RTS Instrumentation


====3.3.1 SURVEILLANCE====
U.S. Nuclear Regulatory Commission June 29, 2010 ATTACHMENT la McGuire Units I and 2 Technical Specification Page Markups


REQUIREMENTS (continued)
RTS Instrumentation 3.3.1 SURVEILLANCE REQUIREMENTS (continued)
SURVEILLANCE FREQUENCY SR 3.3.1.4 ------------------
SURVEILLANCE                                   FREQUENCY SR 3.3.1.4       ------------------ NOTES         ------------------
NOTES ------------------
This Surveillance must be performed on the reactor trip bypass breaker prior to placing the bypass breaker in service.
This Surveillance must be performed on the reactor trip bypass breaker prior to placing the bypass breaker in service.Perform TADOT. 62 days on a STAGGERED TEST BASIS SR 3.3.1.5 Perform ACTUATION LOGIC TEST. 92 days on a STAGGERED TEST BASIS SR 3.3.1.6 ------------------
Perform TADOT.                                             62 days on a STAGGERED TEST BASIS SR 3.3.1.5     Perform ACTUATION LOGIC TEST.                             92 days on a STAGGERED TEST BASIS SR 3.3.1.6       ------------------ NOTES         ------------------
NOTES ------------------
Not required to be performed until 24 hours after THERMAL POWER is > 75% RTP.
Not required to be performed until 24 hours after THERMAL POWER is > 75% RTP.Calibrate excore channels to agree with incore detector 92 EFPD measurements.
Calibrate excore channels to agree with incore detector     92 EFPD measurements.
SR 3.3.1.7 -------------------
SR 3.3.1.7       ------------------- NOTES       ------------------
NOTES ------------------
Not required to be performed for source range instrumentation prior to entering MODE 3 from MODE 2 until 4 hours after entry into MODE 3.
Not required to be performed for source range instrumentation prior to entering MODE 3 from MODE 2 until 4 hours after entry into MODE 3.Perform COT. 184 days (continued)
Perform COT.                                               184 days (continued)
McGuire Units 1 and 2 3.3.1-10 Amendment Nos. 248/228 RTS Instrumentation
McGuire Units 1 and 2                   3.3.1-10                   Amendment Nos. 248/228


====3.3.1 SURVEILLANCE====
RTS Instrumentation 3.3.1 SURVEILLANCE REQUIREMENTS (continued)
SURVEILLANCE                                      FREQUENCY SR 3.3.1.9      ------------------- NOTES        ------------------
Verification of setpoint is not required.
Perform TADOT.                                                92 days SR 3.3.1.10      ------------------ NOTES        ------------------
This Surveillance shall include verification that the time constants are adjusted to the prescribed values.
Perform CHANNEL CALIBRATION.                                  18 months SR 3.3.1.11      ------------------ NOTES        ------------------
: 1.      Neutron detectors are excluded from CHANNEL CALIBRATION.
: 2.      Power and Intermediate Range Neutron Flux detector plateau voltage verification is not required to be performed prior to entry into MODE 1 or2.
Perform CHANNEL CALIBRATION.                                  18 months SR 3.3.1.12  Perform CHANNEL CALIBRATION.                                  18 months SR 3.3.1.13  Perform COT.                                                  18 months (continued)
McGuire Units 1 and 2                    3.3.1-12                    Amendment Nos. 184/166


REQUIREMENTS (continued)
MNS TS Table 3.3.1-1 INSERTS INSERT 1 (j) If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.
SURVEILLANCE FREQUENCY SR 3.3.1.9 -------------------
(k) The instrument channel. setpoint shall be reset to a value that is within the as-left tolerance around the Nominal Trip Setpoint (NTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the NTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (field setting) to confirm channel performance. The methodologies used to determine the as-found and the as-left tolerances are specified in the UFSAR.
NOTES ------------------
INSERT 2 A   The ->4E-1 1 amp Allowable Value, which applies to the Westinghouse-supplied compensated ion chamber Intermediate Range neutron detectors, is non-conservative. The compensated ion chamber neutron detectors are being replaced with Thermo Scientific-supplied fission chamber neutron detectors. Until the replacement occurs, an Allowable Value of > 4.8E-1 1 amp applies.
Verification of setpoint is not required.Perform TADOT. 92 days SR 3.3.1.10 ------------------
NOTES ------------------
This Surveillance shall include verification that the time constants are adjusted to the prescribed values.Perform CHANNEL CALIBRATION.
18 months SR 3.3.1.11 ------------------
NOTES ------------------
: 1. Neutron detectors are excluded from CHANNEL CALIBRATION.
: 2. Power and Intermediate Range Neutron Flux detector plateau voltage verification is not required to be performed prior to entry into MODE 1 or2.Perform CHANNEL CALIBRATION.
18 months SR 3.3.1.12 Perform CHANNEL CALIBRATION.
18 months SR 3.3.1.13 Perform COT. 18 months (continued)
McGuire Units 1 and 2 3.3.1-12 Amendment Nos. 184/166 MNS TS Table 3.3.1-1 INSERTS INSERT 1 (j) If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.(k) The instrument channel. setpoint shall be reset to a value that is within the as-left tolerance around the Nominal Trip Setpoint (NTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable.
Setpoints more conservative than the NTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (field setting) to confirm channel performance.
The methodologies used to determine the as-found and the as-left tolerances are specified in the UFSAR.INSERT 2 A The -> 4E-1 1 amp Allowable Value, which applies to the Westinghouse-supplied compensated ion chamber Intermediate Range neutron detectors, is non-conservative.
The compensated ion chamber neutron detectors are being replaced with Thermo Scientific-supplied fission chamber neutron detectors.
Until the replacement occurs, an Allowable Value of > 4.8E-1 1 amp applies.
RTS Instrumentation


====3.3.1 Table====
RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 1 of 7)
3.3.1-1 (page 1 of 7)Reactor Trip Sys ns en a on APPLICABLE MODES OR OTHER N MINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT 1. Manual Reactor Trip 2. Power Range Neutron Flux 1,2 3 (a), 4(a), 5 (a)2 2 B C SR 3.3.1.14 SR 3.3.1.14 NA NA NA NA a. High 1,2 4 D SR 3.3.1.1 SR 3.3.1.2 SR 3.3.1.7 SR 3.3.1.11 SR 3.3.1.16 E SR 3.3.1.1 SR 3.3.1.8 SR 3.3.1.11 SR 3.3.1.16< 110% RTP 109% RTP< 26% RTP 25% RTP b. Low 4 3. Power Range Neutron Flux Rate High Positive Rate 1,2 4 4. Intermediate Range Neutron Flux 1 (b), 2 (c)2 (d)2 2 2&#xfd;D SR 3.3.1.7 SR 3.3.1'.11 F,G SR 3.3.1.1 SR 3.3.1.8 SR 3.3.1.11 H SR 3.3.1.1 SR 3.3.1.8 SR 3.3.1.11 I,J SR 3.3.1.1 SR 3.3.1.8 SR 3.3.1.11 J,K SR 3.3.1.1 SR 3.3.1.7 SR 3.3.1.11 L SR 3.3.1.1 SR 3.3.1.11< 5.5% RTP with time constant> 2 sec< 30% RTP 25% RTP< 30% RTP 25% RTP< 1.3 E5 cps 1.0 E5 cps 5% RTP with time constant.> 2 sec 5. Source Range Neutron Flux 2 (d)3 (a), 4 (a), 5 (a)3 (e), 4 (e), 5 (e)2 1< 1.3 E5 cps N/A 1.0 E5 cps N/A (continued)(a)(b)(c)(d)(e)With Reactor Trip Breakers (RTBs) closed and Rod Control System capable of rod withdrawal.
Reactor Trip Sys     ns   en a on APPLICABLE MODES OR OTHER                                                                                     N MINAL SPECIFIED             REQUIRED                     SURVEILLANCE         ALLOWABLE             TRIP FUNCTION                 CONDITIONS               CHANNELS       CONDITIONS   REQUIREMENTS             VALUE           SETPOINT
Below the P-1 0 (Power Range Neutron Flux) interlocks.
: 1. Manual Reactor Trip                 1,2                   2              B      SR 3.3.1.14                NA                NA 3 (a), 4(a), 5 (a)           2               C     SR 3.3.1.14                 NA               NA
Above the P-6 (Intermediate Range Neutron Flux) interlocks.
: 2. Power Range Neutron Flux
Below the P-6 (Intermediate Range Neutron Flux) interlocks.
: a. High                           1,2                   4               D     SR 3.3.1.1           < 110% RTP          109% RTP SR 3.3.1.2 SR 3.3.1.7 SR 3.3.1.11 SR 3.3.1.16
With the RTBs open. In this condition, source range Function does not provide reactor trip but does provide indication.
: b. Low                                                  4              E     SR 3.3.1.1             < 26% RTP          25% RTP SR 3.3.1.8 SR 3.3.1.11 SR 3.3.1.16
McGuire Units 1.and 2 3.3.1-14 Amendment Nos. 194/175 RTS Instrumentation
: 3. Power Range Neutron Flux Rate High Positive Rate                 1,2                   4               &#xfd;D     SR 3.3.1.7             < 5.5% RTP          5% RTP SR 3.3.1'.11 with time        with time constant          constant
                                                                                                                  > 2 sec          .> 2 sec
: 4. Intermediate Range              1(b),    (c)              2              F,G     SR 3.3.1.1             < 30% RTP          25% RTP 2
Neutron Flux                                                                      SR 3.3.1.8 SR 3.3.1.11 (d)                  2              H     SR 3.3.1.1             < 30% RTP          25% RTP 2
SR 3.3.1.8 SR 3.3.1.11
: 5. Source Range                      2 (d)                  2              I,J   SR 3.3.1.1             < 1.3 E5 cps      1.0 E5 cps Neutron Flux                                                                      SR 3.3.1.8 SR 3.3.1.11 3 (a), 4 (a), 5 (a)            2              J,K     SR 3.3.1.1               < 1.3 E5            1.0 E5 SR 3.3.1.7                  cps              cps SR 3.3.1.11 3 (e), 4 (e), 5 (e)           1               L    SR 3.3.1.1                  N/A               N/A SR 3.3.1.11 (continued)
(a)   With Reactor Trip Breakers (RTBs) closed and Rod Control System capable of rod withdrawal.
(b)    Below the P-1 0 (Power Range Neutron Flux) interlocks.
(c)  Above the P-6 (Intermediate Range Neutron Flux) interlocks.
(d)    Below the P-6 (Intermediate Range Neutron Flux) interlocks.
(e)  With the RTBs open. In this condition, source range Function does not provide reactor trip but does provide indication.
McGuire Units 1.and 2                                       3.3.1-14                               Amendment Nos. 194/175


====3.3.1 Table====
RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 2 of 7)                                                   I Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER                                                                                 NOMINAL SPECIFIED           REQUIRED                          SURVEILLANCE        ALLOWABLE        TRIP FUNCTION              CONDITIONS           CHANNELS         CONDITIONS     REQUIREMENTS           VALUE     SETPOINT
3.3.1-1 (page 2 of 7)Reactor Trip System Instrumentation I APPLICABLE MODES OR OTHER SPECIFIED CONDITIONS REQUIRED CHANNELS CONDITIONS FUNCTION SURVEILLANCE REQUIREMENTS NOMINAL ALLOWABLE TRIP VALUE SETPOINT 6. Overtemperature AT 7. Overpower AT 1,2 1,2 4 4 E SR 3.3.1.1 SR 3.3.1.3 SR 3.3.1.6 SR 3.3.1.7 SR 3.3.1.12* SR 3.3.1.16 SR 3.3.1.17 E SR 3.3.1.1 SR 3.3.1.3 SR 3.3.1.6 SR 3.3.1.7 SR 3.3.1.12 SR 3.3.1.16 SR 3.3.1.17 Refer to Note 1 (Page 3.3.1-18)Refer to Note 2 (Page 3.3.1-19)Refer to Note 1 (Page, 3.3.1-18)Refer to Note 2 (Page 3.3.1-19)Pressurizer Pressure a. Low b. High 9. Pressurizer Water Level -High 10. Reactor Coolant Flow -Low a. Single Loop b. Two Loops 11. Undervoltage RCPs 1 (f)1,2 l(0)4 M 4 E 3 M 1945 psig 2385 psig 92%) " 88%88%5082 V 1 (g)1 (h)1 (f)3 per loop 3 per loop 1 per bus N M SR3.3.1.1 sR 3.3.1.7 ?SR 3 .3.1.106 SR 3 .3.1 .16ot M SR 3.3.1.9 SR 3.3.1.10 SR 3.3.1.16> 5016 V (continued)(f) Above the P-7 (Low Power Reactor Trips Block) interlock.(g) Above the P-8 (Power Range Neutron Flux) interlock.(h) Above the P-7 (Low Power Reactor Trips Block) interlock and below the P-8 (Power Range Neutron Flux) interlock.
: 6. Overtemperature AT             1,2                 4               E         SR 3.3.1.1             Refer to    Refer to SR 3.3.1.3           Note 1 (Page    Note 1 SR 3.3.1.6             3.3.1-18)      (Page, SR 3.3.1.7                         3.3.1-18)
3.3,1-15 Amendment Nos. 22224 RTS Instrumentation
SR 3.3.1.12
* SR 3.3.1.16 SR 3.3.1.17
: 7. Overpower AT                    1,2                  4              E         SR 3.3.1.1             Refer to    Refer to SR 3.3.1.3           Note 2 (Page    Note 2 SR 3.3.1.6             3.3.1-19)    (Page SR 3.3.1.7                          3.3.1-19)
SR 3.3.1.12 SR 3.3.1.16 SR 3.3.1.17 Pressurizer Pressure
: a. Low                       1(f)                4              M                                              1945 psig
: b. High                       1,2                  4              E                                            2385 psig
: 9. Pressurizer Water               l(0)                3              M                                                92%
Level - High
: 10. Reactor Coolant Flow -
                                                                                                                        )        "
Low
: a. Single Loop               1 (g)           3 per loop          N                                                88%
: b. Two Loops                1 (h)           3 per loop                     sR 3.3.1.7      ?                      88%
M         SR3.3.1.1 SR 3 .3.1
                                                                                          .3.1.106
                                                                                                .16ot
: 11. Undervoltage RCPs              1 (f)            1 per bus            M         SR 3.3.1.9             > 5016 V      5082 V SR 3.3.1.10 SR 3.3.1.16 (continued)
(f)   Above the P-7 (Low Power Reactor Trips Block) interlock.
(g)   Above the P-8 (Power Range Neutron Flux) interlock.
(h)   Above the P-7 (Low Power Reactor Trips Block) interlock and below the P-8 (Power Range Neutron Flux) interlock.
3.3,1-15                           Amendment Nos. 22224


====3.3.1 Table====
RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 3 of 7)
3.3.1-1 (page 3 of 7)Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT 12. Underfrequency RCPs 13. Steam Generator (SG) Water Level -Low Low 14. Turbine Trip a. Low Fluid Oil Pressure b. Turbine Stop Valve Closure 15. Safety Injection (SI)Input from Engineered Safety Feature Actuation System (ESFAS)16. Reactor Trip System Interlocks
Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER                                                                               NOMINAL SPECIFIED         REQUIRED                       SURVEILLANCE     ALLOWABLE           TRIP FUNCTION               CONDITIONS         CHANNELS       CONDITIONS     REQUIREMENTS           VALUE       SETPOINT
: a. Intermediate Range Neutron Flux, P-6 b. Low Power Reactor Trips Block, P-7 c. Power Range Neutron Flux, P-8 d. Power Range Neutron Flux, P-1 0 e. Turbine Impulse Pressure, P-13 1(0 1,2 1 per bus 4 per SG M ;SR 3.3.1.9 >5&.-9Hz 56.4 Hz S R 3 3:.3. 1.1054 SR 3.3.1.16 E R3.3. 1.1>4&/ 167 S R 3.3.1.7 X 16.7 SIR 3.3.1.16 1 (g)1 (g)3 4 O SR 3.3.1.10 SR 3.3.1.15 P .SR 3.3.1.10 SR 3.3.1.15 Q SR 3.3.1.5 SR 3.3.1.14> 42 psig 45 psig> 1% open > 1% open 1,2 2 trains NA NA 2 (d)2 S SR 3.3.1.11 > 4E-11E-1 0 amp SR 3.3.1.13 .D 1 per train 4 T SR 3.3.1.5 T .SR 3.3.1.11 SR 3.3.1.13 NA NA 1< 49% RTP 48% RTP 1,2 4 2 S SR 3.3.1.11 > 7% RTP SR 3.3.1.13 and < 11%RRT T SR 3.3.1.12 < W1 turbine SR 3.3.1.13 impulse pressure Dequivalent 10% RTP 10%turbine impulse pressure equivalent (continued)(d) Below the P-6 (Intermediate Range Neutron Flux) interlocks.
: 12. Underfrequency                 1(0               1 per bus                 M ;SR 3.3.1.9           >5&.-9Hz       56.4 Hz RCPs                                                                          SR 3 3:.3.
(0 Above the P-7 (Low Power Reactor Trips Block) interlock.
1.1054 SR 3.3.1.16
e 8 (Power Range Neutron Flux) interlock.
: 13. Steam Generator                  1,2              4 per SG                  E   R3.3.1.1>4&/                         167 (SG) Water Level -                                                            SR 3.3.1.7   X                         16.7 Low Low SIR 3.3.1.16
C UI nd2 3.3.1-16 b~JsER-Z'Amendment Nos. 494/+75 RTS Instrumentation
: 14. Turbine Trip
: a. Low Fluid Oil            1 (g)                 3             O       SR 3.3.1.10           > 42 psig      45 psig Pressure                                                                SR 3.3.1.15
: b. Turbine Stop              1 (g)                  4              P   . SR 3.3.1.10           > 1% open    > 1% open Valve Closure                                                          SR 3.3.1.15
: 15. Safety Injection (SI)            1,2              2 trains          Q       SR 3.3.1.5               NA            NA Input from Engineered                                                        SR 3.3.1.14 Safety Feature Actuation System (ESFAS)
: 16. Reactor Trip System Interlocks
: a. Intermediate              2 (d)                 2             S       SR 3.3.1.11         > 4E-11E-1           0 amp Range Neutron                                                          SR 3.3.1.13       .               D Flux, P-6
: b. Low Power                                  1 per train         T       SR 3.3.1.5               NA            NA Reactor Trips Block, P-7
: c. Power Range                1                    4              T . SR 3.3.1.11         < 49% RTP      48% RTP Neutron Flux,                                                          SR 3.3.1.13 P-8
: d. Power Range                1,2                   4             S       SR 3.3.1.11           > 7% RTP       10% RTP Neutron Flux,                                                          SR 3.3.1.13           and < 11%
P-1 0                                                                                            RRT
: e. Turbine Impulse                                  2              T       SR 3.3.1.12         < W1 turbine         10%
Pressure, P-13                                                          SR 3.3.1.13             impulse       turbine pressure       impulse Dequivalent     pressure equivalent (continued)
(d)   Below the P-6 (Intermediate Range Neutron Flux) interlocks.
(0   Above the P-7 (Low Power Reactor Trips Block) interlock.
e       8 (Power Range Neutron Flux) interlock.
C UI                 nd2                           3.3.1-16                           Amendment Nos. 494/+75 b~JsER-Z'


====3.3.1 Table====
RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 4 of 7)
3.3.1-1 (page 4 of 7)Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT 17. Reactor Trip 1,2 2 trains R, V SR 3.3.1.4 NA NA Breakers t') 3 (a), 4 (a), 5 (a) 2 trains C SR 3.3.1.4 NA NA 18. Reactor Trip Breaker 1,2 1 each per U SR 3.3.1.4 NA NA Undervoltage and RTB Shunt Trip Mechanisms 3 (a), 4 (a), 5 (a) 1 each per C SR 3.3.1.4 NA NA RTB 19. Automatic Trip Logic 1,2 2 trains Q, V SR 3.3.1.5 NA NA 3 (a), 4 (a), 5 (a) 2 trains C SR 3.3.1.5 NA NA (a) With RTBs closed and Rod Control System capable of rod withdrawal.(i) Including any reactor trip bypass breakers that are racked in and closed for bypassing an RTB.McGuire Units 1 and 2.3.3.1-17 Amendment Nos. 194/175 ESFAS Instrumentation
Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER                                                                           NOMINAL SPECIFIED             REQUIRED                       SURVEILLANCE   ALLOWABLE       TRIP FUNCTION                 CONDITIONS               CHANNELS       CONDITIONS   REQUIREMENTS       VALUE     SETPOINT
: 17. Reactor Trip                         1,2               2 trains         R, V     SR 3.3.1.4           NA         NA Breakerst ')                 3 (a), 4 (a), 5 (a)       2 trains           C       SR 3.3.1.4           NA         NA
: 18. Reactor Trip Breaker                 1,2             1 each per           U       SR 3.3.1.4           NA         NA Undervoltage and                                           RTB Shunt Trip Mechanisms                   3 (a), 4 (a), 5 (a)       1 each per           C       SR 3.3.1.4           NA         NA RTB
: 19. Automatic Trip Logic                 1,2               2 trains         Q, V     SR 3.3.1.5           NA         NA 3 (a), 4 (a), 5 (a)         2 trains           C       SR 3.3.1.5           NA         NA (a)   With RTBs closed and Rod Control System capable of rod withdrawal.
(i)   Including any reactor trip bypass breakers that are racked in and closed for bypassing an RTB.
McGuire Units 1 and 2.                                       3.3.1-17                           Amendment Nos. 194/175


====3.3.2 SURVEILLANCE====
ESFAS Instrumentation 3.3.2 SURVEILLANCE REQUIREMENTS
 
--------------------------                       NOTE---------------------------------
REQUIREMENTS
Refer to Table 3.3.2-1 to determine which SRs apply for each ESFAS Function.
--------------------------
SURVEILLANCE                                       FREQUENCY SR 3.3.2.1           Perform CHANNEL CHECK.                                       12 hours SR 3.3.2.2           Perform ACTUATION LOGIC TEST.                               92 days on a STAGGERED TEST BASIS SR 3.3.2.3           Perform COT.                                                 31 days SR 3.3.2.4           Perform MASTER RELAY TEST.                                   92 days on a STAGGERED TEST BASIS SR 3.3.2.5         Perform COT.                                                 184 days SR 3.3.2.6         Perform SLAVE RELAY TEST.                                     92 days SR 3.3.2.7             -------------------- NOTE       -----------------
NOTE---------------------------------
Refer to Table 3.3.2-1 to determine which SRs apply for each ESFAS Function.SURVEILLANCE FREQUENCY SR 3.3.2.1 Perform CHANNEL CHECK. 12 hours SR 3.3.2.2 Perform ACTUATION LOGIC TEST. 92 days on a STAGGERED TEST BASIS SR 3.3.2.3 Perform COT. 31 days SR 3.3.2.4 Perform MASTER RELAY TEST. 92 days on a STAGGERED TEST BASIS SR 3.3.2.5 Perform COT. 184 days SR 3.3.2.6 Perform SLAVE RELAY TEST. 92 days SR 3.3.2.7 --------------------
NOTE -----------------
Verification of setpoint not required for manual initiation functions.
Verification of setpoint not required for manual initiation functions.
Perform TADOT. 18 months (continued)
Perform TADOT.                                               18 months (continued)
McGuire Units 1 and 2 3.3.2-8 Amendment Nos., 250/230 ESFAS Instrumentation
McGuire Units 1 and 2                           3.3.2-8                       Amendment Nos., 250/230


====3.3.2 SURVEILLANCE====
ESFAS Instrumentation 3.3.2 SURVEILLANCE REQUIREMENTS (continued)
SURVEILLANCE                                      FREQUENCY SR 3.3.2.8      ------------------- NOTE        ------------------
This Surveillance shall include verification that the time constants are adjusted to the prescribed values.
Perform CHANNEL CALIBRATION.                                  18 months SR 3.3.2.9      ------------------- NOTE        ------------------
Not required to be performed for the turbine driven AFW pump until 24 hours after SG pressure is > 900 psig.
Verify ESFAS RESPONSE TIMES are within limit.                18 months on a STAGGERED TEST BASIS McGuire Units 1 and 2                    3.3.2-9                      Amendment Nos. 184/166


REQUIREMENTS (continued)
MNS TS Table 3.3.2-1 INSERTS INSERT 1 (f) If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.
SURVEILLANCE FREQUENCY SR 3.3.2.8 -------------------
(g) The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Nominal Trip Setpoint (NTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the NTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (field setting) to confirm channel performance. The methodologies used to determine the as-found and the as-left tolerances are specified in the UFSAR.
NOTE ------------------
This Surveillance shall include verification that the time constants are adjusted to the prescribed values.Perform CHANNEL CALIBRATION.
18 months SR 3.3.2.9 -------------------
NOTE ------------------
Not required to be performed for the turbine driven AFW pump until 24 hours after SG pressure is > 900 psig.Verify ESFAS RESPONSE TIMES are within limit. 18 months on a STAGGERED TEST BASIS McGuire Units 1 and 2 3.3.2-9 Amendment Nos. 184/166 MNS TS Table 3.3.2-1 INSERTS INSERT 1 (f) If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.(g) The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Nominal Trip Setpoint (NTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable.
Setpoints more conservative than the NTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (field setting) to confirm channel performance.
The methodologies used to determine the as-found and the as-left tolerances are specified in the UFSAR.
ESFAS Instrumentation


====3.3.2 Table====
ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 1 of 5)
3.3.2-1 (page 1 of 5)Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT 1 Safety Injection a. Manual Initiation
Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER                                                                             NOMINAL SPECIFIED         REQUIRED                       SURVEILLANCE     ALLOWABLE           TRIP FUNCTION               CONDITIONS           CHANNELS       CONDITIONS     REQUIREMENTS         VALUE       SETPOINT 1   Safety Injection
: b. Automatic Actuation Logic and Actuation Relays c. Containment Pressure -High d. Pressurizer Pressure -Low Low 2. Containment Spray a. Manual Initiation
: a. Manual Initiation         1,2,3,4                                B      SR 3.3.2.7              NA              NA
: b. Automatic Actuation Logic and Actuation Relays c. Containment Pressure -High High 3. Containment Isolation a. Phase A Isolation 1,2,3,4 1,2,3,4 1,2,3 2 trains 3 B SR 3.3.2.7 C SR 3.3.2.2 SR 3.3.2.4 SR 3.3.2.6 NA NA NA 4 D SR 3.3.2.1 < 1.2 psig 1.11IPsig SR 3.3.2.5 D SR 3.3.25 1-84psig 1845psig SR 3.3.2.80 1,2,3,4 1,2,3,4 1,2,3 1 per train, 2 trains 2 trains 4 B SR 3.3.2.7 C SR 3.3.2.2 SR 3.3.2.4 SR 3.3.2.6 E SR 3.3.2.1 SR 3.3.2.5 SR 3.3.2.8 SR 3.3.2.9 NA NA NA NA I< 3.0 psig 2.9 psig (1) Manual Initiation (2) Automatic Actuation Logic and Actuation Relays 1,2,3,4 1,2,3,4 2 2 trains B SR 3.3.2.7 C SR 3.3.2.2 SR 3.3.2.4 SR 3.3.2.6 NA NA NA NA (continued)(a) Above the P-1 1 (Pressurizer Pressure) interlock.
: b. Automatic                 1,2,3,4             2 trains           C       SR 3.3.2.2             NA Actuation Logic                                                          SR 3.3.2.4 and Actuation                                                            SR 3.3.2.6 Relays
Gir its and 2 3.3.2-10 Amendment Nos.,222/922 ESFAS Instrumentation
: c. Containment                1,2,3                  3              D       SR 3.3.2.1         < 1.2 psig       1.11IPsig Pressure - High                                                          SR 3.3.2.5 SR 3.3.2.80
: d. Pressurizer                                        4              D       SR 3.3.25           1-84psig       1845psig Pressure - Low Low
: 2. Containment Spray
: a. Manual Initiation          1,2,3,4           1 per train,         B     SR 3.3.2.7             NA              NA 2 trains
: b. Automatic                  1,2,3,4            2 trains          C       SR 3.3.2.2             NA              NA Actuation Logic                                                          SR 3.3.2.4 and Actuation                                                            SR 3.3.2.6 Relays
: c. Containment                1,2,3                  4              E     SR 3.3.2.1         < 3.0 psig      2.9 Ipsig Pressure - High                                                          SR 3.3.2.5 High                                                                      SR 3.3.2.8 SR 3.3.2.9
: 3. Containment Isolation
: a. Phase A Isolation (1) Manual                 1,2,3,4                 2             B     SR 3.3.2.7             NA              NA Initiation (2)  Automatic            1,2,3,4              2 trains          C     SR 3.3.2.2             NA              NA Actuation                                                          SR 3.3.2.4 Logic and                                                          SR 3.3.2.6 Actuation Relays (continued)
(a) Above the P-1 1 (Pressurizer Pressure) interlock.
Gir its       and 2                         3.3.2-10                         Amendment Nos.,222/922


====3.3.2 Table====
ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 2 of 5)
3.3.2-1 (page 2 of 5)Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT 3. Containment Isolation (continued)
Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER                                                                                         NOMINAL SPECIFIED         REQUIRED                             SURVEILLANCE         ALLOWABLE             TRIP FUNCTION               CONDITIONS           CHANNELS         CONDITIONS           REQUIREMENTS             VALUE       SETPOINT
(3) Safety Injection Refer to Function 1 (Safety Injection) for all initiation functions and requirements.
: 3. Containment Isolation (continued)
: b. Phase B Isolation (1) Manual Initiation (2) Automatic Actuation Logic and Actuation Relays (3) Containment-Pressure -High High 1,2,3,4 1,2,3,4 1 per train, 2 trains 2 trains B SR 3.3.2.7 C SR 3.3.2.2 SR 3.3.2.4 SR 3.3.2.6 E SR 3.3.2.1 SR 3.3.2.5 SR 3.3.2.8 NA NA NA NA 1,2,3 4< 3.0 psig .2.9 psig 4. Steam Line Isolation a. Manual Initiation (1) System (2) Individual'
(3)   Safety         Refer to Function 1 (Safety Injection) for all initiation functions and requirements.
: b. Automatic Actuation Logic and Actuation.
Injection
Relays c. Containment Pressure -High High 1, 2 (b), 3 (b)1, 2 (b), 3 (b)1 , 2 (b), 3 (b)112(b), 3(b)2 trains 1 per line 2 trains 4 F SR 3.3.2.7 G SR 3.3.2.7 H SR 3.3.2.2 SR 3.3.2.4 SR 3.3.2.6 E SR 3.3.2.1 SR 3.3.2.5 SR 3.3.2.8 SR 3.3.2.9 NA NA NA< 3.0 psig NA NA NA 2.9 psig 775 psig (continued)
: b. Phase B Isolation (1) Manual Initiation           1,2,3,4         1 per train,           B             SR 3.3.2.7                 NA              NA 2 trains (2)  Automatic            1,2,3,4          2 trains              C             SR 3.3.2.2                 NA              NA Actuation                                                                  SR 3.3.2.4 Logic and                                                                  SR 3.3.2.6 Actuation Relays (3)  Containment-            1,2,3                4                E             SR 3.3.2.1               < 3.0 psig . 2.9 psig Pressure -                                                                  SR 3.3.2.5 High High                                                                  SR 3.3.2.8
: d. Steam Line Pressure (1) Low 1, 2 (b), 3 (a)(b) 3 per steam line D (a) Above the P-11 (Pressurizer Pressure) interlock.(b) Except when all MSIVs are closed and de-activated.
: 4. Steam Line Isolation
c ui e UnI s 1 and 2 3.3.2-11 Amendment Nos. .
: a. Manual Initiation (1) System             1,2 (b), 3 (b)       2 trains              F            SR 3.3.2.7                  NA            NA (2) Individual'        1,2 (b), 3 (b)     1 per line             G            SR 3.3.2.7                   NA            NA
ESFAS Instrumentation
: b. Automatic                    (b), 3 (b)      2 trains              H             SR 3.3.2.2                   NA            NA 1 ,2 Actuation Logic                                                                  SR 3.3.2.4 and Actuation.                                                                  SR 3.3.2.6 Relays
: c. Containment            112(b), 3(b)              4                E             SR 3.3.2.1               < 3.0          2.9 psig Pressure - High                                                                  SR 3.3.2.5                 psig High                                                                            SR 3.3.2.8 SR 3.3.2.9
: d. Steam Line Pressure (1) Low             1, 2 (b),   (a)(b)   3 per steam             D                                                      775 psig 3
line (continued)
(a) Above the P-11 (Pressurizer Pressure) interlock.
(b) Except when all MSIVs are closed and de-activated.
c ui e UnI s 1 and 2                                 3.3.2-11                                 Amendment Nos. .


====3.3.2 Table====
ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 3 of 5)
3.3.2-1 (page 3 of 5)Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT 4. Steam Line Isolation (continued)
Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER                                                                                     NOMINAL SPECIFIED           REQUIRED                           SURVEILLANCE           ALLOWABLE         TRIP FUNCTION                 CONDITIONS             CHANNELS       CONDITIONS           REQUIREMENTS             VALUE       SETPOINT
(2) Negative Rate -High 5. Turbine Trip and Feedwater Isolation a. Turbine Trip (1) Automatic Actuation Logic and Actuation Relays (2) SG Water Level-High High (P-14)(3) Safety Injection b. Feedwater Isolation 3 (b)(c)3 per steam line D SR3322N 1 0 0 (d) psi 1,2 1,2 2 trains 3 per SG I SR 3.3.2.2 NA SR 3.3.2.4 SR 3.3.2.6 NA 83.9%Refer to Function 1 (Safety Injection) for all initiation functions and requirements.
: 4. Steam Line Isolation (continued)
See item 5.a.(1) for Applicable MODES.(1) Automatic Actuation Logic and Actuation Relays (2) SG Water Level-High High (P-14)1 , 2 (e), 3 (e)1 , 2 (e), 3 (e)2 trains 3 per SG H SR 3.3.2.2 NA NA SR 3.3.2.4 SR 3.3.2.6 D SR 3.3.2.1 < &S-6 83.9%SR 3.3.2.2 SIR 3.3.2.4 af.o SR 3.3.2.51 'SR 3.3.2.6 SIR 3.3.2.8 SR 3.3.2.9 (continued)(b) Except when all MSIVs are closed and de-activated.(c) Trip function automatically blocked above P-11 (Pressurizer Pressure) interlock and may be blocked below P-11 when Steam Line Isolation Steam Line Pressure-Low is not blocked.(d) Time constant utilized in the rate/lag controller is > 50 seconds.(e) Except when all MFIVs, MFCVs, and associated bypass valves are closed and de-activated or isolated by a closed manual valve.McGuire Uni s 1 and 2 3.3.2-12 Amendment Nos. 224Q,296-ESFAS Instrumentation
(2)   Negative               3 (b)(c)        3 per steam            D            SR3322N                                    (d) psi 100 Rate - High                                 line
: 5. Turbine Trip and Feedwater Isolation
: a. Turbine Trip (1) Automatic                   1,2             2 trains                   I   SR 3.3.2.2                 NA             NA Actuation                                                                    SR 3.3.2.4 Logic and                                                                    SR 3.3.2.6 Actuation Relays (2) SG Water                    1,2            3 per SG                                                                  83.9%
Level-High High (P-14)
(3) Safety          Refer to Function 1 (Safety Injection) for all initiation functions and requirements. See item Injection      5.a.(1) for Applicable MODES.
: b. Feedwater Isolation (1) Automatic             1 ,2 (e), 3 (e)       2 trains           H           SR 3.3.2.2                 NA             NA Actuation                                                                    SR 3.3.2.4 Logic and                                                                    SR 3.3.2.6 Actuation Relays D     SR 3.3.2.1               < &S-6       83.9%
(2) SG Water              1 ,2 (e), 3 (e)      3 per SG Level-High                                                                    SR 3.3.2.2 High (P-14)                                                                  SIR 3.3.2.4 af.o SR 3.3.2.51     '
SR 3.3.2.6 SIR 3.3.2.8 SR 3.3.2.9 (continued)
(b) Except when all MSIVs are closed and de-activated.
(c) Trip function automatically blocked above P-11 (Pressurizer Pressure) interlock and may be blocked below P-11 when Steam Line Isolation Steam Line Pressure-Low is not blocked.
(d) Time constant utilized in the rate/lag controller is > 50 seconds.
(e) Except when all MFIVs, MFCVs, and associated bypass valves are closed and de-activated or isolated by a closed manual valve.
McGuire Uni s 1 and 2                                     3.3.2-12                                 Amendment Nos. 224Q,296-


====3.3.2 Table====
ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 4 of 5)
3.3.2-1 (page 4 of 5)Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT 5. Turbine Trip and Feedwater Isolation (continued)
Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER                                                                                             NOMINAL SPECIFIED         REQUIRED                               SURVEILLANCE         ALLOWABLE             TRIP FUNCTION               CONDITIONS           CHANNELS         CONDITIONS           REQUIREMENTS               VALUE         SETPOINT
(3) Safety Injection (4) Tavg-Low coincident with Reactor Trip, P-4 (5) Doghouse Water Level-High High 6. Auxiliary Feedwater a. Automatic Actuation Logic and Actuation Relays b. SG Water Level -Low Low c. Safety Injection Refer to Function 1 (Safety Injection) for all initiation functions and re uirements.
: 5. Turbine Trip and Feedwater Isolation (continued)
See Ite 5.b.(1) for Applicable MODES.1,2(e) 1 per loop J SR 3.3.2.1 X! > 5&deg;F 553*F SR 3.3.2.5 (f(SR 3...&#xfd;)J Refer to Function 8.a (Reactor Trip, P-4) for all initiation functions and requirements.
(3) Safety         Refer to Function 1 (Safety Injection) for all initiation functions and re uirements. See Ite Injection    5.b.(1) for Applicable MODES.
2 per train per Doghouse 2 trains 4 per SG L,M SR 3.3.2.1 SR 3.3.2.7< 13 inches 12 inches 1,2,3 1,2,3 H SR 3.3.2.2 SR 3.3.2.4 SR 3.3.2.6 NA NA D 16.7%Refer to Function 1 (Safety Injection) for all initiation functions and requirements.
(4) Tavg-Low              1,2(e)           1 per loop             J             SR 3.3.2.1   X!           > 5&deg;F             553*F SR 3.3.2 .5(f(
: d. Station Blackout (1) Loss of voltage (2) Degraded Voltage 1,2,3 1,2,3 3 per bus 3 per bus D SR 3.3.2.7 SR 3.3.2.9 D SR 3.3.2.7 SR 3.3.2.9> 3122 V (Unit 1)> 3108 V (Unit 2) with 8.5 +/- 0.5 sec time delay> 3661 V (Unit 1)> 3685.5 V (Unit 2)with < 11 sec with SI and< 600 sec without SI time delay 3174 V (Unit 1)3157 V (Unit 2) +/-45 V with 8.5 +/- 0.5 sec time delay 3678.5 V (Unit 1)3703 V (Unit 2)with < 11 sec with SI and < 600 sec without SI time delay (continued)(e) Except when all MFIVs, MFCVs, and associated bypass valves are closed and de-activated or isolated by a closed manual Units 1 and 2 3.3.2-13 Amendment Nos.22-2--
SR 3...&#xfd;)J coincident with    Refer to Function 8.a (Reactor Trip, P-4) for all initiation functions and Reactor Trip, P-4  requirements.
ESFAS Instrumentation
(5) Doghouse                                2 per train           L,M           SR 3.3.2.1               < 13 inches      12 inches Water Level-                              per                              SR 3.3.2.7 High High                            Doghouse
: 6. Auxiliary Feedwater
: a. Automatic                  1,2,3             2 trains              H           SR 3.3.2.2                     NA              NA Actuation Logic                                                                  SR 3.3.2.4 and Actuation                                                                    SR 3.3.2.6 Relays
: b. SG Water Level -          1,2,3            4 per SG              D                                                         16.7%
Low Low
: c. Safety Injection  Refer to Function 1 (Safety Injection) for all initiation functions and requirements.
: d. Station Blackout (1)   Loss of             1,2,3           3 per bus               D             SR 3.3.2.7               > 3122 V          3174 V voltage                                                                    SR 3.3.2.9                 (Unit 1)        (Unit 1)
                                                                                                                    > 3108 V          3157 V (Unit 2) with     (Unit 2) +/-
8.5 +/- 0.5 sec     45 V with time delay       8.5 +/- 0.5 sec time delay (2)  Degraded            1,2,3          3 per bus              D            SR 3.3.2.7                > 3661 V        3678.5 V Voltage                                                                    SR 3.3.2.9                (Unit 1)        (Unit 1)
                                                                                                                  > 3685.5 V          3703 V (Unit 2)        (Unit 2) with < 11 sec       with < 11 with SI and     sec with SI
                                                                                                                    < 600 sec       and < 600 without SI      sec without time delay        SI time delay (continued)
(e) Except when all MFIVs, MFCVs, and associated bypass valves are closed and de-activated or isolated by a closed manual Units 1 and 2                             3.3.2-13                                   Amendment Nos.22-2--


====3.3.2 Table====
ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 5 of 5)
3.3.2-1 (page 5 of 5)Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT 6. Auxiliary Feedwater (continued)
Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER                                                                                         NOMINAL SPECIFIED         REQUIRED                               SURVEILLANCE           ALLOWABLE         TRIP FUNCTION             CONDITIONS           CHANNELS         CONDITIONS           REQUIREMENTS               VALUE     SETPOINT
: e. Trip of all Main Feedwater Pumps f. Auxiliary Feedwater Pump Suction Transfer on Suction Pressure -Low 7. Automatic Switchover to Containment Sump a. Refueling Water Storage Tank (RWST) Level -Low Coincident with Safety Injection 8. ESFAS Interlocks
: 6. Auxiliary Feedwater (continued)
: a. Reactor Trip,'P-4 b. Pressurizer Pressure, P-11 c. Tavg -Low Low, P-12 9. Containment Pressure Control System 1,2 1,2,3 1 per MFW pump 2 per MDP, 4 per TDP K SR 3.3.2.7 SR 3.3.2.9 N,O SR 3.3.2.7 SR 3.3.2.8 SR 3.32.9 NA> 3 psig NA 3.5 psig 1,2,3 3 P,S SR 3.3.2.1 SR 3.3.2.3 SR 3.3.2.8 SR 3.3.2.9> 175.85 inches 180 inches Refer to Function 1 (Safety Injection) for all initiation functions and requirements.
: e. Trip of all Main           1,2           1 per MFW               K           SR 3.3.2.7                     NA          NA Feedwater                                      pump                              SR 3.3.2.9 Pumps
1,2,3 1,2,3 1,2,3 1 per train, 2 trains 3 1 per loop F SR 3.3.2.7 NA NA Q SR 3.3.2.5 < >Q,6-psig 1955 psig SIR 3.3.2.8 Q SR 3.3.2.5 > 5&1 0 F 553'F SR 3.3.2.8 1,2,3,4 4 per train, 2 trains R SR 3.3.2.1 SR 3.3.2.3.SR 3.3.2.8 Refer to Note 1 on Page 3.3.2-14 Refer to Note 1 on page 3.3.2-14 NOTE 1: The Trip Setpoint for the Containment Pressure Control System start permissive/termination (SP/T) shall be > 0.3 psig and < 0.4 psig. The allowable value for the SP/T shall be > 0.25 psig and < 0.45 psig.McGuire Units 1 and 2 3.3.2-14 Amendment Nos. 22-0e U.S. Nuclear Regulatory Commission June 29, 2010 ATTACHMENT lb Catawba Units I and 2 Technical Specification Page Markups RTS Instrumentation
: f. Auxiliary                1,2,3          2 per MDP,              N,O           SR 3.3.2.7                 > 3 psig      3.5 psig Feedwater Pump                            4 per TDP                            SR 3.3.2.8 Suction Transfer                                                                SR 3.32.9 on Suction Pressure - Low
: 7. Automatic Switchover to Containment Sump
: a. Refueling Water            1,2,3                 3               P,S           SR   3.3.2.1               > 175.85    180 inches Storage Tank                                                                    SR   3.3.2.3                 inches (RWST) Level -                                                                  SR   3.3.2.8 Low                                                                              SR   3.3.2.9 Coincident with    Refer to Function 1 (Safety Injection) for all initiation functions and requirements.
Safety Injection
: 8. ESFAS Interlocks
: a. Reactor Trip,           1,2,3           1 per train,           F           SR 3.3.2.7                     NA         NA
            'P-4                                        2 trains
: b. Pressurizer            1,2,3                  3                Q           SR 3.3.2.5               < >Q,6-psig 1955 psig Pressure, P-11                                                                SIR 3.3.2.8 0
: c. Tavg - Low Low,          1,2,3            1 per loop              Q           SR 3.3.2.5                 > 5&1F      553'F P-12                                                                          SR 3.3.2.8
: 9. Containment                  1,2,3,4         4 per train,             R           SR 3.3.2.1             Refer to Note Refer to Note Pressure Control                                2 trains                          SR 3.3.2.3.               1 on Page  1 on page System                                                                              SR 3.3.2.8                 3.3.2-14   3.3.2-14 NOTE 1:         The Trip Setpoint for the Containment Pressure Control System start permissive/termination (SP/T) shall be > 0.3 psig and < 0.4 psig. The allowable value for the SP/T shall be > 0.25 psig and < 0.45 psig.
McGuire Units 1 and 2                                   3.3.2-14                                 Amendment Nos. 22-0e


====3.3.1 SURVEILLANCE====
U.S. Nuclear Regulatory Commission June 29, 2010 ATTACHMENT lb Catawba Units I and 2 Technical Specification Page Markups


REQUIREMENTS (continued)
RTS Instrumentation 3.3.1 SURVEILLANCE REQUIREMENTS (continued)
SURVEILLANCE FREQUENCY SR 3.3.1.4 ---------------------
SURVEILLANCE                                     FREQUENCY SR 3.3.1.4       --------------------- NOTE-----------------
NOTE-----------------
This Surveillance must be performed on the reactor trip bypass breaker prior to placing the bypass breaker in service.
This Surveillance must be performed on the reactor trip bypass breaker prior to placing the bypass breaker in service.Perform TADOT. 62 days on a STAGGERED TEST BASIS*SR 3.3.1.5 Perform ACTUATION LOGIC TEST. 92 days on a STAGGERED TEST BASIS SR 3.3.1.6 ---------------------
Perform TADOT.                                               62 days on a STAGGERED TEST BASIS*
NOTE-----------------
SR 3.3.1.5   Perform ACTUATION LOGIC TEST.                               92 days on a STAGGERED TEST BASIS SR 3.3.1.6       --------------------- NOTE-----------------
Not required to be performed until 24 hours after THERMAL POWER is > 75% RTP.Calibrate excore channels to agree with incore detector 92 EFPD measurements.
Not required to be performed until 24 hours after THERMAL POWER is > 75% RTP.
SR 3.3.1.7 ---------------------
Calibrate excore channels to agree with incore detector     92 EFPD measurements.
NOTE-----------------
SR 3.3.1.7       --------------------- NOTE-----------------
Not required to be performed for source range instrumentation prior to entering MODE 3 from MODE 2 until 4 hours after entry into MODE 3.Perform COT. 184 days (continued)
Not required to be performed for source range instrumentation prior to entering MODE 3 from MODE 2 until 4 hours after entry into MODE 3.
Perform COT.                                                 184 days (continued)
* The SR 3.3.1.4 Frequency of "62 days on a STAGGERED TEST BASIS" as it applies to Unit 2 Train 2A and Train 2B reactor trip breaker testing may be extended on a one-time basis to March 10, 2009 at 0500 hours, upon which Unit 2 shall be in Mode 3 with reactor trip breakers open for the End of Cycle 16 Refueling Outage. Upon entry into Mode 3 with reactor trip breakers open for this refueling outage, this extension shall expire. The provisions of SR 3.0.2 are not applicable to this extension.
* The SR 3.3.1.4 Frequency of "62 days on a STAGGERED TEST BASIS" as it applies to Unit 2 Train 2A and Train 2B reactor trip breaker testing may be extended on a one-time basis to March 10, 2009 at 0500 hours, upon which Unit 2 shall be in Mode 3 with reactor trip breakers open for the End of Cycle 16 Refueling Outage. Upon entry into Mode 3 with reactor trip breakers open for this refueling outage, this extension shall expire. The provisions of SR 3.0.2 are not applicable to this extension.
(\l 0 C ca~je~J Pa~j4 ,o'-v'c~)
(\l 0 C   ca~je~J Pa~j4     ,o'-v'c~)           c4t Catawba Units 1 and 2                     3.3.1-10           Amendment Nos. 248/242
c4t Catawba Units 1 and 2 3.3.1-10 Amendment Nos. 248/242 RTS Instrumentation
 
====3.3.1 SURVEILLANCE====


REQUIREMENTS (continued)
RTS Instrumentation 3.3.1 SURVEILLANCE REQUIREMENTS (continued)
SURVEILLANCE FREQUENCY SR 3.3.1.8-------------------
SURVEILLANCE                                       FREQUENCY SR 3.3.1.8       ------------------- NOTE             -----------------
NOTE -----------------
This Surveillance shall include verification that interlocks P-6 (for the Intermediate Range channels) and P-10 (for the Power Range channels) are in their required state for existing unit conditions.
This Surveillance shall include verification that interlocks P-6 (for the Intermediate Range channels) and P-10 (for the Power Range channels) are in their required state for existing unit conditions.
Perform COT.--------
Perform COT                                                       .--------
NOTE -------Only required when not performed within previous 184 days Prior to reactor startup AND Four hours after reducing power below P-10 for power and intermediate range instrumentation AND Four hours after reducing power below P-6 for source range instrumentation AND Every 184 days thereafter (continued)
NOTE-------
Catawba Units 1 and 2 3.3.1-11 Amendment Nos. 247/240 RTS Instrumentation
Only required when not performed within previous 184 days Prior to reactor startup AND Four hours after reducing power below P-10 for power and intermediate range instrumentation AND Four hours after reducing power below P-6 for source range instrumentation AND Every 184 days thereafter (continued)
Catawba Units 1 and 2                   3.3.1-11             Amendment Nos. 247/240


====3.3.1 SURVEILLANCE====
RTS Instrumentation 3.3.1 SURVEILLANCE REQUIREMENTS (continued)
SURVEILLANCE                                      FREQUENCY SR 3.3.1.9      --------------------- NOTE            -----------------
Verification of setpoint is not required.
Perform TADOT.                                                92 days SR 3.3.1.10      -------------------- NOTE            -----------------
This Surveillance shall include verification that the time constants are adjusted to the prescribed values.
Perform CHANNEL CALIBRATION.                                  18 months SR 3.3.1.11      -------------------- NOTE            -----------------
: 1.      Neutron detectors are excluded from CHANNEL CALIBRATION.
: 2.      Power and Intermediate Range Neutron Flux detector plateau voltage verification is not required to be performed prior to entry into MODE 1 or2.
Perform CHANNEL CALIBRATION.                                  18 months SR 3.3.1.12  Perform CHANNEL CALIBRATION.                                  18 months SR 3.3.1.13  Perform COT.                                                  18 months (continued)
Catawba Units 1 and 2                    3.3.1-12              Amendment Nos. 173/165


REQUIREMENTS (continued)
CNS TS Table 3.3.1-1 INSERTS INSERT 1 (I) If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.
SURVEILLANCE FREQUENCY SR 3.3.1.9 ---------------------
(m) The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Nominal Trip Setpoint (NTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the NTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (field setting) to confirm channel performance. The methodologies used to determine the as-found and the as-left tolerances are specified in the UFSAR.
NOTE -----------------
INSERT 2 A   The > 6E-1 1 amp Allowable Value, which applies to the Westinghouse-supplied compensated ion chamber Intermediate Range neutron detectors, is non-conservative. The compensated ion chamber neutron detectors are being replaced with Thermo Scientific-supplied fission chamber neutron detectors. Until the replacement occurs, an Allowable Value of > 6.9E-1 1 amp applies.
Verification of setpoint is not required.Perform TADOT. 92 days SR 3.3.1.10 --------------------
NOTE -----------------
This Surveillance shall include verification that the time constants are adjusted to the prescribed values.Perform CHANNEL CALIBRATION.
18 months SR 3.3.1.11 --------------------
NOTE -----------------
: 1. Neutron detectors are excluded from CHANNEL CALIBRATION.
: 2. Power and Intermediate Range Neutron Flux detector plateau voltage verification is not required to be performed prior to entry into MODE 1 or2.Perform CHANNEL CALIBRATION.
18 months SR 3.3.1.12 Perform CHANNEL CALIBRATION.
18 months SR 3.3.1.13 Perform COT. 18 months (continued)
Catawba Units 1 and 2 3.3.1-12 Amendment Nos. 173/165 CNS TS Table 3.3.1-1 INSERTS INSERT 1 (I) If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.(m) The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Nominal Trip Setpoint (NTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable.
Setpoints more conservative than the NTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (field setting) to confirm channel performance.
The methodologies used to determine the as-found and the as-left tolerances are specified in the UFSAR.INSERT 2 A The > 6E-1 1 amp Allowable Value, which applies to the Westinghouse-supplied compensated ion chamber Intermediate Range neutron detectors, is non-conservative.
The compensated ion chamber neutron detectors are being replaced with Thermo Scientific-supplied fission chamber neutron detectors.
Until the replacement occurs, an Allowable Value of > 6.9E-1 1 amp applies.
RTS Instrumentation


====3.3.1 Table====
RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 1 of 7)
3.3.1-1 (page 1 of 7)Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT 1. Manual Reactor Trip 1,2 3 (a), 4 (a), 5 (a)2 2 B SR 3.3.1.14 C .SR 3.3.1.14 NA NA NA NA 2. Power Range Neutron Flux a. High 1,2 D 109% RTP 25% RTP b. Low 4 E 3. Power Range Neutron Flux High Positive Rate 1.2 4 D SR 3.3.1.7 SR 3.3.1.11< 6.3% RTP with time constant> 2 sec 5% RTP with time constant>_ 2 sec 4. Intermediate Range Neutron Flux 1 (b), 2 (c)2 (d)2 (d)5. Source Range Neutron Flux 2 2 2 2 4 F,G H SR 3.3.1.1 SR 3.3.1.8 SR 3.3.1.11 I,J SR 3.3.1.1 SR 3.3.1.8 SR 3.3.1.11 SR 3.3.1.1 SR 3.3.1.8 SR 33.1.1131% RTP 25% RTP< 31% RTP 25% RTP< 1.4 E5 cps 1.0 E5 cps 3 (a), 4 (a), 5 (a)6. Overtemperature AT 1,2 J,K SIR 3.3.1.1 1.4 E5 SIR 3.3.1.7 cps SIR 3.3. 1.11 E SRF3.3.1.1 Refer to SR 3.3.1.3 Note 1 (Page SI3.3.1-18)
Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER                                                                                     NOMINAL SPECIFIED           REQUIRED                         SURVEILLANCE       ALLOWABLE             TRIP FUNCTION               CONDITIONS           CHANNELS         CONDITIONS       REQUIREMENTS           VALUE         SETPOINT
SIR 3.3.1.16 SIR 3.3.1.17 1.0 E5 cps Refer to Note 1 (Page 3.3.1-18)(continued)(a) With Reactor Trip Breakers (RTBs) closed and Rod Control System capable of rod withdrawal.(b) Below the P-10 (Power Range Neutron Flux) interlocks.(c) Above the P-6 (Intermediate Range Neutron Flux) interlocks.(d) Below the P-6 (Intermediate Range Neutron Flux) interlocks.
: 1. Manual Reactor Trip               1,2               2                B          SR 3.3.1.14                NA              NA 3 (a), 4 (a), 5 (a)       2               C     . SR 3.3.1.14               NA               NA
a 3.3.1-14 Amendment Nos. +79M-71 RTS Instrumentation
: 2. Power Range Neutron Flux
: a. High                         1,2                                 D                                                 109% RTP
: b. Low                                             4               E                                                 25% RTP
: 3. Power Range Neutron Flux High Positive Rate                 1.2               4               D         SR 3.3.1.7           < 6.3% RTP          5% RTP SR 3.3.1.11           with time        with time constant         constant
                                                                                                                > 2 sec         >_2 sec
: 4. Intermediate Range           1(b),     (c)           2             F,G         SR 3.3.1.1           *31% RTP          25% RTP 2
Neutron Flux                                                                    SR 3.3.1.8 SR 33.1.11 2  (d)              2              H          SR 3.3.1.1           < 31% RTP        25% RTP SR 3.3.1.8 SR 3.3.1.11
: 5. Source Range                    2  (d)              2              I,J        SR 3.3.1.1           *< 1.4 E5 cps      1.0 E5 cps Neutron Flux                                                                    SR 3.3.1.8 SR 3.3.1.11 3 (a), 4 (a), 5 (a)         2             J,K         SIR 3.3.1.1
* 1.4 E5       1.0 E5 cps SIR 3.3.1.7               cps SIR 3.3. 1.11
: 6. Overtemperature AT                1,2                4                E         SRF3.3.1.1             Refer to          Refer to SR 3.3.1.3           Note 1 (Page          Note 1 (Page SI3.3.1-18)                      3.3.1-18)
SIR 3.3.1.16 SIR 3.3.1.17 (continued)
(a) With Reactor Trip Breakers (RTBs) closed and Rod Control System capable of rod withdrawal.
(b) Below the P-10 (Power Range Neutron Flux) interlocks.
(c) Above the P-6 (Intermediate Range Neutron Flux) interlocks.
(d) Below the P-6 (Intermediate Range Neutron Flux) interlocks.
a                                                   3.3.1-14                             Amendment Nos. +79M-71


====3.3.1 Table====
RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 2 of 7)
3.3.1-1 (page 2 of 7)Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT 7. Overpower AT 1,2 4 E SR 3.3.1.1 SR 3.3.1.3 SR 3.3.1.6 SR 3.3.1.7 SR 3.3.1.10 SR 3.3.1.16 SR 3.3.1.17 Refer to Note 2 (Page 3.3.1-19)Refer to Note 2 (Page 3.3.1-19)8. Pressurizer Pressure a. Low 1 (e) 4 b. High 1,2 4 9. Pressurizer Water 1 (e) 3 Level -High 10. Reactor Coolant Flow -Low a. Single Loop 1 (g) 3 per loop b. Two Loops l(h) 3 per loop 14M(f) psig L SR 3.3.1.1 SSR a3.3. 1 .7 SR SR 3.3.1.16 1945(f)0 psig Z 3 S2-399 psig ESR 3.3.1.1 SR 3.3.1.7 ( ) 'SR 3.3.1.10" )SR 3.3.1.16 2385 psig I 9Z.7 9-3Z -7 L SR 3.311A1 SR 3.3.1.7 (6)&-i)SR 3.3.1.10 92%1701 M SR 3.3.1.1 SR 3.3.1.7 SR 3.3.1+10 (J/'SR 3.3.1.16 91% 1 90.. S" 1_ -0..7 L SR 3.3.1.1 SR 3.3.1.7 ()(SR 3.3. 1.10 'SR 3.3.1.16 91% 1 (e) Above the P-7 (Low Power Reactor Trips Block) interlock.(f) Time constants utilized in the lead-lag controller for Pressurizer Pressure -Low are 2 seconds for lead and I second for lag.(g) Above the P-8 (Power Range Neutron Flux) interlock.(h) Above the P-7 (Low Power Reactor Trips Block) interlock and below the P-8 (Power Range Neutron Flux) interlock.
Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER                                                                                         NOMINAL SPECIFIED             REQUIRED                           SURVEILLANCE         ALLOWABLE             TRIP FUNCTION                 CONDITIONS           CHANNELS         CONDITIONS       REQUIREMENTS             VALUE           SETPOINT
1,jSE l Catawba Units 1 and 2 3.3.1-15 Amendment Nos. +79M--1 RTS Instrumentation
: 7. Overpower AT                     1,2                   4               E         SR 3.3.1.1               Refer to        Refer to SR 3.3.1.3             Note 2 (Page        Note 2 SR 3.3.1.6               3.3.1-19)          (Page SR 3.3.1.7                                3.3.1-19)
SR 3.3.1.10 SR  3.3.1.16 SR  3.3.1.17
: 8. Pressurizer Pressure
: a. Low                         1 (e)                 4                       L  SR 3.3.1.1 a3.3. 1.7 SSR          (ltX.v*)
14M(f) psig        1945(f)0 psig SR 3.31110(f)C/*
SR 3.3.1.16 Z3
: b. High                        1,2                  4                ESR            3.3.1.1              S2-399 psig       2385 psig  I SR 3.3.1.7 ( )       '
SR 3.3.1.10"       )
SR 3.3.1.16 9Z. 7 9-3Z -7
: 9. Pressurizer Water                1 (e)                3                L           SR 3.311A1                                     92%
Level - High                                                                        SR 3.3.1.7 (6)&-i)
SR 3.3.1.10
: 10. Reactor Coolant Flow - Low 1701
: a. Single Loop                  1 (g)            3 per loop          M           SR 3.3.1.1                                    91%    1 SR 3.3.1.7 SR 3.3.1+10     (J/'
SR 3.3.1.16 1_-0..7S" 90..
: b. Two Loops                    l(h)              3 per loop          L           SR 3.3.1.1                                    91%    1 SR 3.3.1.7 ()(
SR 3.3. 1.10         '
SR 3.3.1.16 (e)     Above the P-7 (Low Power Reactor Trips Block) interlock.
(f)     Time constants utilized in the lead-lag controller for Pressurizer Pressure - Low are 2 seconds for lead and I second for lag.
(g)     Above the P-8 (Power Range Neutron Flux) interlock.
(h)     Above the P-7 (Low Power Reactor Trips Block) interlock and below the P-8 (Power Range Neutron Flux) interlock.
1,jSE       l Catawba Units 1 and 2                                       3.3.1-15                             Amendment Nos. +79M--1


====3.3.1 Table====
RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 3 of 7)
3.3.1-1 (page 3 of 7)Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT 11. Undervoltage RCPs 12. Underfrequency RCPs 13. Steam Generator (SG) Water Level -Low Low 1 (e)l(e)1,2 1 per bus 1 per bus 4 per SG L SR 3.3.1.9 _5016 V 5082 V 31,, *-,SR 3.3.1.10 3.1 L SIR S3.31.9 )(1t A '2!&&.gHz 56.4 Hz E (Unit 1) 10.7%SR 3.31.10 (Unit2) of 36.8%SR 3.3.1.16 narrow range Unit 2) of span narrow ange span 14. Turbine Trip a. Stop Valve EH Pressure Low b. Turbine Stop Valve Closure 15. Safety Injection (SI)Input from Engineered Safety Feature Actuation System (ESFAS)10)10)1,2 4 4 2 trains N SR 3.3.1.10 SR 3.3.1.15 0 SR 3.3.1.10 SR 3.3.1.15 P SR 3.3.1.5 SR 3.3.1.14_> 500 psig>_ 1% open NA 550 psig NA NA (e) Above the P-7 (Low Power Reactor Trips Block) interlock.(i) Not used.() Above the P-9 (Power Range Neutron Flux) interlock.
Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER                                                                             NOMINAL SPECIFIED         REQUIRED                         SURVEILLANCE   ALLOWABLE         TRIP FUNCTION             CONDITIONS         CHANNELS         CONDITIONS       REQUIREMENTS       VALUE       SETPOINT
Catawba Units 1 and 2 3.3.1-16 Amendment Nos. t-19-7"1 RTS Instrumentation
: 11. Undervoltage RCPs           1 (e)           1 per bus           L         SR 3.3.1.9         _5016 V       5082 V 3.3.1.10 31,,               *-,SR 3.1
: 12. Underfrequency                l(e)            1 per bus            L         S3.31.9 )(1t SIR          A   '2!&&.gHz       56.4 Hz RCPs
: 13. Steam Generator              1,2              4 per SG            E                               (Unit 1)   10.7%
(SG) Water Level -
Low Low                                                                      SR 3.31.10         (Unit2) of     36.8%
SR 3.3.1.16     narrow range   Unit 2) of span         narrow ange span
: 14. Turbine Trip
: a. Stop Valve EH           10)                 4               N         SR 3.3.1.10       _>500 psig    550 psig Pressure Low                                                            SR 3.3.1.15
: b. Turbine Stop            10)                  4              0         SR 3.3.1.10       >_1% open        NA Valve Closure                                                          SR 3.3.1.15
: 15. Safety Injection (SI)          1,2              2 trains            P         SR 3.3.1.5           NA            NA Input from                                                                  SR 3.3.1.14 Engineered Safety Feature Actuation System (ESFAS)
(e)   Above the P-7 (Low Power Reactor Trips Block) interlock.
(i)   Not used.
()   Above the P-9 (Power Range Neutron Flux) interlock.
Catawba Units 1 and 2                                 3.3.1-16                             Amendment Nos. t-19-7"1


====3.3.1 Table====
RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 4 of 7)
3.3.1-1 (page 4 of 7)Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT 16. Reactor Trip System Interlocks
Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER                                                                           NOMINAL SPECIFIED         REQUIRED                         SURVEILLANCE ALLOWABLE           TRIP FUNCTION                 CONDITIONS         CHANNELS         CONDITIONS       REQUIREMENTS       VALUE     SETPOINT
: a. Intermediate Range Neutron Flux, P-6 b. Low Power Reactor Trips Block, P-7 c. Power Range Neutron Flux, P-8 d. Power Range Neutron Flux, P-9 e. Power Range Neutron Flux, P-10 f. Turbine Impulse Pressure, P-13 17. Reactor Trip Breakers(k)
: 16. Reactor Trip System Interlocks
: 18. Reactor Trip Breaker Undervoltage and Shunt Trip Mechanisms
: a. Intermediate                 2 (d)               2             R         SR 3.3.1.11     &#x17d; 6E-11amp   lE-10 amp Range Neutron                                                              SR 3.3.1.13 Flux, P-6
: 19. Automatic Trip Logic 2 (d)1,2 1 1,2 3 (a), 4 (a) 5 (a)1,2 3 (a), 4 (a), 5 (a)1,2 3 (a), 4 (a), 5 (a)2 1 per train 4 4 4 2 R SR 3.3.1.11  6E-11amp lE-10 amp SR 3.3.1.13 S SR 3.3.1.5 S SR 3.3.1.11 SR 3.3.1.13 S SR 3.3.1.11 SR 3.3.1.13 NA NA< 50.2% RTP 48%RTP< 70% RTP 69% RTP R SR 3.3.1.11 _> 7.8% RTP SR 3.3.1.13 and < 12.2%P S SR 3.3.1.12 _1-2-% RTP SR 3.3.1.13 turbine impulse pressure 0equivalentp QU SR 3.3.1.4 NA C SR 3.3.1.4 NA 10% RTP 10% RTP turbine impulse pressure equivalent NA NA 2 trains 2 trains C 1 each per RTB 1 each per RTB 2 trains 2 trains T SR 3.3.1.4 C SR 3.3.1.4 NA NA NA NA NA NA NA NA P,U C SR 3.3.1.5 SR 3.3.1.5 (continued)(a) With RTBs closed and Rod Control System capable of rod withdrawal.(d) Below the P-6 (Intermediate Range Neutron Flux) interlocks.(k) Including any reactor trip bypass breakers that are racked in and closed for bypassing an RTB.Catawba Units 1 and 2 3.3.1-17 Amendment Nos. 1-W&#xfd; RTS Instrumentation
: b. Low Power                                  1 per train          S         SR 3.3.1.5             NA          NA Reactor Trips Block, P-7
: c. Power Range                                      4              S         SR 3.3.1.11     *<50.2% RTP    48%RTP Neutron Flux,                                                              SR 3.3.1.13 P-8
: d. Power Range                                      4              S         SR 3.3.1.11       < 70% RTP    69% RTP Neutron Flux,                                                              SR 3.3.1.13 P-9
: e. Power Range                  1,2 1                4              R         SR 3.3.1.11       _>7.8% RTP     10% RTP Neutron Flux,                                                              SR 3.3.1.13     and < 12.2%
P-10                                                                                                P
: f. Turbine                                          2              S         SR 3.3.1.12     _1-2-% RTP     10% RTP Impulse                                                                    SR 3.3.1.13         turbine     turbine Pressure, P-13                                                                                              impulse impulse pressure    pressure 0equivalentp     equivalent
: 17. Reactor Trip                        1,2            2 trains          CQU        SR 3.3.1.4             NA          NA Breakers(k) 3 (a), 4 (a)  5 (a)    2 trains          C         SR 3.3.1.4             NA           NA
: 18. Reactor Trip Breaker                1,2         1 each per           T         SR 3.3.1.4             NA          NA Undervoltage and                                    RTB Shunt Trip Mechanisms                  3 (a), 4 (a), 5 (a)  1 each per          C         SR 3.3.1.4             NA           NA RTB
: 19. Automatic Trip Logic                1,2            2 trains          P,U         SR 3.3.1.5             NA          NA 3 (a), 4 (a), 5 (a)    2 trains          C          SR 3.3.1.5             NA          NA (continued)
(a) With RTBs closed and Rod Control System capable of rod withdrawal.
(d)   Below the P-6 (Intermediate Range Neutron Flux) interlocks.
(k)   Including any reactor trip bypass breakers that are racked in and closed for bypassing an RTB.
Catawba Units 1 and 2                                     3.3.1-17                           Amendment Nos. 1-W&#xfd;


====3.3.1 Table====
RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 5 of 7)
3.3.1-1 (page 5 of 7)Reactor Trip System Instrumentation Note 1: Overtemperature AT The Overtemperature AT Function Allowable Value shall not exceed the following NOMINAL TRIP SETPOINT by more tha erre4*,i (Unlt 2f RTP.(1+ r 1 s) 1 " AT K -K2 (1 4 S) T -T' +K3 (P -P') -f, (A/)+T '2 S +C 3 S ) 0A (1+ 'r 5 s) (1+1-,s)6 I)Where: AT is the measured RCS AT by loop narrow range RTDs, OF.AT 0 is the indicated AT at RTP, OF.s is the Laplace transform operator, sec 1.T is the measured RCS average temperature, OF.T is the nominal Tavg at RTP (allowed by Safety Analysis), < the values specified in the COLR.P is the measured pressurizer pressure, psig P is the nominal RCS operating pressure, = the value specified in the COLR K 1  = Overtemperature AT reactor NOMINAL TRIP SETPOINT, as presented in the COLR, K 2  = Overtemperature AT reactor trip heatup setpoint penalty coefficient, as presented in the COLR, K 3 , = Overtemperature AT reactor trip depressurization setpoint penalty coefficient, as presented in the COLR,'1 1, "r 2 = Time constants utilized in the lead-lag compensator for AT, as presented in the COLR, 13 = Time constant utilized in the lag compensator for AT, as presented in the COLR, 1 4 , 1 5 = Time constants utilized in the lead-lag compensator for Tavg, as presented in the COLR, T6e = Time constant utilized in the measured Tavg lag compensator, as presented in the COLR, and f 1 (AI) = a function of the indicated difference between top and bottom detectors of'the power-range neutron ion chambers; with gains to be selected based on measured instrument response during plant startup tests such that: (i) for qt -qb between the "positive" and "negative" fl(AI) breakpoints as presented in the COLR; fl(Al) = 0, where qt and qb are percent RATED THERMAL POWER in the top and bottom halves of the core respectively, and qt + qb is total THERMAL POWER in percent of RATED THERMAL POWER;(ii) for each percent Al that the magnitude of qt -qb is more negative than the f 1 (AI) "negative" breakpoint presented in the COLR, the AT Trip Setpoint shall be automatically reduced by the fl(AI) "negative" slope presented in the COLR; and (continued)
Reactor Trip System Instrumentation Note 1: Overtemperature AT The Overtemperature AT Function Allowable Value shall not exceed the following NOMINAL TRIP SETPOINT by more tha erre4*,i                               (Unlt 2f RTP.
Catawba Units 1 and 2 3.3..1-118 Amendment Nos. -240t244-RTS Instrumentation
(1+ r1 s)       1 "                                 S) T         -T'   +K3 (P - P') - f, (A/)
        +T' 2 S     +C3 S   )   AT    K -  K2  (1 (1+ 4'r5 s) 0A            (1+1-,s) 6       I)
Where:   AT is the measured RCS AT by loop narrow range RTDs, OF.
AT0 is the indicated AT at RTP, OF.
s is the Laplace transform operator, sec 1 .
T is the measured RCS average temperature, OF.
T is the nominal Tavg at RTP (allowed by Safety Analysis), < the values specified in the COLR.
P is the measured pressurizer pressure, psig P is the nominal RCS operating pressure, = the value specified in the COLR K1      = Overtemperature AT reactor NOMINAL TRIP SETPOINT, as presented in the COLR, K2      =   Overtemperature AT reactor trip heatup setpoint penalty coefficient, as presented in the COLR, K3 ,   =   Overtemperature AT reactor trip depressurization setpoint penalty coefficient, as presented in the COLR,
        ' 11, "r 2 = Time constants utilized in the lead-lag compensator for AT, as presented in the COLR, 13       = Time constant utilized in the lag compensator for AT, as presented in the COLR, 1 4, 1 5 =   Time constants utilized in the lead-lag compensator for Tavg, as presented in the COLR, T6e     = Time constant utilized in the measured Tavg lag compensator, as presented in the COLR, and f1 (AI) = a function of the indicated difference between top and bottom detectors of' the power-range neutron ion chambers; with gains to be selected based on measured instrument response during plant startup tests such that:
(i)     for qt - qb between the "positive" and "negative" fl(AI) breakpoints as presented in the COLR; fl(Al) = 0, where qt and qb are percent RATED THERMAL POWER in the top and bottom halves of the core respectively, and qt + qb is total THERMAL POWER in percent of RATED THERMAL POWER; (ii)     for each percent Al that the magnitude of qt - qb is more negative than the f1 (AI) "negative" breakpoint presented in the COLR, the AT Trip Setpoint shall be automatically reduced by the fl(AI) "negative" slope presented in the COLR; and (continued)
Catawba Units 1 and 2                         3.3..1-118                     Amendment Nos. -240t244-


====3.3.1 Table====
RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 6 of 7)
3.3.1-1 (page 6 of 7)Reactor Trip System Instrumentation (iii) for each percent Al that the magnitude of qt -qb is more positive than the fl(AI) "positive" breakpoint presented in the COLR, the AT Trip Setpoint shall be automatically reduced by the fl(Al) "positive" slope presented in the COLR.KJO0C, ,t1,0 S (-4i Note 2:- Overpower AT Pqej pov~dA &#xfd; 4-The Overpower AT Function Allowable Value shall not exceed the following NOMINAL TRIP SETPOINT by more than 2.6% (Unit 1) and 3.1% (Unit 2) of RTP.(1+ -s) 1 1 AT 0 T -K 6 FT T -f 2 (A)AT( +.r 2 S) l+-3s 1 +rzS 1 +A 6 s K LK 1 (Where: AT is the measured RCS AT by loop narrow range RTDs, &deg;F.ATo is the indicated AT at RTP, OF.s is the Laplace transform operator, sec>.T is the measured RCS average temperature, OF.T is the nominal Tavg at RTP (calibration temperature for AT instrumentation),< the values specified in the COLR.K 4  = Overpower AT reactor NOMINAL TRIP SETPOINT as presented in the COLR, K 5  = the value specified in the COLR for increasing average temperature and the value specified in the COLR for decreasing average temperature, K 6  = Overpower AT reactor trip heatup setpoint penalty coefficient as presented in the COLR for T > T and K 6 = the value specified in the COLR for T < T, T 1 , t 2 = Time constants utilized in the lead-lag compensator for AT, as presented in the COLR, 13 = Time constant utilized in the lag compensator for AT, as presented in the COLR, T6 = Time constant utilized in the measured Tavg lag compensator, as presented in the COLR,= Time constant utilized in the rate-lag controller for Tavg, as presented in the COLR, and f 2 (AI) = a function of the indicated difference between top and bottom detectors of the power-range neutron ion chambers; with gains to be selected based on measured instrument response during plant startup tests such that: (i) for qt -qb between the "positive" and "negative" f 2 (AI) breakpoints as presented in the COLR; f 2 (AI) = 0, where qt and qb are percent RATED THERMAL POWER in the top and bottom halves of the core respectively, and qt + qb is total THERMAL POWER in percent of RATED THERMAL POWER;(continued)
Reactor Trip System Instrumentation (iii)   for each percent Al that the magnitude of qt - qb is more positive than the fl(AI) "positive" breakpoint presented in the COLR, the AT Trip Setpoint shall be automatically reduced by the fl(Al) "positive" slope presented in the COLR.
Catawba Units 1 and 2 3.3.1-19 Amendment Nos. 210/204 ESFAS Instrumentation
KJO0C,         ,t1,0S    -4  -(-4i Note 2:- Overpower AT               Pqej     pov~dA         &#xfd; 4-The Overpower AT Function Allowable Value shall not exceed the following NOMINAL TRIP SETPOINT by more than 2.6% (Unit 1) and 3.1% (Unit 2) of RTP.
AT(
(1+ - s)
            +.r 2 S) l+-3s 1    AT0 K      1+rzS 1
( 1 +A6 s T- K6 FT LK 1       T  - f2 (A)
Where:   AT is the measured RCS AT by loop narrow range RTDs, &deg;F.
ATo is the indicated AT at RTP, OF.
s is the Laplace transform operator, sec>.
T is the measured RCS average temperature, OF.
T is the nominal Tavg at RTP (calibration temperature for AT instrumentation),
          < the values specified in the COLR.
K4        = Overpower AT reactor NOMINAL TRIP SETPOINT as presented in the COLR, K5        = the value specified in the COLR for increasing average temperature and the value specified in the COLR for decreasing average temperature, K6        = Overpower AT reactor trip heatup setpoint penalty coefficient as presented in the COLR for T > T and K6 = the value specified in the COLR for T < T, T1 , t 2 = Time constants utilized in the lead-lag compensator for AT, as presented in the COLR, 13       = Time constant utilized in the lag compensator for AT, as presented in the COLR, T6       = Time constant utilized in the measured Tavg lag compensator, as presented in the COLR, T*7      = Time constant utilized in the rate-lag controller for Tavg, as presented in the COLR, and f2(AI) = a function of the indicated difference between top and bottom detectors of the power-range neutron ion chambers; with gains to be selected based on measured instrument response during plant startup tests such that:
(i)     for qt - qb between the "positive" and "negative" f 2(AI) breakpoints as presented in the COLR; f2(AI) = 0, where qt and qb are percent RATED THERMAL POWER in the top and bottom halves of the core respectively, and qt + qb is total THERMAL POWER in percent of RATED THERMAL POWER; (continued)
Catawba Units 1 and 2                         3.3.1-19                       Amendment Nos. 210/204


====3.3.2 SURVEILLANCE====
ESFAS Instrumentation 3.3.2 SURVEILLANCE REQUIREMENTS
                                            -NOTE-Refer to Table 3.3.2-1 to determine which SRs apply for each ESFAS Function.
SURVEILLANCE                                    FREQUENCY SR 3.3.2.1    Perform CHANNEL CHECK.                                    12 hours SR 3.3.2.2    Perform ACTUATION LOGIC TEST.                              92 days on a STAGGERED TEST BASIS SR 3.3.2.3        --------------------- NOTE        -----------------
Final actuation of pumps or valves not required.
Perform TADOT.                                            31 days SR 3.3.2.4    Perform MASTER RELAY TEST.                                92 days on a STAGGERED TEST BASIS SR 3.3.2.5    Perform COT.                                              184 days SR 3.3.2.6    Perform SLAVE RELAY TEST.                                  92 days OR 18 months for only Westinghouse AR and Potter &
Brumfield MDR relay types SR 3.3.2.7    Perform COT.                                              31 days (continued)
  &#xfd;%jo                  -4          S      d<
Catawba Units 1 and 2                    3.3.2-10            Amendment Nos. 249/243


REQUIREMENTS-NOTE-Refer to Table 3.3.2-1 to determine which SRs apply for each ESFAS Function.SURVEILLANCE FREQUENCY SR 3.3.2.1 Perform CHANNEL CHECK. 12 hours SR 3.3.2.2 Perform ACTUATION LOGIC TEST. 92 days on a STAGGERED TEST BASIS SR 3.3.2.3 ---------------------
ESFAS Instrumentation 3.3.2 SURVEILLANCE                                       FREQUENCY SR 3.3.2.8      --------------------- NOTE                ------------------
NOTE -----------------
Verification of setpoint not required for manual initiation functions.
Final actuation of pumps or valves not required.Perform TADOT. 31 days SR 3.3.2.4 Perform MASTER RELAY TEST. 92 days on a STAGGERED TEST BASIS SR 3.3.2.5 Perform COT. 184 days SR 3.3.2.6 Perform SLAVE RELAY TEST. 92 days OR 18 months for only Westinghouse AR and Potter &Brumfield MDR relay types SR 3.3.2.7 Perform COT. 31 days&#xfd;%jo -4 S d<(continued)
Perform TADOT.                                                 18 months SR 3.3.2.9      --------------------- NOTE -----------------
Catawba Units 1 and 2 3.3.2-10 Amendment Nos. 249/243 ESFAS Instrumentation
This Surveillance shall include verification that the time constants are adjusted to the prescribed values.
Perform CHANNEL CALIBRATION.                                   18 months SR 3.3.2.10      -------------------- NOTE -----------------
Not required to be performed for the turbine driven AFW pump until 24 hours after SG pressure is > 600 psig.
Verify ESFAS RESPONSE TIMES are within limit.                   18 months on a STAGGERED TEST BASIS SR 3.3.2.11  Perform COT.                                                   18 months SR 3.3.2.12  Perform ACTUATION LOGIC TEST.                                 18 months NJ                              I/J Per    C&#xfd;-,
Catawba Units 1 and 2                   3.3.2-11                    Amendment Nos. 249/243


====3.3.2 SURVEILLANCE====
CNS TS Table 3.3.2-1 INSERTS INSERT 1 (f) If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.
(g) The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Nominal Trip Setpoint (NTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the NTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (field setting) to confirm channel performance. The methodologies used to determine the as-found and the as-left tolerances are specified in the UFSAR.


FREQUENCY SR 3.3.2.8 ---------------------
ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 1 of 5)
NOTE ------------------
Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER                                                                                          NOMINAL SPECIFIED          REQUIRED                            SURVEILLANCE          ALLOWABLE          TRIP FUNCTION            CONDITIONS          CHANNELS          CONDITIONS          REQUIREMENTS              VALUE        SETPOINT Safety Injection(b)
Verification of setpoint not required for manual initiation functions.
: a. Manual initiation     1,2,3,4              2                B            SR 3.3.2.8                  NA            NA
Perform TADOT. 18 months SR 3.3.2.9 ---------------------
: b. Automatic              1,2,3,4          2 trains              C            SR 3.3.2.2                  NA            NA Actuation Logic                                                            S R 3.3.2.4 and Actuation Relays
NOTE -----------------
: c. Containment            1,2,3                3                D            SR 3.3.2.1                    psig      1.2 psig Pressure - High SR 3.3.2.10
This Surveillance shall include verification that the time constants are adjusted to the prescribed values.Perform CHANNEL CALIBRATION.
: d. Pressurizer                  (a)            4                      D      SR 3.3.2.1            > 1489Q-psig    1845 psig 1 ,2 ,3                                            '  SR 3.3.2.5 07)-(.J*
18 months SR 3.3.2.10 --------------------
Pressure - Low SR 3.3.2.9    c-P)(3)
NOTE -----------------
SR 3.3.2.10
Not required to be performed for the turbine driven AFW pump until 24 hours after SG pressure is > 600 psig.Verify ESFAS RESPONSE TIMES are within limit. 18 months on a STAGGERED TEST BASIS SR 3.3.2.11 Perform COT. 18 months SR 3.3.2.12 Perform ACTUATION LOGIC TEST. 18 months NJ I/J Per C&#xfd;-, Catawba Units 1 and 2 3.3.2-11 Amendment Nos. 249/243 CNS TS Table 3.3.2-1 INSERTS INSERT 1 (f) If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.(g) The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Nominal Trip Setpoint (NTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable.
: 2. Containment Spray
Setpoints more conservative than the NTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (field setting) to confirm channel performance.
: a. Manual Initiation      1,2,3,4        1 per train,          B            SR 3.3.2.8                  NA              NA 2 trains
The methodologies used to determine the as-found and the as-left tolerances are specified in the UFSAR.
: b. Automatic              1,2,3,4          2 trains            C            SR 3.3.2.2                  NA              NA Actuation Logic                                                            SR 3.3.2.4 and Actuation                                                              SR 3.3.2.6 Relays
ESFAS Instrumentation
: c. Containment            1,2,3                4                E            .SR  3.3.2.1             _<3.2 psig      3.0 psig Pressure                                                                    SR 3.3.2.5 High High                                                                    SR 3.3.2.9 SR 3.3.2.10
: 3. Containment Isolation(b)
: a. Phase A Isolation (1) Manual            1,2,3,4              2                B            SR 3.3.2.8                NA              NA Initiation (2) Automatic          1,2,3,4          2 trains            C              SR 3.3.2.2                NA              NA Actuation                                                              SR 3.3.2.4 Logic and                                                              SR 3.3.2.6 Actuation Relays (3) Safety        Refer to Function 1 (Safety Injection) for all initiation functions and requirements.
Injection (continued)
(a) Above the P-1I (Pressurizer Pressure) interlock.
(b) The requirements of this Function are not applicable to Containment Purge Ventilation System and Hydrogen Purge System components, since the system containment isolation valves are sealed closed in MODES 1, 2, 3, and 4.
Catawba Units 1 and 2                                    3.3.2-12                                  Amendment Nos.             24-&#xfd;
    )Akt            J        I


====3.3.2 Table====
ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 2 of 5)
3.3.2-1 (page 1 of 5)Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT Safety Injection(b)
Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER                                                                           NOMINAL SPECIFIED         REQUIRED                           SURVEILLANCE   ALLOWABLE       TRIP FUNCTION                 CONDITIONS         CHANNELS         CONDITIONS       REQUIREMENTS     VALUE     SETPOINT
: a. Manual initiation
: 3. Containment Isolation (continued)
: b. Automatic Actuation Logic and Actuation Relays c. Containment Pressure -High d. Pressurizer Pressure -Low 2. Containment Spray a. Manual Initiation
: b. Phase B Isolation (1) Manual Initiation             1,2,3,4         1 per train,           B         SR 3.3.2.8         NA           NA 2 trains (2) Automatic                1,2,3,4          2 trains            C           SR 3.3.2.2         NA           NA SR 3.3.2.4 Actuation Logic and                                                                SR 3.3.2.6 Actuation Relays (3) Containment              1,2,3               4                E                                        3.0 psig Pressure -
: b. Automatic Actuation Logic and Actuation Relays 1,2,3,4 1,2,3,4 1,2,3 1 , 2 , 3 (a)2 2 trains 3 4 B SR 3.3.2.8 NA NA C SR 3.3.2.2 NA NA S R 3.3.2.4 D SR 3.3.2.1 psig 1.2 psig SR 3.3.2.10 D SR 3.3.2.1 > 14 89Q-psig 1845 psig' SR 3.3.2.5 SR 3.3.2.9 c-P)(3)SR 3.3.2.10 1,2,3,4 1,2,3,4 1 per train, 2 trains 2 trains B SR 3.3.2.8 C SR 3.3.2.2 SR 3.3.2.4 SR 3.3.2.6 E .SR 3.3.2.1 SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10 NA NA NA NA c. Containment Pressure High High 1,2,3 4_< 3.2 psig 3.0 psig 3. Containment Isolation(b)
High High
: a. Phase A Isolation (1) Manual Initiation (2) Automatic Actuation Logic and Actuation Relays (3) Safety Injection 1,2,3,4 1,2,3,4 2 2 trains B SR 3.3.2.8 C SR 3.3.2.2 SR 3.3.2.4 SR 3.3.2.6 NA NA NA NA Refer to Function 1 (Safety Injection) for all initiation functions and requirements.(continued)(a) Above the P-1I (Pressurizer Pressure) interlock.(b) The requirements of this Function are not applicable to Containment Purge Ventilation System and Hydrogen Purge System components, since the system containment isolation valves are sealed closed in MODES 1, 2, 3, and 4.Catawba Units 1 and 2)Akt J I 3.3.2-12 Amendment Nos. 24-&#xfd; ESFAS Instrumentation
: 4. Steam Line Isolation
: a. Manual Initiation (1) System                                    2 trains            F          SR 3.3.2.8        NA          NA (2) Individual            1,2 (b), 3 (b)    1 per line          G          SR 3.3.2.8         NA          NA
: b. Automatic                                      2 trains            H          SR 3.3.2.2         NA          NA Actuation Logic                                                                SR 3.3.2.4 and Actuation                                                                SR 3.3.2.6 Relays
: c. Containment                                      4                E                                       3.0 psig 1,2(b),3(b)
Pressure - High High
: d. Steam Line Pressure (1) Low                1,2 (b), 3 (a)(b) 3 per steam            D                                        775 psig line (continued)
(a)Above the P-11 (Pressurizer Pressure) interlock.
Uall                  MSIVs are closed and de-activated.
d2                          3.3.2-13                            Amendment Nos. -249/24-3


====3.3.2 Table====
ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 3 of 5)
3.3.2-1 (page 2 of 5)Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT 3. Containment Isolation (continued)
Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER                                                                                     NOMINAL SPECIFIED           REQUIRED                             SURVEILLANCE         ALLOWABLE       TRIP FUNCTION               CONDITIONS           CHANNELS         CONDITIONS         REQUIREMENTS             VALUE     SETPOINT
: b. Phase B Isolation (1) Manual Initiation (2) Automatic Actuation Logic and Actuation Relays (3) Containment Pressure -High High 1,2,3,4 1,2,3,4 1,2,3 1 per train, 2 trains 2 trains B SR 3.3.2.8 C SR 3.3.2.2 SR 3.3.2.4 SR 3.3.2.6 NA NA NA NA 4 E 3.0 psig 4. Steam Line Isolation a. Manual Initiation (1) System (2) Individual 2 trains 1, 2 (b), 3 (b) 1 per line F SR 3.3.2.8 G SR 3.3.2.8 H SR 3.3.2.2 SR 3.3.2.4 SR 3.3.2.6 NA NA NA b. Automatic Actuation Logic and Actuation Relays c. Containment Pressure -High High d. Steam Line Pressure 2 trains 1,2(b),3(b) 4 E NA NA NA 3.0 psig 775 psig (continued)
: 4. Steam Line Isolation (continued)
(1) Low 1, 2 (b), 3 (a)(b) 3 per steam line D (a)Above the P-11 (Pressurizer Pressure) interlock.
(2) Negative            3 (b)(c)        3 perline steam          D                                                10 0 (d) psi Rate - High
Uall MSIVs are closed and de-activated.
: 5. Turbine Trip and Feedwater Isolation
d2 3.3.2-13 Amendment Nos. -249/24-3 ESFAS Instrumentation
: a. Turbine Trip (1) Automatic              1,2            2 trains              I            SR 3.3.2.2                   NA        NA Actuation                                                               SR 3.3.2.4 Logic and                                                               SR 3.3.2.6 Actuation Relays (2)  SG Water              1,2            4 per SG              J            SR  3.3.2.1              *_ 8i5-6%    83.9%
Level-                                                                  SR  3.3.2.2              (Unit 1)    Unit 1)
High-High                                                               SR  3.3.2.4 .                          7.1%
(P-14)                                                                  SR  3.3.2.5+'** )        (Unit 2)    Unit 2)
SR  3.3.2.6 f )(3 SR  3.3.2.94  *')(J,               *
(3)  Safety        Refer to Function 1 (Safety Injection) for all initiation functions and requirements. See Injection    Item 5.a.(1) for Applicable MODES.
: b. Feedwater Isolation (1) Automatic          1,2(e),3(e)          2 trains             H            SR 3.3.2.2                  NA        NA Actuation                                                                SR 3.3.2.4 Logic and                                                                SR 3.3.2.6 Actuation Relays (continued)
(b) Except when all MSIVs are closed and de-activated.
(c) Trip function automatically blocked above P-11 (Pressurizer Pressure) interlock and may be blocked below P-11 when Steam Line Isolation Steam Line Pressure - Low is not blocked.
(d) Time constant utilized in the rate/lag controller is > 50 seconds.
(e) Except when all MFIVs, MFCVs, and associated bypass valves are closed and de-activated or isolated by a closed manual valve.
I---        t~r Catawba Units 1 and 2                                     3.3.2-14                                  Amendment Nos. 24 ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 4 of 5)
Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER                                                                                            NOMINAL SPECIFIED        REQUIRED                              SURVEILLANCE            ALLOWABLE            TRIP FUNCTION                CONDITIONS        CHANNELS          CONDITIONS          REQUIREMENTS                VALUE        SETPOINT (2)    SG Water                              4 per SG                    D      SR 3.3.2.1                  <5 '4-.6, 8&-G            83.9%
SR':3.3.2.2                  (Unit 1)          Unit 1)
Level- High High (P-14)                                                               SIR 3.3.2.4 ...            <7.&o 77,8        77.1%
SR 3.3.2.5(r"),.,          (Unit 2)            nit 2)
SIR 3.3.269")
SR 3.3.2.10 (3) Safety            Refer to Function 1 (Safety Injection) for all initiation functions and requirements. Se Injection      Item 5.b.(1) for Applicable MODES.
(4)    Tavg-Low            ,2                    4                J            SR 3.3.2.1                                    5641F e564F SR 3.3 2 5 SR 3...          j )
coincident with        Refer to Function 8.a (Reactor Trip, P-4) for all initiation functions and requirements.
Reactor Trip, P-4 (5)    Doghouse                              (1/1 logic)           L            (1/1 logic)            < 12 inches      11 inches WaterLevel -                              2 per                             SR 3.3.2.8             above 577 ft      above 577 High High                            doghouse                                                    floor level      ft floor level (2/3 logic)                          (2/3 logic) 3 per train                          SR 3.3.2.8 per                              SR 3.3.2.9 doghouse                            SR 3.3.2.12
: 6. Auxiliary Feedwater
: a.      Automatic                1,2,3              2 trains            H            SR 3.3.2.2                    NA               NA Actuation Logic                                                                 SR 3.3.2.4 and Actuation                                                                   SR 3.3.2.6 Relays to
: b.      SG Water Level            1,2,3            4perSG                D  L        SR  3.3.2.1         ,"      > 010.7%
              - LowLow                                                                        SR  3.325 (        j        (Unit 1)          Unit 1)
SR  3.3.2.9 (-.)()           354o/o  3,i 1 36.8%
SR  3.3.2.10                (Unit 2)          Unit 2)
: c.      Safety Injection    Refer to Function 1 (Safety Injection) for all initiation functions and requirements.
: d.      Loss of Offsite          1,2,3            3 per bus            D            SR 3.3.2.3                > 3242 V          3500 V Power                                                                          SR 3.3.2.9 SR 3.3.2.10 1,2
: e.      Trip of all Main                          3 per pump              K            SR 3.3.2.8                    NA               NA Feedwater                                                                      SR 3.3.2.10 Pumps
: f.      Auxiliary                1,2,3            3 per train            M            SR 3.3.2.8              A) &#x17d;_9.5 psig   A) 10.5 Feedwater Pump                                                                  SR 3.3.2.10                                    psig
            .Train A and Train B Suction                                                                                          B) _>5.2 psig  B) 6.2 psig Transfer on                                                                                                  (Unit 1)     (Unit 1)
Suction                                                                                                    > 5.0 psig      6.0 psig Pressure - Low                                                                                              (Unit 2)     (Unit 2)
(continued)
(        xcep              MFIVs, MF CVs, and associated bypass valves are closed and de-activated or isolated by a closed manual valve.
Caab P S            t I a-Td Cataw a nlits 1 and 2                                      3.3.2-15                              Amendment Nos. 249-2"43


====3.3.2 Table====
ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 5 of 5)
3.3.2-1 (page 3 of 5)Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT 4. Steam Line Isolation (continued)
Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER                                                                                             NOMINAL SPECIFIED         REQUIRED                               SURVEILLANCE         ALLOWABLE               TRIP FUNCTION           CONDITIONS         CHANNELS         CONDITIONS           REQUIREMENTS             VALUE           SETPOINT
(2) Negative 3 (b)(c) 3 per steam D 1 0 0 (d) psi Rate -High line 5. Turbine Trip and Feedwater Isolation a. Turbine Trip (1) Automatic 1,2 2 trains I SR 3.3.2.2 NA NA Actuation SR 3.3.2.4 Logic and SR 3.3.2.6 Actuation Relays (2) SG Water 1,2 4 per SG J SR 3.3.2.1 _ 8i5-6% 83.9%Level- SR 3.3.2.2 (Unit 1) Unit 1)High-High SR 3.3.2.4 .7.1%(P-14) SR ) (Unit 2) Unit 2)SR 3.3.2.6 f )(3 SR 3.3.2.94 *(3) Safety Refer to Function 1 (Safety Injection) for all initiation functions and requirements.
: 7. Automatic Switchover to Containment Sump
See Injection Item 5.a.(1) for Applicable MODES.b. Feedwater Isolation (1) Automatic 1,2(e),3(e) 2 trains H SR 3.3.2.2 NA NA Actuation SR 3.3.2.4 Logic and SR 3.3.2.6 Actuation Relays (continued)(b) Except when all MSIVs are closed and de-activated.(c) Trip function automatically blocked above P-11 (Pressurizer Pressure) interlock and may be blocked below P-11 when Steam Line Isolation Steam Line Pressure -Low is not blocked.(d) Time constant utilized in the rate/lag controller is > 50 seconds.(e) Except when all MFIVs, MFCVs, and associated bypass valves are closed and de-activated or isolated by a closed manual valve.I--- t~r Catawba Units 1 and 2 3.3.2-14 Amendment Nos. 24 ESFAS Instrumentation
: a. Automatic             1,2,3,4            2 trains             C              SR 3.3.2.2                   NA               NA Actuation Logic                                                              SR 3.3.2.4 and Actuation                                                                SR 3.3.2.6 Relays
: b. Refueling Water       1,2,3,4               4                N              SR 3.3.2.1               >_162.4            177.15 Storage Tank                                                                SR 3.3.2.7                 inches          inches (RWST) Level -                                                               SR 3.3.2.9 Low                                                                          SR 3.3.2.10 Coincident with  Refer to Function 1 (Safety Injection) for all initiation functions and requirements.
Safety Injection
: 8. ESFAS Interlocks
: a. Reactor Trip, P-4      1,2,3          1 per train,          F              SR 3.3.2.8                    NA              NA 2 trains 19 4-(
: b. Pressurizer            1,2,3                3                O              SR 3.3.2.5                  J4 419 and        955 psig Pressure, P-11                                                              SR 3.3.2.9
* t9      psig
: c. Tavg - Low Low,        1,2,3           1 per loop            O              SR 3.3.2.5                > -555.WF          553&deg;F P-12                                                                        SR 3.3.2.9                      S    '8
: 9. Containment Pressure Control System
: a. Start Permissive      1;2,3,4          4 per train            P              SR 3.3.2.1              *I
                                                                                                                <.0 psid            0.9 psid SR 3.3.2.7 SR 3.3.2.9
: b. Termination          1,2,3,4          4 per train            P             SR 3.3.2.1            > 0.25 psid          0.35 psid SR 3.3.2.7 SR 3.3.2.9
: 10. Nuclear Service            1,2,3,4          3 per pit            Q,R            SR  3.3.2.1          > El. 555.4 ft      El. 557.5 L    ft Water Suction                                                                    SR  3.3.2.9 Transfer - Low Pit                                                                SR  3.3.2.11 Level                                                                            SR  3.3.2.12 Catawba Units 1 and 2                               3.3.2-16                                  Amendment Nos. 249i243-


====3.3.2 Table====
U.S. Nuclear Regulatory Commission June 29, 2010 ATTACHMENT 2a McGuire Units 1 and 2 Technical Specification Bases Page Markups (Provided for information only)
3.3.2-1 (page 4 of 5)Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT (2) SG Water Level- High High (P-14)(3) Safety Injection (4) Tavg-Low coincident with Reactor Trip, P-4 (5) Doghouse WaterLevel
-High High 4 per SG 5 '4- .6, D SR 3.3.2.1 < 8&-G 83.9%SR':3.3.2.2 (Unit 1) Unit 1)SIR 3.3.2.4 ... <7.&o 7 7,8 77.1%SR 3.3.2.5(r"),., (Unit 2) nit 2)SIR 3.3.269")SR 3.3.2.10 Refer to Function 1 (Safety Injection) for all initiation functions and requirements.
Se Item 5.b.(1) for Applicable MODES.,2 4 J SR 3.3.2.1 e564F 5641F SR 3.3 2 5 SR 3... j )Refer to Function 8.a (Reactor Trip, P-4) for all initiation functions and requirements.
(1/1 logic)2 per doghouse (2/3 logic)3 per train per doghouse L (1/1 logic)SR 3.3.2.8< 12 inches above 577 ft floor level 11 inches above 577 ft floor level (2/3 logic)SR 3.3.2.8 SR 3.3.2.9 SR 3.3.2.12 6. Auxiliary Feedwater a. Automatic Actuation Logic and Actuation Relays b. SG Water Level-LowLow c. Safety Injection d. Loss of Offsite Power e. Trip of all Main Feedwater Pumps f. Auxiliary Feedwater Pump.Train A and Train B Suction Transfer on Suction Pressure -Low 1,2,3 2 trains H SR 3.3.2.2 NA NA SR 3.3.2.4 SR 3.3.2.6 to 1,2,3 4perSG D L SR 3.3.2.1 > ," 010.7%SR 3.325 ( j (Unit 1) Unit 1)SR 3.3.2.9 (-.)() 354o/o 3,i 1 36.8%SR 3.3.2.10 (Unit 2) Unit 2)Refer to Function 1 (Safety Injection) for all initiation functions and requirements.
1,2,3 1,2 3 per bus 3 per pump 3 per train D SR 3.3.2.3 SR 3.3.2.9 SR 3.3.2.10 K SR 3.3.2.8 SR 3.3.2.10 M SR 3.3.2.8 SR 3.3.2.10> 3242 V NA 3500 V NA 1,2,3 A) _ 9.5 psig A) 10.5 psig B) _> 5.2 psig (Unit 1)> 5.0 psig (Unit 2)B) 6.2 psig (Unit 1)6.0 psig (Unit 2)( xcep MFIVs, MF Caab P t S a-T d I Cataw a nlits 1 and 2 (continued)
CVs, and associated bypass valves are closed and de-activated or isolated by a closed manual valve.3.3.2-15 Amendment Nos. 249-2"43 ESFAS Instrumentation


====3.3.2 Table====
3.3.2-1 (page 5 of 5)Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT 7. Automatic Switchover to Containment Sump a. Automatic Actuation Logic and Actuation Relays b. Refueling Water Storage Tank (RWST) Level -Low Coincident with Safety Injection 8. ESFAS Interlocks
: a. Reactor Trip, P-4 b. Pressurizer Pressure, P-11 c. Tavg -Low Low, P-12 9. Containment Pressure Control System a. Start Permissive 1,2,3,4 1,2,3,4 2 trains 4 C SR 3.3.2.2 SR 3.3.2.4 SR 3.3.2.6 N SR 3.3.2.1 SR 3.3.2.7 SR 3.3.2.9 SR 3.3.2.10 NA>_ 162.4 inches NA 177.15 inches Refer to Function 1 (Safety Injection) for all initiation functions and requirements.
1,2,3 1,2,3 1,2,3 1 per train, 2 trains 3 1 per loop F SR 3.3.2.8 NA NA 19 4- (O SR 3.3.2.5 J4 419 and 955 psig SR 3.3.2.9  t9 psig O SR 3.3.2.5 > -555.WF 553&deg;F SR 3.3.2.9 S '8 b. Termination 1;2,3,4 1,2,3,4 1,2,3,4 4 per train 4 per train 3 per pit P SR 3.3.2.1 SR 3.3.2.7 SR 3.3.2.9 P SR 3.3.2.1 SR 3.3.2.7 SR 3.3.2.9I <.0 psid 0.9 psid> 0.25 psid 0.35 psid 10. Nuclear Service Water Suction Transfer -Low Pit Level Q,R SR 3.3.2.1 SR 3.3.2.9 SR 3.3.2.11 SR 3.3.2.12> El. 555.4 ft El. 557.5 ft L Catawba Units 1 and 2 3.3.2-16 Amendment Nos. 249i243-U.S. Nuclear Regulatory Commission June 29, 2010 ATTACHMENT 2a McGuire Units 1 and 2 Technical Specification Bases Page Markups (Provided for information only)
MNS Bases 3.3.1 INSERTS INSERT 1 (new paragraph)
MNS Bases 3.3.1 INSERTS INSERT 1 (new paragraph)
For Functions for which TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions" has been implemented, this SR is modified by two Notes as identified in Table 3.3.1-1. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value. Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology.
For Functions for which TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions" has been implemented, this SR is modified by two Notes as identified in Table 3.3.1-1. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value. Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology. The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the performance of these channels will be evaluated under the plant Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition. The second Note requires that the as-left setting for the channel be returned to within the as-left tolerance of the Nominal Trip Setpoint (NTSP). Where a setpoint more conservative than the NTSP is used in the plant surveillance procedures (field setting), the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint. This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit is maintained. If the as-left channel setting cannot be returned to a setting within the as-left tolerance of the NTSP, then the channel shall be declared inoperable. The second Note also requires that the methodologies for calculating the as-left and the as-found tolerances be in the UFSAR. The NOMINAL TRIP SETPOINT definition includes a provision that would allow the as-left setting for the channel to be outside the tolerance band, provided the setting is conservative with respect to the NTSP. This provision is not applicable to Functions for which the second Note applies.
The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the performance of these channels will be evaluated under the plant Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition.
INSERT 2 Technical Specification Task Force, Improved Standard Technical Specifications Change Traveler, TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions," Revision 4.
The second Note requires that the as-left setting for the channel be returned to within the as-left tolerance of the Nominal Trip Setpoint (NTSP). Where a setpoint more conservative than the NTSP is used in the plant surveillance procedures (field setting), the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint.
 
This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit is maintained.
If the as-left channel setting cannot be returned to a setting within the as-left tolerance of the NTSP, then the channel shall be declared inoperable.
The second Note also requires that the methodologies for calculating the as-left and the as-found tolerances be in the UFSAR. The NOMINAL TRIP SETPOINT definition includes a provision that would allow the as-left setting for the channel to be outside the tolerance band, provided the setting is conservative with respect to the NTSP. This provision is not applicable to Functions for which the second Note applies.INSERT 2 Technical Specification Task Force, Improved Standard Technical Specifications Change Traveler, TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions," Revision 4.
RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
These trip Functions must be OPERABLE in MODE 1 or 2 when the reactor is critical.
These trip Functions     must be OPERABLE in MODE 1 or 2 when the reactor is critical. In MODE 3, 4, or 5, these RTS trip Functions must be OPERABLE         when the RTBs and associated bypass breakers are closed,     and the CRD System is capable of rod withdrawal.
In MODE 3, 4, or 5, these RTS trip Functions must be OPERABLE when the RTBs and associated bypass breakers are closed, and the CRD System is capable of rod withdrawal.
The RTS instrumentation satisfies Criterion 3 of 10 CFR 50.36 (Ref. 6).
The RTS instrumentation satisfies Criterion 3 of 10 CFR 50.36 (Ref. 6).ACTIONS A Note has been added to the ACTIONS to clarify the application of Completion Time rules. The Conditions of this Specification may be entered independently for each Function listed in Table 3.3.1-1. When the 4 Required Channels in Table 3.3.1-1 are specified (e.g., on a per steam line, per loop, per SG, etc., basis), then the Condition may be entered separately for each steam line, loop, SG, etc., as appropriate.
ACTIONS             A Note has been added to the ACTIONS to clarify the application of Completion Time rules. The Conditions of this Specification may be entered independently for each Function listed in Table 3.3.1-1. When the 4                   Required Channels in Table 3.3.1-1 are specified (e.g., on a per steam line, per loop, per SG, etc., basis), then the Condition may be entered separately for each steam line, loop, SG, etc., as appropriate.
0, ,A channel shall be OPERABLE if the point at which the channel trips is r '.4found equal to or more conservative than the Allowable Value. In the event a channel's trip setpoint is found less conservative than the Allowable Value, or the transmitter, instrument loop, signal processing electronics, or bistable is found inoperable, then all affected Functions provided by that channel must be declared inoperable and the LCO Condition(s) entered for the protection Function(s) affected.
0,   ,A               channel shall be OPERABLE if the point at which the channel trips is
fplant conditions warrant, the trip setpoint may be set outside the NOMINAL TRIP SETPOINT calibration tolerance band as long as the trip setpoint is conservative with respect to the NOMINAL TRIP SETPOINTS.
    '.4found r                    equal to or more conservative than the Allowable Value. In the event a channel's trip setpoint is found less conservative than the Allowable Value, or the transmitter, instrument loop, signal processing electronics, or bistable is found inoperable, then all affected Functions provided by that channel must be declared inoperable and the LCO Condition(s) entered for the protection Function(s) affected. fplant conditions warrant, the trip setpoint may be set outside the NOMINAL TRIP SETPOINT calibration tolerance band as long as the trip setpoint is conservative with respect to the NOMINAL TRIP SETPOINTS. If the trip setpoint is found outside the NOMINAL TRIP SETPOINT calibration tolerance band and non-conservative with respect to the NOMINAL TRIP SETPOINT, the setpoint shall be re-adjusted.
If the trip setpoint is found outside the NOMINAL TRIP SETPOINT calibration tolerance band and non-conservative with respect to the NOMINAL TRIP SETPOINT, the setpoint shall be re-adjusted.
When the number of inoperable channels in a trip Function exceed those specified in one or other related Conditions associated with a trip Function, then the unit is outside the safety analysis. Therefore, LCO 3.0.3 must be immediately entered if applicable in the current MODE of operation.
When the number of inoperable channels in a trip Function exceed those specified in one or other related Conditions associated with a trip Function, then the unit is outside the safety analysis.
A.1 Condition A applies to all RTS protection Functions. Condition A addresses the situation where one or more required channels for one or more Functions are inoperable at the same time. The Required Action is to refer to Table 3.3.1-1 and to take the Required Actions for the protection functions affected. The Completion Times are those from the referenced Conditions and Required Actions.
Therefore, LCO 3.0.3 must be immediately entered if applicable in the current MODE of operation.
McGuire Units 1 and 2                   B 3.3.1-29                               Revision No.
A.1 Condition A applies to all RTS protection Functions.
Condition A addresses the situation where one or more required channels for one or more Functions are inoperable at the same time. The Required Action is to refer to Table 3.3.1-1 and to take the Required Actions for the protection functions affected.
The Completion Times are those from the referenced Conditions and Required Actions.McGuire Units 1 and 2 B 3.3.1-29 Revision No.
RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued) relationship between excore and incore measurements changes significantly.
RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued) relationship between excore and incore measurements changes significantly.
A Note modifies SR 3.3.1.6. The Note states that this Surveillance is required only if reactor power is > 75% RTP and that 24 hours is allowed for completing the first surveillance after reaching 75% RTP.The Frequency of 92 EFPD is adequate.
A Note modifies SR 3.3.1.6. The Note states that this Surveillance is required only if reactor power is > 75% RTP and that 24 hours is allowed for completing the first surveillance after reaching 75% RTP.
It is based on industry operating experience, considering instrument reliability and operating history data for instrument drift.SR 3.3.1.7 SR 3.3.1.7 is the performance of a COT every 184 days.A COT is performed on each required channel to ensure the channel will, perform the intended Function.The tested portion of the Loop must trip within the Allowable Values specified in Table 3.3.1-1.The setpoint shall be left set consistent with the assumptions of the setpoint methodology.
The Frequency of 92 EFPD is adequate. It is based on industry operating experience, considering instrument reliability and operating history data for instrument drift.
SR 3.3.1.7 is modified by a Note that provides a 4 hour delay in the requirement to perform this Surveillance for source range instrumentation when entering MODE 3 from MODE 2. This Note allows a normal shutdown to proceed without a delay for testing in MODE 2 and for a short time in MODE 3 until the RTBs are open and SR 3.3.1.7 is no longer required to be performed.
SR 3.3.1.7 SR 3.3.1.7 is the performance of a COT every 184 days.
If the unit is to be in MODE 3 with the RTBs closed for > 4 hours this Surveillance must be completed within 4 hours after entry into MODE 3. The surveillance shall include verification of the high flux at shutdown alarm setpoint of less than or equal to the average CPS Neutron Level reading (most consistent value between highest and lowest CPS Neutron Level reading) at five times background.
A COT is performed on each required channel to ensure the channel will, perform the intended Function.
The Frequency of 184 days is justified in Reference 11.SR 3.3 .1. 8 SR 3.3.1.8 is the performance of a COT as described in SR 3.3.1.7, except it is modified by a Note that this test shall include verification that the P-6, during the Intermediate Range COT, and P-10, during the Power Range COT, interlocks are in their required state for the existing unit condition.
The tested portion of the Loop must trip within the Allowable Values specified in Table 3.3.1-1.
The verification is performed by visual observation of the McGuire Units 1 and 2 B 3.3.1-44 Revision No.--c&#xfd; RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued) permissive status light in the unit control room. The Frequency is modified by a Note that allows this surveillance to be satisfied if it has been performed within 184 days of the Frequencies prior to reactor startup and four hours after reducing power below P-10 and P-6. The Frequency of "prior to startup" ensures this surveillance is performed prior to critical operations and applies to the source, intermediate and power range low instrument channels.
The setpoint shall be left set consistent with the assumptions of the setpoint methodology.
The Frequency of "4 hours after reducing power below P-1 0" (applicable to intermediate and power range low channels) and "4 hours after reducing power below P-6" (applicable to source range channels) allows a normal shutdown to be completed and the unit removed from the MODE of Applicability for this surveillance without a delay to perform the testing required by this surveillance.
SR 3.3.1.7 is modified by a Note that provides a 4 hour delay in the requirement to perform this Surveillance for source range instrumentation when entering MODE 3 from MODE 2. This Note allows a normal shutdown to proceed without a delay for testing in MODE 2 and for a short time in MODE 3 until the RTBs are open and SR 3.3.1.7 is no longer required to be performed. If the unit is to be in MODE 3 with the RTBs closed for > 4 hours this Surveillance must be completed within 4 hours after entry into MODE 3. The surveillance shall include verification of the high flux at shutdown alarm setpoint of less than or equal to the average CPS Neutron Level reading (most consistent value between highest and lowest CPS Neutron Level reading) at five times background.
The Frequency of every 184 days thereafter applies if the plant remains in the MODE of Applicability after the initial performances of prior to reactor startup and four hours after reducing power below P-10 or P-6. The MODE of Applicability for this surveillance is < P-1 0 for the power rangelow and intermediate range channels and < P-6 for the source range'., channels.
The Frequency of 184 days is justified in Reference 11.
Once the unit is in MODE 3, this surveillance is no longer.- required.
SR 3.3 .1.8 SR 3.3.1.8 is the performance of a COT as described in SR 3.3.1.7, except it is modified by a Note that this test shall include verification that the P-6, during the Intermediate Range COT, and P-10, during the Power Range COT, interlocks are in their required state for the existing unit condition. The verification is performed by visual observation of the McGuire Units 1 and 2                   B 3.3.1-44                               Revision No.--c&#xfd;
If power is to be maintained  
 
< P-10 or < P-6 for more than 4 hours, then the testing required by this surveillance must be performed prior to the expiration of the 4 hour limit. Four hours is a reasonable time to complete the required testing or place the unit in a MODE where this surveillance is no longer required.
RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued) permissive status light in the unit control room. The Frequency is modified by a Note that allows this surveillance to be satisfied if it has been performed within 184 days of the Frequencies prior to reactor startup and four hours after reducing power below P-10 and P-6. The Frequency of "prior to startup" ensures this surveillance is performed prior to critical operations and applies to the source, intermediate and power range low instrument channels. The Frequency of "4 hours after reducing power below P-1 0" (applicable to intermediate and power range low channels) and "4 hours after reducing power below P-6" (applicable to source range channels) allows a normal shutdown to be completed and the unit removed from the MODE of Applicability for this surveillance without a delay to perform the testing required by this surveillance. The Frequency of every 184 days thereafter applies if the plant remains in the MODE of Applicability after the initial performances of prior to reactor startup and four hours after reducing power below P-10 or P-6. The MODE of Applicability for this surveillance is < P-1 0 for the power range Q,*          low and intermediate range channels and < P-6 for the source range
This test ensures that the NIS source, intermediate, and power range low channels are OPERABLE prior to taking the reactor critical and after reducing power into the applicable MODE (< P-10 or < P-6) for periods > 4 hours. The Frequency of 184 days is justified in Reference 11.SR 3.3.1.9 72 `.,. SR 3.3.1.9 is the performance of a TADOT and is performed every 92 days, as justified in Reference 7.The SR is modified by a Note that excludes verification of setpoints from the TADOT. Since this SR applies to RCP undervoltage and underfrequency relays, setpoint verification is accomplished during the CHANNEL CALIBRATION.
  '., *u          channels. Once the unit is in MODE 3, this surveillance is no longer
SR 3.3.1.10 A CHANNEL CALIBRATION is performed every 18 months. The CHANNEL CALIBRATION may be performed at power or during refueling based on testing capability.
    .-             required. If power is to be maintained < P-10 or < P-6 for more than 4 hours, then the testing required by this surveillance must be performed prior to the expiration of the 4 hour limit. Four hours is a reasonable time to complete the required testing or place the unit in a MODE where this surveillance is no longer required. This test ensures that the NIS source, intermediate, and power range low channels are OPERABLE prior to taking the reactor critical and after reducing power into the applicable MODE (< P-10 or < P-6) for periods > 4 hours. The Frequency of 184 days is justified in Reference 11.
Channel unavailability evaluations in McGuire Units 1 and 2 B 3.3.1-45 Revision No. 99 RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.3.1.9 72   `.,.         SR 3.3.1.9 is the performance of a TADOT and is performed every 92 days, as justified in Reference 7.
References 10 and 11 have conservatively assumed that the CHANNEL CALIBRAITON is performed at power with the channel in bypass.CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies that the channel responds to a measured parameter within the necessary range and accuracy.CHANNEL CALIBRATIONS must be performed consistent with the assumptions of the setpoint methodology.
The SR is modified by a Note that excludes verification of setpoints from the TADOT. Since this SR applies to RCP undervoltage and underfrequency relays, setpoint verification is accomplished during the CHANNEL CALIBRATION.
SR 3.3.1.10 A CHANNEL CALIBRATION is performed every 18 months. The CHANNEL CALIBRATION may be performed at power or during refueling based on testing capability. Channel unavailability evaluations in McGuire Units 1 and 2                   B 3.3.1-45                             Revision No. 99
 
RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued)
References 10 and 11 have conservatively assumed that the CHANNEL CALIBRAITON is performed at power with the channel in bypass.
CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies that the channel responds to a measured parameter within the necessary range and accuracy.
CHANNEL CALIBRATIONS must be performed consistent with the assumptions of the setpoint methodology.
The Frequency of 18 months is based on the assumption of an 18 month calibration interval in the determination of the magnitude of equipment drift in the setpoint methodology.
The Frequency of 18 months is based on the assumption of an 18 month calibration interval in the determination of the magnitude of equipment drift in the setpoint methodology.
SR 3.3.1.10 is modified by a Note stating that this test shall include verification that the time constants are adjusted to the prescribed values where applicable.
SR 3.3.1.10 is modified by a Note stating that this test shall include verification that the time constants are adjusted to the prescribed values where applicable. The applicable time constants are shown in Table 1-1.
The applicable time constants are shown in Table 1-1.SR 3.3.1.11 SR 3.3.1.11 is the performance of a CHANNEL CALIBRATION, as described in SR 3.3.1.10, every 18 months. Two notes modify this SR.Note 1 states that neutron detectors are excluded from the CHANNEL CALIBRATION.
SR 3.3.1.11 SR 3.3.1.11 is the performance of a CHANNEL CALIBRATION, as described in SR 3.3.1.10, every 18 months. Two notes modify this SR.
The CHANNEL CALIBRATION for the power range neutron detectors consists of a normalization of the detectors based on a power calorimetric and flux map performed above 15% RTP. The CHANNEL CALIBRATION for the source range neutron detectors consists of two methods. Method 1 consists of obtaining the discriminator curves for source range, evaluating those curves, and comparing the curves to the manufacturer's data (adjustments to the discriminator voltage are performed as required).
Note 1 states that neutron detectors are excluded from the CHANNEL CALIBRATION. The CHANNEL CALIBRATION for the power range neutron detectors consists of a normalization of the detectors based on a power calorimetric and flux map performed above 15% RTP. The CHANNEL CALIBRATION for the source range neutron detectors consists of two methods. Method 1 consists of obtaining the discriminator curves for source range, evaluating those curves, and comparing the curves to the manufacturer's data (adjustments to the discriminator voltage are performed as required). Method 2 consists of performing waveform analysis. This analysis process monitors the actual number and amplitude of the Neutron/Gamma pulses being generated by the SR detector. The high voltage is adjusted to optimize the amplitude of the pulses while maintaining as low as possible high voltage value in order to prolong the detector life. The discriminator voltage is then adjusted, as required, to reasonably ensure that the neutron pulses are being counted by the source range instrumentation and the unwanted gamma pulses are not being counted as neutron pulses.
Method 2 consists of performing waveform analysis.
The CHANNEL CALIBRATION for the intermediate range neutron detectors consists of the high voltage detector plateau for intermediate range, evaluating those curves, and comparing the curves to the manufacturer's data. Note 2 states that this Surveillance is not required McGuire Units 1 and 2                   B 3.3.1-46                           Revision No. 49-
This analysis process monitors the actual number and amplitude of the Neutron/Gamma pulses being generated by the SR detector.
 
The high voltage is adjusted to optimize the amplitude of the pulses while maintaining as low as possible high voltage value in order to prolong the detector life. The discriminator voltage is then adjusted, as required, to reasonably ensure that the neutron pulses are being counted by the source range instrumentation and the unwanted gamma pulses are not being counted as neutron pulses.The CHANNEL CALIBRATION for the intermediate range neutron detectors consists of the high voltage detector plateau for intermediate range, evaluating those curves, and comparing the curves to the manufacturer's data. Note 2 states that this Surveillance is not required McGuire Units 1 and 2 B 3.3.1-46 Revision No. 49-RTS Instrumentation B 3.3.1 BASES
RTS Instrumentation B 3.3.1 BASES REFERENCE*          1. UFSAR, Chapter 7.
: 1. UFSAR, Chapter 7.2. UFSAR, Chapter 6.3. UFSAR, Chapter 15.4. IEEE-279-1971.
: 2. UFSAR, Chapter 6.
: 5. 10 CFR 50.49.6. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).
: 3. UFSAR, Chapter 15.
: 7. WCAP-1 0271-P-A, Supplement 2, Rev. 1, June 1990.8. WCAP 13632-P-A, Revision 2, "Elimination of Pressure Sensor Response Time Testing Requirements" Sep., 1995.9. WCAP-14036-P-A, Revision 1, "Elimination of Periodic Protection Channel Response Time Tests" Oct., 1998.10. WCAP-14333-P-A, Revision 1, October 1998.11. WCAP-15376-P-A, Revision 1, March 2003.~~E.A- F McGuire Units 1 and 2 B 3.3.1-50 Revision No. -99&#xfd;-
: 4. IEEE-279-1971.
: 5. 10 CFR 50.49.
: 6. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).
: 7. WCAP-1 0271-P-A, Supplement 2, Rev. 1, June 1990.
: 8. WCAP 13632-P-A, Revision 2, "Elimination of Pressure Sensor Response Time Testing Requirements" Sep., 1995.
: 9. WCAP-14036-P-A, Revision 1, "Elimination of Periodic Protection Channel Response Time Tests" Oct., 1998.
: 10. WCAP-14333-P-A, Revision 1, October 1998.
: 11. WCAP-15376-P-A, Revision 1, March 2003.
                              ~~E.A- F McGuire Units 1 and 2             B 3.3.1-50                               Revision No. -99&#xfd;-
 
MNS Bases 3.3.2 INSERTS INSERT 1 (new paragraph)
MNS Bases 3.3.2 INSERTS INSERT 1 (new paragraph)
For Functions for which TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions" has been implemented, this SR is modified by two Notes as identified in Table 3.3.2-1. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value. Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology.
For Functions for which TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions" has been implemented, this SR is modified by two Notes as identified in Table 3.3.2-1. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value. Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology. The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the performance of these channels will be evaluated under the plant Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition. The second Note requires that the as-left setting for the channel be returned to within the as-left tolerance of the Nominal Trip Setpoint (NTSP). Where a setpoint more conservative than the NTSP is used in the plant surveillance procedures (field setting), the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint. This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit is maintained. If the as-left channel setting cannot be returned to a setting within the as-left tolerance of the NTSP, then the channel shall be declared inoperable. The second Note also requires that the methodologies for calculating the as-left and the as-found tolerances be in the UFSAR. The NOMINAL TRIP SETPOINT definition includes a provision that would allow the as-left setting for the channel to be outside the tolerance band, provided the setting is conservative with respect to the NTSP. This provision is not applicable to Functions for-which the second Note applies.
The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the performance of these channels will be evaluated under the plant Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition.
INSERT 2 Technical Specification Task Force, Improved Standard Technical Specifications Change Traveler, TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions," Revision 4.
The second Note requires that the as-left setting for the channel be returned to within the as-left tolerance of the Nominal Trip Setpoint (NTSP). Where a setpoint more conservative than the NTSP is used in the plant surveillance procedures (field setting), the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint.
 
This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit is maintained.
If the as-left channel setting cannot be returned to a setting within the as-left tolerance of the NTSP, then the channel shall be declared inoperable.
The second Note also requires that the methodologies for calculating the as-left and the as-found tolerances be in the UFSAR. The NOMINAL TRIP SETPOINT definition includes a provision that would allow the as-left setting for the channel to be outside the tolerance band, provided the setting is conservative with respect to the NTSP. This provision is not applicable to Functions for-which the second Note applies.INSERT 2 Technical Specification Task Force, Improved Standard Technical Specifications Change Traveler, TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions," Revision 4.
ESFAS Instrumentation B 3.3.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
ESFAS Instrumentation B 3.3.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
: 9. Containment Pressure Control System Permissives The Containment Pressure Control System (CPCS) protects the Containment Building from excessive depressurization by preventing inadvertent actuation or continuous operation of the Containment Spray and Containment Air Return Systems when containment pressure is at or less than the CPCS permissive setpoint.
: 9.       Containment Pressure Control System Permissives The Containment Pressure Control System (CPCS) protects the Containment Building from excessive depressurization by preventing inadvertent actuation or continuous operation of the Containment Spray and Containment Air Return Systems when containment pressure is at or less than the CPCS permissive setpoint. The control scheme of CPCS is comprised of eight independent control circuits (4 per train), each having a separate and independent pressure transmitter and current alarm module. Each pressure transmitter monitors the containment pressure and provides input to its respective current alarm. The current alarms are set to inhibit or terminate containment spray and containment air return fan operation when containment pressure falls below the setpoint.
The control scheme of CPCS is comprised of eight independent control circuits (4 per train), each having a separate and independent pressure transmitter and current alarm module. Each pressure transmitter monitors the containment pressure and provides input to its respective current alarm. The current alarms are set to inhibit or terminate containment spray and containment air return fan operation when containment pressure falls below the setpoint..The alarm modules switch back to the permissive state (allowing the systems to operate) when containment pressure is greater than or equal to the setpoint.This function must be OPERABLE in MODES 1, 2, 3, and 4 when there is sufficient energy in the primary and secondary sides to pressurize containment following a pipe break. In MODES 5 and 6, there is insufficient energy in the primary and secondary sides to significantly pressurize the containment.
                            .The alarm modules switch back to the permissive state (allowing the systems to operate) when containment pressure is greater than or equal to the setpoint.
The ESFAS instrumentation satisfies Criterion 3 of 10 CFR 50.36 (Ref. 6).ACTIONS A Note has been added in the ACTIONS to clarify the application of Completion Time rules. The Conditions of this Specification may be entered independently for each Function listed on Table 3.3.2-1. When the Required Channels in Table 3.3.2-1 are specified (e.g., on a per steam line, per loop, per SG, etc., basis), then the Condition may be entered separately for each steam line, loop, SG, etc., as appropriate.
This function must be OPERABLE in MODES 1, 2, 3, and 4 when there is sufficient energy in the primary and secondary sides to pressurize containment following a pipe break. In MODES 5 and 6, there is insufficient energy in the primary and secondary sides to significantly pressurize the containment.
A channel shall be OPERABLE if the point at which the channel trips is found equal to or more conservative than the Allowable Value. In the event a channel's trip setpoint is found less conservative than the Allowable Value, or the transmitter, instrument loop, signal processing electronics, or bistable is found inoperable, then all affected Functions provided by the channel must be declared inoperable and the LCO Condition(s) entered for the protection-unctionr`sns) af ected. ,lWplant conditions warrant, the trip setpoint may be set outside the NOMINAL TRIP SETPOINT calibration tolerance band as long as the trip setpoint is conservative with respect to the NOMINAL TRIP SETPOINT.If the trip setpoint is found outside the NOMINAL TRIP SETPINT calibration tolerance band and non-conservative with respect to the NOMINAL TRIP) ~ASETPOINT, the setpoint shall be re-adjusted.
The ESFAS instrumentation satisfies Criterion 3 of 10 CFR 50.36 (Ref. 6).
McGuire Units 1 and 2 B 3.3.2-28 Revision No. 49-ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE REQUIREMENTS (continued)
ACTIONS             A Note has been added in the ACTIONS to clarify the application of Completion Time rules. The Conditions of this Specification may be entered independently for each Function listed on Table 3.3.2-1. When the Required Channels in Table 3.3.2-1 are specified (e.g., on a per steam line, per loop, per SG, etc.,
basis), then the Condition may be entered separately for each steam line, loop, SG, etc., as appropriate.
A channel shall be OPERABLE if the point at which the channel trips is found equal to or more conservative than the Allowable Value. In the event a channel's trip setpoint is found less conservative than the Allowable Value, or the transmitter, instrument loop, signal processing electronics, or bistable is found inoperable, then all affected Functions provided by the channel must be declared inoperable and the LCO Condition(s) entered for the protection
                      -unctionr`sns) af ected. ,lWplant conditions warrant, the trip setpoint may be set outside the NOMINAL TRIP SETPOINT calibration tolerance band as long as the trip setpoint is conservative with respect to the NOMINAL TRIP SETPOINT.
If the trip setpoint is found outside the NOMINAL TRIP SETPINT calibration tolerance band and non-conservative with respect to the NOMINAL TRIP
  ) ~ASETPOINT,                     the setpoint shall be re-adjusted.
McGuire Units 1 and 2                     B 3.3.2-28                                   Revision No. 49-
 
ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.3.2.3 is the performance of a COT on the RWST level and Containment Pressure Control Start and Terminate Permissives.
SR 3.3.2.3 is the performance of a COT on the RWST level and Containment Pressure Control Start and Terminate Permissives.
A COT is performed on each required channel to ensure the entire channel will perform the intended Function.
A COT is performed on each required channel to ensure the entire channel will perform the intended Function. Setpoints must be found within the Allowable Values specified in Table 3.3. 2-1. This test is performed every 31 days. The Frequency is adequate, based on operating experience, considering instrument reliability and operating history data.
Setpoints must be found within the Allowable Values specified in Table 3.3. 2-1. This test is performed every 31 days. The Frequency is adequate, based on operating experience, considering instrument reliability and operating history data.SR 3.3.2.4 SR 3.3.2.4 is the performance of a MASTER RELAY TEST. The MASTER RELAY TEST is the energizing of the master relay, verifying contact operation and a low voltage continuity check of the slave relay coil. Upon master relay contact operation, a low voltage is injected to the slave relay coil. This voltage is insufficient to pick up the slave relay, but large enough to demonstrate signal path continuity.
SR 3.3.2.4 SR 3.3.2.4 is the performance of a MASTER RELAY TEST. The MASTER RELAY TEST is the energizing of the master relay, verifying contact operation and a low voltage continuity check of the slave relay coil. Upon master relay contact operation, a low voltage is injected to the slave relay coil. This voltage is insufficient to pick up the slave relay, but large enough to demonstrate signal path continuity. This test is performed every 92 days on a STAGGERED TEST BASIS. The time allowed for the testing (4 hours) is justified in Reference 7.
This test is performed every 92 days on a STAGGERED TEST BASIS. The time allowed for the testing (4 hours) is justified in Reference 7.The frequency of 92 days is justified in Reference 11.SR 3.3.2.5 SR 3.3.2.5 is the performance of a COT.A COT is performed on each required channel to ensure the channel will perform the intended Function.
The frequency of 92 days is justified in Reference 11.
The tested portion of the loop must trip within the Allowable Values specified in Table 3.3. 2-1.The setpoint shall be left set consistent with the assumptions of the setpoint methodology.
SR 3.3.2.5 SR 3.3.2.5 is the performance of a COT.
Tf ays is justified in Reference 11.SR 3.3.2.6 SR 3.3.2.6 is the performance of a SLAVE RELAY TEST. The SLAVE RELAY TEST is the energizing of the slave relays. Contact operation is verified in one of two ways. Actuation equipment that may be operated in the design mitigation MODE is either allowed to function, or is placed in a condition where the relay contact operation can be verified without operation of the equipment.
A COT is performed on each required channel to ensure the channel will perform the intended Function. The tested portion of the loop must trip within the Allowable Values specified in Table 3.3. 2-1.
Actuation equipment that may not be operated in the design mitigation MODE is prevented from operation by the SLAVE RELAY TEST circuit. For this latter case, contact operation is verified by a continuity check of the circuit containing McGuire Units 1 and 2 B 3.3.2-40 Revision No. &#xfd;9&#xfd; ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE REQUIREMENTS (continued) the slave relay. This test is performed every 92 days. The Frequency is adequate, based on industry operating experience, considering instrument reliability and operating history data.SR 3.3.2.7 SR 3.3.2.7 is the performance of a TADOT. This test is a check of the Manual Actuation Functions, AFW pump start, Reactor Trip (P-4) Interlock and Doghouse Water Level -High High feedwater isolation.
The setpoint shall be left set consistent with the assumptions of the setpoint methodology.
It is performed every 18 months. Each Manual Actuation Function is tested up to, and including, the master relay coils. In some instances, the test includes actuation of the end device (i.e., pump starts, valve cycles, etc.). The Frequency is adequate, based on industry operating experience and is consistent with the typical refueling cycle. The SR is modified by a Note that excludes verification of setpoints during the TADOT for manual initiation Functions.
Tf                         ays is justified in Reference 11.
The manual initiation Functions have no associated setpoints.
SR 3.3.2.6 SR 3.3.2.6 is the performance of a SLAVE RELAY TEST. The SLAVE RELAY TEST is the energizing of the slave relays. Contact operation is verified in one of two ways. Actuation equipment that may be operated in the design mitigation MODE is either allowed to function, or is placed in a condition where the relay contact operation can be verified without operation of the equipment.
Actuation equipment that may not be operated in the design mitigation MODE is prevented from operation by the SLAVE RELAY TEST circuit. For this latter case, contact operation is verified by a continuity check of the circuit containing McGuire Units 1 and 2                   B 3.3.2-40                                 Revision No. &#xfd;9&#xfd;
 
ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE REQUIREMENTS (continued) the slave relay. This test is performed every 92 days. The Frequency is adequate, based on industry operating experience, considering instrument reliability and operating history data.
SR 3.3.2.7 SR 3.3.2.7 is the performance of a TADOT. This test is a check of the Manual Actuation Functions, AFW pump start, Reactor Trip (P-4) Interlock and Doghouse Water Level - High High feedwater isolation. It is performed every 18 months. Each Manual Actuation Function is tested up to, and including, the master relay coils. In some instances, the test includes actuation of the end device (i.e., pump starts, valve cycles, etc.). The Frequency is adequate, based on industry operating experience and is consistent with the typical refueling cycle. The SR is modified by a Note that excludes verification of setpoints during the TADOT for manual initiation Functions. The manual initiation Functions have no associated setpoints.
SR 3.3.2.8 SR 3.3.2.8 is the performance of a CHANNEL CALIBRATION.
SR 3.3.2.8 SR 3.3.2.8 is the performance of a CHANNEL CALIBRATION.
A CHANNEL CALIBRATION is performed every 18 months. The CHANNEL CALIBRATION may be performed at power or during refueling based on bypass testing capability.
A CHANNEL CALIBRATION is performed every 18 months. The CHANNEL CALIBRATION may be performed at power or during refueling based on bypass testing capability. Channel unavailability evaluations in References 10 and 11 have conservatively assumed that the CHANNEL CALIBRATION is performed at power with the channel in bypass.
Channel unavailability evaluations in References 10 and 11 have conservatively assumed that the CHANNEL CALIBRATION is performed at power with the channel in bypass.CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies that the channel responds to measured parameter within the necessary range and accuracy.CHANNEL CALIBRATIONS must be performed consistent with the assumptions of the unit specific setpoint methodology.
CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies that the channel responds to measured parameter within the necessary range and accuracy.
CHANNEL CALIBRATIONS must be performed consistent with the assumptions of the unit specific setpoint methodology.
The Frequency of 18 months is based on the assumption of an 18 month calibration interval in the determination of the magnitude of equipment drift in the setpoint methodology.
The Frequency of 18 months is based on the assumption of an 18 month calibration interval in the determination of the magnitude of equipment drift in the setpoint methodology.
This SR is modified by a Note stating that this test should include verification that the time constants are adjusted to the prescribed values where applicable.
This SR is modified by a Note stating that this test should include verification that the time constants are adjusted to the prescribed values where applicable.
The applicable time constants are shown in Table 3.3.2-1.S R 3.3.2.9 McGuire Units 1 and 2 B 3.3.2-41 Revision No.
The applicable time constants are shown in Table 3.3.2-1.
SR 3.3.2.9 McGuire Units 1 and 2                   B 3.3.2-41                                 Revision No.
ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE REQUIREMENTS (continued) may be replaced without verification testing. One example where response time could be affected is replacing the sensing assembly of a transmitter.
ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE REQUIREMENTS (continued) may be replaced without verification testing. One example where response time could be affected is replacing the sensing assembly of a transmitter.
ESF RESPONSE TIME tests are conducted on an 18 month STAGGERED TEST BASIS. Testing of the final actuation devices, which make up the bulk of the response time, is included in the testing of each channel. The final actuation device in one train is tested with each channel. Therefore, staggered testing results in response time verification of these devices every 18 months.The 18 month Frequency is consistent with the typical refueling cycle and is based on unit operating experience, which shows that random failures of instrumentation components causing serious response time degradation, but not channel failure, are infrequent occurrences.
ESF RESPONSE TIME tests are conducted on an 18 month STAGGERED TEST BASIS. Testing of the final actuation devices, which make up the bulk of the response time, is included in the testing of each channel. The final actuation device in one train is tested with each channel. Therefore, staggered testing results in response time verification of these devices every 18 months.
This SR is modified by a Note that clarifies that the turbine driven AFW pump is tested within 24 hours after reaching 900 psig in the SGs.REFERENCES  
The 18 month Frequency is consistent with the typical refueling cycle and is based on unit operating experience, which shows that random failures of instrumentation components causing serious response time degradation, but not channel failure, are infrequent occurrences.
: 1. UFSAR, Chapter 6.2. UFSAR, Chapter 7.3... UFSAR, Chapter 15.4. IEEE-279-1971.
This SR is modified by a Note that clarifies that the turbine driven AFW pump is tested within 24 hours after reaching 900 psig in the SGs.
: 5. 10 CFR 50.49.6. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).
REFERENCES           1. UFSAR, Chapter 6.
: 7. WCAP-10271-P-A, Supplement 1 and Supplement 2, Rev. 1, May 1986 and June 1990.8. WCAP 13632-P-A, Revision 2, "Elimination of Pressure Sensor Response Time Testing Requirements" Sep., 1995.9. WCAP-14036-P-A, Revision 1, "Elimination of Periodic Protection Channel Response Time Tests" Oct., 1998.10. WCAP-14333-P-A, Revision 1, October 1998.11. WCAP-15376-P-A, Revision 1, March 2003.McGuire Units 1 and 2 B 3.3.2-43 Revision No. 49-U.S. Nuclear Regulatory Commission June 29, 2010 ATTACHMENT 2b Catawba Units I and 2 Technical Specification Bases Page Markups (Provided for information only)
: 2. UFSAR, Chapter 7.
3... UFSAR, Chapter 15.
: 4. IEEE-279-1971.
: 5. 10 CFR 50.49.
: 6. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).
: 7. WCAP-10271-P-A, Supplement 1 and Supplement 2, Rev. 1, May 1986 and June 1990.
: 8. WCAP 13632-P-A, Revision 2, "Elimination of Pressure Sensor Response Time Testing Requirements" Sep., 1995.
: 9. WCAP-14036-P-A, Revision 1, "Elimination of Periodic Protection Channel Response Time Tests" Oct., 1998.
: 10. WCAP-14333-P-A, Revision 1, October 1998.
: 11. WCAP-15376-P-A, Revision 1, March 2003.
McGuire Units 1 and 2                   B 3.3.2-43                                 Revision No. 49-
 
U.S. Nuclear Regulatory Commission June 29, 2010 ATTACHMENT 2b Catawba Units I and 2 Technical Specification Bases Page Markups (Provided for information only)
 
CNS Bases 3.3.1 INSERTS INSERT 1 (new paragraph)
CNS Bases 3.3.1 INSERTS INSERT 1 (new paragraph)
For Functions for which TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions" has been implemented, this SR is modified by two Notes as identified in Table 3.3.1-1. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value. Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology.
For Functions for which TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions" has been implemented, this SR is modified by two Notes as identified in Table 3.3.1-1. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value. Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology. The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the performance of these channels will be evaluated under the plant Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition. The second Note requires that the as-left setting for the channel be returned to within the as-left tolerance of the Nominal Trip Setpoint (NTSP). Where a setpoint more conservative than the NTSP is used in the plant surveillance procedures (field setting), the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint. This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit-is maintained. If the as-left channel setting cannot be returned to a setting within the as-left tolerance of the NTSP, then the channel shall be declared inoperable. The second Note also requires that the methodologies for calculating the as-left and the as-found tolerances be in the UFSAR. The NOMINAL TRIP SETPOINT definition includes a provision that would allow the as-left setting for the channel to be outside the tolerance band, provided the setting is conservative with respect to the NTSP. This provision is not applicable to Functions for which the second Note applies.
The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the performance of these channels will be evaluated under the plant Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition.
INSERT 2 Technical Specification Task Force, Improved Standard Technical Specifications Change Traveler, TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions," Revision 4.
The second Note requires that the as-left setting for the channel be returned to within the as-left tolerance of the Nominal Trip Setpoint (NTSP). Where a setpoint more conservative than the NTSP is used in the plant surveillance procedures (field setting), the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint.
 
This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit-is maintained.
If the as-left channel setting cannot be returned to a setting within the as-left tolerance of the NTSP, then the channel shall be declared inoperable.
The second Note also requires that the methodologies for calculating the as-left and the as-found tolerances be in the UFSAR. The NOMINAL TRIP SETPOINT definition includes a provision that would allow the as-left setting for the channel to be outside the tolerance band, provided the setting is conservative with respect to the NTSP. This provision is not applicable to Functions for which the second Note applies.INSERT 2 Technical Specification Task Force, Improved Standard Technical Specifications Change Traveler, TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions," Revision 4.
RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
: 19. Automatic Trip Loqic The LCO requirement for the RTBs (Functions 17 and 18) and Automatic Trip Logic (Function  
: 19. Automatic Trip Loqic The LCO requirement for the RTBs (Functions 17 and 18) and Automatic Trip Logic (Function 19) ensures that means are provided to interrupt the power to allow the rods to fall into the reactor core. Each RTB is equipped with an undervoltage coil and a shunt trip coil to trip the breaker open when needed. Each train RTB has a bypass breaker to allow testing of the trip breaker while the unit is at power. The reactor trip signals generated by the RTS Automatic Trip Logic cause the RTBs and associated bypass breakers to open and shut down the reactor.
: 19) ensures that means are provided to interrupt the power to allow the rods to fall into the reactor core. Each RTB is equipped with an undervoltage coil and a shunt trip coil to trip the breaker open when needed. Each train RTB has a bypass breaker to allow testing of the trip breaker while the unit is at power. The reactor trip signals generated by the RTS Automatic Trip Logic cause the RTBs and associated bypass breakers to open and shut down the reactor.The LCO requires two trains of RTS Automatic Trip Logic to be OPERABLE.
The LCO requires two trains of RTS Automatic Trip Logic to be OPERABLE. Having two OPERABLE channels ensures that random failure of a single logic channel will not prevent reactor trip.
Having two OPERABLE channels ensures that random failure of a single logic channel will not prevent reactor trip.These trip Functions must be OPERABLE in MODE 1 or 2 when the reactor is critical.
These trip Functions     must be OPERABLE in MODE 1 or 2 when the reactor is critical. In MODE 3, 4, or 5, these RTS trip Functions must be OPERABLE         when the RTBs and associated bypass breakers are closed,     and the CRD System is capable of rod withdrawal.
In MODE 3, 4, or 5, these RTS trip Functions must be OPERABLE when the RTBs and associated bypass breakers are closed, and the CRD System is capable of rod withdrawal.
The RTS instrumentation satisfies Criterion 3 of 10 CFR 50.36 (Ref. 6).
The RTS instrumentation satisfies Criterion 3 of 10 CFR 50.36 (Ref. 6).ACTIONS A Note has been added to the ACTIONS to clarify the application of Completion Time rules. The Conditions of this Specification may be entered independently for each Function listed in Table 3.3.1-1. When the Required Channels in Table 3.3.1-1 are specified (e.g., on a per steam line, per loop, per SG, etc., basis), then the Condition may be entered separately for each steam line, loop, SG, etc., as appropriate.
ACTIONS             A Note has been added to the ACTIONS to clarify the application of Completion Time rules. The Conditions of this Specification may be entered independently for each Function listed in Table 3.3.1-1. When the Required Channels in Table 3.3.1-1 are specified (e.g., on a per steam line, per loop, per SG, etc., basis), then the Condition may be entered separately for each steam line, loop, SG, etc., as appropriate.
0A channel shall be OPERABLE if the point at which the channel trips is-found more conservative than the Allowable Value. In the event a*~ channel's trip setpoint is found less conservative than the Allowable Value, or the transmitter, instrument loop, signal processing electronics, or bistable is found inoperable, then all affected Functions provided by that channel must be declared inoperable and the LCO Condition(s) en ere or e p n nc ion s a ected. 11,,Olant conditions warrant, the trip setpoint may be set outside the NOMINAL TRIP SETPOINT calibration tolerance band as long as the trip.setpoint is conservative with respect to the NOMINAL TRIP SETPOINT.
0A               channel shall be OPERABLE if the point at which the channel trips is
If the trip setpoint is found outside of the NOMINAL TRIP SETPOINT calibration tolerance band and non-conservative with respect to the NOMINAL TRIP Catawba Units 1 and 2 B 3.3.1-30 Revision No. +-
                    -found more conservative than the Allowable Value. In the event a
RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued) condition, thus preventing inadvertent actuation.
  *~
Through the semiautomatic tester, all possible logic combinations, with and without applicable permissives, are tested for each protection function.
* channel's trip setpoint is found less conservative than the Allowable Value, or the transmitter, instrument loop, signal processing electronics, or bistable is found inoperable, then all affected Functions provided by that channel must be declared inoperable and the LCO Condition(s) en ere or e p               n     nc ion s a ected. 11,,Olant conditions warrant, the trip setpoint may be set outside the NOMINAL TRIP SETPOINT calibration tolerance band as long as the trip.setpoint is conservative with respect to the NOMINAL TRIP SETPOINT. If the trip setpoint is found outside of the NOMINAL TRIP SETPOINT calibration tolerance band and non-conservative with respect to the NOMINAL TRIP Catawba Units 1 and 2                   B 3.3.1-30                                 Revision No. +-
The Frequency of every 92 days on a STAGGERED TEST BASIS is justified in Reference 12.SR 3.3.1.6 SR 3.3.1.6 is a calibration of the excore channels to the incore channels.If the measurements do not agree, the excore channels are not declared inoperable but must be calibrated to agree with the incore detector measurements.
 
If the excore channels cannot be adjusted, the channels are declared inoperable.
RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued) condition, thus preventing inadvertent actuation. Through the semiautomatic tester, all possible logic combinations, with and without applicable permissives, are tested for each protection function. The Frequency of every 92 days on a STAGGERED TEST BASIS is justified in Reference 12.
This Surveillance is performed to verify the f(AI)input to the overtemperature AT Function and overpower AT Functionm At Beginning of Cycle (BOC), the excore channels are compared to the incore detector measurements prior to exceeding 75% power. Excore detectors are adjusted as necessary.
SR 3.3.1.6 SR 3.3.1.6 is a calibration of the excore channels to the incore channels.
This low power surveillance 31"1v, satisfies the initial performance of SR 3.3.1.6 with subsequent , surveillances conducted at least every 92 EFPD.At BOC, after reaching full power steady state conditions, additional incore and excore measurements are taken at various Al conditions to determine the Mj factors. The Mj factors are normally only determined at BOC, but they may be changed at other points in the fuel cycle if the-. .relationship between excore and incore measurements changes significantly.
If the measurements do not agree, the excore channels are not declared inoperable but must be calibrated to agree with the incore detector measurements. If the excore channels cannot be adjusted, the channels are declared inoperable. This Surveillance is performed to verify the f(AI) input to the overtemperature AT Function and overpower AT Functionm At Beginning of Cycle (BOC), the excore channels are compared to the incore detector measurements prior to exceeding 75% power. Excore detectors are adjusted as necessary. This low power surveillance 31"1v, satisfies the initial performance of SR 3.3.1.6 with subsequent
A Note modifies SR 3.3.1.6. The Note states that this Surveillance is , , required only if reactor power is > 75% RTP and that 24 hours is allowed--for completing the first surveillance after reaching 75% RTP.The Frequency of 92 EFPD is adequate.
        ,           surveillances conducted at least every 92 EFPD.
It is based on industry operating experience, considering instrument reliability and operating history data for instrument drift.SR 3.3.1.7 SR 3.3.1.7 is the performance of a COT every 184 days.A COT is performed on each required channel to ensure the channel will Catawba Units 1 and 2 B 3.31-45 Revision No- 3 RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued) perform the intended Function.The tested portion of the loop must trip within the Allowable Values specified in Table 3.3.1-1.The setpoint shall be left set consistent with the assumptions of the setpoint methodology.
At BOC, after reaching full power steady state conditions, additional incore and excore measurements are taken at various Al conditions to determine the Mj factors. The Mj factors are normally only determined at BOC, but they may be changed at other points in the fuel cycle if the
SR 3.3.1.7 is modified by a Note that provides a 4 hour delay in the requirement to perform this Surveillance for source range instrumentation when entering MODE 3 from MODE 2. This Note allows a normal shutdown to proceed without a delay for testing in MODE 2 and for a short time in MODE 3 until the RTBs are open and SR 3.3.1.7 is no longer required to be performed.
          -.     . relationship between excore and incore measurements changes significantly.
If the unit is to be in MODE 3 with the RTBs closed for > 4 hours this Surveillance must be completed within 4 hours after entry into MODE 3.J Fr gujwxQL 84 days is justified in Reference 12.SR 3.3.1.8 is the performance of a COT as described in SR 3.3.1.7, except it is modified by a Note that this test shall include verification that the P-6, during the Intermediate Range COT, and P-10, during the Power Range COT, interlocks are in their required state for the existing unit condition.
A Note modifies SR 3.3.1.6. The Note states that this Surveillance is
The verification is performed by visual observation of the permissive status light in the unit control room. The Frequency is modified by a Note that allows this surveillance to be satisfied if it has'been performed within 184 days of the Frequencies prior to reactor startup and four hours after reducing power below P-10 and P-6. The Frequency of "prior to startup" ensures this surveillance is performed prior to critical operations and applies to the source, intermediate and power range low instrument channels.
              ,   , required only if reactor power is > 75% RTP and that 24 hours is allowed
The Frequency of "4 hours after reducing power below P-10" (applicable to intermediate and power range low channels) and "4 hours after reducing power below P-6" (applicable to source range channels) allows a normal shutdown to be completed and the unit removed from the MODE of Applicability for this surveillance without a delay to perform the testing required by this surveillance.
      -         -   for completing the first surveillance after reaching 75% RTP.
The Frequency of every 184 days thereafter applies if the plant remains in the MODE of Applicability after the initial performances of prior to reactor startup and four hours after reducing power below P-10 or P-6. The MODE of Applicability for this surveillance is < P-1 0 for the power range low and intermediate range channels and < P-6 for the source range channels.Catawba Units 1 and 2 B 3.3.1-46 Revision No.
The Frequency of 92 EFPD is adequate. It is based on industry operating experience, considering instrument reliability and operating history data for instrument drift.
SR 3.3.1.7 SR 3.3.1.7 is the performance of a COT every 184 days.
A COT is performed on each required channel to ensure the channel will Catawba Units 1 and 2                   B 3.31-45                               Revision No- 3
 
RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued) perform the intended Function.
The tested portion of the loop must trip within the Allowable Values specified in Table 3.3.1-1.
The setpoint shall be left set consistent with the assumptions of the setpoint methodology.
SR 3.3.1.7 is modified by a Note that provides a 4 hour delay in the requirement to perform this Surveillance for source range instrumentation when entering MODE 3 from MODE 2. This Note allows a normal shutdown to proceed without a delay for testing in MODE 2 and for a short time in MODE 3 until the RTBs are open and SR 3.3.1.7 is no longer required to be performed. If the unit is to be in MODE 3 with the RTBs closed for > 4 hours this Surveillance must be completed within 4 hours after entry into MODE 3.
J       Fr gujwxQL 84 days is justified in Reference 12.
SR 3.3.1.8 is the performance of a COT as described in SR 3.3.1.7, except it is modified by a Note that this test shall include verification that the P-6, during the Intermediate Range COT, and P-10, during the Power Range COT, interlocks are in their required state for the existing unit condition. The verification is performed by visual observation of the permissive status light in the unit control room. The Frequency is modified by a Note that allows this surveillance to be satisfied if it has' been performed within 184 days of the Frequencies prior to reactor startup and four hours after reducing power below P-10 and P-6. The Frequency of "prior to startup" ensures this surveillance is performed prior to critical operations and applies to the source, intermediate and power range low instrument channels. The Frequency of "4 hours after reducing power below P-10" (applicable to intermediate and power range low channels) and "4 hours after reducing power below P-6" (applicable to source range channels) allows a normal shutdown to be completed and the unit removed from the MODE of Applicability for this surveillance without a delay to perform the testing required by this surveillance. The Frequency of every 184 days thereafter applies if the plant remains in the MODE of Applicability after the initial performances of prior to reactor startup and four hours after reducing power below P-10 or P-6. The MODE of Applicability for this surveillance is < P-1 0 for the power range low and intermediate range channels and < P-6 for the source range channels.
Catawba Units 1 and 2                   B 3.3.1-46                               Revision No.
RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued)
RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued)
Once the unit is in MODE 3, this surveillance is no longer required:
Once the unit is in MODE 3, this surveillance is no longer required: If power is to be maintained < P-10 or < P-6 for more than 4 hours, then the testing required by this surveillance must be performed prior to the expiration of the 4 hour limit. Four hours is a reasonable time to complete the required testing or place the unit in a MODE where this surveillance is no longer required. This test ensures that the NIS source, intermediate, and power range low channels are OPERABLE prior to taking the reactor critical and after reducing power into the applicable MODE (< P-10 or < P-6) for periods > 4 hours. The Frequency of 184 days is justified in Reference 12.
If power is to be maintained  
SR3.3.1.9 SR 3.3.1.9 is the performance of a TADOT and is performed every 92 days, as justified in Reference 7.
< P-10 or < P-6 for more than 4 hours, then the testing required by this surveillance must be performed prior to the expiration of the 4 hour limit. Four hours is a reasonable time to complete the required testing or place the unit in a MODE where this surveillance is no longer required.
The SR is modified by a Note that excludes verification of setpoints from the TADOT. Since this SR applies to RCP undervoltage and underfrequency relays, setpoint verification is accomplished during the CHANNEL CALIBRATION.
This test ensures that the NIS source, intermediate, and power range low channels are OPERABLE prior to taking the reactor critical and after reducing power into the applicable MODE (< P-10 or < P-6) for periods > 4 hours. The Frequency of 184 days is justified in Reference 12.SR3.3.1.9 SR 3.3.1.9 is the performance of a TADOT and is performed every 92 days, as justified in Reference 7.The SR is modified by a Note that excludes verification of setpoints from the TADOT. Since this SR applies to RCP undervoltage and underfrequency relays, setpoint verification is accomplished during the CHANNEL CALIBRATION.
SR 3.3.1.10 A CHANNEL CALIBRATION is performed every 18 months, or approximately at every refueling. CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies that the channel responds to a measured parameter within the necessary range and accuracy.
SR 3.3.1.10 A CHANNEL CALIBRATION is performed every 18 months, or approximately at every refueling.
CHANNEL CALIBRATIONS must be performed consistent with the assumptions of the setpoint methodology.
CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies that the channel responds to a measured parameter within the necessary range and accuracy.CHANNEL CALIBRATIONS must be performed consistent with the assumptions of the setpoint methodology.
The Frequency of 18 months is based on the assumption of an 18 month calibration interval in the determination of the magnitude of equipment drift in the setpoint methodology.
The Frequency of 18 months is based on the assumption of an 18 month calibration interval in the determination of the magnitude of equipment drift in the setpoint methodology.
SR 3.3.1.10 is modified by a Note stating that this test shall include verification that the time constants are adjusted to the prescribed values where applicable.
SR 3.3.1.10 is modified by a Note stating that this test shall include verification that the time constants are adjusted to the prescribed values where applicable. The applicable time constants are shown in Table 3.3.1-1.
The applicable time constants are shown in Table 3.3.1-1.Catawba Units 1 and 2 B 3.3.1-47 Revision No.---3--
Catawba Units 1 and 2                   B 3.3.1-47                             Revision No.---3--
 
RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued)
RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.3.1.11 SR 3.3.1.11 is the performance of a CHANNEL CALIBRATION, as described in SR 3.3.1.10, every 18 months. This SR is modified by two notes. Note 1 states that neutron detectors are excluded from the CHANNEL CALIBRATION.
SR 3.3.1.11 SR 3.3.1.11 is the performance of a CHANNEL CALIBRATION, as described in SR 3.3.1.10, every 18 months. This SR is modified by two notes. Note 1 states that neutron detectors are excluded from the CHANNEL CALIBRATION. The CHANNEL CALIBRATION for the power range neutron detectors consists of a normalization of the detectors based on a power calorimetric and flux map performed above 15% RTP.
The CHANNEL CALIBRATION for the power range neutron detectors consists of a normalization of the detectors based on a power calorimetric and flux map performed above 15% RTP.The CHANNEL CALIBRATION for the source range and intermediate range neutron detectors consists of obtaining the high voltage detector plateau and discriminator curves for source range, and the high voltage detector plateau for intermediate range, evaluating those curves, and comparing the curves to the manufacturer's data. Note 2 states that this Surveillance is not required for the NIS power range detectors for entry into MODE 2 or 1, and is not required for the NIS intermediate range detectors for entry into MODE 2, because the unit must be in at least MODE 2 to perform the test for the intermediate range detectors and MODE 1 for the power range detectors.
The CHANNEL CALIBRATION for the source range and intermediate range neutron detectors consists of obtaining the high voltage detector plateau and discriminator curves for source range, and the high voltage detector plateau for intermediate range, evaluating those curves, and comparing the curves to the manufacturer's data. Note 2 states that this Surveillance is not required for the NIS power range detectors for entry into MODE 2 or 1, and is not required for the NIS intermediate range detectors for entry into MODE 2, because the unit must be in at least MODE 2 to perform the test for the intermediate range detectors and MODE 1 for the power range detectors. The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown these components usually pass the Surveillance when performed on the 18 month Frequency.
The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown these components usually pass the Surveillance when performed on the 18 month Frequency.
SR 3.3.1.12 SR 3.3.1.12 is the performance of a CHANNEL CALIBRATION, as described in SR 3.3.1.10, every 18 months.
SR 3.3.1.12 SR 3.3.1.12 is the performance of a CHANNEL CALIBRATION, as described in SR 3.3.1.10, every 18 months.The Frequency is justified by the assumption of an 18 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.SR 3.3.1.13 SR 3.3.1.13 is the performance of a COTof RTS interlocks every 18 months.The Frequency is based on the known reliability of the interlocks and the multichannel redundancy available, and has been shown to be acceptable through operating experience.
The Frequency is justified by the assumption of an 18 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
Catawba Units 1 and 2 B 3.3.1-48 Revision No.-
SR 3.3.1.13 SR 3.3.1.13 is the performance of a COTof RTS interlocks every 18 months.
The Frequency is based on the known reliability of the interlocks and the multichannel redundancy available, and has been shown to be acceptable through operating experience.
Catawba Units 1 and 2                 B 3.3.1-48                             Revision No.-
RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued) time could be affected is replacing the sensing assembly of a transmitter.
RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued) time could be affected is replacing the sensing assembly of a transmitter.
As appropriate, each channel's response must be verified every 18 months on a STAGGERED TEST BASIS. Testing of the final actuation devices is included in the testing. Testing of the RTS RTDs is performed on an 18 month frequency.
As appropriate, each channel's response must be verified every 18 months on a STAGGERED TEST BASIS. Testing of the final actuation devices is included in the testing. Testing of the RTS RTDs is performed on an 18 month frequency. Response times cannot be determined during unit operation because equipment operation is required to measure response times. Experience has shown that these components usually pass this surveillance when performed at the 18 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
Response times cannot be determined during unit operation because equipment operation is required to measure response times. Experience has shown that these components usually pass this surveillance when performed at the 18 month Frequency.
SR 3.3.1.16 is modified by a Note stating that neutron detectors are excluded from RTS RESPONSE TIME testing. This Note is necessary because of the difficulty in generating an appropriate detector input signal. Excluding the detectors is acceptable because the principles of detector operation ensure a virtually instantaneous response. The response time of the neutron flux signal portion of the channel shall be measured from detector output or input of the first electronic component in the channel.
Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
REFERENCES         1. UFSAR, Chapter 7.
SR 3.3.1.16 is modified by a Note stating that neutron detectors are excluded from RTS RESPONSE TIME testing. This Note is necessary because of the difficulty in generating an appropriate detector input signal. Excluding the detectors is acceptable because the principles of detector operation ensure a virtually instantaneous response.
: 2. UFSAR, Chapter 6.
The response time of the neutron flux signal portion of the channel shall be measured from detector output or input of the first electronic component in the channel.REFERENCES  
: 3. UFSAR, Chapter 15.
: 1. UFSAR, Chapter 7.2. UFSAR, Chapter 6.3. UFSAR, Chapter 15.4. IEEE-279-1971.
: 4. IEEE-279-1971.
: 5. 10 CFR 50.49.6. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).
: 5. 10 CFR 50.49.
: 7. WCAP-1 0271-P-A, Supplement 2, Rev. 1, June 1990.S", WCAP-1 3632-P-A Revision 2, "Elimination of Pressure Sensor Response Time Testing Requirements" Sep., 1995.,, 9. WCAP-14036-P-A Revision 1, "Elimination of Periodic Protection Channel Response Time Tests" Oct., 1998.10.10 CFR 50.67.Catawba Units 1 and 2 B 3.3.1-51 Revision No. 2 RTS Instrumentation B 3.3.1 BASES REFERENCES (continued) 11.WCAP-14333-P-A, Rev. 1, October 1998.12.WCAP-15376-P-A, Rev. 1, March 2003.13, i._SE7,C_7 Catawba Units 1 and 2 B 3.3.1-52 Revision No.-
: 6. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).
: 7. WCAP-1 0271-P-A, Supplement 2, Rev. 1, June 1990.
S",*8.                WCAP-1 3632-P-A Revision 2, "Elimination of Pressure Sensor Response Time Testing Requirements" Sep., 1995.
      *j ,,         9. WCAP-14036-P-A Revision 1, "Elimination of Periodic Protection Channel Response Time Tests" Oct., 1998.
10.10 CFR 50.67.
Catawba Units 1 and 2                 B 3.3.1-51                               Revision No. 2
 
RTS Instrumentation B 3.3.1 BASES REFERENCES (continued) 11.WCAP-14333-P-A, Rev. 1, October 1998.
12.WCAP-15376-P-A, Rev. 1, March 2003.
13,i._SE7,C_7 Catawba Units 1 and 2               B 3.3.1-52                   Revision No.-
CNS Bases 3.3.2 INSERTS INSERT 1 (new paragraph)
CNS Bases 3.3.2 INSERTS INSERT 1 (new paragraph)
For Functions for which TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions" has been implemented, this SR is modified by two Notes as identified in Table 3.3.2-1. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value. Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology.
For Functions for which TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions" has been implemented, this SR is modified by two Notes as identified in Table 3.3.2-1. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value. Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology. The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the performance of these channels will be evaluated under the plant Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition. The second Note requires that the as-left setting for the channel be returned to within the as-left tolerance of the Nominal Trip Setpoint (NTSP). Where a setpoint more conservative than the NTSP is used in the plant surveillance procedures (field setting), the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint. This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit is maintained. If the as-left channel setting cannot be returned to a setting within the as-left tolerance of the NTSP, then the channel shall be declared inoperable. The second Note also requires that the methodologies for calculating the as-left and the as-found tolerances be in the UFSAR. The NOMINAL TRIP SETPOINT definition includes a provision that would allow the as-left setting for the channel to be outside the tolerance band, provided the setting is conservative with respect to the NTSP. This provision is not applicable to Functions for which the second Note applies.
The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the performance of these channels will be evaluated under the plant Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition.
INSERT 2 Technical Specification Task Force, Improved Standard Technical Specifications Change Traveler, TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions," Revision 4.
The second Note requires that the as-left setting for the channel be returned to within the as-left tolerance of the Nominal Trip Setpoint (NTSP). Where a setpoint more conservative than the NTSP is used in the plant surveillance procedures (field setting), the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint.
 
This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit is maintained.
ESFAS Instrumentation B 3.3.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) valves, and start the NSWS pumps. This function is initiated on a two-out-of-three logic from either NSWS pump pit.
If the as-left channel setting cannot be returned to a setting within the as-left tolerance of the NTSP, then the channel shall be declared inoperable.
This function must be OPERABLE in MODES 1, 2, 3, and 4 to ensure cooling water remains available to essential components during a DBA. In MODES 5 and 6, the sufficient time exists for manual operator action to realign the NSWS pump suction, if required.
The second Note also requires that the methodologies for calculating the as-left and the as-found tolerances be in the UFSAR. The NOMINAL TRIP SETPOINT definition includes a provision that would allow the as-left setting for the channel to be outside the tolerance band, provided the setting is conservative with respect to the NTSP. This provision is not applicable to Functions for which the second Note applies.INSERT 2 Technical Specification Task Force, Improved Standard Technical Specifications Change Traveler, TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions," Revision 4.
Unlike other shared NSWS equipment, the pit level interlocks do not require both normal and emergency power for OPERABILITY.
ESFAS Instrumentation B 3.3.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) valves, and start the NSWS pumps. This function is initiated on a two-out-of-three logic from either NSWS pump pit.This function must be OPERABLE in MODES 1, 2, 3, and 4 to ensure cooling water remains available to essential components during a DBA. In MODES 5 and 6, the sufficient time exists for manual operator action to realign the NSWS pump suction, if required.Unlike other shared NSWS equipment, the pit level interlocks do not require both normal and emergency power for OPERABILITY.
This is because unlike mechanical components such as pumps and valves, the interlocks are designed to fail safe upon a loss of power, initiating a transfer from Lake Wylie to the standby nuclear service water pond. The definition of OPERABILITY, which requires either normal or emergency power, provides sufficient power supply requirements and these interlocks can be considered OPERABLE provided they are powered from either an inverter or regulated power.
This is because unlike mechanical components such as pumps and valves, the interlocks are designed to fail safe upon a loss of power, initiating a transfer from Lake Wylie to the standby nuclear service water pond. The definition of OPERABILITY, which requires either normal or emergency power, provides sufficient power supply requirements and these interlocks can be considered OPERABLE provided they are powered from either an inverter or regulated power.The ESFAS instrumentation satisfies Criterion 3 of 10 CFR 50.36 (Ref.6).ACTIONS A Note has been added in the ACTIONS to clarify the application of Completion Time rules. The Conditions of this Specification may be entered independently for each Function listed on Table 3.3.2-1. When the Required Channels in Table 3.3.2-1 are specified (e.g., on a per steam line, per loop, per SG, etc., basis), then the Condition may be entered separately for each steam line, loop, SG, etc., as appropriate.
The ESFAS instrumentation satisfies Criterion 3 of 10 CFR 50.36 (Ref.
A channel shall be OPERABLE if the point at which the channel trips is'V found more conservative than the Allowable Value. In the event a channel's trip setpoint is found less conservative than the Allowable Value, or the transmitter, instrument loop, signal processing electronics, or bistable is found inoperable, then all affected Functions provided by that channel must be declared inoperable and the LCO Condition(s) entered for the protection Function(s) affected),plant conditions warrant, the trip setpoint may be set outside the NOMINAL TRIP SETPOINT calibration tolerance band as long as the trip setpoint is conservative with respect to the NOMINAL TRIP SETPOINT.
6).
If the trip setpoint is found outside of the NOMINAL TRIP SETPOINT calibration tolerance band and non-conservative with respect to the NOMINAL TRIP SETPOINT, the setpoint shall be re-adjusted.
ACTIONS             A Note has been added in the ACTIONS to clarify the application of Completion Time rules. The Conditions of this Specification may be entered independently for each Function listed on Table 3.3.2-1. When the Required Channels in Table 3.3.2-1 are specified (e.g., on a per steam line, per loop, per SG, etc., basis), then the Condition may be entered separately for each steam line, loop, SG, etc., as appropriate.
Catawba Units 1 and 2 B 3.3.2-31 Revision No. 2-ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE REQUIREMENTS (continued) semiautomatic tester, all possible logic combinations, with and without applicable permissives, are tested for each protection function.
A channel shall be OPERABLE if the point at which the channel trips is
In addition, the master relay coil is pulse tested for continuity.
'V                 found more conservative than the Allowable Value. In the event a channel's trip setpoint is found less conservative than the Allowable Value, or the transmitter, instrument loop, signal processing electronics, or bistable is found inoperable, then all affected Functions provided by that channel must be declared inoperable and the LCO Condition(s) entered for the protection Function(s) affected),plant conditions warrant, the trip setpoint may be set outside the NOMINAL TRIP SETPOINT calibration tolerance band as long as the trip setpoint is conservative with respect to the NOMINAL TRIP SETPOINT. If the trip setpoint is found outside of the NOMINAL TRIP SETPOINT calibration tolerance band and non-conservative with respect to the NOMINAL TRIP SETPOINT, the setpoint shall be re-adjusted.
This verifies that the logic modules are OPERABLE and that there is an intact voltage signal path to the master relay coils. The Frequency of every 92 days on a STAGGERED TEST BASIS is justified in Reference 14.SR 3.3.2.3 SR 3.3.2.3 is the performance of a TADOT every 31 days. This test is a check of the Loss of Offsite Power Function.
Catawba Units 1 and 2                 B 3.3.2-31                               Revision No. 2-
Each Function is tested up to, and including, the master transfer relay coils.This test also includes trip devices that provide actuation signals directly to the SSPS. The SR is modified by a Note that excludes final actuation of pumps and valves to minimize plant upsets that would occur. The Frequency is adequate based on operating experience, considering , {.. instrument reliability and operating history data.S R 3.3.2.4 SR 3.3.2.4 is the performance of a MASTER RELAY TEST. TheMASTER RELAY TEST is the energizing of the master relay, verifying contact operation and a low voltage continuity check of the slave relay-- ""coil. Upon master relay contact operation, a low voltage is injected to the--f,_ -~slave~relay coil. This voltage is insufficient to pick up the slave relay, but large enough to demonstrate signal path continuity.
 
This test is performed every 92 days on a STAGGERED TEST BASIS. The time allowed for the testing (4 hours) is justified in Reference  
ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE REQUIREMENTS (continued) semiautomatic tester, all possible logic combinations, with and without applicable permissives, are tested for each protection function. In addition, the master relay coil is pulse tested for continuity. This verifies that the logic modules are OPERABLE and that there is an intact voltage signal path to the master relay coils. The Frequency of every 92 days on a STAGGERED TEST BASIS is justified in Reference 14.
: 7. The Frequency of 92 days is justified in Reference 14.cSR 3.3.2.5 SR 3.3.2.5 is the performance of a COT.A COT is performed on each required channel to ensure the channel will perform the intended Function.
SR 3.3.2.3 SR 3.3.2.3 is the performance of a TADOT every 31 days. This test is a check of the Loss of Offsite Power Function. Each Function is tested up to, and including, the master transfer relay coils.
The tested portion of the loop must trip within the Allowable Values specified in Table 3.3.2-1.Catawba Units 1 and 2 B 3.'3.2-45 Revision No. 3 ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE REQUIREMENTS (continued)
This test also includes trip devices that provide actuation signals directly to the SSPS. The SR is modified by a Note that excludes final actuation of pumps and valves to minimize plant upsets that would occur. The Frequency is adequate based on operating experience, considering
  ,   {..           instrument reliability and operating history data.
S R 3.3.2.4 SR 3.3.2.4 is the performance of a MASTER RELAY TEST. The
* MASTER RELAY TEST is the energizing of the master relay, verifying contact operation and a low voltage continuity check of the slave relay
      ""coil.             Upon master relay contact operation, a low voltage is injected to the
      --f,_
      -~slave~relay             coil. This voltage is insufficient to pick up the slave relay, but large enough to demonstrate signal path continuity. This test is performed every 92 days on a STAGGERED TEST BASIS. The time allowed for the testing (4 hours) is justified in Reference 7. The Frequency of 92 days is justified in Reference 14.
cSR                 3.3.2.5 SR 3.3.2.5 is the performance of a COT.
A COT is performed on each required channel to ensure the channel will perform the intended Function. The tested portion of the loop must trip within the Allowable Values specified in Table 3.3.2-1.
Catawba Units 1 and 2                   B 3.'3.2-45                                 Revision No. 3
 
ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE REQUIREMENTS (continued)
The setpoint shall be left set consistent with the assumptions of the setpoint methodology.
The setpoint shall be left set consistent with the assumptions of the setpoint methodology.
The Frequency of 184 days is justified in Reference 14.S 3.. .SR 3.3.2.6 is the performance of a SLAVE RELAY TEST. The SLAVE RELAY TEST is the energizing of the slave relays. Contact operation is verified in one of two ways. Actuation equipment that may be operated in the design mitigation MODE is either allowed to function, or is placed in a condition where the relay contact operation can be verified without operation of the equipment.
The Frequency of 184 days is justified in Reference 14.
Actuation equipment that may not be operated in the design mitigation MODE is prevented from operation by the SLAVE RELAY TEST circuit. For this latter case, contact operation is verified by a continuity check of the circuit containing the slave relay.This test is performed every 92 days. The Frequency is adequate, based on industry operating experience, considering instrument reliability and operating history data.For slave relays or any auxiliary relays in the ESFAS circuit that are of the type Westinghouse AR or Potter & Brumfield MDR, the SLAVE RELAY TEST is performed every 18 months. This test frequency is based on the relay reliability assessments presented in References 10, 11, and 12.These reliability assessments are relay specific and apply only to the Westinghouse AR and Potter & Brumfield MDR type relays. SSPS slave relays or any auxiliary relays not addressed by Reference 10 do not qualify for extended surveillance intervals and will continue to be tested at a 92 day Frequency.
S     3.. .
SR 3.3.2.6 is the performance of a SLAVE RELAY TEST. The SLAVE RELAY TEST is the energizing of the slave relays. Contact operation is verified in one of two ways. Actuation equipment that may be operated in the design mitigation MODE is either allowed to function, or is placed in a condition where the relay contact operation can be verified without operation of the equipment. Actuation equipment that may not be operated in the design mitigation MODE is prevented from operation by the SLAVE RELAY TEST circuit. For this latter case, contact operation is verified by a continuity check of the circuit containing the slave relay.
This test is performed every 92 days. The Frequency is adequate, based on industry operating experience, considering instrument reliability and operating history data.
For slave relays or any auxiliary relays in the ESFAS circuit that are of the type Westinghouse AR or Potter & Brumfield MDR, the SLAVE RELAY TEST is performed every 18 months. This test frequency is based on the relay reliability assessments presented in References 10, 11, and 12.
These reliability assessments are relay specific and apply only to the Westinghouse AR and Potter & Brumfield MDR type relays. SSPS slave relays or any auxiliary relays not addressed by Reference 10 do not qualify for extended surveillance intervals and will continue to be tested at a 92 day Frequency.
SR 3.3.2.7 SR 3.3.2.7 is the performance of a COT on the RWST level and Containment Pressure Control Start and Terminate Permissives.
SR 3.3.2.7 SR 3.3.2.7 is the performance of a COT on the RWST level and Containment Pressure Control Start and Terminate Permissives.
A COT is performed on each required channel to ensure the entire channel will perform the intended Function.
A COT is performed on each required channel to ensure the entire channel will perform the intended Function. Setpoints must be found within the Allowable Values specified in Table 3.3.1-1. This test is performed every 31 days. The Frequency is adequate, based on operating experience, considering instrument reliability and operating history data.
Setpoints must be found within the Allowable Values specified in Table 3.3.1-1. This test is performed every 31 days. The Frequency is adequate, based on operating experience, considering instrument reliability and operating history data.Catawba Units 1 and 2 B 3.3.2-46 Revision No.
Catawba Units 1 and 2                   B 3.3.2-46                               Revision No.
ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE REQUIREMENTS (continued)
ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE REQUIREMENTS (continued)
SIR 3.3.2.8 SR 3.3.2.8 is the performance of a TADOT. This test is a check of the Manual Actuation Functions, AFW pump start on trip of all MFW pumps, AFW low suction pressure, Reactor Trip (P-4) Interlock, and Doghouse Water Level -High High Feedwater Isolation.
SIR 3.3.2.8 SR 3.3.2.8 is the performance of a TADOT. This test is a check of the Manual Actuation Functions, AFW pump start on trip of all MFW pumps, AFW low suction pressure, Reactor Trip (P-4) Interlock, and Doghouse Water Level - High High Feedwater Isolation. It is performed every 18 months. Each Manual Actuation Function is tested up to, and including, the master relay coils. In some instances, the test includes actuation of the end device (i.e., pump starts, valve cycles, etc.). The Frequency is adequate, based on industry operating experience and is consistent with the typical refueling cycle. The SR is modified by a Note that excludes verification of setpoints during the TADOT for manual initiation Functions. The manual initiation Functions have no associated setpoints.
It is performed every 18 months. Each Manual Actuation Function is tested up to, and including, the master relay coils. In some instances, the test includes actuation of the end device (i.e., pump starts, valve cycles, etc.). The Frequency is adequate, based on industry operating experience and is consistent with the typical refueling cycle. The SR is modified by a Note that excludes verification of setpoints during the TADOT for manual initiation Functions.
The manual initiation Functions have no associated setpoints.
SR 3.3.2.9 SR 3.3.2.9 is the performance of a CHANNEL CALIBRATION.
SR 3.3.2.9 SR 3.3.2.9 is the performance of a CHANNEL CALIBRATION.
A CHANNEL CALIBRATION is performed every 18 months, or approximately at every refueling.
A CHANNEL CALIBRATION is performed every 18 months, or approximately at every refueling. CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies that the channel responds to measured parameter within the necessary range and accuracy.
CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies that the channel responds to measured parameter within the necessary range and accuracy.CHANNEL CALIBRATIONS must be performed consistent with the assumptions of the unit specific setpoint methodology.
CHANNEL CALIBRATIONS must be performed consistent with the assumptions of the unit specific setpoint methodology.
The Frequency of 18 months is based on the assumption of an 18 month calibration interval in the determination of the magnitude of equipment drift in the setpoint methodology.
The Frequency of 18 months is based on the assumption of an 18 month calibration interval in the determination of the magnitude of equipment drift in the setpoint methodology.
This SR is modified by a Note stating that this test should include verification that the time constants are adjusted to the prescribed values where applicable.
This SR is modified by a Note stating that this test should include verification that the time constants are adjusted to the prescribed values where applicable. The applicable time constants are shown in Table 3.3.2-1.
The applicable time constants are shown in Table 3.3.2-1.3.3.2. 10 This SR ensures the individual channel ESF RESPONSE TIMES are less than or equal to the maximum values assumed in the accident analysis.Response Time testing acceptance criteria are included in the UFSAR (Ref. 2). Individual component response times are not modeled in the/Catawba Units 1 and 2 B 3.3.2-47 Revision No.
3.3.2. 10 This SR ensures the individual channel ESF RESPONSE TIMES are less than or equal to the maximum values assumed in the accident analysis.
ESFAS Instrumentation B 3.3.2 BASES REFERENCE; S 1. UFSAR, Chapter 6.2. UFSAR, Chapter 7.3. UFSAR, Chapter 15.4. IEEE-279-1971.
Response Time testing acceptance criteria are included in the UFSAR (Ref. 2). Individual
: 5. 10 CFR 50.49.6. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).
                                    /
: 7. WCAP-1 0271-P-A, Supplement 1 and Supplement 2, Rev. 1, May 1986 and June 1990.8. WCAP-1 3632-P-A Revision 2, "Elimination of Pressure Sensor Response Time Testing Requirements" Sep., 1995.9. WCAP-14036-P-A Revision 1, "Elimination of Periodic Protection Channel Response Time Tests" Oct., 1998.10. WCAP-13900, "Extension of Slave Relay Surveillance Test Intervals," April 1994.11. WCAP-13877 Revision 2-P-A, "Reliability Assessment of Westinghouse Type AR Relays Used As SSPS Slave Relays," August 2000.12. WCAP-1 3878-P-A Revision 2, "Reliability Assessment of Potter &Brumfield MDR Series Relays," August 2000.13. WCAP-14333-P-A, Revision 1, October 1998.14. WCAP-15376-P-A, Revision 1, March 2003.j =6-:&#xfd;j-Catawba Units 1 and 2 B 3.3.2-50 Revision No.-G-}}
component response times are not modeled in the Catawba Units 1 and 2                   B 3.3.2-47                             Revision No.
ESFAS Instrumentation B 3.3.2 BASES REFERENCE;S         1. UFSAR, Chapter 6.
: 2. UFSAR, Chapter 7.
: 3. UFSAR, Chapter 15.
: 4. IEEE-279-1971.
: 5. 10 CFR 50.49.
: 6. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).
: 7. WCAP-1 0271-P-A, Supplement 1 and Supplement 2, Rev. 1, May 1986 and June 1990.
: 8. WCAP-1 3632-P-A Revision 2, "Elimination of Pressure Sensor Response Time Testing Requirements" Sep., 1995.
: 9. WCAP-14036-P-A Revision 1, "Elimination of Periodic Protection Channel Response Time Tests" Oct., 1998.
: 10. WCAP-13900, "Extension of Slave Relay Surveillance Test Intervals," April 1994.
: 11. WCAP-13877 Revision 2-P-A, "Reliability Assessment of Westinghouse Type AR Relays Used As SSPS Slave Relays,"
August 2000.
: 12. WCAP-1 3878-P-A Revision 2, "Reliability Assessment of Potter &
Brumfield MDR Series Relays," August 2000.
: 13. WCAP-14333-P-A, Revision 1, October 1998.
: 14. WCAP-15376-P-A, Revision 1, March 2003.
j =6-:&#xfd;j-Catawba Units 1 and 2               B 3.3.2-50                             Revision No.-G-}}

Latest revision as of 22:26, 11 March 2020

License Amendment Request to Revise Reactor Trip System and Engineered Safety Feature Actuation System Technical Specifications
ML101900267
Person / Time
Site: Mcguire, Catawba, McGuire  Duke Energy icon.png
Issue date: 06/29/2010
From: Repko R
Duke Energy Carolinas
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
Download: ML101900267 (98)
v • d • e


Text

{{#Wiki_filter:REGIS T. REPKO Vice President r4tEnergy, McGuire Nuclear Station Duke Energy MG01VP / 12700 Hagers Ferry Rd. Huntersville, NC 28078 980-875-4111 980-875-4809 fax regis.repko@duke-energy.com June 29, 2010 10 CFR 50.90 U.S. Nuclear Regulatory Commission Washington, D.C. 20555-0001 ATTENTION: Document Control Desk Duke Energy Carolinas, LLC (Duke Energy) McGuire Nuclear Station, Units 1 and'2 Docket Nos. 50-369 and 50-370 Catawba Nuclear Station, Units 1 and 2 Docket Nos. 50-413 and 50-414

SUBJECT:

License Amendment Request to Revise Reactor Trip System and Engineered Safety Feature Actuation System Technical Specifications Pursuant to 10 CFR 50.90, enclosed is a Duke Energy License Amendment Request (LAR) for the McGuire Nuclear Station Renewed Facility Operating Licenses and Technical Specifications (TS) and the Catawba Nuclear Station Renewed Facility Operating Licenses and TS. The proposed LAR revises the Reactor Trip System (RTS) Instrumentation TS 3.3.1 and the Engineered Safety Feature Actuation System (ESFAS) Instrumentation TS 3.3.2 for both the McGuire and Catawba Nuclear Stations; to reflect the results of updated setpoint calculations. The proposed LAR affects TS Table 3.3.1-1, "Reactor Trip System Instrumentation" and TS Table 3.3.2-1, "Engineered Safety Feature Actuation System Instrumentation." Applicable aspects of Technical Specification Task Force Traveler TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions," are incorporated in the scope of the proposed changes. Implementation of the proposed license amendment will impact the Updated Final Safety Analysis Report (UFSAR) for both stations. The necessary UFSAR revisions will be submitted in accordance with 10 CFR 50.71 (e). Duke Energy requests approval of this LAR within one calendar-year of tlhe submittal date. Amendment implementation will be accomplished within 60 days of NRC approval. L) www, duke-energy.com

U.S. Nuclear Regulatory Commission June 29, 2010 Page 2 Enclosure 1 provides a description of the proposed change and the technical justification, an evaluation of significant hazards consideration pursuant to 10 CFR 50.92(c), and the following attachments: Attachments 1a and lb provide the existing TS pages marked-up to show the proposed changes for the McGuire and Catawba Nuclear Stations, respectively. Retyped (clean) TS pages will be provided to the NRC immediately prior to issuance of the approved amendment. Attachments 2a and 2b provide the existing Bases pages marked-up to show the proposed changes for the McGuire and Catawba Nuclear Stations, respectively. These pages are provided for information only. This submittal contains no additional regulatory commitments. In accordance with Duke Energy's administrative procedures and Quality Assurance Program, this LAR has been reviewed and approved by the McGuire and Catawba Plant Operations Review Committees. Pursuant to 10 CFR 50.91, a copy of this LAR is being sent to the designated officials of the States of North Carolina and South Carolina. -Ifthere are any questions or if additional information is needed, please contact Mr. M. K. Leisure at (980) 875-5171. Sincerely, Regis T. Repko Enclosure

U.S. Nuclear Regulatory Commission June 29, 2010 Page 3 xc with enclosure': L. A. Reyes Regional Administrator, Region II U.S. Nuclear Regulatory Commission Marquis One Tower 245 Peachtree Center Ave., NE Suite 1200 Atlanta, GA 30303-1257 J. B. Brady NRC Senior Resident Inspector McGuire Nuclear Station G. A. Hutto III NRC Senior Resident Inspector Catawba Nuclear Station J. H. Thompson (addressee only) NRC Project Manager U.S. Nuclear Regulatory Commission Mail Stop 0-8 G9A 11555 Rockville Pike Rockville, MD 20852-2738 W. L. Cox Il1,Section Chief Division of Environmental Health Radiation Protection Section 1645 Mail Service Center Raleigh, NC 27699-1645 S. E. Jenkins, Manager Radioactive and Infectious Waste Management Division of Waste Management South Carolina Department of Health and Environmental Control 2600 Bull St. Columbia, SC 29201

U.S. Nuclear Regulatory Commission June 29, 2010 Page 4 -Regis T. Repko affirms that he is the person who subscribed his name to the foregoing statement, and that all the matters and facts set forth herein are true and correct to the best of his knowledge. Regis ,Vi uire Nuclear Station Subscribed and sworn to me: Date 7 

                           *            ~Notary Public My commission expir es:      (    -]     ,.
                                         //'     40 1%

Date t*

U.S. Nuclear Regulatory Commission June 29, 2010 ENCLOSURE 1 Evaluation of the Proposed Change

Subject:

License Amendment Request to Revise Technical Specification 3.3.1, "Reactor Trip System (RTS) Instrumentation" and Technical Specification 3.3.2, "Engineered Safety Feature Actuation System (ESFAS) Instrumentation"

1. DESCRIPTION
2. PROPOSED CHANGE
3. BACKGROUND
4. TECHNICAL ANALYSIS
5. REGULATORY ANALYSIS 5.1 No Significant Hazards Consideration 5.2 Applicable Regulatory Requirements/Criteria 5.3 Precedents
6. ENVIRONMENTAL CONSIDERATION
7. REFERENCES ATTACHMENTS:

la. McGuire Units 1 and 2 Technical Specification Page Markups lb. Catawba Units 1 and 2 Technical Specification Page Markups 2a. McGuire Units 1 and 2 Bases Page Markups (Information Only) 2b. Catawba Units 1 and 2 Bases Page Markups (Information Only)

U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 2 of 32

1. DESCRIPTION This evaluation supports a request to amend Renewed Facility Operating Licenses NPF-9 and NPF-17 for McGuire Nuclear Station Units 1 and 2, respectively, and Renewed Facility Operating Licenses NPF-35 and NPF-52 for Catawba Nuclear Station Units 1 and 2, respectively.

The proposed changes would revise McGuire and Catawba Technical Specification (TS) 3.3.1, "Reactor Trip System Instrumentation," and TS 3.3.2, "Engineered Safety Feature Actuation System Instrumentation," to reflect the results of updated setpoint calculations.

2. PROPOSED CHANGE Specifically, the proposed changes would revise the McGuire Nuclear Station Units 1 and 2 and Catawba Nuclear Station Units 1 and 2 Technical Specification Tables 3.3.1-1 and 3.3.2-1 as follows:

McGuire Nuclear Station ALLOWABLE VALUE McGuire TS Table 3.3.1-1 FUNCTION Current 

                                                               .. Current'      LProposE Proposed 8.a     Pressurizer Pressure - Low                         > 1935 psig          ->1939 psig 8.b     Pressurizer Pressure - High                        < 2395 psig          _<2390 psig' 9      Pressurizer Water Level - High                          <-93%              _<92.7%

10.a Reactor Coolant Flow - Low - Single Loop > 87% - 87.6% 10.b Reactor Coolant Flow - Low - Two Loops _> 87% _ 87.6% 12 Underfrequency RCPs > 55.9 Hz > 56.3 Hz 13 Steam Generator (SG) Water Level - Low >15% 16% Low 16.a Reactor Trip System Interlocks- Intermediate > 4E-1 1 amp > 4.8E-1 1 amp Range Neutron Flux, P-6 16.e Reactor Trip System Interlocks - Turbine 5 11%

  • 10.7%

Impulse Pressure, P-13

U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 3 of 32 McGuire TS Table 3.3.2-1 FUNCTION ALLOWABLE VALUE Current ,Proposed 1 .d Safety Injection - Pressurizer Pressure - Low > 1835 psig 1840 psig Low 4.d(1) Steam Line Isolation - Steam Line Pressure - > 755 psig > 766 psig Low - 4.d(2) Steam Line Isolation - Steam Line Pressure - < 120 psi < 110 psi Negative Rate - High - 5.a(2) Turbine Trip and Feedwater Isolation - Turbine Trip - SG Water Level - High High < 85.6% < 84.7% (P-14) 5.b(2) Turbine Trip and Feedwater Isolation - Feedwater Isolation - SG Water Level - High 5 85.6% < 84.7% High (P-14) 5.b(4) Turbine Trip and Feedwater Isolation - > 551 OF 551.84 OF Feedwater Isolation - Tavg - Low 6.b Auxiliary Feedwater- SG Water Level - Low > 15% > 16% Low 8.b ESFAS Interlocks - Pressurizer Pressure, <1965 psig <1960 psig P-1 1 8.c ESFAS Interlocks - Tavg - Low Low, P-1 2 >_551 OF >551.84 OF In addition, two new lettered footnotes, designated () and (k), would be added to Table 3.3.1-1, and two new lettered footnotes, designated (f) and (g), would be added to Table 3.3.2-1. The new Table 3.3.1-1 footnotes would apply to the cross-referenced CHANNEL OPERATIONAL TEST (COT) and CHANNEL CALIBRATION requirements listed in the "SURVEILLANCE REQUIREMENTS (SR)" column of the Table for Functions 8.a, 8.b, 9, 10.a, 1.b, 12, and 13, specifically the SR 3.3.1.7 and 3.3.1.10 entries. The new footnotes would read as follows: (j) If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service. (k) The instrument channel setpoint shall be reset to a value that is within the as-left. tolerance around the Nominal Trip Setpoint (NTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the NTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (field setting) to confirm channel performance. The methodologies used to determine the as-found and the as-left tolerances are specified in the UFSAR. The new Table 3.3.2-1 footnotes would apply to the cross-referenced CHANNEL OPERATIONAL TEST (COT) and CHANNEL CALIBRATION requirements listed in the "SURVEILLANCE REQUIREMENTS" column of the Table for Functions 1.d, 4.d(1), 4.d(2), 5.a(2), 5.b(2), 5.b(4), and 6.b, specifically the SR 3.3.2.5 and 3.3.2.8 entries. The new footnotes, (f) and (g) are identical to the proposed new Table 3.3.1-1 footnotes (j) and (k), respectively.

U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 4 of 32 These new footnotes are consistent with Technical Specification Task Force Traveler TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions," Revision 4. In addition to the above-mentioned footnotes, a footnote would be added to Table 3.3.1-1 for the Allowable Value entry for Function 16.a, "Reactor Trip System Interlocks - Intermediate Range Neutron Flux, P-6." This footnote would read as follows: A The > 4E-1 1 amp Allowable Value, which applies to the Westinghouse-supplied compensated ion chamber Intermediate Range neutron detectors, is non-conservative. The compensated ion chamber neutron detectors are being replaced with Thermo Scientific-supplied fission chamber neutron detectors. Until the replacement occurs, an Allowable Value of > 4.8E-1 1 amp applies. This footnote will provide proper coordination with the Duke Energy license amendment application dated July 1, 2009, which was submitted to support plant modifications to the Nuclear Instrumentation System. This license amendment application included a proposed revision to the Allowable Value for the P-6 function. Catawba Nuclear Station atawba ITSTable,3.3.1.1 FUNCTION ALLOWABLE VALUE. CaTTl31Current Proposed 2.a Power Range Neutron Flux - High _ 110.9% RTP _ 110.3% RTP 2.b Power Range Neutron Flux - Low

  • 27.1% RTP 26.3% RTP 6 Overtemperature AT < 4.3% RTP (Unit 1) <3.97% RTP
                                                               < 4.5%   RTP      (Units 1&2)

(Unit 2) 8.a Pressurizer Pressure - Low >1938 psig >1939 

                                                               >_ 198pi                99psig 8.b     Pressurizer Pressure - High                         < 2399 psig       < 2390 psig 9      Pressurizer Water Level - High                         < 93.8%           < 92.7%

10.a Reactor Coolant Flow - Low - Single Loop > 89.7% > 90.5% 10.b Reactor Coolant Flow - Low - Two Loops > 89.7% > 90.5% 12 Underfrequency RCPs > 55.9 Hz > 56.2 Hz 13 Steam Generator (SG) Water Level - Low > 9% > 10% Low (Unit 1) (Unit 1) 

                                                                  > 35.1%           > 36.1%

(Unit 2) (Unit 2) 16.a Reactor Trip System Interlocks - Intermediate > 6E-1 1 amp 6.9E-1 1 amp Range Neutron Flux, P-6 16.f Reactor Trip System Interlocks -Turbine 5 12.2% RTP <5 10.7% RTP Impulse Pressure, P-13

U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 5 of 32 ALLOWABLE VALUE Catawba TS Table 3.3.2-1 FUNCTION Current Proposed 1 .c Safety Injection - Containment Pressure - High < 1.4 psig < 1.3 psig 1 .d Safety Injection - Pressurizer Pressure - Low 1839 psig 1840 psig 3.b(3) Containment Isolation - Phase B Isolation - <3.2 psig 3.1 psig Containment Pressure - High High 4.c Steam Line Isolation- Containment Pressure - <3.2 psig 3.1 psig High High 4.d(1) Steam Line Isolation - Steam Line Pressure - > 744 psig > 766 psig Low - 4.d(2) Steam Line Isolation - Steam Line Pressure - < 122.8 psi <110.1 psi Negative Rate - High - 5.a(2) Turbine Trip and Feedwater Isolation - < 85.6% < 84.6% Turbine Trip - SG Water Level - High-High (Unit 1) (Unit 1) (P-14) < 78.9% < 77.8% (Unit 2), (Unit 2) 5.b(2) Turbine Trip and Feedwater Isolation - < 85.6% < 84.6% Feedwater Isolation - SG Water Level - High (Unit 1) (Unit 1) High (P-14) < 78.9% < 77.8% (Unit 2) (Unit 2) 5.b(4) Turbine Trip and Feedwater Isolation - > 561 OF 562.88 OF Feedwater Isolation - Tavg - Low 6.b Auxiliary Feedwater - SG Water Level - Low > 9% > 10% Low (Unit 1) (Unit 1) 

                                                                       >35.1%             >36.1%

(Unit 2) (Unit 2) 8.b ESFAS Interlocks - Pressurizer Pressure, > 1944 psig > 1946 psig P-11 and and 

                                                                    <1966 psig         <1960 psig 8.c      ESFAS Interlocks - Tavg - Low Low, P-12                      >550 OF          551.88 OF In addition, two new lettered footnotes, designated (I) and (m), would be added to Table 3.3.1-1, and two new lettered footnotes, designated (f) and (g), would be added to Table 3.3.2-1. The new Table 3.3.1-1 footnotes would apply to the cross-referenced CHANNEL OPERATIONAL TEST and CHANNEL CALIBRATION requirements listed in the "SURVEILLANCE REQUIREMENTS" column of the Table for Functions 2.a, 2.b, 6, 8.a, 8.b, 9, 10.a, 10.b, 12, and 13, specifically the SR 3.3.1.7, 3.3.1.8, 3.3.1.10, and 3.3.1.11 entries. The new footnotes would read as follows:

(I) If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service. (m) The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Nominal Trip Setpoint (NTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the NTSP are acceptable provided that the as-found and as-left

U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 6 of 32 tolerances apply to the actual setpoint implemented in the Surveillance procedures (field setting) to confirm channel performance. The methodologies used to determine the as-found and the as-left tolerances are specified in the UFSAR. The new Table 3.3.2-1 footnotes would apply to the cross-referenced CHANNEL OPERATIONAL TEST (COT) and CHANNEL CALIBRATION requirements listed in the "SURVEILLANCE REQUIREMENTS" column of the Table for Functions 1 .c, 1 .d, 3.b(3), 4.c, 4.d(1), 4.d(2), 5.a(2), 5.b(2), 5.b(4), and 6.b, specifically the SR 3.3.2.5 and 3.3.2.9 entries. The new footnotes, (f) and (g) are identical to the proposed new Table 3.3. 1-1 footnotes (I) and (m), respectively. These new footnotes are consistent with Technical Specification Task Force Traveler TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions," Revision 4. In addition to the above-mentioned footnotes, an additional footnote would be added to Table 3.3.1-1 for the Allowable Value entry for Function 16.a, "Reactor Trip System Interlocks - Intermediate Range Neutron Flux, P-6." This footnote would read as follows: A The > 6E-1 1 amp Allowable Value, which applies to the Westinghouse-supplied compensated ion chamber Intermediate Range neutron detectors, is non-conservative. The compensated ion chamber neutron detectors are being replaced with Thermo Scientific-supplied fission chamber neutron detectors. Until the replacement occurs, an Allowable Value of > 6.9E-1 1 amp applies. This footnote will provide proper coordination with the Duke Energy license amendment application dated July 1, 2009, which was submitted to support plant modifications to the Nuclear Instrumentation System. This license amendment application included a proposed revision to the Allowable Value for the P-6 interlock function. Further Discussion Attachments 1a and lb provide marked-up versions of the Technical Specifications for McGuire and Catawba, respectively, showing the proposed changes. Duke Energy will make conforming changes to the Technical Specification Bases in accordance with TS 5.5.14, "Technical Specifications (TS) Bases Control Program." Attachments 2a and 2b provide the affected TS Bases markups for McGuire and Catawba, respectively. These Bases markups are included for information only.

3. BACKGROUND Reactor Trip System The RTS initiates a unit shutdown, based on the values of selected unit parameters, to protect against violating the core fuel design limits and Reactor Coolant System (RCS) pressure boundary during anticipated operational occurrences (AOOs) and to assist the Engineered Safety Features (ESF) Systems in mitigating accidents.

The following describes particular aspects of the RTS that are pertinent to this license amendment application:

U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 7 of 32 Power Range Neutron Flux - High The Power Range Neutron Flux-High trip Function ensures'that protection is provided, from all power levels, against a positive reactivity excursion leading to Departure from Nucleate Boiling (DNB) during power operations. These can be caused by rod withdrawal or reductions in RCS temperature. Power Range Neutron Flux - Low The Power Range Neutron Flux-Low trip Function ensures that protection is provided against a positive reactivity excursion from low power or subcritical conditions. This Function may be manually blocked by the operator when two out of four power range channels are greater than approximately 10% Rated Thermal Power (RTP) (P-10 setpoint). This Function is automatically unblocked when three out of four power range channels are below the P-10 setpoint. Above the P-10 setpoint, positive reactivity additions are mitigated by the Power Range Neutron Flux-High trip Function. OvertemperatureAT The Overtemperature AT trip Function is provided to ensure that the design limit Departure from Nucleate Boiling Ratio (DNBR) is met. The inputs to the Overtemperature AT trip include pressurizer pressure, coolant temperature, axial power distribution, and reactor power as indicated by loop AT, assuming full reactor coolant flow. Protection from violating the DNBR limit is assured for those transients that are slow with respect to delays from the core to the measurement system. The function monitors both variation in power and flow since a decrease in flow has the same effect on AT as a power increase. The Overtemperature AT trip Function uses each loop's AT as a measure of reactor power and is compared with a setpoint that is automatically varied with the following parameters: Reactor Coolant Average Temperature: The Trip Setpoint is varied to correct for changes in coolant density and specific heat capacity with changes in coolant temperature; Pressurizer Pressure: The Trip Setpoint is varied to correct for changes in system pressure; and, Axial Power Distribution-f(AI): The Trip Setpoint is varied to account for imbalances in the axial power distribution as detected by the Nuclear Instrumentation System (NIS) upper and lower power range detectors. If axial peaks are greater than the design limit, as indicated by the difference between the upper and lower NIS power range detectors, the Trip Setpoint is reduced in accordance with Note 1 of Table 3.3.1-1. This Function also provides a signal to generate a turbine runback prior to reaching the Trip Setpoint. A turbine runback will reduce turbine power and reactor power. A reduction in power will normally alleviate the Overtemperature AT condition and may prevent a reactor trip. PressurizerPressure- Low The Pressurizer Pressure - Low trip Function ensures that protection is provided against

U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 8 of 32 violating the DNBR limit due to low pressure. This trip Function is automatically enabled on increasing power by the P-7 interlock. The P-7 interlock, "Low Power Reactor Trips Block," is actuated by input from either the P-10 interlock, "Power Range Neutron Flux," or the, P-13 interlock, "Turbine Impulse Pressure." The P-10 interlock is actuated at approximately 10% power, as determined by the Nuclear Instrumentation System (NIS) power range detectors. The P-13 interlock is described below. On decreasing power, this trip Function is automatically blocked below P-7. Below the P-7 setpoint, power distributions that would cause Departure from Nucleate Boiling (DNB) concerns are unlikely. PressurizerPressure- High The Pressurizer Pressure - High trip Function ensures that protection is provided against overpressurizing the RCS. This trip Function operates in conjunction with the pressurizer relief and safety valves to prevent RCS overpressure conditions. PressurizerWater Level - High The Pressurizer Water Level - High trip Function provides a backup signal for the Pressurizer Pressure - High trip and also provides protection against water relief through the pressurizer safety valves. These valves are designed to pass steam in order to achieve their design energy removal rate. A reactor trip is actuated prior to the pressurizer becoming water solid. This trip Function is automatically enabled on increasing power by the P-7 interlock. On decreasing power, this trip Function is automatically blocked below P-7. Below the P-7 setpoint, transients that could raise the pressurizer water level will be slow and the operator will have sufficient time to evaluate unit conditions and take corrective actions. Reactor Coolant Flow - Low (Single Loop) The Reactor Coolant Flow - Low (Single Loop) trip Function ensures that protection is provided against violating the DNBR limit due to low flow in one or more RCS loops, while avoiding reactor trips due to normal variations in loop flow. Above the P-8 setpoint, which is approximately 48% rated thermal power (RTP) as measured by the NIS power range detectors, a loss of flow in any RCS loop will actuate a reactor trip. Below the P-8 setpoint, a loss of flow in two or more loops is required to actuate a reactor trip because of the lower power level and the greater margin to the design limit DNBR. Reactor Coolant Flow - Low (Two Loops) The Reactor Coolant Flow - Low (Two Loops) trip Function ensures that protection is provided against violating the DNBR limit due to low flow in two or more RCS loops while avoiding reactor trips due to normal variations in loop flow. Above the P-7 setpoint and below the P-8 setpoint, a loss of flow in two or more loops will initiate a reactor trip. Below the P-7 setpoint, all reactor trips on low flow are automatically blocked since power distributions that would cause a DNB concern at this low power level are unlikely. Above the P-7 setpoint, the reactor trip on low flow in two or more RCS loops is automatically enabled. Above the P-8 setpoint, a loss of flow in any one loop will actuate a reactor trip because of the higher power level and the reduced margin to the design limit DNBR. Underfrequency Reactor Coolant Pumps (RCPs) The Underfrequency RCPs reactor trip Function ensures that protection is provided against

U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 9 of 32 violating the DNBR limit due to a loss of flow in two or more RCS loops from a major network frequency disturbance. An underfrequency condition will slow down the pumps, thereby reducing their coastdown time following a pump trip. The proper coastdown time is required so that reactor heat can be removed immediately after a reactor trip. The frequency of each RCP bus is monitored. Above the P-7 setpoint, a loss of frequency detected on two or more RCP buses will initiate a reactor trip. This trip Function will generate a reactor trip before the Reactor Coolant Flow-Low (Two Loops) Trip Setpoint is reached. Time delays are incorporated into the Underfrequency RCPs channels to prevent reactor trips due to momentary electrical power transients. Below the P-7 setpoint, all reactor trips on loss of flow are automatically blocked since power distributions that would cause a DNB concern at this low power level are unlikely. Above the P-7 setpoint, the reactor trip on loss of flow in two or more RCS loops is automatically enabled. Steam GeneratorWater Level - Low-Low The SG Water Level - Low-Low trip Function ensures that protection is provided against a loss of heat sink and actuates the Auxiliary Feedwater (AFW) System prior to uncovering the Steam Generator (SG) tubes. The SGs are the heat sink for the reactor. In order to act as a heat sink, the SGs must contain a minimum amount of water. A narrow range low-low level in any SG is indicative of a loss of heat sink for the reactor. This Function also performs the ESFAS function of starting the AFW pumps on low-low SG level. Reactor Trip System Interlock, Intermediate Range Neutron Flux, P-6 The Intermediate Range Neutron Flux, P-6 interlock is actuated when any Intermediate Range channel goes approximately one decade above the minimum channel reading. If both channels drop below the setpoint, the permissive will automatically be defeated. On increasing power, the P-6 interlock allows the manual block of the NIS Source Range, Neutron Flux reactor trip. This prevents a premature block of the source range trip and allows the operator to ensure that the intermediate range is OPERABLE prior to leaving the source range. When the source range trip is blocked, the high voltage to the detectors is also removed. On decreasing power, the P-6 interlock automatically energizes the NIS source range detectors and enables the NIS Source Range Neutron Flux reactor trip. Reactor Trip System Interlock, Turbine Impulse Pressure,P-13 The Turbine Impulse Pressure, P-13 interlock is actuated when the pressure in the first stage of the high pressure turbine is greater than approximately 10% of the rated full power pressure. Engqineered Safety Features Actuation System The ESFAS initiates necessary safety systems, based on the values of selected unit parameters, to protect against violating core design limits and the Reactor Coolant System (RCS) pressure boundary, and to mitigate accidents. The following describes particular aspects of the ESFAS that are pertinent to this license amendment application: Safety Injection, Containment Pressure- High This signal provides protection against a Steam Line Break (SLB) inside containment, a Loss of

U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 10 of 32 Coolant Accident (LOCA), and a feedwater line break inside containment. Safety Injection, PressurizerPressure- Low-Low (McGuire) Safety Injection, PressurizerPressure- Low (Catawba) This signal provides protection against: the inadvertent opening of a steam generator (SG) relief or safety valve; an SLB; a spectrum of rod cluster control assembly ejection accidents (rod ejection); the inadvertent opening of a pressurizer relief or safety valve; a LOCA; and a SG Tube Rupture. This signal may be manually blocked by the operator below the P-1 1 setpoint. Automatic Safety Injection (SI) actuation below this pressure setpoint is then performed by the Containment Pressure-High signal. The P-1 1 interlock is described below. Containment Isolation, Phase B Isolation, Containment Pressure- High High Containment Isolation provides isolation of the containment atmosphere, and all process systems that penetrate containment, from the environment. This Function is necessary to prevent or limit the release of radioactivity to the environment in the event of a large break LOCA. There are two separate Containment Isolation signals, Phase A and Phase B. Phase A isolation isolates all automatically isolable process lines, except component cooling water (CCW) and nuclear service water system (NSWS). The Phase B signal isolates CCW and NSWS. Steam Line Isolation, Containment Pressure- High High This Function actuates closure of the Main Steam Isolation Valves in the event of a LOCA or an SLB inside containment to maintain three unfaulted SGs as a heat sink for the reactor, and to limit the mass and energy release to containment. Steam Line Isolation, Steam Line Pressure- Low Steam Line Pressure - Low provides closure of the Main Steam Isolation Valves (MSIVs) in the event of an SLB to maintain three unfaulted SGs as a heat sink for the reactor, and to limit the' mass and energy release to containment. This Function provides closure of the MSIVs in the. event of a feed line break to ensure a supply of steam for the turbine driven AFW pump. This signal may be manually blocked by the operator below the P-1 1 setpoint. Below P-1 1, an inside containment SLB will be terminated by automatic actuation via Containment Pressure - High-High signal. Stuck valve transients and outside containment SLBs will be terminated by the Steam Line Pressure - Negative Rate-High signal for Steam Line Isolation below P-1 1 when Steam Line Isolation Steam Line Pressure - Low has been manually blocked. Steam Line Isolation, Steam Line Pressure- Negative Rate - High Steam Line Pressure - Negative Rate - High provides closure of the MSIVs for an SLB When less than the P-1 1 setpoint, to maintain at least one unfaulted SG~as a heat sink for the reactor, and to limit the mass and energy release to containment. When the operator manually blocks the Steam Line Pressure - Low main steam isolation signal when less than the P-1 1 setpoint, the Steam Line Pressure - Negative Rate - High signal is automatically enabled. Turbine Trip, Steam GeneratorWater Level - High-High (P-14) This signal prevents damage to the turbine due to water in the steam lines. The ESFAS SG

U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 11 of 32 water level instruments provide input to the SG Water Level Control System. The setpoints are based on percent of narrow range instrument span. Feedwater Isolation, Steam GeneratorWater Level - High-High (P- 14) This signal provides protection against excessive feedwater flow. The ESFAS SG water level instruments provide input to the SG Water Level Control System. The setpoints are based on percent of narrow range instrument span. Feedwater Isolation, RCS Tavg - Low, Coincident with Reactor Trip (P-4) This signal provides protection against excessive cooldown, which could subsequently introduce a positive reactivity excursion after a plant trip. Auxiliary Feedwater Initiation, Steam GeneratorWater Level- Low-Low SG Water Level - Low-Low provides protection against a loss of heat sink. A feed line break, inside or outside of containment, or a loss of main feedwater (MFW), would result in a loss of SG water level. SG Water Level - Low-Low provides input to the SG Level Control System. The setpoints are based on percent of narrow range instrument span. SG Water Level - Low-Low in any operating SG will cause the motor driven AFW pumps to start. The system is aligned so that upon a start of the pump, water immediately begins to flow to the SGs. SG Water Level - Low-Low in any two operating SGs will cause the turbine driven pumps to start. ESFAS Interlock, PressurizerPressure,P-Il The P-1 1 interlock permits a normal unit cooldown and depressurization without actuation of SI or main steam line isolation. With two-out-of-three pressurizer pressure channels less than the P-1 1 setpoint, the operator can manually block the Pressurizer Pressure - Low SI signal and the Steam Line Pressure - Low steam line isolation signal. When the Steam Line Pressure - Low steam line isolation signal is manually blocked, a main steam isolation signal on Steam Line Pressure - Negative Rate - High is enabled. This provides protection for an SLB by closure of the MSIVs. With two-out-of-three pressurizer pressure channels above the P-1 1 setpoint, the Pressurizer Pressure - Low SI signal and the Steam Line Pressure - Low steam line isolation signal are automatically enabled. The operator can also enable these trips by use of the respective manual reset buttons. When the Steam Line Pressure - Low steam line isolation signal is enabled, the main steam isolation on Steam Line Pressure - Negative Rate-High is disabled. ESFAS Interlock, Tavg - Low-Low, P-12 On increasing reactor coolant temperature, the P-12 interlock provides an arming signal to the Steam Dump System. On a decreasing temperature, the P-12 interlock removes the arming signal to the Steam Dump System to prevent an excessive cooldown of the RCS due to a malfunctioning Steam Dump System.

U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 12 of 32

4. TECHNICAL ANALYSIS Setpoint Calculation Changes Introduction Setpoint calculations were updated, resulting in the need for changes to associated values listed in TS Table 3.3.1-1, "Reactor Trip System Instrumentation," and TS Table 3.3.2-1, "Engineered Safety Features Actuation System Instrumentation," as described in Section 2 above. These setpoint calculations were performed in accordance with Duke Energy Engineering Directives Manual (EDM)-1 02, "Instrument Setpoint/Uncertainty Calculations," Revision 3. The methodology described in EDM-102 is consistent with the intent of Instrument Society of America (ISA) Standard RP67.04-1994 Part II, "Methodologies for the Determination of Setpoints for Nuclear Safety Related Instrumentation."

Basic Methodology - EDM-102 The loop uncertainty methodology is primarily based on the "Square-Root-Sum-of-the- Squares" (SRSS) technique for combination of random-independent uncertainty terms. Random-dependent and bias uncertainty terms must be addressed through a combination of the SRSS and/or algebraic techniques. The over-all methodology requires identification of applicable sources of instrument uncertainty, and categorization of each as a random-independent (x,y), random-dependent (w,u), and bias/abnormal distribution (vt) terms. The magnitude of each term is then combined to determine the "Total Loop Uncertainty" (TLU) as depicted below. The "+" and "-" convention represents the positive or negative uncertainty limits within the measured setpoint or indication. 

                                + TLU=+{x 2 + y2 + (w + u)2}1 /2 +v + t
                                - TLU=-{x 2 + y2 + (w + u) 2}1 /2 - v - t The treatment of bias/abnormal distribution terms requires additional discussion. Bias terms are typically based on conservative estimates and are predictable. Bias terms would normally be applied only in an additive manner, to the respective "+" or "-" TLU component. Biases of unknown direction would be applied in an additive manner to both the -TLU and +TLU determinations. Application of a non-reoccurring bias term shall not be applied so as to decrease a TLU value. Proper application of a bias would normally result in reduced margin for the setpoint limit of interest. Terms that have an abnormal distribution cannot have the SSRS technique applied with normally distributed terms and must therefore be added as a limit of error in both directions.

Evaluation of setpoint acceptability requires comparison of the total loop uncertainty against the operational ranges and the protected limits (process, analytical, and/or safety limits). This setpoint relationship is based on guidance in Regulatory Guide (RG) 1.105, "Instrument Setpoints for Safety-Related Systems." The typical reactor protection and/or safeguard setpoint relationship, depicting a high process setpoint, is depicted as follows:

U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 13 of 32 Safety Limit (SL) Analytical Limit (AL) Tech Spec Allowable Value (AV) Nominal Setpoint Range of Normal Operation Safety Limits (SL) are the values chosen to reasonably protect the integrity of physical barriers that guard against the uncontrolled release of radioactivity. Analytical Limits (AL) typically are values utilized in the safety analyses, which were specifically chosen to allow the equipment time to act and prevent exceeding the Safety Limits. The Allowable Value (AV) represents an acceptable benchmark (specified by Technical Specifications) for which periodic calibrations/checks must fall within to ensure operability. When a channel "As-found" condition is determined to be less conservative than the AV, the channel must be declared inoperable. The AV determination is based on expected uncertainty influences for the portion of the loop tested. Uncertainty magnitudes must be representative of the surveillance interval duration. Examples of typical uncertainty influences, which may be measured during testing, are reference accuracy, calibration uncertainty, representative uncertainty for temperature variations between calibrations, representative drift over surveillance interval, etc. The AV determination is based on the most conservative of either EDM Method 1 or 2 (described below), provided both methods are applicable. If no analytical limit is established, EDM Method 2 is not applicable. EDM Method 2 is typically more conservative for applications with little or no margin from the AL. Conversely, EDM Method 1 is more conservative for applications with substantial margin. The combination of terms for the AV determination should be consistent with that for the TLU value. TLU = +/ - [RUNT 2 + RUT2] 112 + biases where: NT = denotes uncertainty associated with the portion of the loop not tested during the channel check, calibration, etc. T = denotes uncertainty associated with the portion of the loop tested during the channel check, calibration, etc. RU = total random uncertainty EDM METHOD 1 AV = SP + / - RUTcal where: SP = nominal setpoint 

              +/- =     "+" or "-"sign convention dictated by whichever is in the direction of the Analytical Limit (i.e. towards AL)

T-cal = includes representative (minimum) uncertainty term magnitudes associated with the portion of the loop tested and for the desired interval (attributed to the expected variation from "as-left" conditions).

U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 14 of 32 EDM METHOD 2 AV = AL + / - RUNT = AL + / - {[(TLU - Biases) 2- RUT -cal2]1/2 + Biases} where: AL = Analytical Limit 

             +I- =      "+" or "-"sign convention dictated by whichever is in the direction of the setpoint (i.e. towards setpoint)

Total Loop Uncertainty The setpoint calculation revisions used the EDM-102 methodology to determine the channel uncertainty. The calculated TLU values for McGuire are as follows: McGuire TS Table 3.3.1-1 FUNCTION TLU 8.a Pressurizer Pressure - Low 29.6 psi 8.b Pressurizer Pressure - High - 17.3 psi 9 Pressurizer Water Level - High 3.4 % Level 10.a Reactor Coolant Flow - Low - Single Loop 4 % Flow 10.b Reactor Coolant Flow - Low - Two Loops 4 % Flow 12 Underfrequency RCPS 0.052 Hz 13 Steam Generator (SG) Water Level - Low Low 3.56 % Level 16.a Reactor Trip System Interlocks - Intermediate 8.381 x 1011 amps Range Neutron Flux, P-6 16.e Reactor Trip System Interlocks -Turbine Impulse 12.35 psi Pressure, P-13 McGuire TS Table 3.3.2-1 FUNCTION TLU 1 .d Safety Injection - Pressurizer Pressure - Low 29.3 psi Low 4.d(1) Steam Line Isolation - Steam Line Pressure - Low 30.78 psi 4.d(2) Steam Line Isolation - Steam Line Pressure - 31.21 psi Negative Rate - High 5.a(2) Turbine Trip and Feedwater Isolation - Turbine - 5.97 % Level Trip - SG Water Level - High High (P-14) 5.b(2) Turbine Trip and Feedwater Isolation - Feedwater - 5.97 % Level Isolation - SG Water Level - High High (P-14) 5.b(4) Turbine Trip and Feedwater Isolation - Feedwater 1.86 OF Isolation - Tavg - Low II

U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 15 of 32 McGuire TS Table 3.3.2-1 FUNCTION TLU 6.b Auxiliary Feedwater - SG Water Level - Low Low 3.56 % Level 8.b ESFAS Interlocks - Pressurizer Pressure, P-11 - 17.3 psi 8.c ESFAS Interlocks - Tavg - Low Low, P-1 2 1.86 OF The calculated TLU values for Catawba are as follows: Catawba TS Table 3.3.1-1 FUNCTION TLU 2.a Power Range Neutron Flux - High 2.38 % RTP 2.b Power Range Neutron Flux - Low 2.38 % RTP 6 Overtemperature AT 12.05 % RTP 8.a Pressurizer Pressure - Low 32 psi 8.b Pressurizer Pressure - High - 19.7 psi 9 Pressurizer Water Level - High 3.4 %,Level 10.a Reactor Coolant Flow - Low - Single Loop 3.4 % Flow 10.b Reactor Coolant Flow - Low - Two Loops 3.4 % Flow 12 Underfrequency RCPs 0.16 Hz 13 Steam Generator (SG) Water Level - Low Low 3.64 % Level (Unit 1) 8.94 % Level (Unit 2) 16.a Reactor Trip System Interlocks - Intermediate - 7.73 x 1011 amps Range Neutron Flux, P-6 16.f Reactor Trip System Interlocks - Turbine Impulse 19.15 psi Pressure, P-13 Catawba TS Table 3.3.2-1 FUNCTION TLU 1.c Safety Injection - Containment Pressure - High 0.24 psi 1.d Safety Injection - Pressurizer Pressure - Low 31.7 psi 3.b(3) Containment Isolation - Phase B Isolation - 0.24 psi Containment Pressure - High High 4.c Steam Line Isolation - Containment Pressure - High High 4.d(1) Steam Line Isolation - Steam Line Pressure - Low 34.37 psi

U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 16 of 32 Catawba TS Table 3.3.2-1 FUNCTION TLU 4.d(2) Steam Line Isolation - Steam Line Pressure - 34.77 psi Negative Rate - High 34.77_psi 5.a(2) Turbine Trip and Feedwater Isolation - Turbine - 6.05 % Level (Unit 1) Trip - SG Water Level - High-High (P-14) - 13.43 % Level (Unit 2) 5.b(2) Turbine Trip and Feedwater Isolation - Feedwater - 6.05 % Level (Unit 1) Isolation - SG Water Level - High High (P-14) - 13.43 % Level (Unit 2) 5.b(4) Turbine Trip and Feedwater Isolation - Feedwater 1.83 OF Isolation - Tavg - Low 1.83__F 6.b Auxiliary Feedwater - SG Water Level - Low Low 3.64 % Level (Unit 1) 8.94 % Level (Unit 2) 8.b ESFAS Interlocks - Pressurizer Pressure, P-1 1 19.7 psi 8.c ESFAS Interlocks - Tavg - Low Low, P-1 2 1.83 OF Analytical Limits The Analytical Limit (AL) is the limit of a measured .or calculated variable established by the safety analyses to ensure that a safety limit is not exceeded. Several functions, as indicated in the tables below, are not explicitly credited in any design basis accidents, and, therefore, no AL has been established for use in the accident analysis. The ALs for McGuire are as follows: McGuire TS Table 3.3.1-1 FUNCTION Analytical Limit 8.a Pressurizer Pressure - Low 1900 psig 8.b Pressurizer Pressure - High 2415 psig 9 Pressurizer Water Level - High N/A* 10.a Reactor Coolant Flow - Low - Single Loop 83.5% 10.b Reactor Coolant Flow - Low - Two Loops 83.5% 12 Underfrequency RCPs 55.0 Hz 13 Steam Generator (SG) Water Level - Low Low 2.7% 16.a Reactor Trip System Interlocks - Intermediate N/A

  • Range Neutron Flux, P-6 16.e Reactor Trip System Interlocks - Turbine Impulse N/A
  • Pressure, P-13
  • Not credited in accident analyses.

U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 17 of 32 McGuire TS Table 3.3.2-1 FUNCTION Analytical Limit 1.d Safety Injection - Pressurizer Pressure - Low 1800 psig Low 4.d(1) Steam Line Isolation - Steam Line Pressure - Low 725 psig 4.d(2) Steam Line Isolation - Steam Line Pressure - N/A Negative Rate - High 5.a(2) Turbine Tripand Feedwater Isolation - Turbine 91.9% Trip - SG Water Level - High High (P-14) 5.b(2) Turbine Trip and Feedwater Isolation - Feedwater 91.9% Isolation - SG Water Level - High High (P-14) 5.b(4) Turbine Trip and Feedwater Isolation - Feedwater N/A Isolation - Tavg - Low 6.b Auxiliary Feedwater - SG Water Level - Low Low 2.7% 8.b ESFAS Interlocks - Pressurizer Pressure, P-i 1 N/A

  • 8.c ESFAS Interlocks - Tavg - Low Low, P-12 N/A *
  • Not credited in accident analyses.
 ** Credited in accident analyses, but analysis is insensitive to this value.

The ALs for Catawba are as follows: Catawba TS Table 3.3.1-1 FUNCTION Analytical Limit 2.a Power Range Neutron Flux - High 113.2% 2.b Power Range Neutron Flux - Low 37% 6 Overtemperature AT 132.5% RTP 8.a Pressurizer Pressure 

                             *.1 - Low                                        1900 psig 8.b     Pressurizer Pressure - High                                        2415 psig 9      Pressurizer Water Level - High                                       N/A*

10.a Reactor Coolant Flow.- Low - Single Loop 83.5% (Unit 1) 86.5% (Unit 2) 10.b Reactor Coolant Flow - Low - Two Loops 83.5% (Unit 1) 86.5% (Unit 2) 12 Underfrequency RCPs 55 Hz 13 Steam Generator (SG) Water Level - Low Low 2.7% (Unit 1) 25.8% (Unit 2) 16.a Reactor Trip System Interlocks - Intermediate N/A Range Neutron Flux, P-6

U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 18 of 32 Catawba TS Table 3.3.1-1 FUNCTION Analytical Limit 16.f Reactor Trip System Interlocks - Turbine Impulse N/A

  • Pressure, P-13
  • Not credited in accident analyses.

Catawba TS Table 3.3.2-1 FUNCTION Analytical Limit 1 .c Safety Injection - Containment Pressure - High 2.02 psig 1.d Safety Injection - Pressurizer Pressure - Low 1800 psig 3.b(3) Containment Isolation - Phase B Isolation - 4.27 psig Containment Pressure - High High 4.c Steam Line Isolation - Containment Pressure - 4.27 psig High High 4.d(1) Steam Line Isolation - Steam Line Pressure - Low 725 psig 4.d(2) Steam Line Isolation - Steam Line Pressure - N/A Negative Rate - High 5.a(2) Turbine Trip and Feedwater Isolation - Turbine 91.9% (Unit 1) Trip - SG Water Level - High-High (P-14) 90.4% (Unit 2) 5.b(2) Turbine Trip and Feedwater Isolation - Feedwater 91.9% (Unit 1) Isolation - SG Water Level - High High (P-14) 90.4% (Unit 2) 5.b(4) Turbine Trip and Feedwater Isolation - Feedwater N/A Isolation - Tavg - Low 6.b Auxiliary Feedwater- SG Water Level - Low Low 2.7% (Unit 1) 25.8% (Unit 2) 8.b ESFAS Interlocks - Pressurizer Pressure, P-i 1 N/A

  • 8.c ESFAS Interlocks - Tavg - Low Low, P-12 N/A *
  • Not credited in accident analyses.
 ** Credited in accident analyses, but analysis is insensitive to this value.

Nominal Trip Setpoints The Nominal Trip Setpoint (NTSP) is the value at which the trip or actuation is intended to occur. The NTSP is primarily chosen to assure that a trip or safety actuation occurs before the process reaches the AL. Secondarily, the NTSP is chosen to assure the plant can operate and experience expected operational transients without unnecessary trips or safeguards actuations. Many methods are available to determine a NTSP which prevents a process from exceeding the AL while providing adequate operating margin. The following equation represents one such acceptable method for determining the Nominal Trip Setpoint: NTSP = AL +/- (TLU + Margin) Note that the margin term is an allowance added to the instrument channel uncertainty which moves the setpoint farther away from the AL. The TLU plus margin allowance is summed or

U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 19 of 32 subtracted from the AL depending on whether the process is increasing or decreasing toward the NTSP. The calculated Nominal Trip Setpoints for. McGuire are as follows: McGuire TS Table 3.3.1-1 FUNCTION NTSP 8.a Pressurizer Pressure - Low 1945 psig 8.b Pressurizer Pressure - High 2385 psig 9 Pressurizer Water Level - High 92% 10.a Reactor Coolant Flow - Low -Single Loop 88% 10.b Reactor Coolant Flow - Low - Two Loops 88% 12 Underfrequency RCPs 56.4 Hz 13 Steam Generator (SG) Water Level - Low Low 16.7% 16.a Reactor Trip System Interlocks - Intermediate 1E-1 0 amp Range Neutron Flux, P-6 16.e Reactor Trip System Interlocks - Turbine Impulse 10% Pressure, P-13 McGuire TS Table 3.3.2-1 FUNCTION NTSP 1 .d Safety Injection - Pressurizer Pressure - Low 1845 psig Low 4.d(1) Steam Line Isolation - Steam Line Pressure - Low 775 psig 4.d(2) Steam Line Isolation - Steam Line Pressure - 100 psi Negative Rate - High 5.a(2) Turbine Trip and Feedwater Isolation - Turbine 83.9% Trip - SG Water Level- High High (P-14) 5.b(2) Turbine Trip and Feedwater Isolation - Feedwater 83.9% Isolation - SG Water Level - High High (P-14) 5.b(4) Turbine Trip and Feedwater Isolation - Feedwater 553 OF Isolation - Tavg - Low 6.b Auxiliary Feedwater - SG Water Level - Low Low 16.7% 8.b ESFAS Interlocks - Pressurizer Pressure, P-11 1955 psig 8.c ESFAS Interlocks - Tavg - Low Low, P-12 5 Note that these NTSP values are identical to the values currently listed in TS Tables 3.3.1-1 and 3.3.2-1. This license amendment application does not propose any changes to these values.

U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 20 of 32 The calculated Nominal Trip Setpoints for Catawba are as follows: Catawba TS Table 3.3.1-1 FUNCTION NTSP 2.a Power Range Neutron Flux - High 109% RTP 2.b Power Range Neutron Flux - Low 25% RTP 6 Overtemperature AT See TS Table 3.3.1-1 Note 1 8.a Pressurizer Pressure - Low 1945 psig 8.b Pressurizer Pressure - High 2385 psig 9 Pressurizer Water Level - High 92% 10.a Reactor Coolant Flow - Low - Single Loop 91% 10.b Reactor Coolant Flow - Low - Two Loops 91% 12 Underfrequency RCPs 56.4 Hz 13 Steam Generator (SG) Water Level - Low Low 10.7% (Unit 1) 36.8% (Unit 2) 16.a Reactor Trip System Interlocks - Intermediate 1E-1o amp Range Neutron Flux, P-6 16.f Reactor Trip System Interlocks - Turbine Impulse 10% RTP Pressure, P-13 Catawba TS Table 3.3.2-1 FUNCTION -NTSP 1 .c Safety Injection - Containment Pressure - High 1.2 psig 1 .d Safety Injection - Pressurizer Pressure - Low 1845 psig 3.b(3) Containment Isolation - Phase B Isolation - 3.0 psig Containment Pressure - High High 4.c Steam Line Isolation - Containment Pressure - 3.0 psig High High 4.d(1) Steam Line Isolation - Steam Line Pressure - Low 775 psi 4.d(2) Steam Line Isolation - Steam Line Pressure - 100 psi Negative Rate - High 5.a(2) Turbine Trip and Feedwater Isolation - Turbine 83.9% (Unit 1) Trip - SG Water Level - High-High (P-14) 77.1% (Unit 2) 5.b(2) Turbine Trip and Feedwater Isolation - Feedwater 83.9% (Unit 1) Isolation - SG Water Level - High High (P-14) 77.1% (Unit 2) 5.b(4) Turbine Trip and Feedwater Isolation - Feedwater 564 OF Isolation - Tavg - Low

U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 21 of 32 Catawba TS Table 3.3.2-1 FUNCTION NTSP 6.b Auxiliary Feedwater- SG Water Level - Low Low 10.7% (Unit 1) 36.8% (Unit 2)

8. b ESFAS Interlocks - Pressurizer Pressure, P-i 1 1955 psig 8.c ESFAS Interlocks - Tavg - Low Low, P-12 553 OF Note that these NTSP values are identical to the values currently listed in TS Tables 3.3.1-1 and 3.3.2-1. This license amendment application does not propose any changes to these values.

Allowable Values The Allowable Value is a limiting value that the trip setpoint may have when tested periodically, beyond which the channel must be declared inoperable. The AV for each setpoint is calculated using the two EDM methods described above in the Basic Methodology - EDM-102 Section. The more conservative calculated value for the two methods is then utilized as the AV. The calculated Allowable Values for McGuire are as follows: McGuire TS Table 3.3.1-1 FUNCTION ALLOWABLE VALUES 8.a Pressurizer Pressure - Low > 1939 psig 8.b Pressurizer Pressure - High <-2390 psig 9 Pressurizer Water Level - High < 92.7% 10.a Reactor Coolant Flow - Low - Single Loop _> 87.6% 10.b Reactor Coolant Flow - Low - Two Loops > 87.6% 12 Underfrequency RCPs > 56.3 Hz 13 Steam Generator (SG) Water Level - Low Low 16% 16.a Reactor Trip System Interlocks - Intermediate Range Neutron Flux, P-6 > 16.e Reactor Trip System Interlocks - Turbine Impulse < 10.7% Pressure, P-13 

          . McGuirTS Table'3.3.2-1 FUNCTION--                        ALLOWABLE VALUES..

1 .d Safety Injection - Pressurizer Pressure - Low 1840 psig Low 4.d(1) Steam Line Isolation - Steam Line Pressure - Low >766 psig

U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 22 of 32 McGuire TS Table 3.3.2-1 FUNCTION ALLOWABLE VALUES 4.d(2) Steam Line Isolation - Steam Line Pressure - < 110 psi Negative Rate - High 5.a(2) Turbine Trip and Feedwater Isolation - Turbine < 84.7% Trip - SG Water Level - High High (P-14) 5.b(2) Turbine Trip and Feedwater Isolation - Feedwater Isolation - SG Water Level - High High (P-14) 5.b(4) Turbine Trip and Feedwater Isolation - Feedwater > 551.84 OF Isolation - Tavg - Low 6.b Auxiliary Feedwater - SG Water Level - Low Low >16% 8.b' ESFAS Interlocks - Pressurizer Pressure, P-11

  • 1960 psig 8.c ESFAS Interlocks -Tavg - Low Low,.P-12 >551.84OF The calculated Allowable Values for Catawba are as follows:

Catawba TS Table 3.3.1-1 FUNCTION ALLOWABLE VALUES 2.a Power Range Neutron Flux - High < 110.3% RTP 2.b Power Range Neutron Flux - Low _<26.3% RTP 6 Overtemperature AT < 3.97% RTP 8.a Pressurizer Pressure - Low > 1939 psig 8.b Pressurizer Pressure - High < 2390 psig 9 Pressurizer Water Level - High < 92.7% 10.a Reactor Coolant Flow - Low - Single Loop >90.5% 10.b Reactor Coolant Flow - Low - Two Loops > 90.5% 12 Underfrequency RCPs > 56.2 Hz 13 Steam Generator (SG) Water Level - Low Low > 10% (Unit 1) 

                                                              >36.1% (Unit 2) 16.a   Reactor Trip System Interlocks - Intermediate            6.9E-1 1 amp Range Neutron Flux, P-6 16.f   Reactor Trip System Interlocks - Turbine Impulse       < 10.7% RTP Pressure, P-13 CatawbayjTS Tableo3..2-1 FUNCTION r                 ALLOWABLE VALUES 1.c] Safety Injection - Containment Pressure - High             *1.3 psig

U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 23 of 32 Catawba TS Table 3.3.2-1 FUNCTION ALLOWABLE VALUES 1.d Safety Injection - Pressurizer Pressure - Low 1840 psig 3.b(3) Containment Isolation - Phase B Isolation - Containment Pressure - High High 3.1 psig 4.c Steam Line Isolation,- Containment Pressure - 3.1 psig High High 4.d(1) Steam Line Isolation - Steam Line Pressure - Low > 766 psig 4.d(2) Steam Line Isolation - Steam Line Pressure - < 1.10.1 .psi Negative Rate - High 5.a(2) Turbine Trip and Feedwater Isolation - Turbine < 84.6% (Unit 1) Trip - SG Water Level - High-High (P-14) <77.8% (Unit 2) 5.b(2) Turbine Trip and Feedwater Isolation - Feedwater <84.6% (Unit 1) Isolation - SG Water Level - High High (P-14) _<77.8% (Unit 2) 5.b(4) Turbine Trip and Feedwater Isolation - Feedwater > 562.88 OF Isolation - Tavg - Low 6.b Auxiliary Feedwater - SG Water Level - Low Low > 10% (Unit 1) 

                                                                        >36.1% (Unit 2) 8.b     ESFAS Interlocks - Pressurizer Pressure, P-111                     1946 psig and
                                                                            *1960 psig 8.c     ESFAS Interlocks - Tavg - Low Low, P-1 2                          >-551.88 OF As-Found Tolerance "As-Found" is the condition in which a channel, or portion of a channel, is found after a period of operation and before recalibration (if necessary). The As-Found Tolerance is the allowance within the TLU that the channel or portion thereof must be within to ensure the channel is capable of producing a trip prior to reaching the Safety Analysis AL'. Values recorded during a channel as-found surveillance which are within the As-Found Tolerance would clearly indicate a channel is operating as intended. Values recorded during a channel as-found surveillance which exceed the As-Found Tolerance would require a more detailed review to determine the effects of the increased uncertainty on the operability of the channel. Uncertainties which make up the As-Found Tolerance for the portion of the channel under surveillance include, reference accuracy, drift, and measurement and test equipment.

The calculated As-Found Tolerances for McGuire are as follows: McGuire TS Table 3.3.1-1 FUNCTION As-Fond Tolerancep. 8.a Pressurizer Pressure - Low 

                                                                            +/- 4.749 psi 8.b     Pressurizer Pressure - High                                      +/- 4.124 psi 9      Pressurizer Water Level- High                                     +0.515%

U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 24 of 32 McGuire TS Table 3.3.1-1 FUNCTION As-Found Tolerance 10.a Reactor Coolant Flow - Low - Single Loop 0.4 % 10.b Reactor Coolant Flow - Low - Two Loops + 0.4% 12 Underfrequency RCPs + 0.037 Hz 13 Steam Generator (SG) Water Level - Low Low +/- 0.594% McGuire TS Table 3.3.2-1 FUNCTION As-Found.Tolerance 1 .d Safety Injection - Pressurizer Pressure - Low 4.124 psi Low 4.d(1) Steam Line Isolation - Steam Line Pressure - Low 

                                                                   + 6.701 psi 4.d(2)  Steam Line Isolation - Steam Line Pressure -                  7.717 psi Negative Rate - High 5.a(2)  Turbine Trip and Feedwater Isolation - Turbine Trip - SG Water Level - High High (P-14) 5.b(2)  Turbine Trip and Feedwater Isolation - Feedwater           +/-  0.594%

Isolation - SG Water Level - High High (P-14) 5.b(4) Turbine Trip and Feedwater Isolation - Feedwater 0.87 OF Isolation - Tavg - Low 6.b Auxiliary Feedwater - SG Water Level - Low Low +/- 0.594% The calculated As-Found Tolerances for Catawba are as follows: Catawba TS Table 3.3.1-1 FUNCTION As-Found Tolerance 2.a Power Range Neutron Flux - High + 1.262 % RTP 2.b Power Range Neutron Flux - Low + 1.262% RTP 6 Overtemperature AT +/- 2.73% RTP 8.a Pressurizer Pressure - Low +/-4.749 psi 8.b Pressurizer Pressure - High +/- 4.124 psi 9 Pressurizer Water Level- High ++/-0.515% 10.a Reactor Coolant Flow - Low - Single Loop +/- 0.41 % 10.b Reactor Coolant Flow - Low - Two Loops +/-0.41  % 12 Underfrequency RCPs +/- 0.128 Hz

U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 25 of 32 Catawba TS Table 3.3.1-1 FUNCTION As-Found Tolerance 13 Steam Generator (SG) Water Level - Low Low 

                                                                               ++055 0.515 %

Catawba TS Table 3.3.2-1 FUNCTION As-Found Tolerance 1.c Safety Injection - Containment Pressure - High +/- 0.052 psi 1 .d Safety Injection - Pressurizer Pressure - Low +/- 4.124 psi 3.b(3) Containment Isolation - Phase B Isolation - Containment Pressure - High High + 0.052 psi 4.c Steam Line Isolation - Containment Pressure - High High + 0.052 psi 4.d(1) Steam Line Isolation - Steam Line Pressure - Low +/- 6.701 psi 4.d(2) Steam Line Isolation - Steam Line Pressure - +/- 7.717 psi Negative Rate - High 5.a(2) Turbine Trip and Feedwater Isolation - Turbine +0.515 % Trip - SG Water Level - High-High (P-14) 5.b(2) Turbine Trip and Feedwater Isolation - Feedwater Isolation - SG Water Level - High High (P-14) 5.b(4) Turbine Trip and Feedwater Isolation - Feedwater 0.83 OF Isolation - Tavg - Low +_0.83 __F 6.b Auxiliary Feedwater - SG Water Level - Low Low .+ 0.515 % As-Left Tolerance "As-Left" is the condition in which a channel, or portion of a channel, is left after calibration or final setpoint device setpoint verification. The As-Left Tolerance is the acceptable setting variation about the setpoint that the technician may leave the setting following calibration. The size of the setting or As-Left Tolerance is generally based on the reference accuracy and limitations of the technician in adjusting the module (measurement and test equipment and reading resolution). The calculated As-Left Tolerances for McGuire are as follows: As-Left Tole rance jr\cGuireTS Table 3.3.1-1 FUNCTION (bu h TP 8.a Pressurizer Pressure - Low 3.027 psi 8.b Pressurizer Pressure - High +/-2.919 psi 9 Pressurizer Water Level - High + 0.365% 10.a Reactor Coolant Flow - Low- Single Loop + 0.30%

U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 26 of 32 As-Left Tolerance About ThernTP McGuire TS Table 3.3.1-1 FUNCTION (about the NTSP) 10.b Reactor Coolant Flow - Low - Two Loops +/- 0.30% 12 Underfrequency RCPs 0.036 Hz 13 Steam Generator (SG) Water Level - Low Low 

                                                                 +/-  0.378%

As-Left Tolerance McGuire TS Table 3.3.2-1 FUNCTION About ThernTP (about the NTSP) 1 .d Safety Injection - Pressurizer Pressure - Low +/- 2.919 psi Low 4.d(1) Steam Line Isolation - Steam Line Pressure - Low + 4.744 psi 4.d(2) Steam Line Isolation - Steam Line Pressure - +/- 4.919 psi Negative Rate - High 5.a(2) Turbine Trip and Feedwater Isolation - Turbine Trip - SG Water Level - High High (P-14) 5.b(2) Turbine Trip and Feedwater Isolation - Feedwater Isolation - SG Water Level - High High (P-14) +/- 0.378% 5.b(4) Turbine Trip and Feedwater Isolation - Feedwater +/- 0.52 OF Isolation - Tavg - Low +_0.52 __F 6.b Auxiliary Feedwater - SG Water Level - Low Low 

                                                                 +/-  0.378%

The calculated As-Left Tolerances for Catawba are as follows: As-Left Tolerance Catawba TS Table 3.3.1-1 FUNCTION About ThernTP (about the NTSP) 2.a Power Range Neutron Flux - High +/- 0.25% 2.b Power Range Neutron Flux - Low +/- 0.25% 6 Overtemperature AT + 1.81% 8.a Pressurizer Pressure - Low 3.027 psi 8.b Pressurizer Pressure - High + 2.919 psi 9 Pressurizer Water Level - High + 0.365% 10.a Reactor Coolant Flow - Low - Single Loop 0.29% 10.b Reactor Coolant Flow - Low - Two Loops ++/-0.29% 12 Underfrequency RCPs + 0.092 Hz 13 Steam Generator (SG) Water Level - Low Low 0.365%

U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 27 of 32 As-Left Tolerance Catawba TS Table 3.3.2-1 FUNCTION About the (about ThernTP NTSP) 1.c Safety Injection - Containment Pressure - High +/- 0.036 psi 1 .d Safety Injection - Pressurizer Pressure - Low +/- 2.919 psi 3.b(3) Containment Isolation - Phase B Isolation - +/- 0.036 psi Containment Pressure - High High 4.c Steam Line Isolation - Containment Pressure - +/- 0.036 psi High High 4.d(1) Steam Line Isolation - Steam Line Pressure - Low +/-4.744 psi 4.d(2) Steam Line Isolation - Steam Line Pressure - + 4.919 psi Negative Rate - High 5.a(2) Turbine Trip and Feedwater Isolation - Turbine Trip - SG Water Level - High-High (P-14) 5.b(2) Turbine Trip and Feedwater Isolation - Feedwater +/- 0.365% Isolation - SG Water Level - High High (P-14) 5.b(4) Turbine Trip and Feedwater'Isolation - Feedwater + 0.53 OF Isolation - Tavg - Low 6.b Auxiliary Feedwater - SG Water Level - Low Low +/- 0.365% Summary The proposed changes to TS Allowable Values are based on methodology that is consistent with the intent of ISA Standard RP67.04-1994 Part II, "Methodologies for the Determination of Setpoints for Nuclear Safety Related Instrumentation," and will preserve assumptions in the applicable accident analyses. Chancaes Related to TSTF-493 Included in the scope of the proposed changes is the addition of new lettered footnotes applicable to the affected Surveillance Requirements listed in Tables 3.3.1-1 and 3.3.2-1. These footnotes are consistent with Technical Specification Task Force Traveler TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions," Revision 4. The first new lettered footnote in each table requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value. Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology. The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. The second new lettered footnote in each table requires that the as-left setting for the channel be returned to within the as-left tolerance of the NTSP. Where a setpoint more conservative than the NTSP is used in the plant surveillance procedures, the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint. This will ensure that

U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 28 of 32 sufficient margin to the Safety Limit and/or Analytical Limit is maintained. If the as-left channel setting cannot be returned to a setting within the as-left tolerance of the NTSP, then the channel shall be declared inoperable. This footnote also requires that the methodologies for calculating the as-left and the as-found tolerances be in the UFSAR. These new footnotes enhance safety by ensuring that unexpected as-found conditions are evaluated prior to returning the channel to service, and ensuring that as-left settings provide sufficient margin for uncertainties. These changes will have no adverse effect on plant safety. Summary The proposed changes do not adversely affect the overall operation or ability of the equipment to perform its intended function. The proposed changes have no adverse impact on the plant safety analyses, and consequently no impact on plant safety.

5. REGULATORY ANALYSIS 5.1 No Significant Hazards Consideration The proposed amendment affects McGuire Nuclear Station (MNS) and Catawba Nuclear Station (CNS) Technical Specification (TS) 3.3. 1, "Reactor Trip System (RTS) Instrumentation," and TS 3.3.2, "Engineered Safety Feature Actuation System (ESFAS) Instrumentation." The proposed changes are in support of updated setpoint calculations. Applicable aspects of Technical Specification Task.Force Traveler TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions," are incorporated in the scope of the proposed changes.

An evaluation has been performed to determine whether or not a significant hazards consideration is involved with the proposed amendments by focusing on the three standards set forth in 10 CFR 50.92, "Issuance of amendment," as discussed below:

1. Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?

Response: No The specific Technical Specification changes are associated with 1) the specific Allowable Values for various RTS and ESFAS channels, including instrumentation associated with neutron flux, containment pressure, pressurizer pressure, pressurizer water level, reactor coolant flow, reactor coolant pump underfrequency, steam generator water level, turbine impulse pressure, steam line pressure, and reactor coolant temperature; 2) the addition of specific requirements to be taken if an instrument channel setpoint is outside its predefined as-found tolerance; and 3) the addition of specific requirements regarding resetting of an instrument channel setpoint within an as-left tolerance. The RTS and ESFAS instrumentation is accident mitigation equipment and does not affect the probability of any accident being initiated. In addition, none of the above-mentioned proposed Technical Specification changes affect the probability of any accident being initiated.

U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 29 of 32 The proposed changes to TS Allowable Values are based on methodology that is consistent with the intent of ISA Standard RP67.04-1994 Part II, "Methodologies for the Determination of Setpoints for Nuclear Safety Related Instrumentation," and will preserve assumptions in the applicable accident analyses. None of the proposed changes alter any assumption previously made in the radiological consequences evaluations, nor do they affect mitigation of the radiological consequences of an accident previously evaluated. In summary, the proposed changes will not involve a significant increase in the probability or consequences of an accident previously evaluated.

2. Does the proposed amendment create the possibility of a new or different kind of accident from any accident previously evaluated?

Response: No No new accident scenarios, failure mechanisms, or single failures are introduced as a result of any of the proposed changes. The RTS and ESFAS are not capable by itself of initiating any accident. No physical changes to the overall plant are being proposed. No changes to the overall manner in which the plant is operated are being proposed. The proposed changes do not introduce any new failure modes. Therefore, none of the proposed changes will create the possibility of a new or different kind of accident from any accident previously evaluated.

3. Does the proposed amendment involve a significant reduction in a margin of safety?

Response: No Margin of safety is related to the confidence in the ability of the fission product barriers to perform their intended functions. These barriers include the fuel cladding, the reactor coolant system pressure boundary, and the containment barriers. The proposed changes will not have any impact on these barriers. Plant actuation features and Nominal Trip Setpoints will be unchanged and will actuate prior to exceeding any analytical limits. No accident mitigating equipment will be adversely impacted. Therefore, existing safety margins will be preserved. None of the proposed changes will involve a significant reduction in a.margin of safety. Based on the above, it is concluded that the proposed amendment presents no significant hazards consideration under the standards set forth in 10 CFR 50.92 (c), and accordingly, a finding of "no significant hazards consideration" is justified. 5.2 Applicable Regulatory Req uirements/Criteria The regulatory bases and guidance documents associated with the systems discussed in this amendment application include: 10 CFR 50.36(c)(1)(ii)(A), states in part, "Limiting safety system settings for nuclear reactors are settings for automatic protective devices related to those

U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 30 of 32 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." 10 CFR 50 Appendix A General Design Criteria (GDC)-10, Reactordesign, requires that the reactor core and associated coolant, control, and protection systems be designed with appropriate margin to assure that specified acceptable fuel design limits are not exceeded during any condition of normal operation, including the effects of anticipated operational occurrences. GDC-13, Instrumentation and control, requires that instrumentation be provided to monitor variables and systems over their anticipated ranges for normal operation, for anticipated operational occurrences, and for accident conditions as appropriate to assure adequate safety, including those variables and systems that can affect the fission process, the integrity of the reactor core, the reactor coolant pressure boundary, and the containment and its associated systems. GDC-20, Protectionsystem functions, requires that the protection system be designed (1) to initiate automatically the operation of appropriate systems including the reactivity control systems, to assure that specified acceptable fuel design limits are not exceeded as a result of anticipated operational occurrences, and (2) to sense accident conditions and to initiate the operation of systems and components important to safety. The proposed amendment will not change the RTS or ESFAS instrumentation design such that compliance with any of the above regulatory requirements would come into question. All of the proposed Allowable Value changes are conservative based on updated-setpoint calculations. In addition to the above regulatory requirements, Regulatory Guide (RG) 1.105, Revision 3, "Setpoints for Safety-Related Instrumentation," provides regulatory guidance pertinent to the updated instrument setpoint calculations performed in support of this license amendment application. Regulatory Guide 1.105 endorses Instrument Society of America (ISA) Standard S67.04-1994 Part I, subject to four listed exceptions and clarifications. The four listed exceptions and clarifications, taken verbatim from RG 1.105 (as shown in italics), and discussions of each, as applicable to this license amendment application, are as follows: RG 1.105 Regulatory Position C.1 Section 4 of ISA-S67.04-1994 specifies the methods, but not the criterion, for combining uncertaintiesin determining a trip setpoint and its allowable values. The 95/95 tolerance limit is an acceptable criterion for uncertainties. That is, there is a 95% probability that the constructed limits contain 95% of the - populationof interest for the surveillance interval selected. A 95/95 tolerance is used to establish acceptable uncertainty values for the instrument strings. At the McGuire and Catawba Nuclear Stations, this is assured by means of the calculation methods, instrument string calibration, and setpoint

U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 31 of 32 verification. RG 1.105 Regulatory Position C.2 Sections 7 and 8 of Part 1 of ISA-S67.04-1994 reference several industry codes and standards. If a referenced standardhas been incorporatedseparately into the NRC's regulations, licensees and applicants must comply with that standardas set forth in the regulation. If the referenced standardhas been endorsed in a regulatoryguide, the standardconstitutes a method acceptable to the NRC staff of meeting a regulatoryrequirement as describedin the regulatoryguide. If a referenced standardhas been neither incorporatedinto the NRC's regulations nor endorsed in a regulatory guide, licensees and applicants may considerand use the information in the referenced standardif appropriatelyjustified, consistent with current regulatorypractice. The setpoint calculation revisions supporting the proposed Technical Specification changes were performed in accordance with Duke Energy Engineering Directives Manual (EDM)-102, "Instrument Setpoint/Uncertainty Calculations," Revision 3. The methodology described in EDM-1 02 is appropriately justified and is consistent with industry practice. RG 1.105 Regulatory Position C.3 Section 4.3 of ISA-$67.04-1994 states that the limiting safety system setting (LSSS) may be maintainedin technical specificationsor appropriateplant procedures. However, 10 CFR 50.36 states that the technical specifications will include items in the categories of safety limits, limiting safety system settings (LSSS), and limiting control settings. Thus, the LSSS may not be maintained in plant procedures. Rather, the LSSS must be specified as a technical-specification-definedlimit in orderto satisfy the requirements of 10 CFR 50.36. The LSSS should be developed in accordance with the setpoint methodology set forth in the standard,with the LSSS listed in the technical specifications. In accordance with Section 4.3 of Part 1 of ISA S67.04-1994, the purpose of the LSSS is to assure that protective action is initiated before the process conditions reach the analytical limit. In addition, the LSSS may be the Allowable Value, the trip setpoint, or both. Consistent with NRC guidance, the LSSS are specified in the McGuire Nuclear Station and Catawba Nuclear Station Technical Specifications in the "Allowable Value" column of Technical Specification Table 3.3. 1-1, "Reactor Trip System Instrumentation". RG 1.105 Regulatory Position C.4 ISA-$67.04-1994 provides a discussion on the purpose and application of an allowable value. The allowable value is the limiting value that the trip setpoint can have when tested periodically, beyond which the instrument channel is considered inoperableand corrective action must be taken in accordancewith the technical specifications. The allowable value relationship to the setpoint methodology and testing requirementsin the technical specificationsmust be documented.

U.S. Nuclear Regulatory Commission Enclosure 1 June 29, 2010 Page 32 of 32 The Allowable Value relationship to the setpoint methodology and testing requirements in the Technical Specifications is documented in the setpoint calculation. The setpoint calculation is maintained as part of plant records. 5.3 Precedents None. Conclusion In conclusion, based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.

6. ENVIRONMENTAL CONSIDERATION A review has determined that the proposed amendment would change a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, or would change an inspection or surveillance requirement. However, the proposed amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amounts of any effluents that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure.

Accordingly, the proposed amendment meets the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22(c)(9). Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.

7. REFERENCES
1. Technical Specification Task Force (TSTF) Standard Technical Specification Change Traveler, TSTF-493, Revision 4, "Clarify Application of Setpoint Methodology for LSSS Functions."

U.S. Nuclear Regulatory Commission June 29, 2010 ATTACHMENT la McGuire Units I and 2 Technical Specification Page Markups

RTS Instrumentation 3.3.1 SURVEILLANCE REQUIREMENTS (continued) SURVEILLANCE FREQUENCY SR 3.3.1.4 ------------------ NOTES ------------------ This Surveillance must be performed on the reactor trip bypass breaker prior to placing the bypass breaker in service. Perform TADOT. 62 days on a STAGGERED TEST BASIS SR 3.3.1.5 Perform ACTUATION LOGIC TEST. 92 days on a STAGGERED TEST BASIS SR 3.3.1.6 ------------------ NOTES ------------------ Not required to be performed until 24 hours after THERMAL POWER is > 75% RTP. Calibrate excore channels to agree with incore detector 92 EFPD measurements. SR 3.3.1.7 ------------------- NOTES ------------------ Not required to be performed for source range instrumentation prior to entering MODE 3 from MODE 2 until 4 hours after entry into MODE 3. Perform COT. 184 days (continued) McGuire Units 1 and 2 3.3.1-10 Amendment Nos. 248/228

RTS Instrumentation 3.3.1 SURVEILLANCE REQUIREMENTS (continued) SURVEILLANCE FREQUENCY SR 3.3.1.9 ------------------- NOTES ------------------ Verification of setpoint is not required. Perform TADOT. 92 days SR 3.3.1.10 ------------------ NOTES ------------------ This Surveillance shall include verification that the time constants are adjusted to the prescribed values. Perform CHANNEL CALIBRATION. 18 months SR 3.3.1.11 ------------------ NOTES ------------------

1. Neutron detectors are excluded from CHANNEL CALIBRATION.
2. Power and Intermediate Range Neutron Flux detector plateau voltage verification is not required to be performed prior to entry into MODE 1 or2.

Perform CHANNEL CALIBRATION. 18 months SR 3.3.1.12 Perform CHANNEL CALIBRATION. 18 months SR 3.3.1.13 Perform COT. 18 months (continued) McGuire Units 1 and 2 3.3.1-12 Amendment Nos. 184/166

MNS TS Table 3.3.1-1 INSERTS INSERT 1 (j) If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service. (k) The instrument channel. setpoint shall be reset to a value that is within the as-left tolerance around the Nominal Trip Setpoint (NTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the NTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (field setting) to confirm channel performance. The methodologies used to determine the as-found and the as-left tolerances are specified in the UFSAR. INSERT 2 A The ->4E-1 1 amp Allowable Value, which applies to the Westinghouse-supplied compensated ion chamber Intermediate Range neutron detectors, is non-conservative. The compensated ion chamber neutron detectors are being replaced with Thermo Scientific-supplied fission chamber neutron detectors. Until the replacement occurs, an Allowable Value of > 4.8E-1 1 amp applies.

RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 1 of 7) Reactor Trip Sys ns en a on APPLICABLE MODES OR OTHER N MINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT

1. Manual Reactor Trip 1,2 2 B SR 3.3.1.14 NA NA 3 (a), 4(a), 5 (a) 2 C SR 3.3.1.14 NA NA
2. Power Range Neutron Flux
a. High 1,2 4 D SR 3.3.1.1 < 110% RTP 109% RTP SR 3.3.1.2 SR 3.3.1.7 SR 3.3.1.11 SR 3.3.1.16
b. Low 4 E SR 3.3.1.1 < 26% RTP 25% RTP SR 3.3.1.8 SR 3.3.1.11 SR 3.3.1.16
3. Power Range Neutron Flux Rate High Positive Rate 1,2 4 ýD SR 3.3.1.7 < 5.5% RTP 5% RTP SR 3.3.1'.11 with time with time constant constant
                                                                                                                 > 2 sec          .> 2 sec
4. Intermediate Range 1(b), (c) 2 F,G SR 3.3.1.1 < 30% RTP 25% RTP 2

Neutron Flux SR 3.3.1.8 SR 3.3.1.11 (d) 2 H SR 3.3.1.1 < 30% RTP 25% RTP 2 SR 3.3.1.8 SR 3.3.1.11

5. Source Range 2 (d) 2 I,J SR 3.3.1.1 < 1.3 E5 cps 1.0 E5 cps Neutron Flux SR 3.3.1.8 SR 3.3.1.11 3 (a), 4 (a), 5 (a) 2 J,K SR 3.3.1.1 < 1.3 E5 1.0 E5 SR 3.3.1.7 cps cps SR 3.3.1.11 3 (e), 4 (e), 5 (e) 1 L SR 3.3.1.1 N/A N/A SR 3.3.1.11 (continued)

(a) With Reactor Trip Breakers (RTBs) closed and Rod Control System capable of rod withdrawal. (b) Below the P-1 0 (Power Range Neutron Flux) interlocks. (c) Above the P-6 (Intermediate Range Neutron Flux) interlocks. (d) Below the P-6 (Intermediate Range Neutron Flux) interlocks. (e) With the RTBs open. In this condition, source range Function does not provide reactor trip but does provide indication. McGuire Units 1.and 2 3.3.1-14 Amendment Nos. 194/175

RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 2 of 7) I Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT

6. Overtemperature AT 1,2 4 E SR 3.3.1.1 Refer to Refer to SR 3.3.1.3 Note 1 (Page Note 1 SR 3.3.1.6 3.3.1-18) (Page, SR 3.3.1.7 3.3.1-18)

SR 3.3.1.12

  • SR 3.3.1.16 SR 3.3.1.17
7. Overpower AT 1,2 4 E SR 3.3.1.1 Refer to Refer to SR 3.3.1.3 Note 2 (Page Note 2 SR 3.3.1.6 3.3.1-19) (Page SR 3.3.1.7 3.3.1-19)

SR 3.3.1.12 SR 3.3.1.16 SR 3.3.1.17 Pressurizer Pressure

a. Low 1(f) 4 M 1945 psig
b. High 1,2 4 E 2385 psig
9. Pressurizer Water l(0) 3 M 92%

Level - High

10. Reactor Coolant Flow -
                                                                                                                        )        "

Low

a. Single Loop 1 (g) 3 per loop N 88%
b. Two Loops 1 (h) 3 per loop sR 3.3.1.7  ? 88%

M SR3.3.1.1 SR 3 .3.1 

                                                                                          .3.1.106
                                                                                               .16ot
11. Undervoltage RCPs 1 (f) 1 per bus M SR 3.3.1.9 > 5016 V 5082 V SR 3.3.1.10 SR 3.3.1.16 (continued)

(f) Above the P-7 (Low Power Reactor Trips Block) interlock. (g) Above the P-8 (Power Range Neutron Flux) interlock. (h) Above the P-7 (Low Power Reactor Trips Block) interlock and below the P-8 (Power Range Neutron Flux) interlock. 3.3,1-15 Amendment Nos. 22224

RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 3 of 7) Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT

12. Underfrequency 1(0 1 per bus M ;SR 3.3.1.9 >5&.-9Hz 56.4 Hz RCPs SR 3 3:.3.

1.1054 SR 3.3.1.16

13. Steam Generator 1,2 4 per SG E R3.3.1.1>4&/ 167 (SG) Water Level - SR 3.3.1.7 X 16.7 Low Low SIR 3.3.1.16
14. Turbine Trip
a. Low Fluid Oil 1 (g) 3 O SR 3.3.1.10 > 42 psig 45 psig Pressure SR 3.3.1.15
b. Turbine Stop 1 (g) 4 P . SR 3.3.1.10 > 1% open > 1% open Valve Closure SR 3.3.1.15
15. Safety Injection (SI) 1,2 2 trains Q SR 3.3.1.5 NA NA Input from Engineered SR 3.3.1.14 Safety Feature Actuation System (ESFAS)
16. Reactor Trip System Interlocks
a. Intermediate 2 (d) 2 S SR 3.3.1.11 > 4E-11E-1 0 amp Range Neutron SR 3.3.1.13 . D Flux, P-6
b. Low Power 1 per train T SR 3.3.1.5 NA NA Reactor Trips Block, P-7
c. Power Range 1 4 T . SR 3.3.1.11 < 49% RTP 48% RTP Neutron Flux, SR 3.3.1.13 P-8
d. Power Range 1,2 4 S SR 3.3.1.11 > 7% RTP 10% RTP Neutron Flux, SR 3.3.1.13 and < 11%

P-1 0 RRT

e. Turbine Impulse 2 T SR 3.3.1.12 < W1 turbine 10%

Pressure, P-13 SR 3.3.1.13 impulse turbine pressure impulse Dequivalent pressure equivalent (continued) (d) Below the P-6 (Intermediate Range Neutron Flux) interlocks. (0 Above the P-7 (Low Power Reactor Trips Block) interlock. e 8 (Power Range Neutron Flux) interlock. C UI nd2 3.3.1-16 Amendment Nos. 494/+75 b~JsER-Z'

RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 4 of 7) Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT

17. Reactor Trip 1,2 2 trains R, V SR 3.3.1.4 NA NA Breakerst ') 3 (a), 4 (a), 5 (a) 2 trains C SR 3.3.1.4 NA NA
18. Reactor Trip Breaker 1,2 1 each per U SR 3.3.1.4 NA NA Undervoltage and RTB Shunt Trip Mechanisms 3 (a), 4 (a), 5 (a) 1 each per C SR 3.3.1.4 NA NA RTB
19. Automatic Trip Logic 1,2 2 trains Q, V SR 3.3.1.5 NA NA 3 (a), 4 (a), 5 (a) 2 trains C SR 3.3.1.5 NA NA (a) With RTBs closed and Rod Control System capable of rod withdrawal.

(i) Including any reactor trip bypass breakers that are racked in and closed for bypassing an RTB. McGuire Units 1 and 2. 3.3.1-17 Amendment Nos. 194/175

ESFAS Instrumentation 3.3.2 SURVEILLANCE REQUIREMENTS

NOTE---------------------------------

Refer to Table 3.3.2-1 to determine which SRs apply for each ESFAS Function. SURVEILLANCE FREQUENCY SR 3.3.2.1 Perform CHANNEL CHECK. 12 hours SR 3.3.2.2 Perform ACTUATION LOGIC TEST. 92 days on a STAGGERED TEST BASIS SR 3.3.2.3 Perform COT. 31 days SR 3.3.2.4 Perform MASTER RELAY TEST. 92 days on a STAGGERED TEST BASIS SR 3.3.2.5 Perform COT. 184 days SR 3.3.2.6 Perform SLAVE RELAY TEST. 92 days SR 3.3.2.7 -------------------- NOTE ----------------- Verification of setpoint not required for manual initiation functions. Perform TADOT. 18 months (continued) McGuire Units 1 and 2 3.3.2-8 Amendment Nos., 250/230

ESFAS Instrumentation 3.3.2 SURVEILLANCE REQUIREMENTS (continued) SURVEILLANCE FREQUENCY SR 3.3.2.8 ------------------- NOTE ------------------ This Surveillance shall include verification that the time constants are adjusted to the prescribed values. Perform CHANNEL CALIBRATION. 18 months SR 3.3.2.9 ------------------- NOTE ------------------ Not required to be performed for the turbine driven AFW pump until 24 hours after SG pressure is > 900 psig. Verify ESFAS RESPONSE TIMES are within limit. 18 months on a STAGGERED TEST BASIS McGuire Units 1 and 2 3.3.2-9 Amendment Nos. 184/166

MNS TS Table 3.3.2-1 INSERTS INSERT 1 (f) If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service. (g) The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Nominal Trip Setpoint (NTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the NTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (field setting) to confirm channel performance. The methodologies used to determine the as-found and the as-left tolerances are specified in the UFSAR.

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 1 of 5) Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT 1 Safety Injection

a. Manual Initiation 1,2,3,4 B SR 3.3.2.7 NA NA
b. Automatic 1,2,3,4 2 trains C SR 3.3.2.2 NA Actuation Logic SR 3.3.2.4 and Actuation SR 3.3.2.6 Relays
c. Containment 1,2,3 3 D SR 3.3.2.1 < 1.2 psig 1.11IPsig Pressure - High SR 3.3.2.5 SR 3.3.2.80
d. Pressurizer 4 D SR 3.3.25 1-84psig 1845psig Pressure - Low Low
2. Containment Spray
a. Manual Initiation 1,2,3,4 1 per train, B SR 3.3.2.7 NA NA 2 trains
b. Automatic 1,2,3,4 2 trains C SR 3.3.2.2 NA NA Actuation Logic SR 3.3.2.4 and Actuation SR 3.3.2.6 Relays
c. Containment 1,2,3 4 E SR 3.3.2.1 < 3.0 psig 2.9 Ipsig Pressure - High SR 3.3.2.5 High SR 3.3.2.8 SR 3.3.2.9
3. Containment Isolation
a. Phase A Isolation (1) Manual 1,2,3,4 2 B SR 3.3.2.7 NA NA Initiation (2) Automatic 1,2,3,4 2 trains C SR 3.3.2.2 NA NA Actuation SR 3.3.2.4 Logic and SR 3.3.2.6 Actuation Relays (continued)

(a) Above the P-1 1 (Pressurizer Pressure) interlock. Gir its and 2 3.3.2-10 Amendment Nos.,222/922

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 2 of 5) Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT

3. Containment Isolation (continued)

(3) Safety Refer to Function 1 (Safety Injection) for all initiation functions and requirements. Injection

b. Phase B Isolation (1) Manual Initiation 1,2,3,4 1 per train, B SR 3.3.2.7 NA NA 2 trains (2) Automatic 1,2,3,4 2 trains C SR 3.3.2.2 NA NA Actuation SR 3.3.2.4 Logic and SR 3.3.2.6 Actuation Relays (3) Containment- 1,2,3 4 E SR 3.3.2.1 < 3.0 psig . 2.9 psig Pressure - SR 3.3.2.5 High High SR 3.3.2.8
4. Steam Line Isolation
a. Manual Initiation (1) System 1,2 (b), 3 (b) 2 trains F SR 3.3.2.7 NA NA (2) Individual' 1,2 (b), 3 (b) 1 per line G SR 3.3.2.7 NA NA
b. Automatic (b), 3 (b) 2 trains H SR 3.3.2.2 NA NA 1 ,2 Actuation Logic SR 3.3.2.4 and Actuation. SR 3.3.2.6 Relays
c. Containment 112(b), 3(b) 4 E SR 3.3.2.1 < 3.0 2.9 psig Pressure - High SR 3.3.2.5 psig High SR 3.3.2.8 SR 3.3.2.9
d. Steam Line Pressure (1) Low 1, 2 (b), (a)(b) 3 per steam D 775 psig 3

line (continued) (a) Above the P-11 (Pressurizer Pressure) interlock. (b) Except when all MSIVs are closed and de-activated. c ui e UnI s 1 and 2 3.3.2-11 Amendment Nos. .

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 3 of 5) Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT

4. Steam Line Isolation (continued)

(2) Negative 3 (b)(c) 3 per steam D SR3322N (d) psi 100 Rate - High line

5. Turbine Trip and Feedwater Isolation
a. Turbine Trip (1) Automatic 1,2 2 trains I SR 3.3.2.2 NA NA Actuation SR 3.3.2.4 Logic and SR 3.3.2.6 Actuation Relays (2) SG Water 1,2 3 per SG 83.9%

Level-High High (P-14) (3) Safety Refer to Function 1 (Safety Injection) for all initiation functions and requirements. See item Injection 5.a.(1) for Applicable MODES.

b. Feedwater Isolation (1) Automatic 1 ,2 (e), 3 (e) 2 trains H SR 3.3.2.2 NA NA Actuation SR 3.3.2.4 Logic and SR 3.3.2.6 Actuation Relays D SR 3.3.2.1 < &S-6 83.9%

(2) SG Water 1 ,2 (e), 3 (e) 3 per SG Level-High SR 3.3.2.2 High (P-14) SIR 3.3.2.4 af.o SR 3.3.2.51 ' SR 3.3.2.6 SIR 3.3.2.8 SR 3.3.2.9 (continued) (b) Except when all MSIVs are closed and de-activated. (c) Trip function automatically blocked above P-11 (Pressurizer Pressure) interlock and may be blocked below P-11 when Steam Line Isolation Steam Line Pressure-Low is not blocked. (d) Time constant utilized in the rate/lag controller is > 50 seconds. (e) Except when all MFIVs, MFCVs, and associated bypass valves are closed and de-activated or isolated by a closed manual valve. McGuire Uni s 1 and 2 3.3.2-12 Amendment Nos. 224Q,296-

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 4 of 5) Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT

5. Turbine Trip and Feedwater Isolation (continued)

(3) Safety Refer to Function 1 (Safety Injection) for all initiation functions and re uirements. See Ite Injection 5.b.(1) for Applicable MODES. (4) Tavg-Low 1,2(e) 1 per loop J SR 3.3.2.1 X! > 5°F 553*F SR 3.3.2 .5(f( SR 3...ý)J coincident with Refer to Function 8.a (Reactor Trip, P-4) for all initiation functions and Reactor Trip, P-4 requirements. (5) Doghouse 2 per train L,M SR 3.3.2.1 < 13 inches 12 inches Water Level- per SR 3.3.2.7 High High Doghouse

6. Auxiliary Feedwater
a. Automatic 1,2,3 2 trains H SR 3.3.2.2 NA NA Actuation Logic SR 3.3.2.4 and Actuation SR 3.3.2.6 Relays
b. SG Water Level - 1,2,3 4 per SG D 16.7%

Low Low

c. Safety Injection Refer to Function 1 (Safety Injection) for all initiation functions and requirements.
d. Station Blackout (1) Loss of 1,2,3 3 per bus D SR 3.3.2.7 > 3122 V 3174 V voltage SR 3.3.2.9 (Unit 1) (Unit 1)
                                                                                                                    > 3108 V          3157 V (Unit 2) with     (Unit 2) +/-

8.5 +/- 0.5 sec 45 V with time delay 8.5 +/- 0.5 sec time delay (2) Degraded 1,2,3 3 per bus D SR 3.3.2.7 > 3661 V 3678.5 V Voltage SR 3.3.2.9 (Unit 1) (Unit 1) 

                                                                                                                  > 3685.5 V          3703 V (Unit 2)         (Unit 2) with < 11 sec       with < 11 with SI and      sec with SI
                                                                                                                   < 600 sec        and < 600 without SI      sec without time delay         SI time delay (continued)

(e) Except when all MFIVs, MFCVs, and associated bypass valves are closed and de-activated or isolated by a closed manual Units 1 and 2 3.3.2-13 Amendment Nos.22-2--

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 5 of 5) Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT

6. Auxiliary Feedwater (continued)
e. Trip of all Main 1,2 1 per MFW K SR 3.3.2.7 NA NA Feedwater pump SR 3.3.2.9 Pumps
f. Auxiliary 1,2,3 2 per MDP, N,O SR 3.3.2.7 > 3 psig 3.5 psig Feedwater Pump 4 per TDP SR 3.3.2.8 Suction Transfer SR 3.32.9 on Suction Pressure - Low
7. Automatic Switchover to Containment Sump
a. Refueling Water 1,2,3 3 P,S SR 3.3.2.1 > 175.85 180 inches Storage Tank SR 3.3.2.3 inches (RWST) Level - SR 3.3.2.8 Low SR 3.3.2.9 Coincident with Refer to Function 1 (Safety Injection) for all initiation functions and requirements.

Safety Injection

8. ESFAS Interlocks
a. Reactor Trip, 1,2,3 1 per train, F SR 3.3.2.7 NA NA
           'P-4                                         2 trains
b. Pressurizer 1,2,3 3 Q SR 3.3.2.5 < >Q,6-psig 1955 psig Pressure, P-11 SIR 3.3.2.8 0
c. Tavg - Low Low, 1,2,3 1 per loop Q SR 3.3.2.5 > 5&1F 553'F P-12 SR 3.3.2.8
9. Containment 1,2,3,4 4 per train, R SR 3.3.2.1 Refer to Note Refer to Note Pressure Control 2 trains SR 3.3.2.3. 1 on Page 1 on page System SR 3.3.2.8 3.3.2-14 3.3.2-14 NOTE 1: The Trip Setpoint for the Containment Pressure Control System start permissive/termination (SP/T) shall be > 0.3 psig and < 0.4 psig. The allowable value for the SP/T shall be > 0.25 psig and < 0.45 psig.

McGuire Units 1 and 2 3.3.2-14 Amendment Nos. 22-0e

U.S. Nuclear Regulatory Commission June 29, 2010 ATTACHMENT lb Catawba Units I and 2 Technical Specification Page Markups

RTS Instrumentation 3.3.1 SURVEILLANCE REQUIREMENTS (continued) SURVEILLANCE FREQUENCY SR 3.3.1.4 --------------------- NOTE----------------- This Surveillance must be performed on the reactor trip bypass breaker prior to placing the bypass breaker in service. Perform TADOT. 62 days on a STAGGERED TEST BASIS* SR 3.3.1.5 Perform ACTUATION LOGIC TEST. 92 days on a STAGGERED TEST BASIS SR 3.3.1.6 --------------------- NOTE----------------- Not required to be performed until 24 hours after THERMAL POWER is > 75% RTP. Calibrate excore channels to agree with incore detector 92 EFPD measurements. SR 3.3.1.7 --------------------- NOTE----------------- Not required to be performed for source range instrumentation prior to entering MODE 3 from MODE 2 until 4 hours after entry into MODE 3. Perform COT. 184 days (continued)

  • The SR 3.3.1.4 Frequency of "62 days on a STAGGERED TEST BASIS" as it applies to Unit 2 Train 2A and Train 2B reactor trip breaker testing may be extended on a one-time basis to March 10, 2009 at 0500 hours, upon which Unit 2 shall be in Mode 3 with reactor trip breakers open for the End of Cycle 16 Refueling Outage. Upon entry into Mode 3 with reactor trip breakers open for this refueling outage, this extension shall expire. The provisions of SR 3.0.2 are not applicable to this extension.

(\l 0 C ca~je~J Pa~j4 ,o'-v'c~) c4t Catawba Units 1 and 2 3.3.1-10 Amendment Nos. 248/242

RTS Instrumentation 3.3.1 SURVEILLANCE REQUIREMENTS (continued) SURVEILLANCE FREQUENCY SR 3.3.1.8 ------------------- NOTE ----------------- This Surveillance shall include verification that interlocks P-6 (for the Intermediate Range channels) and P-10 (for the Power Range channels) are in their required state for existing unit conditions. Perform COT .-------- NOTE------- Only required when not performed within previous 184 days Prior to reactor startup AND Four hours after reducing power below P-10 for power and intermediate range instrumentation AND Four hours after reducing power below P-6 for source range instrumentation AND Every 184 days thereafter (continued) Catawba Units 1 and 2 3.3.1-11 Amendment Nos. 247/240

RTS Instrumentation 3.3.1 SURVEILLANCE REQUIREMENTS (continued) SURVEILLANCE FREQUENCY SR 3.3.1.9 --------------------- NOTE ----------------- Verification of setpoint is not required. Perform TADOT. 92 days SR 3.3.1.10 -------------------- NOTE ----------------- This Surveillance shall include verification that the time constants are adjusted to the prescribed values. Perform CHANNEL CALIBRATION. 18 months SR 3.3.1.11 -------------------- NOTE -----------------

1. Neutron detectors are excluded from CHANNEL CALIBRATION.
2. Power and Intermediate Range Neutron Flux detector plateau voltage verification is not required to be performed prior to entry into MODE 1 or2.

Perform CHANNEL CALIBRATION. 18 months SR 3.3.1.12 Perform CHANNEL CALIBRATION. 18 months SR 3.3.1.13 Perform COT. 18 months (continued) Catawba Units 1 and 2 3.3.1-12 Amendment Nos. 173/165

CNS TS Table 3.3.1-1 INSERTS INSERT 1 (I) If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service. (m) The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Nominal Trip Setpoint (NTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the NTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (field setting) to confirm channel performance. The methodologies used to determine the as-found and the as-left tolerances are specified in the UFSAR. INSERT 2 A The > 6E-1 1 amp Allowable Value, which applies to the Westinghouse-supplied compensated ion chamber Intermediate Range neutron detectors, is non-conservative. The compensated ion chamber neutron detectors are being replaced with Thermo Scientific-supplied fission chamber neutron detectors. Until the replacement occurs, an Allowable Value of > 6.9E-1 1 amp applies.

RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 1 of 7) Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT

1. Manual Reactor Trip 1,2 2 B SR 3.3.1.14 NA NA 3 (a), 4 (a), 5 (a) 2 C . SR 3.3.1.14 NA NA
2. Power Range Neutron Flux
a. High 1,2 D 109% RTP
b. Low 4 E 25% RTP
3. Power Range Neutron Flux High Positive Rate 1.2 4 D SR 3.3.1.7 < 6.3% RTP 5% RTP SR 3.3.1.11 with time with time constant constant
                                                                                                               > 2 sec          >_2 sec
4. Intermediate Range 1(b), (c) 2 F,G SR 3.3.1.1 *31% RTP 25% RTP 2

Neutron Flux SR 3.3.1.8 SR 33.1.11 2 (d) 2 H SR 3.3.1.1 < 31% RTP 25% RTP SR 3.3.1.8 SR 3.3.1.11

5. Source Range 2 (d) 2 I,J SR 3.3.1.1 *< 1.4 E5 cps 1.0 E5 cps Neutron Flux SR 3.3.1.8 SR 3.3.1.11 3 (a), 4 (a), 5 (a) 2 J,K SIR 3.3.1.1
  • 1.4 E5 1.0 E5 cps SIR 3.3.1.7 cps SIR 3.3. 1.11
6. Overtemperature AT 1,2 4 E SRF3.3.1.1 Refer to Refer to SR 3.3.1.3 Note 1 (Page Note 1 (Page SI3.3.1-18) 3.3.1-18)

SIR 3.3.1.16 SIR 3.3.1.17 (continued) (a) With Reactor Trip Breakers (RTBs) closed and Rod Control System capable of rod withdrawal. (b) Below the P-10 (Power Range Neutron Flux) interlocks. (c) Above the P-6 (Intermediate Range Neutron Flux) interlocks. (d) Below the P-6 (Intermediate Range Neutron Flux) interlocks. a 3.3.1-14 Amendment Nos. +79M-71

RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 2 of 7) Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT

7. Overpower AT 1,2 4 E SR 3.3.1.1 Refer to Refer to SR 3.3.1.3 Note 2 (Page Note 2 SR 3.3.1.6 3.3.1-19) (Page SR 3.3.1.7 3.3.1-19)

SR 3.3.1.10 SR 3.3.1.16 SR 3.3.1.17

8. Pressurizer Pressure
a. Low 1 (e) 4 L SR 3.3.1.1 a3.3. 1.7 SSR (ltX.v*)

14M(f) psig 1945(f)0 psig SR 3.31110(f)C/* SR 3.3.1.16 Z3

b. High 1,2 4 ESR 3.3.1.1 S2-399 psig 2385 psig I SR 3.3.1.7 ( ) '

SR 3.3.1.10" ) SR 3.3.1.16 9Z. 7 9-3Z -7

9. Pressurizer Water 1 (e) 3 L SR 3.311A1 92%

Level - High SR 3.3.1.7 (6)&-i) SR 3.3.1.10

10. Reactor Coolant Flow - Low 1701
a. Single Loop 1 (g) 3 per loop M SR 3.3.1.1 91% 1 SR 3.3.1.7 SR 3.3.1+10 (J/'

SR 3.3.1.16 1_-0..7S" 90..

b. Two Loops l(h) 3 per loop L SR 3.3.1.1 91% 1 SR 3.3.1.7 ()(

SR 3.3. 1.10 ' SR 3.3.1.16 (e) Above the P-7 (Low Power Reactor Trips Block) interlock. (f) Time constants utilized in the lead-lag controller for Pressurizer Pressure - Low are 2 seconds for lead and I second for lag. (g) Above the P-8 (Power Range Neutron Flux) interlock. (h) Above the P-7 (Low Power Reactor Trips Block) interlock and below the P-8 (Power Range Neutron Flux) interlock. 1,jSE l Catawba Units 1 and 2 3.3.1-15 Amendment Nos. +79M--1

RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 3 of 7) Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT

11. Undervoltage RCPs 1 (e) 1 per bus L SR 3.3.1.9 _5016 V 5082 V 3.3.1.10 31,, *-,SR 3.1
12. Underfrequency l(e) 1 per bus L S3.31.9 )(1t SIR A '2!&&.gHz 56.4 Hz RCPs
13. Steam Generator 1,2 4 per SG E (Unit 1) 10.7%

(SG) Water Level - Low Low SR 3.31.10 (Unit2) of 36.8% SR 3.3.1.16 narrow range Unit 2) of span narrow ange span

14. Turbine Trip
a. Stop Valve EH 10) 4 N SR 3.3.1.10 _>500 psig 550 psig Pressure Low SR 3.3.1.15
b. Turbine Stop 10) 4 0 SR 3.3.1.10 >_1% open NA Valve Closure SR 3.3.1.15
15. Safety Injection (SI) 1,2 2 trains P SR 3.3.1.5 NA NA Input from SR 3.3.1.14 Engineered Safety Feature Actuation System (ESFAS)

(e) Above the P-7 (Low Power Reactor Trips Block) interlock. (i) Not used. () Above the P-9 (Power Range Neutron Flux) interlock. Catawba Units 1 and 2 3.3.1-16 Amendment Nos. t-19-7"1

RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 4 of 7) Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT

16. Reactor Trip System Interlocks
a. Intermediate 2 (d) 2 R SR 3.3.1.11 Ž 6E-11amp lE-10 amp Range Neutron SR 3.3.1.13 Flux, P-6
b. Low Power 1 per train S SR 3.3.1.5 NA NA Reactor Trips Block, P-7
c. Power Range 4 S SR 3.3.1.11 *<50.2% RTP 48%RTP Neutron Flux, SR 3.3.1.13 P-8
d. Power Range 4 S SR 3.3.1.11 < 70% RTP 69% RTP Neutron Flux, SR 3.3.1.13 P-9
e. Power Range 1,2 1 4 R SR 3.3.1.11 _>7.8% RTP 10% RTP Neutron Flux, SR 3.3.1.13 and < 12.2%

P-10 P

f. Turbine 2 S SR 3.3.1.12 _1-2-% RTP 10% RTP Impulse SR 3.3.1.13 turbine turbine Pressure, P-13 impulse impulse pressure pressure 0equivalentp equivalent
17. Reactor Trip 1,2 2 trains CQU SR 3.3.1.4 NA NA Breakers(k) 3 (a), 4 (a) 5 (a) 2 trains C SR 3.3.1.4 NA NA
18. Reactor Trip Breaker 1,2 1 each per T SR 3.3.1.4 NA NA Undervoltage and RTB Shunt Trip Mechanisms 3 (a), 4 (a), 5 (a) 1 each per C SR 3.3.1.4 NA NA RTB
19. Automatic Trip Logic 1,2 2 trains P,U SR 3.3.1.5 NA NA 3 (a), 4 (a), 5 (a) 2 trains C SR 3.3.1.5 NA NA (continued)

(a) With RTBs closed and Rod Control System capable of rod withdrawal. (d) Below the P-6 (Intermediate Range Neutron Flux) interlocks. (k) Including any reactor trip bypass breakers that are racked in and closed for bypassing an RTB. Catawba Units 1 and 2 3.3.1-17 Amendment Nos. 1-Wý

RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 5 of 7) Reactor Trip System Instrumentation Note 1: Overtemperature AT The Overtemperature AT Function Allowable Value shall not exceed the following NOMINAL TRIP SETPOINT by more tha erre4*,i (Unlt 2f RTP. (1+ r1 s) 1 " S) T -T' +K3 (P - P') - f, (A/) 

        +T' 2 S     +C3 S   )    AT     K -  K2   (1 (1+ 4'r5 s) 0A            (1+1-,s) 6       I)

Where: AT is the measured RCS AT by loop narrow range RTDs, OF. AT0 is the indicated AT at RTP, OF. s is the Laplace transform operator, sec 1 . T is the measured RCS average temperature, OF. T is the nominal Tavg at RTP (allowed by Safety Analysis), < the values specified in the COLR. P is the measured pressurizer pressure, psig P is the nominal RCS operating pressure, = the value specified in the COLR K1 = Overtemperature AT reactor NOMINAL TRIP SETPOINT, as presented in the COLR, K2 = Overtemperature AT reactor trip heatup setpoint penalty coefficient, as presented in the COLR, K3 , = Overtemperature AT reactor trip depressurization setpoint penalty coefficient, as presented in the COLR, 

        ' 11, "r 2 = Time constants utilized in the lead-lag compensator for AT, as presented in the COLR, 13       = Time constant utilized in the lag compensator for AT, as presented in the COLR, 1 4, 1 5 =   Time constants utilized in the lead-lag compensator for Tavg, as presented in the COLR, T6e      = Time constant utilized in the measured Tavg lag compensator, as presented in the COLR, and f1 (AI) = a function of the indicated difference between top and bottom detectors of' the power-range neutron ion chambers; with gains to be selected based on measured instrument response during plant startup tests such that:

(i) for qt - qb between the "positive" and "negative" fl(AI) breakpoints as presented in the COLR; fl(Al) = 0, where qt and qb are percent RATED THERMAL POWER in the top and bottom halves of the core respectively, and qt + qb is total THERMAL POWER in percent of RATED THERMAL POWER; (ii) for each percent Al that the magnitude of qt - qb is more negative than the f1 (AI) "negative" breakpoint presented in the COLR, the AT Trip Setpoint shall be automatically reduced by the fl(AI) "negative" slope presented in the COLR; and (continued) Catawba Units 1 and 2 3.3..1-118 Amendment Nos. -240t244-

RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 6 of 7) Reactor Trip System Instrumentation (iii) for each percent Al that the magnitude of qt - qb is more positive than the fl(AI) "positive" breakpoint presented in the COLR, the AT Trip Setpoint shall be automatically reduced by the fl(Al) "positive" slope presented in the COLR. KJO0C, ,t1,0S -4 -(-4i Note 2:- Overpower AT Pqej pov~dA ý 4-The Overpower AT Function Allowable Value shall not exceed the following NOMINAL TRIP SETPOINT by more than 2.6% (Unit 1) and 3.1% (Unit 2) of RTP. AT( (1+ - s) 

           +.r 2  S) l+-3s 1    AT0 K       1+rzS 1

( 1 +A6 s T- K6 FT LK 1 T - f2 (A) Where: AT is the measured RCS AT by loop narrow range RTDs, °F. ATo is the indicated AT at RTP, OF. s is the Laplace transform operator, sec>. T is the measured RCS average temperature, OF. T is the nominal Tavg at RTP (calibration temperature for AT instrumentation), 

         < the values specified in the COLR.

K4 = Overpower AT reactor NOMINAL TRIP SETPOINT as presented in the COLR, K5 = the value specified in the COLR for increasing average temperature and the value specified in the COLR for decreasing average temperature, K6 = Overpower AT reactor trip heatup setpoint penalty coefficient as presented in the COLR for T > T and K6 = the value specified in the COLR for T < T, T1 , t 2 = Time constants utilized in the lead-lag compensator for AT, as presented in the COLR, 13 = Time constant utilized in the lag compensator for AT, as presented in the COLR, T6 = Time constant utilized in the measured Tavg lag compensator, as presented in the COLR, T*7 = Time constant utilized in the rate-lag controller for Tavg, as presented in the COLR, and f2(AI) = a function of the indicated difference between top and bottom detectors of the power-range neutron ion chambers; with gains to be selected based on measured instrument response during plant startup tests such that: (i) for qt - qb between the "positive" and "negative" f 2(AI) breakpoints as presented in the COLR; f2(AI) = 0, where qt and qb are percent RATED THERMAL POWER in the top and bottom halves of the core respectively, and qt + qb is total THERMAL POWER in percent of RATED THERMAL POWER; (continued) Catawba Units 1 and 2 3.3.1-19 Amendment Nos. 210/204

ESFAS Instrumentation 3.3.2 SURVEILLANCE REQUIREMENTS 

                                           -NOTE-Refer to Table 3.3.2-1 to determine which SRs apply for each ESFAS Function.

SURVEILLANCE FREQUENCY SR 3.3.2.1 Perform CHANNEL CHECK. 12 hours SR 3.3.2.2 Perform ACTUATION LOGIC TEST. 92 days on a STAGGERED TEST BASIS SR 3.3.2.3 --------------------- NOTE ----------------- Final actuation of pumps or valves not required. Perform TADOT. 31 days SR 3.3.2.4 Perform MASTER RELAY TEST. 92 days on a STAGGERED TEST BASIS SR 3.3.2.5 Perform COT. 184 days SR 3.3.2.6 Perform SLAVE RELAY TEST. 92 days OR 18 months for only Westinghouse AR and Potter & Brumfield MDR relay types SR 3.3.2.7 Perform COT. 31 days (continued) 

  ý%jo                  -4          S      d<

Catawba Units 1 and 2 3.3.2-10 Amendment Nos. 249/243

ESFAS Instrumentation 3.3.2 SURVEILLANCE FREQUENCY SR 3.3.2.8 --------------------- NOTE ------------------ Verification of setpoint not required for manual initiation functions. Perform TADOT. 18 months SR 3.3.2.9 --------------------- NOTE ----------------- This Surveillance shall include verification that the time constants are adjusted to the prescribed values. Perform CHANNEL CALIBRATION. 18 months SR 3.3.2.10 -------------------- NOTE ----------------- Not required to be performed for the turbine driven AFW pump until 24 hours after SG pressure is > 600 psig. Verify ESFAS RESPONSE TIMES are within limit. 18 months on a STAGGERED TEST BASIS SR 3.3.2.11 Perform COT. 18 months SR 3.3.2.12 Perform ACTUATION LOGIC TEST. 18 months NJ I/J Per Cý-, Catawba Units 1 and 2 3.3.2-11 Amendment Nos. 249/243

CNS TS Table 3.3.2-1 INSERTS INSERT 1 (f) If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service. (g) The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Nominal Trip Setpoint (NTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the NTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (field setting) to confirm channel performance. The methodologies used to determine the as-found and the as-left tolerances are specified in the UFSAR.

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 1 of 5) Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT Safety Injection(b)

a. Manual initiation 1,2,3,4 2 B SR 3.3.2.8 NA NA
b. Automatic 1,2,3,4 2 trains C SR 3.3.2.2 NA NA Actuation Logic S R 3.3.2.4 and Actuation Relays
c. Containment 1,2,3 3 D SR 3.3.2.1 psig 1.2 psig Pressure - High SR 3.3.2.10
d. Pressurizer (a) 4 D SR 3.3.2.1 > 1489Q-psig 1845 psig 1 ,2 ,3 ' SR 3.3.2.5 07)-(.J*

Pressure - Low SR 3.3.2.9 c-P)(3) SR 3.3.2.10

2. Containment Spray
a. Manual Initiation 1,2,3,4 1 per train, B SR 3.3.2.8 NA NA 2 trains
b. Automatic 1,2,3,4 2 trains C SR 3.3.2.2 NA NA Actuation Logic SR 3.3.2.4 and Actuation SR 3.3.2.6 Relays
c. Containment 1,2,3 4 E .SR 3.3.2.1 _<3.2 psig 3.0 psig Pressure SR 3.3.2.5 High High SR 3.3.2.9 SR 3.3.2.10
3. Containment Isolation(b)
a. Phase A Isolation (1) Manual 1,2,3,4 2 B SR 3.3.2.8 NA NA Initiation (2) Automatic 1,2,3,4 2 trains C SR 3.3.2.2 NA NA Actuation SR 3.3.2.4 Logic and SR 3.3.2.6 Actuation Relays (3) Safety Refer to Function 1 (Safety Injection) for all initiation functions and requirements.

Injection (continued) (a) Above the P-1I (Pressurizer Pressure) interlock. (b) The requirements of this Function are not applicable to Containment Purge Ventilation System and Hydrogen Purge System components, since the system containment isolation valves are sealed closed in MODES 1, 2, 3, and 4. Catawba Units 1 and 2 3.3.2-12 Amendment Nos. 24-ý 

   )Akt             J        I

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 2 of 5) Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT

3. Containment Isolation (continued)
b. Phase B Isolation (1) Manual Initiation 1,2,3,4 1 per train, B SR 3.3.2.8 NA NA 2 trains (2) Automatic 1,2,3,4 2 trains C SR 3.3.2.2 NA NA SR 3.3.2.4 Actuation Logic and SR 3.3.2.6 Actuation Relays (3) Containment 1,2,3 4 E 3.0 psig Pressure -

High High

4. Steam Line Isolation
a. Manual Initiation (1) System 2 trains F SR 3.3.2.8 NA NA (2) Individual 1,2 (b), 3 (b) 1 per line G SR 3.3.2.8 NA NA
b. Automatic 2 trains H SR 3.3.2.2 NA NA Actuation Logic SR 3.3.2.4 and Actuation SR 3.3.2.6 Relays
c. Containment 4 E 3.0 psig 1,2(b),3(b)

Pressure - High High

d. Steam Line Pressure (1) Low 1,2 (b), 3 (a)(b) 3 per steam D 775 psig line (continued)

(a)Above the P-11 (Pressurizer Pressure) interlock. Uall MSIVs are closed and de-activated. d2 3.3.2-13 Amendment Nos. -249/24-3

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 3 of 5) Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT

4. Steam Line Isolation (continued)

(2) Negative 3 (b)(c) 3 perline steam D 10 0 (d) psi Rate - High

5. Turbine Trip and Feedwater Isolation
a. Turbine Trip (1) Automatic 1,2 2 trains I SR 3.3.2.2 NA NA Actuation SR 3.3.2.4 Logic and SR 3.3.2.6 Actuation Relays (2) SG Water 1,2 4 per SG J SR 3.3.2.1 *_ 8i5-6% 83.9%

Level- SR 3.3.2.2 (Unit 1) Unit 1) High-High SR 3.3.2.4 . 7.1% (P-14) SR 3.3.2.5+'** ) (Unit 2) Unit 2) SR 3.3.2.6 f )(3 SR 3.3.2.94 *')(J, * (3) Safety Refer to Function 1 (Safety Injection) for all initiation functions and requirements. See Injection Item 5.a.(1) for Applicable MODES.

b. Feedwater Isolation (1) Automatic 1,2(e),3(e) 2 trains H SR 3.3.2.2 NA NA Actuation SR 3.3.2.4 Logic and SR 3.3.2.6 Actuation Relays (continued)

(b) Except when all MSIVs are closed and de-activated. (c) Trip function automatically blocked above P-11 (Pressurizer Pressure) interlock and may be blocked below P-11 when Steam Line Isolation Steam Line Pressure - Low is not blocked. (d) Time constant utilized in the rate/lag controller is > 50 seconds. (e) Except when all MFIVs, MFCVs, and associated bypass valves are closed and de-activated or isolated by a closed manual valve. I--- t~r Catawba Units 1 and 2 3.3.2-14 Amendment Nos. 24 ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 4 of 5) Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT (2) SG Water 4 per SG D SR 3.3.2.1 <5 '4-.6, 8&-G 83.9% SR':3.3.2.2 (Unit 1) Unit 1) Level- High High (P-14) SIR 3.3.2.4 ... <7.&o 77,8 77.1% SR 3.3.2.5(r"),., (Unit 2) nit 2) SIR 3.3.269") SR 3.3.2.10 (3) Safety Refer to Function 1 (Safety Injection) for all initiation functions and requirements. Se Injection Item 5.b.(1) for Applicable MODES. (4) Tavg-Low ,2 4 J SR 3.3.2.1 5641F e564F SR 3.3 2 5 SR 3... j ) coincident with Refer to Function 8.a (Reactor Trip, P-4) for all initiation functions and requirements. Reactor Trip, P-4 (5) Doghouse (1/1 logic) L (1/1 logic) < 12 inches 11 inches WaterLevel - 2 per SR 3.3.2.8 above 577 ft above 577 High High doghouse floor level ft floor level (2/3 logic) (2/3 logic) 3 per train SR 3.3.2.8 per SR 3.3.2.9 doghouse SR 3.3.2.12

6. Auxiliary Feedwater
a. Automatic 1,2,3 2 trains H SR 3.3.2.2 NA NA Actuation Logic SR 3.3.2.4 and Actuation SR 3.3.2.6 Relays to
b. SG Water Level 1,2,3 4perSG D L SR 3.3.2.1 ," > 010.7%
             - LowLow                                                                        SR   3.325 (        j        (Unit 1)          Unit 1)

SR 3.3.2.9 (-.)() 354o/o 3,i 1 36.8% SR 3.3.2.10 (Unit 2) Unit 2)

c. Safety Injection Refer to Function 1 (Safety Injection) for all initiation functions and requirements.
d. Loss of Offsite 1,2,3 3 per bus D SR 3.3.2.3 > 3242 V 3500 V Power SR 3.3.2.9 SR 3.3.2.10 1,2
e. Trip of all Main 3 per pump K SR 3.3.2.8 NA NA Feedwater SR 3.3.2.10 Pumps
f. Auxiliary 1,2,3 3 per train M SR 3.3.2.8 A) Ž_9.5 psig A) 10.5 Feedwater Pump SR 3.3.2.10 psig
            .Train A and Train B Suction                                                                                           B) _>5.2 psig   B) 6.2 psig Transfer on                                                                                                  (Unit 1)     (Unit 1)

Suction > 5.0 psig 6.0 psig Pressure - Low (Unit 2) (Unit 2) (continued) ( xcep MFIVs, MF CVs, and associated bypass valves are closed and de-activated or isolated by a closed manual valve. Caab P S t I a-Td Cataw a nlits 1 and 2 3.3.2-15 Amendment Nos. 249-2"43

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 5 of 5) Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT

7. Automatic Switchover to Containment Sump
a. Automatic 1,2,3,4 2 trains C SR 3.3.2.2 NA NA Actuation Logic SR 3.3.2.4 and Actuation SR 3.3.2.6 Relays
b. Refueling Water 1,2,3,4 4 N SR 3.3.2.1 >_162.4 177.15 Storage Tank SR 3.3.2.7 inches inches (RWST) Level - SR 3.3.2.9 Low SR 3.3.2.10 Coincident with Refer to Function 1 (Safety Injection) for all initiation functions and requirements.

Safety Injection

8. ESFAS Interlocks
a. Reactor Trip, P-4 1,2,3 1 per train, F SR 3.3.2.8 NA NA 2 trains 19 4-(
b. Pressurizer 1,2,3 3 O SR 3.3.2.5 J4 419 and 955 psig Pressure, P-11 SR 3.3.2.9
  • t9 psig
c. Tavg - Low Low, 1,2,3 1 per loop O SR 3.3.2.5 > -555.WF 553°F P-12 SR 3.3.2.9 S '8
9. Containment Pressure Control System
a. Start Permissive 1;2,3,4 4 per train P SR 3.3.2.1 *I
                                                                                                               <.0 psid            0.9 psid SR 3.3.2.7 SR 3.3.2.9
b. Termination 1,2,3,4 4 per train P SR 3.3.2.1 > 0.25 psid 0.35 psid SR 3.3.2.7 SR 3.3.2.9
10. Nuclear Service 1,2,3,4 3 per pit Q,R SR 3.3.2.1 > El. 555.4 ft El. 557.5 L ft Water Suction SR 3.3.2.9 Transfer - Low Pit SR 3.3.2.11 Level SR 3.3.2.12 Catawba Units 1 and 2 3.3.2-16 Amendment Nos. 249i243-

U.S. Nuclear Regulatory Commission June 29, 2010 ATTACHMENT 2a McGuire Units 1 and 2 Technical Specification Bases Page Markups (Provided for information only)

MNS Bases 3.3.1 INSERTS INSERT 1 (new paragraph) For Functions for which TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions" has been implemented, this SR is modified by two Notes as identified in Table 3.3.1-1. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value. Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology. The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the performance of these channels will be evaluated under the plant Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition. The second Note requires that the as-left setting for the channel be returned to within the as-left tolerance of the Nominal Trip Setpoint (NTSP). Where a setpoint more conservative than the NTSP is used in the plant surveillance procedures (field setting), the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint. This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit is maintained. If the as-left channel setting cannot be returned to a setting within the as-left tolerance of the NTSP, then the channel shall be declared inoperable. The second Note also requires that the methodologies for calculating the as-left and the as-found tolerances be in the UFSAR. The NOMINAL TRIP SETPOINT definition includes a provision that would allow the as-left setting for the channel to be outside the tolerance band, provided the setting is conservative with respect to the NTSP. This provision is not applicable to Functions for which the second Note applies. INSERT 2 Technical Specification Task Force, Improved Standard Technical Specifications Change Traveler, TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions," Revision 4.

RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) These trip Functions must be OPERABLE in MODE 1 or 2 when the reactor is critical. In MODE 3, 4, or 5, these RTS trip Functions must be OPERABLE when the RTBs and associated bypass breakers are closed, and the CRD System is capable of rod withdrawal. The RTS instrumentation satisfies Criterion 3 of 10 CFR 50.36 (Ref. 6). ACTIONS A Note has been added to the ACTIONS to clarify the application of Completion Time rules. The Conditions of this Specification may be entered independently for each Function listed in Table 3.3.1-1. When the 4 Required Channels in Table 3.3.1-1 are specified (e.g., on a per steam line, per loop, per SG, etc., basis), then the Condition may be entered separately for each steam line, loop, SG, etc., as appropriate. 0, ,A channel shall be OPERABLE if the point at which the channel trips is 

   '.4found r                    equal to or more conservative than the Allowable Value. In the event a channel's trip setpoint is found less conservative than the Allowable Value, or the transmitter, instrument loop, signal processing electronics, or bistable is found inoperable, then all affected Functions provided by that channel must be declared inoperable and the LCO Condition(s) entered for the protection Function(s) affected. fplant conditions warrant, the trip setpoint may be set outside the NOMINAL TRIP SETPOINT calibration tolerance band as long as the trip setpoint is conservative with respect to the NOMINAL TRIP SETPOINTS. If the trip setpoint is found outside the NOMINAL TRIP SETPOINT calibration tolerance band and non-conservative with respect to the NOMINAL TRIP SETPOINT, the setpoint shall be re-adjusted.

When the number of inoperable channels in a trip Function exceed those specified in one or other related Conditions associated with a trip Function, then the unit is outside the safety analysis. Therefore, LCO 3.0.3 must be immediately entered if applicable in the current MODE of operation. A.1 Condition A applies to all RTS protection Functions. Condition A addresses the situation where one or more required channels for one or more Functions are inoperable at the same time. The Required Action is to refer to Table 3.3.1-1 and to take the Required Actions for the protection functions affected. The Completion Times are those from the referenced Conditions and Required Actions. McGuire Units 1 and 2 B 3.3.1-29 Revision No. RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued) relationship between excore and incore measurements changes significantly. A Note modifies SR 3.3.1.6. The Note states that this Surveillance is required only if reactor power is > 75% RTP and that 24 hours is allowed for completing the first surveillance after reaching 75% RTP. The Frequency of 92 EFPD is adequate. It is based on industry operating experience, considering instrument reliability and operating history data for instrument drift. SR 3.3.1.7 SR 3.3.1.7 is the performance of a COT every 184 days. A COT is performed on each required channel to ensure the channel will, perform the intended Function. The tested portion of the Loop must trip within the Allowable Values specified in Table 3.3.1-1. The setpoint shall be left set consistent with the assumptions of the setpoint methodology. SR 3.3.1.7 is modified by a Note that provides a 4 hour delay in the requirement to perform this Surveillance for source range instrumentation when entering MODE 3 from MODE 2. This Note allows a normal shutdown to proceed without a delay for testing in MODE 2 and for a short time in MODE 3 until the RTBs are open and SR 3.3.1.7 is no longer required to be performed. If the unit is to be in MODE 3 with the RTBs closed for > 4 hours this Surveillance must be completed within 4 hours after entry into MODE 3. The surveillance shall include verification of the high flux at shutdown alarm setpoint of less than or equal to the average CPS Neutron Level reading (most consistent value between highest and lowest CPS Neutron Level reading) at five times background. The Frequency of 184 days is justified in Reference 11. SR 3.3 .1.8 SR 3.3.1.8 is the performance of a COT as described in SR 3.3.1.7, except it is modified by a Note that this test shall include verification that the P-6, during the Intermediate Range COT, and P-10, during the Power Range COT, interlocks are in their required state for the existing unit condition. The verification is performed by visual observation of the McGuire Units 1 and 2 B 3.3.1-44 Revision No.--cý

RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued) permissive status light in the unit control room. The Frequency is modified by a Note that allows this surveillance to be satisfied if it has been performed within 184 days of the Frequencies prior to reactor startup and four hours after reducing power below P-10 and P-6. The Frequency of "prior to startup" ensures this surveillance is performed prior to critical operations and applies to the source, intermediate and power range low instrument channels. The Frequency of "4 hours after reducing power below P-1 0" (applicable to intermediate and power range low channels) and "4 hours after reducing power below P-6" (applicable to source range channels) allows a normal shutdown to be completed and the unit removed from the MODE of Applicability for this surveillance without a delay to perform the testing required by this surveillance. The Frequency of every 184 days thereafter applies if the plant remains in the MODE of Applicability after the initial performances of prior to reactor startup and four hours after reducing power below P-10 or P-6. The MODE of Applicability for this surveillance is < P-1 0 for the power range Q,* low and intermediate range channels and < P-6 for the source range 

  '.,  *u           channels. Once the unit is in MODE 3, this surveillance is no longer
    .-              required. If power is to be maintained < P-10 or < P-6 for more than 4 hours, then the testing required by this surveillance must be performed prior to the expiration of the 4 hour limit. Four hours is a reasonable time to complete the required testing or place the unit in a MODE where this surveillance is no longer required. This test ensures that the NIS source, intermediate, and power range low channels are OPERABLE prior to taking the reactor critical and after reducing power into the applicable MODE (< P-10 or < P-6) for periods > 4 hours. The Frequency of 184 days is justified in Reference 11.

SR 3.3.1.9 72 `.,. SR 3.3.1.9 is the performance of a TADOT and is performed every 92 days, as justified in Reference 7. The SR is modified by a Note that excludes verification of setpoints from the TADOT. Since this SR applies to RCP undervoltage and underfrequency relays, setpoint verification is accomplished during the CHANNEL CALIBRATION. SR 3.3.1.10 A CHANNEL CALIBRATION is performed every 18 months. The CHANNEL CALIBRATION may be performed at power or during refueling based on testing capability. Channel unavailability evaluations in McGuire Units 1 and 2 B 3.3.1-45 Revision No. 99

RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued) References 10 and 11 have conservatively assumed that the CHANNEL CALIBRAITON is performed at power with the channel in bypass. CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies that the channel responds to a measured parameter within the necessary range and accuracy. CHANNEL CALIBRATIONS must be performed consistent with the assumptions of the setpoint methodology. The Frequency of 18 months is based on the assumption of an 18 month calibration interval in the determination of the magnitude of equipment drift in the setpoint methodology. SR 3.3.1.10 is modified by a Note stating that this test shall include verification that the time constants are adjusted to the prescribed values where applicable. The applicable time constants are shown in Table 1-1. SR 3.3.1.11 SR 3.3.1.11 is the performance of a CHANNEL CALIBRATION, as described in SR 3.3.1.10, every 18 months. Two notes modify this SR. Note 1 states that neutron detectors are excluded from the CHANNEL CALIBRATION. The CHANNEL CALIBRATION for the power range neutron detectors consists of a normalization of the detectors based on a power calorimetric and flux map performed above 15% RTP. The CHANNEL CALIBRATION for the source range neutron detectors consists of two methods. Method 1 consists of obtaining the discriminator curves for source range, evaluating those curves, and comparing the curves to the manufacturer's data (adjustments to the discriminator voltage are performed as required). Method 2 consists of performing waveform analysis. This analysis process monitors the actual number and amplitude of the Neutron/Gamma pulses being generated by the SR detector. The high voltage is adjusted to optimize the amplitude of the pulses while maintaining as low as possible high voltage value in order to prolong the detector life. The discriminator voltage is then adjusted, as required, to reasonably ensure that the neutron pulses are being counted by the source range instrumentation and the unwanted gamma pulses are not being counted as neutron pulses. The CHANNEL CALIBRATION for the intermediate range neutron detectors consists of the high voltage detector plateau for intermediate range, evaluating those curves, and comparing the curves to the manufacturer's data. Note 2 states that this Surveillance is not required McGuire Units 1 and 2 B 3.3.1-46 Revision No. 49-

RTS Instrumentation B 3.3.1 BASES REFERENCE* 1. UFSAR, Chapter 7.

2. UFSAR, Chapter 6.
3. UFSAR, Chapter 15.
4. IEEE-279-1971.
5. 10 CFR 50.49.
6. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).
7. WCAP-1 0271-P-A, Supplement 2, Rev. 1, June 1990.
8. WCAP 13632-P-A, Revision 2, "Elimination of Pressure Sensor Response Time Testing Requirements" Sep., 1995.
9. WCAP-14036-P-A, Revision 1, "Elimination of Periodic Protection Channel Response Time Tests" Oct., 1998.
10. WCAP-14333-P-A, Revision 1, October 1998.
11. WCAP-15376-P-A, Revision 1, March 2003.
                             ~~E.A- F McGuire Units 1 and 2              B 3.3.1-50                                Revision No. -99ý-

MNS Bases 3.3.2 INSERTS INSERT 1 (new paragraph) For Functions for which TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions" has been implemented, this SR is modified by two Notes as identified in Table 3.3.2-1. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value. Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology. The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the performance of these channels will be evaluated under the plant Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition. The second Note requires that the as-left setting for the channel be returned to within the as-left tolerance of the Nominal Trip Setpoint (NTSP). Where a setpoint more conservative than the NTSP is used in the plant surveillance procedures (field setting), the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint. This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit is maintained. If the as-left channel setting cannot be returned to a setting within the as-left tolerance of the NTSP, then the channel shall be declared inoperable. The second Note also requires that the methodologies for calculating the as-left and the as-found tolerances be in the UFSAR. The NOMINAL TRIP SETPOINT definition includes a provision that would allow the as-left setting for the channel to be outside the tolerance band, provided the setting is conservative with respect to the NTSP. This provision is not applicable to Functions for-which the second Note applies. INSERT 2 Technical Specification Task Force, Improved Standard Technical Specifications Change Traveler, TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions," Revision 4.

ESFAS Instrumentation B 3.3.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

9. Containment Pressure Control System Permissives The Containment Pressure Control System (CPCS) protects the Containment Building from excessive depressurization by preventing inadvertent actuation or continuous operation of the Containment Spray and Containment Air Return Systems when containment pressure is at or less than the CPCS permissive setpoint. The control scheme of CPCS is comprised of eight independent control circuits (4 per train), each having a separate and independent pressure transmitter and current alarm module. Each pressure transmitter monitors the containment pressure and provides input to its respective current alarm. The current alarms are set to inhibit or terminate containment spray and containment air return fan operation when containment pressure falls below the setpoint.
                            .The alarm modules switch back to the permissive state (allowing the systems to operate) when containment pressure is greater than or equal to the setpoint.

This function must be OPERABLE in MODES 1, 2, 3, and 4 when there is sufficient energy in the primary and secondary sides to pressurize containment following a pipe break. In MODES 5 and 6, there is insufficient energy in the primary and secondary sides to significantly pressurize the containment. The ESFAS instrumentation satisfies Criterion 3 of 10 CFR 50.36 (Ref. 6). ACTIONS A Note has been added in the ACTIONS to clarify the application of Completion Time rules. The Conditions of this Specification may be entered independently for each Function listed on Table 3.3.2-1. When the Required Channels in Table 3.3.2-1 are specified (e.g., on a per steam line, per loop, per SG, etc., basis), then the Condition may be entered separately for each steam line, loop, SG, etc., as appropriate. A channel shall be OPERABLE if the point at which the channel trips is found equal to or more conservative than the Allowable Value. In the event a channel's trip setpoint is found less conservative than the Allowable Value, or the transmitter, instrument loop, signal processing electronics, or bistable is found inoperable, then all affected Functions provided by the channel must be declared inoperable and the LCO Condition(s) entered for the protection 

                     -unctionr`sns) af ected. ,lWplant conditions warrant, the trip setpoint may be set outside the NOMINAL TRIP SETPOINT calibration tolerance band as long as the trip setpoint is conservative with respect to the NOMINAL TRIP SETPOINT.

If the trip setpoint is found outside the NOMINAL TRIP SETPINT calibration tolerance band and non-conservative with respect to the NOMINAL TRIP 

  )  ~ASETPOINT,                     the setpoint shall be re-adjusted.

McGuire Units 1 and 2 B 3.3.2-28 Revision No. 49-

ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE REQUIREMENTS (continued) SR 3.3.2.3 is the performance of a COT on the RWST level and Containment Pressure Control Start and Terminate Permissives. A COT is performed on each required channel to ensure the entire channel will perform the intended Function. Setpoints must be found within the Allowable Values specified in Table 3.3. 2-1. This test is performed every 31 days. The Frequency is adequate, based on operating experience, considering instrument reliability and operating history data. SR 3.3.2.4 SR 3.3.2.4 is the performance of a MASTER RELAY TEST. The MASTER RELAY TEST is the energizing of the master relay, verifying contact operation and a low voltage continuity check of the slave relay coil. Upon master relay contact operation, a low voltage is injected to the slave relay coil. This voltage is insufficient to pick up the slave relay, but large enough to demonstrate signal path continuity. This test is performed every 92 days on a STAGGERED TEST BASIS. The time allowed for the testing (4 hours) is justified in Reference 7. The frequency of 92 days is justified in Reference 11. SR 3.3.2.5 SR 3.3.2.5 is the performance of a COT. A COT is performed on each required channel to ensure the channel will perform the intended Function. The tested portion of the loop must trip within the Allowable Values specified in Table 3.3. 2-1. The setpoint shall be left set consistent with the assumptions of the setpoint methodology. Tf ays is justified in Reference 11. SR 3.3.2.6 SR 3.3.2.6 is the performance of a SLAVE RELAY TEST. The SLAVE RELAY TEST is the energizing of the slave relays. Contact operation is verified in one of two ways. Actuation equipment that may be operated in the design mitigation MODE is either allowed to function, or is placed in a condition where the relay contact operation can be verified without operation of the equipment. Actuation equipment that may not be operated in the design mitigation MODE is prevented from operation by the SLAVE RELAY TEST circuit. For this latter case, contact operation is verified by a continuity check of the circuit containing McGuire Units 1 and 2 B 3.3.2-40 Revision No. ý9ý

ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE REQUIREMENTS (continued) the slave relay. This test is performed every 92 days. The Frequency is adequate, based on industry operating experience, considering instrument reliability and operating history data. SR 3.3.2.7 SR 3.3.2.7 is the performance of a TADOT. This test is a check of the Manual Actuation Functions, AFW pump start, Reactor Trip (P-4) Interlock and Doghouse Water Level - High High feedwater isolation. It is performed every 18 months. Each Manual Actuation Function is tested up to, and including, the master relay coils. In some instances, the test includes actuation of the end device (i.e., pump starts, valve cycles, etc.). The Frequency is adequate, based on industry operating experience and is consistent with the typical refueling cycle. The SR is modified by a Note that excludes verification of setpoints during the TADOT for manual initiation Functions. The manual initiation Functions have no associated setpoints. SR 3.3.2.8 SR 3.3.2.8 is the performance of a CHANNEL CALIBRATION. A CHANNEL CALIBRATION is performed every 18 months. The CHANNEL CALIBRATION may be performed at power or during refueling based on bypass testing capability. Channel unavailability evaluations in References 10 and 11 have conservatively assumed that the CHANNEL CALIBRATION is performed at power with the channel in bypass. CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies that the channel responds to measured parameter within the necessary range and accuracy. CHANNEL CALIBRATIONS must be performed consistent with the assumptions of the unit specific setpoint methodology. The Frequency of 18 months is based on the assumption of an 18 month calibration interval in the determination of the magnitude of equipment drift in the setpoint methodology. This SR is modified by a Note stating that this test should include verification that the time constants are adjusted to the prescribed values where applicable. The applicable time constants are shown in Table 3.3.2-1. SR 3.3.2.9 McGuire Units 1 and 2 B 3.3.2-41 Revision No. ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE REQUIREMENTS (continued) may be replaced without verification testing. One example where response time could be affected is replacing the sensing assembly of a transmitter. ESF RESPONSE TIME tests are conducted on an 18 month STAGGERED TEST BASIS. Testing of the final actuation devices, which make up the bulk of the response time, is included in the testing of each channel. The final actuation device in one train is tested with each channel. Therefore, staggered testing results in response time verification of these devices every 18 months. The 18 month Frequency is consistent with the typical refueling cycle and is based on unit operating experience, which shows that random failures of instrumentation components causing serious response time degradation, but not channel failure, are infrequent occurrences. This SR is modified by a Note that clarifies that the turbine driven AFW pump is tested within 24 hours after reaching 900 psig in the SGs. REFERENCES 1. UFSAR, Chapter 6.

2. UFSAR, Chapter 7.

3... UFSAR, Chapter 15.

4. IEEE-279-1971.
5. 10 CFR 50.49.
6. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).
7. WCAP-10271-P-A, Supplement 1 and Supplement 2, Rev. 1, May 1986 and June 1990.
8. WCAP 13632-P-A, Revision 2, "Elimination of Pressure Sensor Response Time Testing Requirements" Sep., 1995.
9. WCAP-14036-P-A, Revision 1, "Elimination of Periodic Protection Channel Response Time Tests" Oct., 1998.
10. WCAP-14333-P-A, Revision 1, October 1998.
11. WCAP-15376-P-A, Revision 1, March 2003.

McGuire Units 1 and 2 B 3.3.2-43 Revision No. 49-

U.S. Nuclear Regulatory Commission June 29, 2010 ATTACHMENT 2b Catawba Units I and 2 Technical Specification Bases Page Markups (Provided for information only)

CNS Bases 3.3.1 INSERTS INSERT 1 (new paragraph) For Functions for which TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions" has been implemented, this SR is modified by two Notes as identified in Table 3.3.1-1. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value. Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology. The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the performance of these channels will be evaluated under the plant Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition. The second Note requires that the as-left setting for the channel be returned to within the as-left tolerance of the Nominal Trip Setpoint (NTSP). Where a setpoint more conservative than the NTSP is used in the plant surveillance procedures (field setting), the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint. This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit-is maintained. If the as-left channel setting cannot be returned to a setting within the as-left tolerance of the NTSP, then the channel shall be declared inoperable. The second Note also requires that the methodologies for calculating the as-left and the as-found tolerances be in the UFSAR. The NOMINAL TRIP SETPOINT definition includes a provision that would allow the as-left setting for the channel to be outside the tolerance band, provided the setting is conservative with respect to the NTSP. This provision is not applicable to Functions for which the second Note applies. INSERT 2 Technical Specification Task Force, Improved Standard Technical Specifications Change Traveler, TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions," Revision 4.

RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

19. Automatic Trip Loqic The LCO requirement for the RTBs (Functions 17 and 18) and Automatic Trip Logic (Function 19) ensures that means are provided to interrupt the power to allow the rods to fall into the reactor core. Each RTB is equipped with an undervoltage coil and a shunt trip coil to trip the breaker open when needed. Each train RTB has a bypass breaker to allow testing of the trip breaker while the unit is at power. The reactor trip signals generated by the RTS Automatic Trip Logic cause the RTBs and associated bypass breakers to open and shut down the reactor.

The LCO requires two trains of RTS Automatic Trip Logic to be OPERABLE. Having two OPERABLE channels ensures that random failure of a single logic channel will not prevent reactor trip. These trip Functions must be OPERABLE in MODE 1 or 2 when the reactor is critical. In MODE 3, 4, or 5, these RTS trip Functions must be OPERABLE when the RTBs and associated bypass breakers are closed, and the CRD System is capable of rod withdrawal. The RTS instrumentation satisfies Criterion 3 of 10 CFR 50.36 (Ref. 6). ACTIONS A Note has been added to the ACTIONS to clarify the application of Completion Time rules. The Conditions of this Specification may be entered independently for each Function listed in Table 3.3.1-1. When the Required Channels in Table 3.3.1-1 are specified (e.g., on a per steam line, per loop, per SG, etc., basis), then the Condition may be entered separately for each steam line, loop, SG, etc., as appropriate. 0A channel shall be OPERABLE if the point at which the channel trips is 

                   -found more conservative than the Allowable Value. In the event a
  *~
  • channel's trip setpoint is found less conservative than the Allowable Value, or the transmitter, instrument loop, signal processing electronics, or bistable is found inoperable, then all affected Functions provided by that channel must be declared inoperable and the LCO Condition(s) en ere or e p n nc ion s a ected. 11,,Olant conditions warrant, the trip setpoint may be set outside the NOMINAL TRIP SETPOINT calibration tolerance band as long as the trip.setpoint is conservative with respect to the NOMINAL TRIP SETPOINT. If the trip setpoint is found outside of the NOMINAL TRIP SETPOINT calibration tolerance band and non-conservative with respect to the NOMINAL TRIP Catawba Units 1 and 2 B 3.3.1-30 Revision No. +-

RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued) condition, thus preventing inadvertent actuation. Through the semiautomatic tester, all possible logic combinations, with and without applicable permissives, are tested for each protection function. The Frequency of every 92 days on a STAGGERED TEST BASIS is justified in Reference 12. SR 3.3.1.6 SR 3.3.1.6 is a calibration of the excore channels to the incore channels. If the measurements do not agree, the excore channels are not declared inoperable but must be calibrated to agree with the incore detector measurements. If the excore channels cannot be adjusted, the channels are declared inoperable. This Surveillance is performed to verify the f(AI) input to the overtemperature AT Function and overpower AT Functionm At Beginning of Cycle (BOC), the excore channels are compared to the incore detector measurements prior to exceeding 75% power. Excore detectors are adjusted as necessary. This low power surveillance 31"1v, satisfies the initial performance of SR 3.3.1.6 with subsequent 

        ,           surveillances conducted at least every 92 EFPD.

At BOC, after reaching full power steady state conditions, additional incore and excore measurements are taken at various Al conditions to determine the Mj factors. The Mj factors are normally only determined at BOC, but they may be changed at other points in the fuel cycle if the 

          -.     . relationship between excore and incore measurements changes significantly.

A Note modifies SR 3.3.1.6. The Note states that this Surveillance is 

             ,    , required only if reactor power is > 75% RTP and that 24 hours is allowed
     -         -    for completing the first surveillance after reaching 75% RTP.

The Frequency of 92 EFPD is adequate. It is based on industry operating experience, considering instrument reliability and operating history data for instrument drift. SR 3.3.1.7 SR 3.3.1.7 is the performance of a COT every 184 days. A COT is performed on each required channel to ensure the channel will Catawba Units 1 and 2 B 3.31-45 Revision No- 3

RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued) perform the intended Function. The tested portion of the loop must trip within the Allowable Values specified in Table 3.3.1-1. The setpoint shall be left set consistent with the assumptions of the setpoint methodology. SR 3.3.1.7 is modified by a Note that provides a 4 hour delay in the requirement to perform this Surveillance for source range instrumentation when entering MODE 3 from MODE 2. This Note allows a normal shutdown to proceed without a delay for testing in MODE 2 and for a short time in MODE 3 until the RTBs are open and SR 3.3.1.7 is no longer required to be performed. If the unit is to be in MODE 3 with the RTBs closed for > 4 hours this Surveillance must be completed within 4 hours after entry into MODE 3. J Fr gujwxQL 84 days is justified in Reference 12. SR 3.3.1.8 is the performance of a COT as described in SR 3.3.1.7, except it is modified by a Note that this test shall include verification that the P-6, during the Intermediate Range COT, and P-10, during the Power Range COT, interlocks are in their required state for the existing unit condition. The verification is performed by visual observation of the permissive status light in the unit control room. The Frequency is modified by a Note that allows this surveillance to be satisfied if it has' been performed within 184 days of the Frequencies prior to reactor startup and four hours after reducing power below P-10 and P-6. The Frequency of "prior to startup" ensures this surveillance is performed prior to critical operations and applies to the source, intermediate and power range low instrument channels. The Frequency of "4 hours after reducing power below P-10" (applicable to intermediate and power range low channels) and "4 hours after reducing power below P-6" (applicable to source range channels) allows a normal shutdown to be completed and the unit removed from the MODE of Applicability for this surveillance without a delay to perform the testing required by this surveillance. The Frequency of every 184 days thereafter applies if the plant remains in the MODE of Applicability after the initial performances of prior to reactor startup and four hours after reducing power below P-10 or P-6. The MODE of Applicability for this surveillance is < P-1 0 for the power range low and intermediate range channels and < P-6 for the source range channels. Catawba Units 1 and 2 B 3.3.1-46 Revision No. RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued) Once the unit is in MODE 3, this surveillance is no longer required: If power is to be maintained < P-10 or < P-6 for more than 4 hours, then the testing required by this surveillance must be performed prior to the expiration of the 4 hour limit. Four hours is a reasonable time to complete the required testing or place the unit in a MODE where this surveillance is no longer required. This test ensures that the NIS source, intermediate, and power range low channels are OPERABLE prior to taking the reactor critical and after reducing power into the applicable MODE (< P-10 or < P-6) for periods > 4 hours. The Frequency of 184 days is justified in Reference 12. SR3.3.1.9 SR 3.3.1.9 is the performance of a TADOT and is performed every 92 days, as justified in Reference 7. The SR is modified by a Note that excludes verification of setpoints from the TADOT. Since this SR applies to RCP undervoltage and underfrequency relays, setpoint verification is accomplished during the CHANNEL CALIBRATION. SR 3.3.1.10 A CHANNEL CALIBRATION is performed every 18 months, or approximately at every refueling. CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies that the channel responds to a measured parameter within the necessary range and accuracy. CHANNEL CALIBRATIONS must be performed consistent with the assumptions of the setpoint methodology. The Frequency of 18 months is based on the assumption of an 18 month calibration interval in the determination of the magnitude of equipment drift in the setpoint methodology. SR 3.3.1.10 is modified by a Note stating that this test shall include verification that the time constants are adjusted to the prescribed values where applicable. The applicable time constants are shown in Table 3.3.1-1. Catawba Units 1 and 2 B 3.3.1-47 Revision No.---3--

RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued) SR 3.3.1.11 SR 3.3.1.11 is the performance of a CHANNEL CALIBRATION, as described in SR 3.3.1.10, every 18 months. This SR is modified by two notes. Note 1 states that neutron detectors are excluded from the CHANNEL CALIBRATION. The CHANNEL CALIBRATION for the power range neutron detectors consists of a normalization of the detectors based on a power calorimetric and flux map performed above 15% RTP. The CHANNEL CALIBRATION for the source range and intermediate range neutron detectors consists of obtaining the high voltage detector plateau and discriminator curves for source range, and the high voltage detector plateau for intermediate range, evaluating those curves, and comparing the curves to the manufacturer's data. Note 2 states that this Surveillance is not required for the NIS power range detectors for entry into MODE 2 or 1, and is not required for the NIS intermediate range detectors for entry into MODE 2, because the unit must be in at least MODE 2 to perform the test for the intermediate range detectors and MODE 1 for the power range detectors. The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown these components usually pass the Surveillance when performed on the 18 month Frequency. SR 3.3.1.12 SR 3.3.1.12 is the performance of a CHANNEL CALIBRATION, as described in SR 3.3.1.10, every 18 months. The Frequency is justified by the assumption of an 18 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis. SR 3.3.1.13 SR 3.3.1.13 is the performance of a COTof RTS interlocks every 18 months. The Frequency is based on the known reliability of the interlocks and the multichannel redundancy available, and has been shown to be acceptable through operating experience. Catawba Units 1 and 2 B 3.3.1-48 Revision No.- RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued) time could be affected is replacing the sensing assembly of a transmitter. As appropriate, each channel's response must be verified every 18 months on a STAGGERED TEST BASIS. Testing of the final actuation devices is included in the testing. Testing of the RTS RTDs is performed on an 18 month frequency. Response times cannot be determined during unit operation because equipment operation is required to measure response times. Experience has shown that these components usually pass this surveillance when performed at the 18 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint. SR 3.3.1.16 is modified by a Note stating that neutron detectors are excluded from RTS RESPONSE TIME testing. This Note is necessary because of the difficulty in generating an appropriate detector input signal. Excluding the detectors is acceptable because the principles of detector operation ensure a virtually instantaneous response. The response time of the neutron flux signal portion of the channel shall be measured from detector output or input of the first electronic component in the channel. REFERENCES 1. UFSAR, Chapter 7.

2. UFSAR, Chapter 6.
3. UFSAR, Chapter 15.
4. IEEE-279-1971.
5. 10 CFR 50.49.
6. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).
7. WCAP-1 0271-P-A, Supplement 2, Rev. 1, June 1990.

S",*8. WCAP-1 3632-P-A Revision 2, "Elimination of Pressure Sensor Response Time Testing Requirements" Sep., 1995. 

     *j ,,         9. WCAP-14036-P-A Revision 1, "Elimination of Periodic Protection Channel Response Time Tests" Oct., 1998.

10.10 CFR 50.67. Catawba Units 1 and 2 B 3.3.1-51 Revision No. 2

RTS Instrumentation B 3.3.1 BASES REFERENCES (continued) 11.WCAP-14333-P-A, Rev. 1, October 1998. 12.WCAP-15376-P-A, Rev. 1, March 2003. 13,i._SE7,C_7 Catawba Units 1 and 2 B 3.3.1-52 Revision No.- CNS Bases 3.3.2 INSERTS INSERT 1 (new paragraph) For Functions for which TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions" has been implemented, this SR is modified by two Notes as identified in Table 3.3.2-1. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value. Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology. The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the performance of these channels will be evaluated under the plant Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition. The second Note requires that the as-left setting for the channel be returned to within the as-left tolerance of the Nominal Trip Setpoint (NTSP). Where a setpoint more conservative than the NTSP is used in the plant surveillance procedures (field setting), the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint. This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit is maintained. If the as-left channel setting cannot be returned to a setting within the as-left tolerance of the NTSP, then the channel shall be declared inoperable. The second Note also requires that the methodologies for calculating the as-left and the as-found tolerances be in the UFSAR. The NOMINAL TRIP SETPOINT definition includes a provision that would allow the as-left setting for the channel to be outside the tolerance band, provided the setting is conservative with respect to the NTSP. This provision is not applicable to Functions for which the second Note applies. INSERT 2 Technical Specification Task Force, Improved Standard Technical Specifications Change Traveler, TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions," Revision 4.

ESFAS Instrumentation B 3.3.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) valves, and start the NSWS pumps. This function is initiated on a two-out-of-three logic from either NSWS pump pit. This function must be OPERABLE in MODES 1, 2, 3, and 4 to ensure cooling water remains available to essential components during a DBA. In MODES 5 and 6, the sufficient time exists for manual operator action to realign the NSWS pump suction, if required. Unlike other shared NSWS equipment, the pit level interlocks do not require both normal and emergency power for OPERABILITY. This is because unlike mechanical components such as pumps and valves, the interlocks are designed to fail safe upon a loss of power, initiating a transfer from Lake Wylie to the standby nuclear service water pond. The definition of OPERABILITY, which requires either normal or emergency power, provides sufficient power supply requirements and these interlocks can be considered OPERABLE provided they are powered from either an inverter or regulated power. The ESFAS instrumentation satisfies Criterion 3 of 10 CFR 50.36 (Ref. 6). ACTIONS A Note has been added in the ACTIONS to clarify the application of Completion Time rules. The Conditions of this Specification may be entered independently for each Function listed on Table 3.3.2-1. When the Required Channels in Table 3.3.2-1 are specified (e.g., on a per steam line, per loop, per SG, etc., basis), then the Condition may be entered separately for each steam line, loop, SG, etc., as appropriate. A channel shall be OPERABLE if the point at which the channel trips is 

'V                 found more conservative than the Allowable Value. In the event a channel's trip setpoint is found less conservative than the Allowable Value, or the transmitter, instrument loop, signal processing electronics, or bistable is found inoperable, then all affected Functions provided by that channel must be declared inoperable and the LCO Condition(s) entered for the protection Function(s) affected),plant conditions warrant, the trip setpoint may be set outside the NOMINAL TRIP SETPOINT calibration tolerance band as long as the trip setpoint is conservative with respect to the NOMINAL TRIP SETPOINT. If the trip setpoint is found outside of the NOMINAL TRIP SETPOINT calibration tolerance band and non-conservative with respect to the NOMINAL TRIP SETPOINT, the setpoint shall be re-adjusted.

Catawba Units 1 and 2 B 3.3.2-31 Revision No. 2-

ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE REQUIREMENTS (continued) semiautomatic tester, all possible logic combinations, with and without applicable permissives, are tested for each protection function. In addition, the master relay coil is pulse tested for continuity. This verifies that the logic modules are OPERABLE and that there is an intact voltage signal path to the master relay coils. The Frequency of every 92 days on a STAGGERED TEST BASIS is justified in Reference 14. SR 3.3.2.3 SR 3.3.2.3 is the performance of a TADOT every 31 days. This test is a check of the Loss of Offsite Power Function. Each Function is tested up to, and including, the master transfer relay coils. This test also includes trip devices that provide actuation signals directly to the SSPS. The SR is modified by a Note that excludes final actuation of pumps and valves to minimize plant upsets that would occur. The Frequency is adequate based on operating experience, considering 

 ,    {..           instrument reliability and operating history data.

S R 3.3.2.4 SR 3.3.2.4 is the performance of a MASTER RELAY TEST. The

  • MASTER RELAY TEST is the energizing of the master relay, verifying contact operation and a low voltage continuity check of the slave relay
      ""coil.             Upon master relay contact operation, a low voltage is injected to the
      --f,_
      -~slave~relay              coil. This voltage is insufficient to pick up the slave relay, but large enough to demonstrate signal path continuity. This test is performed every 92 days on a STAGGERED TEST BASIS. The time allowed for the testing (4 hours) is justified in Reference 7. The Frequency of 92 days is justified in Reference 14.

cSR 3.3.2.5 SR 3.3.2.5 is the performance of a COT. A COT is performed on each required channel to ensure the channel will perform the intended Function. The tested portion of the loop must trip within the Allowable Values specified in Table 3.3.2-1. Catawba Units 1 and 2 B 3.'3.2-45 Revision No. 3

ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE REQUIREMENTS (continued) The setpoint shall be left set consistent with the assumptions of the setpoint methodology. The Frequency of 184 days is justified in Reference 14. S 3.. . SR 3.3.2.6 is the performance of a SLAVE RELAY TEST. The SLAVE RELAY TEST is the energizing of the slave relays. Contact operation is verified in one of two ways. Actuation equipment that may be operated in the design mitigation MODE is either allowed to function, or is placed in a condition where the relay contact operation can be verified without operation of the equipment. Actuation equipment that may not be operated in the design mitigation MODE is prevented from operation by the SLAVE RELAY TEST circuit. For this latter case, contact operation is verified by a continuity check of the circuit containing the slave relay. This test is performed every 92 days. The Frequency is adequate, based on industry operating experience, considering instrument reliability and operating history data. For slave relays or any auxiliary relays in the ESFAS circuit that are of the type Westinghouse AR or Potter & Brumfield MDR, the SLAVE RELAY TEST is performed every 18 months. This test frequency is based on the relay reliability assessments presented in References 10, 11, and 12. These reliability assessments are relay specific and apply only to the Westinghouse AR and Potter & Brumfield MDR type relays. SSPS slave relays or any auxiliary relays not addressed by Reference 10 do not qualify for extended surveillance intervals and will continue to be tested at a 92 day Frequency. SR 3.3.2.7 SR 3.3.2.7 is the performance of a COT on the RWST level and Containment Pressure Control Start and Terminate Permissives. A COT is performed on each required channel to ensure the entire channel will perform the intended Function. Setpoints must be found within the Allowable Values specified in Table 3.3.1-1. This test is performed every 31 days. The Frequency is adequate, based on operating experience, considering instrument reliability and operating history data. Catawba Units 1 and 2 B 3.3.2-46 Revision No. ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE REQUIREMENTS (continued) SIR 3.3.2.8 SR 3.3.2.8 is the performance of a TADOT. This test is a check of the Manual Actuation Functions, AFW pump start on trip of all MFW pumps, AFW low suction pressure, Reactor Trip (P-4) Interlock, and Doghouse Water Level - High High Feedwater Isolation. It is performed every 18 months. Each Manual Actuation Function is tested up to, and including, the master relay coils. In some instances, the test includes actuation of the end device (i.e., pump starts, valve cycles, etc.). The Frequency is adequate, based on industry operating experience and is consistent with the typical refueling cycle. The SR is modified by a Note that excludes verification of setpoints during the TADOT for manual initiation Functions. The manual initiation Functions have no associated setpoints. SR 3.3.2.9 SR 3.3.2.9 is the performance of a CHANNEL CALIBRATION. A CHANNEL CALIBRATION is performed every 18 months, or approximately at every refueling. CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies that the channel responds to measured parameter within the necessary range and accuracy. CHANNEL CALIBRATIONS must be performed consistent with the assumptions of the unit specific setpoint methodology. The Frequency of 18 months is based on the assumption of an 18 month calibration interval in the determination of the magnitude of equipment drift in the setpoint methodology. This SR is modified by a Note stating that this test should include verification that the time constants are adjusted to the prescribed values where applicable. The applicable time constants are shown in Table 3.3.2-1. 3.3.2. 10 This SR ensures the individual channel ESF RESPONSE TIMES are less than or equal to the maximum values assumed in the accident analysis. Response Time testing acceptance criteria are included in the UFSAR (Ref. 2). Individual 

                                    /

component response times are not modeled in the Catawba Units 1 and 2 B 3.3.2-47 Revision No. ESFAS Instrumentation B 3.3.2 BASES REFERENCE;S 1. UFSAR, Chapter 6.

2. UFSAR, Chapter 7.
3. UFSAR, Chapter 15.
4. IEEE-279-1971.
5. 10 CFR 50.49.
6. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).
7. WCAP-1 0271-P-A, Supplement 1 and Supplement 2, Rev. 1, May 1986 and June 1990.
8. WCAP-1 3632-P-A Revision 2, "Elimination of Pressure Sensor Response Time Testing Requirements" Sep., 1995.
9. WCAP-14036-P-A Revision 1, "Elimination of Periodic Protection Channel Response Time Tests" Oct., 1998.
10. WCAP-13900, "Extension of Slave Relay Surveillance Test Intervals," April 1994.
11. WCAP-13877 Revision 2-P-A, "Reliability Assessment of Westinghouse Type AR Relays Used As SSPS Slave Relays,"

August 2000.

12. WCAP-1 3878-P-A Revision 2, "Reliability Assessment of Potter &

Brumfield MDR Series Relays," August 2000.

13. WCAP-14333-P-A, Revision 1, October 1998.
14. WCAP-15376-P-A, Revision 1, March 2003.

j =6-:ýj-Catawba Units 1 and 2 B 3.3.2-50 Revision No.-G-}}

Retrieved from "https://kanterella.com/w/index.php?title=ML101900267&oldid=2557000"