ML11207A440
| ML11207A440 | |
| Person / Time | |
|---|---|
| Site: | Crystal River  |
| Issue date: | 06/15/2011 |
| From: | Progress Energy Florida |
| To: | Office of Nuclear Reactor Regulation |
| References | |
| 3F0611-02 | |
| Download: ML11207A440 (227) | |
Text
{{#Wiki_filter:PROGRESS ENERGY FLORIDA, INC. CRYSTAL RIVER UNIT 3 DOCKET NUMBER 50-302 /LICENSE NUMBER DPR-72 LICENSE AMENDMENT REQUEST #309, REVISION 0 ATTACHMENT 8 SAMPLE INSTRUMENTATION SETPOINT CALCULATION
U. S. Nuclear Regulatory Commission Attachment 8 3F0611-02 Page 1 of I SAMPLE INSTRUMENTATION SETPOINT CALCULATION This Attachment is consistent with the guidance provided in Technical Specifications Task Force (TSTF) proposal, TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions." The Crystal River Unit 3 (CR-3) Extended Power Uprate (EPU) does not require revision to any existing Limiting Safety System Setting (LSSS) setpoints. However, the new CR-3 Improved Technical Specifications (ITS) 3.3.19, "Inadequate Core Cooling Monitoring System (ICCMS) Instrumentation," ensures that adequate core protection is provided for a specific range of small break loss of coolant accidents (LOCAs). Therefore, the notes consistent with the intent of TSTF-493, Option A have been added to ITS Surveillance Requirement (SR) 3.3.19.3 (CHANNEL CALIBRATION) for this instrurnentation. Associated ITS Bases changes also reflect the addition of these notes. As requested in the notice of availability for TSTF-493, CR-3 is providing a summary calculation demonstrating the plant specific instrument setpoint methodology. A setpoint calculation of the Reactor Coolant System pressure instrumentation (an input parameter to ICCMS) has been included in this attachment to provide a representative view of the methodology used in developing and maintaining safety-related setpoints at CR-3. The methodology used at CR-3 is primarily based on Instrument Society of America (ISA) Recommended Practice RP67.04, Part 11, 1994. The CR-3 methodology utilizes a graded approach to setpoints, with a more rigorous approach taken for setpoints that are critical for shutting down the reactor, maintaining the reactor in a shutdown configuration and mitigating the effects of accident conditions. The setpoint program establishes four category levels with Category A being the most stringent. Category A calculations meet the 95/95 tolerance limit as identified in Regulatory Guide 1.105, "Setpoints for Safety-Related Instrumentation." The sample setpoint calculation attached, Calculation 1 0014, "Reactor Coolant Pressure Loop Accuracy for Engineered Safeguards," is a Category A calculation. This calculation supports multiple setpoint categories. Examples include: Reactor Coolant Pressure instrumentation going to the Low Temperature Overpressure Protection System, and the Reactor Protection System and the Safety Parameter Display System. As such, the level of rigor utilized in the calculation will not be consistent throughout the entire calculation.
Fkodda INTEROFFICE CORRESPONDENCE Power CORP ORATI0N A-C-XMTLFRM Design Engineering NAIE 3415 Office MAC Telephone
SUBJECT:
Crystal River Unit 3 Quality Record Transmittal - Analysis/Calculation TO: Records Management i NR2A The following analysis/calculation package is submitted as the QA Record copy: DOCNO (FPC DOCUMENT IDENTIFICATION NUMBER) I REV. SYSTEM(S) TOTAL PAGES TRANSMITTED 1-89-0014 10 RC qq TITLE FL0RIDA FOWER CORPORATION RC PRESSURE LOOP ACCURACY FOR ES NUCLEAR ENOINEERIN, DEPARTMEpNT REVIEWED AND ACCEPTED BY: EINGINEER ~DT KWDS (IDENTIFY KEYWORDS FOR LATER RETRIEVAL) Calculation. Insulation Resistanrte. Setnoint. Accuracv. RC. HPI* SUPERVISOR X-C-_ P. S--" 4 -I24 Calculation. Insulation Resistance. SetDoint. Accu cv. RC. HPI. LPI ES DXREF (REFERENCES OR FILES I LIST PRIMARY FILE FIRST) 1P-132 1-84-0002 I MAR 97-02-12-01, MAR 97-02-12-02 VEND (VENDOR NAME) VENDOR DOCUMENT NUMBER (DXREF) SUPERSEDED DOCUMENTS (DXREF) FRAMATOME N/A 1-89-0014 R9, ICA RO, " Pev I RC-3A-PT3, RC-3A-PT4, RC-3B-PT3 ITAGRC-3A-JX3, RC-3A-JX4, RC-3B-JX3, RC-3A-P13, RC-3A-P12 I'~i~ RC-3A-PY3, RC-3A-PY4-1, RC-3B-PY3 RC-3A-EB1, RC-3B-EB2, RC-3A-EB2, RC-3A-EB3, RC-163A-PY1, RC-163A-PY2 RC-3B-EB3 RC-154-PRrTR RC-3-BT1, RC-3-BT7, RC-3-BT2 RC-3A-PS3, RC-3A-PS4, RC-3A-PS5 RC-3-BT4, RC-3-BT5, RC-3-BT6, RC-3-BT10 RC-3-BT8, RC-3-BT3, RC-3-BT9 RC-3A-PS6, RC-3A-PS7, RC-3A-PY4 RC-3-BT11, RC-3-BT12 PART NO. COMMENTS (USAGE RESTRICTIONS, PROPRIETARY, ETC.) This calculation incorporates the changes made by HPI MAR 97-02-12-01 and MAR 97-02-12-02 which revised the Low pressure setpoint and modified the RCITS Foxboro module and a~dds the Signal Monitor/Bypass Alarm setpoints. "..tA.hmenta6of RO'Asioa9.. n . ie*-.. j6 /4/1./19 7k t 74".2a46 ir tks; rev;s3;m trFna;)7 )4e .sam"e a-s Pev;.%;Ofl ? ZCA40 iev0~. NOTE: Use Tag number only for valid tag numbers (i.e., RCV-8, SWV-34, DCH-99); otherwise, use Part number field (i.e., CSC 14599, AC 1459). If more space is required, write "See Attachment" and list on separate sheet.
**FOR RECORDS MANAGEMENT USE ONLY **
Quality Record Transmittal received and information entered into SEEK. Entered by: _ Date (Return copy of Quality Record Transmittal to DE Support Specialist.) DESIGN ENGIMRW..P well DATE V FIION ENGINEER JR Brannon DATE SUPERVIS§QR, DESIGN ENG. L. Lesniak DATE cc: Nuclear Projects (If MAR/CGWR/PEERY Calculation Review form Part III eIns required ElYes 0 No Return to Service Related) E] Yes [K No (If Yes, send copy of the Calculation to the Responsible Organization(s) Supervisor, Config. Mgt. Info. identified in Part IIIon the Calculation Review form.) Mgr., Design Engineering (Original) w/attach Mgr., Radiological Emergency Planning w/attach nl Yes D.M. Porter w/ attach 24 1999 2_OV
,Fbrida 1W OPR'OAA~O4 ANALYSIS/CALCULATION
SUMMARY
A-C-SUM.FRM DISQpL'NE CONTROL NO. REVISIONLEVEL DOCUMENT IDENTIFICATION NUMBER 89-0014 10 TrLE CLASSIFICATION (CHECK ONE) RC PRESSURE LOOP ACCURACY FOR ES Safety Related LI Non Safety Related MAR/SP/CGWR/PEERE NUMBER 97-02-12-01 &97-02-12-02 VENDOR DOCUMENT NUMBER APPROVAL PRINTED SIGNATURES NAME Design Engineer W.H.P'owell Date _ _ _ _ _ _ _ / 9 Verification Engineer Jim Brannon Date /o/.? ___ Supervisor 1. Lesniak L Date-- ITEMS REVISED Items Revised: ES Low Pressure, Bypass Reset and Bypass Permit and Alarm setpoints. PURPOSE
SUMMARY
- RCITS IN uncertainty has been removed from this calculation. Reason: The RCITS IN loop uncertainty is no longer required as input to calculation 189-0010 (Reference 60) and the RCITS loop input is not tested in SP-0132 (Reference 37). However, the loop IR effects have been revised to incorporate the MAR 97-02-12-02 (Reference 86) RC-163A-PY1 and RC-163B-PY1 IN modification to the new Foxboro IN module.
The HPI Upgrade project altered the current high pressure injection (HPI) system to improve its reliability and capability to meet its defined functional requirements as well as reduce operator burden durng accident scenarios. The change impacts the interfacing system such as the engineered safeguards actuation system (ESAS) by revising the ITS ES RCS Low Pressure setpoint, Bypass Reset and Bypass Permit values. Section I of this calculation summarizes the old and new setpoint values. All setpoint values are summarized on Table IV of Section 2 of this calculation. This revision will incorporate the revised values for the ES RCS Low Pressure Trip, Bypass and Permit and alarm setpoints. The HPI MAR 97-02-12-01 and MAR 97-02-12-02 (References 85 and 86) established the Bypass Reset and Permit setpoints since there are no analytical limits associated with these setpoints.
- This Revision also adds the Signal Monitor and Bypass Alarm setpoint values to Table IV of Section 2.
FL.ORC.A POI: CO]"A&..: R:N NUCLFAR FNOlNEt'NG Ohi1 N CRYSTAL RIVER UNIi'T 3 ENGINEOR CETE Y L SUPERVISOR4 ýkýFa4 4DATE, § RESULTS
SUMMARY
The Revision 9 calculated loop errors have not been changed in this calculation. This calculation applies the existing loop uncertainty errors to the above listed Low Pressure values, assesses the HPI MAR changes for impact on these setpoints and adds the Signal Monitor and BVpass Alarm setpoints.
S. CALCULATION REVIEW 1-1 CALC-R EV.FRM Page 1 of 2 CALCULATION NO./REV. /0 1-89-0014 Rev.-9 4C-A-,Rev4)g PART I - DESIGN ASSUMPTIONIINPUT REVIEW: APPLICABLE [- Yes ] No The following organizations have reviewed and concur with the design assumptions and inputs identified for this calculation: Systems Engineering Signature/Date Nuclear Plant Operations OTHER(S) Signature/Date Signature/Date Signature/Date PART II - RESULTS REVIEW: APPLICABLE -- Yes 0 No The following organizations have reviewed and concur with the results of this calculation and understand the actions which the organizations must take to implement the results. System Engineering Signature/Date Comments: Nuclear Plant Operations Signature/Date Comments: Safety Analysis G roup L-I Yes [-] N/A Signature/Date Signature/Date Comments: Nuclear Plant Maintenance E] Yes 0 N/A ______________ Signature/Date Comments: Nuclear Licensed Operator Training F-1 Yes [-R N/A Signature/Da Signature/Data Comments: Manager, Nuclear Regulatory Compliance F1 Yes L] N/A ______________ Signature/Date Comments: Sr. Radiation Protection Engineer FL Yes I- N/A ______________ Signature/Data Comments: Nuclear Plant EOP Group LII] Yes FL N/A ______________ Signatuie/Date Comments: Design Engineering F] Yes LI N/A ______________ Signature/Date Comments: OTHER: Rl Yes FI1 N/A Signature/Dale Signature/Date Rev. 9/98
,CALCULATION Power f 0*, NO./ftEv. 1-89-0014 Rev. 10 R . CALCULATION REVIEW Page 2 of 2 I PART III - CONFIGURATION CONTROL: APPLICABLE [I Yes M No PC # 99-3260 for R9, ICA RO already addresses configuration control changes The following is a list of Plant procedures/lesson plans/other documents and Nuclear Engineering calculations which require updating based on calculation results review: Document Date Reauired Responsible Organization Upon completion, generate a Precursor Card in accordance with CP-111 for tracking of actions for any items identified in Part III. If calculations are listed, a copy shall be sent to the original file and the calculation log updated to reflect this impact. PART IV - NUCLEAR ENGINEERING DOCUMENTATION REVIEW The responsible Design Engineer must thoroughly review the below listed documents to assess if the calculation requires revision to these documents. If "Yes," the change authorizations must be listed below and issued concurrently with the calculation. Enhanced Design Basis Document E] Yes 0 No (TC#) Vendor Qualification Package [] Yes M No (vQp#) FSAR El Yes 0 No (Letr#) Topical Design Basis Doc. [] Yes 0 No (TC#) Improved Tech. Specification []Yes [ No _ _e__r_) E&SQPM [] Yes 0 No (Tc#) Improved Tech. Spec. Bases El Yes No (LetteF) Other Documents reviewed: Config. Mgmt. Info. System []Yes Z No (CIDP#) _ []Yes [] No (CHANGEDOC.REFERENCE) Design Basis Document []Yes [ No (-rc) __ Yes I] No (CHANGEDNC. REFERENCE) Appendix R Fire Study []Yes [ No (TC#) __ Yes El No (CHANGEDOC. REFERENCE) Fire Hazardous Analysis El Yes No (TC#) _______________El Yesl[] No ________ (CHANGEDOC. REFERENCE) NFPA Code Cormn-xe Dowo. t []Yes [ No (TC#) [] Yes [] No (CHANGEDOC.REFERENCE) PART V - PLANT REVIEWS/APPROVALS FOR INSTRUMENT SETPOINT CHANGE PRC/DNPO approval is required if a setpoint is to be physically changed in the plant through the NEP-213 process PRC Review Required [i] Yeso No PRC Chairman /Date DNPO Review Required I- YesM No DNPO /Date DEI IN 6 DESIGN ENGINEER - PRINED NAME
?W.H. Powell 4 v- . , /
- Rorida CALCULATION VERIFICATION CHECKLIST
*o*RwPReIr Crystal River Unit 3 CALVERCL.FRM CALCULATION NUMBER:
1-89-0014 Rev. 10 YES NO N/A
- 1. Are inputs, including codes, standards, regulatory requirements, procedures, data, and ED El El Engineering methodology correctly selected and applied?
- 2. Have assumptions been identified? Are they reasonable and justified? (re: NEP-101) N El El El
- 3. Are references properly identified, correct, and complete? (re: NEP-101 ) 171 ED
- 4. Have applicable construction and operating experiences been considered? El
- 5. Was an appropriate Design Analysis/Calculation method used? 11 El
- 6. In cases where computer software was used, has the program been verified or reverified in El El accordance with NEP-1 51 for safety related design applications and/or are inputs, formulas, and outputs associated with spreadsheets accurate?
19
- 7. Is the output reasonable, compared to inputs? El El N]
- 8. Has technical design information provided (via letter, REA, IOC, or telecon) by other El N disciplines or programs been verified by that discipline or program?
N]
- 9. Has technical design information provided via letter or telecon from an external Engineering El El Organization or vendor been confirmed and accepted by FPC?
N]
- 10. Has atypical equipment/bus alignment been considered in the calculation? El El El
- 11. Do the calculation results indicate a non-conforming condition exists? (If "Yes," El N immediately notify the responsible Supervisor.)
- 12. Do the results require a change to other Engineering documents? (If "Yes," have these El N El documents been identified for revision on the Calculation Review Form?)
Rev. 2/99
SFlorida REVIEWER CONCURRENCE FORM
"°Pow-er Crystal River Unit 3 RCF.FRM Document Number/Revision Level: 1-89-0014, Rev. 10 Originator: A. T. Barnard _____ _ ___
(Print) (Sign) Signatures delineated below signify whether the department/organization needs to review the Analysis/Calculation. This determination will be made by the individual department/organization, along with the respective discipline. All blocks must be signed by a representative from the respective department/organization.
- Denartment/Oraanization Review Required Signature/Date DE Electrical El Yes Z No N/A**
DE I&C EL Yes M No N/A** DE Mechanical El Yes Z No N/A** DE Structural EL Yes M No N/A** ISI EL Yes Z No N/A** Licensing El Yes M No N/A** Maintenance El Yes M No N/A** Nuclear Safety Management El Yes M No N/A** N/A** Operations El Yes M No Operations (EOP/AP El Yes 0 No N/A** Programs All N/A** El Yes 0 No (Identify App."R", EQ, and/or Fire Protection) Systems Engineering N/A** EL Yes M No N/A** Training E] Yes M No Other N/A** EL Yes El No Other N/A** EI Yes El No
*NOTE: In lieu of signatures by respective departments, the originator may sign for them, based on verbal concurrence (telecons), cc:mail notes, etc. ** The only effect of this revision is to convert an Interim Change to a permanent revision. No changes were made to the calculation. Therefore, the Manager, Design Engineering has waived the requirement for reviewer concurrence.
12/98
Florida INTEROFFICE CORRESPONDENCE Power CORPORATION A-C-XMTL.FRM Design Engineering NA1 E 3415 Office MAC Telephone
SUBJECT:
Crystal River Unit 3 Quality Record Transmittal - Analysis/Calculation TO: Records Management - NR2A The following analysis/calculation package is submitted as the QA Record copy: DOONO (FPC DOCUMENT IDENTIFICATION NUMBER) I REV. 1-89-0014 9 ICA, Rev. 00 SYSTEM(S) RC T Hs TOTAL PAGES TRANSMITTED TITLE FLORIDA POWER CORPORATION RC PRESSURE LOOP ACCURACY FOR ES NUCLEAR ENGINEERING DEPARTMENT CRYSTAL RiVER UN~IT 3 REVIEWED AND ACCEPTED BY: AN-ENGINEER -=~~- DAITEL/10 KWDS (IDENTIFY KEYWORDS FOR LATER RETRIEVAL)_ 4 Calculaton. Insulation Resistance. Setpoint. Accuracv. RC.h l lio. t - -,41ý =--*,*-DATE
-- J, DXREF (REFERENCES OR FILES - LIST PRIMARY FILE FIRST)
SP-132 1-84-0002 MAR 97-02-12-01, MAR 97-02-12-02 VEND (VENDOR NAME) VENDOR DOCUMENT NUMBER (DXREF) SUPERSEDED DOCUMENTS (DXREF) FRAMATOME N/A N/A TAG RC-3A-PT3, RC-3A-PT4, RC-3B-PT3 RC-3A-JX3, RC-3A-JX4, RC-3B-JX3, RC-3A-PI3, RC-3A-P12 RC-3A-PY3, RC-3A-PY4-I, RC-38-PY3 RC-3A-EB1, RC-3B-EB2, RC-3A-EB2, RC-3A-EB3, RC-163A-PY1, RC-163A-PY2 RC-3B-EB3 RC-1 54-PR/TR RC-3-BT1, RC-3-8T7, RC-3-BT2 RC-3A-PS3, RC-3A-PS4, RC-3A-PS5 RC-3-BT4, RC-3-BT5, RC-3-BT6, RC-3-BT10 RC-3-BT8, RC-3-BT3, RC-3-BT9 RC-3A-PS6, RC-3A-PS7, RC-3A-PY4 RC-3-BT1 1, RC-3-BT12 COMMENTS (USAGE RESTRICTIONS, PROPRIETARY, ETC.) This calculation incorporates the changes made by HPI MAR 97-02-12-01 and MAR 97-02-12-02 which revised the Low pressure setpoint and modified the RCITS Foxboro module and adds the Signal Monitor/Bypass Alarm setpoints. Attachment 6 of Revision 9 ha been deleted. .... , th' .. o..... bz6,1;rlzI-zIll* ll f10 S-9.. hzn i9,c * ...- NOTE: Use Tag number only for valid tag numbers (i.e., RCV-8, SWV-34, DCH-99); otherwise, use Part number field (i.e., CSC14599, AC1459). If more space is required, write "See Attachment" and list on separate sheet.
**FOR RECORDS MANAGEMENT USE ONLY **
Quality Record Transmittal received and information entered into SEEK. Entered by: Date (Return copy of Quality Record Transmittal to DE Support Specialist.) DATE I VE$RPKION ENGINEER JR DATE SOR, DESIGN ENG. 7;-. r I *r i" cc: Nuclear Projects (If MARICGWR/PEERý' Calculation Review form Part IIIactions required NYes F1 No Return to Service Related) 0 Yes [I No (IfYes, send copy of the Calculation to the Responsible Organization(s) Supervisor, Config. Mgt. Info. identified in Part IIIon the Calculation Review form.) Mgr., Design Engineering (Original) w/attach Mgr., Radiological Emergency Planning w/attach LI Yes [ No G~io4l cv. 11R" D.M. Porter w/ attach, W.S. Koleff w/attach , W. ,, M.,V LA-l 80o &VIA#Ae& Au --6 1999
Florida ANALYSIS/CALCULATION
SUMMARY
Power A-C-SUM.FRM DOCUMENT IDENTIFICATION NUMBER DTDISCIPLINE I89-0014 CONTROL NO. 9 ICA, I'Re 11 00 REVISION LEVEL TITLE CLASSIFICATION (CHECK ONE) RC PRESSURE LOOP ACCURACY FOR ES Safety Related
- Non Safety Related MARJSP/CGWR/PEERE NUMBER VENDOR DOCUMENT NUMBER APPROVAL PRINTED
_IGNATU5ES NAME Design Engineer W.H. Powell Date 09/23/99 Verification Engineer Jim Brannon _ _ _ _ Date __ _ _ _ __ Supervisor J.R. PaIjug Date Ž.-9" ITEMS REVISED Items Revised: ES Low Pressure, Bypass Reset and Bypass Permit and Alarm setpoints. PURPOSE
SUMMARY
- RCITS IN uncertainty has been removed from this calculation. Reason: The RCITS IN loop uncertainty is no longer required as' I. ation 189-0010 (Reference 60) and the RCITS loop input is not tested in SP-0132 (Reference Y~l..owever, the loop IR effects have been revised to incorporate the MAR 97-02-12-02 (Reference 86) RC-163A-PYI and RC-163B-PY1 IN modification to the new Foxboro IN module.
" The HPI Upgrade project will alter the current high pressure injection (HPI) system to improve its reliability and capability to meet its defined functional requirements as well as reduce operator burden during accident scenarios. The change impacts the interfacing system such as the engineered safeguards actuation system (ESAS) by revising the ITS ES RCS Low Pressure setpoint, Bypass Reset and Bypass Permit values. Section I of this calculation summarizes the old and new setpoint values. All setpoint values are summarized on Table IV of Section 2 of this calculation. This revision will incorporate the revised values for the ES RCS Low Pressure Trip, Bypass and Permit and alarm setpoints. The HPI MAR 97-02-12-01 and MAR 97-02-12-02 (References 85 and 86) will establish the Bypass Reset and Permit .setpoints since there are no analytical limits associated with these setpoints.
- This Revision also add the Signal Monitor and Bypass Alarm setpoint values to Table IVof Section 2.
FLORIDA POWER CORPORATION NUCLEAR ENGINEERING DEPARTMENT CRYSTAL RIVER UNIT 3 REVW D1 ) ACCEPTED BY: ENGINEER , CZ- DATE J !/ 7 SUPERVISORh DATE DAT-EU-JJi4-- RESULTS
SUMMARY
Fo*z 5 *.&k'kk., The Revision 9 calculated loop errors have not been changed in this calculation. This calculation applies the exsiting loop uncertainty errors to the above listed Low Pressure values, assesses the HPI MAR changes for impact on these setpoints and adds'the Signal Monitor and Bypass Alarm setpoints.
CP-213 Page 1 of 2 Florida Power Enclosure 5 CHANGE, TEST OR EXPERIMENT EVALUATION Document No. 1-89-0014 Revision No. 09, ICA, Rev. 00 A. Briefly describe the proposed activity (change, test or experiment): Calculation 1-89-0014, Revision 09, ICA, Rev. 00 is revising;
- 1) the ES Reactor Coolant System Pressure - Low (HPI actuation) setpoint from 1540 psig decreasing to 1665 psig decreasing
- 2) the ES Reactor Coolant System Pressure - Low (HPI actuation) Bypass automatic reset setpoint from 1695 psig increasing to 1795 psig increasing
- 3) the shutdown bypass permit setpoint for bypass of the ES Reactor Coolant System Pressure -
Low HPI actuation trip from 1670 psig decreasing to 1770 psig decreasing
- 4) the HPI Not Bypassed alarm setpoint from 1640 psig decreasing to 1740 psig decreasing
- 5) the HPI Not Reset alarm setpoint from 1640 psig increasing to 1740 psig increasing
- 6) the RC Low Pressure alarm setpoint from 1550 psig decreasing to 1675 psig decreasing This change is being made to accommodate revision of the ITS Allowable Value for the ES Reactor Coolant System Pressure - Low (HPI actuation) setpoint and revision of the ITS Applicable Mode and Other Specified Conditions requirement for operability of the ES Reactor Coolant System Pressure -
Low (HPI actuation) function. These setpoints are being revised based on HPI modifications MAR 97-02-12-01 and MAR 97-02-12-02. Per MAR 97-02-12-02, the ES Reactor Coolant System Pressure - Low (HPI actuation) setpoint Allowable Value is changing from > 1500 psig to > 1625 psig. Per Calculation 1-89-0014, Revision 9, ICA, Rev.00 the new ES Reactor Coolant System Pressure - Low (HPI actuation) in plant setpoint will be 1665 psig decreasing based on the post MAR ITS allowable value of > 1625 psig. The 10 psi margin between the current in plant HPI actuation setpoint of 1540 psig and the current in plant RC Low Pressure alarm setpoint of 1550 psig will be retained for the post MAR alarm setpoint. Therefore, the new RC Low Pressure alarm setpoint will be 1675 psig decreasing. The RC Low Pressure alarm is an operator aid device only and it has no safety-related function. Also, per MAR 97-02-12-02, the ITS Applicable Mode and Other Specified Conditions requirement for operability of the ES Reactor Coolant System Pressure - Low (HPI actuation) is changing from > 1700 psig to >1800 psig. The MAR will change the ES Reactor Coolant System Pressure - Low (HPI actuation) Bypass automatic reset setpoint from 1695 psig to 1795 psig to ensure this Applicable Mode and Other Specified Condition requirement is met. The adjustable bistable reset deadband setting of 25 psi is being retained by the MAR setpoint change. This will result in a ES Reactor Coolant System Pressure - Low (HPI actuation) Bypass Permit setpoint of 1770 psig. These setpoint changes have been validated/verified by Calculation 1-89-0014, Revision 9, ICA, Rev.00. The 55 psi margin between the current in plant ES Reactor Coolant System Pressure - Low (HPI actuation) Bypass automatic reset setpoint of 1695 psig increasing and the HPI Not Reset alarm setpoint of 1640 psig increasing will be retained for the post MAR alarm setpoint. Therefore, the new HPI Not Reset alarm setpoint will be 1740 psig increasing. The current practice of having the HPI Not Bypassed Alarm equal to the HPI Not Reset alarm will be retained. The HPI Not Bypassed alarm actuates on decreasing pressure vice HPI Not Reset Alarm actuating on increasing pressure. Therefore, the new HPI Not Bypassed alarm setpoint will be 1740 psig decreasing. This alarm is an operator aid only and it has no safety-related function. CP-213 Rev. 7 Enclosure 5
CP-213 Page 2 of 2 B. Disposition: B.1 List the applicable previously approved SA/USQD numbers and titles: SA/USQD No. 99-0010, Revision 2 HPI Upgrade Project B.2 Describe how the proposed activity is covered by the approved SA/USQD and whether or not all aspects of this change been addressed in the SA/USQD. SA/USQD 99-0010 has justified the specific values for the revised ITS ES Reactor Coolant System Pressure - Low HPI actuation trip setpoint and revised ITS Applicable Mode and Other Specified Conditions requirement for operability of the ES Reactor Coolant System Pressure - Low HPI actuation setpoint discussed in Section A above. The conclusions of this discussion remain unchanged by the results of Calculation 1-89-0014, Revision 9, ICA, Rev. 00. The alarm setpoints are operator aids only. The new post MAR alarm setpoints will be based on margins and relationships between existing alarms and actuation setpoints in an effort maintain the preexisting coordination. NOTE: If the proposed activity is not completely bounded by the approved SA/USQD, either revise the existing SA/USQD or prepare a separate SA/USQD. Preparer: / /?, / (Prin e Name) -(Signature) (Date) Reviewer: L ,
$, Ie -P (PrintedName) (Signature) (6ate)
Interpretation
Contact:
/ I (InterpretationContactfor New Proceduresor ProcedureRevisions Only) CP-213 Rev. 7 Enclosure 5
Rodida INTEROFFICE CORRESPONDENCE Power COAP lI Design Engineering A-C-XMTL.FRM NAIE 3415 Office MAC Telephone
SUBJECT:
Crystal River Unit 3 Quality Record Transmittal - Analysis/Calculation TO: Records Management - SA2A The following analysis/calculation package is submitted as the QA Record copy: OOCNO (FPC DOCUMENT IDENTIFICATION NUMBER) I REV. SYSTEM(S) TOTAL PAGES TRANSMITTED 1-89-0014 9 -7 8RC IO TITLE RC PRESSURE LOOP ACCURACY FOR ES KWDS (IDENTIFY KEYWORDS FOR LATER RETRIEVAL) Calculation,. Insulation Resistance, Setpoint, Accuracy. RC, HPI, LPI. ES DXREF (REFERENCES OR FILES - LIST PRIMARY FILE FIRST) SP-132 1-84-0002 VEND (VENDOR NAME) VENDOR DOCUMENT NUMBER (DXREF) SUPERSEDED DOCUMENTS (DXREF) FRAMATOME N/A 1-89-0014 , Rev. 8 TAG RC-3A-PT3, RC-3A-PT4, RC-3B-PT3 RC-3A-JX3, RC-3A-JX4, RC-3B-JX3, RC-3A-P13, RC-3A-P12 RC-3A-PY3, RC-3A-PY4-1, RC-3B-PY3 RC-3A-EB1, RC-3B-EB2, RC-3A-EB2, RC-3A-EB3, RC-163A-PY1, RC-163A-PY2 RC-3B-EB3 RC-154-PR1TR RC-3-BT1, RC-3-BT7, RC-3-BT2 RC-3A-PS3, RC-3A-PS4, RC-3A-PS5 RC-3-BT4, RC-3-BT5, RC-3-BT6, RC-3-BT1O RC-3-BT8, RC-3-BT3, RC-3-BT9 RC-3A-PS6, RC-3A-PS7, RC-3A-PY4 RC-3-BTl1, RC-3-BT12 PART NO. COMMENTS (USAGE RESTRICTIONS, PROPRIETARY, ETC.) This calculation incorporates the control complex temperature range change. NOTE: Use Tag number only for valid tag numbers (i.e., RCV-8, SWV-34, DCH-99); otherwise, use Part number field (i.e., CSC14599, AC1459). If more space is required, write "See Attachment" and list on separate sheet.
"*FOR RECORDS MANAGEMENT USE ONLY Quality Record Transmittal received and infonmation entered into SEEK.
Entered by: Date (Return copy of Quality Record Tr smittal to DE Support Specialist.) DESIGN ENGINEER . DATE VERIFICATION ENGINEE f. W.H. Powell .*/* s/7j) J' . { SUPERl SOR, DESIGN ENG.
--.
4 ' I."-. DATE cc: Nuclear Projects (If MAR/CGWRJPEERE Calculation Review for PnakiI ctions required SYes [] No Return to Service Related) 0 Yes 0 No (IfYes, send copy of the Calculation to the Responsible Organization(s) Supervisor, Config. Mgt. Info. dentified in Part III on the Calculation Review form.) Mgr., Design Engineering (Original) w/attach Mgr., Radiological Emergency Planning w/attach El Yes Z
., ... i" oJ , . .
C- *0ý Ck ~0i~ /VXw/- iI-sr Om t rlcavezv-NUCLEAR FLORIDA POWER CORPORATION
-ENGINEERING CRYSTAL RIVER UNIT 3 DEPARTMEN U0, REVUI'Eb A ACCEPTED BY-Re.59 .o 0of z od ENGIMNEER Exhlbq2 NEP-213 (Page 21 of 4s)
DATE ?Z16 9? co SSUP '/ISOR. II
,WPowe Co. .... 70" ANALYSIS/CALCULATION
SUMMARY
DISCIPUNE A-C-SUM.FRM I CONTROL NO REVISION LEVEL DOCUMENT IDENTIFICATION NUMBER 89-0014 9 TITLE CLASSIFICATION (CHECK ONE) RC PRESSURE LOOP ACCURACY FOR ES Safy Related
-' Non Safety Related MAR/SPICGWRPEERE NUMBER VENDOR DOCUMENT NUMBER APPROVAL PRINTED SIGNATURES NAME Design Engineer W.H. Powell Date 2- 22 08/09199 Verification Engineer . ./.J.R. Brannon Date _ _"_ _ __!_"_ __
Supervisor )J,)/ _j . 1-? 1..tesjl,* k ARPaijug- L,M . L-CeU1,qK Da te ... ... . .. . . .. . . . . ..... . ITEMS REVISED Items Revised: Complete calculation and deleted Attachments 5 &8 PURPOSE
SUMMARY
The purpose of Revision 9 is as follows:
" Incorporate changes from instrument loop components that were identified inCalculation M-97-0020 Rev. 0 (Reference 77) as located inthe Control Room complex and could be subjected to revised temperature profiles. The accident and normal ambient temperature ranges that will be applied are as follows; Normal = A20OF (See Assumption 1)
Accident = A34OF for Zones 13 and 58 (See Assumption 1) The Detailed Analysis/Calculation Section of this calculation will be revised to encompass the effects of the above listed temperature ranges as well as the Operational Consideration and Result Conclusion Sections. + J,* 1 -1#
" The I&C Design Criteria For Instrument Loop Uncertainty Calculation" has been recently revised (Rev.X to incorporate a Graded Approach Method for instrument loops components that are calibrated on different time intervals. This new method has been identified as a Split Loop method. This method is detailed inAttachment #5 to the Design Criteria (see D137 below) and specifies the method to be used for Instrumentation inside containment and outside of containment. This calculation will provide a Category A/B Partial Spilt Loop method.
Attachment 5 circuit diagram will be added to the body of calculation and the attachment deleted.
" The previous revision to this calculation added an Attachment 8 which provided a revised estimate of the uncertainty for the signals sent to the T'SAT Meters and the Plant Computer/RECALL/SPDS using the Graded Approach found inthe CR3 I&C Design Criteria For Instrumentation Loop Uncertainty Calculations, Revision 2. This attachment will be incorporated into the body of the calculation and the Attachmenft 5&8 will be deleted.
RESULTS
SUMMARY
Calculated loop errors have been revised and detailed in Tables I through VIII. All of the previous setpolnts (AL, AF and CE) have been reduced and redefined by applying a new split-loop method. However, the actual HP4LPI trip setpoints have remained unchanged by adding additional engineering margin to the newly calculated total loop uncertainty (TLU).
* "ORI-WD'A POWER MR POR"A T-:PON NUCLEAR ENGINEERING DEPARTMENT CRYSTAL RIVER UNIT 3 KhVEAED BY:
SUPERISORDATE________
COPOmAs, CALCULATION REVIEW CALC-REV.FRM Page 1 of 2 CALCULATION NO./REV. 1-89-0014 Rev. 9 PART I - DESIGN ASSUMPTIONIINPUT REVIEW: APPLICABLE Q1 Yes F- No The following organizations have reviewed and concur with the design assumptionsan inputs identified for this calculation: Systems Engineering IZ Nuclear Plant Operations M M wiAR,- OTHER(S) Sinature/Date / I yPIA DVZeeia.tiL4 fgnature/D(IAý !ýMogL7f Signature/Date PART II - RESULTS REVIEW: APPLICABLE N] Yes FD No The following organizations have reviewed and concur with the results of this calculation apd understand the actions which the organizations must take to implement the results. System Engineering ///J, *Aij, ~1z Comments: Nuclear Plant Operations (".(7,-Z. Comments: Safety Analysis Group IFA Yes E] N/A Al' . ,l Comments:
.- .. -.'.
Nuclear Plant Maintenance Yes LI N/A 0 e.CJLJA izn Comments: ADD5P :5P-is CM'T5 L-4St Nuclear Licensed Operator Training L- Yes r* N/A ___________ Srgnature/Date Comments: Manager, Nuclear Regulatory Compliance r- Yes f N/A Signature/Oate Comments: Sr. Radiation Protection Engineer E] Yes M N/A ______________ SignatureJ)ate Comments: Nuclear Plant EOP Group [- Yes -I N/A _-_______ /__i_"_
"ightu '~'t Comm ents:
Design Engineering VE-C-HAMJILAE Yes n- N/A 1"4A,-02*1fI K. Comments: 'Wt-ut f , 9/ OTHER: __ Yes F1 N/A Signature/Oate
lkxida CALCULATION REVIEW
. . . ...... P a g e 2 of 2 PART III - CONFIGURATION CONTROL: APPLICABLE M Yes n- No PC # 'f -3,(
The following is a list of Plant procedures/lesson plans/other documents and Nuclear Engineering calculations which require updating based on calculation results revi Document Date Required 1 'A Responsible Organization SP-132 ./2-14, er . Se.C. -,c , -: 1-84-0002 .'-c. ?)*---a-.- E .tAe.r-17 1-89-0010 1-96-0002 ftjue- 'SOJý,6 xtj:j,,+ M-97-0020 fL rae,(,ý b 1-88-0024 - 'h e M-97-0076 e e M-97-0075 1-84-0003 5?'-130 ye -I I r1k -e Upon completion, generate a Precursor Card in accordance with CP-1 11 for tracking of actions for any items identified in Part III. If calculations are listed, a copy shall be sent to the original file and the calculation log updated to reflect this impact PART IV - NUCLEAR ENGINEERING DOCUMENTATION REVIEW The responsible Design Engineer must thoroughly review the below listed documents to assess ifthe calculation requires revision to these documents. If "Yes," the change authorizations must be listed below and issued concurrently with the calculation. Enhanced Design Basis Document [] Yes 0 No (TC#) Vendor Qualification Package [] Yes I] No (voP") FSAR El Yes M No (Le-) Topical Design Basis Doc. [] Yes 0 No (TC*) Improved Tech. Specification [] Yes Z No (Lettoa) E&SQPM [] Yes [ No (Tc') Improved Tech. Spec. Bases. El Yes [K No (Letter#) Other Documents reviewed: Config. Mgmt. Info. System Yes [ No (CIDP_) _] Yes [] No DOC.REFERENCE) (CHANGE Design Basis Document 0l Yes Z No (Tco) _E Yes El No DOC.REFERENCE) (CHANGE Appendix R Fire Study El Yes 0 No (TCO __ Yes E] No (CHANGE DOC.REFERENCE) Fire Hazardous Analysis El Yes Z No (TC#) El Yes El No (CHANGEDOC.REFERENCE) NFPA Code Caftmanos Doment El Yes 0 No El Yes El No [] (CHANGEDOC.REFERENCE) PART V - PLANT REVIEWSIAPPROVALS FOR INSTRUMENT SETPOINT CHANGE PRC/DNPO approval is required ifa setpoint is to be physically changed in the plant through the NEP-213 process. PRC Review Required L- Yes [ No PRu Chnairman /Date DNPO Review Required LI1 Yes M No DNPO /Date DESIGN ENGINEER/DATE I A/ DESIGN ENGINEER - PRINTED NAME I 4ýA) W.H. Powell
Florida CALCULATION VERIFICATION CHECKLIST Power 0 Crystal River Unit 3 CALVERCL.FRM t ra, ,.i II n-run., ~1l LAOCD 0 I ev. 1-89001 I YES NO N/A
- 1. Are inputs, including codes, standards, regulatory requirements, procedures, data, and 0 11 El Engineering methodology correctly selected and applied?
- 2. Have assumptions been identified? Are they reasonable and justified? (re: NEP-101) El El
- 3. Are references properly identified, correct, and complete? (re: NEP-101 )
0l
- 4. Have applicable construction and operating experiences been considered? 0]
El 0l
- 5. Was an appropriate Design Analysis/Calculation method used? []
El
- 6. In cases where computer software was used, has the program been verified or reverified in accordance with NEP-151 for safety related design applications and/or are inputs, 0]
formulas, and outputs associated with spreadsheets accurate? []
- 7. Is the output reasonable, compared to inputs?
- 8. Has technical design information provided (via letter, REA, IOC, or telecon) by other disciplines or programs been verified by that discipline or program?
- 9. Has technical design information provided via letter or telecon from an external Engineering El Organization or vendor been confirmed and accepted by FPC?
- 10. Has atypical equipment/bus alignment been considered in the calculation? El 0]
- 11. Do the calculation results indicate a non-conforming condition exists? (If "Yes," El immediately notify the responsible Supervisor.)
- 12. Do the results require a change to other Engineering documents? (If "Yes," have these 0 El El documents been identified for revision on the Calculation Review Form?)
Rev. 6/99
*Florida REVIEWER CONCURRENCE FORM CPower Crystal River Unit 3 RCF.FRM Document Number/Revision Level: 1_-_92-
_ _ON/_ i _v__q Originator: A. T. Barnard __ _- _ (Print) (Sign) Signatures delineated below signify whether the department/organization needs to review the Analysis/Calculation. This determination will be made by the individual department/organization, along with the respective discipline. All blocks must be signed by a representative from the respective department/organization.* Denartment/Oraanization Review Required Signature/Date DE Electrical El Yes No 5a DE I&C Yes El No DE Mechanical [] Yes El No DE Structural El Yes No
~4ALAIZZ2/ 7-1-7 7 ISI Fl Yes No El Licensing El Yes El No Maintenance [ Yes El No entL AV- /lh Nuclear Safety Management [] Yes El No ALL zJIIY4I Operations Yes No Operations (EOP/AP) I] Yes No efite"; LL I//IY9k Programs EQ I] Yes No (Identify App. "R", EQ, and/or Fire Protecti on)
Systems Engineering R Yes El No Training EL Yes No Other App. R / Fire Prot. El Yes El No f 0ther EL Yes No
*NOTE: In lieu of signatures by respective departments, the originator may sign for them, based on verbal concurrence (telecons) , cc:Mail notes, etc.
12/98 Exhibit 14 NEP-213 (Page 46 of 46)
Florida INTEROFFICE CORRESPONDENCE Power CORPORATION A-C-XMTL.FRM Nuclear Engineering NT3C 1565 Office MAC Telephone
SUBJECT:
Crystal River Unit 3 Quality Document Transmittal - Analysis/Calculation TO: Records Management - NR2A The following analysis/calculation package is submitted as the QA Record copy: DOCNO (FPC DOCUMENT IDENTIFICATION NUMBER) REV- SYSTEM(S) TOTAL PAGES TRANSMITTED 1-89-0014 8 RC 2 344,*-. TITLE RC PRESSURE LOOP ACCURACY FOR ES KWDS (IDENTIFY KEYWORDS FOR LATER RETRIEVAL) Same as Rev. 6 DXREF (REFERENCES OR FILES - LIST PRIMARY FILE FIRST) 1-84-0002 1-96-0002 1-97-001 5 VEND (VENDOR NAME) VENDOR DOCUMENT NUMBER (DXREF) SUPERSEDED DOCUMENTS (DXREF) FPC N/A N/A TAG Same as Rev. 6 PART NO. Same as Rev. 6 COMMENTS (USAGE RESTRICTIONS, PROPRIETARY, ETC.) NOTE: Use Tag number only for valid tag numbers (i.e., RCV-8, SWV-34, DCH-99), otherwise; use Part number field (i.e., CSC14599, AC1459). If more space is required, write "See Attachment" and list on separate sheet. DESIGNENGINEER DATE ER)CTNEIIER7DATE SUPERVISOR, NUCLEAR ENG. DATE iSKle 7->~ 7Le"39 7 cc: Nuclear Projects (If MAR/CGWR/PEERE Calculation Review form Part IIIactions required [:]Yes Z No Return to Service Related) [ Yes Z No (If Yes, send copy of the form to Nuclear Regulatory Assurance and a Supervisor, Config. Mgt. Info. copy of the Calculation to the Responsible Organization(s) identified in Mgr., Nucl. Operations Eng. (Original) w/attach Part IIl on the Calculation Review form.) Rev. 3/97
Floid ANALYSIS/CALCULATION
SUMMARY
Powe
........... A-C-SUM.FRM DISCIPLINE CONTROL NO. REVISION LEVEL DOCUMENT IDENTIFICATION NUMBER 89-0014 8 TITLE CLASSIFICATION (CHECK ONE)
RC PRESSURE LOOP ACCURACY FOR ES [ Safety Related El Non Safety Related MAR/SP/CGWR/PEERE NUMBER SP 95-002 VENDOR OOCUMENT NUMBER C-423-5510-066 APPROVAL PRINTED SIGNATURES NAME Design Engineer . *. - M. D. Lord Date //, -, 11/11/97 Verification Engineer S. Z. Barkofski Date_______________1/37 Supervisor W. S. Koleff Date //ho /'q ITEMS REVISED New Attachment 8 added. Revised Sheets 28, 32, 35, 36, 51, 52, 53, 57, 58, 61, 64, 66, 69, & 74. PURPOSE
SUMMARY
The purpose of this revision is to apply the CR3 I&C Design Graded Approach (as described in the I&C Design Criteria for Instrument Loop Uncertainty Calculations) to the signal sent to the T'SAT Meters, the Plant Computer, and RECALL/SPDS. The Graded Approach had not been developed when the calculation was rewritten in Revision 6 to take advantage of this less regorous method for determining uncertaintie. for less critical functions. The results of this calculation will be used to revise calculations 1-84-0002 and 1-96-0002. In addition this revision also e.tahlishes a setpoint for the Low Temperature Overpressure Proteption II TOP) alarm based upon the LTOP initiation setpoint determined by 1-97-0015. RESULTS
SUMMARY
The Calibrated Loop Error (under normal conditions) for the signal to the T'SAT Meters was reduced by + 15.00 and -23.50 psig using the Category B Graded Aporoach versus the approach initially adopted. Under accident the error was reduced by +/-39.50 psig using the Category B Graded Approach. The Calibrated Loop Error (under normal conditionns) for the signal to RECALL/SPD' was redurc.d hy + 18.50 psig. Under accident conditions the error was reduced by +/-23.25 psig. The LTOP alarm setpoint remains 50 psig below the LTOP initation setpoint which has been reduced by 1 0015 to 442.6 psig. Therefore the npw I TOP alarm setpnint is 39296 npqig Rev. 3/97
Foknoda
-Power. CALCULATION REVIEW CA.C-REV..FM Page ýof CALCULATION NO/IREV.
I1-89-0014, Rev. 8 PART I - DESIGN ASSUMPTION/INPUT REVIEW: APPLICABLE E Yes E] No The following organizations have reviewed and concur with the design assumptions and inputs identified for this calculation: Nuclear Plant Technical Support .r - rl o Signature/Date System Engr Nuclear Plant Operations OTHER(S) 7 PART II - RESULTS REVIEW: APPLICABLE Z Yes E] No The following organizations have reviewed and concur with the results of this calculation and understand the actions which the organizations must take to implement the results. Nuclear Plant Technical Support /A/-.v,<-Ti.vN
//,/
Signature/Date System Engr Nuclear Plant Operations 1111r-117 Signature/Date Nuclear Plant Maintenance /. Z Yes E] N/A nte/Date (
-
Nuclear Licensed Operator Training Signature/Date [] Yes Z N/A Manager, Site Nuclear Services Signature/Date El Yes 0 N/A Sr. Radiation Protection Engineer Signature/Date F] Yes MN/A OTHERS: Signature/Date 3/JylarueiL/aie Ie v. 9:97
S.. fl~a Power Ceft'OnA,.0~ CALCULATION REVIEW CALC-REV.FRM Page 1 of/ 3 CALCULATION NO./REV. I1-89-0014, Rev. 8 PART I - DESIGN ASSUMPTION/INPUT REVIEW: APPLICABLE 0 Yes El No The following organizations have reviewed and concur with the design assumptions and inputs identified for this calculation: Nuclear Plant Technical Support Sigature/Date System Engr Nuclear Plant Operations Signature/Date OTHER(S) Operations - EOP Group Signature/Date Maintenance Signature/Date Licensina Signature/Date PART II - RESULTS REVIEW: APPLICABLE Z Yes R No The following organizations have reviewed and concur with the results of this calculation and understand the actions which the organizations must take to implement the results. Nuclear Plant Technical Support DQ ,,"CVAW^, 4 iny!, Sigrrturei/Date System Engr Nuclear Plant Operations Signature/Date Nuclear Plant Maintenance Signature/Date Z Yes nI N/A Nuclear Licensed Operator Training SignaturelDate [] Yes Z N/A Manager, Site Nuclear Services Signature/Date [-] Yes Z N/A Sr. Radiation Protection Engineer Signature/Date E] Yes MN/A OTHERS: Signature/Date Signature/Date Rev. 8/97
,, ; CALCULATION REVIEW Page iof imý l CALCULATION NO/JREV.
1-89-001 4, Rev. 8 PART III - CONFIGURATION CONTROL: APPLICABLE Z Yes LI No The following is a list of Plant procedures/lesson plans/other documents and Nuclear Engineering calculations which require updating based on calculation results review: Document Date Required Responsible Organization 1-84-0002 /2.-11 I/f NOE 1-96-0002 12-_/?t I-)" NOE SP-132 12J31,f'id Maintenance
# Z -- Y3 (
Upon completion, forward a copy to the Manager, Nuclear Regulatory Assurance Group for tracking of actions if any items are identified in Part Ill. If calculations are listed, a copy shall be sent to the original file and the calculation log updated to reflect this impact. PART IV - NUCLEAR ENGINEERING DOCUMENTATION REVIEW The responsible Design Engineer must thoroughly review the below listed documents to assess if the calculation requires revision to these documents. If "Yes," the change authorizations must be listed below and issued concurrently with the calculation. Enhanced Design Basis Document Ej Yes E No (Tc#) Vendor Qualification Package (VoP#) FSAR [I Yes E No (Letter#) Topical Design Basis Doc. El Yes 0 No (TC#) Improved Tech. Specification El Yes Z No (Letterf) E/SQPM El Yes E No (TC4) Improved Tech. Spec. Bases El Yes 0 No (Letter#) Other Documents reviewed: Config. Mgmt. Info. System 0 Yes El No (CIDPffI 97 /j/ q/ IDS RC-3A-PS4 M Yes [I No Ptrc" V7 - 6 75 (CHANGEDOC. REFERENCE) Analysis Basis Document El Yes [R No (TC#) El Yes El No (CHANGEDOC. REFERENCE) Design Basis Document El Yes 0 No (TC#) __ Yes El No (CHANGEDOC. REFERENCE) Appendix R Fire Study El Yes ER No (TC#) El Yes E] No (CHANGEDOC. REFERENCE) Fire Hazardous Analysis El Yes 0 No ITc#) E] Yes [] No ICHANGEDOC. REFERENCE) NFPA Code Conformance Document El Yes S No (TC#) El Yes [E No (CHANGEDOC. REFERENCE) PART V - PLANT REVIEWS/APPROVALS FOR INSTRUMENT SETPOINT CHANGE PRC/DNPO approval is required if a setpoint is to be physically changed in the plant through the NEP 213 process. PRC Review Required [ Yes LI No PRC Chairman /Date DNPO Review Required M Yes F] No DNPO /Date DESIGN ENGINEER/DATE DESIGN ENGINEER- PRINTED NAME
,./// / ? I If : Lo,.L
-P.
Rev. 8/97
Florida Power CALCULATION VERIFICATION REPORT COflPofA7.oN Crystal River Unit 3 CALVERRP.FRM Page 1 of 1 CALCULATION NUMBER 1-89-0014, Rev. 8 PROJECT/TITLE RC PRESSURE LOOP ACCURACY FOR ES YES NO N/A E] Li Are inputs, including codes, standards, regulatory requirements, procedures, data, and Engineering methodology correctly selected and applied? 2.Li LI [] Have assumptions been identified? Are they reasonable and justified? (See NEP 101, V.c, for discussion on references). LI LI Are references properly identified, correct, and complete? (See NEP 101, V.c., for discussion on assumptions and justification.)
- 4. Li El ni Have applicable construction and operating experiences been considered?
- 5. E] [] Was an appropriate Design Analysis/Calculation method used?
Li
- 6. LI X In cases where computer software was used, has the program been verified or reverified in accordance with NEP 135 for safety related design applications and/or are inputs, formulas, and outputs associated with spreadsheets accurate?
LI fl Is the output reasonable compared to inputs? Li Has technical design information provided via letter, REA, IOC or telecon by other
#P7lv/Ic;dsciplines or programs been verified by that discipline or program?
9.L Li [] Has technical design information provided via letter or telecon from an external Engineering Organization or vendor been confirmed and accepted by FPC? 10.Eli [] Li Do the calculation results indicate a non-conforming condition exists? If "Yes," immediately notify the responsible Supervisor.
- 11. X Li Ii Do the results require a change to other Engineering documents? If "Yes," have these documents been identified for revision on the Calculation Review Form?
I have performed a verification on the subject calculation package and find the results acceptable. VERIFICATION ENGINEER DATE SUPERVISOR, NUCLEAR ENGINEERING DATE "g~. Z.t tZ9-S -/'ap /u Rev. 3197 RET: Optional RESP: Nuclear Engineering 912 247
Florida INTEROFFICE CORRESPONDENCE oio:. Power
.00.00?CORPORATION Nuclear Engineerin-q NAIE 240-3490 Office MAC Telephone
SUBJECT:
Crystal River Unit 3 Quality Document Transmittal - Analysis/Calculation TO: Records Management- NR2A The following analysis/calculation package is submitted as the QA Record copy: DOCNO (FPC DOCUMENT IDENTIFICATION NUMBER) REV. SYSTEM(S TOTAL PAGES TRANSMITTED 1-89-0014 j7 RIC 7 TITLE RC PRESSURE LOOP ACCURACY FOR ES KWOS (IDENTIFY KEYWORDS FOR LATER RETRIEVAL) Same as Rev. 6 DXREF (REFERENCES OR FILES - LIST PRIMARY FILE FIRST) Same as Rev. 6 VEND (VENDOR NAME) VENDOR DOCUMENT NUMBER (DXREF) SUPERSEDED DOCUMENTS (DXREF) FPC C-423-5510-066 1-88-0024 TAG Same as Revision 6 PART NO. COMMENTS (USAGE RESTRICTIONS, PROPRIETARY, ETC.) NOTE: Use Tag number only for valid tag numbers (i.e., RCV-8, SWV-34, DCH-99), otherwise; use Part number field (i.e., CSC14599, AC1459). If more space is required, write "See Attachment" and list on separate sheet. DESIGN ENGINEER DATEl VERIFICA] ENI. DATE ISUPERVISOR, NUCLEAR ENG. _ DATE cc: MAR Office (If MAR Related) 0 Yes 4I No FPlant Document Updates Required WYes 0 No (IfYes, send copy of the Mgr. Nucl. Config. Mgt. (Calculation Review form to Nuclear Ucensing and a copy of the Calculation to Mgr., Nucl. Eng. Design he Pesponsible Organization(s) identified in Part IIIon the Calculation Review form.) (Original) w/attach AlE -eet-- 6 t- tj *6 E]Yes 0 No (If yes, Transmit w/attach) 't O/-f5L
/ WET: L oPe Rev, !SA . f& ---J/A-T44 Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
RFlorida Power
.Orpora tln ANALYSI SICALMOLATI ON SUMMNARY DOCUMENT IDENTIFICATION NUMBER 89-0014 7 I DISCIPLINE CONTROL NO. REVISION LEVEL TITLE CLASSIFICATION (CHECK ONE)
RC PRESSURE LOOP ACCURACY FOR ES [] Safety Related I] Non Safety Related MAR/SP/CGWR/PEERE NUMBER SP 95-002 VENDOR DOCUMENT NUMBER C-423-5510-066 REVISION ITEMS REVISED APPROVALS Design Engineer 2. Z? Pages 60, 68, & 69 Date '____" Verification Engineer Date/Method* ! ___ Supervisor _ _ _ _ _ __._ __-_ Date , *h3l*-
- VERIFICATION METHODS: R - Design Review; A - Alternate Calculation; T - Qualification Testing DESCRIBE BELOW IF METHOD OF VERIFICATION WAS OTHER THAN DESIGN REVIEW PURPOSE
SUMMARY
This revision corrects minor arithmetic and typographical errors made in Revision 6. RESULTS
SUMMARY
Tolerance on Table VI of Section VI (Results/Conclusions) was corrected. Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
AN[b= .. CALCULATION REVIEW Page 1 of 2 CALCULATION NO,/REV. 1-89-0014/Rev. 7 PART I - DESIGN ASSUMPTION/INPUT REVIEW The following organizations have reviewed and concur with the design assumptions and inputs identified for this calculation: Nuclear Plant Technical Support System Signature/Da Engr Nuclear Plant Operations Sign ure/Date OTHER(S) 7 Signature/Date PART II - RESULTS REVIEW The following organizations have reviewed and concur with the results of this calculation and understand the actions which the organizations must take to implement the results. Nuclear Plant Technical Support System _ I___ _ ___ __________ Engr Slgnature/Dalte Nuclear Plant Operations Nuclear Plar Maintenance rrnrrw -- .rrý~ Signatu ' , , A, [3"Yes E- N/A Nuclear Licensed Operator Training E* Yes Z N/A Signature/Date Manager, Site Nuclear Services L- Yes E N/A Signature/Date Sr. Radiation Protection Engineer Signature/Date D- Yes IZ N/A OTHERS: Signature/Date Signature/Date Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
AKf CALCULATION REVIEW Page 2 of 2 CALCULATION NO./REV. 1-89-0014/Rev. 7 PART III - CONFIGURATION CONTROL The following is a list of Nuclear Engineering and Plant procedures/lesson plans/other documents which require updating based on calculation results review: Document Date Required Responsible Organization
?
SI-13 2 -7 2 I*(% 6-'.ke -*,rA 6-6,A.. ,J5l;I Upon completion, forward a copy to the Manager, Nuclear Licensing for tracking of actions if any items are identified in Part Ill. PART IV - PLANT REVIEWS/APPROVALS FOR FIELD SETPOINT CHANGE PRC review is required if a full 10CFR50.S9Safety Evaluation is performed. DNPO approval is required if a setpoint is to be physically changed in the plant. PRC Review Required r] Yes El No PRC Chairman /Date DNPO Review Required [1 Yes El No [DESIGN ENGiNEr;R/DATE DNPO /Date Rev. 6/85 RET: Life of Plant RESP: Nuclear Englneefin9
oe* Florida INTEROFFICE CORRESPONDENCE -oPo_, Power 4o C R P0 RATION Nuclear Enaineerina Desian NA1E 231-5619 Office MAC Telephone
SUBJECT:
Crystal River Unit 3 Quality Document Transmittal - Analysis/Calculation File: CALC TO: Records Management - NR2A The following analysis/calculation package is submitted as the QA Record copy: DOCNO (FPC DOCUMENT IDENTIFICATION NUMBER) REV. SYSTEM($) TALPAGES TRANSMITTED 1-89-0014 6 RC F ý100 TITLE RC PRESSURE LOOP ACCURACY FOR ES KWDS (IDENTIFY KEYWORDS FOR LATER RETRIEVAL) Calculation, Insulation Resistance, Setpoint, HPI, LPI, ES, Accuracy DXREF (REFERENCES OR FILES - LISTPRIMARY FILE FIRST) SP95-002,_1-83-0001,1-89-0010,_1-84-0002, SP-130, SP-132, SP-135A, SP-135B, SP-135C, 1-84-0001 VEND (VENDOR NAME) VENDOR DOCUMENT NUMBER (DXREF) SUPERSEDED DOCUMENTS (DXREF) FPC C-423-5510-066 1-89-0014, Rev. 5 TAG See Attached PART NO. COMMENTS (USAGE RESTRICTIONS. PROPRIETARY, ETC.) NOTE: Use Tag number only for valid tag numbers (i.e., RCV-8, SWV-34, DCH-99), otherwise; use Part number field (i.e., CSC14599, AC1459). If more space is required, write 'See Attachment, and list on separate sheet. DESIGN ENGINEER DATEI VERIFI ON ENEEýEER, DATE SUPERVISOR, NUCLEAR ENO. ,. DATE cc: MAR Office (If MAR Related) 0 Yes5'" No Plant Document Review Required XYes 0 No MAR/Project File Supervisor, Nuclear Document Control w/ Plant Doc. Rev. Mgr. Nucl. Config. Mgt. Eval. and Analysis / CaIc. Summary (If Plant Doc. Rev., is Yes) File (CALC) - FPES "Original" w/attach A/E BWNT 13 Yes 0 No Mgr., Site Nucl. Eng. Serv. w/attach (Ifyes, Transmit w/attach) 4 p" . D. L o ,rJ La./.-r'r'. C._(. 4- 4-rJrKL ,. Rev. 111/94 RET: Life of Plant RESP: Nuclear Engineering 900 628
QUALITY DOCUMENT TRANSMITTAL (PAGE 2 OF 2) CALCULATION 1-89-0014, REV. 6 Tag Number RC-3A-PT3 RC-3A-PT4 RC-3B-PT3 RC-3A-PY3 RC-3A-PY4-1 RC-3B-PY3 RC-3-BT1 RC-3-BT7 RC-3-BT2 RC-3-BT8 RC-3-BT3 RC-3-BT9 RC-3A-JX3 RC-3A-JX4 RC-3B-JX3 RC-3A-EB 1 RC-3B-EB2 RC-3A-EB2 RC-3A-EB3 RC-3B-EB3 RC-3A-PS3 RC-3A-PS4 RC-3A-PS5 RC-3A-PS6 RC-3A-PS7 RC-3A-PY4 RC-3A-P13 RC-3B-PI2 RC-1 63A-PY1 RC-1 63B-PY1 RC-154-PR/TR RC-3-BT4 RC-3-BT5 RC-3-BT6 RC-3-BTI0 RC-3-BT1 1 RC-3-BT12 Rev. 11/94 RET: Life of Plant RESP: Nuclear Engineering 900 628
Florida Power Corporation ANALYSIS/CALCULATION
SUMMARY
DISCIPUNE CONTROL NO. REVISION LEVEL DOCUMENT IDENTIFICATION NUMBER I 89-0014 6 T[TLE CLASSIFICATION (CHECK ONE) RC PRESSURE LOOP ACCURACY FOR ES [] Safety Related fl Non Safety Related MAR/SP/CGWR/PEERE NUMBER/FILE SP 95-002 VENDOR DOCUMENT NUMBER C-423-5510-066 REVISION ITEMS REVISED APPROVALS Design Engineer M.D. Lord ;oZ/I.9
*, * * 't',' C Date 03/2495 Verification Engineer &Z1___
Date/Method* ._____ Supervisor kr-" A_ _. Date 6 1, I,1 __
*VERIFICATION METHODS: R - Design Review; A - Alternate Calculation; T - Qualification Testing DESCRIBE BELOW IF METHOD OF VERIFICATION WAS OTHER THAN DESIGN REVIEW PURPOSE
SUMMARY
This calculation has been totally rewritten to add "AS-LEFT" and "AS-FOUND" tolerances, 1/2 minor division errors, and "CALIBRATED" errors to the calculation so as to orovide a bases for the tolerances used in SP-1 32. RESULTS
SUMMARY
See the TABLES in Section VI "RESULTS/CONCLUSIONS" for the errors.I 'AS-Left' &"As-Found" tolerances.Iand "CALIBRATED" errors associated with the components and the loops. Rev. 11/94 RET: Life of Plant RESP: Nuclear Engineering 900 625
Florida Page 1 of 1 Power Corporation PLANT DOCUMENT REVIEW EVALUATION DOCUMENT TYPE / NUMBER TO BE EVALUATED Calculation 1-89-0014 Revision 6 PART I INSTRUCTIONS: Calculations, Document Change Notices, and Plant Equipment Equivalency Replacements have the potential to affect plant documents. The Originator of any of these documents is required to determine which, if any, plant organizations should review the subject document for impact. The Originator should use the best judgment to make this determination based on the nature of the changes. If in doubt as to whether or not a plant organization should review a particular document, it is suggested that the subject organization be contacted. The Originator is to check the appropriate boxes below and attach to the subject package as follows: Calculations - Insert behind Analysis/Calculation Transmittal DCNs - Insert behind DCN page 1 PEEREs - Insert behind PEERE page 3 CIDPs - Insert behind CIDP page 1 The above referenced document must be distributed as follows: E0 Senior Radiation Protection Engineer [] Other(s): El Manager, Site Nuclear Services D.E. McPherson for Calibration Data Sheet Revisions Manager, Nuclear Maintenance Supervisor, Operations Engineering & Support Supervisor, Nuclear Training Controls [] Manager, Nuclear Plant Technical Support Manager, Nuclear Operations Training ORIGINATOR / DATE UPERVSOR / DATE M. D. Lord *77. P. 7ýo,-,t, T,//,-%ýir-. f ! Upon completion of Part I, if applicable, attach to the subject document, check "Plant Document Review Required" block, *Yes," and give to Nuclear Engineering Department Support Specialist for distribution. CIDPs - Distribute with Attachments Calcs - Distribute with Transmittal Memo, Summary - PEERE - Distribute with Attachments - DCNs - Distribute with Attachments and Drawings PART 11 INSTRUCTIONS: Upon receipt of the subject document, the assigned Reviewer enters the "Reviewing Department" name below, reviews the subject document for impact on plant procedures, and completes the evaluation below. CAUTION: IF THE SUBJECT DOCUMENT STATES SPECIFIC PLANT PROCEDURES/DOCUMENTS MUST BE DEVELOPED OR REVISED AND IT IS DETERMINED BY THE REVIEWER NOT TO REVISE OR DEVELOP THOSE PROCEDURES/DOCUMENTS, THE ORIGINATOR MUST BE CONTACTED BY THE REVIEWER. REVIEWING DEPARTMENT PLANT REVIEW IMPACT EVALUATION: The above referenced document has been reviewed and evaluated as follows: El No Action Required El Action Required: The below listed document(s) is affected and requires revision and/or other actions as indicated (i.e., generate a new procedure, void a procedure, etc.) DOCUMENTS / ACTIONS REVIEWER / DATE SUPERVISOR / DATE Upon completion, forward evaluation form only to Nuclear Document Control (NR2A)
- If the Supervisor or designee acts as the Originator or Reviewer, the applicable "Originator/Reviewer" block should be NA'd.
12/94
- 1. . t f -.
Florida INTEROFFICE CORRESPONDENCE Power COIPOmAT lOf Nuclear Enaineerina Desian Office NAIE MAC 240-3434 Telephone
SUBJECT:
Crystal River Unit 3 Quality Document Transmittal - Analysis/Calculation File: CALC TO: Records Management - NR2A The following analysis/calculation package is submitted as the QA Record copy: DOCNO (FPC DOUMENT IDOENnFMON NU0 EF R- I 7 m(% TOTAL PAGES TFIAN*U*TED 1-89-0014 5 ES. RC I 22 ITLE RC PRESSURE LOOP ACCURACY FOR ES KWDG (IDENTIFY KEYWORDS FOR LATER RETRiEVAL) ES, Actuation, Alarm, Interlock, IR, Error, Calculation DXF_ (REFERENCES OR FILES - LIST PRIMARY PILEFIRPI) SP-132 VEND KENOORNAME) VENDORDOCUMENT NUMBER(OXFEF) SUPEFrX0ED DOCUMENTS (OXREF) FPC/GCI C-423-5510-066 N/A
- ~PART NO.-
COMMCNI! USAGE RESTRECTlONS, PROPRETARY, ETC. This Revision replaces Sheets 3, 4, 5, 7, 8, 9, 10, 11, 12, 15 and 16. In addition pages 4A, 4B, 8A and Attachment 11 are being added to this calculation. No changes to Tag Numbers. NOTE: Use Tag number only for valid tag numbers (i.e., RCV-8, SWV.34, DCH.99), otherwise; use Part number field (i.e., CSC14599, AC1459). If more space is required, write *See Attachment, and list on separate sheet. __L 2~3 DA'E P.E. Couvillo n, DESIGN ENGINEER ATI j rVE ,FVFICATIO ENGINEER
//;I -'.
DATE SUPERVISOR. 1~ NUCLEAR EFNG. zf3lqs-cc: MAR Office (ffMAR Related) D Yes 11 No Plant Document Review Required H Yes 1 No MAR/Prolect File Supervisor. Nuclear Document Control w/ Plant Doc. Rev. Mgr. Nucl. Config. Mgt. Eval. end Analysis I Caic. Summary (IfPlant Doo. Rev.. Is Yes) File (CALC) - FPES 'Origlnal' w/attach A/E N/A DYes M No Mgr., Site Nucl. Eng. Serv. 7 /attach yes, Transmit wlattach) (Nf V',A &S.4V e-0.4%, Rý*. 11194
~~
Rev.~~ 119*,:LfeCb1- ~;N~.,E.gn,~ 2 RET: Lit. of PI.-t RIESP: WO.- ENIn"-9 900 626
Florida Power
.orporsiion ANALYSIS/CALCULATION
SUMMARY
DISCIPLNE CCZWTROL NO. REV91ON LEVL DOCUMENT IDENTIFICATION NUMBER 89-0014 5 ITrLE CAW ITI r.HEC. ONE) RC PRESSURE LOOP ACCURACY FOR ES [] safety Related M Safety Related Non MARI SPIOcGWRIPEERE NLUMR/EtE SP88-006 VENOOR DOCUMENT NUMBER C-423-5510-066 REVISION ITEMS REVISED APPROVALS Design Engineer P.E. Couvilon .l..-Revlse pages 3, 4. 5, 7, 8, 9, 10, 11, 12, 15 and 16. Date Add pages 4A, 4B, 8A and Attachment 11. Verification Engineer _____ __,_,____._.__ Date/Method'
-Supervisor _____________________________
Date
*VERIFICATION METHODS: R - Design Review; A - Alternale Calculation; T - Qualification Testing OFESCRIBE BELOW IF METHOD OF VERIFICATION WAS OTHER THAN DESIGN REVIEW PUIFOSE SUMIARY This calculation revises the above mentioned pages to reflect the deletion of Radiation Effects from the transmitters for the actuation of the 500 and 1500 psig setpoints. In addition, the temperature range used in calculating the Temperature Effect on the pressure transmitters is being revised.
RESULTS
SUMMARY
See Section VI 'RESULTS/CONCLUSIONS' for the Calculated Loop Errors associated with the pressure transmitters. R-v It194 RET: t?/BA Lite R~ of Pht" RESP; Nuclea~r Engineerin~gNOC 625
Florida Page I of I Power PLANT DOCUMENT REVIEW EVALUATION Coarepotion DOCUMENT TY I NUM8MR TO BEEVALtATED Cakluation 1-M9-0014 Revisin 5 PART I 3STILICTIONS: Calculations, Document Change Notices. and Plant Equipment Equivalency Replacements have the potential to affect plant documents. The Originator of any of theae documents Is required to determine which, If any, plant organizations should review the aubjef document for Impact. The Odginator should use the beat judgment to make this determlnallon based on the nature of the changes. If In doubt as to whether or not a plant organization should review a particular document, A is suggested that the subject organization be contacted. The Originator is to check the appropriate boxes below and attach to the subject package as follows; Calculations - Insert behind AnalysieJCalculation Transmittal D.Ns - Insert behind DCN page I PEEREs - Insert behind PEERE page 3 CIDPs. Insert behind CIDP page 1 The above reierenced document must be distributed as follows: C0 Senior Radiatdon Protection Engineer 0] Other(s): I] Manager. Site Nuclear Services Cl Manager, Nuclear Maintenance [] Supervisor, Operations Engineering & Support Manager, Nuclear Plant Technical Support I DAE sunGcNATOo DATEUPEAS__ Upon completion of Part I, If applicable, attach to the subject document, check 'Plant Document Review Required* block. 'Yes., and nive to wti, n . Muclear E-nin rin a Dor- artment Su r. C:art S r-- !a!;-!! r -A;e+r;b
-
CIDPs - Distribute with Attachments Caike - Distribute with Transmittal Memo, Summary - PEE*E - Distribute with Attachments - lXNs - Distribute with Attachments end Drawings PART II INSTRUCTIONS: Upon receipt of the subject document, the assigned Reviewer enters the 'Reviewing Department' name below, reviews the subject document for impact on plant procedures, and completes the evaluation below. CALUTOlN: F THE SUBJECT DOCUMENT STATES SPECVIFC PLANT PPOCEDURESIDOCUMENTS MUST BE DEVELOPED OR REVtSED AND rT IS DETERMINED BY THE REVIEWER NOT TO REVISE OR DEVELOP THOSE POCEDURES/DoCUMENTS, THE OIRIGIIATOA MUST BE CONTACTED BY THE REVIEWEIR. PLANT tEVIEW IMPACT EVALUALTXON The above referenced document has been reviewed and evaluated as follows:
"J No Action Required El Action Required: The below listed document(s) is affected and requires revision and/or other actions as indicated (i.e., generate a new procedure, void a procedure, elr.)
DOCUMENTS / ACTIONS P-V1/*w.R i DATE J UPERVYWR IDAT"E Upon.completion. forward evaluation form only to Nuclear Document Control (NR2A) if the Supervisor or designee acts as the Originator or Reviewer. the applicable "OriginatorlRoviewer" block should be NA'd. 12S4
e 0Florida
~Power INTEROFFICE CORRESPONDENCE C* Nuclear Engineering CZI g_ 37 OFFICE MAC PHONE
SUBJECT:
Crystal River Unit No. 3 Quality Document Transmittal - Analysis/Calculations File: CALC TO: Records Management - NR2A The following analysis/calculation package is submitted as the QA Record copy: DOCNO (FPC DOCUMENT IDENTIFICATION NUMBER) REV SYSTEM(S) TOTAL PAGES TRANSMIfTED TITLE KWDS IIDENTIFY KEYWORDS FOR LATER RETRIEVAL) EA./7l-c,,,l-il , AlaM g*, , ]nk ,r/,Xc f-rV , I, ?7, 7 7, f DXREFK(REFERENCES OR FILES)-IST PRIMARY FILE4KRST) / ' VEND (VENDOR NAME) VENDOR DOCUMENT NUMBER (DXREF) SUPERSEDED DOCUMENTS (DXREF) COMMENTS (USAGE RESTRICTIONS, PROPRIETARY, ETC.)
/'-a Cze S/c (0vt~
'le~ C^c dC6_(ee c S.
NOTE: Use Tag number only for valid tag numbers (i.e., RCV-8, SWV-34, DCH-99) otherwise, use Part number field (i.e., CSC14599, AC1459). If more space is required, write "See Attachment" and list on separate sheet. DE
*o*..
/IEI NEER 13173tq i !,si.,s DATE VERIFICATION NGINEER I-Ifkzu"l*
DATE S 5L
-ISJ W7
*
* <Z */<l ENG. /SA /
cc: MAR Office (If MAR Related) 0 Yes ieNo Supervisor, Nuclear Dolument ContrgjVw/Plant 6oc. Rev. MAR/Project File Eval. and Analysis I CaIc. Summary Mgr., Nucl. Config. Mgt. Plant Document Review Required A' No File (CALC) - FPES - "Original" wlattach.
, Mgr., Site NucI. Eng. Serv. wlattach. 'A& RevAig_' (tiF* ,. REerLeoP ,ESP .Nuclear Engineering 900628
A Florida Power C.orporation ANALYSIS/CALCULATION
SUMMARY
DISCIPUNE CONTROL NO. REVISION LEVEL DOCUMENT IDENTIFICATION NUMBER I 89-0014 4 TITLE CLASSIFICATION (CHECK ONE) RC PRESSURE LOOP ACCURACY FOR ES [] Safety Related [z Non Safety Related MAR/SP NUMBER/FILE SP88-006 VENDOR DOCUMENT NUMBER C-423-5510-066 REVISION ITEMS REVISED APPROVALS Design Engineer 1 z-.. SHEET 9 Date__ Verification Engineer ___ Date/Method* ___/_ ____ ____ ____ Supervisor "'L3 _,__,- Date __ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
*VERIFICATION METHODS: R - Design Review; A - Alternate Calculation; T - Qualification Testing DESCRIBE BELOW IF METHOD OF VERIFICATION WAS OTHER THAN DESIGN REVIEW PURPOSE
SUMMARY
This revision corrects typographical errors on sheet 9. RESULTS
SUMMARY
No change. ES Actuation, Permit and Reset, +/-40 psi Alarm and Interlock via NNI, +/-45 psi (Alarm of CFT valve not open could be at >750 psial) Recording, +/-39 psi RIP Indicator +/-48 psi See Section VI for outputs to RCITS, T-SAT, Plant Computer, Recall and RPP. Rev. 4/92 /RET: ULfeof Plant RESP: Nuclear Engineering 900 825
~Florida Power PLANT DOCUMENT REVIEW EVALUATION Corporetion UMENT TYPE / NUMBER TO BE EVALUATED PART I INSTRUCTIONS: Calculations, Document Change Notices, and Plant Equipment Equivalency Replacements have the potential to affect plant documents. The Originator of any of these documents is required to determine which, if any, plant organizations should review the subject document for impact. The Originator should use the best judgment to make this determination based on the nature of the changes. If in doubt as to whether or not a plant organization should review a particular document, it is suggested that the subject organization be contacted.
The Originator is to check the appropriate boxes below and attach to the subject package as follows: Calculations - Insert behind Analysis/Calculation Transmittal DCNs - Insert behind DCN page 1 PEEREs - Insert behind PEERE page 2 The above referenced document must be distributed as follows: 5/No Review Required LI Nuclear Operations Superintendent 0i Manager, Nuclear Plant Systems Engineering LD Nuclear Maintenance Work Controls Superintendent o] Nuclear Chem/Rad Protection Superintendent LI Manager, Nuclear Plant Technical Support DI Senior Radiation Protection Engineer Li Other(s): 01 Manager, Site Nuclear Services ORIGINATOR / DATE PE D ATE Upon complein of Part I, attach to the subject document, check "Plant Document Review Required lock, as applicable, and give to Nuclear Engineering Clerk for distribution. CIDPs - Distribute with Attachments Calcs - Distribute with Transmittal Memo, Summary - PEERE - Distribute with Attachments - DCNs - Distribute with Attachments and Drawings PART II INSTRUCTIONS: Upon receipt of the subject document, the assigned Reviewer enters the 'Reviewing Department" name below, reviews the subject document for impact on plant procedures, and completes the evaluation below. REVIEWING DEPARTMENT PLANT REVIEW IMPACT EVALUATION: The above referenced document has been reviewed and evaluated as follows: Di No Action Required Di Action Required: The below listed document(s) is affected and requires revision and/or other actions are required as indicated (i.e., generate a new procedure, void a procedure, etc.) DOCUMENTS / ACTIONS REVIlEWER / DATE SUPERVISOR / DATE Upon completion, forward evaluation form o to Nuclear Document Control (NR2A)
- If the Supervisor or designee acts as the Originator or Reviewer, the applicable "Originator/Reviewer" block should be NA'd.
E: o i, fS:N.ceEgneig 919 129 12,192 RET: L:fe of Plant RESP: Nuclew Enaineeting 901 193
Florida INTEROFFICE CORRESPONDENCE
- Power C 0APOROA I ON Nuclear Engineering C 2 .E 5-PN7 OFFICE MAC PHONE
SUBJECT:
Crystal River Unit No. 3 Quality Document Transmittal - AnalysislCalculatlons File: CALC TO: Records Management - NR2A The following analysislcalculation package is submitted as the QA Record copy: OOCNO tFPC DOCUMENT
-'S.O/ IDENTIFICATION NUMBER) I REV I TOTAL PAGES TRANSMITTED lnnrLE TTEk'C Pr ess- ,,,e- Looe A cc L..rý- cy rvn- , S KWDS (IDENTIFY KEYWORDS FOR LATER RETRIEVAL)
,, e-.--
-- 4 .-- f; t' D X K.t-,F- '
DXREF (REFERENCES OR FILES . LIST PRIMARY FILE FIRST) .- _ 2o-o oS. - ot'q do- ./O-/-f0/o3 - j -Eff-CO3o
&a oo/_5 ZT8'-0`17J &L.F '-13. 2 ,- - 2i:5g-1-o3z, VEND (VENDOR NAME) VENDOR DOCUMENT NUMBER (DXREF) SUPERSEDED DOCUMENTS (DXAPF)
Fr-- 6 r--Z 3-- o - O*,/ ev. z AC-3A/i3- P-3 I C -3A - ES I 2-t3 Prc--A- PT4+R--30;-er IRC_-3. _- 3 __%JX 1Z c-3,4-05 , q-, 5,. L -7 AC - 3 A -. t-C k -3T P y , , 21'
.R c .- 31i- PA -3 3_-_0-r_ ,_ _ZC_- __2_,_3_7 P C -A16-y_3 q c-.303- 0 XZ
.C-3A - Py9-5L/- 1 O/
COMMENTS (USAGE RESTRICTIONS, PROPRIETARY. ETC.) AD P'L. E:*- ; Sp <. J'-,.. 3r*.. z, I- *.d .J r S P13z2 - 13 P0 t\J - -D1 l5.T - 3(q -o3 NOTE: Use Tag number only for valid tag numbers (i.e., RCV-8, SWV-34, DCH-99) otherwise, use Part number field (i.e., CSC1459R, AC1459). If more space is required, write "See Attachment" and list on separate sheet. DESIGNDN"EE K ATE VERIFICPTION ENGINEER DATE SU ISO~jMUCLJR ENG
- DATi cc: MAR Office MAR Related) 0 0If Yes ,f No Supervisor, Nuclear Do'cument ContdwlPlant 0oc, Rev.
MAR/Project File S? V-00C Eval. and Analysis I Calc. Summary Mgr., Nucl. Config. Mgt. Plant Document Review Required IV'Yes 0 No File (CALC) - FPES - "Original" w/attach. <C8.k J.oy e- I"1 -1/53C £ Cj-Jlk Mgr., Site Nucl. Eng. Serv. w/attach. J..D . ,e, RAe 4,'Q_ RET: Life of Plant RESPt Nuclear Engineenng 900 628
Florida Power Corporation ANALYSIS/CALCULATION
SUMMARY
DISCIPLINE CONTROL NO. REVISION LEVEL DOCUMENT IDENTIFICATION NUMBER I 89-0014 3 TITLE CLASSIFICATION (CHECK ONE) RC PRESSURE LOOP ACCURACY FOR ES [] Safety Related L] Non Safety Related MAR/SP NUMBER/FILE SP88-006 VENDOR DOCUMENT NUMBER C-423-5510-066 REVISION ITEMS REVISED Design Engineerate_ _ _ __-_ _ _ Date__ _ __ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Verification Engineer 41_ C_._ r-ka__ __ __- Date/Method* I oVIZ. Z _ ___ __ Supervisor Date
*VERIFICATION METHODS: R - Design Review; A - Alternate Calculation; T - Qualification Testing DESCRIBE BELOW IF METHOD OF VERIFICATION WAS OTHER THAN DESIGN REVIEW PURPOSE
SUMMARY
Determine the instrument loop accuracy of the RC Pressure loops of the Engineered Safeguards (ES), control room recorders and alarms. NNI interlocks RECALL (SPDSi. T.. meters. plant computer reactimeter natch nanel
... .... .... ........ i ................. i ........ I SAT and RCITS (for oressure comoensation of level).
r . .. rrss........ ... f lve.. and T (for. IC RESULTS
SUMMARY
ES Actuation, Permit and Reset, +/-40 psi Alarm and Interlock via NNI, +/-45 psi (Alarm of CFT valve not open could be at >750 psig) Recording. +/-39 psi RIP Indicator +/-48 psi See Section VI for outputs to RCITS, T-SAT, Plant Computer, Recall and RPP. Rev. 4/92 RET: Life of Plant RESP: Nuclear Engineering BOO625
,PLANT DOCUMENT REVIEW EVALUATION DOCUMENT TYPE / NUMBERTO BE EVALUATED PART I INSTRUCTIONS: Calculations, Document Change Notices, and Plant Equipment Equivalency Replacements have the potential to affect plant documents. The Originator of any of these documents is required to determine which, If any, plant organizations should review the subject document for Impact. The Originator should use the best judgment to make this determination based on the nature of the changes. If In doubt as to whether or not a piant organization should review a particular document, it Is suggested that the subject organization be contacted.
The Originator is to check the appropriate boxes below and attach to the subject package as follows: Calculations - Insert behind Analysis/Calculation Transmittal DCNs- Insert behind DCN page 1 PEEREs - Insert behind PEERE page 2 The above referenced document must be distributed as follows: o No Review Required :* Nuclear Operations Superintendent o Manager, Nuclear Plant Systems Engineering 0 Nuclear Maintenance Work Controls Superintendent o Nuclear Chem/Rad Protection Superintendent [D Manager, Reliability Centered Maintenance o Senior Radiation Protection Engineer Dl Other(s): ORIGINATOR / DATE s Upon completion of Part I, attach to the subject document, check "Plant Do*m~nt Review Requiredalock, as applicable, and give to Nuclear Engineering Clerk for distribution. Calca - Distribute with Transmittal Memo, Summary - PEERE - Distribute with Attachments - DCNs - Distribute with Attachments and Drawings PART Ii INSTRUCTIONS: Upon receipt of the subject document, the assigned Reviewer enters the "Reviewing Department" name below, reviews the subject document for impact on plant procedures, and completes the evaluation below. REVIEWING DEPARTUEMT PLANT REVIEW IMPACT EVALUATION: The above referenced document has been reviewed and evaluated as follows: 13 No Action Required Action Required: The below listed document(s) is affected and requires revision and/or other actions are required as indicated (i.e., generate a new procedure, void a procedure, etc.) DOCUMENTS / ACTIONS REVIEWER DAITE SUEVIO / DATE Upon completion, forward evaluation form only to Nuclear Document Control (NR2A)
- If the Supervisor or designee acts as the Originator or Reviewer, the applicable "Originator/Reviewer" block should be NAd.
4/92 RET: We of Ptaryt RESFý Nudew Englroednq 901 193
Florida INTEROFFICE CORRESPONDENCE Power CORPORATION Nuclear Enqineerinq C-aT LPHONE OFFICE MAC PHONE
SUBJECT:
Crystal River Unit No. 3 Quality Document Transmittal - Analysis/Calculations File: CALC SE - TO: Records Management - NR2A The following analysis/calculation package is submitted as the QA Record copy: I DOCNO (FPC DOCUMENT IDENTIFICATION NUMBER) REV DATE
-_ . ,1- 0o01 TITLE L12. f(LLSSujlý Loof Prcx_0VkC14 'FýI`L_ ES C Hw X-
_prc-T\) f\rlooJ KWDS (IDENTIFY KEYWORDS FOR LATER RETRIEVAL) DXREF (REFEFOENCES OR FILES --LIST PRIMARY FILE FIRST)
-I - - -b its 9_0o1P .- " L--f- -/
VEND (VENDOR NAME) VENDOR DOCUMENT NUMBER (DXREF) SUPERSEDED DOCUMENTS (DXREF) c; /C--- (Z- %-S4723,4, Ac. - o' -Oz -j. pC_- coo3 e-T- q' Y, (Lq_ F- I COMMENTS (USAGE RESTRICTIONS, PROPRIETARY, ETCj NOTE: Use Tag number only for valid tag numbers (i.e., RCV-8, SWV-34, DCH-99) otherwise, use Part number field (i.e., CSC14599, AC1459). If more space is required, write "See Attachment" and list on separate sheet. DESIGNANGINEER DATE VERIFICATION ENGINEER DATE SUPER R AR ENG. A CC: Readers "1.. " MARIProject File *-* *-" S O Mgr., Nucl. Config. Mgt. File (CALC) - FPES - "Original" wlattach. Mgr., Site Nuci. Engrg. Serv. wlattach. Rev. 7/89 RET: Life of Plant RESP: Nuclear Ops. Engineering 900 628
POWER AND INDUSTRIAL SYSTEMS DIVISION - READING PAGE OF.)-> CALCULATION PG F 2 PROJ ECT: IDENTIFIER C FJT*A ,Z'JA' V/T-? " - - o,-<, COImWi-nI*iJI
SUBJECT:
qC. P,-JJ'40e-e- C.C,- ' 61*t.- &'e9cX '- CJ- CLASSIFICATION CnpawS (hz) .,T,'*.9-,,,- 0-0/49. ¢ ,&,4 I." SECTION NAME ANO NUMBER W.O.
.,3-7fL0, d_3_-55../
_- -. o REVISION 0 2 3 ITEM(S) REVISED ALL ORIGINATOR cc Ifn-J .* , ./-Z/_._. - DATE ~Ž L~--- REVIEWER/VERIFIER ., y-§ '. ,- ______-__ DATE_____ _ APPROVAL (ýŽjPywL (--4 ý-'n DATE 3 Z, 2~ A___1__A-2_ / ASSUMPTIONS/PRELIMINARY DATA . _ __, _ NG
-L 1)G' PAGES REFERENCE _
THIS CALCULATION REQUIRES 0l REVIEW PER E-1 NO. 9 VERIFICATION PER DCP 2.05 RESULTS ARE NOTED BELOW. /y REMARKS REMARKS REMARKS REMARKS THE REVIEW OF THE CALCULATION INCLUDED EVALUATION AGAINST THE FOLLOWING QUESTIONS: e/ WERE INPUTS, INCLUDING CODES, STANDARDS, AND REGULATORY REQUIREMENTS, CORRECTLY SELECTED AND APPLIED? ARE ASSUMPTIONS REASONABLE AND ADEQUATELY IDENTIFIED? HAVE APPLICABLE CONSTRUCTION AND OPERATING EXPERIENCES BEEN CONSIDERED? WAS AN APPROPRIATE CALCULATION METHOD USED? IS THE OUTPUT R EASONABLE PUTS? COMPARED TO INI
, Gilbert/Commonwealth GAI-525 4-84 THIS IS A PERMANENT DESIGN RECORD DO NOT DESTROY
Florida INTEROFFICE CORRESPONDENCE Power CORPORATION Nuclear Enqineering eZ- : 4051 OFFICE MAC PHONE
SUBJECT:
Crystal River Unit No. 3 Quality Document Transmittal - Analysis/Calculationss V--*-.. V, 1 FYA- L 01\) L-' - File: CALC . TO: Records Management - NR2A 4FCrC- I1OCV(AoNi-The following analysis/calculation package is submitted as the QA Record copy: DOCNO (FPC DOCUMENT IDENTIFICATION NUMBER) REV DATE I SYSTEM(S) TOTAL P GES IN PKG. TITLE Calculation for VC fg755~up2..L Ltoy9 4rCCua4Cq Fpa- --,( 4' KWDS (IDENTIFY KEYWORDS FOR LATER RETRIEVAL) OXREF (REFERENCES OR PILES
- LIST PRIMARY FILE FIRST)
ýe-6 6,- Dý G- 3*tz- &o. __ _ _ _
DR-5 W.- 36q- 3T-R- Poq Dt5 r-5 1'- 3 T- - 003 A VEND (VENDOR NAME) VEDRDCUMENT NUMBER (OXREF) SUPERSEDED DOCUMENTS (DXREF)
,ZC- oo3A- FT3 (S)
RC- oo3A- (S) _T_ IlI ADDL NOTE: Use Tag number only for valid tag numbers (i.e., RCV-8, SWV-34, DCH-99) otherwise, use Part number field (i.e., CSC-14599, AC1459). Do not include /, -, or other types of field separators, except as shown for tag numbers. When neither tag or part number applies to a calculation, leave these fields blank. If more space Is required, write "See Attachment" and list on separate sheet. DESIN)(lIGIEERDAT/ VERIFICATION E GiE/ DATE SUPERVI R. NUCLER G. T:
- 1"J/ . ..
Readers ..3r. S' S71 P0.5 - - . MAR File Mgr., Nucl. Config. Mgt. File (CALC) - FPES - "Original" wlattach. Mgr., Site Nucl. Engrg. Serv. wlattach. Rev. 12J88 RET: Life of Plant RESP: Nuclear Engineering Assurance 912 248
Florida
*Power CORPORATION DESIGN ANALYSISICALCULATION Crystal River Unit 3 DESA-C.FRM Page 1 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 PURPOSE:
The purpose of this calculation is to determine the instrument loop accuracy of the RC pressure loops of the Engineered Safeguards (ES), control room recorders and alarms, NNI interlocks, RECALL (SPDS), TSAT meters and plant computer. The instrument loop accuracy values calculated will be used to support the ES surveillance requirements given in Improved Technical Specifications (ITS) section 3.3.5.3 (Reference 63). The purpose of Revision 9 ICA is as follows:
- RCITS IN uncertainty has been removed from this calculation. Reason: The RCITS IN loop uncertainty is no longer required as input to calculation 189-0010 (Reference 60) and the RCITS loop input is not tested in SP-0132 (Reference 37). However, the loop IReffects have been revised to incorporate the MAR 97-02-12-02 (Reference 86) RC-163A-PYI and RC-163B-PY1 IN modification to the new Foxboro IN module.
" The HPI Upgrade project altered the current high pressure injection (HPI) system to improve its reliability and capability to meet its defined functional requirements as well as reduce operator burden during accident scenarios.
The change impacts the interfacing system such as the engineered safeguards actuation system (ESAS) by revising the ITS ES RCS Low Pressure setpoint, Bypass Reset and Bypass Permit values (see table below). This revision will incorporate the revised values for the ES RCS Low Pressure Trip, ES Low RC Pressure Alarm , Bypass Permit, Bypass Permit Alarm, Bypass Reset, and Bypasss Reset Alarm setpoints. The HPI MAR 97-02-12-01 and MAR 97-02-12-02 (References 85 and 86) will establish the Bypass Reset and Permit setpoints since there are no analytical limits associated with these setpoints. ES RCS Low Pressure _1500 psig -a1625 psig (ITS Required Value) ES RCS Low Pressure Bypass Reset _*1700 psig _1 800 psig (ITS Required Value) ES RCS Low Pressure Bypass Permit 1670 psig 1770 psig (Plant Implemented Value) ES RCS HPI Not Bypassed/Reset Alarm 1640 psig 1740 psig (Plant Implemented Value) ES Low Low RC Pressure Alarm 1550 psig 1675 psig (Plant Implemented Value)
- This revision also adds the Signal Monitor and Bypass Alarm setpoint values to calculation Table IV.
Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
- r r DESIGN ANALYSIS/CALCULATION Crystal River Unit 3 DESA-C.FRM Page 2 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 Instrument Loops Bailey 6621500A1 EQ ZONE CC CC 4066 EQ ZONE 58 EQ ZONE 13 BT HPI -BYPASS RC-3-BT4 RC-3-BT5 RC-3-BT6 EaT EBT Bailey 6621500A1 Rosemount 1154GP9RA EBT EST EpT, E PT/ACT E (PT/1.97)
CC EQ ZONE 58 Foxboro 610 -AT
'Component in RC-3A-PT3 Loop Only "Component not InRC-3A-PT4 RC PRESSURE LOOPS ECALL Rev. 6195 RET: Life of Plant RESP: Nuclear Engineering
FlRorida Power DESIGN ANALYSIS/CALCULATION
......... o. Crystal River Unit 3 DESA-C.FRM Page 3 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 11 RESULTSICONCLUSIONS:
ERROR USAGE INFORMATION The error values provided in the tables below for indicators/recorders do not include indicator/recorder readability. These error values must be used along with readability when determining a proper offset for taking a required reading from one of the indicators/recorders. The required value would be offset by the appropriate error from Table VII table below, then rounded (in the conservative direction) to the 1/2 minor division for taking a reading. A more detailed discussion on this subject, with examples, is provided in the Operational Considerations section below. The list below gives the 1/2 minor division for the indication/recording devices analyzed. END DEVICE 112 MINOR DIVISION RC-154-PR/TR 25 psig RC-3A-PI3 25 psig RC-3B-P12 25 psig The following tables list the applicable results of this calculation. TABLE I RC-3-BT1, RC-3-BT2, & RC Ž 1625 PSIG FSAR TABLE 6-13 BT3 ITS TABLE 3.3.5-1 RC-3-BT4, RC-3-BT5, & RC >1800 PSIG (Nominal) ITS TABLE 3.3.5.1 BT6 RC-3-BT1 0, RC-3-BT1 1, & RC- >900 PSIG (Nominal) ITS TABLE 3.3.5.1 3-BT 12 RC-3-BT7, RC-3-BT8, & RC >500 PSIG FSAR TABLE 6-13 BT9 ITS TABLE 3.3.5.1 RC-3A-PS3 (LO) Ž653 PSIA ITS Section 3.5.1 (SR 3.5.1.3) RC-3A-PS3 (HI) < 750 PSIG ITS Section 3.5.1
- Reference 40 TABLE II Transmitter Scaling/Calibration RC-3A-PT3 27.2 PSIG 27.2 PSIG 2527.2 PSIG RC-3A-PT4 27.2 PSIG 27.2 PSIG 2527.2 PSIG RC-3B-PT3 27.8 PSIG 27.8 PSIG 2527.8 PSIG Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
eFlorida Power
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DESIGN ANALYSISICALCULATION C rys ta l R iv e r U n it 3 DESA-C.FRM Page 4 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 TABLE III Slit LooP :IN Transmitter Settin Tolerances TABLE IV RC-3-BT1 6.660 Vdc 1665 psig 4 +/-0.010 Vdc +/-0.026 Vdc (HPI TRIP) RC-3-BT2 6.660 Vdc, 1665 psig 4 +/-0.010 Vdc +/-0.026 Vdc (HPI TRIP) RC-3-BT3 6.660 Vdc, 1665 psig +/-0.010 Vdc
+/- +/-0.026 Vdc (HPI TRIP)
RC-3-BT4 Permit: 7.080 Vdc, 1770 psig 4 +/-0.010 Vdc +/-0.026 Vdc (HPI Bypass Permit/Reset) Reset: 7.180 Vdc, 1795 psig 1T +/-0.010 Vdc +/-0.026 Vdc RC-3-BT5 Permit: 7.080 Vdc, 1770 psig 4 +/-0.010 Vdc +/-0.026 Vdc (HPI Bypass Permit/Reset) Reset: 7.180 Vdc, 1795 psig +/-0.010 Vdc
+/- +/-0.026 Vdc RC-3-BT6 4 Permit: 7.080 Vdc, 1770 psig +/-0.010 Vdc +/-0.026 Vdc (HPI Bypass Permit/Reset)
Reset: 7.180 Vdc, 1795 psig +/-"0.01 0 Vdc +/-0.026 Vdc RC-3-BT7 2.240 Vdc, 560 psig 4 +/-0.010 Vdc +/-0.026 Vdc (LPI TRIP) RC-3-BT8 2.240 Vdc, 560 psig 4 +/-0.010 Vdc +/-0.026 Vdc (LPI TRIP) RC-3-BT9 2.240 Vdc, 560 psig 4,+/-0.010 Vdc +/-0.026 Vdc (LPI TRIP) RC-3-BT10 Permit: 3.400 Vdc, 850 psig 4 +/-0.010Vdc +/-0.026 Vdc (LPI Bypass Permit/Reset) Reset: 3.500 Vdc, 875 psig +/-0.010 Vdc
+/- +/-0.026 Vdc RC-3-BT1 1 Permit: 3.400 Vdc. 850 psig 4 +/-0.010 Vdc +/-0.026 Vdc (LPI Bypass Permit/Reset)
Reset: 3.500 Vdc, 875 psig +0.010 Vdc
+/- +/-0.026 Vdc RC-3-BT12 Permit: 3.400 Vdc, 850 psig 4 +/-0.010 Vdc +/-0.026 Vdc (LPI Bypass Permit/Reset)
Reset: 3.500 Vdc, 875 psig T I +/-0.010 Vdc +/-0.026 Vdc RC-3A-PS3 (LO) (CFT 2.760 Vdc, 690 psig 1 +/-0.025 Vdc +/-0.026 Vdc Isolation Valve Not Closed) I RC-3A-PS3 (HI) 2.810 Vdc, 702.5 psig T +/-0.025 Vdc +/-0.026 Vdc (CFT Isolation Valve Not Open) Rev. 6/95 RET: Lifeof Plant RESP: Nuclear Engineering
Florida Power DESIGN ANALYSIS/CALCULATION CORPORATION Crystal River Unit 3 DESA-C.FRM Page 5 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10
....... "."..........
RC-3A-PS4 "*te*1.570 Vdc, 392.6 psig 1T +/- 0.025 Vdc +/-0.026 Vdc (LTOP Alarm)I RC-3A-PS4 0.800 Vdc, 200 psig T" +/- 0.025 Vdc +/-0.026 Vdc (DHR ACI Valve Position Alarms) RC-3A-PS5 3.000 Vdc, 750 psig I, +/- 0.025 Vdc +/-0.026 Vdc (LPI Not Bypassed Alarm) RC-3A-PS5 3.000 Vdc, 750 psig T +/- 0.025 Vdc +/-0.026 Vdc (LPI Not Reset Alarm) RC-3A-PS6 6.960 Vdc, 1740 psig I1 +/- 0.025 Vdc +/-0.026 Vdc (HPI Not Bypassed Alarm) RC-3A-PS6 6.960 Vdc, 1740 psig T +/- 0.025 Vdc +/-0.026 Vdc (HPI Not Reset Alarm) RC-3A-PS7 0.800 Vdc, 200 psig T +/- 0.025 Vdc +/-0.026 Vdc (DH Isolation Valve to PZR Spray Open Alarm ) RC-3A-PY4 6.700 Vdc, 1675 psig $ +/- 0.025 Vdc +/-0.026 Vdc (RC Low Pressure Alarm) Note 1: The LTOP Alarm will remain at 1.570 Vdc (392.6 psig) after implementation of the 32 EFPY LTOP Analysis setpoints. Refer to section 6.9 of this calculation for details. TABLE V SDlit Looo:OUT (TOTAL) Tolerances (Input at Cabinet to Output of Device)
.
............... ................
.. ..
......
................. ..... XX :X:-N-N
..................................
..
................ ......
..... ....
.......
Z:%:
. ......
............... .
Iýovýp .- ............................ RC-154-PRrrR +/-1.0%, +/-25 psig +/-2.0%,+/-50 psig PC/RECALUSPDS +0.45%, +/-11.3 psig +/-1.03%, +/-25.8 psig (R208,R21 0,RECL-4,RECL-5) Output to -PSat +0. 14%, +/-3.5 psig +/-0.72%, +/-18.0 psig RIP lndicators(RC-3A-PI3, RC-313-PI2) +/-2.0%, +/-50 psig +/-3.0%, +/-75 psig TABLE VI Split Loop: OUT(Partial) Tolerance (input at Cabinet to Input of Bistable/Sl nall Monitor) RC-3-BT1, RC-3-BT2, RC-3-BT3, RC +/-0.01 0 Vdc +/-0.068 Vdc BT7, RC-3-BT8, & RC-3-BT9 Signal Monitors (Alarnnfint1k) +/-0.014 Vdc +/-0.072 Vdc, Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
Florida Power
........... DESIGN ANALYSISICALCULATION Crystal River Unit 3 DESA-C.FRM Page 6 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 TABLE Vii RC-154-PR/TR +3.31%, - 2.97% +6.27%, -5.82%
+82.8, - 74.3 psig +156.8, -145.5 psig PC/RECALIJSPDS +1.66%, -1.32% +5.55%, -5.10%
(R208,R210,RECL-4,RECL-5) +41.5, -33.0 psig +138.8, -127.5 psig Output to T'Sat +1.43%, -1.09% +5.49%, -5.04%
+35.8, -27.3 psig +137.3, -126.0 psig RIP Indicators +3.45%, -3.11% +6.33%, -5.88%
(RC-3A-PI3, RC-3B-PI2) +86.3, -77.8 psig +158.3, -147.0 psig Trip Units - RC-3-BT1, RC-3-BT2, RC NA +1.37%, +34.3 psig BT3, RC-3-BT7, RC-3-BT8, & RC-3-BT9 Signal Monitors (Alarm/Intlk) +1.57%. - 1.23% NA
+39.3, -30.8 psig TABLE VIII HPIILP! LOOP RESPONSE TIME 0.2 sec 1 sec 0.1 sec 1.3 sec Rev. 6195 RET: Life of Plant RESP: Nuclear Engineering
Rlorida
*s Power DESIGN ANALYSIS/CALCULATION Crystal River Unit 3 DESA-C.FRM Page 7 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 110 FIGURE I ESAS TRIP DATA Normal Operating Pressure 2155 psig 1665 psig HPI Trip Inplant Setpoint HPI ITS Trip Allowable Value 1625 psig
&Analytical Limit Core Flood Tank Flow Initiation 600 psig
...........- 560 psig LPI Trip Inplant Setpoint LPI ITS Trip Allowable Value 500 psig NOTE: Pressures given in the above figure are ideal and are not scaled to the specific transmitter calibration spans.
Rev. 5195 RET: Life of Plant RESP: Nuclear Engineering
aFlorida Power DESIGN ANALYSIS/CALCULATION
........... Crystal River Unit 3 DESA-C.FRM Page 8 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 1 10 FIGURE II ESIHPI BISTABLE DATA 1800 ITS HPI Bypass Reset Value 1795 psig HPI BYPASS Reset Inplant Setpoint
--..-----.1770 psig HPI BYPASS Permit Inplant Setpoint 1665 psig HPI Trip Inplant Setpoint NOTE: Pressures given in the above figure are ideal and are not scaled to the specific transmitter calibration spans.
Rev. U/95 RET: Life of Plant RESP: Nuclear Engineering
0Florda Power DESIGN ANALYSISICALCULATION
........... Crystal River Unit 3 DESA-CFRM Page 9 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 1 10 FIGURE III ES/LPI BISTABLE DATA 900 psig I1S LPI Bypass Reset Value 875 psig LPI BYPASS Reset Inplant Setpoint 850 psig LPI BYPASS Permit Inplant Setpoint 560 psig LPI Trip Inplant Setpoint NOTE: Pressures given in the above figure are ideal and are not scaled to the specific transmitter calibration spans.
Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
SFlorida Power DESIGN ANALYSISICALCULATION CORPORATI.O N C rystal R iver U nit 3 DESA-C.FRM Page 10 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 OPERATIONAL CONSIDERATIONS: Maximum and Minimum Pressure Limits using Indicator, Recorder and Computer Points Uncertainty and 1/%-MinorDivision Readability When the RC-3A or 3B indicators, recorder or computer points are used to determine the RCS 0-2500 psig pressure range, the positive and negative indicator and recorder uncertainties and 1/2-minor division readability (readability error is not applicable to the computer points) should be treated as follows: For a maximum (increasing) pressure limit, the negative indicator, recorder or computer uncertainty value would be subtracted from the maximum allowed pressure limit value. For all indicators and recorders the resultant pressure value would then be rounded down to the nearest 1/2-minorscale division. For a minimum (decreasing) pressure limit, the positive indicator, recorder or computer uncertainty value would be added to the minimum allowed pressure limit value. For all indicators and recorders the resultant pressure value would then be rounded up to the nearest 1/2-minor scale division. EXAMPLE 1: For example, if the minimum allowable RCS pressure limit for accident conditions is 1625 psig the positive indicated pressure accident uncertainty at RC-3A-PI3 and RC-3B-P12 would be found on Table VII "Calibrated Total Loop Errors". (1) Take the required minimum allowable RCS pressure (1625 psig) and add the positive pressure accident uncertainty value for RC-3A-P13 and RC-3B-P12 from Table VII ( +158.3 psig) to the required minimum limit value (1625 psig + 158.3 psig = 1783.3 psig). (2) Round this calculated value (1783.3 psig) up to the next 1/2-minordivision (25 psig) which gives a required minimum pressure reading (1800 psig). This is the indicated value which must not be exceeded to ensure the minimum pressure (1625 psig) is not exceeded. Note: No rounding is required if computer points are used. EXAMPLE 2: If the maximum allowable RCS pressure limit for accident conditions is 1800 psig the negative indicated pressure accident uncertainty at RC-3A-P13 and RC-3B-PI2 would be found on Table VII "Calibrated Total Loop Errors". (1) Take the required minimum allowable RDS pressure (1800 psig) and subtract the negative pressure accident uncertainty value for RC-3A-PI3 and RC-3B-P12 from Table VII ( -147.0 psig) from the required maximum limit value (1800 psig - 147.0 psig = 1653 psig). (2) Round this calculated value (1653 psig) down to the next 1/2-minor division (25 psig) which gives a required maximum pressure reading (1650 psig). This is the indicated value which must not be exceeded to ensure the maximum pressure (1800 psig) is not exceeded. Note: No rounding is required if computer points are used. Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
Florida SPower DESIGN ANALYSIS/CALCULATION River Unit CORPOATIONCrystal 3 DESA-C.FRM Page 11 of 88 DOCUMENT IDENTIFICATION NO. IREVISION 1-89-0014 10 III. DESIGN INPUT (DI): Instrument loop drawing in Section I above and drawings 205-047 sheets RC-1 1 (Reference 1), RC-1 1A (Reference 2), RC-12A (Reference 73), RC-13A (Reference 56), D8034033 sheet 4 (Reference 3), 210-481 (Reference 4), 210-483 (Reference 5), 210-485 (Reference 6), 210-480 (Reference 64), 210-482 (Reference 71), and 210-484 (Reference 72) show the circuit configuration for the RC Pressure loops. 2 The transmitters RC-3A-PT3, RC-3A-PT4, and RC-3B-PT3 are part of instrument loops which provide signals to the Engineered Safeguards Actuation System (ESAS) and to R.G. 1.97 indication in the main control room. According to Section B.3.3.5 of the Improved Technical Specifications (ITS) (Reference 63), the analyzed accidents which rely upon automatic ESAS actuation include Loss of Coolant Accidents (LOCA), Main Steam Line Breaks (MSLB), Steam Generator Tube Rupture (SGTR), and feedwater line break events that result in a RCS inventory reduction or severe loss of RCS cooling. The ESAS actuation of High Pressure Injection (HPI) has been assumed for core cooling in the Small Break LOCA (SBLOCA) analysis and is also credited in the MSLB analysis for the purposes of adding boron and negative reactivity. The ITS allowable ES value of 1500 psig (ITS Table 3.3.5-1) for low RCS pressure is established to provide for the initiation of core protection systems on decreasing low RCS pressure. Such decreasing pressure would indicate either a severe overcooling event or a loss of reactor coolant. Accident analyses has previously used a conservative actual initiation setpoint of 1480 psig which bounds the ITS allowable value and accounted for uncertainties and instrument errors. The time delay between the onset of the accident and HPI initiation has been modeled in the accident analysis. At this low RCS pressure, the time delay prior to HPI initiation for some SBLOCAs can affect the PCTs achieved in the core. This will raise the ITS allowable ES value to 1625 psig and accident analysis F-98-0008 (Ref.78) will now use a setpoint approaching 1625 psig to provide a shorter time delay between onset of the accident and the initiation of HPI flow. This will result in slightly lower PCTs for the spectrum of SBLOCAs. The new ES initiation setpoint also accommodates the effects of increased steam generator tube plugging. 3 According to Section 2.4 of the TSBBD (Reference 62), the Crystal River 3 Improved Technical Specifications do not include a requirement for a low (1625 psig) RCS pressure trip setpoint for the ESAS actuation of Low Pressure Injection (LPI). According to Section B.3.3.5 of the ITS (Reference 63), the ESAS actuation of LPI has been assumed for LBLOCA's. Table 3.3.5.-l of that same reference provides a RCS Low-Low Pressure Setpoint of _t500 psig. Section B.3.3.5 also states that the RCS Low-Low Pressure Setpoint for LPI occurs in sufficient time to ensure LPI flow prior to the emptying of the core flood tanks during a LBLOCA. As with the RCS Low Pressure Setpoint described above, Section 2.1.4.3 of the TSBBD (Reference 41) states that the establishment of the ESAS Low-Low RCS Pressure Setpoint is determined from the accident analysis value by adjusting for errors of the instrument channel. According to Section 2.1 of the TSBBD (Reference 62), the LBLOCA establishes the basis for the LPI safety function of ESAS. This is true from a flow perspective, but not from an operability perspective. During a SBLOCA, the HPI and RB sprays will drain the BWST. Since the HPI pumps can not take suction directly from the RB emergency sump, the LPI pumps must operate in a recirculation mode (piggyback) to maintain operability of the HPI pumps. The operability of LPI has been assumed in analyses of LBLOCA's and SBLOCA's. LPI flow is required for a range of break sizes above a certain minimum; however, the LBLOCA is the most limiting event in requiring timely actuation LPI to meet the flow requirements. For some smaller break sizes, LPI flow is required and must be manually aligned to the HPI system to support extended core cooling, but is not limiting in terms of actuation. This is due to the relatively slow decrease in RCS pressure as a function of the break size. Rev. 6/95 RET: Life of Plant RESP: Nudear Engineering
SFlorida SPower DESIGN ANALYSIS/CALCULATION
........... Crystal River Unit 3 DESA-C.FRM Page 12 of 88 DOCUMENT IDENTIFICATION NO. ~REVISION 4 The Design Basis Document for Post-Accident Monitoring Instrumentation, Tab 5/11, (Reference 10), shows the TsAT meters as a Type A,B, Cat. 1 variable. This calculation will determine the error for signals sent to T'Sat for the accident environment, as well as the normal operating environment for the Post Accident Monitoring Instrumentation. Calculation 1-84-0002 (Reference 59) for T'Sat will use the error values from this calculation to compute the remaining loop error for the T'Sat.
5 RC-154-PR/TR was installed as part of the Overpressure Mitigating System. CMIS classifies this recorder as a R.G. 1.97 Category 3 variable; therefore, accident environment errors will be considered for the recorder's instrument loop. 6 Pressure transmitters RC-3A-PT3, RC-3A-PT4, and RC-3B-PT3 are located in the Reactor Building. (a) Per drawing 308-605 (Reference 12), RC-3A-PT3 is located at the North "X" Station at an elevation of 104'-1" (+/- 1") in the Reactor Building. (b) Per drawing 308-606 (Reference 13), RC-3A-PT4 is located at the North "Y"Station at an elevation of 104'-1/2"(+/- 1") in the Reactor Building. (c) Per drawing 308-603 Sheet 2 (Reference 14), RC-3B-PT3 is located at the South "X" Rack at an elevation of 102'-9" (+/- 4") in the Reactor Building. (d) The connections for RC-3A-PT3, RC-3A-PT4, and RC-3B-PT3 sensing lines are shown on drawings 308-601 (Reference 15), 308-602 (Reference 16), and 308-604 (Reference 17). The connections to the RCS Hot Legs for all three transmitters are at an elevation of 167-2%". Per CMIS, RC-3A-PT3, RC-3A-PT4, and RC-3B-PT3 are located in EQ Zone 66. Per the Environmental and Seismic Qualification Program Manual (E/SQPM - Reference 18) EQ Zone 66 is "HARSH" and has the following specifications: Radiation - Normal: 1.4 x 107 rads TID for 40 year dose. Radiation - LOCA: 1.3 x 108 rads TID (40 year TID + 6 months). Temperature - Normal: 700 to 109 0 F. Temperature - LOCA: 1100 to 3020 F. Temperature - HELB: NA Per drawing 308-601 (Reference 15) and 308-602 (Reference 16), the sensing lines are routed inside the D-Rings, which is designated as EQ Zone 40 per the E/SQPM (Reference 18) and has the following specifications: Radiation - Normal: 3.3 x 107 rads TID for 40 year dose. Radiation - LOCA: 1.4 x 108 rads TID (40 year TID + 6 months). Temperature - Normal: 1100 to 149 0F. Temperature - LOCA: 1100 to 302 0F. Temperature - HELB: NA Calculation 1-90-0014 (Reference 19) provides a point specific 10 year radiation dose for Zone 66. (e) RC-3A-PT3 is located at the North "X" Station in the Reactor Building; it has a 10 year dose rate of 2.3 X 103 rads at an elevation of 104'. Rev. 6195 RET: Life of Plant RESP: Nucdear Engineering
- oe DESIGN ANALYSIS/CALCULATION Crystal River Unit 3 DESA-C.FRM Page 13 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 (f) RC-3A-PT4 is located at the North "Y" Station in the Reactor Building; it has a 10 year dose rate of 2.3 X 103 rads at an elevation of 104'.
(g) RC-3B-PT3 is located at the South "X" Rack in the Reactor Building; it has a 10 year dose rate of 8.0 X 103 rads at an elevation of approximately 103'. 7 Instrument Data Sheets RC-3A-PT3 (Reference 20.a), RC-3A-PT4 (Reference 20.b), and RC-3B-PT3 (Reference 20.c) show that the pressure transmitters are Rosemount Model 11 54GP9RA pressure transmitters with a calibrated span of 0 to 2,500 psig. The specifications for these transmitters are described in Instruction Manual 1260 (Reference 21). The transmitters have the following specifications: Upper Range Limit (URL): 3,000 psig. Reference Accuracy: +/-0.25% of calibrated span (includes linearity, hysteresis, & repeatability). Temperature Effect: +/-(0.75% URL + 0.5% span)/100°F ambient temperature change. Drift (Stability): +/-0.2% of upper range limit for 30 months. Overpressure Effect: +/-0.5% of upper range limit after exposure to 4,500 psig. Power Supply Effect: < 0.005% per volt. Steam Pressure/Temp: +/-(2.5% URL + 0.5% span) during and after sequential exposure to steam at the following temperature and pressure, concurrent with chemical spray for the first 24 hours: 420 0 F, 50 psig for 3 minutes 3500 F, 110 psig for 7 minutes 3200 F, 75 psig for 8 hours 2650 F, 24 psig for 56 hours. Seismic Effect: +/-0.5% URL after a disturbance defined by a required response spectrum with a ZPA of 7 g's. Radiation Effect: +/-(1.5% URL + 1.0% span) during and after exposure to 55 x 106 rads TID gamma radiation at the centerline per the following dose rate schedule of: 2 x 106 rads/hr for 2 hours, 1.5 x 106 rads/hr for 4 hours, 1x 106 rads/hr upto6 55 x 10 rads TID and an additional 55 x 106 rads TID at a rate of 1 x 10 rads/hr during post-accident operation. Normal Operating Design Temperature Limits: 40 °F to 200 'F Mounting Position Effect: Effect is superseded by accuracy specifications. Response Time Fixed time constant (63%) at 100 0 F is 0.2 seconds. (a) Accident conditions use either the Temperature Effect or the Steam Pressure/Temperature Effect as identified in D129.h. (b) Per the Enhanced Design Basis Document for the Reactor Coolant System, Section 6/1 (Reference 22), the RCS pressure is limited to 2750 psig due to the Code Safety Valves and the Reactor Protection System (RPS). Because of this, the transmitters will never experience their overpressure limit, which is the same as their upper range limit (4,500 psig). Therefore, the overpressure effect for the pressure transmitters will be considered as +/- 0.0%. (c) Since the conditions required for the Steam Pressure/Temperature effect during Normal operating conditions is not applicable, the Normal Steam Pressure/Temperature effect will be considered as +/- 0.0%. Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
Florida Power
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DESIGN ANALYSIS/CALCULATION Crystal River Unit 3 DESA-C.FRM Page 14 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 (d) Per Letter LFM90-0006 (Reference 23); "It is not required to apply LOCA + MHE simultaneously to system functions." In other words, a Seismic event (MHE) and a LOCA do not need to be considered to occur simultaneously. Therefore, this calculation will only consider the LOCAIHELB effects (Radiation Effect and Steam/Temperature Effect) since the Seismic Effect is less than the LOCA/HELB effects. The Seismic Effect will be considered as +/- 0.0% for Normal and Accident conditions. (e) Per Letter SNES94-0276 (Reference 24), "...Rosemount has stated that any of these radiation induced errors may be compensated by calibration up to the tested dose from environmental qualification testing or about 110 MRads. Thus, it is shown that compensation of the radiation induced errors by calibration is a viable method up to the qualification level of 110 MRads." Per the Attachment to Letter SNES94-0276, "The lower the dose rate, the lesser the effect on instrument accuracy. For the lower dose rates (104 Rads/hour) itwas shown that a TID of less than 1 x 105 Rads resulted in a maximum output shift within the stated accuracy of the transmitter. These results are meant to be an aid in determining effects of radiation on accuracy of Rosemount transmitters." Since the highest dose rate expected for RC-3A-PT3, RC-3A-PT4, and RC-3B-PT3 is 8.0 x 103 rads for 10 years per D16, the NORMAL total dose rate for 30 months is 2.0 x 103 rads [(8 x 103 rads/10 years) x 2.5 years]. Therefore, the radiation effect for NORMAL operating 4 conditions will be considered as +/- 0.0% since the transmitters receive less than 1 x 10 rads/hour and a 30 month TID of less than 1 x 105 rads. (f) According to Instruction Manual 1260 (Reference 21), the pressure transmitter accuracy at reference conditions shall be within +/- 2.5% of the URL after exposure to the DBE for one year following the DBE. Since this value will be less than that calculated for the accident, the accident value will serve as the R.G. 1.97 post-accident accuracy. 8 All instrument string components other than the above transmitters and portions of the T'Sat Meter strings are located at the 145' elevation of the Control Complex (Reference 20 and CMIS). Per the E/SQPM (Reference 18), the 145' elevation of the Control Complex is designated as EQ Zone 13, which is "MILD" and has the following specifications: Radiation - Normal: <1.00 x 104 rads TID for 40 year dose. Radiation - Accident: <1.00 x 104 rads TID (40 year TID + 6 months). Temperature - Normal: 70°F to 801F. Temperature - LOCA: 95 0F for 1.5 hours (Based on loss of offsite power coupled with a LOCA) The RCITS modules are located at the 124' elevation of the Control Complex (Reference 20bb,cc). The PORV/T'Sat Meter Cabinets are located at the 108' elevation of the Control Complex(Reference 20), which according to the E/SQPM, is classified as EQ Zone 58. The zones are considered as "MILD" and have the same environmental data as Zone 13 except Temperature
- LOCA = 98 0 F.
9 Buffer amplifier (BA) RC-3A-PY3, bistables (BT) RC-3-BT1, RC-3-BT7, RC-3-BT4, and RC-3-BT1 0, transmitter power supply (PS) RC-3A-JX3, and associated resistor network are located in the ES Channel Test Cabinet 1 (Reference 20). Rev. 6195 RET: Life of Plant RESP: Nuclear Engineering
Florida SPower DESIGN ANALYSIS/CALCULATION Crystal River COAPORA71ON Unit 3 DESA-C.FRM Page 15 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 10 Buffer amplifier (BA) RC-3A-PY4-1, bistables (BT) RC-3-BT2, RC-3-BT8, RC-3-BT5, and RC BT1 1, transmitter power supply (PS) RC-3A-JX4, and associated resistor network are located in the ES Channel Test Cabinet 2 (Reference 20). 11 Buffer amplifier (BA) RC-3B-PY3, bistables (BT) RC-3-BT3, RC-3-BT9, RC-3-BT6, and RC-3-BT12, transmitter power supply (PS) RC-3B-JX3, and associated resistor network are located in the ES Channel Test Cabinet 3 (Reference 20). 12 Voltage buffers (EB) RC-3A-EB1, RC-3A-EB2, RC-3A-EB3, RC-3B-EB2, and RC-3B-EB3 and signal monitors (SM) RC-3A-PS3, RC-3A-PS4, RC-3A-PS5, RC-3A-PS6, RC-3A-PS7, and RC-3A-PY4 are located in the Non-Nuclear Instrumentation (NNI) cabinets (Reference 20). 13 Pressure indicators (PI) RC-3A-PI3 and RC-3B-PI2 are located on the Redundant Indicator Panel (RIP) above the ES section of the Main Control Board (Reference 20). 14 Pressure recorder (PR) RC-154-PR/TR is located on the HVR section of the Main Control Board (Reference 20). 15 Instrument Data Sheets RC-3A-PY3 (Reference 20.d), RC-3A-PY4-1 (Reference 20.e), RC-3B-PY3 (Reference 20.f) show that these buffer amplifiers are Bailey model 6621670A1 241 with a 10 Vdc input span and a 0 to +10 Vdc output. Calculations 1-83-0001 (Reference 45) and 1-90-1020 (Reference 74) provide the following specifications: Reference Accuracy (EBA(re)) = +/- 0.1% span Drift over 30 days (EBA(-.30)) = +/- 0.1% span Response Time (RTBA) = 1 sec. DRE (EBA(DRE)) = +/- 0.399 % span Design Temperature Range Operating Conditions: +/- 35 RF from the selected calibration temperature. Calibration temperature is to be between 75 °F and 105 RF (See Assumption xx). Therefore, operating temperature range is between 40 to 140 RF. RF Bailey qualified the 880 series of analog devices for use in nuclear facilities and reported on those results in several reports that are referenced in 1-83-0001 (Reference 45). The approach used by Bailey was to establish a Design Range Error (DRE) for the components that considered all the effects of the environment taken to the extreme range allowed by the specifications of the product. For example, the ambient temperature of the module was allowed to vary by as much as +/- 35 0F from the calibration (reference) temperature. Similar impacts for humidity and power supply effects were included and then combined algebraically to arrive at the DRE. This error value was used to initially calculate an "Abnormal" Condition error that was different from the "Accident" error The meters on the front plate of the Buffer Amplifiers are not used by Operations or for surveillance. The only function they provide is a maintenance aid. For that reason, they will be excluded from this instrument error calculation. 16 Instrument Data Sheets RC-3-BT1 (Reference 20.g), RC-3-BT7 (Reference 20.h), RC-3-BT2 (Reference 20.i), RC-3-BT8 (Reference 20.j), RC-3-BT3 (Reference 20.k), RC-3-BT9 (Reference 20.1), RC-3-BT4 (Reference 20.ee), RC-3-BT5 (Reference 20.ff), RC-3-BT6 (Reference 20.gg), RC-3-BT10 (Reference 20.hh), RC-3-BT1 1 (Reference 20.ii), and RC-3-BT12 (Reference 20.jj) show that these bistables are Bailey model 6621500A1 with a 0 to +10 Vdc input and a contact output. Calculation 1-83-0001 (Reference 45) provides the following specifications: Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
Florida Power DESIGN ANALYSIS/CALCULATION Crystal River Unit 3 DESA-C.FRM Page 16 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 Reference Accuracy (EBT(re,) = +/- 0.17% span Drift over 30 days (EBT(df-30)) = +/- 0.03% span Potentiometer Resolution (EBT(pt)) = +/- 0.05% span Repeatability of Setpoint (EBT(sp)) +/- 0.02% span Temperature Effect (EBT(t)) = + 0.07% span Humidity Effect (EBT(hum)) = +/- 0.56% span Response Time (RTB-T) = 100 ms Design Temperature Range Operating Conditions: +/- 35 'F from the selected calibration temperature. Calibration temperature is to be between 75 'F and 105 'F (See Assumption xx). Therefore, operating temperature range is between 40 'F to 140 'F. 17 Calculation 1-83-0001 (Reference 45) gives a 30 day drift value for the buffer amp. A 30 month drift is calculated using the SRSS method described in Section 6.2.7 of ISA-RP67.04 (Reference 38). It is assumed that the drift during each of the 30 day drift periods is random and independent. 2
]1/
(EBA(df)) = +/- [(30)(EBA(5r-0))
= +/- [(30)(0.1) ]
= 0.548% span 2
(EBT(dft)) = [(30)(EBT(dlr 30I)
= + [(30)(0.03)]
= +/- 0.164% span 18 Instrument Data Sheets RC-3A-JX3 (Reference 20.m), RC-3A-JX4 (Reference 20.n), and RC-3B-JX3 (Reference 20.o) show that these power supplies, which provide power to the above transmitters, are Foxboro model 610-AT power supplies. According to Instruction Manual 49, Volume lC, Book 1887 (Reference 27), dc output voltage from this power supply is regulated to +/- 2 volts over a range of 76 volts (10 ma) to 84 volts (50 ma). These power supplies were originally installed to support a 10-50 ma transmitter circuit; however, MAR 82-05-24-04 (Reference 51) replaced the transmitters with the 4-20 ma transmitters described in DI7. Voltage divider networks were added to allow the original power supplies to be used with the new transmitters. Although the new transmitter's minimum current (4 ma) is less than the published minimum current (10 ma) associated with the power supply output regulation value, the fact is that the resistors were sized for a total current output from the power supply that is within the 10 to 50 ma range (see MAR 82 24-04 Reference 51). For that reason, the +/- 2 volt power supply regulation still applies with the new transmitters.
19 When MAR 82-05-24-04 (Reference 51) replaced the transmitters with Rosemount transmitters, the original 250Q dropping resistors were replaced by voltage divider networks (consisting of 630n, 1300Q, and 1600Q resistors) to allow the continued use of the original power supplies, while providing the same input voltage range (2.5 - 12.5 Vdc) to the Buffer Amplifiers (References 4, 5, &
- 6) and ensuring sufficient voltage was provided to the transmitter to keep it within its design range.
According to procurement documents within the MAR (including FCN-15A), the resistors are Ohmite Series 55 Acrasil Wirewound Type (Models 55-5-S-630RO-B, 55-5-S-1K300-B, and 55-2-S-1K600-B) and have a manufacturer's tolerance of +/- 0.1% (Attachment 2). Since the transmitter maintains a constant current output dependent upon the pressure it sees (and not based upon inaccuracies in the load resistance), the only resistor error the Buffer Amplifiers see is that associated with the 6302 dropping resistor across their input. The errors associated with the other resistors in the current loop will have no effect on the 2.5 - 12.5 Vdc Buffer Amplifier input voltage. Referring to the schematic for the Buffer Amplifier given in Bailey Product Instruction E92-316 (Instruction Manual 206 - Reference 43), the input impedance for the Buffer Amplifier is 100kN. Rev. 6195 RET: Life of Plant RESP: Nuclear Engineering
S Florda SPower
......... o. DESIGN ANALYSIS/CALCULATION Crystal River Unit 3 DESA-C.FRM Page 17 of 88 DOCUMENT IDENTIFICATION NO- REVISION 1-89-0014 10 The input filter resistor for a Buffer Amplifier with a gain of I (last digit of Buffer Amplifier part number is either a 1 or 2) has a value of 50kQ. This resistor is in series with a 50k.Q resistor on the Buffer Amplifier's input stage amplifier up to the operational amplifier's summing point. Therefore, the input impedance is the summation of these two resistors. MAR 82-05-24-04 installed a 630n dropping resistor on the presumption that the input impedance of the Buffer Amplifier was 80k1.
This value appears to be in error. Apparently it was believed that the input filter resistor was 30kQ (instead of 50k.0), which corresponds to an incorrect gain of 1.25. The use of the incorrectly sized dropping resistor appears to have little or no effect on plant operation since the combined dropping resistor/Buffer Amplifier resistance is so close to the correct value (626n rather than 62592). Despite this, the error created by the incorrectly sized resistor will be accounted for in this calculation. The maximum total input current of 20 mA from the transmitter is divided between the 630n resistor and the two 50kQ resistors (0.01% tolerance per Instruction Manual 206) in the Buffer Amplifier's input circuit. With a tolerance of 0.1%, the 6300 resistor's actual value from the supplier could be 630CI (1.001) = 630.63K or 630n (0.999) = 629.37K. Neglecting the tolerance of the Buffer Amplifier input resistors, the following equation can be written to describe this current divider: 20 mA = (V/630.63C) + (V/10OkI) V 12.534 volts and 20 mA = (V/629.37Q) + (V/1 00kg) V = 12.509 volts For a resistor output of 2.5 V to 12.5 V (10 V span), the above translates into the following resistor error values: ERES(BIAS) = [(12.534 V - 12.5 V)/10 V](100%)
= + 0.34% span and ERES(BIAS) = [(12.509 V - 12.5 V)/10 V](100%)
= + 0.09% span The larger value will be used in this calculation; therefore ERES(BIAS) = + 0.34% span The above resistor error is considered a bias error. It applies to the unscaled outputs of the Buffer Amplifier (i.e. 1700# HPI and 900# LPI bypass bistables, signal monitors, computer, indicators, etc.). Since this calculation assumes the Buffer Amplifier is calibrated with its resistor (Assumption 4), the above error is calibrated out for the scaled ouputs of the buffer amplifier (i.e. 1500# HPI and 500# LPI trip bistables). The scaled output has an adjustable gain which can compensate for the Rev. 6195 RET: Life of Plant RESP: Nuclear Engineering
Florida
- Pow= DESIGN ANALYSISICALCULATION Crystal River Unit 3 DESA-C.FRM Page 18 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 differences between the actual and calculated resistor values. Therefore, this resistor error will not apply to the scaled outputs of the Buffer Amplifier.
According to the Ohmite product sheet for the resistors (Attachment 2), the resistors have a temperature coefficient of +/- 20 ppm/°C (or 0.002%/°C) for resistors 1092 and above. Using the ambient temperature variation of +/- 20°F normal and +/- 34 0F accident (Assumption 1) for the Buffer Amplifier, the following temperature effect is calculated for the 6300 resistor: ERESN(temp) = + (0.00002/°C)(630*2)(20 0 F)(5 0 C/90 F)
=+/- 0.140 ERESA(temp) = + (0.00002/°C)(630!))(34 0 F)(5°C/9 0 F)
= +0 2389 This resistor error due to temperature variations produces a voltage error proportional to the transmitter current. The temperature effect will have the greatest impact at the maximum transmitter current (20 mA); therefore, this error in terms of % of span is:
ERESN(temp) = + {[(0.14Q)(0.020 A)]/10 V)(100%)
= + 0.028% of span ERESA(temp) = + {[(0.238C)(0.020 A)]/10 V)(100%)
=+/- 0,048% of span The above temperature effect error term is treated as a random error in this calculation and is applied to both the scaled and unscaled Buffer Amplifier outputs.
20 Instrument Data Sheets for RC-3A-EB1 (Reference 2 0.p), RC-3A-EB2 (Reference 20.q), RC-3A-EB3 (Reference 20.r), RC-3B-EB2 (Reference 20.p), and RC-3B-EB3 (Reference 20.s) show that these voltage buffers are cards contained within Bailey model 6624610 buffer modules with a 0 to
+10 Vdc input and a 0 to +10 Vdc output. Instruction manual 49 (Reference 46) provides the following specifications:
Reference Accuracy (EEg(re)) = + 0.1% span Temperature Effect (EEB(temp)) = +0.25% span Normal Temperature Range = 40 OF to 140°F 21 Instrument Data Sheets RC-3A-PS3 (Reference 20.t), RC-3A-PS4 (Reference 20.u), RC-3A-PS5 (Reference 20.v), RC-3A-PS6 (Reference 20.w), RC-3A-PS7 (Reference 20.x), and RC-3A-PY4 (Reference 20.y) show that these signal monitors are Bailey model 6623819-1 with a 0 to +10 Vdc input and a span of 0 to 2,500 psig. Instruction manual 49 (Reference 47) provides the following specifications: Reference Accuracy (EsM(reý) = +/- 0.25% span Temperature Effect (ESM(temp)) = +/- 0.25% span Repeatability = +/- 0.1% span Hysteresis = -0.05% span Normal Temperature Range = 40 OF to 140 OF 22 Instrument Data Sheets for RC-3A-PI3 (Reference 20.z) and RC-3B-PI2 (Reference 20.aa) show that these indicators are Bailey model ES-260 with a 0 to +10 Vdc input for a span of 0 to 25 (psi X Rev. 6/95 RET: Lifeof Plant RESP: Nuclear Engineering
Florida Power CORPORATION DESIGN ANALYSIS/CALCULATION Crystal River Unit 3 DESA-C.FRM Page 19 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 100 or 0-2500 psi). Instruction manual 49 (Reference 48) provide the following specifications for indicators with DC movements: Reference Accuracy (EES(reO) = +/-1.0% span Temperature Effect (EES(temp)) = +/-0.01%/fF Linearity = +/-0.25% span Hysteresis = 0.8% span Repeatability = 0.25%span Dead Band = 0.25% span Humidity = Negligible Minor Scale Division = 50 psig Normal Temperature Range = 40 OF to 140 OF Per Assumption #9, the linearity, hysteresis, dead band, and repeatability errors are assumed to be included in the stated reference accuracy. However, the ambient temperature effects and readability must be factored in to arrive at a total error value. This is achieved using the SRSS methodology since these are considered random error terms. 23 Per FPC Calculation 1-97-0015 (Reference 11), the Low Temperature Overpressure Protection (LTOP) ITS value for the PORV is 457 psig, with an inplant setpoint of 442.6 psig.. 24 Instrument Data Sheet for RC-1 54-PR/TR (Reference 20.dd) shows that this indicator is a Esterline Angus strip chart recorder model MS426C-30(A)-90(B)-90(C)-30(D)-90(E)-90(F)-D201 DR61 -RD-E7 with a 0 to +10 Vdc input for a span of 0 to 2,500 psig for both the A & B pressure signals. The specifications for the pressure recorder are described in Instruction Manual 1243 (Reference 49). The recorder has the following specifications:. Reference Accuracy (EREC(re)) = +0.5% span Temperature Effect (EREC(temp)) = +/-0.03%/°C over 10°C to 450 C Deadband = 0.2% span (maximum) Minor Scale Division = 50 psig (indicating and recording) Normal Temperature Range = 50 °F to 113 °F 25 CMIS show that the Auxiliary Relays RC-3A-AR1 and RC-3A-AR2 are Bailey Model 6624913-1. These relays make no contribution to the instrument error since they are discrete (on/off) devices. 26 Bailey test modules RC-3A-PX3, RC-3A-PX4, and RC-3B-PX3 will not be considered in this calculation, because they are only used for testing ( Reference 37). The modules do not contribute to the loop error. 27 The I&C Design Criteria (Reference 25), Calculation 1-89-0004 (Reference 9), and ISA-RP67.04 Part II(Reference 37) provide the bases for the development of calculations which require the incorporation of Insulation Resistance (IR)effects. According to Figure 9 of Bailey Product Instruction E92-316 (Reference 43), the transmitter loop is grounded through the Buffer Amplifier input circuit; therefore, the IReffects are due to conductor-to-ground as well as conductor-to-conductor current leakage. Rev. 6195 RET: Lie of Plant RESP: Nuclear Engineering
- Poe DESIGN ANALYSIS/CALCULATION CORPOATIONCrystal River Unit 3 DESA-C.FRMV Page 20 of 88 DOCUMENT IDENTIFICATION NO REVISION 1-89-001 10 28 Per Calculation 1-88-0015 (Reference 26), the following is a list of the circuit data for the loop components which are located in a "HARSH" environment:
INSTRUMENT LOOP CABLE WDP SEAL SPLIT PEN B NO. SENSOR MFG MODEL B/M (EK) CKT LGNT QT MF QTY NO. Y RC-3A-PT3 RMT 1154 36A-001 RCR86 130 188 1 RMT 2 SPL 129 RC-3A-PT4 RMT 1154 38A-001 RCR91 65 184 1 RMT 2 SPL 132 RC-3B-PT3 RMT 1154 37A-001 RCR95 150 185 1 RMT 2 SPL 130 29 Since environmental effects can greatly affect transmitter signal accuracy, and since the accidents identified in D12 &3 can represent substantially different environmental conditions, this calculation must consider the following environmental scenarios under which these transmitters will operate to satisfy the requirements of D12 & 3:
- a. Normal Environmental Conditions
- b. Environmental Effects Prior to ES Actuation Following LBLOCA
- c. Environmental Effects Prior to ES Actuation Following SBLOCA
- d. Environmental Effects Prior to ES Actuation Following MSLB
- e. Environmental Effects Post-Accident (SBLOCA)
- f. Environmental Effects Post-Accident (LBLOCA)
- g. Environmental Effects Post-Accident (MSLB inside and outside containment)
The RB accident environment following a main feedwater line break is considered to be enveloped by the main steam line break RB environment since main feedwater temperature and pressure is lower than that of main steam. The accident analysis for the Steam Generator Tube Rupture accident takes credit for HPI; however, this accident doesn't create severe RB environmental conditions which can affect the signal accuracy. Therefore, it will not be included in this evaluation. The above normal and accident conditions will now be discussed as to their impact on various transmitter accuracy components (i.e. temperature, insulation resistance on the circuit, steam pressure/temperature, and radiation). The normal and accident temperatures described in the ESQPM are used in all temperature calculations rather than the Technical Specification limit for RB average temperature of 1300F. The Technical Specification limit represents an average temperature over the RB elevations during normal (non-accident) plant operations. Since the subject transmitters are located on the 95' elevation, their temperatures will be lower than the average RB temperature.
- a. Normal Environmental Conditions The only effects considered are the transmitter temperature effects created by the differential temperature between the transmitter's calibration temperature and the normal operating temperature inside the RB. Insulation resistance (IR) degradation is not a concern since there is no steam environment and no high temperatures present to reduce insulation resistance. As explained in D17.e, radiation effects are not a factor for the normal operating environment.
- b. Environmental Effects Prior to ES Actuation Following LBLOCA (>0.5 It)
Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
Florida Power
...........ONCrystal DESIGN ANALYSIS/CALCULATION River Unit 3 DESA-C.FRM Page 21 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 HPI According to D13, HPI is not considered for LBLOCA. The depressurization to the HPI analysis actuation value (1625 psig) is so immediate that the transmitters essentially perform their HPI safety function before the changing environment has time to affect their accuracy.
For that reason, the only LOCA environment that is likely to adversely affect the accuracy of the transmitters before they are able to perform their HPI safety function is the SBLOCA which will be addressed under D129.c.. LPI According to the Topical Report BAW-10103A (Reference 79), the RCS depressurizes to the LPI setpoint (500 psig) following a double-ended, 8.55 ft2 break at the RCP discharge in approximately 18.5 seconds. Section 5.0 of Calculation 1-88-0028 (Reference 65) states that due to the size and nature of a LBLOCA, there is very little difference in the RCS pressure responses for different break sizes and locations. The maximum RB temperature over this period rises to 299OF according to Zone 66 environmental data from the EQSPM (Reference 18). Since the transmitter electronics housing is sealed from the environment, an accident pressure spike should have no effect on the transmitter accuracy. For this reason, the transmitter steam pressure/temperature effect error term should not apply from strictly a pressure standpoint. The real environmental parameter impacting the transmitter accuracy is the environment temperature. Since there is a thermal lag associated with the transmitter, the transmitter housing will not reach 302OF before the LPI actuation pressure is reached. The maximum transmitter housing temperature will be far less than the temperature the transmitter was tested to for which the steam pressure/temperature effect applies. Rosemount conducted a thermal response test of the internal housing of its 1154D transmitter (using the same stainless steel housing as used on the subject transmitters) and found the thermal time constant to be approximately 4.8 minutes (Reference 8 and Attachment 3). Using a lumped parameter approach to heat transfer, a transmitter temperature at the time of LPI actuation can be derived. This method provides good results whenever the internal conductive resistance is small compared to the external convective resistance. Whenever this is true, the temperature of the object will be spatially uniform at any given time. Rosemount used this approach in Attachment 1 to determine transmitter temperature as a function of time. The approach as illustrated in Attachment I assumes a step change in environment temperature. In actuality, the LOCA temperature profile for the RB involves a ramp change in environment temperature. The approach will be modified to accommodate a ramp change. According to the environmental data for Zone 66 from the ESQPM (Reference 18), the building temperature ramps from 110°F to 299°F during the first 1 second and is at 3020 at the end of 150 seconds, following the LBLOCA. As mentioned earlier, a ramp up to 302°F will be assumed for the 18.5 seconds time to actuation. Attachment 1 provides the following equation: (T1 - TO) = (T2 - TO)(1 - e(-trrc)) or T1 = TO + (T2 - TO)(1 - e(-trrc)) where: TO = Temperature of the electronics board (or other device) at time = 0 Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
- owe DESIGN ANALYSIS/CALCULATION CO R P O R ATION C ry s ta l R iv e r U n it 3 DESA-C.FRM Page 22 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 T1 = Temperature of the electronics board (or other device) at time = t T2 = Temperature of the environment at time = t t = Time TC = Time Constant of the transmitter housing (or other device)
Using this equation, the transmitter temperature at the time of LPI actuation is: TTN(18.5.) = 110°F + (302°F - 110°F)(1 - e'(18.5sy(288 s)
= 1220 F Since the transmitter temperature at the time of LPI actuation is below the 200°F design range for the Rosemount transmitter (Reference 21), the normal temperature effect error term will be used in the computation of the LPI error rather than the steam pressure/temperature effect.
Since during the time to LPI actuation the instrumentation cable, splices, conduit seals, and penetrations are exposed to an elevated environment temperature and humidity, the issue of decreased insulation resistance effects on the instrument loop must be addressed. As with the transmitter, there is a thermal lag associated with these devices. Rather than performing a rather rigorous finite element thermal analysis on each device to determine its approximate temperature at the time of LPI actuation, the above lumped parameter approach will be used for each device for this accident. Subsequent comparisons of these results with those of other accidents will be made later in the Design Inputs, using the worst case ES actuation and post-accident temperatures to determine the effect of IR. Attachment 2 of Calculation 1-89-0004 (Reference 9) states the IR lag of multiconductor cables is typically about 3 minutes for those tested in SAND89-1755C (Attachment 2 of Calculation 1-89-0004 - Reference 9). Although the specific cable used in the RC pressure application was not included in the above test, since silicone rubber cable was tested, the 3 minutes thermal lag is considered applicable to this calculation. According to the report, this 3 minute period was the time it took for the cables to reach a stable value of IR. The report does not indicate how many time constants this value represents, but if it is considered that this 3 minute period represents 3 time constants, one time constant would be equal to 60 seconds. This time constant should be conservative since the cables were not tested in conduit. The RC pressure transmitter cables are routed in conduit. Conduit provides additional thermal resistance to cable temperature increases and would thus increase the actual thermal time constant of the cable (i.e. reduce the cable temperature). In addition, as will be seen later, this thermal time constant is much smaller than that calculated for heat shrink sleeving (based upon actual thermal data for the sleeving). The thermal time constant of the cable is most likely more along the order of that of the heat shrink sleeving. Using the 60 seconds as a conservative thermal time constant, the following cable temperature at the time of LPI actuation following a LBLOCA is calculated using the above lumped parameter approach: Tc(18.5s) = 110"F + (302'F - 110°F)(1 - e-(1'-'s)(60 ))
= 161OF According to CMIS, the electrical penetration feedthroughs are Conax feedthroughs. Since the penetrations involve much more thermal mass than the transmitters, they will have a much larger thermal time constant, resulting in a lower penetration temperature at the time of LPI actuation. Since no thermal time constant information is available from the manufacturer, Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
Florida Power CORPORATION DESIGN ANALYSISICALCULATION Crystal River Unit 3 DESA-C.FRM Page 23 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 it is conservatively considered that the penetration temperature will be the same as the transmitter temperature (122°F) at the time of LPI actuation. TP = 122°F VQP TERM-R098-04, the applicable VQP per D133, Raychem has not published data regarding thermal lag through its WCSF-N splice sleeving. Attachment 7 containes the results of laboratory testing done on a sample of WCSF-200 material. From those test results, a thermal time constant for the HPI/LPI actuation periods (0-120 seconds) based upon the inside sleeve temperature will be determined using the same lumped parameter approach established earlier: 0 126 0C = 50'C + (225 C - 50°C)(1 - e-(120 sy(TC) TC =211 seconds This thermal time constant is conservative since it is based upon a splice sleeving that is not enclosed in a splice box or penetration housing. Estimated splice temperatures based on this thermal time constant will be higher than what is expected in the application for these transmitter circuits. The estimated inner sleeve temperature at LPI actuation is: 2 11
= 1 10°F + (298°F - 1 10°F)(1 - e"(15s S)/( s))
Ts(l8.5s)
= 126°F No thermal time constant information is available for the Rosemount conduit seals used at the transmitters; therefore, the seals will be considered as having the same thermal time constant as the cable. This should be conservative since the seals are an extension of the cable and are more dense than the cable. Therefore, the transmitter seal temperature at LPI actuation is considered to be the same as the cable temperature (161 OF).
Tcs = 161'F Attachment 4 estimates an expected integrated dose at 20 seconds following a LBLOCA of 8.55 ft2 as 50 Rad. Since this exposure combined with a 30 month normal operating exposure (described in D16) is less than the threshold for the radiation effects to apply (see D17.e), no radiation effects will be considered for the LPI error. The transmitter performs its LPI safety function before it receives enough radiation to affect the accuracy of its signal.
- c. Environmental Effects Prior to ES Actuation Followinq SBLOCA (_<0.5 ft2)
HPI With the HPI/MU System upgrade (MARs 97-02-12-01 and 97-02-12-02 References 85 and 86) and associated setpoint changes, the period of operability of the ES HPI channels for a SBLOCA and the applicable RB environment at the time of actuation are determined by examining FTI documents 32-1266348-01 (Reference 87) and 32-1266137-01 (Reference 81). For small breaks from 0.5 ft2 down to 0.04 ft. 2. the ES HPI actuates very quickly as the RC pressure drops, i.e., within the first 40 to 50 seconds into the transient. The smaller size SBLOCAs result in a much slower depressurization, which results in a greater exposure of the transmitter and other circuit devices to the post-accident reactor building environmental conditions prior to the initiation of the HPI safety function. Rev. M/5 RET: Ufe of Plant RESP: Nuclear Engineering
Florida Power C.......... DESIGN ANALYSIS/CALCULATION Crystal River Unit 3 DESA-C.FRM Page 24 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 1 10 For a break size of 0.01 ft.2, FTI document 32-1266348-01 (Reference 87) indicates that the revised HPI analysis actuation setpoint (1625 psig) is reached around 200 seconds. The corresponding RB atmosphere is at an approximate temperature of 160 0F, FTI Document 32-1266137-01 (Reference 81). To be conservative and ensure that the calculation will not have to be revised each time the temperature profile changes, this instrument accuracy calculation will use a more conservative value of 180°F for the RB temperature. This value corresponds to that for a break size of 0.04 ft.2 at 78 seconds. This value is taken from FTI document 32-1266137-01 (Reference 81). (Note that this is conservative because ES actuation occurs at approximately 43 seconds for the 0.04 ft 2 break with the revised ES actuation setpoint.) Using the same lumped parameter approach described earlier and conservatively using a step change of the RB environment to 180°F to simplify the calculation, the transmitter housing temperature at the time of HPI actuation can be estimated 200 seconds after the SBLOCA occurs: TTN(200s) = 110OF + (180°F - 110-F)(1 - e7(200 sy288 S))
= 145OF Since the transmitter temperature at the time of the HPI actuation is below the 200'F design range for the transmitter, the normal temperature effect error term will be used in the computation of the HPI error. In addition, since the HPI actuation temperature for the transmitter is higher than that calculated for the LPI actuation following a LBLOCA, to simplify the error calculation, the higher HPI (SBLOCA) transmitter temperature (145 0 F) will be used for both.
Using the same 60 second thermal time constant used for the LBLOCA LPI evaluation and following the same approach, the following cable temperature at the time of HPI actuation following a SBLOCA is calculated: Tc(2 oos) = 110°F + (180°F - 110°F)(1 -e"(2°°s)/(60s)
= 178 0 F Since this cable temperature is higher than that calculated for the LBLOCA LPI actuation, the higher temperature (178 0 F) will be applied to both accidents to simplify the calculation.
As was done under the LBLOCA LPI evaluation, the penetration temperature at the time of HPI actuation is conservatively considered to be same as the transmitter temperature. Since the SBLOCA HPI actuation results in a higher transmitter temperature, to simplify the calculation, the higher HPI (SBLOCA) 145°F value will be used for both actuation's. Using the same approach and thermal time constant used for the LBLOCA LPI actuation, the following Raychem splice inner sleeve temperature is found for the HPI actuation: 2 2 Ts(20os) = 110OF + (180OF - 110OF)(1 - e-( 00 s)/( 11 s))
= 153 0F Since this splice temperature is higher than that calculated for the LBLOCA LPI actuation, the higher SBLOCA HPI value (153 0 F) will be applied to both accidents to simplify the calculation.
As was done for the LBLOCA LPI actuation evaluation, the transmitter seal temperature is conservatively considered to be the same as the cable temperature. Since this temperature is higher than that calculated for the LBLOCA LPI actuation, the higher temperature (1 70°F) will be applied to both accidents to simplify the calculation. Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
0Florida Power CORPORATION DESIGN ANALYSISICALCULATION Crystal River Unit 3 DESA-C.FRM Page 25 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 BWNT document 51-1234893-00 (Attachment 4) estimates an expected accident integrated dose at 200 seconds following a SBLOCA of 0.01 ft2 as 250 Rad. Since this exposure combined with a 30 month normal operating exposure (per D16) is less than the threshold for the radiation effects to apply (see D17.e), no radiation effects will be considered for the HPI error. The transmitter performs its HPI safety function before it receives enough radiation to affect the accuracy of its signal. LPI For the SBLOCA events, the combination of HPI and CFT will terminate the fuel clad heatup. Since the pump startup time is on the order of a few seconds, a slight increase in the time that LPI flow becomes available will not change the results.. Therefore, no error effects will be considered for the LPI setpoint for SBLOCA's.
- d. Environmental Effects Prior to ES Actuation Followinq MSLB HPI For the overcooling events, namely the steam line break accident, the increase in the ES setpoint will result in HPI being actuated earlier which has the potential for a slightly increased cooling effect. In the analysis of record, Reference 66, HPI was initiated at 5.5 seconds (1587 psia with no ES actuation time delay). This results in approximately a 106-psi/second decrease in RCS pressure prior to actuation. Considering the worst-case instrument uncertainties, HPI could be actuated one second earlier. The makeup/HPI system modification increases the hydraulic resistance of the HPI injection lines over the current configuration. This effectively reduces the HPI flow delivery to the RCS for any given pressure.
Based upon the above, a MSLB environment will not be considered in calculating the instrument error for HPI. LPI The FSAR Chapter 14 analysis for the MSLB makes no mention of taking credit for the low-low RCS pressure ES actuation; therefore, instrument loop accuracy will not be considered for pre-ES actuation for this accident.
- e. Environmental Effects Post-Accident (SBLOCA)
These effects are enveloped by the more severe temperature, pressure, and radioactive environment of the LBLOCA and will therefore not be calculated separately.
- f. Environmental Effects Post-Accident (LBLOCA)
The steam pressure/temperature effect on accuracy published in the Rosemount literature applies to the transmitter (rather than the normal environmental temperature effect) since it will be exposed to the environment for the duration specified in the product specification. To address IR effects on the cable, penetrations, seals, and splices, and to simplify the calculation, instead of calculating the maximum temperatures these devices would reach during the accident, IR values will be taken at a maximum temperature of 302 0 F. This is conservative since due to the thermal lag of these devices, they will never reach the maximum 302°F RB temperature (Zone 66 environmental data from the ESQPM - Reference 18). The radiation effect specified in the product specifications for the transmitter applies since the transmitter will be exposed to a radioactive accident environment. Rev. 6195 RET: Life of Plant RESP: Nuclear Engineering
Florida Power
......... o. DESIGN ANALYSIS/CALCULATION Crystal River Unit 3 DESA-C.FRM Page 26 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10
- g. Environmental Effects Post-Accident (MSLB)
The MSLB inside the RB is encompassed by the LBLOCA profile (Reference 18) and the LBLOCA RB 302°F temperature will be used for the transmitters, cables, penetrations, seals and splice. The steam pressure/temperature effects published in the transmitter literature apply to the transmitter since it will be exposed to the environment for the duration specified in the product specification. The cable and penetration temperatures for a MSLB occurring inside the Intermediate Building (IB) would be greater than that of the cable and penetrations for a MSLB accident inside the RB, producing a greater insulation resistance error. However, the steam pressure/temperature error effect seen by the transmitters during a LBLOCA inside the RB, which would not apply to the transmitters for the MSLB accident inside the IB, is a much larger contributor to instrument loop error and would thus more than offset the difference in IR values. For that reason, the LBLOCA accident inside the RB represents the worst-case error.
- h. The above environmental conditions are summarized by the following table:
;:..-. . ...s*.-.....-...-...:.. :. .. . ..... .......
.......................
Normal Operating Normal Temperature No Effect No Effect No Effect No Effect Effect (109 0 F - 70 0F) , LPI/HPI Normal Temperature 153 0F 178OF 145°F No Effect Actuation Effect (133 0 F - 70 0 F) R.G. 1.97 Accident Steam 302°F 302°F 302°F Accident Press/Temp Effect Radiation Effect 30 The Configuration Management Information System (CMIS) shows the EQ Zones and the VQP's applicable to all of the components addressed in this calculation. The component cable IR values are taken from these VQPs (References 29, 34 and 42). 31 The methodology used in Appendix D of ISA-RP67.04 (Reference 38) is used to determine the error due to degraded insulation resistance. Per Section 6.2.2 of the I&C Design Criteria For Instrument Loop Uncertainty Calculations (Reference 25): "IR uncertainties due to accident environments are considered systematic." This combined error term is therefore additive with the other terms in the total loop error calculation. 32 The cable IR (Rc) is derived from the cable qualification test specimen IR (R), the specimen length (LsPL) and the total length of cable in the harsh environment (LcKT), in feet. Therefore, the following formula is used: RCE = Rc x LSPL/LcKT Rev. 6/95 RET: Life of Plant RESP: Nudear Engineering
Florida Power
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DESIGN ANALYSIS/CALCULATION Crystal River Unit 3 DESA-C.FRM Page 27 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 According to CMIS, the VQP which applies to the cables used in this application is CABL-C595-08 (Reference 42). Contained in Tab F1 of that reference is Anaconda (same as Continental Wire & Cable Corp.) Report 79118. Appropriate IR values for the cable at the above maximum ES actuation and post-accident monitoring temperatures (D129.h) will be taken from this report. According to Table II of Tab F1, of the specimens tested, Specimens 49.6.1, 2, and 3 were aged at the highest temperature/duration value and were aged radioactively at a gamma total integrated dose (TID) closest to that of ESQPM Zone 66 - 2.9 x 107R (D16) versus 2.0 x 107R. Previous revisions of Calculation 1-89-0014 used data from Calculation 1-88-0004 (Reference 28), which determined an IR value based upon a specimen from this report which had not been aged. The 49.7 specimens were aged at a higher TID than the 49.6 specimens; however, these cables exhibited unexpected behavior with respect to IR versus temperature. As the temperature was lowered, the IR value for these specimens dropped. According to Table IV of the VQP, the 49.5 and 49.7 specimens (those aged the most radioactively) failed the high potential withstand test. Both sets of specimens exhibited the same unexpected behavior with respect to IR versus temperature. For these reasons, Specimens 49.6.1, 2, and 3 will be considered applicable for this calculation. Table III gives conductor-to-ground IR values for the cable specimens. No conductor-to-conductor values were given; therefore, according to Assumption 10, the conductor-to-conductor value is assumed to be twice that of the conductor-to-ground value. One of the lowest IR values of the three aged specimens prior to testing was 2.44 x 1011 ohms (Cl) per Table Ill. According to this table, the Pre-LOCA IR reading was taken while the test chamber was at 68 0F, implying the cable temperature was also 680 F. The lowest IR value of the three at the first LOCA plateau of 280°F was 1.77 x 1080 during chemical spray with an applied voltage of 500 Vdc. No test data is available in the VQP for the maximum ES actuation temperature calculated above without chemical spray and at a lower applied voltage. IR data was taken after devices were soaked at steady elevated temperatures. Using this source alone, it cannot be determined whether or not a time lag (not to be confused with the thermal lag) exists before IR begins to take effect, whether or not IR would be significant in the absence of chemical spray, and whether or not the applied voltage is a major contributor to the measured value. Data from the SAND89-1755C report (Attachment 2 of Calculation 1-89-0004 - Reference 9) and SAND90-2629 (Reference 70) does shed some light on these questions. The testing done in both was conducted without chemical spray; the cables were exposed to saturated and superheated steam. Data from both reports supports the premise that once the steam environment and cable temperatures begin to increase, the cable IR begins to decrease with little or no time lag. The IR decrease rate is rather dramatic if the environment (and cable) temperature rate of increase is also large. The SAND89-1755C report also concluded that IR is largely independent of voltage over the range of 50-250 V for the cables that were tested (which included silicon rubber). ISA RP67.04, Part II (Reference 38) illustrates the relationship between temperature and insulation conductivity (or the inverse of insulation resistance) as an exponential function. To estimate a cable insulation resistance applicable to HPI/LPI actuation (Rc(ACT)) at a cable temperature of 170°F (maximum between calculated HPI and LPI cable temperatures in D129.h) this relationship will be used rather than using linear interpolation (which would give a higher IR value). The relationship is as follows: C = CO a e(B13 where: C Conductivity of the insulation or the inverse of the insulation resistance (R) Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
Rod Florida
*R Power DESIGN ANALYSISICALCULATION CORPOA71ONCrystal River Unit 3 DESA-C.FRM Page 28 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 CO & B = Constants T = Temperature in °K (Absolute temperature will be expressed in OR since the constants will be derived. OR = OF + 460°F )
Using the above data from the pre-LOCA and first plateau, the constants are solved as follows: 1/(2.44 x 101n) =CO eIB/(68-F + 460aF)] 2 4 1/(1.77 x 10'0) = CO. e[B/( 8°°F + 60°F)i Simplifying and taking the natural log of both sides of both equations yields the following:
- 26.22 = In (CO) + (-B)(0.00189)
- 18.99 = In (CO) + (-B)(0.00135)
Subtracting the second equation from the first and solving for B yields: B = 13,389 Substituting this value for B into the first equation and solving for CO yields:
-26.22 = In (CO) + (-13,389)(0.00189)
CO = 0.4006 Substituting the above constants and the estimated 178°F cable temperature into the relationship yields the following cable insulation conductivity (conductor-to-ground) for the HPI/LPI actuation cable temperature: CCg(ACT) = (0.4006) e-13 -38 9 1(178F +460F)]
=3.08 x 10"10 mhos Since RCC-g(ACT) = 1/C(ACT)
RCcg(ACT) = 1/(3.08 x 10-1° mhos)
= 3.25 x 109n (20 ft sample per page 3-2 of Tab F1)
Using the cable lengths from D128, the following cable IR values are found for the HPI/LPI actuation: RCc-g(ACT) = 3.25 x 1090 (20 ft)/(130 ft)
= 5.00 X 108Q for RC-3A-PT3 RCc-g(ACT) = 3.25 x 109n (20 ft)/(65 ft) 1.00 X 109 for RC-3A-PT4 RCc-g(ACT) = 3.25 x 109n (20 ft)I(150 ft)
= 4-33-x 10!Q for RC-3B-PT3 Rev- 6/95 RET: Life of Plant RESP: Nuclear Engineering
*1h%= DESIGN ANALYSISICALCULATIONCrystal River Unit 3 DESA-C.FRM Page 29 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 The sample result agrees very closely with the IR measurements taken for the three 49.6 cable specimens at 180°F (from Table III of the cable VQP) of 1.27 x 109n, 1.36 x 1090, and 3.8 x 108K).
Therefore, the calculated value will be used for the cable IR (conductor-to-ground) at the HPI and LPI actuation points. Per Assumption 10, the conductor-to-conductor value for the HPI/LPI actuation cable temperature is therefore: 2 RCc-(ACT) = (Rc-(ACr)) For the above cables, conductor-to-conductor values are then: RCcc(ACT) = 2(5.00 x 108n)
= 1.00 x I 090 for RC-3A-PT3 RCc-C(ACT) = 2(1.00 x 10 9n)
= 2.00x1Q for RC-3A-PT4 RcC,(AcT) = 2(4.33 x 108Q)
= &. x 10LQ for RC-3B-PT3 For the post-accident conditions, the lowest value of the 49.6 specimens will be used:
Rcc-g(. 97) = 8.3 x 107k (20 ft sample per page 3-2 of Tab Fl) Using the cable lengths from D129, the following cable IR values are found for the post-accident condition: Rcc-g(1.9 7) = 8.3 x iO7 (20 ft)/(130 ft)
= 1.28 x 107) for RC-3A-PT3 Rccg(j9-* = 8.3 x 107n (20 ft)/(65 ft)
= 2.55 x 107 for RC-3A-PT4 Rcc-g(I.97) = 8.3 x 1iO7 (20 ft)/(150 ft)
= 1.11x 10zýQ for RC-3B-PT3 The post-accident conductor-to-conductor values are therefore (per Assumption 10):
Rc,-cl.9 7) = 2(1.28 x 107f)
= 2.56 x 107) for RC-3A-PT3 Rcc(l.97 ) = 2(2.55 x 10o7 )
= 5.1Q0x10D for RC-3A-PT4 Rc.-(I.9 7 ) = 2(1.11 x 107n)
= 2.2Zx I7Q for RC-3B-PT3 Rev. 6f95 RET: Life of Plant RESP: Nuclear Engineering
Florida Power DESIGN ANALYSIS/CALCULATION CORPORATION Crystal River Unit 3 DESA-C.FRM Page 30 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 This estimated post-accident IR values should be conservative (i.e. applying only for a short period) since even for the worst case profile (LBLOCA), according to Zone 66 data from the ESQPM (Reference 18), the RB temperature has dropped below 302°F 4 minutes after the accident began. 33 CMIS lists three VQP's for the splices. These were reviewed for applicability with the following results: TERM-R098-02 is for motor connection kits. TERM-R098-04 (Reference 55) is for standard bolted and butted in-line splice assembly kits. TERM-R098-05 is for non-standard (improperly installed) splices with Raychem WCSF-N heat shrink tubing. Since all of the splices addressed by this calculation are in-line butt splices, VQP TERM-R098-02 does not apply. The following walk down packages were reviewed to determine whether any anomalies were present for the splice configuration so a determination of which of the remaining VQP's apply S....................... RC-3A-PT3 Per WDP 0188 (Reference 31) VQP TERM-R098-04 applies. MAR 90-06-10-02 relocated transmitter above flood level. Work Request NU 0287448 (Reference
- 61) re-spiced cable. Inspection Plan accepted splices.
RC-3A-PT4 Per WDP 0184 (Reference 32) VQP TERM-R098-04 applies. MAR 90-06-10-02 relocated transmitter above flood level. Work Request NU 0287448 (Reference
- 61) re-spliced cable. Inspection Plan accepted splices.
RC-3B-PT3 Per WDP 0185 (Reference 33) VQP TERM-R098-04 applies. MAR 90-06-10-02 relocated splices. Per WDP, Work Request NU 0296434 installed spices. QC inspection accepted installation. PEN-129 No anomalies per WDP 0817 VQP TERM-R098-04 applies since no (MTBD-9A) (Reference 52). anomalies found. PEN-1 30 Seal on braided cable per WDP VQP TERM-R098-04 applies since no (MTBD-9B) 0254 (Reference 55). anomaly. Actual seal is on cable insulation. Raychem holds braid in place. 1800 bend per WDP 0254 VQP TERM-R098-04 applies since (Reference 55). specimen D9 (Tab B, 4.1) in-line butt splice with bend radii of less than 5 times the diameter, recorded no leakage (Tab F2, p. VIII-10). PEN-132 No walk down on inboard per WDP Assume same as 9B and 9A. VQP (MTBD-9C) 0815 (Reference 54). TERM-R098-04 applies. Rev. 6/95 RET: Lifeof Plant RESP: Nuclear Engineering
Florida Power
....oRAI
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DESIGN ANALYSIS/CALCULATION Crystal River Unit 3 DESA-C.FRM Page 31 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 Since either no anomalies were found or what anomalies were found had no impact on reducing the IR of the splices at the transmitters and penetrations, the IR for all of the splices will be determined by an evaluation of VQP TERM-R098-04 (Reference 55) for standard WCSF-N splice sleeves. According to Tab F5 of the VQP, of the six specimens tested, two (Specimens 1-5 and 1-6) were not thermally aged, and two (Specimens 1-1 and 1-2) suffered splitting of the cable insulation near the splice sleeves. IR data from Table 1 of Tab F5 is incomplete for Specimen 1-3 at the lower temperatures. Therefore, data for Specimen 1-4 will be used in this calculation. IR values from Table 1 are considered to be conductor-to-ground. Per D129.h, the maximum splice temperature for HPI/LPI actuation is 139 0 F. According to Table 1 of Tab F5 of the VQP, the closest temperature to this temperature for which IR data exists is 21 0°F. Instead of using this value, the same approach used in D132 will be used to estimate an IR for the lower temperature. From Table 1, Specimens 1-4 had an IR value at ambient temperature (assume 75-F) of 5 x 10'°Q. At the highest temperature (3141F), this specimen had an IR value of 1.8 x 107g. The following constants are determined for the splice material: 11(5.0 x 101°)) = CO e[B/(75* F+ 460*F)] 3 4 1/(1.8 x 107C2) = CO
- el[BI( 14°F + 60°F)l Simplifying and taking the natural log of both sides of both equations yields the following:
-24.64 = In (CO) + (-B)(0.00187)
- 16.71 = In (CO) + (-B)(0.00129)
Subtracting the second equation from the first and solving for B yields: B = 13,672 Substituting this value for B into the first equation and solving for CO yields:
-24.64 = In (CO) + (-13,672)(0.00187)
CO = 2.5260 Substituting the above constants and the estimated 153 0 F splice temperature into the relationship yields the following splice conductor-to-ground insulation conductivity: 3 6 72 1 3 CSc.g(ACT) = (2.5260)
- e[- 5 -F + 46',F)]
= 5.20 x 1010 mhos Since Rsg(Acr) = l/Csc-g(Acr)
RScg(ACT) = 1/(5.20 x 10.10 mhos)
= 1.92 x109 0 Rev. 695 RET: Life di Plant RESP: Nuclear Engineering
Florida Power
........... DESIGN ANALYSISICALCULATION Crystal River Unit 3 DESA-C.FRM Page 32 of 88 DOCUMENT IDENTIFICATION NO- REVISION 1-89-0014 10 In comparison, the lowest IR value for Specimen 1-4 at 210°F from Table I of the VQP is 4.6 x 108Q. Per Assumption 10, the conductor-to-conductor value for the HPI/LPI actuation splice temperature is therefore:
Rs.(ACm) = 2 (Rsc~g(AcT))
= 2(1.92 x 109Q)
Since according to Table I and Figure 4 of Tab F5 the IR measurement for the splices were taken 12 minutes after the initial temperature rise to 390 0 F, and since the splice has a thermal time constant of 211 seconds (per D129.b), the splice specimens would have exceeded the maximum 300OF temperature estimated for the post-accident conditions (D129.h). Therefore, the IR value at 314°F from Table 1 for Specimen 1-4 will be conservatively used. Rsc-g(1. 97 ) = 1.8 xA10 Per Assumption 10, the conductor-to-conductor post-accident value for the splice is therefore: Rs c(1.97) = 2(Rsc-g(g97
=2(1.8 x 10 92)
= 3.6 x107 Additional conservatism is included in the above IR values for the splices due to the fact that per Tab F5 of the VQP, each test circuit consisted of three (3) test splices, each consisting of a single layer of WCSF-N sleeving. In addition, per Page 10 of 11 of Tab D2, a higher concentration of chemical spray was used than what is used at CR3 and for a longer duration. This calculation will use the above calculated values for the two splices in the circuit (one at the penetration, the other at the transmitter seal).
34 VQP INST-R369-03 (Reference 29) covers Rosemount Model 1154 transmitters. Tab F2, Section II, page 11-5 states that the transmitters used a Conax conduit seal during the qualification testing. According to the walk down packages for RC-3A-PT3 (Reference 31), RC-3A-PT4 (Reference 32), and RC-3B-PT3 (Reference 33), Rosemount 353C conduit seals are used on the transmitters. Since VQP INST-R369-03 does not list the IR associated with the Conax conduit seal, and since a Rosemount 353C conduit seal is actually used in the plant configuration, the IR values associated with the Rosemount 353C conduit seal will be included for conservatism. VQP PEN-R369-01 (Reference 34) documents the testing of the Rosemount Model 353C conduit seal. Calculation 1-88-0003 (Reference 35) calculated an IR based upon the acceptance criteria given in the test report, which was that the voltage measured across the 5000 in the test could not shift by more than 40 mV. According to the calculation, the test setup used in the qualification test measured total leakage (lead-to-lead and leads-to-case). It further added that since it is not possible to determine how the leakage is divided, all measured leakage current was assumed to be lead-to-lead leakage. The calculation then used the 40 volts between the seal leads to arrive at an IR value of 5 x 105. Rosemount (Jane Sandstrom) indicated that the acceptance criteria values typically are very conservative. Rev. 6195 RET: Life of Plant RESP: Nuclear Engineering
- FRorida Power DESIGN ANALYSIS/CALCULATION Crystal CORPO.ATION River Unit 3 DESA-C.FRM Page 33 of 88 DOCUMENT IDENTIFICATION NO. I REVISION 1-89-0014 10 A less conservative approach is to use actual test data from the VQP (as has been done with the other devices in the circuit) to arrive at the appropriate IR value. Two different design configurations were tested. According to Tab 14, Page 2, the conduit seals supplied to CR3 were of the Design 2 configuration (i.e. leads covered with heat shrink tubing, epoxy stycast potting, and modified strain relief). Per Tab F1, Appendix A, Page 17 & 18, the initial LOCA test was interrupted by steam escaping from the chamber. Inspection of the test units revealed that the heat shrink tubing on the lead wires of the units had been perforated during the test setup. A modification of the configuration was made, and the units were re-tested. The results of the tests were a maximum shift of unit A003 of 21 mV during the first test and 4 mV (Page 20) during the re-test. The other unit (AO01) had suffered degradation; therefore, the data for unit A003 will be used in this calculation.
According to Tab F2, Sections 17.3.1 and 17.3.2 of the VQP, the acceptance criteria during the LOCA test for voltage shifts across the 5002 resistor and for IR measurements was 40 mV and 6 x 10'5. According to Sections 17.2.4 and 10.1.2.4.2, this IR measurement was to be from lead-to-case. Although the test procedure gave instructions for taking IR measurements while at elevated temperatures during the test (Section 17.3.2 and 17.2.4), this apparently was not done until after the chamber had cooled. (Tab F1, Appendix A, Table 7). Therefore, the only way to establish an IR value for the LOCA temperatures is to evaluate the voltage shift measured during the LOCA test. Using the approach of Calculation 1-88-0003 (Reference 35) and the 4 mV shift value from the test, a leakage current of 0.004 V/5009 = 8 x 106A is found. Tab F1, Appendix A, Page 6 indicates the voltage potential between the leads was 40 V. Insulation resistance is then 40 V/8 x 106A = 5 x 106n, which agrees closely with that determined above. Since the data does not indicate when the maximum 4 mV shift occurred, it is reasonable to assume that it occurred at the maximum seal temperature (due to the nature of IR). Since according to Page 18 of Appendix A (Tab Fl) the chamber temperature was held for 320°F for 8 hours, the seal temperature would have reached the same ambient temperature. Therefore, a less conservative estimate for conductor-to-ground IR at 320°F for the seal would be 5 x 106n. Despite the higher IR value estimated above, this calculation (to maintain consistency between current IR calculations) will use the more conservative value of 5 x 101/29 for the post-accident monitoring condition (assumed conductor-to-conductor in Calculation 1-88-0003). RsEALc1c(g.97) = 5aXiaa Per Assumption 10, the post accident conductor-to-ground IR value is then: RsEALOg(1.97) = (I/ 2 )(RSEALC 5*1.97))
= (1/2)(5 x 10 Q)
= 25X10i2 As stated in D129.c, the conduit seal temperature at the time of HPI or LPI actuation is conservatively considered to be that of the cable (170 0 F). No IR values were recorded at that temperature during the LOCA test; however, IR values for unit A003 were taken following thermal aging during a functional aging test when the seals were cycled between 40°F and 175 0F and between 50% and 95% relative humidity. According to Tab F2, Sections 10.2.2.6 and 10.1.2.4.2, the IR measurements were to be from lead-to-case. On the 20th day of such cycling, the IR value for unit A003 taken at 1750 F and 50% relative humidity (value was lower than that at 95% relative humidity) was 2.8 x 1070 per Tab F1, Appendix A, Table 3. Although this test was done prior to the radiation aging, examination of data taken following the functional aging (Table 4) and following the Rev. 6/95 RET: Life of Plant RESP: Nudear Engineering
P DESIGN co-04710.Crystal ANALYSIS/CALCULATION R River Unit 3 DESA-C.FRM Page 34 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 radiation aging (Table 5) show negligible IR degradation caused by radiation. Therefore, a 2.8 x 107 conductor-to-ground IR value for the HPI/LPI actuation is reasonable. RSEALcg(ACT) = Per Assumption 10, the conductor-to-conductor IR value at the HPI/LPI seal actuation temperature is then: 2 RSEAL.c(ACT) = (RsEALc-(ACT))
=2(2.8 x 1070) 35 Per CMIS, Penetrations 129 (MTBD-9A), 130 (MTBD-9B), and 132 (MTBD-9C) are all covered under VQP PEN-C515-04 (Reference 36). Tab D1, note 3 of the VQP states that the test profile envelops the plant worst case LOCA/MSLB composite profile except for 60 seconds at the beginning of the test, and notes that the thermal stresses imposed by the test are considered more severe than the short 150F temperature spike in the plant. Note 1 states that the test of Tab F1 is applicable to the CR-3 installed equipment. Note 9 states that the feedthroughs utilize #14 AWG conductors.
Per D129.h, the penetration temperature at HPI/LPI actuation is conservatively estimated to be 1330 F. According to Tab F1, Data Sheet L of the VQP, no leakage current was detected until 6 hours had elapsed in the environmental test (which reached temperatures in excess of 3700 F). From this it is concluded that the 200 seconds to the HPI actuation point will present no detectable change in IR over the thermally and radiation aged reading. According to Page 10 (Section 6.12.4) of Tab F1, the lowest measurement of aged and irradiated penetration feedthroughs was 2.1 x 109n. It was not indicated whether this represented a conductor-to-ground or a conductor-to-conductor measurement; therefore, the conservative approach is to consider it conductor-to-conductor. Therefore: RPENc-(ACT) = 2.1 x 0 Per Assumption 10, the conductor-to-ground IR value at the HPI/LPI actuation temperature for the penetration is then: 2 RPENc-(ACT) = (1/ )(RpENc-,(ACT))
= (1/2)(2.1 x 109K)
Per D129.h, the penetration temperature to be used for post-accident monitoring is 3020 F. According to Tab F1, Pages 25 and 26, IR measurements were taken during the design basis event environment test, and these results were recorded on Data Sheet P (Appendix A). Pages 1, 2, & 3 of Data Sheet P (Tab F1, Appendix A) provide the IR measurements for the #14 AWG penetration feedthroughs. The data on these data sheets implies the data was taken on 7/18/80. According to Data Sheet K (Sheet 13 of 32, Tab F1, Appendix A), the chamber temperature on that date was in excess of 3140F. This is confirmed by Data Sheet K (Sheet 3 of 32) which implies the test began on 7/14/80 and Figure 6.20.7 of Tab F1 which provides the temperature/pressure test profile. It can therefore be concluded that the data from Data Sheet P was taken when the penetration feedthroughs temperature was in excess of 302 0 F. The lowest IR value from those data sheets were": Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
Florida Power
......... o. DESIGN ANALYSIS/CALCULATION Crystal River Unit 3 DESA-C.FRM Page 35 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 RpENc-g(1. 97 ) 2x 107Q RpENC.c(1.97) = 3.0 x 107k Leakage current was also measured throughout the test. These measurements are documented on Data Sheet L of Appendix A. The maximum leakage current for the #14 AWG conductors was 0.12 mA at 536 VAC; therefore, the IR at that point was (536 V/0.12 mA) = 4.47 x 106 . For conservatism, this calculation will use the lower IR value and will also conservatively assume it represents a conductor-to-conductor value.
RpENc-c(1.97) = 4A. xi106 Per Assumption 10: RpENC-g(1.97) =
= (1/2)(4.47 2.24x 106Mx 106n) 36 Two types of "As-Left" tolerances will be developed in this calculation:
a) ALLOOP:IN will be the SRSS of the Reference Accuracies of loop components located inside a "Harsh Environment". b) ALLOOP:OUTWill be the SRSS of the Reference Accuracies of loop components located outside a "Harsh Environment" Since "As-Left" tolerances are only used to determine drift between calibrations, only Normal operating condition parameters affect the determination of the tolerances. 37 In accordance with the I&C Design Criteria (Reference 25) Instrument loop errors that are associated with the HPI and LPI trip and alarm function are being calculated using the Category "A" graded approach. The "Calibrated" Loop Error will be determined from the SRSS of the random portion of the "Calculated" Loop Error and the "As-Found" tolerances for the Loop. The "Calibrated" Loop Error is the maximum error that operations could expect between calibrations of the loop. TERMS USED INTHE PARTIAL SPLIT LOOP "A" GRADED APPROACH CELOOP:TOTAL = Calibrated Loop Error - The overall instrument channel error, which is used to determine setpoints and action values from the design limit/analytical limit. CELOOP: IN Calibrated Split Loop Random Error for the instrumentation inside containment, intermediate building, or wherever a harsh environment exists during normal plant operation, precluding on-line calibration. CELoop:ouT = Calibrated Partial Loop Random Error for the combined partial loops in an instrument channel outside of a harsh environment, which can be calibrated on line. ELOOP IN Calculated Split Loop In Error - Error of instrument split loop located in a harsh environment that does not take into account calibration, drift, process errors and known biases. 2 2
+/- [(EcoMPIlN) 2
+ (EcoMP21N) + ... (EcoMPNIN) ]'A Rev. 6/95 RET! Life of Plant RESP: Nuclear Engineering
Florida Power
......... 0. DESIGN ANALYSISICALCULATION Crystal River Unit 3 DESA-C.FRM Page 36 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 ECOMPPL = Component Error - The SRSS of the errors associated with an individual component in a partial loop (i.e.: Reference Accuracy, Temperature Effect, etc.),
with the exception of Drift. 2 2 EpL-3S= +/- [(EcoMPIPL.BS) 2 + (EcoMP2PL.BS) + ... (ECOMPNPLBS) ]A EBS = +/- ECOMPBS MTELOOP:IN = M&TE (Maintenance &Test Equipment) error - The errors due to the M&TE used in the calibration of equipment located in a harsh environment. MTEPL = M&TE (Maintenance &Test Equipment) error- The errors due to the M&TE used in the calibration of a partial loop. SBLOOP:IN = Stability/Drift - The error due to the stability/drift of the components in a harsh environment, which cannot be calibrated on-line. SBPL = Stability/Drift - The error due to the stability/drift of the components in the partial loop which can be calibrated on-line. ALLOOP:IN = As-Left Tolerance or Calibration Tolerance - The tolerance to which a split loop in a harsh environment is left after calibration. This term is determined from the Reference Accuracy of the components. 2
= +/- [(COMP1-EREF)2 + (COMP2-EREF) + ... (COMPN-EREF)2]'A ALPL = As-Left Tolerance or Calibration Tolerance - The tolerance to which a partial loop is left after calibration. This term is determined from the Reference Accuracy of the components.
2 2 ALPL-BS= +/- [(COMP1-EREFPL.BS) 2 + (COMP2-EREFPL-BS) + (COMPN-EREFPL.BS) ]% AL8 s = +/- COMP-EREFBS AFLOOP:IN = As-Found Split Loop:ln Tolerance - The tolerances in which a split loop in a harsh environment can be after a period of operation, prior to calibration. These terms includes the errors due to M&TE and Drift/Stability. 2 2
+/-
+ {ALLOOP:IN + [(MTELOOP:IN) + (SBLOOP:IN) ]'1}
AFPL = The tolerances in which a partial loop can be after a period of operation, prior to calibration. These terms includes the errors due to M&TE and Drift/Stability.
= 22 AFPL-BS +/-{ALpL-BS + [(MTEpL-BS) 2 + (SBPL-BS) 2 ]1}
AFBs = +/-{ALBs + [(MTEEs) 2 + (SBBs)2]'} EBIAS:IN/OUT = Bias Errors - Known biases that affect the operation of an instrument loop, such as static pressure shifts, IR effects, etc. Rev. 6/95 RET: Life of Plant RESP: Nudear Engineering
aFlorida Power
......... o. DESIGN ANALYSIS/CALCULATIONCrystal River Unit 3 DESA-C.FRM Page 37 of 88 1-89-0014 DOCUMENT IDENTIFICATION NO. REVISION 10 EBIAS:OUT = +/- EBIAS:PL.BS +/- EBIAS:BS EPROCESSIN = Process Errors - The error that results from the range of process operation limits, based on the scaling of the sensing instruments. This error includes either normal or accident conditions.
ENPE = Normal Process Errors - The error that results from the range of Normal process operation limits, based on the scaling of the sensing instruments. EAPE = Accident Process Errors - The error that results from the range of Accident process operation limits, based on the scaling of the sensing instruments. (Difference between ENPE extremes and accident extremes). Nominal Value = A value determined to require no error correction. Category A (Split-Loop) 2 2
- 1) CELOOP:IN = +/- [(ELOOP:IN) + (AFLOOP:IN) ]',
- 2) CELOOP:OUT= + [(EPLBS) 2
+ (AFPL.BS) 2
+ (EBs) 2
+ (AFBs) 2]1/2
- 3) CELOOP:TOTAL = +/- [(CELoOP:IN) 2
+ (CELOOP:OUT) ]
2 11 2
+/- EPROCESS:IN +/- EBIAS:IN +/- EBIAS:OUT Instrument loop errors that are associated with the T'SAT, RECALUSPDS, Recorders and Indicators are being calculated using the Category "B" graded approach. The formula that will be used for the calibrated loop errors is as follows:
TERMS USED IN THE PARTIAL SPLIT LOOP "B" GRADED APPROACH CELOOP: TOTAL = Calibrated Loop Error - The overall instrument channel error, which is used to determine setpoints and action values from the design limit/analytical limit. CELOOP: IN = Calibrated Split Loop Random Error for the instrumentation inside containment, intermediate building, or wherever a harsh environment exists during normal plant operation, precluding on-line calibration. CELOOP:OUT = Calibrated Split Loop Random Error for the instrumentation outside of a harsh environment, which can be calibrated on-line. ECOMP = Component Error - The SRSS of the errors associated with an individual component (i.e.: Reference Accuracy, Temperature Effect, etc.), with the exception of Drift. ELooP IN/OUT = Calculated Split Loop Errors - The instrument split loop errors not taking into account calibration, drift, process errors and known biases. 2
+/-- [(EcoMpISPLIT)2 + (ECOMP2SPLIT) + ... (EcoMPNSPLIT)2]1/2 Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
Florida Power DESIGN ANALYSIS/CALCULATION y CORPOATIONCrystal River Unit 3 DESA-C.FRM Page 38 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1 1-89-0014 10 MTELOOP IN/OUT= M&TE (Maintenance & Test Equipment) error - The errors due to the M&TE used in the calibration of the split loop. SB3LOOP N/OUT Stability/Drift - The error due to the stability/drift of the components in the split loop. ALLOOP IN/OUT = As-Left Tolerance or Calibration Tolerance - The tolerance to which a split loop is left after calibration. This term is determined from the Reference Accuracy of the components. 2 2 2
- +/- [(COMP1-EREF) + (COMP2-EREF) + ... (COMPN-EREF) ]'
AFLOOP IN/OUT = As-Found Split Loop Tolerances - The tolerances in which a split loop can be after a period of operation, prior to calibration. These terms includes the errors due to M&TE and Drift/Stability. 2
= +/- {ALSPLITLOOP + [(MTESPLITLOOP) + (SBsPLITLOOp) 2
]1}
EEIASIN/OUT= Bias Errors - Known biases that affect the operation of an instrument loop, such as static pressure shifts, IReffects, etc. EPROCESSIN = Process Errors - The error that results from the range of process operation limits, based on the scaling of the sensing instruments. This error includes either normal or accident conditions. ENPE = Normal Process Errors - The error that results from the range of Normal process operation limits, based on the scaling of the sensing instruments. EAPE = Accident Process Errors - The error that results from the range of Accident process operation limits, based on the scaling of the sensing instruments. (Difference between ENPE extremes and accident extremes). Nominal Value = A value determined to require no error correction. Category B (Split Loop) This is the second category in the "Graded Approach". The methodology for this category will be the same as for Category A instrument strings, except that the Normal Process Errors will be combined via the SRSS method with the other random loop errors. Inaddition, 2/3 of the M&TE error will be used. This method still ensures appropriate actuator actions are taken. Nevertheless itdoes not compromise the ability to use the instrumentation by more accurately reflecting actual uncertainty. CAUTION: CE LOOP:IN and CE LOOP:OUT can have different equations (Equations 1,2, or 3) depending on which condition (Condition 1, 2, or 3) is met by each part of the split loop. For example, CE LOOP:IN could require Equation I and CE LOOP:OUT could require Equation 3. Rev. 6/95 RET: UWeof Plant RESP; Nuclear Engineering
Florida Power
........... DESIGN ANALYSIS/CALCULATION Crystal River Unit 3 DESA-C.FRM Page 39 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 Condition #1:
The following criteria are to be applied separately to CELOOP:JN and CELOOP:OUT: IfALSPLITLOOP is greater than the SRSS of the Reference Accuracy of the components in the split loop and 2 2 AFSPLITLOOP is greater than (ALsPLITLOOP + [(2/3 MTESPLITLOOP) + (SBsPLrrLOOP) ]f), then the formulas to use are: Equation #1 2 2
- 1) CELOOP:IN= +/- 2
[(ELOOP:IN) +(ENP-N) + (ALLOOP:IN + [(2/3 MTELOOP:IN)
+ (SBLOOP:IN) I )]I Caution: Ifthe CELOOP:IN is less than the AFLOOP:IN, then CELOOP:IN - +/- AFLOOP:IN Note: Also, see Attachment 1,General Information Number 10.
- 2) CELooP:OUT = +/- [(ELOOP:OUT) 2 + (ALLOOP:OUT + [(2/3 MTELOOP:OUT) 2 + (SBLoOP:OUT) 2] ) 2]1 Caution: Ifthe CELOOP:OUT is less than the AFLOoP:OUT, then CELOOP:OUT = +/- AFLOOP:OUT 2 2
- 3) CELOOP:TOTAL = +/- [(CELOOP:IN) + (CELoOP:OUT) 2]% +/- EBIAS:IN +/- EAPE:IN + EBIAS:OUT Condition #2 The following criteria are to be applied separately to CELOOP:IN and CELoOP:OUT:
Ifthe ALsPLITLOOP is greater than the SRSS of the Reference Accuracy of the components in the split loop and 2 AFsPLITLOOP is less than (ALsPLTLOOP + [(2/3 MTESPLITLOOP) 2
+ (SBsPLITLOOp) ]),
then the formulas to apply are: Equation #2
- 1) CELOOP:IN = +/- [(ELOoP:IN) 2
+ (ENPE:IN) 2
+ (AFLooP:IN )2]1 2
- 2) CELOOP:OUT +/- [(ELOOP:OLT) + (AFLOOP:OUT )21/
- 3) CELOOP:TOTAL =+/- [(CELOOP:IN) 2
+ (CELOOP:OUT) ]%,
2 I EBIAS:IN +/- EAPE:IN +/- EBIAS:OUT Condition #3: The following criteria are to be applied separately to CELOOP:IN and CELooP:OUT: Rev. 6/95 RET: Lifeof Plant RESP: Nuclear Engineering
eFlorida Power
......... o.
DESIGN ANALYSIS/CALCULATION Crystal River Unit 3 DESA-C.FRM Page 40 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 1 10 If the ALSPLrrLOOP is less than or equal to the SRSS of the Reference Accuracy of the components in the split loop, then the formulas to use are: Equation #3 2 2 2
- 1) CELOoP:IN = +/- [(ELOOp:IN) 2
+ (ENPE:IN) + (2/3 MTELOOP:IN) + (SBLOOP:IN) ]'2 Caution: If the CELOoP:IN is less than the AFLOOP:IN, then CELOOP:IN = +/- AFLOOP:IN Note: Also, see Attachment 1, General Information Number 10.
2 2 2
- 2) CELOOP:OUT= + [(ELooP:OUT) + (2/3 MTELOOP:OUT) + (SBLOOP:OUT) ]/
Caution: If the CELOOP:OUT is less than the AFLOOP:OUT, then CELOOP:OUT = + AFLOOP:OUT Note: Also, see Attachment 1, General Information Number 10. 2 2
- 3) CELOOP:TOTAL= +/- [(CELOOP:IN) + (CELOOP:OUT) ]11 +/- EBIAS:IN +/- EAPE:IN + EBIAS:OUT 38 Surveillance Procedure SP-132 (Reference 37) describes the calibration equipment to be used during the calibration of RC-3A-PT3, RC-3A-PT4, and RC-3B-PT3 loop components. The procedure presently states that Keithley Model 2001 and Model 197A, a transmation, and Druck DPI-51 0 are to be used (or their equivalent). Voltage measurements on Bailey 880 modules (Buffer Amplifiers and Bistables) require a voltmeter with an input impedance of at least 100 Mo (per Instruction Manual 206 - References 43 and 44). A Keithley 2001 satisfies this requirement.
The following MTE values combine the reference accuracy, calibration tolerance, and temperature effect terms in a SRSS fashion which is allowed by ISA-RP67.04, Part II,Section 6.2.6.1 (Reference 38). Per Calculation 1-95-0005 (Reference 68), the following M&TE values apply to the 0 - 3000 psig input range/4 - 20 mA output range Druck DPI-510 Pressure Controller/Calibrator when used on the 95' elevation of the RB: MTEDP = + 0.115% reading Calculation 1-95-0005 (DPI-5105p2) MTEDI = +/- 0.165% span (4 - 20 mA output span) Calculation 1-95-0005 (DPI-5105A2) Note: Per calculation 1-95-0005 (Reference 68), the Keithly 2001 has M&TE errors less than the ones stated for the Druck above and may be subsituted for the Druck to measure current on the 20 mAdc range. Since the maximum calibration pressure is 2527.8 psig and the calibrated span of the transmitters is only 2,500 psig, the M&TE for the Druck will be conservatively corrected for this difference: MTEDP = + 0.115% span (2527.8 psig/2500 psig)
= +_0.116% span Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
Florida Power CO ......... DESIGN ANALYSISICALCULATION Crystal River Unit 3 DESA-C.FRM Page 41 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 Per Calculation 1-95-0005 (Reference 68), the following M&TE value applies to the Keithley 197A Digital Multimeter when used at the 145' elevation of the Control Complex for a 4-20 mA span: MTEKI = + 0.190% span Note: Per Calculation 1-95-0005 (Reference 68), the Keithly 197 and 2001 have M&TE errors equal to or less than the Keithley 197A above and can be subsituted for the Keithley 197A to measure current on the 20 mAdc range. Per Calculation 1-95-0005 (Reference 68), the following M&TE value applies to the Keithly 2001 when used at the 145' elevation of the Control Complex for a 0-10 V span: MTEFV = +/- 0.005% soan 39 Per Calculation 194-0012 (Reference 76), the error associated with RECALL/SPDS is EERECALLN
+/-0.220% of Full Scale Range (20 Vdc or 4096 counts) for 60 to 80 *F and EEREACLLA = +0.317% of Full Scale Range (20 Vdc or 4096 counts) for accident temperatures of 70 to 104'F.
40 The NRC has accepted instrument error calculations based upon a 2 sigma confidence level via R.G. 1.105 (Reference 39). Per the I&C Design Criteria (Reference 25), published instrument errors are usually expressed at a confidence level of 3 sigma, unless otherwise indicated. That philosophy should be valid for error terms which pertain to equipment operated in a controlled environment. However, for equipment which must survive the environmental effects of an accident (LOCA, HELB), that philosophy cannot be adhered to. The reason for such is that special environmental testing to quantify the temperature, pressure, and radiation effects due to accident conditions are usually done on too small a sample to represent a 3 sigma value. Therefore, environmental error terms shall be considered as 2 sigma values unless otherwise indicated. This calculation does not convert any 3 sigma non-environmental error terms (i.e. reference accuracy, drift, etc.) into 2 sigma terms when it combines the non-environmental with the environmental terms. This approach adds conservatism to the end result. 41 The following method will be used to determine the overall error for component(s) and/or loop(s) that have Positive (+) and/or Negative (-) Biases:
- a. Positive Biases will be added to the SRSS of the Positive random errors, while ignoring Negative Biases.
- b. Negative Biases will be added to the SRSS of the Negative random errors, while ignoring Positive Biases.
For example, although the errors due to sensing line density changes and cable insulation resistance are both due to elevated temperatures created by the accident and could be assumed to be present at the same time, for conservatism, they will not be allowed to compensate for one another or for the random error terms. 42 The effect of a decreased insulation resistance (increased leakage current) on the ES RC pressure signals which are grounded loops (on the negative side of the power supply via the Buffer Amplifiers) can be to deliver either a higher or lower pressure signal to the ES and indication than is actually present. The direction depends upon the relative degradation in the insulation resistance of the two conductors within the cable. Should the negative lead (transmitter output to the Buffer Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
Florida
*PowerCO.........
DESIGN ANALYSIS/CALCULATION Crystal River Unit 3 DESA-C.FRM Page 42 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 Amplifier) experience a much higher degradation (lower IR) than the positive lead from the power supply (i.e. conductor-to-ground resistance on the negative lead is much lower than conductor-to-conductor), more current will bypass the Buffer Amplifier circuit (assuming the shield-to-drain-to-ground is intact) than can be made up by conductor-to-conductor leakage. The net effect is a lower pressure value is sent to the ES and indication than is actually present. In this scenario, HPI/LPI will actuate at a higher pressure than required, which is a failure in the conservative direction for the ES which actuates on a decreasing pressure signal. This scenario will be called Case 1. Should the leads exhibit a much lower conductor-to-conductor IR than the negative lead's conductor-to-ground value (i.e. no ground available on the negative lead), the effect will be more leakage conductor-to-conductor than can be drained to ground, resulting in a higher pressure signal sent to the ES and indication than is actually present. This failure is in the non-conservative direction, since HPI/LPI will actuate at a lower pressure than required. This scenario will be called Case 2. Conductor-to-ground leakage on the positive lead has no effect on the transmitter signal to ES since the power supply simply makes up for the leakage. This scenario will be called Case 3. Not knowing how the conductor insulation will degrade during an accident, all three conditions will be analyzed so as to bound the error. Rev. 6f95 R5ET: Life of Plant RESP: Nuclear Engineering
SFlorida Power CO.PORATION DESIGN ANALYSIS/CALCULATION Crystal River Unit 3 DESA-C.FRM Page 43 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 43 Surveillance Procedure SP-132 (Reference 37) has the following "As-Left" and "As-Found" tolerances: Pressure +/- 0.04 mAdc +/- 0.115 mAdc Transmitters Trip Bistable Input +/-0.027 Vdc +/- 0.102 Vdc (1500# & 500#) Trip Bistable Actuation +/- 0.010 Vdc +/- 0.027 Vdc (1500# & 500#) Signal Monitors Input +/- 0.063 Vdc +/- 0.138 Vdc Bypass Bistable Actuation (1700# +/- 0.010 Vdc +/- 0.027 Vdc
& 900# Trip)
Bypass Bistable Actuation (1700# +/- 0.010 Vdc +/- 0.027 Vdc
& 900# Automatic Reset)
Plant Computer +/- 20 psig +/- 25 psig Buffer Amplifier +/- 75 psig +/- 75 psig Meter RECALL +/- 20 psig +/- 25 psig Pressure Recorder +/- 25 psig +/- 50 psig T'Sat Meter +/- 20 psig +/- 50 psig RIP Indicator +/- 50 psig +/- 50 psig Signal Monitor +/- 0.025 Vdc +/- 0.027 Vdc (On) Signal Monitor +/- 0.025 Vdc +/- 0.027 Vdc (Off) 44 This calculation addresses the time response of the HPI and LPI actuation instrument strings. According to Calculation 1-83-0001 (Reference 45), the required time response of the components is dependent upon the relative values of the time constant, r, of the component and the time for the process to change, T (also the signal change). For step changes to the process (Tg T), five time constants (to 99% of output) are required. For ramp inputs (T >> T), only one time constant is required. The following response times (RT) are given for the Bailey Buffer Amplifier and Bistable from DI15 and D116: RTBA = 1 sec RTBT = 100 ms Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
0Floria Power CORP..A...N DESIGN ANALYSIS/CALCULATION Crystal River Unit 3 DESA-C.FRM Page 44 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 According to Section 6.2 of Calculation 1-83-0001 (Reference 45), the response times given for the Bailey modules are for the time required for the output of the module to change by 99% in response to a step change of the input. Since the values are based upon a step change of the input signal, they represent the worst case. The response time given for the Rosemount transmitter in D17 is for one time constant. According to Calculation 1-83-0001 (Reference 45), the process times for the various accidents must be evaluated to justify using one time constant. For accidents which produce slow process changes (T
>>>> ), one time constant is acceptable. For accidents which result in more rapid process changes where T and t are nearly equal, the effect of a longer time delay must be analyzed.
Referring to D129, the accidents under consideration regarding the issue of time response are the SBLOCA and the LBLOCA. The time to ES actuation for these accidents are 200 seconds and 18.5 seconds, both of which are much larger than the 0.2 second time constant for the transmitter. Based upon this comparison, the use of one time constant for the Rosemount transmitters is acceptable (RTpT = 0.2 sec). 45 The current ITS required ES Low Pressure Bypass Reset Value is < 1700 psig per ITS bases B 3.3.5. This is reflected in ITS Table 3.3.5-1 "Applicable Modes and Other Specified Conditions" for the Reactor Coolant System Pressure - Low parameter. The HPI MAR (References 85 and 86) will increase the ITS required Bypass Reset Value from _ 1700 psig to < 1800 paig. The existing ES Low Pressure Bypass Reset setpoint is 1695 psig which provides a 5 psi offset from the existing required reset value. This ensures the ES low RCS pressure trip is not bypassed during the specified conditions of ITS Table 3.3.5-
- 1. The new ES Low Pressure Bypass Reset setpoint will also be offset from the nominal value by 5 psig therefore, the post MAR Bypass Reset setpoint will be 1795 psig. The ES Low RC Pressure Bypass bistables have an adjustable deadband which is set at 25 psig. This results in a post MAR setpoint of 1770 psig for the ES Low RC Pressure Bypass Permit function. The bistables affected by this change are RC-003-BT4, RC-003-BT5 and RC-003-BT6.
See FTI 86-5001942-02 and FPC F98-0008 for the above setpoint values (References 84 and 78) The 1800# (revised from 1700#) and 900# setpoints for the HPI and LPI Bypass bistables are nominal values and therefore, do not need to be error corrected. According to Table 3.3.5-1 of the ITS (Reference 67), the setpoints for these bistables are considered as "Applicable Modes or Other Specified Conditions" and not as "Allowable Values". Exceeding these values (though not advised) is not considered a violation of the Technical Specifications. Administrative controls are in place to provide assurance against exceeding these values (Reference 30). The LPI and HPI setpoints for the Bypass Bistables are as follows: 1800# HPI Bypass Permit = 1770 psig (References 85 &86) 1800# HPI Bypass Reset = 1795 psig (References 85 &86) 900# LPI Bypass Permit = 850 psig (Reference 37) 900# LPI Bypass Reset = 875 psig (Reference 37) 46 Section 3.5.1 of the ITS (Reference 63) requires that there be two core flood tanks (CFT's) operable in Mode 3 when reactor coolant (RCS) pressure > 750 psig. One of the signal monitors included in this calculation provides an alarm whenever RCS pressure is > 750 psig and the CF isolation valves are not open (i.e. CFT's not operable). This alarm is considered an operator aid during normal heatup and cooldown; therefore, the 750 psig value is treated as a nominal value. The inplant Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
Florida Power
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DESIGN ANALYSIS/CALCULATION Crystal River Unit 3 DESA-C.FRM Page 45 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 setpoint will be established by backing off the nominal value given in ITS by the "As-Found" value for the loop to help ensure the CFT's are operable above 750 psig RCS pressure. No ITS requirement exists for the alarm which alerts the operator whenever RCS pressure is below 638.3 psig and the CF isolation valves are not closed (so as to prevent an inadvertent actuation). This alarm is also considered as an operator aid; therefore, the 638.3 psig value is treated as a nominal value. According to Section B 3.5.1 of the ITS (Reference 63), below 750 psig the blowdown rate is such that the LOW pressure safety injection pumps can provide adequate injection to ensure peak clad temperature remains below the required limit. The low pressure setpoint is established in the same manner as the high pressure by backing off the maximum nitrogen blanket pressure given in Section 3.5.1 of the ITS (Reference 63) of 653 psia (638.3 psig) by the "As-Found" value for the loop. The HPI Not Bypassed and Not Reset Alarms are actuated by signal monitor RC-3A-PS6. The RC-3A-PS6 setpoint is presently 1640 psig per SP-132 (Reference 37). The HPI MAR (Reference 86) will maintain the same pressure differential as presently maintained between the Bypass/Reset functions and alarm setpoints. The HPI MAR (Reference 86) will set the ES HPI Not Bypassed/Not Reset setpoint to 1740 psig. The ES Low Low RC Pressure Alarm setpoint is actuated by signal monitor RC-3A-PY4. The RC-3A-PY4 setpoint is presently 1550 psig per SP-132 (Reference 37). The HPI MAR (Reference 86) will maintain the same pressure differential as presently maintained between the trip and alarm setpoint. HPI MAR (Reference 86) increase the ES Low RC Pressure Alarm setpoint by 125 psi to 1675 psig. The remainder of the signal monitor alarm setpoints will remain as specified in SP-1 32 (Reference
- 37) or Sections 8 and 9 of this calculation. Therefore, the signal monitor alarm setpoints are as follows:
RC-3A-PS6 "HPI Not Bypassed" 1740 psig (Reference 86) RC-3A-PS6 "HPI Not Reset" 1740 psig (Reference 86) RC-3A-PY4 "RC Low Pressure" 1675 psig (Reference 86) RC-3A-PS5 "LPI Not Bypassed" 750 psig (Reference 37) RC-3A-PS5 "LPI Not Reset" 750 psig (Reference 37) RC-3A-PS3 "CFT Isolation Valve Not Closed" 690 psig (Section 8) RC-3A-PS3 "CFT Isolation Valve Not Open" 702.5 psig (Section 8) RC-3A-PS4 "LTOP Event in Progress" 392.6 psig (Section 9) RC-3A-PS7 "DH Isolation Valve to PZR Spray Open" 200 psig (Reference 37) Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
*owe DESIGN ANALYSIS/CALCULATION
........... Crystal River Unit 3 DESA-C.FRM Page 46 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 IV. ASSUMPTIONS (A):
- 1. The modules and indicators located in Control Complex EQ Zones 13 and 58 will be calibrated at a temperature between 700 and 80 0F, based on the Normal Temperature range stated in Design Inputs(DI) 8, and on the M&TE accuracy selected in D139.
The modules and indicators located in EQ Zones 13 and 58 will be operated over a normal temperature range of 600 to 80 0 F. This range is based on the maximum Normal Temperature stated in DI 8 and an assumed minimum temperature. The maximum temperature is maintained at the DI 8 stated value of 80°F since the Control Complex Heat Load Evaluation calculation M-97-0020 (reference 77) assumes this to be the maximum initial temperature for evaluation. The minimum temperature is assumed to be 600 F, since this bounds the minimum Normal Temperature stated in DI 8 and also allows for continued analyzed plant operations during HVAC equipment problems when the temperature may decrease below the minimum value stated in D18. The modules and indicators located in EQ Zones 13 and 58 will be operated over an accident temperature range of 600 to 104 0F. This range is based on the minimum assumed temperature discussed in the paragraph above. The maximum temperature is assumed to be 104 0 F, since this bounds the maximum Accident Temperature stated in D18 and also allows for continued analyzed plant operations up to the vendor stated limit for the lowest maximum temperature rated component in the loop. The Foxboro components are limited to 1040 F per Product Specification PSS 9-7A1A page 4 located in Instruction Manual 586 (reference 58), which states a 1040 F ambient limit for racks fully loaded with one power supply and no fans, the configuration which exists in the RCITS Cabinets. Considering the above paragraphs, the module and indicator temperature effects will be calculated for the maximum change in temperature of the component from the temperature at which it was calibrated to the temperature at which it will be operated. For normal conditions, the component will be assumed to be calibrated at 80°F and operated at 60°F for a 20OF change (80-
- 60) and for accident conditions, the component will be assumed to be calibrated at 70°F and operated at 104 0 F for a 34 0F change (104-70).
- 2. The lower limit of EQ Zone 66 is 70°F and the upper limit is 109 0 F, the transmitters are conservatively assumed to be calibrated at 700F. Therefore a maximum 39°F change occurs between calibration temperature and Normal operating conditions.
- 3. Split loop calibration is broken down into an "IN"portion of the loop and "OUT" portion of the loop.
The IN part of the calibration refers to the calibration of the portion of the loop that is in containment or a harsh environment and the OUT part of the calibration refers to the calibration of the remaining portion of the loop. The OUT portion of the loop will be calibrated by inputting a signal at 4, 8, 12, 16 and 20 mA. The tolerance for these values is assumed to be +/-0.004 mA which is an order of magnitude smaller than the As-Left IN tolerance of +/-0.04 mA. This small tolerance of +/-0.025% of span is considered to be negligible and will not be included in this calculation.
- 4. It is assumed that each Buffer Amplifier is calibrated with its 630Q resistor (across its input).
- 5. The position taken by the I&C Design Criteria (Reference 25) typically considers input and output test equipment used during the calibration of a device as independent, thus combining the corresponding error terms by the SRSS method. This calculation assumes the input and output test equipment are independent.
Rev. 6/95 RET: Lifeof Plant RESP: Nuclear Engineering
Florida Power DESIGN ANALYSISICALCULATION CO......... Crystal River Unit 3 DESA-C.FRM Page 47 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10
- 6. The test equipment referenced under D138 will be used in the future to calibrate the RC-3A-PT3, RC-3A-PT4, and RC-3B-PT3 loops.
- a. Obtaining "As-Found" and "As-Left" values on each transmitter is accomplished using the Druck DPI-510. Although the Druck is essentially one piece of MTE measuring both the input and the output, itis assumed these measurements would be independent of one another. Therefore, per Assumption 5, the accuracies are combined by SRSS. The M&TE error for the pressure transmitter is:
MTELOOPPT:IN +/- [(MTEDp) 2 + (MTED1/' 2
+/-+ [(0.116) + (0.165)2
+/- 0.202% span
- b. "As-Found" and "As-Left" values for the Bistable (TRIP and BYPASS) and Signal Monitor inputs are found by using a transmation and a Keithley 197A (4-20 ma range) to supply and measure a simulated transmitter signal (4-20 ma corresponding to the "As-Found" and "As-Left" current output of the transmitter) to the input of the Buffer Amplifier's resistor network and by using a Keithley 2001 (0-10 V range) to measure the input voltage to the TRIP Bistable at its input jack and to the signal monitor at its input jack 2 211 2 MTETsAT = MTEBA = MTEsMA = MTEpL:OUTI =+/- [(MTEKI) + (MTEFV)
]
[(0.190)2 + (0.005)21l/2 y=
- c. "As-Found" and "As-Left" actuation values (and reset values as applicable) for the Bistables (TRIP and BYPASS) and Signal Monitors are found by using a transmation to supply a current signal to the input of the Buffer Amplifier's resistor network and by using a Keithley 2001(0-10 V range) to measure the voltage (at the TRIP Bistable input jack) at which each of the Bistables and Signal Monitors actuates (or resets, as applicable). Therefore, the M&TE error for the Bistables and Signal Monitors is:
MTEBT = MTEPLiOUT2 = +/-MTEFv
= 0.005% spa
- d. "As-Found" and "As-Left" values for each indicating device (Pressure Indicator, Buffer Amplifier Meter, Recorder, Plant Computer Point, RECALL Point, Reactor Patch Panel Point, and T'SAT Meter) are found by monitoring these devices while using a transmation and a Keithley 197A (4-20 mA range) to supply and measure a simulated transmitter signal (4-20 mA corresponding to the "As-Found" and "As-Left" current output of the transmitter) to the input of the Buffer Amplifier's resistor network.
MTELooP:ouT = +MTEKI
= +0.190
= + 0.190% span
- 7. For components where a drift term is not specified, it is assumed that any drift present is bounded by the Reference Accuracy of the device.
- 8. The Control Complex is considered a Controlled Environment; therefore, no significant changes in humidity will be considered.
Rev. 6/95 RET: Life of Plant RESP: Nudear Engineering
Rrd
*M"4= DESIGN ANALYSISICALCULATION Crystal River Unit 3 DESA-C.FRM Page 48 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10
- 9. Per Section 6.3.1 of I&C Design Criteria (Reference 25);
"Accuracy as identified in a vendor specification is usually assumed to be Reference Accuracy.
Reference Accuracy is a number or quantity which defines the limit that uncertainties will not exceed under reference operating conditions. Reference operating conditions are the range of operating conditions under which operating influences are negligible. Reference Accuracy includes the combined effects of conformity (linearity), hysteresis, and repeatability. It should be noted that linearity is a particular definition of conformity. Reference Accuracy is determined from the deviation values of a number of tests; therefore, it represents a statistical compounding of the random elements of conformity, hysteresis, and repeatability. Reference Accuracy is measured as inaccuracy but expressed as accuracy." In addition, the current philosophy is to endorse ANSI/ISA-S51.1-1979 (Reference 7) which includes dead band in the reference accuracy when applicable. Where conformity (linearity), hysteresis, dead band, and repeatability values are less than the specified accuracy, the above statement is to be considered true. For conservatism, where conformity (linearity), hysteresis, dead band, and/or repeatability values are equal to or greater than the specified accuracy, then the value(s) will be combined via the SRSS method with the specified accuracy term to determine the Reference Accuracy value.
- 10. Assume conductor-to-conductor IR for cable, splices, seals, and penetration feedthroughs is twice that of conductor-to-ground IR ifone of the values are not given in test data. This assumption is made since conductor-to-conductor involves twice the insulation thickness of the cable, splice, etc.
- 11. To allow consistent usage of Bailey 880 module accuracy and time response data, it is assumed that the analysis of Calculations 1-83-0001 (Reference 45) and 1-90-1020 (Reference 74) includes the Buffer Amplifier and Bistable module types used in the RC pressure loops for ES.
V.
REFERENCES:
Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
*flRorida owe DESIGN ANALYSISICALCULATION
.........o" Crystal River Unit 3 DESA-C.FRM Page 49 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10
- 1. Drawing 205-047, sheet RC-1 1, Instrument Loop Diagram Reactor Coolant to Steam Generator 3A, Revision 7
- 2. Drawing 205-047, sheet RC-1 1A, Instrument Loop Diagram Reactor Coolant to Steam Generator 3B, Revision 4
- 3. Drawing D8034033, sheet 4, Reactor Coolant Control Loop RC-3, RC3A, Revision 13
- 4. Drawing 210-481, Engineered Safeguard - Channel Test Cabinet 1, Revision 9
- 5. Drawing 210-483, Engineered Safeguard - Channel Test Cabinet 2, Revision 8
- 6. Drawing 210-485, Engineered Safeguard - Channel Test Cabinet 3, Revision 12
- 7. ANSI/ISA-S51.1-1979, Process Instrumentation Terminology, December 28, 1979
- 8. Rosemount Report 78212, Internal Thermal Response of Transmitter Housings to Steam Impingement, Revision A, SEEK 3466, Reel 0116
- 9. Calculation 1-89-0004, Instrument Loop and Insulation Resistance (IR) Accuracy Calculations, Revision 8
- 10. Design Basis Document (DBD) for Post Accident Monitoring Instrumentation (Section 5/11),
Revision 7 (Temporary Changes 735,929,968,986,990,997, & 1050)
- 11. Calculation 1-97-0015, RCS Low Range Pressure Loop Accuracy, RC-147-PT &RC-148-PT, Revision 1
- 12. Drawing 308-605, Instruments Arrangement at North X Station, Revision 15
- 13. Drawing 308-606, Instruments Arrangement at North Y Station, Revision 15
- 14. Drawing 308-603, sheet 2, Instruments Arrangement at South X and Y Instrument Rack Station, Rev. 1
- 15. Drawing 308-601, Instruments Connections on Steam Generator 3A & RC 36" Line, Revision 11
- 16. Drawing 308-602, Instruments Connections on Steam Generator 3B & RC 36" Line, Revision 12
- 17. Drawing 308-604, Instruments Arrangement at South X Station Steam Generator 3B, Revision 14
- 18. Environmental and Seismic Qualification Program Manual (E/SQPM), Revision 11 (with Intermin Change 99-01)
- 19. Calculation 1-90-0014, EQ Zone 66 Normal 10 Year Radiation Levels, Revision 2
- 20. Instrument Data Sheets:
20.a RC-3A-PT3, Revision 5 20.b RC-3A-PT4, Revision 5 Rev. 6/95 RET: Lifeof Plant RESP: Nuclear Engineering
Florida Power
...........
DESIGN ANALYSISICALCULATION Crystal River Unit 3 DESA-C.FRM Page 50 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 20.c RC-3B-PT3, Revision 4 20.d RC-3A-PY3, Revision 1 20.e RC-3A-PY4-1, Revision 2 20.f RC-3B-PY3, Revision 2 20.g RC-3-BT1, Revision 4 20.h RC-3-BT7, Revision 3 20.i RC-3-BT2, Revision 3 20.j RC-3-BT8, Revision 3 20.k RC-3-BT3, Revision 3 20.1 RC-3-BT9, Revision 3 20.m RC-3A-JX3, Revision 1 20.n RC-3A-JX4, Revision 1 20.0 RC-3B-JX3, Revision 1 20.p SP-1A-EB1 (RC-3A-EB1, RC-3B-EB2), Revision 1 20.q BS-1-IB2 (RC-3A-EB2), Revision 3 20.r SP-6A-EB4 (RC-3A-EB3), Revision 2 20.s SF-1-IB1 (RC-3B-EB3), Revision 2 20.t RC-3A-PS3, Revision 4 20.u RC-3A-PS4, Revision 4 20.v RC-3A-PS5, Revision 4 20.w RC-3A-PS6, Revision 4 20.x RC-3A-PS7, Revision 2 20.y RC-3A-PY4, Revision 2 20.z RC-3A-PI3, Revision 2 20.aa RC-3B-P12, Revision 2 20.bb RC-163A-PY1, Revision 4 and MAR 97-02-12-02 FCN #2 Rev. 6/95 RET: Life of Plant RESP; Nuclear Engineering
Power FlRorida DESIGN ANALYSIS/CALCULATION CORPO RATIO N C rys ta l R iv e r U n it 3 DESA-C.FRM Page 51 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 20.cc RC-163B-PY1, Revision 3 and MAR 97-02-12-02 FCN #2 20.dd RC-154-PR/TR, Revision 8 20.ee RC-3-BT4, Revision 3 20.ff RC-3-BT5, Revision 3 20.gg RC-3-BT6, Revision 3 20.hh RC-3-BT10, Revision 3 20.ii RC-3-BT11, Revision 3 20.JJ RC-3-BT12, Revision 3
- 21. Instruction Manual 1260, Revision 12
- 22. Enhanced Design Basis Document (EDBD) for the Reactor Coolant System (Section 6/1), Rev 8 (Temporary Changes 665, 942, 1018, and 1035)
- 23. Letter LFM90-0006, dated 1/29/90 - Licensing Interpretation Seismic and LOCA
- 24. Letter SNES94-0276, dated 9112/94 - Response to NEA94-0694 on RPS Instruments
- 25. CR-3 I&C Design Criteria For Instrument Loop Uncertainty Calculations, Revision 4
- 26. Calculation 1-88-0015, Selection of Circuit Data for IRAccuracy Calculations, Revision 6
- 27. Instruction Manual 49, Volume 1C (Book 1887, Revision 0), Foxboro Model 610A Power Supply, Revision 15
- 28. Calculation 1-88-0004, Insulation Resistance of Continental Cable, Revision 2 (voided)
- 29. Vendor Qualification Package (VQP) INST-R369-03, Rosemount Model 1154 Transmitters, Revision 9
- 30. Letter SNES 94-0356, dated 12/07/94 - ESAS Bypass Permit Automatic Reset Bistable
- 31. Walk Down Package 0188, RC-3A-PT3, 1992
- 32. Walk Down Package 0184, RC-3A-PT4, 1992
- 33. Walk Down Package 0185, RC-3B-PT3, 1993
- 34. Vendor Qualification Package (VQP) PEN-R369-01, Rosemount Model 353C Conduit Seals, Revision 5
- 35. Calculation 1-88-0003, Insulation Resistance of Rosemount Conduit Seal, Revision 3 Rev. 6195 RET: Life of Plant RESP: Nuclear Engineenng
0Florida
*Power CORPORATION DESIGN ANALYSISICALCULATION C ry s ta l Riv e r U n it 3 DESA-C.FRM Page 52 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10
- 36. Vendor Qualification Package (VQP) PEN-C515-04, Conax PIN 2325-7867/7868 Electrical Penetration Assembly, Revision 4
- 37. Plant procedure SP-1 32, Engineered Safeguards Channel Calibration, Revision 37
- 38. ISA-RP67.04, Part II,Methodologies for the Determination of Setpoints for Nuclear Safety-Related Instrumentation, September 1994
- 39. Reg. Guide 1.105, Instrument Setpoints for Safety-related Systems, Revision 2
- 40. Final Safety Analysis Report, Revision 25.4
- 41. Technical Specification Basis Backup Document, 51-1173714-01, Volume 2, Book 1, Tab 15
- 42. Vendor Qualification Package (VQP) CABL-C595-08, Continental CC-2193 Instrument Cable, Revision 2
- 43. Instruction Manual 206, Volume 1 of 2, Revision 22, Bailey Product Instruction E92-316, 1970
- 44. Instruction Manual 206, Volume 1 of 2, Revision 22, Bailey Product Instruction E92-341, 1969
- 45. Calculation 1-83-0001, Calculation for Statistical Errors, Crystal River 3 RPS, Revision 4
- 46. Instruction Manual 49, Volume 1B, Revision 19, Bailey Product Instruction E92-79, 1980
- 47. Instruction Manual 49, Volume 1B, Revision 19, Bailey Product Instruction E92-74, 1972
- 48. Instruction Manual 49, Volume 1B, Revision 19, Bailey Product Instruction E12-1-1, 1971
- 49. Instruction Manual 1243, Esterline Angus, Miniservo VI Strip-Chart Recorder, Revision 1
- 50. Instruction Manual 1278, Revision 10, Foxboro Instruction SI 1-01693, May 1979
- 51. MAR 82-05-24-04, 79-01 B Transmitter Replacement
- 52. Walk Down Package 817, MTBD-9A, 1992
- 53. Walk Down Package 254, MTBD-9B, 1990
- 54. Walk Down Package 815, MTBD-9C, 1992
- 55. Vendor Qualification Package (VQP) TERM-R098-04, Raychem NPKC, NPKP, and NPKS Transition Splice Assemblies, Revision 5
- 56. Drawing 205-047, sheet RC-13A, Instrument Loop Diagram RCS Hot Leg Level/Head Level, Revision 9
- 57. ASME Steam Tables, Second Edition
- 58. Instruction Manual 586, Revision 7, Foxboro Product Specifications PSS 2E-1A1 A, 1985
- 59. Calculation 1-84-0002, Instrument error calc. For T'Sat display, Revision 2 Rev. G(95 RET: Life of Plant RESP: Nuclear Enginaering
*.........
owero. DESIGN ANALYSIS/CALCULATION Crystal River Unit 3 DESA-C.FRM Page 53 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 1 10
- 60. Calculation 1-89-0010, RCITS Hot Leg and Reactor Vessel Level Loop Accuracy, Revision 2, ICA, Rev.00
- 61. WR287448 RAN 99115-1061, LOC 7169-0393
- 62. Technical Specification Basis Backup Document, 51-1173557-01, Volume 2, Book 1, Tab 16
- 63. Improved Technical Specifications, Volumes I and 2, Amendment 186.
- 64. Drawing 210-480, Engineered Safeguard - Channel Test Cab ESCC-1 Reactor Coolant Pressure, Revision 13
- 65. Calculation 1-88-0028, Reduction in LPI Start Signal, Revision 0
- 66. Calculation F-97-0018, CR-3 MSLB with MFP Trip failure, Revision 0
- 67. WR324749 RAN 90006-2483
- 68. Calculation 1-95-0005, Measurement and Test Equipment Accuracy Calculation, Revision 2
- 69. Instruction Manual 1981, Keithley 197A Multimeter, Revision 0
- 70. Submergence and High Temperature Steam Testing of Class 1E Electrical Cables, NUREG/CR-5655, SAND90-2629, Sandia National Laboratories
- 71. Drawing 210-482, Engineered Safeguard - Channel Test Cab ESCC-2 Reactor Coolant Pressure, Revision 12
- 72. Drawing 210-484, Engineered Safeguard - Channel Test Cab ESCC-3 Reactor Coolant Pressure, Revision 14 73 Drawing 205-047, sheet RC-12A, Instrument Loop Diagram RCS Hot Leg Level & Head Level, Revision 8 74 Calculation 1-90-1020, B&WOG Cross Compatibility Analysis of Bailey Controls Company, Revision 0
75 Calculation M-97-0072 Containment Analysis for SBLOCA Rev. 2 76 Calculation 1-94-0012 Computer Instrument Accuracy, Rev. 3 77 Calculation M-97-0020 Control Complex Heat Load Evaluation, Rev. 0 78 F-98-0008 IS "SBLOCA ANALYSIS FOR CRAFT2 TO RELAP5 TRANSITION" REV. 0 79 BAW-1 01 03A, Rev. 3 Containment Analysis for SBLOCA. 80 FTI Document 32-1266137-00, CR-3 Containment Analysis for SBLOCA, December 1997 81 FTI Document 32-1266137-01, CR-3 Containment Analysis for SBLOCA, January 1998 Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
0Florida Power CORPORATION DESIGN ANALYSISICALCULATION C ry s ta l R iv e r U n it 3 DESA-C.FRM Page 54 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 82 FTI Document 32-1266137-02, CR-3 Containment Analysis for SBLOCA, February 1998 83 FTI Document 32-1266137-03, CR-3 Containment Analysis for SBLOCA, December 1998 84 FTI Document 86-5001942-02, CR-3 RELAP5/MOD2 SBLOCA Summary - HPI Upgrade, March1999 85 MAR 97-02-12-01, High Pressure Injection Upgrade - Mechanical and Structural Equipment. 86 MAR 97-02-12-02, High Pressure Injection Upgrade - Electrical and I&C Equipment. 87 FTI Document 32-1266348-01, "CR-3 Mk-Bg 20% SGTP R5/M2 SBLOCA Spectrum (HPI Upgrade), 2/18/99. Rey. MS9 RET: Life of Plant RESP: Nuclear Engineering
Florida Power
...........
DESIGN ANALYSIS/CALCULATION Crystal River Unit 3 DESA-C.FRM Page 55 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 VI. DETAILED CALCULATION This calculation will evaluate the instrument loop accuracies associated with the RCS pressure transmitters RC-3A-PT3, RC-3A-PT4, and RC-3B-PT3 during normal and accident conditions.
- 1. COMPONENT ERRORS
- a. Process Error Per D16, the sensing lines associated with RC-3A-PT3, RC-3A-PT4, and RC-3B-PT3 are routed through EQ Zones 66 and 40. Since neither of the zones has an overwhelming portion of the sensing lines routed through it,an average of the zones Normal temperatures will be used for calculating the differential density effect. Per the E/SQPM (Reference 18) the temperature in Zone 40 is between 130°F and 149 0F a majority of the time (average of 1400 F), and Zone 66 is between 900 and 109 0 F a majority of the time (average 100 0F); therefore, 120OF (average of the two averages) will be used as the average Normal sense line temperature. In addition, the normal operating pressure of the RCS is 2155 psig per the EDBD for the Reactor Coolant System (Reference 22).
According to D16, the change in elevation between the tap connections for the transmitters on the RCS piping and the location of the transmitters is 63.13 feet (167.21'- 104.08') for RC-3A-PT3, 63.17 feet (167.21' - 104.04') for RC-3A-PT4, and 64.46 feet (167.21'- 102.75') for RC-3B-PT3. From Table 3 of the ASME Steam Tables (Reference 57), the Specific Volume of water at 120OF and at 2169.7 psia (2155 psig) is 0.01610 ft3/lb. The density is then 62.11 lb/ft3 (1/0.01610 ft3/lb). Therefore, the following corrections are required for the calibration of the transmitters: RC-3A-PT3 (62.11 b'/fti (1 ft2/144 in2) = 0.431 lb/(in 2-ft) (0.431 lb/in -ft)(63.13 ft) = 272 psig TRANSMITTER SCALING = 27.2 osie (0%) to 2527.2 psig (100%) RC-3A-PT4 (0.431 b/in-ft)(63.17 ft) 2 TRANSMITTER SCALING = 27.2 psi. (0%) to 2527.2 psig (100%) RC-3B-PT3 (0.431 lb/in2-ft)(64.46 ft) = TRANSMITTER SCALING = 27.8 psi_ (0%) to 2527.8 psiq (100%n The above mentioned correction factors are to be included in the calibration of the transmitters. As was found in D129.h, the maximum temperature of cable, splices, penetrations, and transmitters following the worst accident temperature profile (MSLB) would not exceed 302 0 F. Transmitter sensing lines, just like these devices, have thermal mass. Since water has a very large specific heat, it is reasonable to conclude that the sensing line temperature will remain below the maximum computed in D129. Therefore, a value of 3020 F will be used to determine the maximum error due to density changes within the sensing lines. The hotter, less dense post-accident condition in the sensing lines will lower the indicated pressure. From Table 1 of the ASME Steam Tables, the saturation pressure of water at 300°F is 67.005 psia. The Specific Volume of water at this point is 0.01745 ft3/lb. Therefore, the density is 57.31 lb/ft3 (1/0.01745 ft3/Ib). Rev. 6/95 RET: Lifeof Plant RESP: Nuclear Engineering
Florida SPower DESIGN ANALYSISICALCULATION River Unit CORPOTiONCrystal 3 DESA-C.FRM Page 56 of 88 DOCUMENT IDENTIFICATION NO. I REVISION 1-89-0014 1 10 The change in pressure for the sensing lines of the pressure transmitters is related to the change in sensing line water density as follows: ASENSE-LINE = [(dT2 - dT1)/(144 in2/1 fe)] x [L/span] x 100% where dTl and dT2 is the density of the sensing lines at 120OF and 300 0 F, respectively and L is the elevation differential in the sensing line. The resulting effect on the transmitters' span is as follows: RC-3A-PT3 ASENSELINE = [(57.31 lb/ft 3-62.11 lb/ft3)/(144 in2/1 ft2)][(63.13 ft)/(2500 lb/in 2)](100%)
= - 0.08% span RC-3A-PT4 ASENSE-LINE = [(57.31 lb/ft 3 - 62.11 lb/ft3)/(144 in2/1 ft2)][(63.17 ft)/(2500 WIin 2)](100%)
= -0.08% span RC-3B-PT3 ASENSE-LINE = [(57.31 lb/ft3 - 62.11 lb/ft3)/(144 in2/1 ft2)][(64.46 ft)/(2500 lb/in2)](100%)
= - 0.09% span Note: This error will be neglected for the LPI/HPI actuation condition. Decreases in sensing line density create a negative error (i.e. measured value is less than actual value). Neglecting this effect in establishing the HPI/LPI setpoint is therefore conservative since the positive error term is what is used to define the setpoint for actuation's which occur on decreasing signals. The larger value will be used for the post-accident condition. Therefore:
ASENSE.LINE =
- b. Device PT Rosemount Pressure Transmitter D17 Span = 2,500 psig URL = 3,000 psig (Upper Range Limit)
Normal Conditions (EpTN) EPTN(ref)= Reference Accuracy = + 0.25% span EpTN(t) = Temperature Effect +/- (0.75% URL + 0.5% span)/100°F
= +/- [0.75%(3000 psig/2500 psig) + 0.5%] (109 0F - 70°F)/1000F D129.h, A2
+/- 0.55% span EPTN(op) = Overpressure Effect = + 0.0% span D17.b EPTN(ps) = Power Supply Effect = 0.005% span per volt
= +/- (0.005 span)(2 volts) D118,D17
= +/- 0.01% span EPTN(plt) = Steam Pressure/Temperature Effect =+/- 0.0% span D17.c EPTN(s) = Seismic Effect = +/- 0.0% span D17.d Rev. 6/95 RET: Life of PlaM RESP: Nuclear Engineering
Florida
*Power DESIGN ANALYSIS/CALCULATION CORPORATION Crystal River Unit 3 DESA-C.FRM Page 57 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 EpTN(,md) = Radiation Effect = 0.0% span D17.e EPTN = + [(EPT(re) + (Ep:(t))2 + gE 2 1/2
= [[(0.25)2 + (0.55) + (0.01)]1
= + 0.60% span HPIILPI Actuation (EPTIACT)
EPT/ACT(re0 = Reference Accuracy = + 0.25% span EpT/ACT(t) = Temperature Effect = - (0.75% URL + 0.5% span)/100°F D129.h, A2
= [0.75%(3000 psig/2500 psig) + 0.5%] (133°F - 70°F)/100°F
= +/- 0.88% span EpT/ACT(op) = Overpressure Effect = +/- 0.0% span D17.b EpT/AcT(ps) = Power Supply Effect = +/- 0.005% span/volt
= + 0.005% span/volt
= + (0.005% span/volt)(2 volts) D118,D17
= + 0.01% span EPT/ACT(p/t) = Steam Pressure/Temperature Effect = 0.0% span D129.h EpTACT(S) = Seismic Effect = +/- 0.0% span D17.d EPT/ACT(rad) = Radiation Effect = +/- 0.0% span D129.h 2 2 2 1 2
= +/- [(EPT/AST(ref)) + (EPT/ACT(psý + (EPTIACT(t)) ]
EpT/AcT
= +/- [(0.25) + (0.01) + (0.88) ]112
=+/-+0.91% span Post-Accident Conditions - (EpT,1.97)
EPTI.97(ref = Reference Accuracy = +/- 0.25% span EpT/1.97(t) = Temperature Effect = + 0.0% span D129.h EpT/1.97(op) = Overpressure Effect = +/- 0.0% span D17.b EpT/1.97(ps) = Power Supply Effect = +/- 0.005% span/volt
= + (0.005% span/volt)(2 volts) D118,D117
= +/- 0.01% span EpT1.g7(p/t) = Steam Pressure/Temperature Effect = +/- (2.5% URL + 0.5% span) D129.h, D17
= +/- [(2.5%)(3000 psig/2500 psig) + 0.5%]
+/- 3.5% span EpT/1.97(s) = Seismic Effect = + 0.0% span DI7.d EpT/,1.97(rad) = Radiation Effect= +/- (1.5% URL + 1.0% span) D129.h, DI7
= +/- [(1.5%)(3000 psig/2500 psig) + 1.0%]
+/- 2.8% span Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
SFlorida Power co ......... DESIGN ANALYSISICALCULATIONCrystal River Unit 3 DESA-C FRM Page 58 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 2 2 2 2 2 EpT,197 ++[(EPTII97(req) ) + (EPTI1.97(rad)) (EpT,.97(ps)) + (EPTI.9,7 "" ]" (0.01)2 + (3.5)2 + (2.8)]
= +[(0.25) +
= + 4.49% span C. Insulation Resistance Errors Before an IR error value can be determined for the transmitter circuit, the circuit must be analyzed to determine how much leakage current exists.
NOTE: MAR 97-02-12-02 modifies the RC-163A-PY1 and RC-163B-PY1 RCS pressure loops (205-047, Sht. 11, 11 A, 12, 12A) to ensure a loss of power to the modules in the RCITS does not cause an ES channel trip for low RCS pressure. The present current-to-voltage (IN) modules in the RCITS will be replaced with a new current-to-voltage (IN) module which consist of a IN (Foxboro N-2AX-VZ) and a VN (Foxboro N-2AI-T2V) combination unit. The input resistance for this device is 59. (Reference 86) in lieu of the 50n used for the previous device. Although one of the transmitter circuits does not include the 5K resistor (Reference 86) for the RCITS interface, the circuit analysis will be done for the loops which include this resistor. There is negligible difference in the loops despite this additional resistor. Using a variation (grounded loop versus ungrounded loop) of the IR model given ISA-RP67.04 (Reference 38), the circuit to be analyzed is depicted in Figure 1 of Attachment 5, where: VS = Power supply voltage I1 = Power supply current 12,13 = Loop Currents IE 1,2,3 = Leakage Currents IS = Transmitter current REQ1 = IR for conductor-to-conductor REQ2 = IR for conductor-to-ground (negative side of transmitter) REQ3 = IR for conductor-to-ground (positive side of transmitter) The IR values for the parallel insulation resistance from each of the components (i.e. cable, splice, seal,
& penetration) are combined as done in ISA-RP67.04 (Reference 38) using the following:
I/REQ1 = 1I/RsEALc- + 1/Rs. + 1/Rc. + 1/Rs,_, + I/RpENc-I/REQ2 = 1/REQ3 = I/RsEALc-g + l/Rsc-g + l/Rcg + l/Rscg + l/RpENcg Using the HPI/LPI actuation values from D132, 33, 34, and 35, the following equivalent resistances are calculated: RC-3A-PT3 Loop I/REQI(AcT) = (1/5.6x10 70) + (1/6.48x10 9Q) + (1/1.30x10 9n) + (1/6.48x10C) 9 + (1/2.1x10 9n) REQI(ACT) = 5LIx0D 1/REQ2(ACT) = (1/2.8x10k2) + (1/3.24x10 9n) + (1/6.52x10 8n) + (1/3.24x10 9f) + (1/1.05x10 9') REQ2(ACT) = 2.58x1&0 = REQ 3 (ACT) RC-3A-PT4 Loop 1I/REQ1(AcT) = (1/5.6x10 70) + (1/6.48x10 9n) + (1/2.60x10 90) + (1/6.48xl0 9C) + (1/2.1x10 9fl) REQI(ACT) -5.xA107 Rev. 6/95 RET: Life of Plani RESP: Nuclear Engineering
Florida Power
........... DESIGN ANALYSISICALCULATION Crystal River Unit 3 DESA-C.FRM Page 59 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 1/REQ2(ACT) = (1/2.8xlO.) + (1/3.24x10 9C) + (1/1.30x109L) + (1/3.24x10 9Q) + (1/1.05x10 9Q)
REQ2(ACT) = 2.63 x 107Q = REQ3(ACt) RC-3B-PT3 Loop 1/REQI(AcT) = (1/5.6x'107 Q) + (1/6.48x109Q) + (1/1.13x109Q) + (1/6.48x109Q) + (1/2.1x109Q) REQ1(AcT) = 5.12 X D107 1/REQ2(ACT) = (1/2.8x107n) + (1/3.24x10 9Q) + (1/5.65x10 80) + (1/3.24x10 90) + (1/1.05x10 9n) REQ2(ACT) = 2.56 x 107o = REQ3(ACT) Using the post-accident (1.97) values from D133, 34, 35, and 36, the following equivalent resistances are calculated: RC-3A-PT3 Loop 1/REQ1(l.97) = (1/5x10 5Q) + (1/3.6x10 7 Q) + (1/2.56x1072) + (1/3.6x107Q) + (1/4.47x10 6 f2) REQ1( 1.97 ) = 4,31 x 105-1/REQ2(e97) = (1/2.5x10 5 Q) + (1/1.8x107n) + (1/1.28x10 7 Q) + (1I/1.8x107n) + (1/2.24x10M2)6 REQ2(1.97) = 2.a!x10Q52 = REQ3(l. 97) RC-3A-PT4 Loop 7 1/REQ1(l. 9 7 ) = (1/5x10sn) + (1/3.6x10 n) + (1/5.1x107j2) + (1/3.6x107K) + (1/4.47x106 n) REQ1(1. 97) - 4.35ixA10 1/REQ2(1 ,97) = (1/2.5x105f) + (1/1.8x10 7Q) + (1/2.55x1070) + (1/1.8x107n) + (1/2.24x10 6fl) REQ2(1 .97) = 2.18 x 105Q = REQ3(1.97) RC-3B-PT3 Loop 1/REQ1(1. 97) = (1/5x10 n) + (1/3.6x10 7Q) + (1/2.22x107Q) + (1/3.6x10 7Q) + (1/4.47x10 6Q) REQ1(1.97) = 4.30 x 105! 1/REQ2(1. 97) = (1/2.5x105CQ) + (1/1.8x10 70) + (1/1.1 lx107l) + (1/1.8x107Q) + (1/2.24x1Of)6 REQ2(l.g7) = 2.5 x.10- S = REQ3(l. 9 7) Since the transmitter seal IR value is so much smaller than the other components, to simplify the calculation, the worst case equivalent resistances (those for RC-3B-PT3) will be used to determine insulation resistance error. The transmitter is not a true current source since it must rely upon an external power supply. It acts as a variable resistor which maintains a constant current (IS) for a constant pressure input. From References 86 the input impedance for the new IN module is 59. Referring to DI19, the input impedance for the buffer amplifier is 100k1. The cases defined in D142 will now be analyzed. CASE 1 - Negative Conductor-to-Ground Leakage Predominates The first case to be analyzed assumes REQ2 << REQ1 and REQ2 << REQ3. All of the leakage current passes from the negative conductor (i.e. transmitter to buffer amplifier) to ground. This case assumes Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
SFRorda Power
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DESIGN ANALYSIS/CALCULATION C ry s ta l R iv e r U n it 3 DESA-C.FRM Page 60 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 the ground for the circuit is intact. The net effect is to produce a signal to the buffer amplifier that is smaller than that sent by the transmitter; therefore, the error will be negative. These assumptions essentially remove REQI and REQ3 and place REQ2 in parallel with the 630M input resistor across the buffer amplifier input and with the buffer amplifier's input impedance (100k<). Combining the 630n with the 1OOkQ results in the following buffer amplifier equivalent resistance (RBA): RBA = (630Q)(100k1<) 6300 + 100kn
= 626K2 This case simplifies to that shown in Figure 2 of Attachment 5. The leakage current (IE) for this scenario is simply the current through the current divider between the negative conductor-to-ground and the buffer amplifier's resistance. Therefore:
IE 2 = IS(6269)/(REQ2 + 6260) Per ISA-RP67.04 (Reference 38) the percentage error (IE2%) due to degraded insulation resistance is: lE 2% = [lE2/(ISMAx-- ISMIN)l(100%) Substituting the above expression for IE2 yields: IE 2% = [lS(626Q2)/(REQ2 + 626n)1(100%) ISMAx - ISMIN The following insulation resistance error (IE%) values are calculated for the HPI/LPI actuation and post-accident conditions using the worst case (lowest) equivalent resistance values for REQ2 calculated above. The error is negative for the reason given above. HPI/LPI IE2%(Ac) = - [(0.020 A)(626(2)/(2.56 x 10z'. + 626()1(100%) 0.020 A - 0.004 A
= - 0.003% for a 0.020 A transmitter current IE2%(ACT) = - [(0.004 A)(626()/(2.56 x 1o0Q + 626()1(100%)
0.020 A - 0.004 A
= - 0.0006% for a 0.004 A transmitter current The above error values are considered negligible when compared to the other error terms in the instrument loop. This calculation thus neglects insulation resistance error for the HPI/LPI actuation condition for Case 1. Therefore:
IE2%(ACT) = 0.0% span Post-Accident (1.97) IE2%( 1.97) = - [(0.020 A)(6260)/(2.15 x o0s + 626()1(100%) 0.020 A- 0.004 A Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
0Florida Power CORPORATION DESIGN ANALYSIS/CALCULATION Crystal River Unit 3 DESA-C.FRM Page 61 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10
= - 0.36% for a 0.020 A transmitter current IE2%(1.97) = - [(0.004 A)(62602)/(2.15 x 10s) + 6260)1(100%)
0.020 A - 0.004 A
- 0.073% for a 0.004 A transmitter current The error due to insulation resistance is largest at the highest transmitter current, therefore:
lE2%(1.97) = -0 spa CASE 2 - Conductor-to-Conductor Leakage Predominates The second case to be analyzed assumes REQ1 << REQ2 and REQ1 << REQ3. All of the leakage current passes from the positive conductor to the negative conductor. This case assumes the ground for the circuit is not intact. These assumptions essentially remove REQ2 and REQ3 from the circuit. The net effect is to produce a signal to the buffer amplifier and to RCITS that is larger than that sent by the transmitter; therefore, the error will be positive. The circuit simplifies to that shown in Figure 3 of Attachment 5. Using Kirchoffs Law, summing the voltage drops around Loop ABCDA results in the following equation: VS = 12(5n) + IEj(REQ1) + 12(626n) + 11(13000)
= 12(631n) + IE,(REQI) + 11(13000) EQN. 1 Summing voltage drops around Loop ADA results in the following equation:
VS = 13(1600Q) + 11(13009) EQN. 2 From Instruction Manual 49 (Reference 27), the output voltage of each of the transmitter power supplies is 84 Vdc @ 10 mA and 76 Vdc @ 50 mA. From this the following relationship between the power supply output voltage and output current can be derived: VS = 86 V - (2000)ILI EQN. 3 Summing the currents at Node B yields the following: 12 = IS + IE1 EQN. 4 Summing the currents at Node A yields the following: 11= 12+ 13 EQN. 5 Setting EQN. 1 equal to EQN. 2 yields: 12(6310) + IE,(REQ1) + 11(13000) = 13(1600n) + 11(13000) Simplifying and solving for 13 yields: 13 =19(631n) + IE_(REQ1) EQN. 6 Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
- w
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DESIGN ANALYSIS/CALCULATION Crystal River Unit 3 DESA-C.FRM Page 62 of 88 DOCUMENT IDENTIFICATION ND. REVISION 1-89-0014 10 16000 Setting EQN. 2 equal to EQN. 3 yields: 13(16000) + I(1300Q) = 86 V- (200n)lL1 Simplifying yields: 86 V = 13(160092) + 11(15000) EQN. 7 Substituting EQN. 5 into EQN. 7 yields: 86 V = 13(1600Q2) + 12(15000) + 13(150092) Simplifying yields: 86 V = 13(3100 2) + 12(15000) EQN. 8 Substituting EQN. 6 into EQN. 8 yields: 86 V = (3100Q)[12(63110) + IEI(REQ1)1 + 12(1500Q) 16000 Simplifying yields: 86 V = 2722.5692(12) + 1.9375(IE 1)(REQ1) EQN. 9 Substituting EQN. 4 into EQN. 9 yields: 86 V = 2722.5692(IS + IE1) + 1.9375(IE 1)(REQ1) Solving for 1E 1 (the leakage current) yields: IE1 86 V - (2722.560)1S EQN. 10 2722.560 + 1.9375(REQ3) Per ISA-RP67.04 (Reference 38) the percentage error (IE1%) due to degraded insulation resistance is: IE1% = [lEl/(lSMAx - ISMIN)](100%) Substituting the above expression for 1E, yields: IE,% = [86V-(2722.56&)lS1(100%) [2722.56C2 + 1.9375(REQ 1)](ISMAx - ISMIN) The following insulation resistance error (IE%) values are calculated for the HPIILPI actuation and post-accident conditions using the worst case (lowest) equivalent resistance values for REQ1 calculated above. The error is positive for the reason given above. HPI/LPI Rev. 6t95 RET: Life of Plant RESP: Nuclear Engineering
S od Pow
......... o.
DESIGN ANALYSISICALCULATION Crystal River Unit 3 DESA-C.FRM Page 63 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 IE,%(ACT) = [86 V - (2722.560)(0.020 A)(1 00%) [2722.56n + 1.9375(5.12 x 107n)](0.020 A - 0.004 A)
= + 0.0020% span for a 0.020 A transmitter current IE1%(AcT) = [86 V- (2722.56Q)(0.004 A)](100%)
[2722.56Q + 1.9375(5.12 x 107n)](0.020 A - 0.004 A)
= + 0.0047% span for a 0.004 A transmitter current The above error values are considered negligible when compared to the other error terms in the instrument loop. This calculation thus neglects insulation resistance error for the HPI/LPI actuation condition for Case 2. Therefore:
IE1%(ACT) =0.%sa Post-Accident (1.97) IE1%(1.97) = [86 V- (2722.56Q)(0.020 A)1(100%) [2722.56K + 1.9375(4.30 x 105C)](0.020 A - 0.004 A)
= + 0.24% span for a 0.020 A transmitter current IEl%( 1,9 7) = [86 V - (2722.56n)(0.004 A)](100%)
[2722.56n + 1.9375(4.30 x 105n)](0.020 A - 0.004 A)
= + 0.56% span for a 0.004 A transmitter current The error due to insulation resistance is largest at the lowest transmitter current, therefore:
IEl%( 1.9 7) = + 0.56% soan
- d. Device BA Bailey Buffer Amplifier (EBA) DI15 EBA(reo = Reference Accuracy = +/- 0.1% span ERESN(temp) = Resistor Temperature Effect = + 0.028% span D119 ERESA(temp) = Resistor Temperature Effect = + 0.048% span D119 EBA(DRE) = Design Range Error = +/- 0.399% span DI15 NORMAL 2 EBAN = +[(EBA(r*j)) + (ERE3N(temp) + (EBDRE))
= +/- [(0.1) + (0.028)" + (0.399)12
= +/- 0.41% span ACCIDENT 2 EBAA= [(EBA(rf)) + (EREys(temp) (EB&RE)) 2
[(0.1) + (0.048) + (0.399)] Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
0FRorda Power
......... o. DESIGN ANALYSIS/CALCULATION Crystal River Unit 3 DESA-C.FRM Page 64 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 -110
- e. Device BT TRIP & BYPASS Bistable Actuation (EBT) DI16 EBT(ref = Reference Accuracy =+ 0.17% span EBT(pot) = Potentiometer Resolution = 0.05% span EBT(sp) = Setpoint Repeatability = + 0.02% span EBT(t) = Temperature Effect = + 0.07% span EBT(hum) = Humidity Effect = +/- 0.0 span A8 2 2 EBT = +/- 2
[(EBT(req) + (EaTTot)) + (EqT(sp)) + (EBT(t))2]
= +/- [(0.17) + (0.05) + (0.02) + (0.07)2]
= +/--0.19% span
- f. Device EB Bailey Voltage Buffer (EEB) D120 EEB(reo= Reference Accuracy = - 0.1% span NORMAL EEBN(temp) = Temperature Effect = +/- 0.25(20 0 F)/100°F Al
= +/- 0.05% span ACCIDENT EEBA(temp) = Temperature effect = +/- 0.25(34 0 F)/100°F Al
= + 0.085% span NORMAL 2 11 2 EEBN = +/- [(EEBtef)) + (E2*N(temp)) ]
+/- [(0.-1) + (0.05)]
= +/- 0.11% span ACCIDENT 2 2 11 2 EEBA =- [(EEB(ef)) + (EEBA(temp)) ]
+ [(0.1) + (0.085)2]
= +/--0.13% span
- g. Device SM Bailey Signal Monitor (EsM) D121 EsM(reý = Reference Accuracy = + 0.25% span NORMAL EsMN(temp) = Temperature Effect = +/- 0.25(20°F)/100°F Al
= +/- 0.05% span ACCIDENT ESMA(temp) = Temperature Effect = +/- 0.25(34 0 F)/100°F Al
= +/- 0.09% span Repeatability and hysteresis assumed included in EsM(rne A9 NORMAL 2 2 2 ESMN + [(EsM(rep) + (S~emp)) 1
[(0.25) + (0.05)]
= .'- 0.25% span ACCIDENT 2 ESMA = +/- [(ESM(rep) + (EsMA, p))2]1/2
+/- [(0.25) + (0.085)]
= +-0.26% soan RET: Lifeof Plant RESP: Nuclear Engineering Rev. 6/95
Florida Power DESIGN ANALYSISICALCULATION CORPORATION Crystal River Unit 3 DESA-C.FRM Page 65 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10
- h. Device ES Bailey Indicator (EEs) D122 EES(,te= Reference Accuracy +/- 1.0% span NORMAL EESN(temp) = Temperature Effect = + (0.01/°F)(20 0F) Al
= +/- 0.20% span ACCIDENT EESA(temp) = Temperature Effect = + (0.01/°F)(34 0 F) Al
= +/-0.34% span Linearity, repeatability, and hysteresis assumed included in EES(,ef) A9 EEs(sc)= Scale Error = + 2 minor scale division
= +/- [(0.5)(50 psig)/2500 psig](100%)
+ 1.0% span NORMAL ~2 / 2 21/2 2
EESN = - [(EES(re)) + (EESN(temp)P + (EES(sc))/].
= +[(1.0) + (0.2)2 + (1.0)']1 ACCIDENT 2 21 2
-[(EESrer)' + (EsA(lemp)) + (EES(SC)) l/
EESA =
= +[(1.0) + (0.34) + (1.0)2]'
Device REC Esterline Angus Recorder (EREc) D124 EREC(ref) = Reference Accuracy = + 0.5% span NORMAL EREC(temp) = Temperature Effect = + [(0.03/°C)(20°F)(5°C/9°F)
= +/- 0.33% span ACCIDENT EREC(temp) = Temperature Effect = + [(0.03/°C)(34 0 F)(50 C/9°F)
= - 0.57% span EEs(sc)= Scale Error = Y2 minor scale division
= [(0.5)(50 psig)/2500 psig](100%)
=+ 1.0% span NORMAL 2 2 112 ERECN = +/- [(ERES(reQ)) + (E REC rtemp))+ (EEs(sc)) ]
2 [[(0.5) + (0.33) + (1.0) f
=~~ +(1.7%s0a ACCIDENT ERECA = +/- [(0.5)2 + (0.57)2 + (1.0)2]'A Rev695 spaneein ET Lle=f la+1R.25Nue Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
SPower FlRorida DESIGN ANALYSISICALCULATION
.... o.... oCrystal River Unit 3 DESA-C.FRM Page 66 of 88 SDOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10
- j. Device RCALL RECALLISPDSIPlant Computer (ERCALL)
NORMAL ERECALLN +/- 0.220% FSR D139
= + (0.220%)(20 Vdc/10 Vdc)
- + 0.44% span ACCIDENT ERECALLA= +/- 0.317% FSR D139
= +/- (0.317%)(20 Vdc/10 Vdc)
=+ 0.63% span Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
- oe DESIGN ANALYSISICALCULATION CORPORA...N Crystal River Unit 3 DESA-C.FRM Page 67 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10
- 2. CALCULATED LOOP ERRORS
- a. Transmitter NORMAL (ELOOPPTN:IN)
ELOOPPTN:IN = +/-[(EpTN)
+ (0.60%)
ACCIDENT 1.97 (ELooPPTI197:IN) ELOOPPT/197IN = +/- EpTi1.97
=+ 4.49% san HPI/LPI Actuation (ELooPPTIACT:IN)
ELOOPPTIACT:IN = +/- (EPT/ACT)
= + 0.91% span
- b. TRIP Bistable (1625# & 500#) - HPIILPI Actuation NORMAL (EPL.BSBTLJACTN:OUT)
EPLBSACTN:OUT = - EBAN
=+0.41
= 0.41% span EBSACTNOUT + EBT
= + 0.19% span ACCIDENT (EPL-BSBTUACTA:OLrr)
EPL-BSACTA:OUT = EBAA
= + 0.41% span EBSACTAXOUT = + EBT
=+ 0.19% span Note: Only the positive error value is used to establish the HPI/LPI setpoints due to the actuation's occurring on a decreasing RCS pressure signal.
- c. Pressure Recorder Normal (ELOOPPR(N):OUT) 2 2 1/ 2 ELOOPPR(N):OUT +/- [(EBAN) + (ERECN) ]
= + [(0.41)2 + (1.17)2]1/2
= 1.24% span Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
Power DESIGN ANALYSISICALCULATION s CORPDA710NCrystal River Unit 3 DESA-C.FRM Page 68 of 88 DOCUMENT IDENTIFICATION NO. REIIN 1-89-0014 10 Accident (ELooPPR(1.97):OUT) 2 /2 2 ELOOPPR(197):OUT = + [(EBAA) + (ERECA) 11
= + [(0.41)2 + (1.25)2]112
=+ 1.32% span
- d. Plant Computer, RECALL, & SPDS Normal (ELOOPRECALN:OUT) 2 2
+ [(EBAN) + (EREcýL ) ]'
ELOOPRECALLN:OUT
+ [(0.41)2 + (0.44) ]
= + 0.60% span Accident (ELOoPRECALLA:OUT) 2 ELOOPRECALLk:OUT [+/-
(E BAA)2 + (EREcA, .)) ]M
= + [(0.41)2 + (0.63) ]A
= + 0.75% span
- e. Output to T'Sat.
Normal (ELOOPTSATN:OUT) 2 2 ELOOPTSATN:OUT = +/- [(EEAN) + (EEBN) ]1/2
= + [(0.41)2 + (0.11)2]112
+ 0.42% span Accident (ELOOPTSATA:OUT) 2 2 112
= [(EBAA) + (EEBA) ]
ELOOPTSATA:OUT
= +/- [(0.41)2 + (0.13)2]1/2
= + 0.43% span
- f. RIP Indicators Normal (ELOOPPI(N):OUT) 2 2 ELOOPPI(N):OLrT = _ [(EBAN) 2 + (EEBN) 2
+ (EEsN) 1
= +/- [(0.41)2 + (0.11)2 + (1.43)211/2
= +/- 1.49% span Accident (ELOOPPI(i.97):OUT) 2 2 2 112 ELOOPPI(1.97):OUT = - [(EBA) + (EEBA) + (EEsA) ]
= + [(0.41)2 + (0.13)2 + (1.45)2]112
= +/- 1.51% span Rev. 6195 RET: Life of Plant RESP: Nuclear Engineering
0=rda *ower DESIGN ANALYSIS/CALCULATION CO RP ORATIO N C ry s ta l R ive r U n it 3 DESA-C.FRM Page 69 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10
- g. NNI Alarm and Interlock Contacts Normal (EPL-BSALN:OUT) 2 EPL-BSALN:OUT = +/- [(E BAN) 2 + (EEBN)
= + [(0.41)2 + (0.11)211]2
= +/- 0.42% span EBSALN:OUT = +/- ESMN
= +/- 0.25% span Rev. 6195 RET: Life of Plant RESP: Nudear Engineering
Florida Power
......... o. DESIGN ANALYSIS/CALCULATION Crystal River Unit 3 DESA-C.FRM Page 70 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10
- 3. "AS-LEFT" TOLERANCES D137
- a. Pressure Transmitter ALLOOPPTN:IN = - (EpTN(reo)
= +/- 0.25% span
+/- (0.25%/100%)(16 mA)
= +/- 0.040 mA Per the SP-1 32 for RC-3A-PT3, RC-3A-PT4, and RC-3B-PT3, the currently used "As-Left" tolerance for calibrating these transmitters is +/- 0.04 mA. Since the calculated tolerance is the same as currently used, the "As-Leff' tolerance for all three pressure transmitters will remain at +/- 0.04 mA. Therefore:
ALLOOPPTN:IN = +/-0.25% span = +/- 0.04 mA
- b. TRIP & BYPASS Bistable Actuation (ALBSBTA)
ALBSBTA:OUT = +/- (EBT(reo)
= +0.17% span
= + (0. 17%/100%)(10 Vdc]
= +/- 0.017 Vdc Per D143, the "As-Left" tolerance currently used for the TRIP and BYPASS bistable actuation is +/- 0.01 Vdc. Based on past experience of being able to calibrate the bistables to the tighter tolerance currently in SP-1 32, the procedure will continue to use this tolerance. Consequently, this calculation will use the same value for all three pressure transmitter loops. Therefore:
ALBsBTA:OUT = +-0.10 % span = +/- 0.010 Vdc
- c. NNI Alarm and Interlock Contacts (ALBSAL)
ALBSAL:OUT = +/- (ESM(re.0)
= + 0.25% span
= + (0.25%/i 00%)(10 Vdc) 0.025 Vdc Per D143, the "As-Left" tolerance currently used for the NNI Alarm bistable actuation is +/- 0.025 Vdc.
Based on past experience of being able to calibrate to the tolerance currently in SP-1 32, this calculation will use the same value as calculated. Therefore: ALBSAL:OUT = +/- 0.25% span = +/-0.025 Vdc
- d. TRIP Bistable Input (ALPL-BSBTI) - Partial Loop ALPL-BSi3Tn:OUT = +/- EBA(reml
= + 0.10% span
= + (0.10%/100%)(10 Vdc)
= +/- 0.010 Vdc for all three transmitter loops ALPL-BSBTI:OUT = +/- 0 10% span = +/- 0.010 Vdc
- e. NNI Alarm and Interlock Input (ALpL-BSALI) - Partial Loop
= +/- [(EBA(ref)2 + E BIre)/2 ALPL-BSALI:OUT
+ [(0.1)2 + (0.1)2]Nr2 Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
SPower FlRorida DESIGN ANALYSIS/CALCULATION CORPORATION Crystal River Unit 3 DESA-C.FRM Page 71 of 88 DOCUMENT IDENTIFICATION NO. jREEvSION 10 1-89-0014
= +/- 0.14% span
= + (0.14%/100%)(10 Vdc)
= + 0.014 Vdc for RC-3A-PT3 loop:
ALPL-BSALI:OUT = t 0.14% span = + 3.5 pasq = 0,014 Vdc
- f. Plant Computer, RECALL & SPDS 2 21 2 ALLOOPRECALL:OUT -[(EBA(ref)) + (ERECALLN) 1
+ [(0.1)2 + (0.44)2]1/2
= + 0.45% span
= + (0.45%)(2500 psig)
= 11.3 psig Since this is a new split loop calculation and prior calibrations have included the transmitter input the calculated AL will be used. Therefore:
ALLOOPRECALLýOUT = 0.45% span = 11.3 psig
- g. Pressure Recorder ALLOOPPR:OUT = +Ep~afl)
(EBA(Tf) + ]
= + [(0.1) + (0.5)2]1
= + 0.51% span
= + (0.51%)(2500 psig)
= + 12.8 psig for RC-3A-PT3 and RC-3B-PT3 loops Since the Recorder can only be read to 25 psig ('A minor scale division), the "As-Left" tolerance for the Recorder will be rounded to +/- 25 psig (+/- 1.0% span). Per D143, the current "As-Left tolerance is +/- 50 psig. Since this is a new split loop calculation and prior calibrations have included the transmitter input the rounded up AL will be used. Therefore:
ALLOOPPROUT = +/- 1 .0% span = 25 psia
- h. Output to T'Sat.
2 ALLOoPTSAT:OUT = +/- [(EBA(re.0) + (EEE3)2]1/2 1 [(0 .1)2 + (0.1)2 _+
= - 0.14% span
= +/- (0.14%)(2500 psig)
= +/- 3.5 psig
- Since this is a new split loop calculation and prior calibrations have included the transmitter input the calculated AL will be used. Therefore:
' ALLOOPTSAT:OUT = +/- 0.14% = 3.5 psig Rev- 6/95 RET: Life of Plant RESP: Nuclear Engineering
- Power DESIGN ANALYSIS/CALCULATION CORPOATIONCrystal River Unit 3 DESA-C.FRM Page 72 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 L RIP Indicators 2 2
[(EBA(re) + (EEB(ref)) + ( -ES(ref) ] ALLooPPLOUT [ [(0.1)2 + (0.1)2 + (1.0)211/2
= +/- 1.01% span
+/- (1.01%)(2500 psig)
= +/- 25.3 psig for RC-3A-PT3 and RC-3B-PT3 loops Since the Indicator can only be read to 25 psig (/ minor scale division) and the current SP-132 value is 50 psig the error will be rounded up to 50 psig. Therefore:
ALLOOPPIOUT = +/- 2% span = +/- 50 psiq Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
0Florida Power CO RPORATIO N DESIGN ANALYSIS/CALCULATIONC ry s ta l R iv e r U n it 3 DESA-C.FRM Page 73 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10
- 4. "AS-FOUND" TOLERANCES SBLOOPPTN:IN = +/- EPTN(dft) = (Drift (Stability):+/-0.2% of upper range limit for 30 months.) D17
= (0.2%)(3000/2500)
= + 0.24% span
- a. Pressure Transmitter A6 Category A Method 2 112 AFLOOPPT:INA = - {ALLOOPPTN:IN + [(SBLOoPPTIN)2 + (MTELOOP:IN) ] }
= +/- (0.25 + [(0.24)2 + (0.202)]1 }
=+/- 0.56% span
=+/- (0.56%/100%)(16 mA)
= + 0.090 mA for all three transmitter loops Since the calculated tolerance is based on applying a new category A method, the calculated value will be used in the calculation and the procedure in lieu of the current SP-132 value.
AFLOOPPT:IN = +/- 0.56% span = +/- 0.090 mA
- b. TRIP & BYPASS Bistable Actuation D117 SBBsBT:OUT +/- EBT(dft)
= +/- 0.164% span AFBsBTA:OUT = {ALBSBTA:OUT + [ýSBBSBT:OU) 2
+ (MTEpLOUT2) 2] 112} A6
= ({0.10 + [(0.164) + (0.005) ]1/2}
= + 0.26% span
+/- (0.26%/i 00%)(10 Vdc)
= +/- 0.026 Vdc for all three transmitter loops Per D143, the "As-Found" tolerance currently used for the TRIP and BYPASS bistable actuation is +
0.027 Vdc. Based on applying a new Split-Loop method and Design Guide methodology the tigher tolerance calculated above will be used. Therefore:. AFBsBTA:OuT = +/- 0.26% span = +/- 0.026 Vdc
- c. NNI Alarm and Interlock Contacts AFBSAL:OUT = + (ALBSAL:OUT + MTEPL:OUTr2)
= + (0.25 + 0.005)
= +/- 0.26% span
= +/- (0.26%/l 00%)(10 Vdc)
= + 0.026 Vdc for RC-3A-PT3 loop Per D143, the "As-Found" tolerance currently used for the NNI Alarm bistable actuation is +/- 0.027 Vdc.
Based on applying a new Split-Loop method and Design Guide methodology the tigher tolerance calculated above will be used. Therefore: AFBSAL:OUT= +/- 0.26% span = +/- 0.026 Vdc Rev. 6195 RET: Life of Plant RESP: Nudear Engineering
Forida
*Power DESIGN ANALYSISICALCULATION Crystal River Unit 3 DESA-C.FRM Page 74 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 1 10
- d. TRIP Bistable - Partial Loop DI17 SBPL-BSBA:OUT = + EBA(dft) 2
=+0.548% span 9L:OUT ) 2 AFPL-BSBTI:OUT {ALPL-BSBTI:OUT +[( SBP:OUT + (MTEpL:OUTr)] A6
= {0.10 + [(0.548) + (0.19)y'A}
= +/- 0.68% span
= +/- (0.68%/i 00%)(10 Vdc)
= +/- 0.068 Vdc for all three transmitter loops Since this calibration is a partial loop (not including the input tolerance) the AFLOOPBTL:OUT value will be revised to the following tighter tolerance:
AFPL.BSBTI:OUT -'-0.68 % span = +/-0.068 Vdc
- e. NNI Alarm and Interlock - Partial Loop 2 2 1 2 AFPL-BSALI:OUT + [(ALPL-BSALI:OUT) + [(SBpL-BSyA:OUT) + (MTEpL:OUT1) 1 / A7
+/- {0.14 + [(0.548)2 + (0*.-19)1 S0.72% span
= + (0.72%/100%)(10 Vdc)
= +/- 0.072 Vdc for RC-3A-PT3 loop Since this calibration is a partial loop (not including the transmitter values) the AFLOOPBTL:OUT value will be revised to the following tighter value:
AFPL.BSALI:OUT = +/- 0.72 % span = +/-0.072 Vdc
- f. Plant Computer, RECALL & SPDS 2 2 11 2 AFLOOPRECALL:OUT = - {ALLOOPRECALL:OUT + [(SBPL.BSBA:OUT) + (MTELooP:OUT) ]
= +(0.45% + [(0.548)2 + (0.190)2]112
= + 1.03% span
= + 1.03%(2500 psig)
= 25.8 psig Since this is a new split loop calculation and prior calibrations have included the transmitter input the calculated AF will be used. Therefore:
AFLOOPRECALL:OUT = +/- 1.03% span = + 25.8 psiq Rayý.6/95 RET: Life of Plant RESP: Nuclear Engineenng
S Fla
*9=
...........
DESIGN ANALYSIS/CALCULATION Crystal River Unit 3 DESA-C.FRM Page 75 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10
- g. Pressure Recorder 112 AFLOOPPR:OUT {ALLOOPPR:OUT + [(SBPL.BSBOUT) + (MTELOOP:OUT)] ]
+ {1.0 + [(0.548)2 + (0.190)]121}
=+1.58% span
= + (1.58%)(2500 psig)
= +/- 39.5 psig for RC-3A-PT3 and RC-3B-PT3 loops Since the recorder can only be read to 25 psig (1/2 minor scale division), the "As-Found" tolerance for the recorder will be rounded up to +/- 50 psig or 2.0% span. Since this is a new split loop calculation and prior calibrations have included the transmitter input the calculated AF will be used. Therefore; AFLOOPPR:OUT = + 2.0% span = +/- 50 psiq
- h. Output to T'Sat.
2 2 AFLOOPTSAT:OUT ={ALLOOPTSAT.OUT + [(SBPL.BSBA:OUT) + (MTELoOP:OUT) 1
= +/- {0.14 + [(0.548)2 + (0.19)2]112}
= 0.72% span
= + 0.72%(2500 psig)
=+18.0 psig Since this is a new split loop calculation and prior calibrations have included the transmitter input the calculated AF will be used. Therefore:
AFLooPTSAT:OUT =+/- 0.72% span = +/- 18.0 psiq I. RIP Indicators 2 2 12 AFLOOPPI:OUT = +/-{ALLOOPPI:OUT + [(SBPL-BSBA.O ) + (MTELOOP:OUT) ] / }
+/- {2.00 + [(0.548) + (0.19)]1}
+/- 2.58% span
= +/- (2.58%)(2500 psig)
= +/- 64.5 psig for RC-3A-PT3 and RC-3B-PT3 loops Since the Indicator can only be read to 25 psig (1/2 minor scale division), the "As-Found" tolerance for the Indicator will be rounded up to +/- 75 psig or +/- 3.0% span. Therefore:
AFLOOPPI:OUT = + 3.0% span = +/- 75 psig Rev. 6195 RET: Life of Plant RESP: Nuclear Engineering
SPower DESIGN ANALYSIS/CALCULATION CORPOATIONCrystal River Unit 3 DESA-C.FRM Page 76 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 1 01
- 5. CALIBRATED LOOP ERRORS
- a. TRIP Bistable Actuation HPIILPI ACTUATION NOTE: The resistor bias is not include in the scaled trip unit (See DI19) and the accident ELOOPBTI/ACTA values will be used.
Instrument loop errors that are associated with the HPI and LPI trip and alarm function are being calculated using the Category "A"(Partial Loop) graded approach. The formula that will be used for the calibrated loop errors is as follows: ACCIDENT CELOOP:IN =+/- [(ELOOP:IN) 2 + (AFLOOP:IN) 2 ]', CELOOP:OUT 2
= +/- [(EPL.BS ) + (AFPL-BS )
2
+ (EBS ) +
2 (FS)]1 2 2 2 CELOoP:TOTAL = +/- [(CELOOP:IN) + (CELooP:OUT) ]11 +/- EPROCESS:IN +/- EBIAS:IN +/- EBIAS:OUT 2 CELOOPBT:IN +/- [(ELOOPPT/ACT:IN) + (AFLOOPPT:?N)2]1/2
= + [(0.91)2 + (0.56)211/2
= +/- 1.07% span
= +/- (1.07%)(2500 psig)
= + 26.8 psig 2 2 2 2 112 CELOOPBT:OUT = +/- [(EPL.BSACTA:OUT) + (AFPL.BSBTI:OUT) + (EBsACTA:OUT) + (AFBSBTA:OUT) ]
= +/-[(0.41)2 + (0.68) + (0.19)2 + (0.26)21l12
= + 0.86% span
= + (0.86% span)(2500 psig)
= +/- 21.5 psig 2 2 11 2 CELOOPBT:TOTAL= +/- [(CELOOPBT:IN) + (CELOOPBT:OUT) ]
= +/- ((1.07)2 + (0.86)2)112
= +/- 1.37% span
= +/- (1.37%)(2500 psig)
= +/- 34.3 psici for all three transmitter loops
- b. Pressure Recorder Normal (CELOOPPRN:TOTAL)
CELOOP:IN NOTE: The transmitter is a Category A, Therefore the Category A equation will be used. 2 C ELOOP:IN =+/-[(ELOOP:IN )2 + (AFLOOP:IN ) ]',' CELOOPPRN:IN = +/-[(ELoOPPTN:IN) 2 + (AFLOOPPT:IN) 2 ]11/2
= +/-[(0.60)2 + (0.56)2]112 Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
Rlorida Power DESIGN ANALYSISICALCULATION s CORPOAYIONCrystal River Unit 3 DESA-C.FRM Page 77 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10
= +/- 0.82% span CELOOPPRN:IN +/- 0.82% span CELOoP:OUT - NOTE: The OUT function is Category B:
ALLOOPPR:OUT (1.0% span) is greater than SRSS of the Reference Accuracy of the components in the split loop (0.51% span) and the AFLOOPPR.OUT (2 .0% span) is greater than (ALsPLITLOOP + [(2/3 MTESPLITLOOP) + (SBsPLITLOOP) 2]'. = 1.58% span), Therefore Equation #1 of Category B will be used; 2 2 2 2 + (SBLooP:OUT) ]1/ )21A CELOOPOUT = +/-I[(ELooP:oUT) + (AFLooP:OUT + [(2/3 MTELOOP:o-rT) CELOOPPRN:OUT = +[(ELooPPR(N):OUT) 2 + (AFLOOPPROUT + [(2/3 MTELOOP:OUT) 2 +(SBpL-BSBA:OUT) 2 ]1 2 ]1/2
= +[(1.24)2 + (2.0 + [(0.13)2 + (0.548)2112)2]1/2
= + 2.85
= + 2.85% span CELOOPPRN:OUT (2.85%) is greater than AFLOOPPR:OUT (2.0%). Therefore; CELOOPPRN:OUT = +/-2.85% span 2 2 CELOOPPRN:TOTAL +[(CELOoPPRN:IN) + (CELooPPRN:OUT)] + ERES(BIAS) DI19
+[(0.82) + (2.85)2112+ 0.34
= + 2.97 + 0.34
=+ 3.31% span for RC-3A-PT3 and RC-3B-PT3 loops
= +3.31%(2500 psig)
= + 82.8 psig 2 2 112 CELOOPPRN:TOTAL
-[(CELooPPRN:IN) 2+ (CELooPPRN:OUT) 2] /
- [(0.82) + (2.85)2]1/2
= - 2.97% span for RC-3A-PT3 and RC-3B-PT3 loops
= - 2.97%(2500 psig)
=-74.3 psig Accident (CELOOPPRI .97:TOTAL)
CELOOP:IN NOTE: The transmitter is a Category A, Therefore the Category A equation will be used. CELOOP:IN = +/-[(ELOOP:IN)2 + (AFLOOPIN)2], 2 21
= +/-[(ELooPPT/197) + (AFLooPPT:IN) M CELOOPPR197:IN
= +/- [(4.49)2 (0.56)2]112
+
CELOOPPR197:IN = +/- 4.53% span CELOOP:OUT - NOTE: The OUT function is Category B: Rev- 6195 RET: Life of Plant RESP: Nuclear Engineering
Florida Power CORPORATION DESIGN ANALYSIS/CALCULATION Crystal River Unit 3 DESA-C.FRM Page 78 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 110 ALLOOPPR:OUT(1.0% span) is greater than SRSS of the Reference Accuracy of the components in the split loop (.51% span) and the AFLOOPPR:OUT (2.0% span) is greater than (ALSPLITLOOP + [(2/3 MTEsPLITLOOP)- + (SBsPLITLOOp) 2 ]11 = 1.58% span), Therefore Equation #1 of Category B will be used; 2 2 12 CELOOP:OUT = -[(ELoOP:OUTr) 2
+ (AFLOoP:OUT + [(2/3 MTELOOP:OUT-) + (SBLOoP:OUT) ] / )2]/
CELOOPPR1197OUT = +[(ELooPPR(197):OUT,. 2 + JAFLOOPPROUT + [(2/3 MTELOOP:OUT) 2 + (SBPL-BSBA:OUT) / 2 1/221/2
= +[(1.32) + (2.0 + [(0.13)2 + (0.548)] )]
= + 2.88% span CELOOPPR197:OUT (2.88%) is greater than AFLOOPPR:OUT (2.0%). Therefore; CELOOPPR197:OUT = +/-2.88% span 2 2 12 C ELOOPPR197:TOTAL +[(CELOoPPR197:IN) + (CELOOPPR197:OLFF) ] + ERES(BIAS) + IE,%(1. 9 7 )
= +[(4.53) + (2.88)211/2+ 0.34 + 0.56
= + 5.37 + 0.34 + 0.56
= + 6.27% span for RC-3A-PT3 and RC-3B-PT3 loops
= +6.27%(2500 psig)
= + 156.8 psig 2 2 112 CELOOPPR197:TOTAL = (CELooPPR197:IN) + (CELOOPPR197:OUT) 2 ASENSE-LINE I1E 2 %(1. 9 7)
-[(4.53) + (2.88)2]1/2- 0.09 -0.36
= - 5.37 - 0.09 - 0.36
= - 5.82% span for RC-3A-PT3 and RC-3B-PT3 loops
= -5.82%(2500 psig)
= - 145.5 Psin
- c. Plant Computer, RECALL, & SPDS NORMAL (C ELOOPRECALLN:TOTAL)
CELOCoP:IN NOTE: The transmitter is a Category A, Therefore the Category A equation will be used. CELOOPIN = +[(ELOOP[N) 2 + (AFLOOP:IN) 2] 1/ 2 12 CELOOPRECALLN:IN = +/-[(ELoOPPTN) 2 + (AFLOOPPT:IN) ]1
= +/-[(0.60)2 + (0.56)2]1/2 CELOOPRECALLN:IN = +/- 0.82% span CELOOP:OUT - NOTE: The OUT function is Category B:
The ALLOOPRECALL:OUT (0.45%) is equal to the SRSS of the Reference Accuracy of the components in the split loop (0.45%), Therefore, Category B Equation #3 will be used. CELooP:OUT _ +[(ELooP:OUT) 2 +
-- (2/3 MTELooP:OUT) 2 + (SBLooP:OUT) 2%] +/- EBIAS:OUT C ELOOPRECALLN:OUT =-+/-[(ELOoPRECALLN:OUT) 2
+ (2/3MTELoop: 0 UT) 2 + (SBpL.BSBA:oU-r) 2]1/ 2 Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
0Florida
*ower
.........o. DESIGN ANALYSISICALCULATION Crystal River Unit 3 DESA-C.FRM Page 79 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10
=+/- [(0.60)2 + (2/3(.1 90))2 + (0.548)2]1/2
= + 0.82% span CELOOPRECALLN:OUT (0.82%) is less than AFLOOPRECALL:OUT (1.03%). Therefore; C ELOOPRECALLN:OUT = +/- AFLOOPRECALL:OUT
= +/- 1.03% span 2
CELOoPRECALLN:TOTAL +[(CELOoPRECALLN:IN) + (CELooPRECALLNOUT) 1 + ERES(BIAS)
= +[(0.82) + (1.03)2]1/2 + 0.34
= + 1.32 + 0.34
= + 1.66% span for RC-3A-PT3 and RC-3B-PT3 loops
+1.66%(2500 psig)
= + 41.5 psig 2 2 11 2 C ELOOPRECALLN:TOTAL = -[(CELoIoPRECALLN:VN + (CELoOPRECALLN:OUT) ]
= -[(0.82) + (1.03)]
=- 1.32
= - 1.32% span for RC-3A-PT3 and RC-3B-PT3 loops
= -1.32%(2500 psig)
=- 33.0 sisi ACCIDENT (CELOOPRECALLA:TOTAL)
CELOOP:IN NOTE: The transmitter is a Category A, Therefore the Category A equation will be used. 2 2 CELOOP:IN = +/-[(ELOOP:IN) + (AFLOOP:IN ) ]IM CELOOPRECALLAIN = +/-[(ELooPPTt97) 2 + (AFLOOPPT:IN) 2 ] 11 2
+ [(4.49)2 + (0.56)2]1/
+/-
CELOOPRECALLA:IN = +/-4.53% span CELOoP:OUT. NOTE: The OUT function is Category B: The ALLOOPRECALL:OUT (0.45%) is equal to the SRSS of the Reference Accuracy of the components in the split loop (0.45%), Therefore, Category B Equation #3 will be used. 2 2]21 2 CELOOPRECALLA:OUT = +[(ELOoPRECALLA:Ou-T) +(2/3MTELoOP OUT) + (SBPL-BSBA:OUT)2]1/2
= +[(0.75) + (2/3(.190)) + (0.548)1
= + 0.94 CELOOPRECALLA:OUT = + 0.94% span CELOOPRECALLA:OUT (0.94%) is less than AFLOOPRECALL:OUT (1.03%). Therefore; CELOOPRECALLA:OUT = + AFLOOPRECALL:OUT
= + 1.03% span Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
Florida
*oe DESIGN ANALYSIS/CALCULATION Crystal River Unit 3 DESA-C.FRM Page 80 of 88 DOCUMENT IDENTIFICATION NO. 1 REVISION 1-89-0014 2 22]11/2+
CELOOPRECALLA:TOTAL +[(CELooPRECALLA.IN) + (CELOOPRECALLA:OUT) ] + IEl%(1.97 ) + ERES(BIAS)
= +[(4.53) + (1.03) 1 + 0.56 + 0.34
= + 4.65 + 0.56 + 0.34
= + 5.55% span for RC-3A-PT3 and RC-3B-PT3 loops
= +5.55%(2500 psig)
=+ 138.8 psi:g CELOOPRECALLA:TOTAL = -(0CELooPRECALLA:.N 2
-
(CELooPRECALLA:OUT) 2]2 "SENSE-LINE IAE% 97)
= -[(4.53) + (1.03)] -0.09 - 0.36
= - 4.65 -0.09 - 0.36
= - 5.10% span for RC-3A-PT3 and RC-3B-PT3 loops
= -5.10%(2500 psig)
= - 127.5 psig
- d. Output to T'Sat.
NORMAL (CELOoPTSATN:TOTAL) CELOOP:IN NOTE: The transmitter is a Category A, Therefore the Category A equation will be used. 2 2 CELOOP:IN = +/-[(ELooP:IN) + (AFLOOP:IN) ]A 21 2 CELOOPTSATN:IN = +/-[(ELOOPPTN) 2 + (AFLooPPT:IN) ]/
= +/-[(0.60)2 + (0.56)2]1/2
= +/- 0.82% span CELOOPTSATN:IN = +/- 0.82% span CELooP:OUT - NOTE: The OUT function is Category B:
The ALLOOPTSAT:OUT (0.14%) is equal to the SRSS of the Reference Accuracy of the components in the split loop (0.14%), Therefore, Category B Equation #3 will be used. 2 2 2 CELOOP:OUT =+/-[(ELoOP:OUT) + (2/3 MTELOOP:OUT) + (SBLOOP:OUT) ]A 2 2 1
= +/-[(ELOOPTSATN:OUT)2 + (2/3MTELoOP:OUr) + (SBpL-BSBA:ouT) ] /2 CELOOPTSATN:OUT
= +/- [(0.42)2 + (2/3(.190))2 + (0.548)211,2 CELOOPTSATN:OUT = +/- 0.70% span CELOOPTSATN:OUT (0.70%) is less than AFLOOPTSAT:OUT (0.72%). Therefore; CELOOPTSATN:OUT = +/- AFLOOPTSAT:OUT
=+0.72
= +/- 0.72% span 2 2 1 C ELOOPTSATN:TOTAL +[(CELOoPTSATN:IN) + (CELOOPTSATN:OUT) 1 / 2+ ERES(BIAS)
+[(0.82) + (0.72)211/2 + 0.34 Rev. 6/95 RET: Life of Plani RESP: Nudear Engineering
Florida
*Power CORPORATION DESIGN ANALYSISICALCULATION Crystal River Unit 3 DESA-C.FRM Page 81 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10
=+ 1.09 + 0.34
= + 1.43% span for RC-3A-PT3 and RC-3B-PT3 loops
= +1.43%(2500 psig)
+ 35.8 ipsig 2
CELOOPTSATN:TOTAL -[(CELOoPTSATN:IN) + (CELOOPTSATN:OUT)2 ] 2
-[(0.82) + (0.72)2]V2
= - 1.09% span for RC-3A-PT3 and RC-3B-PT3 loops
-1.09%(2500 psig)
= - 27.3 psici ACCIDENT (CELOOPTSATA:TOTAL)
CELOOP:IN NOTE: The transmitter is a Category A, Therefore the Category A equation will be used. 2 2 CELOOP:IN = _[(ELOOP:IN) + (AFLOOP:IN) ]A 2 2 1/2 CELOOPTSATA:IN +/-+ [(ELooPPT197) + (AFLooPPT:IN) ]
+/-+ [(4.49)2 + (0.56)2]1/2 C ELOOPTSATA:IN +/-
+/- 4.53% span CELooP:OUT. NOTE: The OUT function is Category B:
The ALLOOPTSAT:OUT (0.14%) is equal to the SRSS of the Reference Accuracy of the components in the split loop (0.14%), Therefore, Category B Equation 2
#3 will be 2used.
2 CELOOP:OUT ý+/-[(ELOOP:OUT) + (2/3 MTELOOP:OUT) + (SBLOOP:OUT) ]1 2 2 2 1 C ELOOPTSATA:OUT -[(ELOOPTSATA:OUT) + (2/3MTELOOP:OUT) + (SBpL-BSBA:oUr) ] /2
= +/- [(0.43)2 + (2/3(.190))2 + (0.548)2]112
= + 0.71% span CELOOPTSATA:OUT (0.71%) is less than AFLOOPTSAT:OUT (0.72%). Therefore; C ELOOPTSATA:OUT = +/- AFLOOPTSAT:OUT
= +/- 0.72% span C ELOOPTSATA:TOTAL = +[(CELo9 PTSATA:IN) 2 + (CELooPTSATA:OUT) 2 1/ 2 + IEl%( 1 97)+ ERES(BIAS)
= +[(4.53) + (0.72)2]112 + 0.56 +0.34
= + 4.59 + 0.56 + 0.34
= + 5.49% span for RC-3A-PT3 and RC-3B-PT3 loops
= +5.49%(2500 psig)
= + 137.3 psici 2 1
= [(CELOOPTSATA:IN) 2 + (CELOoPTSATA:OUT) ] r2 - ASENSE-LINE - IE 2 %(1.97)
C ELOOPTSATA:TOTAL
= -[(4.53)2 + (0.72)2]12-0.09- 0.36
= - 4.59 -0.09 - 0.36 Rev. 69 RET: Life of Plant RESP: Nudear Engineedng
AmFlorida
- Fwr DESIGN ANALYSISICALCULATION Crystal River Unit 3 DESA-C.FRM Page 82 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10
= - 5.04% span for RC-3A-PT3 and RC-3B-PT3 loops
= -5.04%(2500 psig)
= - 126.0 psig
- e. RIP Indicators NORMAL (CELOOPPINTOTAL)
CELOOP:IN NOTE: The transmitter is a Category A, Therefore the Category A equation will be used. CELOOP:IN = +/-[(ELOOP:IN) 2 + (AFLOOP:IN )2 11, 2 2 CELOOPPiN:IN = +/-[(ELooPPTN) + (AFLooPPT:IN)2]1
= +/-[(0.60)2 + (0.56)211/2
= +/- 0.82% span CELOOPPININ = +/- 0.82% span CELOOP:OuT -NOTE: The OUT function is Category B:
The ALLOOPPI:OUT (2.00%) is greater than the SRSS of the Reference Accuracy of the components in the split loop (1.01%), and AF 0ooPPV:OUT (3.00%) is greater than (ALLOOPPI:OUT + [(2/3 2 2 MTELOOP:OUT) + (SBLooPBA:OUT) ] (2.58%), Therefore Category B Equation #1 will be used. 2 2 2 2 CELOOP:OUT = +/-[(ELOOP:OUT) + (ALLOOP:OUT + [(2/3 MTELOOP:OUT) + (SBLoop:OUT) ]Y) ]'A CELOOPPINOUT 2
+/-[(ELOOPPI(N):OUT)21/22* + (ALLOOPPIOUT + [(2/3 MTELOOP:OUT) 2 +
2 2 (SBpL-B BA:OUT) ] ) ]
= +/- [(1.49) + (2.0 + (213(.190))2 + (0.548)2]1/2
= +/- 2.96% span CELOOPPIN:OUT (2.97%) is less than AFLOOPPIOUT (3.00%). Therefore; CELOOPPINOUT = + AFLOOPPIOUT
+/- 3.00% span C ELOOPPIN:TOTAL = +[(CELooPPIN:IN) 2 + (CELOOPPIN:OUT) ]1 2
+ ERES(BIAS)
= +[(0.82) + (3.00)2] '2 + 0.34
= + 3.11 + 0.34
= + 3.45% span for RC-3A-PT3 and RC-3B-PT3 loops
= +3.45%(2500 psig)
= + 86.3 psiQ 2 2 2 C ELOOPPINTOTAL = -[(CELo 9 PPtN:IN) + CELOOPPINOUT) ]
= -[(0.83) + (3.00)2 1/2
= - 3.11% span for RC-3A-PT3 and RC-3B-PT3 loops
= -3.11%(2500 psig)
Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
Florida
*Power DESIGN ANALYSISICALCULATION Crystal CORPORATION River Unit 3 DESA-C.FRM Page 83 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 ACCIDENT (CELOOPPIA:TOTAL)
CELOOPIN NOTE: The transmitter is a Category A, Therefore the Category A equation will be used. 2 2 CELOOPIN = +/-[(ELOOP:IN) + (AFLOOPIN ) ]'4 2 CELOoPPIAIN = +[(ELooPPT197) (+AFLOOPPT:IN) ]12
+ [(4.49)2 + (0.56)1" CELOOPPIAIN = + 4.53% span CELOOP:OUT - NOTE: The OUT function is Category B:
The ALLOOPPIOUT (2.00%) is greater than the SRSS of the Reference Accuracy of the components in the split loop (1.01%), and AFOOPPL:OUT (3.00%) is greater than (ALLOOPPI:OUT + [(2/3 2 2 MTELOOP:OUT) + (SBLOOPBA:OUT) ]Y, (2.56%), Therefore Category B Equation #1 will be used. 2 2 2 CELOOPOUT = +/-[(ELooP:OUT) 2
+ (ALLOOPOUT + [(2/3 MTELOOPOUT) + (SBLOOPOUT) ],) ]/.
CELooPTPA:OUT 2
"+/-I[(ELooPPI(197):OUT) + ,ALLooPPlIOUT +
]'
[(2/3 MTELOOP:OUT) + (SBpL'B¶BA:OUT) ])
-+/-[(1.51 ) + (2.0 + (2/3(.190))2 + (0.548)211/2
= +/- 2.97% span CELOOPPIA:OUT (2.98%) is less than AFLOOPPIOUT (3.00%). Therefore; CELOOPPIA:OUT = + AFLOOPP:OUT
= + 3.00% span 2
CELOOPPIA:TOTAL +[(CELooPPLA:IN) + (CELOOPPIA:OUT) 2 ]112 + lE 1%(1g.)+ ERES(BIAS)
= +[(4.53) + (3.00)2] /2+ 0.56 + 0.34
= + 5.43 + 0.90
= + 6.33% span for RC-3A-PT3 and RC-3B-PT3 loops
= +6.33%(2500 psig)
= + 158.3 psli 2 21/2 CELOOPPIA:TOTAL = 4(CELooPPIA:IN) +SCELooPPrkour) ] - ASENSE-LINE - IE2%(1.97)
= -[(4.53) + (3.00) 1 - 0.09- 0.36
= - 5.43 - 0.45
= - 5.88% span for RC-3A-PT3 and RC-3B-PT3 loops
= -5.88%(2500 psig)
= - 147.0 psicq
- f. NNI Alarm and Interlock Contacts Rev- 6195 RET: Life of Plant RESP: Nuclear Engineering
SFlorida Power
...........
DESIGN ANALYSISICALCULATION Crystal River Unit 3 DESA-C.FRM Page 84 of 88 DOCUMENT IDENTIFICATION NO. REMSION 1-89-0014 1- 10 Instrument loop errors that are associated with the HPI and LPI trip and alarm function are being calculated using the Category "A"(Partial Loop) graded approach. The formula that will be used for the calibrated loop errors is as follows:
= +/- [(E~oop:IN) 2 + (AFLoOpN) f'"
2 CELOOPIN CELOOPOUT = +/- [(EPL-BS) 2 + (AFPL-BS) 2 + (EBs) 2 + (AFBs)2]1/2 CELOOPTOTAL = +/- [(CELooP.N) 2 + (CELOOP:OUT) 2 ] 112 +/- EPROCESS:IN +/- EBIAS:IN +/- EBIAS:OUT 2 211 2 CELOOPALIN = + [(ELOOPPTN:IN) + (AFLOOPPT:IN)
= + [(0.60)2 + (0.56)2112
= + 0.82% span
= + (0.82%)(2500 psig)
= 20.5 IDsiq CELOOPALOUT =_[(EpL.BSALN:OUT )2+ (AFpL-SALI:OU-2)2 + (EBSALN:OUT)2 + (AFBsAL:OUT)2]1/2
= + [(0.42)2 + (0.72)2 + (0.25)2 + (0.26)2]lr2
=+/- 0.91% span
=+ (0.91% span)(2500 psig)
=_22.8 psig C ELOOPAL:TOTAL = + [(CELOoPAL:IN) 2 + (CELOOPAL:OUT) 2 ]112+ ERES(BIAS)
= + ((0.82) + (0.91)2)1/2 + 0.34
= + 1.57% span
= + (1.57%)(2500 psig)
= + 39.3 psiq for RC-3A-PT3 LooD 2 2 112 CELOOPALTOTAL [(CELOoPAL:IN) + (CELOOPAL:OUT) ]
=- ((0.82) + (0.91)2)1/2
-- 1.23% span
= - (1.23%)(2500 psig)
= - 30.8 psicq for RC-3A-PT3 Loop
- 6. LOOP RESPONSE TIME The time response for both the HPI and LPI actuations are the same since the same modules are involved in each actuation. Using values from Di7 and DI44, the following loop response time (RTL) applies to all three channels of ESAS and for both HPI and LPI:
RTL = RTPT + RTBA + RTBT
= 0.2 sec + 1 sec + 0.1 sec
- 7. HPI/LPI TriplBypass Instrument Setpoints:
Rev. 6195 RET: Lifeof Plard RESP: Nuclear Engireernng
Florida Power CORP 0 A &T10kCrystal DESIGN ANALYSIS/CALCULATION River Unit 3 DESA-C.FRM Page 85 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10 HPIILPI TriD The setpoints for TRIP Bistable Actuation HPI/LPI ACTUATION using CELOOPBT:TOTAL (Section 5.a.) are calculated as follows: The current philosophy on establishing inplant setpoints (SP) is to back off from the analytical limit (ANL) by the amount of the calibrated loop error (CE) which includes the "As-Found" tolerance (SPLpI = ANLLPI + CELOOPBT:TOTAL). Ideally, the Improved Technical Specification setpoint (ITS) is offset from the inplant setpoint by the amount of the "As-Found" tolerance (AF). This approach assures plant maintenance personnel that as long as the "As-Found" value can be achieved, the Improved Technical Specification value will not be exceeded (SPLpI = ITSLPI + AFBTL). Since no analytical limit currently exists for LPI, the Improved Technical Specification value of 500 psig will be used. Since LPI actuates on a decreasing RCS pressure signal, the actual inplant LPI setpoint is to be set above the Analytical Limit by the amount of the calibrated looperror (CELOOPBT:TOTAL). The value of this error is added to the Analytical Limit to arrive at an inplant LPI setpoint. Therefore, the inplant LPI setpoint is: SPLPI = ANLLpI + CELOOPBT:TOTAL
= 500 psig + 34.3 psig
= 534.3 psig
= [(534.3 psig)/(2500 psig)](10 Vdc)
=2.137 Vdc To maintain the existing setpoint of 560 psig,a margin of 25.7 psig will be added to the calculated setpoint for ease of setting. Therefore:
SP'LPI = SPLp, + Margin
= 534.3 psig + 25.7 psig
= [(560 psig)/(2500 psig)](10 Vdc)
= 2.240- c Since HPI actuates on a decreasing RCS pressure signal at an Analytical Limit (ANLHpI) of 1625 psig, the actual inplant HPI setpoint (SPHPI) is to be set above 1625 psig by the amount of calibrated loop error (CELOOP:TOTAL). The value of this error is added to the Analytical Limit as follows:
SPHPI = ANLHPI + CELOOPBT:TOTAL
= 1625 psig + 34.25 psig
= 1659.25psig
= [(1659.25 psig)/(2500 psig)](10 VDC)
= 6.637 VDC To establish a new HPI setpoint of 1665 psig, a margin of 5.75 psig will be added to the calculated setpoint.
Therefore: SP'HPI = SPHPI + Margin
= 1659.25 psig + 5.75 psig
= 1665 osig
= [(1665 psig)/(2500 psig)](10 Vdc)
Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineering
Rlorda SPower DESIGN ANALYSIS/CALCULATION COAPOA71ONCrystal River Unit 3 DESA-C.FRM Page 86 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89-0014 10
= 6_60 Vdc HPIILPI Bypass & Reset RC-3-BT4, BT5, & BT6 "HPI Bypass Permit" =[(1770 psig)/(2500 psig)](10 Vdc) D145 "HPI Bypass Reset" =[(1795 psig)/(2500 psig)](10 Vdc) D145
= 7180 Vdc RC-3-BT10, BT11, & BT12 "LPI Bypass Permit" =[(850 psig)/(2500 psig)](10 Vdc) D145 "LPI Bypass Reset" =[(875 psig)/(2500 psig)](10 Vdc) D145
= 3.500Vdc Vdc
- 8. NNI Alarm and Interlock Setpoints The calculated setpoint for the NNI Alarm and Interlock Contacts using CELOOPALTOTAL (Section 5.f.) applies only to those alarms described in D146 dealing with the CF isolation valves. The setpoint for the alarm to close the CFT valves will be established using the maximum CFT nitrogen pressure of 638.3 psig (D146). To assure the alarm is activated before 638.3 psig is reached on a decreasing pressure signal, the positive CELOOPAL:TOTAL value could be added to the ITS value (using the approach used for the other setpoints);
however, this approach would result in a higher setpoint for the low alarm than for the high alarm and confuse the operator. To avoid this, high and low setpoints will be established by backing off the values given in the ITS by the "As-Found" value for the loop. 2 2 2 AFLOOPALTOTAL = [(AFLooPPTNA:IN) + (AFLOOPALL:OUT) ]
= [(0.57)2 + (0.77)2]12
= 0.96% span
=(0.96%)(2500)
= 24.0 psig The ITS value of 750 psig (D146) will be used to establish a setpoint for the alarm to open the valves.
SPCF(HI) = ITS - AFLOOPALTOTAL
= 750 psig - 24.00 psig
= 726 psig An additional setback of 23.5 psig will be included to allow the continued use of the existing inplant setpoint of 702.5 psig.
SP'CF(HI) = SPcF(HI) - Additional Setback
= 726 psig - 23.5 psig
= 702.5 psiq
= 1(702.5 psig)/(2500 psig)](10 Vdc)
= 2.810 Vdc As mentioned above, the 638.3 psig value will be used to establish the low setpoint.
SPCF(LO) = ITS + AFLOOPAL:TOTAL
= 638.3 psig + 24 psig
= 662.3 psig Rev. 6/95 RET: Life of Plant RESP: Nuclear Engineenng
Florida Power
........... DESIGN ANALYSISICALCULATION Crystal River Unit 3 DESA-C.FRM Page 87 of 88 DOCUMENT IDENTIFICATION NO. REVISION 1-89_0014 1 10 An additional setback of 27.7 psig will be included to allow the continued use of the existing setpoint of 690 psig.
SP'cF(LO) = SPCF(LO) + Additional Setback
= 662.3 psig + 27.7 psig
= 690 Dsicg
=[(690 psig)/(2500 psig)](10 Vdc)
= 2.760 Vdc RC-3A-PS6 = [(1740 psig)/(2500 psig)](10 Vdc) D146
= 6.960 Vdc RC-3A-PY4 = [(1675 psig)/(2500 psig)](10 Vdc) D146
= 6.700 Vdc RC-3A-PS5 = [(750 psig)/(2500 psig)](10 Vdc) D146
= 3.000 Vdc RC-3A-PS7 = [(200 psig)/(2500 psig)](10 Vdc) D146
= 0.800 Vdc
- 9. LTOP Setpoint According to Reference 11, the ITS value for LTOP initiation is 457 psig with an inplant setpoint of 442.6 psig. There is no ITS value for the LTOP alarm. As stated in D146, the LTOP alarm setpoint will be considered as a nominal value. This is consistent with the Graded Approach established by Revision 2 of Reference 25. The LTOP alarm setpoint is being classified as a Category D under the Graded Approach since it is part of a defense-in-depth strategy complimenting other alarms/indications to allow the operator to terminate a Low Temperature Over Pressurization (LTOP) event. The LTOP actuation of the PORV provides the redundant protective function. The alarm serves to provide an early indication of an impending LTO event and to transfer a recorder to high speed to record the event. Prior to the issuance of 1-97-0005 (being superseded by 1-97-0015), the previous LTOP alarm setpoint (500 psig) was set 50 psig below the previous LTOP initiation setpoint (550 psig). With the LTOP setpoint initiation change made by 1-97-0015, this 50 psig differential was retained. Therefore, the LTOP alarm setpoint was chosen as 392.6 psig.
LTOP Alarm =[(392.6 psig)/(2500 psig)](10 Vdc)
= 1.570 Vdc The LTOP ITS value will change from 457 psig to 454 psig and the inplant setpoint will change to from 442.6 psig to 441 psig (Reference 11) after implementation of the 32 EFPY LTOP analysis. Because the alarm setpoint is considered a nominal value per Category D under the Graded Approach methodology of Reference 25, itwill remain at 392.6 psig after implementing the new inplant setpoint of 441 psig. The 1.6 psig reduction in margin between the PORV actuation setpoint and the alarm is insignificant when considering operator actions are based on indicators with readability resolution no better than +/- 25 psig.
Rev. 6195 RET: Life of Plant RESP: Nuclear Engineering
Florida Power DESIGN ANALYSIS/CALCULATION CORPORATION Crystal River Unit 3 DESA-C.FRM Page 88 of 88 DOCUMENT IDENTIFICATION NO REVISION 1-89-0014 10 VII. ATTACHMENTS:
- 1. Analysis of the Model 1153 Series D Transmitters to 420°F for Three Minutes, Rosemount Report 108220A, Revision A (6 Pages)
- 2. Excerpt from Ohmite Catalog #101, 1980 (1 page)
- 3. Rosemount Inc letter to FPC (Dave Owen), dated 10/23/91 (1 page)
- 4. B&W Nuclear Technologies Letter FPC-95-027, Doc. No. 51-1234893-00, Revision 0 (6 pages)
- 5. IRAnalysis for RC Pressure Loops (3 pages)
- 6. Deleted
- 7. Vendor Qualification Package (VQP) TERM-R098-04, TAB14, Thermal Lag Through Raychem WCSF (1 page)
Rev. 6195 RET: Lifoof Plant RESP: Nuclear Engineenng
Rosemount ROSEMOUNT INC., POST OFFICE BOX 35129 / MINNEAPOLIS. MINNESOTA 56435 / TEL (812) 9i¶.-5. TWX: 10-676-3103, TELEX. 29ý-oi : NUCLEAR OPERATIONS GROUP ANALYSIS OF THE MODEL 1153 SERIES D TRANSMITTERS TO 420'F FOR THREE MINUTES RMT REPORT 108220A REVISION A
\11., )
Approved by Eng. ___, _________ Date /o/z/32.. SHARON WILDGEN - Nuclear Project Engineer Approved by Eng. L.I',, ;.(_i;, L- -~Date CHUCK ODEGAARD Nuclear Operations Manager Approved by Q.A. (- Ž ..,/*
- Date / S; JERRY ANDERSON - Quality Assuranre ¶unPrvi-,nr Approved by Q.A.
Dateer MIKE POLLACK --Quality ProJect Engineer 1-89-0014, Rev. 9, .rr-A, 2e,. Attachment 1 Page 1 of 6
ANALYglS OF TH7 '*nDr. 1153 .="tITS D T7W*rTTir'-7 TO 420 F FvR ;RFE ,T,"' R'I'r R7?ORT 109220A
"--'JI.IO'N A
- 1. 1 NCOT1 The 1153 Series 0 transmitter was testei iurina 7ualiification to the followinq steam temnerattire/oressure orofile: 350 F, p9 osiI For 10 minutes; 320 1, 60 osig for 3 hours; 240 F, 27 rsij for 21 hours; 17;.4 , 3 nsin for 30 -las. -here are numerous anolications where a r,OCA condition .iill cause hioh temoerature tr3nsionts in excess of 390 P. For these annlicltiOns it is necessArv to have a transmitter that is
- ualifiei *to onerate above 350 F for short time neriods. *he intent of this renort is to justifv raisinq the temoerature limit diuring a rOCzk cond1ition to 42.1 *or r 3 minutes, followed b1! 350 F for 7 minutes in olace of thre 11593 9eries r steam -trofile of 350 F for 10 minutes.
2.0 REPER7 4CF: 2.1 42" F Tem-erature Test Results, M!o-!el 113 3eries , I 2.2 Renort 43223Y, Rev. None. 1193 Series D 0?ualification Test Renort 1-89-0014, Rev. 9, Attachment I Page 2 of 6
..CA, ?ev. 0O (nen,]in.) .
O\f~'. 1
I 2.3 internal Thermal Response of Transmitter Housings to Steam Impingement, Rosemount models 1153 Series B and D, RMT Report 78212, Rev. A. 3.0 ANALYSIS The 1153 Series D transmitter is virtually identical to the I) the 1153 Series B transmitter. The only differences are: I use of an elev. /supp. switch vs. jumper wires, and 2) different electronics housings. The 1153 Series B is intended for BWR applications (and out-of-containment PWR applications) and has an aluminum housing. The 1153 Series D is intended for PWR applications and has a stainless steel housing. Functionally, they are identical, therefore, the 420 F temperature test performed on the 1153 Series B will provide the basis for justifying a 420 F temperature spike for the 1153 Series D. A test was setup to expose seven 1153 Series B transmitters to superheated steam at 420 F for 3 minutes. The transmitters had previously been exposed to 24.4 megarads gamma radiation and two steam temperature/pressure tests typical of a BWR. Radiation shielding for stainless steel is about twice the value for aluminum, therefore 24.4 megarads on an aluminum housing is approximately equivalent to 50 megarads on a stainless steel housing. 1-89-0014, Rev. 9, 1..C0,J Rev, 100 PAGE 2 Attachment I Page 3 of 6
During the test, thermocouple readings inside the steam chamber indicated the transmitters were exposed to temperatures in excess of 435 F for more than four minutes. The temperature transient from room temperature to 420 F took approximately 1 minute to achieve. During the test, chamber pressure was in excess of 115 psig for more than two minutes. Throughout the test all seven units continued functioning and the maximum errors were within the present LOCA specification of + 8.0% of upper range limit. Since the electronics housings are different, the temperature effect on the electronics must be determined separately. During the 1153 Series B test, the maximum average electronics board temperature was 326 F. (Ref. 2.1). Since the electronics in the two models are identical, test results will be identical if the 1153 Series D electronics board does not exceed 326 F. The time constant for the stainless steel housing. used on the 1153 Series D is approximately 4.8 minutes. (Ref. 2.3). Using this value, the electronics board temperature can be determined as follows: (Tl - TO) = (T2 - TO) (1 - exp(-t/TC)) Where: TO - Temperature of the electronics board at time = 0 (. 70 F) Tl = Temperature of the electronics board at time = t T2 Temperature of the chamber at time - t (- 420 F) t = time (- 3 minutes) TC = time constant (a 4.8 minutes) 1-89-0014, Rev. 9) *C*4A 'e*. O . PAGE 3 Attachment 1 Page 4 of 6
Tl - 70 F = (420F - 70 F) (1 - exp(-3/4.8)) Ti = 233 F The temperature of the electronics board will be approximately 233 F after the transmitter has been exposed to superheated steam at 420 F for 3 minutes. After the chamber temperature is lowered to 350 F, the electronics board temperature will continue to heat as follows: Ti - TO = (T2 - TO) (1 - exp(-t/TC)) Where: TO = Temperature of the electronics board at time = 0 (= 233 F) TI = Temperature of the electronics board at time = t T2 = Temperature of the chamber at time = t (= 350 F) t = time (= 7 minutes) TC = time constant (= 4.8 minutes) Ti - 233 F = (350 F - 233 F) (1 - exp(-7/4.8)) Ti = 323 F The temperature of the electronics board will be about 323 F after the temperature profile of 420 F for 3 minutes, followed by 350 F for 7 minutes. This is approximately the temperature achieved during the 1153 Series B test.
4.0 CONCLUSION
There are situations where an 1153 Series D transmitter could see a 420 F temperature for 3 minutes during a LOCA condition. Although the 1153 Series D has never been tested to 420 F, the 1153 Series B transmitter was exposed to 1-89-0014, Rev. 9, XcA oe*o0 Attachment 1 . PAGE .-- 4-.-- Page 5 of 6
temneratures in excess of 420 1 For at least 3 *inutes Durinq the 1153 series 3 test, the maxilum errors "were wjthj the existing + 8.0% of unner ranie limit t,)C\ snecific.tio an the raxinum temnerature of the electronics w 7 *32ý n, -rhe calculated mnaximJR tewI#erature is 323 for the 115: series -1 .electronics exnosel to 420 F for 3 Tinutes, follog..e The electronics and function oF t* by 3ýO F for 7 minutes. t4o0odels are identical, therefore by similaritv, the 1153 series V woul,! continue to function within snecifination if ex2osure to 420 F for 3 minutes ,.as irnclu.e-i in the acci-ient orof ile. 1-89-0014, Rev. 9. tC4 , 0e0. 00 Attachment I Page 6 of 6
Conformal Silicone Series 55ACRASILO Axial Lead Wirewound Resistors Features " LOw Temperature Coefficient " High Dielectric Strength " MIL-R-26 Approved Units Available " All Welded Construction " Ideal for Machine Insertion " High Reliability 1-89-0014, Rev. 9) I..CA *,/. oo Attachmnent 2 Pagel1 of 1 Specifications hA -j~ Tolerance
- 1% std. +/- .05% to +/- 10% available.
Temperature Coefficient LZZJhT
+/- 20ppml*C 10 ohms and above. *o501pm/ C 1 to 9.99 ohms.
2:90ppmI1C less than I ohm. Dielectric Withstanding Voltage 1000 VAC. (500 VAC for 1 walt size.) -- !""A 11111111917--m. ABC= = 11111 11111M.10IN 11.111 UIP AN 9.4 An Overload 10X rated wattage for 5 seconds for 5 wall size 2 59 .40111 to.3 .219 and larger. 5X rated wattage tot under S watt size. 3 59 .11-01.1111 X3 14.3 M Inductance Standard units have single layer Inductive 5 KS IIJIý-159 .131 23.4 .343 winding. Non-Inductive (Aryton Perry or limited Inductance) 7 N? 11.0-111911 11.110 32.5 .343 windings available. 10 550 IJý-n= IA43 46.9 .4411111 Core Steatite ceramic Coating Conformal silicone Ordering Data To specify resistors see below. Available only as "made to Deratings order" Items. Wattage ratings are based on 25"C Free Air Rating. For Tylpicall No. 55-11-S-IMSIX11-J h*gher ambient temperatures, use deratlng Chan. ONMITE SESUES NO. TOLERANCE mblor emuIIucMCM.T Am *.5% I WAT`TAGI 02 *.1% ~i Is L A Eu2 t 06 1 wo *.25% Ca. *,23% 020*1% 2IC Fa it1% d 0C.VC*M2I an-low flM:a&f 25 SPECIFICATIONS 2S+5 0. 21+ N = No fWl"~~~k winft. Res ISTANCf VALUE 0 21.50 4~I3 *tsO .,0 .21 , 30 DbcbW Pl. DabIW Pl. andXIOOO 0 RIO
=O25.001Mw
.2510 3>ATMV 1 q8 0 10
MeaSurement ROSEMOUNT Control Analylical Rosemount Inc. 120CI1 Technology Orve Eden Prairie, MN 55344 U.S.A Valves Tel (612) 941.5560 Telex 4310012 Fax (612) 828-3088 October 23, 1991 Florida Power Corporation P.O. Box 14042 St. Petersburg, FL 33733 Att: David Owen, M/C C21
Dear Mr. Owen:
Enclosed please find a copy of Report 78212 as requested. This report will apply to the Model 1154 and 1154 Series H transmitters as well. If you have any further questions please feel free to call me at (612) 828-3100. Sin e-b eil P. Lien Marketing Engineer Rosemount Nuclear Products enc: Report 78212 1-89-0014, Rev.3 9 =C4 Re.OO Attachment Page 1 of I
.f3W9 SSW NL/CLEARt TECHNOLOGIES 3315 Old Forest Rcac P.QL Box 1OS35 February 10, 1995 Lynchbumg VA 24506-os:.5 Telephone e04.832.3 cc FPC-95-027 relecopy. 804-832366,- Kr. W.W. Nisula, C21 Manager, Nuclear Engineer Project. Florida Power Corporation 3201 34th Street South Post Office Box 14042 St. Petersburg, FL 33733 Attention: Mr. S.K. Balliet
Subject:
. Crystal River Unit 3 FPC Contract NPMO10AD, WA #1, Small Account Request #24 Task 616 - Reactor Coolant Pressure ESAS Actuation Setpoints Gentlemen: Attached is BWNT Document 51-1234893-00 which is the deliverable for the subject contract. Should you have any questions or comments, please call me. Very truly yours, Customer Service Manager Plant Engineering Projects RLB/skg Attachment c: P.E. Couvillon R.J. Finnin G.W. Christman B.J. Shepherd 1-89-0014, Rev. 9 I MCA, "eq. o3 Attachment 4 Page 1 of 6
8WMT-20440-8 ill R I 91TECHNOLOGIES E&WNUCLE4R ENGINEERING INFORMATION RECORD K Document Identifier 51-1234893-00 Title Low & Low-Low Pressure ESAS Setpoints PREPARED BY: REVIEWED BY: Name J.C. seals, __
--
Name R.H. Ellison Signature76/yf Date Signature Date -__?/1/__ Technical Manager Statement: Initials 9f/L Reviewer is Independent. Remarks: The NRC is asking the Florida Power Corporation (FPC) questions relating to the low and low-low reactor coolant system (RCS) pressure setpoints of the engineered safeguards actuation system (ESAS). In particular, the current technical specification setpoint may be violated when the setting tolerance is added to the calculated instrument uncertainty and drift. FPC has asked BWNT to clarify the bases that should be applied to the uncertainty calculation. In response, the following discussion is presented herein. 1-89-0014, Rev. 9, i-C., Rev.Oo Attachment 4 Page 2 of 6 UdIT PIIORJETARY-1: THIS DOM*MT CONTAINS InFCNATIW Pa rETARY TO so V cLEAR TECHNOLOGIES (DWT) AND SMALL ONLY BEUSED OR DISCLOSED TO OTHERS AS AGREED UPON IN WRITING BYBfNT. I
PROGRESS ENERGY FLORIDA, INC. CRYSTAL RIVER UNIT 3 DOCKET NUMBER 50-302 /LICENSE NUMBER DPR-72 LICENSE AMENDMENT REQUEST #309, REVISION 0 ATTACHMENT 8 SAMPLE INSTRUMENTATION SETPOINT CALCULATION
8WPNT-2C44o~a (I1I i I 3 I& WNUCLEAR W W TECHNOLOGIES ENGINEERING INFORMATION RECORD Document Identifier 51-1234893-00 Title Low & Low-Low Pressure ESAS Setpoints PREPARED BY: REVIEWED BY: Name J.C. seals, Name R.H. Ellison P Signature Date Signature Date ____- I / Technical Manager Statement: Initials Reviewer is Independent. Remarks: The NRC is asking the Florida Power Corporation (FPC) questions relating to the low and low-low reactor coolant system (RCS) pressure setpoints of the engineered safeguards actuation system (ESAS). In particular, the current technical specification setpoint may be violated when the setting tolerance is added to the calculated instrument uncertainty and drift. FPC has asked BWNT to clarify the bases that should be applied
'to the uncertainty calculation. In response, the following discussion is presented herein.
cA, iev.00 1-89-0014, Rev. 9, -. Attachment 4 Page 2 of 6
1-89-0014, Rev. 9JCAi Rv. 00 Attachment 4 Page 3 of 6 51-1234893-00
Background
The NRC is asking the Florida Power Corporation (FPC) questions relating to the low and low-low reactor coolant system (RCS) pressure setpoints of the engineered safeguards actuation system (ESAS). In particular, the current technical specification setpoint may be violated when the setting tolerance is added to the calculated instrument uncertainty and drift. FPC has asked BWNT to clarify the bases that should be applied to the uncertainty calculation. In response, the following discussion is presented: The ESAS monitors the reactor coolant (RC) and reactor building (RB) pressures and will initiate emergency core coolant system (ECCS) injection on indications of an accident. The design basis accident that determines the low and low-low pressure setpoints is the small break loss-of-coolant accident (LOCA). For the Crystal River-3 plant, the in-plant low pressure setpoint is 1540 psig and the in-plant low-low pressure setpoint is 540 psig. The allowed plant technical specifications values are 1500 and 500 psig, respectively for the low and low-low pressure setpoints (Ref.1). The primary function of the ESAS low pressure setpoint is to initiate the high pressure injection (HPI) pumps, isolate the RB, and isolate normal makeup and letdown flows. The primary function of the low-low pressure setpoint is to initiate the low pressure injection (LPI) or decay heat pumps. Once actuated, these setpoints perform no other safety functions. Therefore, any environmental conditions used in determining the setpoint uncertainty should only be based on the period of operability, or the time from the beginning of the transient to the time of actuation. In previous calculations, FPC has determined that the instrument uncertainty for the low pressure ESAS setpoint is +39.25 psi. The setting tolerance is +/-12.5 psi. In the worst case, then, the total instrument error could be +51.75 psi and could result in an action value (1488.25 psig) that is less than the allowed plant technical specification setpoint (1500 psig). It should be stated that although the plant technical setpoint may be violated following these assumptions, plant safety is not compromised. In order to justify the current in-plant setpoint, the NRC-approved B&W approach for determining technical specification and in-plant setpoints should be understood. The values modeled in the plant design bases accident analyses were chosen to protect a safety limit (e.g. 110 percent of the design pressure or limits on peak clad temperature). The plant technical specification limit is determined based on the specific instrument string errors corresponding to the limiting environmental conditions for the period of operability for a given setpoint function. The actual in-plant setpoint should be set conservatively to the technical Page 2 of 5
51-1234893-00 specification value by accounting for instrument drift, repeatability error, and setting tolerance. In 1982, a preliminary safety concern was written (PSC 25-82). The PSC related to possible delayed ESAS actuation. B&W issued a site instruction (Ref. 2) for determining the plant low pressure ESAS setpoint for the B&W-design plants operating with a rated core power level of 2568 MWt or less. The guidance was based on the small break LOCA design basis accident analysis and determined that the plant setpoint should be 1600 psig or 1480 psig plus the plant specific total instrument uncertainty, whichever is greater. The concern was transmitted to the individual utilities for their evaluation. The affected utilities generally chose to set the plant setpoints based on 1480 psig plus plant specific instrument uncertainty rather than following the B&W guidance to use 1600 psig. B&W agreed with this position (Ref. 3). This is acceptable so long as actuation of the low pressure ESAS setpoint can be guaranteed to occur at an RCS pressure greater than 1480 psig as measured at the hot leg pressure taps. For the Crystal River-3 plant, the minimum allowed plant setpoint, or action value, should be 1531.75 psig based on the existing calculated instrument error and setting tolerance to ensure that the safety limits is preserved. Since the actual plant setpoint of 1540 psig is greater than the minimum allowed plant setpoint from the design bases accident analyses, plant safety was not compromised. Low RCS Pressure ESAS Setpoint For the low pressure ESAS setpoint, the limiting design basis accident is a small break LOCA on the order of 0.01 ft 2 . For the break size, the RCS will depressurize to the analysis actuation setpoint within approximately 115 seconds (Ref. 4). The expected integrated dose at 115 seconds is 250 Rad (Ref. 5). BWNT does not have a specific calculation for RB building pressure and temperature corresponding to a 0.01 ft 2 break, but a calculation for a 0.04 ft2 is available. The results for the 0.04 ft 2 case would be conservative because of the higher mass and energy release. At 115 seconds for the 0.04 ft 2 break, the expected building temperature is 180OF (Ref. 6). The instrument string error for the low RCS pressure ESAS setpoint should be based on these environmental conditions. 1-89-0014, Rev. 9, XCA, ev.O0 Attachment 4 Page4of6 Page 3 of 5
51-1234893-00 Low-Low RCS Pressure ESAS Setpoint The low-low RCS pressure setpoint was based on a review of both small and large break LOCAs. No specific calculations have been performed to support the low-low RCS pressure setpoint. The justification of the setpoint was based on engineering evaluations of the existing design basis accident analyses (Ref. 7). For small break LOCA, the key factors are (1) does the event evolve to RCS conditions that would challenge the low-low setpoint, and (2) if the setpoint is reached, how long will it take the RCS pressure to decrease to below the shut-off head of the LPI (or decay heat) pumps? For large break LOCAs, the key factor is to verify that the initiation of LPI flow to the RCS must occur no later than what was considered in the accident analysis. For the limiting size small break LOCA of approximately 0.07 ft 2, relative to peak clad temperature concerns, immediate actuation of the low-low setpoint is not required. The RCS pressure will decrease to near 600 psia. HPI and the core flood tanks are adequate to maintain a two-phase mixture level above the top of the active fuel region. Larger small break LOCAs will result in a depressurization of the RCS to below the low-low pressure setpoint, but these sizes are not limiting. Due to the steep depressurization rate, flashing of the saturated coolant will cause the mixture to swell and the core will remain covered. For the largest small break LOCA, 0.5 ft 2 , the 500 psia setpoint will be reached at approximately 125 seconds. The RCS depressurizes to the shut-off head of the pumps by about 200 seconds (Ref. 8). Since the LPI pump start time is on the order of a few seconds (Ref. 8), the small break LOCAs will not be the limiting breaks to be considered when determining the low-low RCS pressure ESAS setpoint. For large break LOCAs, it must be shown that the LPI injection time credited in the existing calculations is preserved with the low-low RCS pressure ESAS setpoint. The RCS pressure will decrease to 500 psia by approximately 18 seconds and to about 200 psia by 21 seconds into the large break LOCA transient. The RB pressure will be less than 60 psia during this time. This is conservative in that it bounds the maximum calculated RB pressure. The environment will be saturated resulting in a temperature of less than 293 0 F. From a dose perspective, Reference 5 can still be applied. The title states that the integrated dose is for small break LOCAs, but the method applied to the calculation is independent of the system thermal-hydraulic response. The integrated dose was based on an instantaneous release of 100 percent of the fuel gap and coolant activities. Therefore, the same curve can be applied to determine the integrated dose for the large break LOCA response. At approximately 20 seconds into the event, the integrated dose is 50 rads (Ref. 5). The instrument string error for the low-low RCS 1-89-0014, Rev. 9) MCA Pe 0O.. Attachment4 Page 4 of 5 Page 5 of 6
51-1234893-00 pressure ESAS setpoint should be based on these environmental conditions. Conclusion A review of existing documentation has been performed to determine the dose and environmental conditions that should be applied to the string error calculations for the WSAS low and low-low RCS pressure setpoints. The period of operability for these setpoints was considered in establishing the conditions. For the low pressure setpoint, an integrated dose of 250 Rad and a temperature of 180OF should be considered for a period of operability of 115 seconds. For the low-low pressure setpoint, an integrated dose of 50 Rad and a temperature of 2930F should be considered for a period of operability of 20 seconds. As long as the instrument strings associated with these setpoints can be qualified to these conditions, then no additional dose contribution needs to be considered in the string error calculation. References
- 1. Crystal River-Unit 3 Plant Technical Specifications, Table 3.3.5-1, Amendment 149.
- 2. B&W Document 51-1146255-04, Site Instruction for Oconee 1, 2, 3, ANO-l, CR-3.
- 3. B&W Document 51-1176207-00, HPI Setpoint Description.
- 4. Small Break Loss-of-Coolant Accident Analysis for B&W 177FA Lowered Loop Plants in Response to NUREG-0737, Item II.K.3.31, BAW-1976A, Babcock and Wilcox, Lynchburg, Virginia, May 1989.
- 5. B&W Document 32-1125564-00, Small LOCA Containment Integrated Doses for 177 Plants.
- 6. B&W Document 86-1103119-01, Containment Response to a Small Break LOCA.
- 7. B&W Document 51-1172948-00, Reduction in LPI Start Signal.
- 8. ECCS Analysis of B&W's 177-FA Lowered-Loop NSS, BAW-10103A.
Rev. 3, Babcock and Wilcox, Lynchburg, Virginia, July 1977. 1-89-0014, Rev. 9, iC 3zev. 00 Attachment 4 Page 6 of 6 Page 5 of5 '
PROGRESS ENERGY FLORIDA, INC. CRYSTAL RIVER UNIT 3 DOCKET NUMBER 50-302/LICENSE NUMBER DPR-72 LICENSE AMENDMENT REQUEST #309, REVISION 0 ATTACHMENT 9 SUPPLEMENTAL ENVIRONMENTAL REPORT
Supplemental Environmental Report Extended Power Uprate Rev. 5 Crystal River Unit 3 Nuclear Power Plant Progress Energy Florida Docket No. 50-302 License No. DPR-72 April 2011
Crystal River Unit 3 Extended Power Uprate TABLE OF CONTENTS Section Page 1.0 EXECUTIVE
SUMMARY
........................................................................................ 1-1 2.0 INTRO DU CTIO N ...................................................................................................... 2-1 3.0 PURPOSE AND NEED ............................................................................................. 3-1 3.1 T H E PRO JE C T .................................................................................................... 3-1 3.2 N EED FO R A CT IO N .......................................................................................... 3-1 3.3 CO ST - BEN EFIT AN A LY SIS .......................................................................... 3-2 4.0 PROJECT ALTERNATIVES ................................................................................... 4-1 4.1 PRO PO SED A C T IO N ......................................................................................... 4-1 4.1.1 EPU ALTERNATIVE - HELPER COOLING TOWER OPTION ......... 4-1 4.1.2 EPU ALTERNATIVE - LOAD REDUCTION MANAGEMENT O PT IO N ................................................................................................... 4 -2 4.2 NO ACTION ALTERNATIVE ............................................................... 4-2 5.0 OVERVIEW OF OPERATIONAL AND EQUIPMENT CHANGES .................. 5-1 6.0 NON-RADIOLOGICAL ENVIROMENTAL IMPACTS ..................................... 6-1 6.1 TERRESTRIAL RESOURCES .......................................................................... 6-1 6.1.1 L A N D U S E .............................................................................................. 6-1 6.1.1.1 EPU ALTERNATIVE - HELPER COOLING TOWER O P T IO N ........................................................................................ 6-3 6.1.1.2 EPU ALTERNATIVE - LOAD REDUCTION MANAGEMENT OPTION .......................................................... 6-5 6.1.1.3 NO ACTION ALTERNATIVE .................................................... 6-5 6.1.2 TRAN SM ISSION FAC ILITIES .............................................................. 6-5 6.1.3 SOCIOECONOMIC CONSIDERATIONS ............................................. 6-6 6.1.3.1 CURRENT SOCIOECONOMIC STATUS .................................. 6-6 6.1.3.2 SOCIOECONOMIC IMPACTS ................................................... 6-6 6.1.3.2.1 EPU ALTERNATIVE - HELPER COOLING TOWER O PT IO N ................................................................................. 6-6 6.1.3.2.2 EPU ALTERNATIVE - LOAD REDUCTION MANAGEMENT OPTION ................................................... 6-8 6.1.3.2.3 NO ACTION ALTERNATIVE ............................................. 6-9 6.1.4 ENVIRONMENTAL JUSTICE .............................................................. 6-9 6.1.4.1 MINORITY AND LOW-INCOME POPULATIONS .................. 6-9 6.1.4.2 ENVIRONMENTAL JUSTICE IMPACTS ................................. 6-10 ii April 2011 Contents Table of Contents ii April 2011
Crystal River Unit 3 Extended Power Uprate 6.1.4.2.1 EPU ALTERNATIVE - HELPER COOLING TOWER O P T IO N ................................................................................. 6-10 6.1.4.2.2 EPU ALTERNATIVE - LOAD REDUCTION MANAGEMENT OPTION ................................................... 6-11 6.1.4.2.3 NO ACTION ALTERNATIVE ............................................. 6-11 6.1.5 MISCELLANEOUS WASTES ............................................................... 6-11 6.1.6 AIR QUALITY AND VISIBILITY ........................................................ 6-11 6.1.6.1 B A C K G R O UN D ........................................................................... 6-11 6.1.6.2 AIR QUALITY AND VISIBILITY IMPACTS ........................... 6-13 6.1.6.2.1 EPU ALTERNATIVE - HELPER COOLING TOWER O PT IO N ................................................................................. 6-13 6.1.6.2.2 EPU ALTERNATIVE - LOAD REDUCTION MANAGEMENT OPTION ................................................... 6-14 6.1.6.2.3 NO ACTION ALTERNATIVE ............................................. 6-14 6 .1.7 N O IS E ...................................................................................................... 6-14 6.1.7.1 EPU ALTERNATIVE - HELPER COOLING TOWER O P T IO N ........................................................................................ 6-14 6.1.7.2 EPU ALTERNATIVE - LOAD REDUCTION MANAGEMENT OPTION .......................................................... 6-15 6.1.7.3 NO ACTION ALTERNATIVE .................................................... 6-15 6.1.8 TER REST RIA L B IO TA .......................................................................... 6-15 6.1.8.1 EPU ALTERNATIVE - HELPER COOLING TOWER O P T IO N ........................................................................................ 6-21 6.1.8.2 EPU ALTERNATIVE - LOAD REDUCTION MANAGEMENT OPTION .......................................................... 6-22 6.1.8.3 NO ACTION ALTERNATIVE ................................................... 6-22 6.2 HYDROLOGY AND AQUATIC RESOURCES ............................................... 6-22 6.2.1 COOLING WATER SYSTEM ................................................................ 6-22 6.2.2 D ISC HA R G E S ........................................................................................ 6-23 6.2.3 ENTRAINMENT AND IMPINGEMENT .............................................. 6-24 6.2.4 THERMAL DISCHARGE EFFECTS ..................................................... 6-24 6.2.5 A Q UA T IC B IO T A .................................................................................. 6-24 6.2.5.1 EPU ALTERNATIVE - HELPER COOLING TOWER O PT IO N ........................................................................................ 6-30 6.2.5.2 EPU ALTERNATIVE - LOAD REDUCTION MANAGEMENT OPTION .......................................................... 6-30 6.2.5.3 NO ACTION ALTERNATIVE .................................................... 6-31 7.0 RADIOLOGICAL ENVIRONMENTAL IMPACTS ............................................. 7-1 7.1 RADIOACTIVE WASTE STREAMS ................................................................ 7-1 iii April 2011 Table of Contents Contents iii April12011
Crystal River Unit 3 Extended Power Uprate 7.1.1 EPU ALTERNATIVE - HELPER COOLING TOWER AND LOAD RED UCTION OPTION S ......................................................................... 7-I 7.1.1.1 SO LID W A ST E ........................................................................... . 7-1 7.1.1.2 LIQ U ID W A ST E .......................................................................... 7-2 7.1.1.3 G A SEO US W A STE ...................................................................... 7-3 7.1.2 NO ACTION ALTERNATIVE ............................................................... 7-4 7.2 RADIATION LEVELS AND OFFSITE DOSE ................................................. 7-4 7.2.1 EPU ALTERNATIVE - HELPER COOLING TOWER AND LOAD RED UCTION O PTION S ......................................................................... 7-4 7.2.1 .1 OPERATING AND SHUTDOWN IN-PLANT LEVELS ........... 7-4 7.2.1.2 OFFSITE DOSES AT EPU CONDITIONS ................................. 7-6 7.2.2 NO ACTION ALTERNATIVE ............................................................... 7-6 7.3 RADIOLOGICAL CONSEQUENCES OF ACCIDENTS ................................. 7-7 7.3.1.1 CLASS I -TRIVIAL INCIDENTS ............................................. 7-9 7.3.1.2 CLASS 2 - SMALL RELEASES OUTSIDE CONTAINMENT. 7-10 7.3.1.3 CLASS 3 - RADWASTE SYSTEM FAILURES ........................ 7-10 7.3.1.3.1 CLASS 3.1 -EQUIPMENT LEAKAGE OR M A LFUN C T IO N .................................................................. 7-10 7.3.1.3.2 CLASS 3.2 - RELEASE OF LIQUID WASTE STORAGE C O N T EN T S ........................................................................... 7-10 7.3.1.4 CLASS 4 - FISSION PRODUCTS TO PRIMARY SYSTEM .... 7-10 7.3.1.5 CLASS 5 - FISSION PRODUCTS TO PRIMARY AND SECONDA RY SYSTEM S ............................................................ 7-10 7.3.1.5.1 FUEL CLADDING DEFECTS AND STEAM GEN ERATO R LEA KS ........................................................ 7-11 7.3.1.5.2 OFF-DESIGN TRANSIENTS THAT INDUCE FUEL FAILURE ABOVE THOSE EXPECTED WITH STEAM GEN ERATOR LEA K ........................................................... 7-11 7.3.1.5.3 STEAM GENERATOR TUBE RUPTURE .......................... 7-11 7.3.1.6 CLASS 6 - REFUELING ACCIDENTS ...................................... 7-12 7.3.1.6.1 FUEL BUN D LE DRO P ......................................................... 7-13 7.3.1.6.2 HEAVY OBJECT DROP ONTO FUEL IN CORE .............. 7-13 7.3.1.7 CLASS 7 - ACCIDENTS TO SPENT FUEL OUTSIDE C O N T A IN M EN T .......................................................................... 7-13 7.3.1.8 CLASS 8- ACCIDENT INITIATION EVENTS CONSIDERED IN THE DESIGN BASIS EVALUATION IN THE SAFETY A N A LY SIS R EPO RT ................................................................... 7-14 7.3.1.8.1 LOSS OF COOLANT ACCIDENT INSIDE CO N TA IN M EN T .................................................................. 7-14 7.3.1.8.2 CONTROL ROD EJECTION ACCIDENT .......................... 7-14 Table of Contents iv April 2011
Crystal River Unit 3) Extended Power Uprate 7.3.1.8.3 STEAMLINE BREAK (OUTSIDE CONTAINMENT) ....... 7-15 7.3.1.9 CLASS 9 -SEVERE ACCIDENTS ............................................. 7-15 7.3.1.10 OTHER ACCID ENTS .................................................................. 7-15 7.3.2 NO ACTION ALTERNATIVE ............................................................... 7-16 7.4 OTHER POTENTIAL ENVIRONMENTAL ACCIDENTS .............................. 7-16 7.4.1 EPU ALTERNATIVE - HELPER COOLING TOWER AND LOAD RED U CTIO N O PTIO N S ......................................................................... 7-16 7.4.2 NO ACTION ALTERNATIVE ............................................................... 7-16 8.0 ENVIRONMENTAL EFFECTS OF URANIUM FUEL CYCLE ACTIVITIES AND RADIOACTIVE WASTE TRANSPORT ...................................................... 8-1 8.1 EPU ALTERNATIVE - HELPER COOLING TOWER AND LOAD R ED U CTIO N O PTIO N S .................................................................................... 8-1 8.2 NO ACTION A LTERN ATIV E ........................................................................... 8-2 9.0 EFFECTS OF DECOMMISSIONING .................................................................... 9-1 9.1 EPU ALTERNATIVE - HELPER COOLING TOWER AND LOAD R ED U CT IO N O PTION S .................................................................................... 9-1 9.2 NO ACTION A LTERN ATIVE ........................................................................... 9-2 10.0 REFERE N CES ........................................................................................................... 10-1 Table of Contents V April 2011
Crystal River Unit 3 Extended Power Uprate Crystal River Unit 3 Extended Power Uprate LIST OF TABLES Tables Page Table 5-1 Major Equipment Modifications to Support CR-3 EPU ................................... 5-1 Table 6-1 CR-3 Tax Inform ation, 2005-2008 ................................................................... 6-6 Table 6-2. Endangered and Threatened Species in Citrus County and Counties Crossed by C R -3 Transm ission Lines ............................................................................ 6-17 Table 7-1. CR-3 Low-Level Radioactive Waste Generation by Waste Type, 2004 - 2008. 7-2 Table 7-2. Liquid Effluent Releases From CR-3, 2004 - 2008 ......................................... 7-3 Table 7-3. Gaseous Effluent Releases From CR-3, 2004 - 2008 ....................................... 7-3 Table 7-4. Collective Occupational Radiation Dose at CR-3, 2002 - 2007 ...................... 7-5 Table 7-5. Historic and Projected EPU Offsite Doses Compared to 10 CFR 50, A ppendix I A LA RA G uidelines ....................................................................... 7-6 T able 7-6. A ccident Dose C riteria ...................................................................................... 7-9 LIST OF FIGURES Figures Page Figure 6-1 Developed Portion of Crystal River Site .......................................................... 6-2 Figure 6-2 Land Use Changes Associated with SGR and EPU .......................................... 6-4 vi April 2011 of Contents Table of vi April 2011
Crystal River Unit -3) Extended Power Uprate ACRONYM LIST AADT annual average daily traffic AEC U.S. Atomic Energy Commission ALARA As Low As Reasonably Achievable AST alternative source term BMP Best Management Practice BWR boiling water reactor CEQ Council on Environmental Quality Ci curie cfs cubic feet per second CR-3 Crystal River Unit 3 Nuclear Power Plant CRE Control Rod Ejection CREC Crystal River Energy Complex CWIS Cooling Water Intake Structure DAW dry active waste DBA design basis accident EAB Exclusion Area Boundary EC Engineering Change ECCS emergency core cooling systems EMF electromagnetic field EPU Extended Power Uprate OF degrees Fahrenheit FDEP Florida Department of Environmental Protection FES Final Environmental Statement FHA Fuel Handling Accident FNAI Florida Natural Areas Inventory FOCC Florida Oceanographic Coastal Center Acronym List vii April 2011
Crystal River Unit 3 Extended Power Uprate ACRONYM LIST (CONT.) FPC Florida Power Corporation FPSC Florida Public Service Commission FSAR Final Safety Analysis Report GElS Generic Environmental Impact Statement GMFMC Gulf of Mexico Fisheries Management Council gpm gallon per minute gpd gallon per day GSRT Gulf Sturgeon Recovery/Management Task Team HCTS Helper Cooling Tower South ISFSI Independent Spent Fuel Storage Installation LLRW low-level radioactive waste LOCA loss of coolant accident LOS Level of Service LPZ Low Population Zone LWDS liquid waste disposal system mCi millicurie MGD million gallons per day mg/L milligram per liter mrad millirad In remn millirem MWd/MTU megawatt-day/metric ton of uranium MWe megawatts-electrical MWt megawatts-thermal NEI Nuclear Energy Institute NEPA National Environmental Policy Act NMFS National Marine Fisheries Service Acronym List viii April 2011
Crystal River Unit 3 Extended Power Uprate ACRONYM LIST (CONT.) NPDES National Pollutant Discharge Elimination System NRC U.S. Nuclear Regulatory Commission ODCM Offsite Dose Calculation Manual PEF Progress Energy Florida POD point of discharge POR Prudent Operating Reserve ppt parts per thousand PWR pressurized water reactor RCS Reactor Coolant System RF Refueling Outage SCA Site Certification Application SFP Spent Fuel Pool SG steam generator SGR steam generator replacement SGTR steam generator tube rupture SWEC Stone and Webster Engineering Corporation TDS total dissolved solids TEDE total effective dose equivalent TID Technical Information Document TRO total residual oxidant USFWS United States Fish and Wildlife Service USGS U.S. Geological Survey WGDT Waste Gas Decay Tank ix April 2011 Acronymn List Acronym List ix April 2011
Crystal River Unit 3 Extended Power Uprate 1.0 EXECUTIVE
SUMMARY
This Supplemental Environmental Report contains Progress Energy Florida's (PEF's) assessment of the environmental impacts of the proposed Crystal River Unit 3 Nuclear Power Plant (CR-3) extended power uprate (EPU) from 2,609 megawatts-thermal (MWt) to 3,014 MWt. The intent is to provide sufficient information for the U.S. Nuclear Regulatory Commission (NRC) to evaluate the environmental impact of the power uprate in accordance with the requirements of 10 CFR 51. The environmental impacts of the EPU are described and where appropriate compared to those previously identified in the FinalEnvironmental Statement (FES) related to the proposed Cristal River Unit 3 (AEC 1973) and in the NRC evaluations of two previous uprates at CR-3, a 0.9 percent stretch uprate approved by the NRC in December 2002 and a 1.6 percent measurement uncertainty recapture uprate approved by the NRC in December 2007. No National Environmental Policy Act (NEPA) documentation was prepared by the NRC for the two small uprates because environmental impacts were negligible. The comparisons show that the conclusions of the FES remain valid for operation at 3,014 MWt. The CR-3 EPU would be implemented in two phases and would include significant hardware changes. Phase One occurred during a scheduled refueling outage in the fall of 2009 and coincided with the replacement of the plant's steam generators. Phase One improved the efficiency of the secondary side of the plant and produced a small increase in electrical output with no change in rated thermal power. The second phase, scheduled to occur during a refueling outage in 2013, would produce an increase of 405 MWt and bring the total increase in plant output associated with the EPU project to 168 megawatts-electrical (MWe). Increasing the plant's rated thermal power level will increase the amount of steam generated and the temperature of the circulating water. Therefore, PEF is considering two possible strategies for mitigating the increased thermal output from the EPU: a new mechanical-draft (helper) cooling tower and load reduction management. The potential environmental impacts associated with these two strategies, or options, are evaluated and compared in the pages that follow. Much of the work associated with the uprate would take place inside of existing buildings and previously-disturbed areas; therefore, construction impacts to cultural resources and terrestrial wildlife (including special-status species) are expected to be very small. Potential impacts to soils and down-gradient wetlands from construction of the new cooling tower under the Helper Cooling Tower Option would be mitigated by best management practices (BMPs). Impacts to marine life would be small regardless of which cooling option is selected. There would be no increase in cooling water withdrawal rate, thus no change in current levels of impingement and entrainment. There would be no increase in discharge temperatures, because of the mitigation measures, thus no EPU-related thermal impacts to aquatic biota. Radioactive releases and 1-1 April 2011 Executive Summary Surninary 1-1 April 2011
Crystal River Unit 3 Extended Power Uprate resulting offsite doses are expected to increase in approximate proportion to the increase in power level. Normal operational radiation exposures to plant workers are expected to increase by no more than the percentage increase of the EPU. All occupational radiation doses would continue to be within applicable regulatory standards. PEF concludes that the environmental impacts of operation at 3,014 MWt are either bounded by impacts described in earlier assessments or within regulatory limits. As a consequence, PEF believes that the EPU would not significantly (as defined in 40 CFR 1508.27) affect human health or the environment. 1-2 April 2011 Summary Executive Surnmary 1-2 April 2011
Crystal River Unit 3 Extended Power Uprate
2.0 INTRODUCTION
CR-3 is located in northwestern Citrus County, Florida, on Crystal Bay, an embayment of the Gulf of Mexico. CR-3 is part of the larger Crystal River Energy Complex (CREC), which includes the single nuclear unit and four fossil-fueled units, Crystal River Units 1, 2, 4, and 5. PEF owns the 4,738 acre site that contains the CREC. The CR-3 powerblock is located in the developed central portion of the CREC and comprises approximately 27 acres. Fossil-fired Units I and 2 and CR-3 employ once-through cooling, withdrawing from and discharging to the Gulf of Mexico. Units 4 and 5 are closed-cycle units that withdraw water for cooling tower makeup from the discharge canal for Units 1, 2, and 3. During certain times of the year (May I through October 31), a portion of the heated discharge from Units 1, 2, and 3 is routed through helper cooling towers designed to lower discharge temperatures. The helper cooling towers are operated as necessary to ensure that the discharge temperature does not exceed 96.5°F (as a three-hour rolling average) at the point of discharge (POD) to the Gulf of Mexico. CR-3 is a single-unit nuclear plant with a conventional domed concrete containment building. The plant includes a pressurized light-water reactor nuclear steam supply system supplied by Babcock & Wilcox and turbine-generator designed and manufactured by the Westinghouse Electric Company (AEC 1973; Progress Energy 2008; Scientech 2007). PEF is committed to operating CR-3 in an environmentally responsible manner. Plant activities including design, construction, maintenance, and operations are conducted in a manner so as to protect the environment and preserve natural resources. PEF operates in compliance with state and federal environmental regulations, while providing safe, reliable, and economical electrical service to its customers. In keeping with this commitment to environmental stewardship and in accordance with regulatory requirements, PEF has conducted a comprehensive environmental evaluation of the proposed EPU, which would increase CR-3's licensed core thermal power level 15.5 percent, from 2,609 MWt to 3,014 MWt. This increase in thermal output would produce a near-proportional increase in the plant's electrical output, from 912 MWe to 1,080 MWe. The proposed uprate would also replace higher cost generation in PEF's system, yielding substantial fuel savings to PEF's customers. Customers would receive additional generation at a net savings to them. The proposed uprate would advance the conservation goals of Florida by replacing some fossil fiuel generation and emissions with relatively cleaner nuclear fuel generation (FPSC 2010). This environmental evaluation is provided pursuant to 10 CFR 51.41 ("Requirement to Submit Environmental Information") and is intended to support the NRC environmental review of the proposed uprate. The uprate will require the issuance of an operating license amendment for Introduction 2-1 April 2011
Crystal River Unit 3 Extended Power Uprate CR-3. The regulation (10 CFR 51.41) requires that applications to the NRC be in compliance with Section 102(2) of NEPA and consistent with the procedural provisions of NEPA (40 CFR 1500-1508). There are no NRC regulatory requirements or guidance documents specific to preparation of environmental reports for EPUs. Florida Power Corporation (FPC) applied to the U.S. Atomic Energy Commission (AEC), the NRC's predecessor agency, for a license to build and operate a nuclear power plant at the Crystal River site in 1967. The AEC issued a construction permit for the Crystal River plant on September 25, 1968 (AEC 1973). FPC submitted an Environmental Report in February 1971, supplemental information in November 1971, and a revised Environmental Report, Operating License Stage, in January 1972. In May 1973, the AEC prepared the Final Environmental Statement related to the proposed Crystal River Unit 3 (AEC 1973). The AEC concluded that the actions called for under NEPA and 10 CFR Part 50 were the continuation of the construction permit and issuance of an operating license for the facility (AEC 1973). The plant's operating license was issued on December 3, 1976 and it began commercial operation on March 13, 1977 (Scientech 2007). CR-3 was initially licensed to operate at a maximum power level of 2,452 MWt. In 1981, the NRC approved operation of CR-3 at tip to 2,544 MWt. Progress Energy was created in 2000, when Carolina Power & Light Company (CP&L) acquired Florida Progress, the parent company of Florida Power Corporation. CR-3 has ten licensees and ten owners, but Florida Power Corporation (doing business as Progress Energy Florida) remains the primary licensee and owns 91.8 percent of the plant. In 2002, a 0.9 percent stretch uprate was implemented, increasing CR-3's licensed thermal power level from 2,544 to 2,568 MWt. In 2007, a 1.6 percent measurement uncertainty recapture uprate was implemented, increasing the plant's licensed thermal power level from 2,568 to 2,609 MWt. No NEPA documentation was prepared by the NRC for the two small uprates because environmental impacts were judged to be negligible. This Supplemental Environmental Report is intended to provide sufficient detail on both the radiological and non-radiological environmental impacts of the proposed EPU to allow NRC to make an informed decision regarding the proposed action. It does not reassess the current environmental licensing basis or re-evaluate the environmental impacts of operating the unit at the current power level of 2,609 MWt. 2-2 April 2011 Introduction 2-2 April 2011
Crystal River Unit 3 Extended Power Uprate 3.0 PURPOSE AND NEED 3.1 THE PROJECT PEF proposes to increase the licensed core thermal power level of CR-3 from 2,609 MWt to 3,014 MWt, an increase of approximately 15.5 percent. In doing so, PEF would add 168 MWe to the plant's generating capacity. The increased generating capacity would result from improving the performance of the steam turbine and by increasing the size of the refueling batches to provide the necessary energy to support operation at the higher power levels. This increase in generating capacity would ensure the continued delivery of safe, reliable, and cost-effective service to PEF's customers. Increasing the plant's rated thermal power level would increase the amount of steam generated and the temperature of the circulating water. Therefore, PEF is considering two possible strategies for mitigating the increased thermal output from the EPU: (1) a new mechanical-draft (helper) cooling tower or (2) load reduction management. The potential environmental impacts associated with each of these two strategies, or options, are evaluated and compared in the pages that follow. 3.2 NEED FOR ACTION The proposed CR-3 EPU is needed because it would supply the benefits of additional, reliable, baseload power at a net savings to PEF customers. The proposed CR-3 EPU would displace higher cost fossil fuel and purchased power generation with low cost nuclear generation, resulting in substantial fuel savings that provide a net benefit to customers. Nuclear energy is the lowest cost energy source available on PEF's system; therefore, the production of additional electricity from the CR-3 EPU would result in the lowest possible generation fuel cost. The CR-3 uprate will increase the plant's gross power output by 168 MWe, the equivalent of the electricity used by approximately 103,000 homes. In its Petition for Determination of Need, PEF estimated that the CR-3 EPU would save customers more than $2.6 billion in gross fuel costs through 2036, equivalent to a net present value to retail customers after costs of approximately
$327 million (PEF 2006a).
The displacement of fossil fuel and purchased power generation resulting from the CR-3 EPU will result in increased fuel diversity and supply reliability, consistent with the goals of the (1980) Florida Energy Efficiency and Conservation Act and (2006) Florida Energy Plan. It will reduce reliance on fossil fuels, resulting in lower air emissions while providing a stable source of additional baseload power. The Florida Public Service Commission (FPSC) has the authority to ensure the delivery of adequate, reliable, reasonably-priced electricity to consumers. The FPSC has specific authority under Chapter 366, Florida Statutes, to regulate the rates and service of Florida's investor-owned electric utilities. The FPSC has determined that the CR-3 power uprate is an economical option 3-1 April 2011 Proposed Action and Need and Need 3-1 April 2011
Crystal River Unit 3 Extended Power Uprate to add generating capacity and power output. The FPSC approved PEF's petition for a detennination of need for the CR-3 EPU Project on February 8, 2007. 3.3 COST - BENEFIT ANALYSIS The EPU at CR-3 would provide approximately 168 MWe of additional baseload generating capacity for PEF's residential and commercial customers. The cost-benefit analysis for determining whether or not to proceed with the EPU at CR-3 is based on a comparison of the projected market price and the projected cost of producing more power from CR-3. In its Petition for Determination of Need, submitted to the FPSC in September 2006, PEF estimated that the total cost of the EPU would be about $382 million, with $89 million allotted to transmission system improvements and $43 million to the POD project (i.e., Helper Cooling Tower South). This number excluded a portion of the potential cooling tower costs as they have a different recovery mechanism. The total project cost including these cooling tower costs was $427 million. At that time, PEF estimated that total gross fuel savings would exceed $2.6 billion through 2036, with a net present value of savings after costs to retail customers of approximately $327 million (PEF 2006a). In an April 2010 FPSC filing, PEF updated its estimate for the total project cost of EPU to $418.6 million. As described above, this number excludes a portion of the potential cooling tower costs allocated to a different recovery mechanism. The total project cost including these cooling tower costs would be $479.4 million. It should be noted that the updated cost also reflects the cancellation of the transmission system improvements. This cost estimate is subject to change depending on what solution is ultimately selected to mitigate increased heat loading. There could be other, less-significant scope changes as well. The EPU would increase fuel diversity and supply reliability. It would provide a stable source of additional baseload power. Nuclear generation is not subject to the same supply interruptions or changes and price volatility that can affect generation with fossil fuels. Nuclear fuel is relatively plentiful and stable in price (FPSC 2007, pp. 3-4). A national comparison of power-producing alternatives indicates that nuclear power generation production costs are approximately 71 percent of coal-fired power, 26 percent of gas-fired power, and 17 percent of oil-fired power production (NEI 2008). Progress Energy's customers and the State of Florida would benefit from increased price stability, enhanced fuel diversity, and decreased reliance on foreign fuel sources resulting from the addition of nuclear capacity to PEF's system (FPSC 2007). A quantitative study of environmental costs of alternatives is not necessary to recognize that significant environmental benefits may be derived from an EPU when compared to other options for creating additional generating capacity. As demonstrated herein, an EPU is not expected to result in significant environmental costs. Unlike fossil fuel plants, CR-3 does not emit sulfur dioxide, nitrogen oxides, carbon dioxide, or other atmospheric pollutants during normal operations. As a result, the EPU at CR-3 would not create greenhouse gases or contribute to acid rain. Proposed Action and Need 3-2 April 2011
Crystal River Unit 3 Extended Power Uprate The EPU would result in a 15.5 percent increase in the plant's thermal and electrical output. For analytical purposes only, PEF estimates that a similar increase would be expected in the volume of spent nuclear fuel generated. In reality, the increase may be smaller, as EPU upgrades may result in additional fuel efficiencies. The NRC NEPA regulation at 10 CFR 51.51 (Table S-3) summarizes environmental impacts of the uranium fuel cycle, which it defines as "uranium mining and milling, the production of uranium hexaflouride, isotopic enrichment, fuel fabrication, reprocessing of irradiated fuel, transportation of radioactive materials and management of low-level wastes and high-level wastes related to uranium fuel cycle activities." The NRC has determined that non-radiological impacts of the uranium fuel cycle are, in every instance, "small and acceptable" and that radiological releases/doses associated with the uranium fuel cycle are relatively modest and limited by regulations and regulatory standards. The NRC analysis of impacts at 10 CFR 51.51 is based on a theoretical 1,000 MWe plant. The proposed output after EPU would be within 8 percent of that level, at 1,080 MWe. Therefore, the radiological and environmental effects of EPU-related changes to the uranium fuel cycle would also be considered small. While the EPU project would produce additional spent nuclear fuel, the added amount would be accommodated by CR-3's existing spent fuel storage facility and the soon-to-be-built Independent Spent Fuel Storage Installation (ISFSI). Conservation program expansion would not be a superior alternative to the proposed EPU. PEF is currently exceeding its FPSC-approved numeric conservation goals. Further, PEF has recently expanded its demand-side management program offerings, resulting in additional savings. The EPU would add more energy to the system than an equivalent amount of conservation could save. If the comparison were made on equivalent energy alone, it would take more megawatts of conservation to save an amount of energy equivalent to the energy produced by the CR-3 EPU, which would result in higher costs to customers. There are no cost-effective demand-side management measures available to offset the need (FPSC 2007). Based upon the discussion above, it is reasonable to conclude that the CR-3 EPU provides an economic advantage over other alternatives for additional generation. EPU involves a cost-effective utilization of an existing asset, with relatively little environmental impact, making it a preferred means of securing additional generating capacity. April 2011 Proposed Action and Need Action and Need 33-3
-3) April 2011
Crystal River Unit 3 Extended Power Uprate 4.0 PROJECT ALTERNATIVES 4.1 PROPOSED ACTION The proposed action is to increase the licensed core thermal power level of CR-3 from 2,609 MWt Lip to 3,014 MWt, which represents an increase of approximately 15.5 percent from the current licensed core thermal power level, and 22.9 percent above the originally licensed reactor power level of 2,452 MWt. This change in core thermal power level would require NRC to amend the facility's operating license. The EPU would add 168 MWe to the plant's gross power output. The increased power output would result from improving the performance of the steam turbine and by increasing the size of the refueling batches to provide the necessary energy to support operation at the higher power levels. PEF intends to increase the power level in two phases. Phase One took place during a scheduled refueling outage in the fall of 2009 and coincided with the replacement of the plant's steam generators. Phase One of the [PU produced a small increase in electrical output with no change in rated thermal power. The net impact of this initial phase is a more efficient secondary plant. Phase Two, scheduled to occur during a refueling outage in spring 2013, would increase the reactor thermal power by increasing the size of the refueling batches and increasing the average enrichment of the core. This change would bring the total increase in electrical output associated with the EPU project to 168 MWe. Increasing the plant's rated thermal power level would increase the amount of steam generated and the temperature of the circulating water; therefore, some accommodation would have to be made to ensure that discharge temperatures comply with NPDES thermal limits. PEF is considering two options for mitigating potential impacts from increased thermal loading, a new helper cooling tower or seasonal load reduction. 4.1.1 EPU ALTERNATIVE - HELPER COOLING TOWER OPTION Under this option, a new mechanical-draft cooling tower, designated Helper Cooling Tower South (HCTS), would be installed to accommodate the higher circulating water temperatures. HCTS design specifications call for a circular, counter-flow, induced-draft cooling tower with lightning protection, wind walls, a splash-type fill system, and high-efficiency drift eliminators. The HCTS is to be built in the location currently occupied by the CREC percolation clarifier pond and south of the existing helper cooling towers, as shown in Figure 6-2. The proposed HCTS would be 289 feet in diamneter and 73.5 feet tall, and constructed of a rot- and chemical-resistant composite material. It will be capable of providing a cold water temperature of 90'F at 79'F design-point ambient wet bulb temperature, at design flow rate of 320,000 gpm and at design inlet water temperature of 108'F. The new HCTS would operate as a once-through or "single pass" cooling tower (i.e., no recirculation), discharging to the intake canal or discharge canal depending on the season and plant operating conditions. The exit structure from the tower basin would consist of two flumes, one conveying effluent to the discharge canal, and one conveying effluent to the intake canal. Proposed Action and Need 4-1 April 2011
Crystal River Unit 3 Extended Power Uprate Flow diversion gates installed on these flumes would allow operators to control the percentage of flow that goes to each flume. Each flume would be designed to receive up to 100 percent of the total flow. Operational requirements for the flow diversion gates have not been determined; however, the gates will be operated so as to ensure continued compliance with the thermal limits of the NPDES permit. PEF would seek approval from FDEP to modify the current NPDES pernit to authorize the operation of the new HCTS if this cooling option is selected. The actual operational procedures, discharge locations, and timeframes would be established during the permit modification process. 4.1.2 EPU ALTERNATIVE - LOAD REDUCTION MANAGEMENT OPTION Under the Load Reduction Management Option, PEF would manage the discharge canal water temperature, as measured at the POD, through the operation of existing cooling towers. If the POD temperature is expected to increase to the 3-hour rolling average permitted temperature limit with all available cooling towers in operation, the discharge canal temperature would be lowered by reducing power output from Unit I and/or Unit 2. The thermal input to the discharge canal is directly proportional to unit electrical output, and a reduction in electrical output (load reduction) would result in a concurrent reduction in thermal output. This strategy has been employed for many years at the site when climatic factors and inlet water temperatures create a situation whereby the existing mechanical draft cooling tower operation was insufficient to achieve compliance with the NPDES permitted temperature limits at the POD. Given that thermal loading to the discharge canal would be higher uinder EPU conditions, PEF anticipates that the existing helper cooling towers would operate more frequently, and over a longer seasonal period. Units I and 2 Fossil Operations have existing procedures that guide the operator on when to initiate load reduction to maintain compliance with the applicable temperature limits. 4.2 NO ACTION ALTERNATIVE Under the No Action Alternative, CR-3 would continue to operate at the currently licensed power level of 2,609 MWt, with no change in current environmental impacts. Proposed Action and Need 4-2 April 2011l
Crystal River Unit 3 Extended Power Uprate 5.0 OVERVIEW OF OPERATIONAL AND EQUIPMENT CHANGES PEF proposes to implement the CR-3 EPU in two phases. Phase One occurred during a scheduled refueling outage in the fall of 2009 and coincided with replacement of the plant's steam generators. This initial phase produced a small increase in electrical output, but no change in rated thermal power. The Phase One modifications were intended to make the secondary side of the plant more efficient. Phase Two, in 2013, during which many of the hardware changes necessitated by higher operating temperatures will be made, will bring the total increase in electrical output associated with the EPU to 168 MWe. Table 5-1 shows the sequence of equipment changes as currently envisioned. TABLE 5-1 MAJOR EQUIPMENT MODIFICATIONS TO SUPPORT CR-3 EPU. Refueling Outage 16 Refueling Outage 17 Fall 2009 2013 Remove and Replace /Upgrade the Main Replace and upgrade High-pressure Turbine Generator Rotor and Related Components Upgrade Turbine-Generator-Exciter Replace and upgrade Low-pressure Turbines Replace (4) Moisture Separator Reheaters Replace Booster Pump impellers and motors Replace Isophase Bus Duct. Bus Duct Cooler Modify the Main and Emergency Feedwater and Related Components Systems for the additional feedwater flow Replace Secondary Cooling Pump Impeller and Complete instrumentation upgrades and any Motor necessary changes to computer hardware and software Replace/Upgrade (2) Secondary Cooling Heat Install a Low-Pressure Injection System Cross Tie Exchangers Replace/Upgrade Turbine Generator Lube Oil Replace Condensate Pumps and Motors (2) Heat Exchanger Tube Bundles Replace (4) Turbine Bypass Valves and Modify High Pressure Injection System associated components Make necessary changes in plant Complete the POD cooling task improvements instrumentation, computer hardware, and (HCTS) - If this thermal mitigation option is computer software (Integrated Control System) selected Upgrade the Turbine Building Crane Replace (2) Automatic Dump Relief Steam Valves Replace Heater Drain Valves Flow Replace Feedwater Heat Exchangers Transmitters, and Pipe Sections Install Moisture Separator Belly Drain Heat Exchangers Replace (2) Condensate Heaters Install a Fiber Optic Communication System The activities needed to produce thermal power increases are a combination of those that directly produce more power and those that must accommodate the effects of the power increase. The Operational and Equipment Changes 5-1 April 2011
Crystal River Unit 3) Extended Power Uprate primary means of producing more power are a change to a more highly-enriched uranium fuel, an operational change in reactor thermal-hydraulic parameters, and upgrade of Balance of Plant (BOP) capacity by component replacement or modification. BOP changes include replacing the high-pressure turbine, replacing selected feedwater heaters that are already operating at capacity, providing additional cooling for some plant systems, various electrical upgrades to accommodate the higher currents, modifications to accommodate greater steam and condensate flow rates, and instrumentation upgrades that include replacing parts, changing setpoints, and modifying software. These major equipment modifications would be made whether the Helper Cooling Tower Option or Load Reduction Management Option is selected. If the Helper Cooling Tower Option is selected, construction on the tower would be completed in time to support operation of CR-3 at EPU conditions. Operational and Equipment Changes 5-2 April 2011l
Crystal River Unit 3 Extended Power Uprate 6.0 NON-RADIOLOGICAL ENVIROMENTAL IMPACTS 6.1 TERRESTRIAL RESOURCES 6.1.1 LAND USE CR-3 is part of the larger CREC, which includes the single nuclear unit and four fossil-fueled units, Crystal River Units 1, 2, 4, and 5. CR-3, a pressurized water reactor that began operating in 1977, is rated at 912 MWe. The four coal-fired units have a total generating capacity of 2,311 M We (Progress Energy 2009a). CR-3 and the four fossil units lie in the developed core area of the 4,738 acre site, which is shown in Figure 6-1. Aside from generating and support facilities, this developed area also contains office buildings, warehouses, fuel oil tanks, coal storage areas, and ash storage areas. Units 1, 2, and 3 are referred to as "Crystal River South," while Units 4 and 5 are referred to as "Crystal River North." Crystal River Unit 3's Reactor Building, Turbine Building, and Auxiliary Building are in the southern part of the developed area, but in the approximate center of the larger 4,738 acre site. The nuclear exclusion zone is defined by a circle centered on the CR-3 Reactor Building with a radius of 4,400 feet (Florida Power 2008). The stacks of the four coal-fired units and the Unit 4 and 5 cooling towers dominate the local viewscape, with CR-3-associated structures much less obtrusive visually. The area immediately surrounding the plant is, for the most part, a mix of upland (pine) forest, agricultural lands, swamps, and salt marshes. The large tract of land immediately north of the plant is owned by an agri-business concern with mining interests. Parts of this property are forested, parts are used for cattle ranching and cultivation of citrus trees, and other parts of this property are devoted to limestone/dolomite mining. The area southwest of the plant is salt marsh, while the area south and southeast of the plant is mostly forested wetlands. The proposed EPU would have very little effect on land use at the 4,738-acre CREC site. All areas on the CREC site that would be disturbed or altered by EPU-related activities were previously disturbed during development of the two fossil units in the 1960s and CR-3 in the 1970s and/or by subsequent facility modifications, upgrades, and expansions. As noted in Section 2.5.3 of the CR-3 Final Safety Analysis Report (FSAR; Florida Power 2008), the site is adjacent to the Gulf of Mexico in a former marsh area that was reclaimed for site development. The developed portion of the site is covered by a 3-to-5-foot-thick layer of fill made up of coarse silty sand and limestone rock fragments that were placed directly over existing soil and vegetation to facilitate construction of plant facilities (Florida Power 2008, Section 2.5.3). Clearing, filling, and grading during construction raised the land level in the general vicinity of Non-Radiological Environmental Impacts 6-1 April 21011
r IA Crystal River Unit 3 EPU Supplemental Environmental Report Figure 6-1 Developed Portion of Crystal River site 6-2 January 2011 Non-Radiological Environmental Impacts Impacts 6-2 January. 2011
Crystal River Unit 3 Extended Power Uprate CR-3 by approximately five feet, to about 8 feet above sea level (AEC 1973). As a consequence, there are no undisturbed areas and no native soils or vegetation communities within the central developed portion of the site. Land use in several areas changed before and during the fall 2009 outage (RF-16), when the steam generators were replaced, because additional materials storage and parking areas were needed. A small (approximately one acre) previously-disturbed wetland approximately 1,600 feet east-northeast of CR-3 (labeled "South Laydown Area" in Figure 6-2) was converted into a permanent laydown area. All trees in this formerly forested wetland were cut down due to security concerns after the events of September 11, 2001 and barriers/fencing were erected along its length. A 3.5-acre strip of mowed grasses adjacent to an east-west running transmission corridor approximately 2,000 feet north-northeast of CR-3 (labeled "North Laydown Area") was used temporarily for materials storage and work areas during the fall 2009 outage and will be used again during the spring 2013 outage. An area adjacent to the North Laydown Area was used as a temporary overflow parking area during RF-16, and will likely be used for parking during RF- 17. Both areas will be restored (i.e., grass will be replanted) after completion of the EPU. 6.1.1.1 EPU ALTERNATIVE - HELPER COOLING TOWER OPTION The new mechanical draft cooling tower, the HCTS, would be built in an area 3,400 feet west of the powerblock area that was originally intended for use as a settling (final polishing) pond for dewatering hydraulic dredge spoil (see Figure 6-2). A construction laydown area has been established to service the EPU project on a 4-acre parcel of land 3,600 feet WSW of the powerblock area on which the CR-3 meteorological tower was formerly located (see Figure 6-2). This site was historically salt marsh but was filled in 1970 for an experimental mariculture (shrimp-rearing) facility operated by the Ralston Purina Corporation. The mariculture facility, which expanded to include several raceways, rearing ponds, and a laboratory, was closed in 1981 when it became clear that the operation was not economically viable. The facility was subsequently modified to make room for the meteorological tower and a nuclear security training complex that includes an office building and a firing range. Should the Helper Cooling Tower Option be selected, land use in several small, previously-disturbed areas would change during the construction period and two small (totaling approximately 5 acres), previously-disturbed parcels would be converted to industrial use (for the new cooling tower and associated construction laydown yard). The overall impact to land use on the CREC and surrounding areas would be negligible. There would be a small change in the viewscape associated with the new HCTS, but visual/aesthetic impacts would be small in comparison to the visual impact of the existing stacks and natural draft cooling towers (see Figure 6-1 ). Given that none of the EPU-related activities would take place in an undeveloped or undisturbed area and that the developed portion of the CREC was cleared, filled, and graded during Non- Radiological Enviromnental Impacts 6-3) April 2011
Crystal River Unit 3 Extended Power Uprate Legend 0Legn250 500 1.000 1,500 Feet Permanently Altered Area E Temporarily Disturbed Area Crystal River Unit 3 EPU Supplemental Environmental Report Figure 6-2 Land Use Changes Associated with SGR and EPU Non-Radiological Environmental Inpacts 6-4 January 2011
Crystal River Unit 3 Extended Power Uprate construction in the 1960s, 1970s, and 1980s, the probability of impacts to cultural resources is very remote. 6.1.1.2 EPU ALTERNATIVE - LOAD REDUCTION MANAGEMENT OPTION Should PEF decide to pursue the Load Reduction Management Option, no cooling tower would be built and there would be no land use changes beyond those already described. Therefore, impacts to land use would be negligible. 6.1.1.3 NO ACTION ALTERNATIVE Under the No Action Alternative, CR-3 would continue to operate at the currently licensed power level of 2,609 MWt and there would be no changes in land use beyond those already described. 6.1.2 TRANSMISSION FACILITIES The EPU would result in an increase in transmission line electrical current that is proportional to the increase in electrical power generated. The degree of change is assumed to be independent of which cooling option is employed. The No Action Alternative would not change the transmission line current from the present conditions. The following types of transmission facility impacts would be expected for the proposed action. Transmission Lines The EPU would not require any new transmission lines and would not require changes in the maintenance and operation of existing transmission lines, switchyards, or sub-stations. Right-of-way maintenance practices (including vegetation management) would not be affected by the EPU. The only operational change from EPU would be increased current. Increased current would slightly increase temperature and sag of the lines, but the voltage would be unchanged. Shock Hazards The EPU should not increase the probability or magnitude of shock from primary or secondary currents because there would be no change in voltage. Increased current may cause transmission lines to sag more, but adequate clearance between energized conductors and the ground would prevent electrical shock to ecological receptors. Transmission lines are designed in accordance with the applicable shock prevention provisions of the National Electrical Safety Code©. Electromagnetic Fields (EMF) The increased electrical power output would cause a corresponding current rise on the transmission system and this would result in an increased magnetic field (but not the electric field). PEF adopts by reference the NRC conclusion that chronic effects of EMF on humans are not quantified at this time and no significant impacts to terrestrial biota have been identified (NRC 1996). 6-5 April 2011 Environmental Impacts Non-Radiological Environmental Impacts 6-5 April 2011
Crystal River Unit 3 Extended Power Uprate 6.1.3 SOCIOECONOMIC CONSIDERATIONS The proposed EPU at CR-3 would provide economic benefits to the surrounding communities through tax revenues and local business revenues produced by plant construction and operations. 6.1.3.1 CURRENT SOCIOECONOMIC STATUS Currently CR-3 employs approximately 760 full-time staff and long-term contract employees, the majority of whom live in Citrus County. During refueling outages, the normal plant staff is supplemented by approximately 1,300 additional workers, both contract workers and technical specialists from other Progress Energy power plants. Through income, sales, and property taxes, employees' salaries contribute to the surrounding communities, having a positive influence on the economies of the region. Additionally, property taxes paid by CR-3 to Citrus County are considerable. In 2008, CR-3's total taxable value was $644 million. Table 6-1 presents the percentage of Citrus County property tax revenues attributable to CR-3 for the past four years. Communities surrounding CR-3 benefit from local taxes paid by PEF. Public services, including city operations, water management, public education, and health services receive economic support through these tax revenues. TABLE 6-1 CR-3 TAX INFORMATION, 2005-2008. Percent of Citrus Citrus County Property Tax Paid County Year Tax Revenues by Progress Energy Revenues 2005 $157,764,712 $8,445,007 5.4 2006 $190,064,953 $8,998,384 4.7 2007 $194,188,833 $10,072,127 5.2 2008 $185,500,539 $9,941,454 5.4 Source: Waldemar 2009 6.1.3.2 SOCIOECONOMIC IMPACTS 6.1.3.2.1 EPU ALTERNATIVE - HELPER COOLING TOWER OPTION The proposed EPU is not expected to affect the size of the CR-3 operations workforce or the labor force required for future normal refueling outages. The only increase in plant staffing would take place during two refueling outages, one that has already occurred in 2009 and one planned in 2013, when most EPU construction activities are scheduled to take place. During the 2009 outage, the peak number of construction workers on site supporting steam generator replacement (SGR) and EPU-related activities was approximately 1,800. At peak, during the 2013 outage, there would be approximately 1,350 EPU-related construction workers on site. During the 2009 outage, additional labor demands associated with construction activities did not create labor shortages. As such, labor shortages are not expected during the 2013 outage. Because much of the construction work associated with EPU activities is specialized, many workers come from outside of the 50-mile region. Some workers come from the Tampa-St. Non-Radiological Environmental Impacts 6-6 April 2011
Crystal River Unit 3 Extended Power Uprate Petersburg-Clearwater metropolitan area (approximately 60 miles south of Citrus County). Due to the proximity of the plant site to the Tampa-St. Petersburg-Clearwater metropolitan area, population and housing impacts are expected to be minimal. The existing communities within the region have sufficient infrastructure and resources to accommodate the temporary influx of construction workers. This was demonstrated during the 2009 outage, as there were no infrastructure problems or resource (i.e., housing, public water supply) shortages. In 2007, PEF commissioned a traffic study designed to assess the impacts created by the EPU (Trans Associates 2007). Results of this study indicate that the 2009 outage represented the greatest potential for impact to transportation in the region. This is due to the construction activities associated with the CR-i, CR-2, CR-3, CR-4 and CR-5 projects, all taking place at varying periods throughout 2009. In the study, two highway capacity analyses were performed; one for the 2009 outage and one for the 2013 outage. The study's capacity analysis of the 2009 outage indicated that the intersection of US-19/US-98 and West Power Line Road was anticipated to perform at LOS B during peak hours. The sections of US-19/US-98 north and south of West Power Line Road were expected to operate at LOS A. Results of the capacity analysis of the 2013 outage indicate that the intersection of US-19/US-98 and West Power Line Road is anticipated to perform at LOS B during peak hours. The sections of US-19/US-98 north and south of West Power Line Road are expected to operate at LOS A. The predictions of the 2007 Trans Associates study for the 2009 outage were confirmed, anecdotally, by PEF employees following completion of the outage. Employees report that, at peak, approximately 1,800 SGR and EPU-related construction workers traveled to and from the site each day and nothing more than small delays were experienced. To mitigate potential traffic congestion at the intersection of US-19/US-98 and West Power Line Road, PEF developed a temporary off-site parking area that would enable workers to be shuttled to the site by bus. The parking area, the 20-acre Holcirn site, was located one mile north of the intersection of US-19/US-98 and West Power Line Road and provided approximately 1,950 parking spaces. The offsite parking plan was considered a success by greatly reducing the traffic flow on West Power Line Road. In 2010, the Holcim site was restored and returned to the owner. Fewer workers would be needed for the 2013 outage. At this time, PEF has made no final decisions regarding traffic management during the 2013 outage. Several traffic management options are being explored. PEF recognizes that an arrangement similar to the one used during the 2009 outage could, once again, be utilized, if necessary. There would be positive economic benefits to the local economy because the assessed value of CR-3 would increase as a result of capital upgrades. Local taxing authorities would benefit from an increase in the plant's property tax base. Positive economic benefits would be realized by local, regional, and national businesses contributing goods and services to the proposed EPU. In addition, engineering and consulting firms, equipment suppliers, and service industries would receive payments for EPU activities. Non-Radiological Environmental Impacts 6-7 April 2011
Crystal River Unit 3 Extended Power Uprate The direct revenue associated with the EPU would not be sustained once modifications are complete. However, the economic benefits associated with the EPU would represent a positive impact on regional economies, both in terms of the one-time benefit of EPU equipment installation and the long-term benefit of operating CR-3 at a higher power level. 6.1.3.2.2 EPU ALTERNATIVE - LOAD REDUCTION MANAGEMENT OPTION The proposed Load Reduction Management Option is not expected to affect the size of the CR-3 operations workforce or the labor force required for future normal refueling outages. The only increase in plant staffing would take place during the two refueling outages mentioned previously. During the 2009 outage, there was a peak of 1,800 SGR and EPU-related construction workers on site. At peak, during the 2013 outage, there would be approximately 1,350 EPU-related construction workers on site. As stated previously, during the 2009 outage, additional labor demands associated with multiple construction projects did not create labor shortages. As such, labor shortages are not expected during the 2013 outage. As demonstrated during the 2009 outage, EPU-related workers did not create problems or shortages with existing infrastructure and community resources. Existing communities in the region have sufficient infrastructure and resources to accommodate the temporary influx of construction workers during the 2013 outage. As stated previously, the 2007 PEF traffic study indicates that, during the 2013 outage, the intersection of US-19/US-98 and West Power Line Road is anticipated to perform at LOS B during peak hours. The sections of US-19/US-98 north and south of West Power Line Road are expected to operate at LOS A. At this time, PEF has made no final decisions regarding traffic management during the 2013 outage. Several traffic management options are being explored. PEF recognizes that an arrangement similar to the one used during the 2009 outage could, once again, be utilized, if necessary. For the Load Reduction Management option, there would also be positive economic benefits to the local economy because the assessed value of CR-3 would increase as a result of capital upgrades. Local taxing authorities would benefit from an increase in the plant's property tax base. Again, positive economic benefits would be realized by local, regional, and national businesses contributing goods and services to the proposed EPU. In addition, engineering and consulting firms, equipment suppliers, and service industries would receive payments for EPU activities. The direct revenue associated with the EPU would not be sustained once modifications are complete. However, the economic benefits associated with the EPU would represent a positive impact on regional economies, both in terms of the one-time benefit of EPU equipment installation and the long-term benefit of operating CR-3 at a higher power level. Non- Radiological Environmental Impacts 6-8 April'2011I
Crystal River Unit 3 Extended Power Uprate 6.1.3.2.3 NO ACTION ALTERNATIVE Under the No Action Alternative, CR-3 would continue to operate at the currently licensed power level of 2,609 MWt, there would be no changes in employment levels or spending on behalf of CR-3 and no changes in existing traffic patterns. 6.1.4 ENVIRONMENTAL JUSTICE 6.1.4.1 MINORITY AND LOW-INCOME POPULATIONS Executive Order 12898, "Federal Actions to Address Environmental Justice in Minority Populations and Low-income Populations," 59 FR 7629 (1994), directs Federal agencies in the Executive Branch to "make achieving environmental justice part of its mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of its programs, policies, and activities" on minority and low-income populations. Although an independent agency, the NRC has indicated its willingness to comply with the Executive Order. The Council on Environmental Quality (CEQ) developed guidelines to assist Federal agencies with integration of environmental justice into the NEPA process. The guidelines are contained in CEQ's December 10, 1997, document, "Environmental Justice Guidance Under the National Environmental Policy Act." CEQ's guidance is not binding on NRC activities; however, NRC has voluntarily committed to conducting environmental justice reviews of actions under its jurisdiction and has issued a policy statement and procedural guidance. Much of CEQ's guidance has been incorporated into NRC's environmental justice procedural guidance (NRC 2004a). The NRC guidance defines a minority population as: American Indian or Alaskan Native; Asian; Native Hawaiian or other Pacific Islander; Black Races; all other single races; multi-racial; and Hispanic Ethnicity (NRC 2004a). The guidance indicates that a minority population exists if the minority population percentage in the census block group or environmental impact site exceeds 50 percent, or is significantly greater (typically at least 20 percentage points) than the minority population percentage in the geographic area chosen for comparative analysis. PEF defines the geographic area for CR-3 as the state of Florida. NRC guidance calls for using the most recent U.S. Census Bureau (USCB) decennial census data. PEF used 2000 census data to determine the percentage of the total population in Florida for each minority category, and to identify minority populations within 50 miles of CR-3. For each of the 483 block groups within 50 miles of CR-3, PEF compared the minority percentage to the corresponding geographic area's minority threshold percentages to determine whether minority populations exist. USCB data for Florida characterizes 0.3 percent of the state as American Indian or Alaskan Native, 1.7 percent as Asian, 0.1 percent as Native Hawaiian or other Pacific Islander, 14.6 percent as Black races, 3.0 percent as all other single minorities, Non- Radiological Environmental Inpacts 6-9 April 2011
Crystal River Unit 3 Extended Power Uprate 2.4 percent as multi-racial, 22.0 percent as an aggregate of minority races, and 16.8 percent as Hispanic Ethnicity (Progress Energy 2008). No census blocks within the 50-mile radius have American Indian or Alaska Native, Asian, Native Hawaiian or Pacific Islander, or multi-racial minority populations that exceed the Florida average by 20 percent. Thirty-two census blocks within the 50-mile radius have Black Races populations that exceed the state average by 20 percent. One census block group within the 50-mile radius has a population of all other single minorities that exceeds the state average by 20 percent. Thirty-one census block groups within the 50-mile radius have significant aggregate minority populations. Three census blocks within the 50-mile radius have significant Hispanic Ethnicity populations (Progress Energy 2008). Most of the block groups with significant minority populations are found in Levy, Marion, and Sumter Counties. The Hispanic block groups are located in Pasco County. Generally speaking, there are relatively few census blocks exceeding the threshold for minority populations within a 50-mile radius: only one in Citrus County, and none within 5 miles of the plant. NRC guidance defines low-income populations based on statistical poverty thresholds (NRC 2004a). PEF divided the number of USCB low-income households in each census block group by the total households in that block group to obtain the percentage of low-income households per block group. USCB data characterize 11.7 percent of Florida households as low-income households (Progress Energy 2008). A low-income population is considered to be present if the percentage of households below the poverty level in the census block group or the environmental impact site exceeds 50 percent or is significantly greater (typically at least 20 percentage points) than the low-income households percentage in the geographic area chosen for comparative analysis (NRC 2004a). Sixteen census blocks within the 50-mile radius have low-income households that exceed the state average by 20 percent. Of those 16 census blocks, 3 have 50 percent or more low-income households. Again, there are relatively few census blocks exceeding the threshold for low-income populations within a 50-mile radius and none within 5 miles of the plant (Progress Energy 2008). 6.1.4.2 ENVIRONMENTAL JUSTICE IMPACTS 6.1.4.2.1 EPU ALTERNATIVE - HELPER COOLING TOWER OPTION The NRC procedure makes clear that if no potentially significant impacts are anticipated from the proposed action, then "...these results should be documented and the environmental justice review is complete" (NRC 2004a, pg. D-10). Progress Energy has reviewed the pathways through which impacts from the EPU could occur by analyzing the following resource areas: socioeconomics, land use, non-radioactive waste, noise, air quality and visibility, terrestrial and aquatic ecology, hydrology, and radiation. Based on this review, PEF has determined that the EPU would result in no significant impacts. Therefore, there would be no disproportionately 6-10 April 2011 Environmental Impacts Non-Radiological Environmental Impacts 6-10 April 2011
Crystal River Unit 3 Extended Power Uprate high and adverse impacts on any member of the public, including minority and low-income populations, from implementation of this option. 6.1.4.2.2 EPU ALTERNATIVE - LOAD REDUCTION MANAGEMENT OPTION Progress Energy has reviewed the pathways through which impacts from the EPU could occur by analyzing the following resource areas: socioeconomics, land use, non-radioactive waste, noise, air quality and visibility, terrestrial and aquatic ecology, hydrology, and radiation. Based on this review, PEF has determined that the EPU would result in no significant impacts. Therefore, there would be no disproportionately high and adverse impacts on any member of the public, including minority and low-income populations, from implementation of this option. 6.1.4.2.3 NO ACTION ALTERNATIVE Under the No Action Alternative, CR-3 would continue to operate at the currently licensed power level of 2,609 MWt, resulting in no additional human health or environmental effects on minority and low-income populations. 6.1.5 MISCELLANEOUS WASTES CR-3 generates both hazardous and non-hazardous wastes. They are handled and disposed of properly in accordance with the station's waste management program. CREC is a small quantity generator of hazardous waste. Wastes are recycled and minimized by chemical control management whenever possible. The recycling program at CR-3 currently includes scrap metal, printer cartridges, batteries, containers and fluorescent bulbs. No change in hazardous or non-hazardous waste management practices are anticipated as a result of operating CR-3 under EPU conditions. Installation of equipment under either of the two cooling options could involve the generation of small quantities of solid wastes (e.g., wooden crates, pallets, packing material) and potentially hazardous wastes (e.g., lubricants, solvents, adhesives). Construction of the HCTS under the Helper Cooling Tower Option would also generate a modest amount of solid, non-hazardous waste, such as scrap lumber. The cooling tower is composed of"pre-engineered" components, which would minimize the amount of waste generated. Any wastes generated during the construction/installation phase will be temporarily stored and prepared for offsite disposal in accordance with state, federal and NRC regulations. Under the No Action Alternative there would be no change in volumes of solid and hazardous wastes generated. 6.1.6 AIR QUALITY AND VISIBILITY 6.1.
6.1 BACKGROUND
CR-3 is located in Citrus County, Florida near the City of Crystal River. The climate of the region around the CR-3 site is humid subtropical, which is characterized by relatively dry winters and rainy summers, a high annual percentage of sunshine, a long growing season, and high humidity. The terrain is generally flat and featureless with the Gulf of Mexico being the Non-Radiological Environmental Impacts 6-11 April 2011
Crystal River Unit 3 Extended Power Uprate major climatic influence. Snowfall is virtually non-existent, but rainfall averages about 50-60 inches per year, with more than 50 percent of the total rainfall occurring during the months of June through September (Florida Power 2008). Temperatures in the site region (modified by the waters of the Gulf of Mexico) seldom exceed 90'F or fall below 32°F. Fog has a high frequency of occurrence at night during the winter season. Prevailing winds are from the east, but the winds are somewhat erratic since the coastal regions experience frequent local circulations caused by the land-sea breeze. The coastal location of the site also results in vulnerability to tropical storms and hurricanes. In addition, tornadoes occur quite frequently in this region. Under the Clean Air Act, the U.S. Environmental Protection Agency (EPA) has established National Ambient Air Quality Standards (NAAQS), which specify maximum concentrations for carbon monoxide (CO), particulate matter with aerodynamic diameters of 10 microns or less (PMlo), particulate matter with aerodynamic diameters of 2.5 microns or less (PM 2 5), ozone, sulfur dioxide (SO 2), lead, and nitrogen dioxide (NO 2). Areas of the United States having air quality as good as or better than the NAAQS are designated by EPA as attainment areas. Areas having air quality that is worse than the NAAQS are designated by EPA as non-attainment areas. CR-3 is located in the West Central Florida Intrastate Air Quality Control Region (AQCR) (40 CFR 81.96). The West Central Florida AQCR is designated as in attainment or unclassifiable for all air quality standards as are all counties in the State of Florida (40 CFR 81.310). The nearest non-attainment area is Bibb County, Georgia, approximately 275 miles north of CR-3, which is designated as a non-attainment area Linder the 1997 PM 2.5 and a maintenance area under the 8-hour ozone NAAQS (40 CFR 81.311). The Chassahowitzka National Wildlife Refuge, approximately 13 miles south of CR-3 is designated as a mandatory Class I Federal area in which visibility is an important value (40 CFR 81.407). No other Class I areas are located within 100 miles of the site. On January 6, 2010, U.S. Environmental Protection Agency (EPA) proposed revisions to strengthen the NAAQS for ground-level ozone. The revisions would strengthen the primary 8-hour ozone standard and would also establish a separate cumulative secondary standard. USEPA plans to issue final standards on or about the end of October 2010 (USEPA 2010). The proposed implementation timeline includes states making recommendations to USEPA by January 2011 for areas to be designated as in attainment, non-attainment, or unclassifiable with final designations being in effect no later than August 2011 (75 FR 2938-3052). Based on 2006-2008 air quality data, Citrus County had not exceeded the proposed ozone standards. Therefore, Citrus County's attainment designation for ozone is not expected to change following the issuance of new USEPA standards. However, Hernando and Pasco counties, located south of Citrus County and within 50 miles of CREC, have been recommended by the FDEP as designated ozone nonattainment areas (FDEP 2009). Non-Radiological Environmental Impacts 6-12 April 2011
Crystal River Unit 3 Extended Power Uprate 6.1.6.2 AIR QUALITY AND VISIBILITY IMPACTS 6.1.6.2.1 EPU ALTERNATIVE - HELPER COOLING TOWER OPTION Under this option, a new mechanical-draft cooling tower would be installed to accommodate higher circulating water temperatures. Cooling towers operate by transferring heat from the cooling tower water to the air by evaporating the water. Drift is small water droplets that become entrained in the air flow leaving the cooling tower and escape the tower without evaporating. Once out of the tower, the water in the drift may evaporate leaving any solids that are in the water behind. The drift and the solids formed from the drift would be a type of air pollution called particulate matter (PM). Some of this PM would have a diameter equal to or less than 10 microns, called PM 10. PM 10 is a criteria pollutant, one of six common air pollutants that the Clean Air Act specifies that the EPA set NAAQS. PMj 0 is typically small enough to pass through the nose and throat and enter the lungs, causing potential health effects. Emissions firom the HCTS would be limited to particulate matter. The EPA has implemented regulations requiring a Prevention of Significant Deterioration (PSD) review for new or modified sources that increase air emissions above certain threshold amounts. EPA's PSD regulations are implemented in Florida through the approved PSD program of the Florida Department of Environmental Protection. The threshold for PM emissions is 25 tons per year and the threshold for PM 1 0 emissions is 15 tons per year. Drift from cooling towers is controlled using drift eliminators. The HCTS would be equipped with drift eliminators that would limit the drift to 0.0005 percent of the cooling tower flow rate. This represents the best available control technology for drift. PM and PM 10 emissions were estimated for the operation of the proposed HCTS in the Site Certification Application (SCA) (PEF 2007a). Estimated PM emissions from the HCTS exceeded the threshold for a PSD review. The PSD review is included in the SCA. Air quality impacts were not determined for the PM emissions since PM is not a criteria pollutant. PM1 0 emissions were below the threshold for a PSD review. Following the submittal of the SCA in 2007, the cooling tower design was modified. An analysis was recently performed consistent with the analysis in the SCA but updated to the new tower design (Tetra Tech 2009). PM emissions from the re-designed cooling tower would be lower than the PM emissions from the original design since the flow rate through the tower would be reduced, reducing drift and associated PM emissions. The predicted emissions for the new tower design would be 91.2 tons per year for PM and 5.5 tons per year for PM 10 (Tetra Tech 2009). The PM emission rate is above the threshold for a PSD review while the PM 10 emission rate is below the threshold for PSD review. PM emissions with particle sizes above 10 microns are not generally considered a health risk. The PM emissions from the HCTS would be confined to the plant property, to which the public does not have access. High PM emissions also have the potential to impair visibility. However, Non-Radiological Environmental Impacts 6-13 April 2011
Crystal River Unit 3 Extended Power Uprate the PM emissions resulting from drift would be highest in the vicinity of the HCTS, and any impacts to visibility from these emissions would be small and localized. The PM 10 emission rate from the HCTS would be small and would not impact air quality. For the reasons discussed above, the air quality impacts from the operation of the HCTS would be small. 6.1.6.2.2 EPU ALTERNATIVE - LOAD REDUCTION MANAGEMENT OPTION Under this option, the site would continue to manage discharge canal water temperatures, as measured at the Point of Discharge (POD), through the operation of existing cooling towers. If the POD temperature approaches the permitted temperature limit with all available cooling towers in operation, the discharge canal temperature will be reduced by reducing thermal input from fossil-fired Unit I and/or Unit 2. The reduction in thermal input to the discharge canal would be achieved by reducing unit electrical power output. PEF anticipates that the net effect of implementing this option would be more frequent periods when load reduction is required. PEF operates Units I and 2 in accordance with the air operation permit for Crystal River (FDEP 2010). Emissions from the operation of Units I and 2 under load reduction conditions would not exceed their permitted emissions rates under any circumstance. 6.1.6.2.3 NO ACTION ALTERNATIVE Under the No Action Alternative, CR-3 would continue to operate at the currently licensed power level of 2,609 MWt. There would be no change in emissions from CR-3 or CREC as a whole. 6.1.7 NOISE A noise survey was conducted in 2007 to characterize existing background sound levels at CREC (PEF 2007a). Average baseline ambient sound pressure levels ranged from 57-71 dBA (decibels adjusted) at four locations proposed as construction staging areas or construction sites. These ranges are below the 75 dBA known to cause behavioral impacts on various species of birds and mammals (Golden et al. 1980). 6.1.7.1 EPU ALTERNATIVE - HELPER COOLING TOWER OPTION It would require approximately 18 months to build the new HCTS. Noise levels associated with heavy equipment at construction sites can be as high as 100 dBA at 100 feet from the noise source (Golden et al. 1980). However, noise attenuates over relatively short distances. For example, at 400 feet from a 100 dBA noise source, the noise levels typically fall within the 60-80 dBA range. Even with attenuation, some temporary noise-associated displacement of wildlife is expected during the construction phase. The proposed HCTS would be built at a point where the developed part of the plant adjoins the salt marsh. Noise impacts to wildlife would likely be limited to minor disturbance of common birds that use the marsh (e.g., wading birds, grackles, and red-winged blackbirds) and common wildlife species found on the plant site (e.g., raccoons, rabbits, doves, vultures). Given the existing background noise levels, the limited construction Non-Radiological Environmental Impacts 6-14 April 2011
Crystal River Unit 3 Extended Power Uprate activities planned for the uprate, and the rapid attenuation of noise, impacts to wildlife from implementation of this option are expected to be small and temporary. During normal operations, the noise level in the immediate vicinity of the proposed HCTS is expected to be no higher than 87.3 dBA (measured five feet from the cooling tower; Evaptech 2009). This noise level is below the 90 dBA threshold beyond which OSHA (29 CFR 1910.95) requires administrative or engineering controls. Two hundred feet from the tower, the noise level is expected to be approximately 74 dBA, below that known to disturb wildlife. The 200-ft radius of the tower encompasses a portion of the discharge canal (north of the proposed cooling tower), disturbed areas (east and south), and a small area of undeveloped land to the west. Noise impacts to wildlife from operation of the HCTS would be negligible. 6.1.7.2 EPU ALTERNATIVE - LOAD REDUCTION MANAGEMENT OPTION Under this option, most construction activity would take place indoors. Noise impacts to workers and wildlife would be negligible. 6.1.7.3 NO ACTION ALTERNATIVE Under the No Action Alternative, there would be no change in baseline noise levels at the Crystal River site. 6.1.8 TERRESTRIAL BIOTA The 4,738-acre CREC lies roughly in the center of the Big Bend area of the western Florida coast, and is situated between the Withlacoochee and Crystal Rivers (Progress Energy 2008). The area immediately surrounding the plant is a mixture of pine forests, agricultural lands, freshwater swamps and salt marshes. The Crystal River Preserve State Park adjoins the southeastern boundary of the CREC. Approximately 1,062 acres of the CREC have been developed or altered and are occupied by power-generating and support facilities, maintenance areas, warehouses and storage/laydown areas, roads, parking lots, roads, and transmission corridors associated with Crystal River Units I - 5 (Progress Energy 2008). The remaining 3,676 acres surrounding the facility consist of salt marshes, pinelands, mixed wetland hardwoods (hardwood hammock forests) and freshwater marshes (Progress Energy 2008). Small strips of vegetation occur along roadsides and other boundaries within the facility areas, including eastern redcedar (Juniperus virginiana), cabbage palm (Sabal pahnetto), Brazilian pepper (Schinus terebinlhifolius), groundsel tree (Baccharis halimnifolia), and wax myrtle (Myrica cerifera). Regularly mowed open lands (e.g., transmission corridors) are dominated by grasses, primarily Bermuda grass (Cynodon dactylon) and bahia grass (Paspalurnnotalturn). The more natural habitat types contain flora typical of the western coast of Florida (see AEC 1973 and Progress Energy 2008). The salt marshes are dominated by smooth cordgrass (Spartina alterniflora) and black rush (Juncus roemerianus). The hardwood wetland areas Non-Radiological Environmental Impacts 6-15 April 2011
Crystal River Unit 3 Extended Power Uprate contain magnolia (Magnolia grandiflora), laurel oak (Quercus laurifolia), and American hombeam (Carpinuscaroliniana). Pinelands, also known as pine flatwoods, are dominated by slash pine (Pinus elliotti) and loblolly pine (P. taeda) and frequently have a dense understory of sawtooth palmetto (Serenoa repens). Freshwater marshes occur on-site in the form of wetland depressions embedded in the pinelands (Progress Energy 2008). Characteristic vegetation within these depressions includes pond cypress (Taxodium ascendens), swamp tupelo (Nyssa biflora) and swamp ash (Fraxinuspauciflora). Presence of standing water and water depth at these sites are largely determined by rainfall amounts. A 0.9-acre construction laydown area labeled South Laydown Area on Figure 6-2 has been established approximately 1,600 feet ENE of the containment building on an area previously described as a mixed-hardwood wetland. This wetland area was altered for security purposes after September 11, 2001, which included the cutting of all trees (near ground level) within the site and the construction of security-related structures (e.g., fencing, barriers), thus resulting in a wetland area of marginal value. This area was converted into a permanent laydown area through the FDEP Environmental Resource Permit process. An additional 4-acre construction laydown has been established on previously disturbed land approximately 3,600 feet west of CR-3 (Figure 6-2). This site was historically marsh, but was impounded and built up with fill material in the 1970-1971 period. The original CR-3 meteorological tower was located on the highest portion of this site, which also contains some low, wet areas. It was necessary to relocate the meteorological tower due to potential interference from the proposed HCTS. A new meteorological tower has been built on the west end of the discharge canal (north bank) and placed into operation. A review of the federal (US Fish and Wildlife Service [USFWS]) and state (Florida) databases pertaining to listed species (FNAI 2010; USFWS 2010a) indicated that multiple federal and/or state-listed plants and animals occur (or have occurred) in the six counties containing CREC and its associated transmission corridors (Table 6-2). County occurrences of federally protected species include 6 bird species, 2 mammal species, 8 reptile species, I amphibian species, I fish species and 8 vascular plant species. Eight federally protected animals have been observed within the CREC site boundary, including American alligators (Alligator mississippiensis), Florida manatees (Trichechus manatus latirostris),wood storks (M.lycteria americana), bald eagles (Haliaeetus leucocephalus), and four species of sea turtles: Kemp's ridley (Lepidochelys kenipii), green (Chelonia mydas), loggerhead (Carettacaretta) and hawksbill (Eretmochelys inibricata). The manatee and the four sea turtle species are discussed further under Aquatic Biota (Subsection 6.2.5). The American alligator is common throughout Florida, but is federally listed as "threatened due to similarity of appearance" to the threatened American crocodile (Crocodylus acutus). Non-Radiological Environmental Impacts 6-16 April 2011
Crystal River Unit 3 Extended Power Uprate TABLE 6-2. ENDANGERED AND THREATENED SPECIES IN CITRUS COUNTY AND COUNTIES CROSSED BY CR-3 TRANSMISSION L1NES. Federal State Scientific Name Common Name Statusa Statusa Countyb Birds Aphelocoma Florida scrub-jay T T Citrus, Hernando, coeruiescens Marion, Pasco, Pinellas, Sumter Charahriusalexandrinus Snowy plover T Pinellas Charadriusmelodus Piping plover T T Citrus, Hernando, Pasco, Pinellas Falco sparveriuspaulus Southeastern American T Citrus, Pasco, kestrel Hernando, Marion, Pinellas, Sumter Grus canadensis Florida sandhill crane T Citrus, Hernando, pratensis Marion, Pasco, Sumter Haliaeetus Bald eagle Citrus, Hernando, leucocephalus Marion, Pasco, Pinellas, Sumter Mtycteria americana Wood stork E E Citrus, Hernando, Marion, Pasco, Pinellas, Sumter Picoides borealis Red-cockaded woodpecker E E Citrus, Hernando, Marion, Pasco, Pinellas, Sumter Rostrhamus sociabilis Everglade snail kite E E Marion, Sumter plumbeus Sterna antillarum Least tern T Citrus, Hernando, Pasco, Pinellas Mammals Puma concolor coryi Florida panther E E Citrus, Marion Trichechus manatus Florida manatee E E Citrus, Hernando, latirostris Marion, Pasco, Pinellas Ursits amtericants Florida black bear T Citrus, Hernando, floridanus Marion, Pasco, Sumter Reptiles Alligator mississippiensis American alligator SAT SAT Citrus, Hernando, Marion, Sumter, Pasco, Pinellas Non-Radiological Environmental Impacts 6-17 April 2011
Crystal River Unit 3 Extended Power Uprate TABLE 6-2. ENDANGERED AND THREATENED SPECIES IN CITRUS COUNTY AND COUNTIES CROSSED BY CR-3 TRANSMISSION LINES (CONTINUED) Federal State Scientific Name Common Name Statusa Statusa Countyb Carettacaretta Loggerhead sea turtle T T Citrus, Hernando, Pasco, Pinellas Chelonia nodas Green sea turtle E E Citrus, Hernando, Pasco, Pinellas Dermochelys coriacea Leatherback sea turtle E E Citrus, Hernando, Pasco, Pinellas, Diymarchon corais Eastern indigo snake T T Citrus, Hernando, coujperi Marion, Pasco, Pinellas, Sumter Eretmochelys imbricata Hawksbill sea turtle E E Citrus Gopheruspolyphemus Gopher tortoise T Citrus, Hernando, Marion, Pasco, Pinellas, Sumter Lamproteltisextenuata Short-tailed snake T Citrus, Hernando, Marion, Pasco, Pinellas, Sumter Lepidochelys kempii Kemp's ridley sea turtle E E Citrus, Hernando, Pasco, Pinellas Neoseps revnoldsi Sand skink T T Marion Amphibians Ambystoma cingulatum Frosted flatwoods T T Marion salamander Fish Acipenser oxyrinchus Gulf sturgeon T T Citrus, Hernando desotoi Pasco, Pinellas Vascular Plants Acrostichum aureum Golden leather fern T Pinellas Adiantum lenerum Brittle maidenhair fern E Citrus, Hernando, Marion Agrimonia incisa Incised groove-bur E Citrus, Hernando, Marion Asplenium erosum Auricled spleenwort E Hernando, Pasco, Sumter Asplenium pumilum Dwarf spleenwort E Citrus, Hernando, Marion Asplenium verecundumn Modest spleenwort E Citrus, Sumter Bigelowia nuttallii Nuttall's rayless goldenrod E Pinellas Blechnum occidentale Sinkhole fern E Citrus, Hernando, Pasco 6-18 April 2011 Non-Radiological Environmental Impacts Non-Radiological Environmental Impacts 6-18 April 2011
Crystal River Unit 3 Extended Power Uprate TABLE 6-2. ENDANGERED AND THREATENED SPECIES IN CITRUS COUNTY AND COUNTIES CROSSED BY CR-3 TRANSMISSION LINES (CONTINUED) Federal State Scientific Name Common Name Status" Statusa Countyb Bonania grandiflora Florida bonamia T E Marion Calaminthaashei Ashe's savory T Marion Campanularobinsiae Brooksville bellflower E E Hernando Carex chapmanii Chapman's sedge T Marion Centrosema arenicola Sand butterfly pea E Citrus, Hernando, Marion, Pasco, Sumter Chaniaesycecunu/licola Sand-dune spurge E Pinellas Cheilanthes microphylla Southern lip fern E Citrus Coelorachistuberculosa Piedmont jointgrass T Hernando, Marion Chrsopsisfloridana Florida golden aster E E Pinellas Dicerandracornutissima Longspurred mint E E Marion, Surnter Drosera intermedia Spoon-leaved sundew T Marion Eragrostispectinacea Sanibel lovegrass E Pinellas tracVi Erigonum longifolium Scrub buckwheat T E Marion, Sumter var gnaphalifolium Euphorbiacommunta Wood spurge E Marion Fostieragodf!reyi Godfrey's privet E Marion Glandulariainaritimna Coastal vervain E Citrus Glandularia(= Verbena) Tampa vervain E Citrus, Pasco, tampensis Pinellas Gossypiurn hirsutum Wild cotton E Pinellas Harhvrightiafloridana Hartwrightia T Marion lllicium parviflorum Star anise E Marion Justiciacooleyi Cooley's water-willow E E Hernando, Sumter Lechea cernua Nodding pinweed T Pinellas Lechea divaricata Pine pinweed E Hernando, Pinellas Litsea aestivalis Pondspice E Marion, Pasco Mateleafloridana Florida spiny-pod E Citrus, Marion, Sumter Monotropa hypopithys Pinesap E Marion M'Ionolropsis reynoldsiae Pygmy pipes E Citrus, Hernando, Marion, Pasco Najasfilifolia Narrowleaf naiad T Marion Nemas'tvlisfloridana Celestial lily E Pasco Nolina atopocarpa Florida beargrass T Marion Nolina brittoniana Britton's beargrass E E Hernando, Marion, Pasco Ophioglossum palmatum Hand fern E Pasco Parnassiagrandifolia Large-leaved grass-of- E Marion parnassus Non-Radiological Environmental Impacts 6-19 April 2011
Crystal River Unit 3 Extended Power Uprate TABLE 6-2. ENDANGERED AND THREATENED SPECIES IN CITRUS COUNTY AND COUNTIES CROSSED BY CR-3 TRANSMISSION LINES (CONTINUED) Federal State Scientific Name Common Name Statusa Statusa Countyb Pecluniadisperssa Widespread polypody E Hernando, Marion Peclumaplumnula Plume polypody E Hernando, Mai-ion, Sumter Peclumaplilodon Swamp plume polypody E Citrus, Marion, Sumter Peperomia humilis Terrestrial peperomia E Citrus, Hernando, Sumter Polygala lewtonii Lewton's milkwort E E Marion Pteroglossaspisecrislata Giant orchid T Citrus, Hernando, Marion, Pinellas Pycnanthemnun Florida mountain-mint T Hernando, Marion floridanum Salix floridana Florida willow E Marion Schizachyrium niveum Scrub bluestern E Hernando Sideroxilon alachuense Silver buckthorn E Marion Sideroxvlon ljcioides Buckthorn E Marion Spigelia loganioides Pinkroot E Marion, Sumter Spiranthespolyantha Green ladies'-tresses E Citrus Stylisma abclita Scrub stylisma E Citrus, Marion Thelypleris reptans Creeping maiden fern E Citrus Trichomanespuctatum Florida filmy fern E Sumter ssp.floridanum Triphoracraigheadii Craighead's noddingcaps E Citrus, Hernando, Sumter Vicia ocalensis Ocala vetch E Marion
- a. E = Endangered; T = Threatened; - = Not listed; SAT =threatened due to similarity of appearance; S = species of special concern (FNAI 2010, USFWS 2010a).
- b. Source of County Occurrence: FNAI 2010, LUSFWS 2010a
- c. Although delisted as a federal endangered species, the bald eagle remnains federally protected under the Bald and Golden Eagle Protection Act.
Alligators are occasionally observed in swampy areas on CREC and undoubtedly occur in wetlands, swamps and ponds along the two transmission corridors associated with CR-3. Wood storks are federally listed (endangered) and typically feed on small fish in shallow, relatively open wetlands. There are no known nesting colonies or core foraging areas in or around the CREC site (USFWS 2010b). Wood storks have occasionally been observed around the property foraging in site ponds, impoundments, and ditches, and have also been seen in tidal creeks and wetland areas surrounding the CREC. Due to the species' rather specific dietary requirements and the need for shallow or draining wetlands where fish are trapped or Non-Radiological Environmental Impacts 6-20 Apri 121011
Crystal River Unit 3 Extended Power Uprate concentrated in isolated pools, it is believed that the small impoundments within the CREC do not provide high-quality foraging habitat for wood storks. Rapid water level changes; vegetation maintenance; movement and noise associated with workers, vehicles, and equipment; and pond maintenance activities all limit the suitability of on-site ponds as foraging habitat for wood storks. It is more likely that wood storks occasionally use the property in transit as they move through the area to higher quality, offsite foraging habitat. Bald eagles have been recently de-listed, but remain federally protected under the Bald and Golden Eagle Protection Act (USFWS 2007). There is one bald eagle nest on-site, in the southeast corner of the CREC property approximately 1.9 miles from CR-3. Another bald eagle nest is located just off-site, approximately 1.2 miles northwest of CR-3. Both nests were active over the 2002-2007 period. During this same six-year period, there were approximately 200 eagle nests reported in the counties containing CR-3 associated transmission corridors. The two closest bald eagle nests were within 0.1 and 0.6 mile of the Lake Tarpon and Central Florida transmission corridors, respectively. Although not observed on the CREC site, federally listed (threatened) Florida scrub jays (Apheloconia coerulescens) have been observed at various locations within the transmission corridors. No other federally listed species has been documented on CREC or its transmission corridors. Additional state-listed fauna and flora are reported for the six Florida counties containing the CREC and its transmission corridors (Table 6-2). These include birds (4 species), mammals (1 species), reptiles (2 species) and vascular plants (51 species). Gopher tortoises (Gopherus polyphemus), which are known for digging extensive burrow systems used by many wildlife species, are state-listed as threatened. They have been observed on the CREC property, in upland areas adjacent to the existing rail line but outside of the project area (PEF 2007a). They also occur at several locations within transmission corridors associated with CR-3. During corridor maintenance activities, Progress Energy policy is to avoid using heavy equipment (such as tractors) within 25 feet of gopher tortoise burrows. Vegetation is instead cut by hand, to avoid potential damage to the burrows by heavy equipment. 6.1.8.1 EPU ALTERNATIVE - HELPER COOLING TOWER OPTION The new HCTS would be built approximately 3,400 feet west of CR-3 (see Figure 6-2). It would require approximately 18 months to build the new HCTS, a period when construction noise levels would be relatively high and wildlife could be disturbed. In addition there would be disturbance associated with movement of personnel and heavy equipment and there could also be disturbance associated with night lighting. Because implementing the Helper Cooling Tower Option would only impact previously-disturbed land, would be associated with activities that disturb wildlife only during the 18-month-long construction phase, would not require transmission system changes (i.e., new towers, lines or substations or changes in right-of-way Non-Radiological Environmental Impacts 6-21 April 2011
Crystal River Unit 3 Extended Power Uprate maintenance practices), impacts to terrestrial biota (including threatened and endangered species) would be small. 6.1.8.2 EPU ALTERNATIVE - LOAD REDUCTION MANAGEMENT OPTION If this cooling option were to be implemented, there would be considerably less disturbance of wildlife, as virtually all of the EPU-related work would take place indoors. There would be some disturbance associated with an additional 1,350 commuting workers involved in EPU-related activities, but this disturbance would cease when the project was completed. 6.1.8.3 NO ACTION ALTERNATIVE Under the No Action Alternative, there would be no construction, no additional workers on site, and impacts to terrestrial wildlife would be those associated with normal operations. 6.2 HYDROLOGY AND AQUATIC RESOURCES 6.2.1 COOLING WATER SYSTEM As discussed in Section 3.0, CR-3 is part of the larger CREC, which includes the single nuclear unit and four fossil-fuieled units, Crystal River Units 1, 2, 4, and 5. Fossil Units 1, 2, and CR-3 employ once-through cooling, withdrawing from and discharging to the Gulf of Mexico. Units 4 and 5 are closed-cycle units that withdraw water for cooling tower makeup from the discharge canal for Units 1, 2, and 3. During certain times of the year (May I through October 31), a portion of the heated discharge from Units 1, 2, and 3 is routed through helper cooling towers designed to lower discharge temperatures (Golder Associates 2006). The helper cooling towers are operated as necessary to ensure that the discharge temperature does not exceed 96.5°F (as a three-hour rolling average) at the POD to the Gulf of Mexico. The design intake flow for CR-3 is 680,000 gallons per minute (gpmn) or 979 million gallons per day (MGD). Service water pumps at CR-3 withdraw an additional 10,000-20,000 gpm, depending on system demand (Golder Associates 2006). Units 1, 2, and 3 have a total design flow of approximately 1,318,000 gpm, or 1,898 MGD. The National Pollutant Discharge Elimination System (NPDES) permit for Units 1,2, and 3 limits the combined condenser flow to 1897.9 MGD over the May I - October 31 period, and 1613.2 MGD from November I through April 30. A portion of the discharge from the once-through cooling systems of Units 1, 2, and 3 is withdrawn as cooling tower makeup for Units 4 and 5. Four permanent helper cooling towers (36 cells) line the northern bank of the discharge canal and receive a portion of the circulating water flow. The helper cooling towers were installed to allow Units 1, 2, and 3, which have a combined discharge, to meet the NPDES (3-hour rolling average) discharge limit of 96.5°F in warmer months. In April 2006, Progress Energy received approval from the state of Florida to install up to 70 additional modular cooling towers. Sixty-seven of the modular cooling towers were ultimately put into service. During hot summers in recent years, Progress Energy has occasionally chosen to reduce power at coal-fired Units I and 2 Non-Radiological Environmental Impacts 6-22 April 2011
Crystal River Unit 3 Extended Power Uprate to stay within NPDES permit thermal limits. The additional modular towers were installed to reduce the frequency of de-rates during the warmest times of the year. Increasing CR-3's thermal power level would increase the amount of steam generated and the temperature of circulating water. As discussed in detail in the Project Alternatives section, PEF is considering two possible strategies for mitigating the increased heat loading to the discharge-a helper cooling tower or load reduction management. Regardless of the cooling option chosen, PEF intends to comply with the current NPDES discharge limit of 96.5' (three hour rolling average). 6.2.2 DISCHARGES Surface water and wastewater discharges at the CREC are regulated by the state of Florida. The NPDES permit is periodically reviewed and re-issued by the FDEP's Division of Water Resource Management. The current NPDES permit (FL0000159)was issued on May 9, 2005 and expired on May 8, 2010., An NPDES permit application was submitted October 30, 2009, therefore the existing NPDES permit has been administratively extended. This permit authorizes PEF to discharge once-through condenser cooling water from three outfalls (D-01 1. D-012, and D-0 13) to the site discharge canal and ultimately the Gulf of Mexico. The NPDES permit for Crystal River Units 1, 2, and 3 contains limits on discharge flow, chlorination duration, total residual oxidants (TROs), and temperature. The permit limits the combined discharge flow from Units 1, 2, and 3 to 1,897.9 MGD over the May 1-October 31 period and 1,613.2 MGD during the remainder of the year. The discharge of chlorine/TRO from the condenser of each unit may not exceed a maximum of 60 minutes in any calendar day. The maximum instantaneous TRO concentration at any of the three outfalls (D-01 , D-0 12, or D-013) may not exceed 0.01 milligrams per liter (mg/L). The discharge temperature may not exceed 96.5'F as a three-hour rolling average. The CR-I, -2, and -3 NPDES permit stipulates that a permit revision from FDEP shall be required prior to the use of any biocide or chemical additive used in the cooling system or any other portion of the treatment system which may be toxic to aquatic life. The permit also authorizes use of the existing Amertap Condenser Cleaning System at CR-3, "or an equivalent system." The permit notes that any substantive change to the Amertap system must be approved by FDEP. The new HCTS associated with the Helper Cooling Tower Option would operate as a once-through or "single pass" cooling tower (i.e., no recirculation), discharging to the intake canal or discharge canal depending on the season and plant operating conditions. The HCTS has been designed to allow sections of cooling tower cells to be taken out of service, allowing the cells to dry out and eliminate bio-fouling organisms. For this reason, PEF does not anticipate using any chemicals or biocides in the cooling tower. The evaporation associated with the new HCTS is estimated to be about 1.5 percent of the total tower flow or 4,800 gpm, an amount that would not significantly increase total dissolved solids (TDS) concentrations in the cooling water discharge. Non-Radiological Environmental Impacts 6-23 April 2011
Crystal River Unit 3 Extended Power Uprate At this evaporation rate, the increase in TDS concentration assuming an existing value of 28,000 mg/L would be about 426 mg/L. PEF would request modification of the NPDES permit to authorize operation of the new HCTS if this option is selected. It is during this permit modification process that actual operational procedures, discharge locations, and timeframes would be established. 6.2.3 ENTRAINMENT AND IMPINGEMENT The current EPU Project Plan calls for no increase in the volume of water withdrawn from the Gulf of Mexico for condenser cooling, regardless of the cooling option chosen, thus there would be no increase in current levels of impingement and entrainment at the CR-3 cooling water intake structure. Should the Helper Cooling Tower Option be selected, PEF plans to route a portion of the discharge from the HCTS to the site intake canal in late fall and winter. This would have the effect of reducing the amount of water withdrawn from the Gulf of Mexico because some of the "used" cooling water (water that has already gone through the plant) would be recycled. This could slightly reduce entrainment since there would be a reduction in the overall amount of ocean water used (although the intake flow would remain unchanged). During warmer months, the cooling tower discharge would be routed to the site discharge canal. 6.2.4 THERMAL DISCHARGE EFFECTS As noted previously, PEF currently uses four permanent helper cooling towers and an array of smaller, leased modular towers in summer to meet the NPDES discharge limit of 96.5°F. Should PEF decide to implement the Helper Cooling Tower Option, the cooling tower would be sized to accommodate EPU heat loads and meet current discharge limits, and would also allow PEF to retire the 67 temporary modular towers. Should the Load Reduction Management Option be selected, both the permanent and leased cooling towers would continue to operate and discharge canal temperatures would be reduced, as necessary, by reducing power at Unit I or Unit 2 (or both), thereby reducing the thermal output to the discharge canal. In either case, PEF would comply with applicable NPDES temperature limits. The two options differ in that the Load Reduction Management Option is expected to extend the period in which (currently-installed) cooling towers are used, with an earlier seasonal start date and later seasonal end date. 6.2.5 AQUATIC BIOTA The two most comprehensive sources of information on the aquatic biota of the CR-3 area are the Final Environmental Statement related to the proposed Crystal River Unit 3 (FES) (AEC 1973) and the Crystal River Units 1, 2, and 3 (Section) 316 Demonstration (SWEC 1985). Although three and two decades old, respectively, these documents contain useful information on the oceanography (bathymetry, currents, tides, water quality) and marine/estuarine communities of the Crystal Bay area. The Physical Setting Non-Radiological Environmental Impacts 6-24 April 2011
Crystal River Unit 3 Extended Power Uprate The Crystal River site is on Crystal Bay, a shallow embayment of the Gulf of Mexico. As far out as Fisherman's Pass, approximately three miles west of the site, the depth of the Bay is less than 10 feet (SWEC 1985). Shallow inshore areas are characterized by oyster bars (or oyster "reefs") oriented parallel to shore that are visible at low tide and covered by water at high tide. These oyster bars, composed mostly of broken shell, create numerous small basins with north-south orientation in the area of the intake and discharge canals. Salinity in the area of the plant ranges from 22 to 29 parts per thousand (ppt), depending on freshwater inflows to Crystal Bay from rivers and creeks in the area (AEC 1973). Eight to ten miles offshore, in the Gulf of Mexico, the salinity is more typical of open ocean waters, approximately 35 ppt. Water temperatures in the area are lowest in December-January and highest in late summer (July-September). Temperatures as high as 92°F were measured in the general area of the plant (Cedar Keys) prior to CR-3 operation, but more typically average in the mid-to-high 80s in late summer (AEC 1973, Appendix D). Water temperatures in mid-winter can approach 40'F in shallow areas, but are generally in the 50s (AEC 1973, Appendix D). Biological Communities Shoreline Marshlands A well-developed, 0.5 to 1.0 mile-wide band of marshland extends up and down the coast in the Crystal River area, separating the uplands to the east from the Gulf of Mexico. These marshlands are drained by numerous small creeks. The marshlands in the vicinity of the site are typical of those found up and down this part of the Gulf Coast, with Juncus and Spartina the dominant marshland plants. These marshlands and associated creeks provide habitat for a variety of invertebrate organisms, including oysters and crabs, and are nursery areas for finfish including mullet (Mugil spp.), spot (Leiostonus xanthurus), black drum (Pogonia cromis), red drum (Sciaenops ocellatus), and croaker (Micropogonias undidatus) (AEC 1973). Seagrasses Five species of seagrass were found in shallow water adjacent to the site prior to plant startup (AEC 1973). Three species were most abundant: shoal grass (Halodule wrightii), widgeon grass (Ruppia maritima), and turtle grass (Thalassia testudinum). Manatee grass (Syringodium filiforme) and star-grass (Halophila engelmanni) were also present. Seagrass beds often contained dense assemblages of rooted green algae, primarily Caulerpa spp. Limestone outcroppings were colonized by rockweeds, such as Sargassum. The same five seagrass species were observed by biologists conducting studies in the Crystal Bay area in support of the Crystal River Section 316 Demonstration in 1983-1984 (SWEC 1985). These operational surveys confirmed what studies in the 1970s had suggested: that the heated effluent from the plant influenced seagrass abundance and distribution in the immediate area of the discharge (SWEC 1985). In 1983-1984, shoalgrass was the only seagrass species observed at Station D, northwest of the plant's discharge canal and the station most obviously affected by the Non-Radiological Environmental Impacts 6-25 April 2011
Crystal River Unit 3 Extended Power Uprate plant's heated discharge (SWEC 1985). Shoal grass often colonizes areas where other, more-sensitive seagrasses cannot grow (FOCC 2003). It may be locally dominant in disturbed areas and areas subject to salinity and temperature extremes. More seagrass species were observed at Stations E and F, which were further offshore but still affected by the plant's thermal discharge. The greatest number of species was observed at stations (A, B, C) south of the intake canal and outside of the influence of the plant's heated discharge. Benthic Invertebrates Preoperational surveys of marine benthos at the Crystal River site identified 286 species, including Carolinian (Atlantic Coast) and West Indian species (AEC 1973). Most of these were widely distributed forms capable of withstanding a wide variation of environmental conditions (fluctuating temperature and salinity). Thirty mollusk species were characterized as "common" or "abundant," including 22 marine gastropods (snails) and 8 marine pelecypods (bivalves). The following mollusks were described as "abundant" in the vicinity of the Crystal River plant: Bittium varium (variable bittium), Anachis senziplicata (sem iplicate doveshell), Mitrella hlnata (hlmar doveshell), Nassarius vibex (common eastern nassa), Brachidontes exustus (scorched mussel), Musculus lateralis (lateral musculus), and Crassostrea virginica (American oyster). Other important groups were Polychaetes (six families), Isopods (four species), and Decapods (eight species, including pink shrimp (Farfantepenaeusduorarum). Fisheries The FES (AEC 1973) for CR-3 lists 64 finfish species and 6 shellfish species commonly found in the Crystal River area that are either commercially/recreationally important or important as "food chain species" (serving as a food source for other, more-important species). The four finfish species collected most often in pre-operational (1969-1970) surveys were silver perch (Bairdiella chiysoura), spot, pigfish (Orthopristis chiysoptera), and pinfish (Lagodon rhomboides). American oyster, blue crab (Callinectes sapidus), stone crab (Menippe mercenaria), and pink shrimp were the most important shellfish. Extensive studies of adult and juvenile fish were carried out in support of the Crystal River 316 Demonstration (SWEC 1985) and are perhaps the best source of information on the area's fisheries. Fish were collected monthly over the June 1983-May 1984 period using a variety of sampling gear intended to capture fish occupying a range of marine (offshore and inshore) and estuarine (creeks) habitats. Trawls captured 98 species of fish and 108 species of invertebrates in the general vicinity of the plant (SWEC 1985). Catch varied by season, with highest numbers in the spring and summer (April through August) and lowest numbers in January and February. Although there was considerable variability in the data, some trends were apparent. Lowest densities of fish and invertebrates were observed along the central transect (stations T4, T5, and T6), the transect Non-Radiological Environmental Impacts 6-26 April 2011
Crystal River Unit 3 Extended Power Uprate most affected by the plant's heated discharge. Transects to the north (stations TI, T2, and T3) and south (stations T7, T8, and T9) had similar densities of fish, and were both higher than the central transect. With regard to important species, spot were present year-round and were captured in highest numbers at northern transects (TI, T2, and T3). Pigfish were collected primarily in spring and summer, but were found in greater concentrations at southern transects. Pinfish were collected mostly in spring and summer, but were collected in substantial numbers at both northern and southern transects. Seine collections in 1983-1984 produced 49 species of fish and 15 invertebrate species (SWEC 1985). Fish captured in highest numbers were usually juveniles of schooling species, such as spot and bay anchovy. Highest densities were generally observed in June and July and lowest densities were normally observed in fall, winter, and spring. Large numbers of spot, clupeids, and anchovies were sometimes captured during these "slow" periods, however, as schools of these small fish moved into nearshore shallows where they were more vulnerable to capture by seiners. Creek trawls collected 43 species of fish and 27 species of invertebrates. The largest numbers of fish were collected from January through May with the peak in March (SWEC 1985). Juveniles dominated all creek samples. Fish biomass was also highest in the spring, with a secondary peak in November. Invertebrate numbers were highest from November through March. Fish and invertebrate densities were highest at Station TC2, a creek north of the discharge canal. They were lowest at Stations TCI, a creek north of the discharge canal, and TC4, a creek south of the intake canal. Stock Enhancement, Flow Reduction, and SeagrassRestoration, 1991-Present As discussed previously in this section, FPC conducted studies at Crystal River in the 1970s and again over the 1983-1984 period to gauge the impact of the Crystal River (Units 1, 2, and 3) cooling water system on local and regional fish populations (SWEC 1985). In January 1985, FPC submitted a Clean Water Act Section 316 Demonstration study to the EPA that evaluated both cooling water intake system impacts and thermal impacts, as required by the plant's NPDES permit. After reviewing the 1985 Section 316 study, the EPA concluded that entrainment and impingement losses were unacceptably high and indicative of an "adverse impact to the biota of Crystal Bay and environs" (Golder Associates 2006). FPC and the EPA considered a range of potential mitigation measures and ultimately determined that flow reduction and stock enhancement (rearing and stocking important fish species) showed the most potential for mitigating entrainment and impingement losses at the plant's CWIS. The EPA in consultation with FDEP also issued a public notice at this time asserting that "substantial damage" had been done to 1,100 acres of Crystal Bay, primarily from the thermal discharge from Units 1, 2, and 3 (FPC 1996). Non-Radiological Environmental Impacts 6-27 April 2011I
Crystal River Unit 3) Extended Power Uprate In September 1988, following several years of feasibility studies, engineering studies, and negotiations, the EPA issued an NPDES permit with the following requirements: installation of flow reduction equipment at Crystal River Units I and 2 to reduce cooling water flows by 15 percent (no more than 1,613.2 MGD over the November 1 - April 30 period); construction and operation of a multi-species mariculture facility to mitigate for intake impacts to fisheries; and construction and operation of helper cooling towers to mitigate for thermal impacts to water quality and seagrasses (FPC 1996). In October 1991, as part of a negotiated settlement with EPA, FPC opened the Crystal River Mariculture Center, a multi-species marine hatchery intended to mitigate impacts of the Crystal River plant's once-through cooling system (FWC undated). Flow reduction was implemented in May 1992. The helper cooling towers, designed to ensure a maximum discharge temperature at the Crystal River site POD of 97 0 F, were placed in service in 1993. FPC monitored seagrass recovery in the area of the POD for three years, from 1993 through 1995 (FPC 1996). The results, although promising, were not conclusive. In 2001, FPC and Coastal Seas Consortium, Inc. (CSC) re-surveyed areas that had been surveyed in the 1990s to determine to what extent these areas had been re-colonized by seagrasses. The re-surveys revealed that the seagrass Halodule wrightii (shoal grass) had spread throughout Basins I and 2, the basins most affected by the CR-I, -2, and -3 discharge. Halodule wrightii had become established in virtually all areas with suitable substrate and depth. Basin I, the area most directly affected by the thermal discharge, was "...more or less a continuous bed of seagrass..." (CSC 2002). The authors of the CSC report noted that shoalgrass is an early colonizer of previously-barren areas (an early successional species) and speculated that other seagrasses (Thalasscia and Syringodium) would subsequently become established. The effect of the 15 percent flow reduction implemented in 1992 was to reduce the rate of entrainment at the CR-i, -2, and -3 cooling water intake structure, as the rate of entrainment is proportional to the rate of cooling water withdrawal. Impingement, although less directly affected by withdrawal rate, was presumed to be substantially reduced as well. The beneficial effect of the 15 percent flow reduction is compounded by the fact that flow reduction is imposed during the period (fall-winter-early spring) when many important fish species are found inshore. The work of the Crystal River MaricultUre Center further mitigates impacts of Crystal River Units 1, 2, and 3 cooling system operation. Although 12 finfish and shellfish species have been cultured at the Mariculture Center, red drum, spotted seatrout, and pink shrimp are the primary species (FWC undated). Since opening in 1991, the Mariculture Center has reared and released 2.25 million juvenile red drum, spotted seatrout, and pink shrimp in local coastal waters (mostly Citrus County) (Progress Energy 2009b). A certain number of fish in each stocking are tagged, so that survival and movement can be assessed. Based on tag returns, a substantial number of stocked fish survive to adulthood (or catchable size), enhancing fishing opportunities in the region. Non-Radiological Envirormnental Impacts 6-28 April 2011
Crystal River Unit 3 Extended Power Uprate Sensitive Aquatic Species The Gulf sturgeon (Acipenseroxyrinchus desotoi) is a large (to 8 feet in length) anadromous fish that inhabits Gulf Coast rivers from Louisiana to Florida (USGS 2006). A sub-species of the Atlantic sturgeon, the Gulf sturgeon was listed by the USFWS and National Marine Fisheries Service (NMFS) as threatened in 1991 (USGS 2006). Adult and sub-adult sturgeon ascend Gulf Coast rivers in early spring to spawn, when water temperatures range from 61-75°F, remain in these rivers for 8 or 9 months, and then move back to the Gulf in September or October, when water temperatures return to the 70s (GSRT 1995). Gulf sturgeon reach sexual maturity between the ages of 8 and 12 years. and can live as long as 25 years (USGS 2006). The status of the Gulf sturgeon, including several Florida populations, was reviewed in The Gulf Sturgeon Recovery/Management Plan (GSRT 1995). The Plan noted that the Suwannee River (approximately 35 miles northwest of CR-3) supported the most important population in Florida, and estimated this population at from 2,250 to 3,300 individuals. Large numbers of Gulf sturgeon were caught by commercial fishermen in Tampa Bay in the late 1880s, but this population was virtually eliminated by overfishing (GSRT 1995). Although individual sturgeon were occasionally caught in the Tampa Bay area by commercial fishermen in the 1980s and 1990s (GSRT 1995) or in more recent years found dead on area beaches (Minai 2002), this population is no longer considered self-sustaining. These fish were probably strays from the Suwannee River area (Minai 2002). Critical Habitat for the Gulf sturgeon was designated in 2003 (Federal Register Volume 68, No. 53, March 19, 2003, pp. 13370-13495), and includes riverine and estuarine/coastal areas of Alabama and Florida. The riverine Critical Habitat closest to CR-3 is the East Pass of the Suwannee River, which is approximately 33 miles northwest of the Crystal River site (68 FR 53, Map 7.2). The nearest estuarine/coastal Critical Habitat is Suwannee Sound, the southern boundary of which is approximately 30 miles from the Crystal River site (68 FR 53, page 13495). . No Gulf sturgeon were captured or observed in the vicinity of CR-3 during pre-operational surveys in the 1970s or operational surveys in the 1980s. Although there has been no systematic monitoring in recent years, no sturgeon have been observed by PEF environmental personnel in the intake or discharge canal or by operations personnel involved in removing fish and debris washed into sumps from travelling screens. Florida manatees are large aquatic mammals that feed on seagrass and other aquatic vegetation. They are protected under the Endangered Species Act, the Marine Mammal Protection Act, and the Florida Manatee Sanctuary Act. Citrus County has an approved manatee protection plan as guidance for coastal development. Manatees require warm water temperatures (> 68°F) and thus tend to inhabit springs and power plant discharge areas during the winter months. Manatee sightings in the CREC discharge canal typically occur in the fall and winter months. Progress Energy has implemented a Manatee Protection Plan to minimize potential hazards to manatees at the intake and outfall areas. Non-Radiological Environmental Impacts 6-29 April 2011
Crystal River Unit 3 Extended Power Uprate Sea turtles have been observed in the CREC intake canal and have been occasionally found (stranded) on the CR-3 intake bar racks since the 1990s. The Kemp's ridley sea turtle is the species most often observed at CREC, followed by the green sea turtle, with loggerhead and hawksbill sea turtles less frequently observed. Due to an unusually high number of strandings of Kemp's ridleys (approximately 50) in 1998, a Biological Opinion was issued by the NMFS in 1999 which determined that CREC operations would not jeopardize the existence of sea turtles in this region. A second Biological Opinion was issued in 2002 which determined that continued operation of the CREC and its cooling system would not jeopardize sea turtle populations and included an Incidental Take Statement allowing live takes of 75 sea turtles annually and three annual lethal takes that are causally related to plant operations (NMFS 2002). CREC initiated a continuous monitoring and rescue program in 1998 (PEF undated) to reduce potential sea turtle strandings and mortalities due to facility operations. 6.2.5.1 EPU ALTERNATIVE - HELPER COOLING TOWER OPTION Given that there would be no net increase in cooling water withdrawal for CR-3 and no increase in discharge temperatures under this option, impacts to aquatic communities would be small and would continue to be mitigated by measures (i.e., flow reduction and stock enhancement) discussed previously that were implemented in the 1980s and 1990s. Likewise, impacts to sensitive and protected estuarine/marine populations, including Gulf sturgeon, manatees, and sea turtles would be small. As noted in Section 6.2.3, routing a portion of the cooling tower discharge to the intake canal in late fall and winter could slightly reduce entrainment at the circulating water intake. The NPDES permit for Crystal River Units 1, 2, and 3 (FL00059) requires PEF to prepare a Plan of Study (POS) for evaluating compliance with Rule 62-302.520(l)(a) of the Florida Administrative Code, which states that facilities with heated water discharges " shall not increase the temperature of the RBW (receiving body of water) so as to cause substantial damage or harm to the aquatic life or vegetation therein or interfere with beneficial uses assigned to the RBW." PEF submitted a draft POS on September 17, 2007 that includes (Phase 1) plans for delineation of the thermal plume in spring, summer, and fall (April-October) and an assessment of potential biological impacts. Once Phase I work has been completed, PEF will present (Phase 11) recommendations for monitoring of potentially impacted seagrass beds and benthic macroinvertebrates. The POS is being reviewed by FDEP along with the NPDES permit renewal application that was submitted on October 30, 2009. PEF anticipates that the renewed permit will contain dates by which the various phases/elements of the thermal plume study shall be completed. 6.2.5.2 EPU ALTERNATIVE - LOAD REDUCTION MANAGEMENT OPTION If this option is implemented, there would be no net increase in cooling water withdrawal and no increase in discharge temperatures. Impacts to aquatic communities would be small, and would Non-Radiological Environmental Impacts 6-30 April 2011
Crystal River Unit 3 Extended Power Uprate continue to be mitigated by the measures (i.e., flow reduction and stock enhancement) discussed previously. 6.2.5.3 NO ACTION ALTERNATIVE Impacts to aquatic communities would be those associated with normal (on-going) operations. 6-31 April 2011 Environmental Impacts Non-Radiological Environmental Impacts 6-31 April 2011
Crystal River Unit 3 Extended Power Uprate 7.0 RADIOLOGICAL ENVIRONMENTAL IMPACTS 7.1 RADIOACTIVE WASTE STREAMS 7.1.1 EPU ALTERNATIVE - HELPER COOLING TOWER AND LOAD REDUCTION OPTIONS The radioactive waste systems at CR-3 are designed to collect, process, and dispose of radioactive wastes in a controlled and safe manner. The design bases for these systems during normal operation are to limit discharges in accordance with 10 CFR 20, to limit exposures to the requirements of 40 CFR 190, and to satisfy the design objectives of 10 CFR 50 Appendix 1. Adherence to these limits and objectives would continue under the proposed EPU. Operation at EPU conditions would not result in any physical changes to the solid waste, liquid waste, or gaseous waste systems. The safety and reliability of these systems would be unaffected by the proposed EPU. Also, the EPU would not affect the environmental monitoring of any of these waste streams or the radiological monitoring requirements of the CR-3 Offsite Dose Calculation Manual (ODCM). Under normal operating conditions, the EPU would not introduce any new or different radiological release pathways and would not increase the probability of an operator error or equipment malfunction that would result in an uncontrolled radioactive release from the radioactive waste streams. Additionally, the reduction of radioactive waste volumes is a routine component of plant operations. The specific effects of the proposed EPU on each of the radioactive waste systems are evaluated in the following sections. 7.1.1.1 SOLID WASTE Solid radioactive wastes include solids recovered from the reactor process system, solids in contact with reactor process system liquids or gases, and solids used in the reactor process system operation. The largest volume of solid radioactive waste at CR-3 is low-level radioactive waste (LLRW). Sources of LLRW at CR-3 include resins and charcoal, sludges and filters from water processing, dry active waste (DAW) from outages and routine maintenance, and oil from plant systems. DAW includes paper, plastic, wood, rubber, glass, floor sweepings, cloth, metal, and other types of waste routinely generated during site maintenance and outages. Table 7-1 presents the annual volume and activity of LLRW generated at CR-3 for the period 2004 through 2008 by waste type. Impacts 7-I April 2011 Environmental Impacts Radiological Environmental 7-1 April 2011
Crystal River Unit 3 Extended Power Uprate TABLE 7-1. CR-3 LOW-LEVEL RADIOACTIVE WASTE GENERATION BY WASTE TYPE, 2004 - 2008. Spent resins, filter Dry compressible sludges, waste, equipment, Other Total evaporator etc. bottoms, etc. Year Ft3 Ci Ft 3 Ci Ft3 Ci Ft3 Ci 2004 2,497 193 11,050 0.175 1,487 2.39 15,040 2.58 2005 480 506 13,000 82.9 600 1.59 14,080 591 2006 1,536 211 3,920 0.114 206 4.18 5,662 4.32 2007 306 476 12,010 1.38 604 2.65 12,920 480 2008 2,133 343 7,063 0.36 1,282 8.86 10,480 352 Source: PEF 2005. 2006b. 2007b, 2008, 2009 An evaluation by AREVA and PEF determined that there would be no significant increase in the generation of solid radioactive waste including DAW, however there may be an increase in the activity of the generated waste. 7.1.1.2 LIQUID WASTE Liquid radioactive wastes include liquids from the reactor process systems and liquids that have become contaminated with process system liquids. Table 7-2 presents liquid releases from CR-3 for the period 2004 through 2008. These values are assumed to be representative of future normal operations. Liquid effluent release volumes and activity are not expected to increase significantly as a result of EPU because the concentration would continue to be reduced to minimal levels due to operation of the liquid waste disposal system (LWDS). The offsite radiation dose consequences of these effluent releases are described in Section 7.2. 7-2 April 2011 Radiological Environmental Impacts Radiological Environmental Impacts 7-2 April 2011
Crystal River Unit 3 Extended Power Uprate TABLE 7-2. LIQUID EFFLUENT RELEASES FROM CR-3, 2004 -2008. Fission and Activation Dissolved and Gallons Products Activity Released Tritium Entrained Gases Year Released (mCi) (mCi) (mCi) 2004 10,700,000 10.9 506,000 99.7 2005 8,050,000 104 694,000 87.2 2006 7,990,000 16.9 311,000 13.9 2007 7,690,000 10.1 713,000 35.8 2008 10,200,000 7.4 347,500 10.0 Source: PEF 2005, 2006b, 2007b, 2008, 2009. 7.1.1.3 GASEOUS WASTE Gaseous radioactive wastes principally include activation gases and fission product radioactive noble gases vented from process equipment and, tinder certain conditions, building ventilation exhaust air. Table 7-3 presents gaseous releases from CR-3 for 2004 through 2008. Radioactive releases with EPU are expected to increase in approximate proportion to the increase in power level. Using the five-year average of gaseous releases as representative of future normal operations, this would result in releases of approximately 4.93 curies (Ci) of noble gases, 3.90X10-6 Ci of particulates and iodines, and 28 Ci of tritium annually after EPU. The offsite radiation dose consequences of these effluent releases are described in Section 7.2. TABLE 7-3. GASEOUS EFFLUENT RELEASES FROM CR-3, 2004 -2008. Fission and Particulates and Tritium Activation Gases Iodines (Ci) Year (Ci) (Ci) 2004 26.40 1.21 x 10-6 5.66 2005 47.20 5.86x 1 0- 5 7.64 2006 4.31 2.02x 10-6 7.84 2007 4.45 1.93X 10-6 11.9 2008 3.27 3.99x 10-6 15.6 Source: PEF 2005, 2006b, 2007b, 2008, 2009. Radiological Environmental Ininacts 7-3 Anril 2011
Crystal River Unit 3 Extended Power Uprate 7.1.2 NO ACTION ALTERNATIVE Under the No Action Alternative, CR-3 would continue to operate at the currently licensed power level of 2,609 MWt and there would be no changes in radioactive waste streams from plant construction activities or operations related to EPU. 7.2 RADIATION LEVELS AND OFFSITE DOSE 7.2.1 EPU ALTERNATIVE - HELPER COOLING TOWER AND LOAD REDUCTION OPTIONS 7.2.1.1 OPERATING AND SHUTDOWN IN-PLANT LEVELS In-plant radiation levels and associated doses are controlled by the ALARA (As Low As Reasonably Achievable) program, as required by 10 CFR 20. PEF has a policy of maintaining occupational dose to the individual and the collective doses received by all exposed workers to ALARA levels. This ALARA philosophy is implemented in a manner consistent with CR-3 operating, maintenance, and modification requirements and accounts for the state of technology, the economics of improvements relative to the state of technology, the economics of improvements relative to public health and safety benefits, the public interest relative to utilization of nuclear energy and licensed materials, and other societal and socioeconomic considerations. Table 7-4 presents the collective CR-3 occupational radiation doses for 2002 through 2007. Because of CR-3's two year refueling cycle, there is a significant difference in collective doses for refueling outage years and non-refueling outage years. Averaging the collective dose values for the six years, which covers three refueling cycles, results in an annual collective dose of 74.5 person-remn. In calendar year 2007, the average annual collective dose per reactor for light water reactors was 97 person-remn (NRC 2008). Considering a proportional increase in collective dose equivalent to the percentage increase of the EPU, average annual collective dose would be expected to increase to 85.7 person-rein per year. 7-4 April 2011 Radiological Environmental Impacts Radiological Environmental Impacts 7-4 April 2011
Crystal River Unit 3 Extended Power Uprate TABLE 7-4. COLLECTIVE OCCUPATIONAL RADIATION DOSE AT CR-3, 2002 - 2007. Collective dose Year (person-rem) 2002 5.0 2003 126.6 2004 4.0 2005 122.6 2006 4.5 2007 184.6 Source: NRC 2003. 2004b, 2005, 2006, 2007, 2008. The CR-3 ALARA program manages exposure by:
- Minimizing the time personnel spend in radiation areas,
- Maximizing the distance between personnel and radiation areas,
" Maximizing shielding to minimize radiation levels in routinely occupied plant areas and in the vicinity of plant equipment requiring attention, and
- Reducing the amount of radioactive material that could lead to worker radiation doses (source term reduction).
Normal operation radiation levels are expected to increase by the approximate percentage increase of the EPU. Impacts could result from increasing the core power level on neutron flux and gamma flux in and around the core, increases in fission product and actinide activity inventory in the core and spent fuiels, increased N-16 source in the reactor coolant, increased neutron activation in the vicinity of the reactor core, and increases in fission/corrosion products activity in the reactor coolant and downstream systems. Shielding is used throughout the plant to protect personnel against radiation emanating from the reactors and their auxiliary systems, and to limit radiation damage to operating equipment. PEF has reviewed the current radiation shielding and plant radiation zoning in relation to the projected increase in dose rates due to EPU and proposed appropriate plant changes. Radiation measurements will be taken during Startup Testing to validate radiation zoning and ALARA program compliance. The increase in radiation levels is not expected to have any significant effect on the plant radiation shielding and would be offset by conservatism in the original design, source terms used, and analytical techniques. Therefore, no new dose reduction programs are planned and the ALARA program would continue in its current form. Radiological Environmental Impacts 7-5 April 2011
Crystal River Unit 3 Extended Power Uprate 7.2.1.2 OFFSITE DOSES AT EPU CONDITIONS Offsite doses from radioactive effluents and direct radiation are calculated at CR-3 by measuring the concentration of radioactivity in the liquid and gaseous effluents to determine the total amount of each radionuclide released through these pathways, then applying computer models, as described in the ODCM, to calculate radiation doses from these measured releases. Under EPU conditions, the increase in the amount of radioactivity released, and thus the offsite doses, could be considered to be approximately proportional to the increase in reactor coolant activity, which in turn, could be proportional to the increase in core inventory. Therefore, a scaling factor could be used to increment offsite doses from the current CR-3 doses. The highest annual offsite doses from CR-3 liquid and gaseous effluents for the period 2000 through 2008 are presented in Table 7-5, according to 10 CFR 50, Appendix I dose categories. A scaling factor of two conservatively bounds the percent increase in reactor coolant activities for all radionuclides of interest in liquid and gaseous effluents. As shown in Table 7-5, the doubled doses under EPU conditions remain less than one percent of the Appendix I ALARA guidelines. These doses are also bounded by the analysis in the FES for Operation (AEC 1973), which predicted an offsite whole body dose of 0.36 torem/year and a maximum organ dose (thyroid) of 4.0 mrem/year. TABLE 7-5. HISTORIC AND PROJECTED EPU OFFSITE DOSES COMPARED TO 10 CFR 50, APPENDIX I ALARA GUIDELINES. Historic CR3 Projected Post- Appendix I Doses EPU Doses ALARA Units (2000 - 2008) (x 2 scaling) Guideline Liquid Total Body 9.39x 10.5 1.88xI0. 3 mrem/yr Maximum Organ 3.65x 10-3 7.30x 10-3 10 mrem/yr Gaseous Gamma Air Dose 2.69x 10-3 5.38x 10-3 10 mrad/yr Beta Air Dose 1.95x 102 3.90x 10-2 20 mrad/yr Total Body 5.61I0- 1.1 x 102 15 mrem/yr Maximum Organ 1.68x 10-2 3.36x 0-2 15 mrem/yr 7.2.2 NO ACTION ALTERNATIVE Under the No Action Alternative, CR-3 would continue to operate at the currently licensed power level of 2,609 MWt and there would be no changes in radiation levels and offsite doses from plant construction activities or operations related to EPU. Radiological Environmental Impacts 7-6 April 2011
Crystal River Unit 3 Extended Power Uprate 7.3 RADIOLOGICAL CONSEQUENCES OF ACCIDENTS Chapter 6 of the FES (AEC 1973) identified nine categories of accidents, the severity of their consequences ranging from trivial (Class I - small leaks into containment) to very serious (Class 9 - severe accidents). The consequence analysis presented in the FES was based on representative accidents provided in the CR-3 Environmental Report (ER) as part of the original license application. Some categories of accidents were treated in detail in the subsequent FSAR as part of the analysis of potential steam generator tube rupture (SGTR) accidents (Class 5), fuel handling accidents (Class 6 & 7) and design basis accidents (DBAs) (Class 8). Additionally, PEF has performed a radiological analysis of DBAs using the alternate source term (AST) methodology established in NRC Regulatory Guide 1.183, "Alternative Radiological Source Terms for Evaluating Design Basis Accidents at Nuclear Power Reactors" (NRC 2000), with the exception of the SGTR which follows the methods of the current licensing basis analysis, which was approved tinder License Amendment 199. With the exception of the SGTR, the results of this analysis for the EPU at CR-3 are summarized in "CR-3 EPU Radiological Consequences Using Alternative Source Term - Summary Report" (AREVA 2009), henceforth referred to as the Summary Report. This section addresses potential radiological consequences of accidents from a proposed 15.5 percent uprate. The FES estimated the collective dose from accidents to the population within 50 miles of the reactor (in person-rem to the whole body). There are no criteria or limits on the collective dose to members of the public that can be used for comparison. In addition, the FES also estimated the fraction of the 10 CFR 20 limit that could be incurred by an individual located at the site boundary at the time of an accident. At the time the FES was prepared, this dose limit was 500 mrem per year. Since the FES was issued, the dose limit for a member to the public in 10 CFR 20 has been reduced to 100 mrem per year. In addition, the dose calculation methodology was changed substantially at the same time the 10 CFR 20 limit was reduced. Organ and whole body doses were replaced with the total effective dose equivalent (TEDE), a methodology which incorporates organ doses from radionuclide intakes as well as whole body doses from external radiation. In addition, the revised dose methodology results in internal dose conversion factors that tend to be at least a factor of two times lower for most radionuclides when compared to the old methodology. While a comparison with dose limits in 10 CFR 20 may be appropriate for routine emissions, it is not strictly applicable to accidents with low probabilities of occurrence. The dose criteria in 10 CFR 100 apply more appropriately to such accidents. The limiting criteria are 300 rem to the thyroid from radioiodine releases and 25 rem to the whole body of an individual at the exclusion zone received over two hours from all radionuclides released in an accident. These criteria have not changed since the time of the original license application. The differences in applicability of dose acceptance criteria (i.e., 10 CFR 20 vs. 10 CFR 100), as well as the changes in the criteria and calculational methodology over time (i.e., revisions to 10 Radiological Environmental Impacts 7-7 April 2011
Crystal River Unit 3 Extended Power Uprate CFR 20 and 10 CFR 50), make the direct comparison of impacts between the original licensed power and the proposed power uprate more challenging. In addition, the methodology used to estimate the radiological source term (i.e., the amount of radionuclides released to the environment, as well as the timing of the release) directly affects the estimation of doses to members of the public. The source term methodology used in the past for severe accident analyses was based on releases from a severely damaged core, as published in 1962 by the AEC (AEC 1962) in Technical Information Document (TID) 14844, "Calculation of Distance Factors for Power and Test Reactors." Since this document was published, there have been significant advances in establishing the timing, magnitude, and chemical forms of the fission product release from severe reactor accidents. This extensive research and experience culminated in the development of a new or revised source term described in NUREG-1465, "Accident Source Terms for Light-Water Nuclear Power Plants" (NRC 1995). The CR-3 FSAR (Florida Power 2008) uses the alternative radiological source term (AST) methodology established in NRC Regulatory Guide 1.183, "Alternative Radiological Source Terms for Evaluating Design Basis Accidents at Nuclear Power Reactors" (NRC 2000), to reassess the consequences of refueling and design basis accidents. Regulatory Guide 1.183 endorses a source term derived from NUREG-1465 and provides guidance on the acceptable attributes of other alternative source terms. As stated, PEF has performed an evaluation of the DBAs using the AST methodology to assess the impacts of the 15.5 percent increase associated with the EPU. The AST guidance requires consideration of the dose at the site boundary over the worst two-hour interval after the accident. In the previous guidance, only the first two hours after an accident were considered, because the bulk of the radionuclides were assumed to be released immediately following an accident. The comparison of older analyses contained in the FES with more current analyses reported in the Summary Report is complicated by a number of factors. As indicated earlier, the FES reports doses at the site boundary in terms of fractions of the 10 CFR 20 limit that was applicable at the time (500 mrem, whole body), as well as collective doses to the public. The NRC's dose acceptance criteria, analysis assumptions, and acceptable source term methodologies for low-probability/ high-consequence accidents have changed significantly since the FES was published. Depending on the accident, the current dose acceptance criteria contained in Regulatory Guidance 1.183 are shown in Table 7-6. Radiological Environmental impacts 7-8 April 2011
Crystal River Unit 3 Extended Power Uprate TABLE 7-6. ACCIDENT DOSE CRITERIA. Accident or Case EABa and LPZb Analysis Release Duration Dose Criteria Loss of Coolant Accident (LOCA) 25 rem TEDE 30 days for containment and emergency core cooling systems (ECCS) leakage Pressurized Water Reactor (PWR) Affected Steam Generator (SC): Steam Generator Tube Rupture time to isolate; Fuel Damage or Pre-incident Spike 25 rem TEDE Unaffected SG(s): until cold Coincident Iodine Spike 2.5 rem TEDE shutdown is established PWR Main Steam Line Break Fuel Damage or Pre-incident Spike 25 rem TEDE Until cold shutdown is established Coincident Iodine Spike 2.5 rem TEDE PWR Locked Rotor Accident 2.5 rem TEDE Until cold shutdown is established PWR Rod Ejection Accident 6.3rein TEDE 30 days for containment pathway; until cold shutdown is established for secondary pathway Fuel Handling Accident 6.3 rem TEDE 2 hours aEAB - Exclusion Area Boundary bLPZ - Low Population Zone While the older analyses are presented for comparison, direct comparisons are difficult due to different assumptions. Where applicable, accident consequences should be evaluated against the current acceptance criteria. 7.3.1.1 CLASS 1 - TRIVIAL INCIDENTS Class I accidents were not considered in the CR-3 FES, consistent with the AEC guidance for environmental reports at the time. The magnitude of these leaks is bounded by those analyzed under Class 8.1 (LOCA Inside or Outside Primary Containment), because small leaks and spills are defined here as being below the Technical Specification limits. The FES concluded that the dose to an offsite individual from small leaks inside the containment building would be bounded by the design objectives for routine liquid and gaseous effluents (i.e., 5 mrem/yr). Plant improvements since the period of initial operations have led to significantly lower concentrations Radiological Environmental Impacts 7-9 April 2011
Crystal River Unit 3 Extended Power Uprate of radionuclides in reactor coolant than those predicted by the FES. These improvements more than offset any potential increases in activity concentrations attributable to the EPU. Therefore, any impacts from small leaks remain bounded by the criteria for routine effluents. 7.3.1.2 CLASS 2 - SMALL RELEASES OUTSIDE CONTAINMENT The FES did not estimate the radiological consequences of a Class 2 accident. The rationale for dismissing this class of accidents was the same as the one used to dismiss the Class I accidents. 7.3.1.3 CLASS 3 - RADWASTE SYSTEM FAILURES This class of accidents was addressed in Table 6-2 of the FES and consisted of three postulated events: " Equipment leakage or malfunction (Class 3.1)
- Release of liquid waste storage contents (Class 3.2) 7.3.1.3.1 CLASS 3.1 - EQUIPMENT LEAKAGE OR MALFUNCTION The FES estimated that doses from equipment leakage and malfunction would be 2 percent of the 10 CFR 20 limit at the site boundary (equivalent to 10 tmrerm) and would result in a collective dose of 0.7 person-rem. The assumptions for these dose estimates were not provided in the FES.
Depending on the assumed exposure pathways and dominant radionuclides, it is likely that impacts calculated using revised dose factors alone would be reduced by more than enough to offset the 15.5 percent increase in releases from such an accident following the EPU. The probability of these postulated accidents would not be affected by the EPU. 7.3.1.3.2 CLASS 3.2 - RELEASE OF LIQUID WASTE STORAGE CONTENTS The FES estimated that doses due to release from the liquid waste storage contents would be 2.2 percent of the 10 CFR 20 limit at the site boundary (equivalent to 11 mrem) and would result in a collective dose of 0.1 person-rem. These impacts would not increase because the EPU conditions would not have significant impacts on the effectiveness of the liquid waste treatment system or on the amount and concentration of the waste liquid generated from this processing. Therefore, the conclusions in the FES remain bounding. 7.3.1.4 CLASS 4 - FISSION PRODUCTS TO PRIMARY SYSTEM Severe accidents that release radioactivity into primary systems apply primarily to boiling water reactors (BWRs). Since CR-3 is a PWR, the impacts of events in this class were not analyzed in the FES. 7.3.1.5 CLASS 5 - FISSION PRODUCTS TO PRIMARY AND SECONDARY SYSTEMS This class of accidents was addressed in Table 6-2 of the FES and consisted of three postulated events: Radiological Environmental Impacts 7-10 April 2011
Crystal River Unit 3 Extended Power Uprate " Fuel cladding defects and steam generator leaks (Class 5.1)
- Off-design transients that induce fuel failure above those expected and steam generator leak (Class 5.2)
" Steam generator tube rupture (Class 5.3) 7.3.1.5.1 FUEL CLADDING DEFECTS AND STEAM GENERATOR LEAKS The FES concluded that the dose to an offsite individual from this event would be bounded by the design objectives for routine liquid and gaseous effluents (i.e., 5 mrem/yr). Therefore, the FES did not estimate the radiological consequences of a Class 5.1 accident 7.3.1.5.2 OFF-DESIGN TRANSIENTS THAT INDUCE FUEL FAILURE ABOVE THOSE EXPECTED WITH STEAM GENERATOR LEAK The FES estimated that doses due to releases caused by fuel clad failure with steam generator leakage would be less than 0.1 percent of the 10 CFR 20 limit at the site boundary (equivalent to < 0.5 mrem) and would result in a collective dose of less than 0.1 person-remn. These impacts would not increase because the EPU conditions would not result in an increase in off-design transients leading to fuel clad failure with subsequent releases through steam generator leakage. Therefore, the conclusions in the FES remain bounding. 7.3.1.5.3 STEAM GENERATOR TUBE RUPTURE This analysis of the steam generator tube rupture (SGTR) Radiological Consequences does not follow the guidance of Regulatory Guide 1.183, Appendix F, but is consistent with the current licensing basis and the SGTR (pre-EPU) analysis presented as part of the original Alternate Source Term submittal (LAR #262) and approved by the NRC in License Amendment #199. This analysis is not discussed in the Summary Report. The SGTR dose calculation is simplistic and conservative. No credit is taken for decay from time of accident. No credit for retention of iodine in the steam generators is taken. Iodine in the reactor coolant system (RCS) is assumed to be at a concentration consistent with 1% failed fuel, and not at the much lower Technical Specification limit. EAB dose is based on a two hour exposure period. No credit is taken for isolation time of the affected steam generator in calculating the LPZ dose, which is based on a break flow duration of 24 hours. Break flow for the full 24 hours is assumed to be a constant bounding value, which is approximately 50% greater than the average break flow up to isolation of the affected steam generator. Primary-to-secondary leakage is assumed to be I gpm into the intact SG. The public dose consequence for two hours at the EAB was calculated to be 0.16 rem TEDE, and dose consequence at the LPZ was calculated to be 0.19 rem TEDE. These values are well within the limit of 2.5 remn TEDE. The FES estimated that doses due to releases caused by a steam generator tube rupture would be 2.6 percent of the 10 CFR 20 limit at the site boundary (equivalent to 13 mrem) and would result in a collective dose of less than 1.0 person-rem. The Radiological Environrnental Impacts 7-11 April 2011I
Crystal River Unit 3 Extended Power Uprate differences in the FES values and these values are probably due to differences in the modeling assumptions that went into the calculations. 7.3.1.6 CLASS 6 - REFUELING ACCIDENTS This class of accidents was addressed in Table 6-2 of the FES and consisted of two postulated events: " Fuel bundle drop (Class 6.1) " Heavy object drop onto fuel in core (Class 6.2) Section 14.2.2.3 of the CR-3 FSAR addresses all Fuel Handling Accidents (FHAs) in one evaluation. Two accident scenarios are considered: (1) refueling accident occurring inside the Reactor Building and (2) refueling accident occurring outside the Reactor Building. For an FHA inside the reactor building, it was postulated that a fuel assembly was dropped during refueling resulting in breaching of the fuel rod cladding. As a result of the damage, the volatile fission gases contained in the fuel to pellet gap of all 208 fuel rods of one assembly are released to the water. Subsequently, a fraction of the iodine was absorbed in the water. The escaped gases are assumed to be released to the environment via the Reactor Building Purge System. No credit was assumed for iodine removal by this system (Florida Power 2008). The analysis of a FHA in the Spent Fuel Pool was identical to the FHA inside the Reactor Building with the exception that the escaped gaseous fission products are released to the Spent Fuel Pool and subsequently to the Fuel Handling Building. These gases are released to the environment via the Auxiliary and Fuel Handling Building Charcoal Exhaust System. No credit was assumed for iodine removal by this system. Since the final release point was the same for both the FHA inside and outside the Reactor Building, and since neither takes credit for release filters, only one dose assessment was required to represent both scenarios. The calculated doses for an FHA are 0.83 rem TEDE at the EAB, 0.073 rein TEDE at the LPZ, and 4.43 rem TEDE in the control room. These doses are within the required limits. The calculated control room doses take no credit for the isolation of the control room ventilation, or the use of filtered recirculation of control room air. Therefore, even though the calculated dose to the control room is higher for the FHA compared to other DBAs, the FHA is not considered the limiting accident for control room habitability as it does not impose any design or operability requirements for the Control Complex Habitability Envelope or the Control Room Emergency Ventilation System. 7-12 April 2011 Environmental Impacts Radiological Environmental Impacts 7-12 April 2011
Crystal River Unit 3) Extended Power Uprate 7.3.1.6.1 FUEL BUNDLE DROP The FES estimated that doses resulting from a dropped fuel bundle would be 0.4 percent of the 10 CFR 20 limit at the site boundary (equivalent to 2 mrem) and would result in a collective dose of 0.2 person-rem. The differences in the FES values and the AST values is probably due to differences in the modeling assumptions used in the calculations. The Summary Report discusses the evaluation of radiological consequences of a fuel handling accident (FHA) for CR-3 at EPU conditions. The fuel handling accident assumes that 104 fuel rods of a fuel assembly fail after the assembly is dropped on top of the spent fuel racks or the shallow end of the fuel transfer canal (135' elevation) assuming 2 hour release duration and a water depth of 22 feet and 20 feet, respectively (AREVA 2009). The public dose consequence for two hours at the EAB was calculated to be 1.012 remn TEDE (open containment) and 0.724 rem TEDE (spent fuel pool). The public dose consequence in the LPZ was calculated to be 0.118 rem TEDE (open containment) and 0.084 remn TEDE (spent fuel pool). The Main Control Room dose was calculated to be 4.906 remn TEDE (open containment) and 3.352 rem TEDE (spent fuel pool) (AREVA 2009). These values are within the limits of 6.3 remn TEDE for the EAB and LPZ and 5 remn TEDE (MCR) given in 10 CFR 50.67. 7.3.1.6.2 HEAVY OBJECT DROP ONTO FUEL IN CORE The FES estimated that doses resulting from dropping a heavy object onto the exposed core fuel would be 7.2 percent of the 10 CFR 20 limit at the site boundary (equivalent to 36 torem) and would result in a collective dose of 2.6 person-tern. These impacts would not increase because the EPU conditions should not result in an increase in refueling pool activities above the exposed core. 7.3.1.7 CLASS 7 - ACCIDENTS TO SPENT FUEL OUTSIDE CONTAINMENT This class of accidents was addressed in Table 6-2 of the FES and consisted of two postulated events:
- Fuel assembly drop in fuel rack (Class 7.1)
- Heavy object drop onto fuel rack (Class 7.2)
Both of these accidents are similar to those described in Section 7.3.1.6, but involve the spent fuel storage pool rather than the reactor core. The doses for these accidents are bounded by the impacts reported in the FES for Class 6 accidents, due to the lower fission product inventories in the stored spent fuel assemblies. As discussed in Section 7.3.1.6, Section 14.2.2.3 of the CR-3 FSAR addresses all FHAs in one evaluation. The same conclusions reached for refueling FHAs apply to spent fuel pool FHAs. Conservatively assuming that the increase in dose consequences for the EPU would be equivalent to the 15.5 percent change in power level, the projected doses at the EAB and the LPZ would still be well below the Regulatory Guide 1.183 values. Likewise, the Control Room dose Radiological Environmental Impacts 7-13 April 2011I
Crystal River Unit 3 Extended Power Uprate would slightly exceed the Regulatory Guide 1.183 value of 5 rem, however the mitigative measures listed in 7.3.1.6 should reduce the estimated dose below the 5 rem value. 7.3.1.8 CLASS 8 - ACCIDENT INITIATION EVENTS CONSIDERED IN THE DESIGN BASIS EVALUATION IN THE SAFETY ANALYSIS REPORT Three subclasses of DBAs are analyzed in the FES. These include a LOCA inside containment (small and large break), a control rod ejection accident, and a steamline break accident (small and large break outside of containment). These accidents were also analyzed in the CR-3 FSAR. 7.3.1.8.1 LOSS OF COOLANT ACCIDENT INSIDE CONTAINMENT The FES estimated that doses from a large break in the reactor coolant system pressure boundary would result in a dose at the boundary equivalent to 30.8 percent (154 mrem) of the 10 CFR 20 limits applicable at the time; the collective population dose from this accident was estimated to be 69 person-remn. The dose from a small-break LOCA is bounded by the dose from a large-break LOCA. The Summary Report discusses the evaluation of radiological consequences of a LOCA in support of EPU for CR-3. The calculated maximum 2 hour dose at the EAB is 12.79 rem TEDE. The calculated dose at the LPZ is 1.79 rem TEDE. The calculated dose in the Main Control Room is 3.49 remn TEDE (AREVA 2009). These doses are within the Regulatory Guide 1.183 and 10 CFR 50.67 limits. 7.3.1.8.2 CONTROL ROD EJECTION ACCIDENT The FES estimated that doses from a control rod ejection (CRE) accident would result in a dose at the site boundary equivalent to 3 percent (15 mrem) of the 10 CFR 20 limits applicable at the time; the collective population dose from this accident was estimated to be 6.9 person-rem. The Summary Report discusses the radiological impact associated with the postulated CRE accident at CR-3. Two alternative accident scenarios were postulated: (a) the entire initial RCS radioactivity as well as the activity released from clad failures and fuel overheat/melt becomes airborne within the primary containment and is available for release to the atmosphere as a result of containment leakage, and (b) the entire activity is retained within the RCS and is available for release as a result of steam generator tube leakage during the plant cooldown phase. The pre-accident primary coolant activity was set at the proposed TS limit of 0.35 ptCi/gm DE ]- 131 for the iodines, and at 1 percent failed fuel fraction for the noble gases (AREVA 2009) The maximum calculated TEDE dose at the EAB was 5.67 rem for the containment release case and 2.83 rem for the secondary side release case. The calculated TEDE dose at the LPZ was 1.50 remn for the containment release case and 1.34 rem for the secondary side release case. These doses are within the Regulatory Guide 1.183 criterion of 6.3 rem TEDE for this accident (AREVA 2009). The calculated dose to the Main Control Room was 3.79 remn TEDE for the containment release case and 4.50 rem for the secondary side release case. These doses are within the 5 rem TEDE 10 CFR 50.67 limit. Radiological Environniental Impacts 7-14 April 2011
Crystal River Unit 3 Extended Power Uprate 7.3.1.8.3 STEAMLINE BREAK (OUTSIDE CONTAINMENT) The FES estimated that doses from a steamline break accident (both small and large breaks outside of containment) would result in a dose at the site boundary of less than 0.1 percent (<0.5 mrero) of the 10 CFR 20 limits applicable at the time. The collective population dose from this accident was estimated to be less than 0.1 person-rem. The Summary Report discusses the radiological impact associated with a Main Steam Line Break (MSLB) in support of the EPU for CR-3. Two alternative source term release scenarios were postulated for the radiological evaluation, as follows: (a) MSLB with a pre-accident iodine spike, where a reactor transient occurs prior to the MSLB raising the primary coolant concentration to 21 jtCi/gm Dose Equivalent 1-131 (60 times the 0.35 [tCi/gm DE 1-131 proposed Technical Specifications limit) and (b) MSLB with an 8 hour coincident iodine spike, where the MSLB itself induces an iodine spike corresponding to an increase in the design bases iodine appearance rate into the primary coolant by a factor of 500 (AREVA 2009). The public dose consequence for two hours at the EAB was calculated to be 0.0282 rem TEDE pre-accident iodine spike and 0.149 rem TEDE with a concurrent iodine spike. The public dose consequence in the LPZ was calculated to be 0.0239 rem TEDE pre-accident iodine spike and 0.100 rem TEDE with a concurrent iodine spike. The Main Control Room dose was calculated to be 0.0914 rem TEDE pre-accident iodine spike and 0.396 rem TEDE with a concurrent iodine spike (AREVA 2009). These values are well within the limits of 25 rem TEDE (pre-accident iodine spike), 2.5 rem TEDE (concurrent iodine spike) and the 5 rem TEDE (MCR) limits given in Regulatory Guide 1.183 and 10 CFR 50.67. 7.3.1.9 CLASS 9 - SEVERE ACCIDENTS The impacts of any severe accidents outside the design basis provided by the engineered safety system were not evaluated in the FES. The possible sequence of events that might lead to beyond design basis accidents are of very low probability when considering the design conservatism, multiple barriers, quality assurance, and testing that are now in place. The environmental risk of Class 9 accidents is extremely low, and the EPU would not involve any changes that would alter the validity of this conclusion. 7.3.1.10 OTHER ACCIDENTS Letdown Line Rupture/Break (LLR) accidents are not discussed in the FES. LLR is also not addressed in the Regulatory Guide 1.183. However, the LLR accident is included in the FSAR and as such is part of the current licensing basis. Therefore, the LLR is included for completeness' sake. The Letdown Line Rupture/Break is assumed to occur in the Auxiliary Building resulting in a release directly to the environment without mitigation by the Auxiliary Building ventilation system filtration or holdup. The letdown line break flow is in the Auxiliary Building, at 120°F and 14.7 psia. No flashing is expected to occur at these conditions, however, a 10 percent flashing fraction is applied per Reg. Guide 1.183, Appendix A, Section 5.5. Radiological Environmental Impacts 7-15 April 2011
Crystal River Unit 3 Extended Power Uprate The radiological consequences of a postulated LLR outside containment were evaluated. Regulatory Guide 1.183, Appendix E guidance for the Main Steam Line Break was applied to the LLR analysis. A break in fluid-bearing lines that penetrate the reactor containment may result in the release of radioactivity to the environment. There are lines within the Makeup and Purification (MU) System and the Decay Heat Removal (DHR) System that penetrate the containment. A pre-accident iodine spike and an accident-induced concurrent iodine spike were evaluated. The maximum calculated TEDE doses at the EAB were 0.15 rem for the pre-accident spike scenario and 0.06 rem for the concurrent spike scenario. The calculated TEDE doses at the LPZ were 0.02 rem for the pre-accident spike scenario and 0.01 rem for the concurrent spike scenario. The calculated TEDE dose to the Main Control Room was 0.71 remn for the pre-accident spike scenario and 0.24 rein for the concurrent spike scenario. These doses meet the exposure guideline values specified in FSAR Section 1.4.11 and 10 CFR Part 50.67. 7.3.2 NO ACTION ALTERNATIVE Under the No Action Alternative, CR-3 would continue to operate at the currently licensed power level of 2,609 MWt and there would be no changes in radiological consequences of accidents from plant construction activities or operations related to EPU. 7.4 OTHER POTENTIAL ENVIRONMENTAL ACCIDENTS 7.4.1 EPU ALTERNATIVE - HELPER COOLING TOWER AND LOAD REDUCTION OPTIONS Other potential environmental accidents could involve chemicals, industrial gases, oil, oil products, or other hazardous substances. The EPU would not significantly alter their inventory, storage, usage, or control requirements, and no new hazardous substances would be used or introduced. The risk from oil or chemical spills, releases of industrial gases, or other events involving non-radioactive hazardous material would not increase significantly as a result of the EPU. 7.4.2 NO ACTION ALTERNATIVE Under the No Action Alternative, CR-3 would continue to operate at the currently licensed power level of 2,609 MWt and there would be no changes in other potential environmental accidents from plant construction activities or operations related to EPU. 7-16 April 2011 Environmental Impacts Radiological Environmental Radiological Impacts 7-16 April 2011
Crystal River Unit 3 Extended Power Uprate 8.0 ENVIRONMENTAL EFFECTS OF URANIUM FUEL CYCLE ACTIVITIES AND RADIOACTIVE WASTE TRANSPORT 8.1 EPU ALTERNATIVE - HELPER COOLING TOWER AND LOAD REDUCTION OPTIONS NRC regulations (10 CFR 51.51, Table S-3) provide the basis for evaluating the contribution of the environmental effects of the uranium fuel cycle to the environmental impacts of licensing a nuclear power plant. NRC regulations (10 CFR 51.52, Table S-4) describe the environmental impacts of transporting nuclear fuel and radioactive wastes. Tables S-3 and S-4 were developed in the 1970s. Since that time, most plants have increased both the uranium-235 enrichment and the burnup of their nuclear fuel. In 1988, NRC generically evaluated the impacts of extended burnup fuel and increased enrichment oil tile uranium fuel cycle, including impacts to transportation of nuclear fuel and wastes, to determine whether higher burnup and enrichment could result in environmental impacts greater than those described in Tables S-3 and S-4. The Environmental Assessment and Finding of No Significant Impact (53 FR 6040; February 29, 1988) concluded that burnup limits of up to 50,000 megawatt-days per metric ton of uranium (MWd/MTU) or higher (as long as the peak rod average burnup is no greater than 60,000 MWd/MTU) and uranium-235 enrichment up to 5 weight percent would have no significant adverse environmental effects oil the uranium fuel cycle or the transport of nuclear fuel and wastes, and would not change the impacts presented in Tables S-3 and S-4. In 1996, in connection with the Generic Environmental Impact Statement (GELS) for License Renewal of Nuclear Power Plants, NRC looked at transporting higher enrichment and higher burnup spent nuclear fuel to a geologic repository (NRC 1996). The conclusion of that evaluation was that tile environmental impacts would be consistent with the values presented in Table S-4 and that the impacts in Table S-4 are bounding. For the proposed EPU, design studies project that the fundamental mechanical design and the range of fuel enrichment will not change. The average enrichment may change. The design full power discharge burnup rate of 47,830 MWd/MTU and the design licensed life burnup rate of 48,730 MWd/MTU will remain bounded by the impacts in Tables S-3 and S-4 of 10 CFR 51. Therefore, PEF concludes that impacts to the uranium cycle and transport of nuclear fuel from the proposed action would be insignificant and not require mitigation. The EPU would require more fuel assemblies per reload. Design studies project an increase in reload batch from 72 to 88 assemblies. The current capacity of the CR-3 Spent Fuel Pool (SFP) is 1474 assemblies. The current spent fuel inventory is 1066 assemblies (as of 7/20/2009). PEF has initiated a project to design and construct an ISFSI at CR-3. The ISFSI will provide for the dry storage of spent nuclear fuel at the CR-3 nuclear plant site. PEF has initiated a series of Environmental Effects of Uranium Fuel Cycle Activities and Radioactive Waste Transport 8-1 April 2011
Crystal River Unit 3 Extended Power Uprate Engineering Changes (EC) to design and construct an ISFSI at the CR-3 site. Each of the Engineering Changes along with design interfaces will be described in the EC document. The CR-3 reactor core holds 177 fuel bundles. Based on current spent fuel inventory and the projected refueling outage discharges, CR-3 will lose Prudent Operating Reserve (POR) after RF-17. With the current storage capacity of 1,474 cells, there would not be enough empty cells to store a full core offload of 177 assemblies plus a new fuel batch of 88 assemblies. It is essential that the first dry storage transfers (from the SFP to an ISFSI) for CR-3 occur prior to receipt of new fuel during RF-I 8. The ISFSI will be designed to ensure compliance with regulatory standards 10 CFR 72.104 and 10 CFR 72.106 for normal, accident and post-accident conditions at various distances from the storage cask array. 8.2 NO ACTION ALTERNATIVE Under the No Action Alternative, CR-3 would continue to operate at the currently licensed power level of 2,609 MWt and there would be no changes in uranium fuel cycle activities and radioactive waste transport from plant construction activities or operations related to EPU. Environmental Effects of Uranium Fuel Cycle Activities and Radioactive Waste Transport 8-2 April 2011
Crystal River Unit 3 Extended Power Uprate 9.0 EFFECTS OF DECOMMISSIONING 9.1 EPU ALTERNATIVE - HELPER COOLING TOWER AND LOAD REDUCTION OPTIONS The FES for CR-3 described the process in place for decommissioning nuclear reactors at the time of its publication but did not evaluate the environmental effects of decommissioning (AEC 1973). In 1988 NRC published the Final Generic Environmental Impact Statement on Decommissioning of Nuclear Facilities (NUREG-0586; NRC 1988). Environmental impacts from the activities associated with the decommissioning of any nuclear power reactor before or at the end of an initial or renewed license period are evaluated in the Generic Environmental Impact Statement for Decommissioning of Nuclear Facilities, NUREG-0586, Original and Supplement I (NRC 1988, NRC 2002). The conclusions of this environmental impact statement are that environmental impacts of decommissioning are generally small and that only two environmental issues would require site-specific evaluation: threatened and endangered species and environmental justice. The NRC procedures for all phases of decommissioning are described in NRC regulations (Title 10 of the Code of Federal Regulations, part 20 subpart E, and parts 50.75, 50.82, 51.53, and 51.95). Incremental environmental impacts that would be associated with decommissioning activities resulting from continued plant operation during the renewal term are evaluated in the Generic Environmental Impact Statement Jbr License Renewal of Nuclear Plants (GEIS), NUREG-1437, Volumes I and 2 (NRC 1996). The evaluation in NUREG-1437 includes a determination of whether the analysis of the environmental issue could be applied to all plants and whether additional mitigation measures would be warranted. Impacts to air quality, water quality, ecology, are expected to be much smaller than those incurred during construction and operation. Radiation exposure to workers and the public, socioeconomic effects and waste management impacts also were evaluated and determined to be Category I issues. For all the environmental issues evaluated in NUREG-1437 the NRC staff concluded that impacts of license renewal on decommissioning would be small and mitigation would not be warranted. Prior to any decommissioning activity at CR-3, PEF would submit a post-shutdown decommissioning activities report (i.e., decommissioning plan) to describe planned decommissioning activities, any environmental impacts of those activities, a schedule, and estimated costs. Implementation of an EPU does not affect PEF's ability to maintain financial reserves for decommissioning nor does the EPU alter the decommissioning process. The potential environmental impacts on decommissioning associated with the proposed EPU would be due to the increased neutron flux. As a result of EPU changes, the amount of activated corrosion products could increase, and consequently, the post-shutdown radiation levels could increase. PEF expects the increases in radiation levels as a result of operations under the proposed EPU conditions to be small (see Section 7.2); however, the expected increases in Effects of Decommissioning 9-1 April 2011
Crystal River Unit 3 Extended Power Uprate radiation levels would be addressed in the post-shutdown decommissioning activities report and would not result in significant increases in doses to workers or the public. 9.2 NO ACTION ALTERNATIVE Under the No Action Alternative, CR-3 would continue to operate at the currently licensed power level of 2,609 MWt and there would be no changes in the effects of decommissioning from plant construction activities or operations related to EPU. Effects of Decommissioning 9-2 April 2011
Crystal River Unit 3 Extended Power Uprate
10.0 REFERENCES
AEC (Atomic Energy Commission). 1962. Calculation of Distance Factors for Power and Test Reactor Sites, USAEC TID-14844, Washington, D.C. March AEC (Atomic Energy Commission). 1973. Final Environmental Statement related to the proposed Crystal River Unit 3, Florida Power Corporation, Docket No. 50-302. Directorate of Licensing, Washington, D.C. May 1973. AREVA. 2009. CR-3 EPU Radiological Consequences Using Alternative Source Term - Summary Report. 0402-01-FO1 (20697) Rev. 013. Document No. 86-9099336-000. February 18. CSC (Coastal Seas Consortium, Inc). 2002. Seagrass Survey: November 2001 Resurvey at the Florida Power Crystal River Generating Facility. Prepared by Coastal Seas Consortium, Bradenton, Florida, for Florida Power, St. Petersburg, Florida. Evaptech (Evaptech, Inc). 2009. Sound calculations. Prepared for PEF by Evaptech, Inc., Lenexa, KS. Florida Power. 2008. Final Safety Analysis Report, Revision 31. May. FDEP (Florida Department of Environmental Protection) 2010. Title V Air Operation Permit Renewal for Crystal River Power Plant, Permit No. 0170004-024-AV. January 1. FDEP, 2009. Letter from FDEP to USEPA regarding recommendations for the designation of "attainment," "nonattainment," or "unclassifiable areas in Florida with respect to the 2008 revised national ambient air quality standard (NAAQS) for ozone. March 7. FNAI (Florida Natural Areas Inventory). 2010. FNA1 Tracking List, last updated in December. Available on-line at http://www.fnai.org/trackinglist.cfm. Accessed January 23, 2011. FOCC (Florida Oceanographic Coastal Center). 2003. "Shoal Grass." Available on-line at http://www.floridaoceanographic.org/environ/seagrass7.htm. Accessed March 30, 2009. FPC (Florida Power Corporation). 1996. Final Report of Seagrass Advisory Committee. Submitted to FDEP by Florida Power Corporation, Crystal River Units 1, 2, and 3. FPSC (Florida Public Service Commission). 2007. "Final Order Granting Petition for Determination of Need for Proposed Expansion of Crystal River Unit 3 Nuclear Power Plant." Order Number PSC-07-0119-FOF-E I. Docket Number 060642-E . February 8. FPSC (Florida Public Service Commission). 2010. "Annual Report on Activities Pursuant to the Florida Energy Efficiency and Conservation Act. As Required by Sections 366.82(10), 377.703(2)(f), and 553.975, Florida Statutes." Available on-line at http://www.psc.state.fl.us/publications/pdf/electricgas/FEECA2O1O.pdf. Accessed December 7,2010. References 10-1 April 2011l
Crystal River Unit 3 Extended Power Uprate FWC (Florida Fish and Wildlife Conservation Commission). Undated. "Crystal River Mariculture Center." Available on line at http://floridamarine.org/features/view article.asp?id= 10469. Accessed March 27, 2009. GSRT (Gulf Sturgeon Recovery/Management Task Team). 1995. Gulf Sturgeon Recovery/Management Plan. Prepared for USFWS Southeast Region, Gulf States Marine Fisheries Commission, and National Marine Fisheries Service. September. Golden et al. (Golden, J., R.P. Ouellette, S. Saari, and P.M. Cheremisinoff). 1980. Environmental Impact Data Book. Ann Arbor Science Publishers, Inc. Ann Arbor, Michigan. Golder Associates. 2006. Crystal River Energy Complex Proposal for Information Collection: NPDES Permit No. FLO000159. Prepared for Progress Energy, Raleigh, North Carolina, by Golder Associates, Tampa, Florida. Minai, L. 2002. "Scientists eager to learn about big fish." St. Petersburg Times, March 19. Online edition available at http://www.sptimes.com/2002/03/19/TampaBay/Scientists eager to I.shtml. Accessed November 21, 2006. NEI (Nuclear Energy Institute). 2008. "U.S. Electricity Production Costs and Components. 1995-2007, In 2007 cents per kilowatt-hour." Available online at http://www.nei.org/filefolder/U S_ElectricityProduction_Costs_and_Components.xls. Accessed January 27, 2009. NMFS (National Marine Fisheries Service). 2002. Endangered Species Act - Section 7 Consultation Biological Opinion. Cooling water intake system at the Crystal River Energy Complex (F/SER/2001/01080). National Oceanic and Atmospheric Administration, Southeast Regional Office, St. Petersburg, Florida. August 8. NRC (Nuclear Regulatory Commission). 1988. Final Generic Environmental Impact Statement on Decommissioning of Nuclear Facilities issued in 1988 (NUREG-0586). NRC (Nuclear Regulatory Commission) 1995. Accident Source Terms for Light-Water Nuclear Power Plants - Final Report. NUREG-1465. Office of Nuclear Regulatory Research, Washington, D.C. February. NRC (Nuclear Regulatory Commission). 1996. Generic Environmental Impact Statement for License Renewal of Nuclear Plants. Office of Nuclear Regulatory Research, Washington, DC. May 1996. NRC (Nuclear Regulatory Commission). 2000. Alternative Radiological Source Terms for Evaluating Design Basis Accidents at Nuclear Power Reactors. Regulatory Guide 1.183, NRC Public Document Room, Washington, D.C. July. NRC (Nuclear Regulatory Commission). 2002. NUREG-0586 - Generic Environmental Impact on Decommissioning of Nuclear Reactors. Supplement 1. Regarding the Decommissioning References 10-2 April 2011
Crystal River Unit 3 Extended Power Uprate of Nuclear Power Reactors. Main Report, Appendices A through M. Final Report. November 2002. NRC (Nuclear Regulatory Commission). 2003. NUREG-0713, Volume 24, Occupational RadiationExposure at Commercial Nuclear Power Reactors and Other Facilities2002. Office of Nuclear Regulatory Research. Washington, DC. October. NRC (Nuclear Regulatory Commission). 2004a. "Procedural Guidance for Preparing Environmental Assessments and Considering Environmental Issues, Rev. 1." NRR Office Instruction No. LIC-203, May 24. NRC (Nuclear Regulatory Commission). 2004b. NUREG-0713, Volume 25, Occupational Radiation Exposure at CommercialNuclear Power Reactors and Other Facilities2003. Office of Nuclear Regulatory Research. Washington, DC. October. NRC (Nuclear Regulatory Commission). 2005. NUREG-0713, Volume 26, Occupational Radiation Exposure at Commercial Nuclear Power Reactors and Other Facilities2004. Office of Nuclear Regulatory Research. Washington, DC. November. NRC (Nuclear Regulatory Commission). 2006. NUREG-0713, Volume 27, Occupational Radiation Exposure at Commercial Nuclear Power Reactors and Other Facilities2007. Office of Nuclear Regulatory Research. Washington, DC. December. NRC (Nuclear Regulatory Commission). 2007. NUREG-0713, Volume 28, Occupational Radiation Exposure at Commercial Nuclear Power Reactors and Other Facilities2006. Office of Nuclear Regulatory Research. Washington, DC. November. NRC (Nuclear Regulatory Commission). 2008. NUREG-0713, Volume 29, Occupational Radiation Exposure at Commercial Nuclear Power Reactors and Other Facilities2007. Office of Nuclear Regulatory Research. Washington, DC. December. PEF (Progress Energy Florida, Inc.). 2004. Radioactive Effluent Release Report 2003. Crystal River Unit 3. April 22. PEF (Progress Energy Florida, Inc.). 2005. Radioactive Effluent Release Report 2004. Crystal River Unit 3. April 28. PEF (Progress Energy Florida, Inc.). 2006a. "Petition for Determination of Need for Expansion of an Electrical Power Plant, for Exemption from Rule 25-22.082, F.A.C., and for Cost Recovery through the Fuel Clause." Submitted September 22, 2006. PEF (Progress Energy Florida, Inc.). 2006b. Radioactive Effluent Release Report 2005. Crystal River Unit 3. April 27. PEF (Progress Energy Florida, Inc). 2007a. Site Certification Application, Crystal River Unit 3 Power Uprate Project - Crystal River, Florida. Prepared for Progress Energy by Golder Associates, Inc., Tampa, FL. June. 10-3 April 2011 References References 10-3) April 2011
Crystal River Unit 3 Extended Power Uprate PEF (Progress Energy Florida, Inc.). 2007b. Radioactive Effluent Release Report 2006. Crystal River Unit 3. April 21. PEF (Progress Energy Florida, Inc.). 2008. Radioactive Effluent Release Report 2007. Crystal River Unit 3. April 21. PEF (Progress Energy Florida, Inc.). 2009. Radioactive Effluent Release Report 2008. Crystal River Unit 3. March 9. PEF (Progress Energy Florida, Inc.). Undated. Sea Turtle Rescue and Handling Guidance. Progress Energy Crystal River Unit 3 Plant Operating Manual, Al -571, Rev 5. Progress Energy. 2008. Applicant's Environmental Report - Operating License Renewal Stage Crystal River Unit 3. Docket No. 50-302, License No. DPR-72. November. Progress Energy. 2009a. "Crystal River." Available on line at http://progress-energy.com/aboutenergy/powerplants/nuclearplants/crystalriver.asp. Progress Energy. 2009b. "Spotlight: Crystal River Mariculture Center." Available on line at http://www.progress-energy.com/environment/programs/rareplant/index.asp. SWEC (Stone & Webster Engineering Corporation). 1985. Final Report: Crystal River 316 Studies. Prepared for Florida Power Corporation. January 15. Scientech. 2007. Commercial Nuclear Plants (Edition No. 24). Scientech, Incorporated, Gaithersburg, MD. Tetra Tech. 2009. Calculation Package for Air Quality Impacts from the Helper Cooling Tower South. Prepared for Progress Energy Florida by Tetra Tech, Aiken, SC. December 3. Trans Associates. 2007. "Traffic Impact Study. Progress Energy Uprate. Crystal River Energy Complex. Citrus County, Florida." GOLASOO-D7219. Tampa, Florida. August 13, 2007. USEPA, 2010. State of Mississippi, et al. v. USEPA. EPA's Status Report. August 20. USFWS (U.S. Fish and Wildlife Service). 2007. News release: Bald eagle soars off endangered species list. U.S. Department of the Interior, June 28, 2007. USFWS (U.S. Fish and Wildlife Service). 2010a. North Florida Federally-Listed Species: North Florida Counties, last updated November 12, 2010. North Florida Ecological Services Office, Jacksonville. Available at http://www.fws.gov/northflorida/gotocty.htm. Accessed January 23, 2011. USFWS (U.S. Fish and Wildlife Service). 2010b. Florida Wood Stork Colonies Core Foraging Areas. North Florida Ecological Services Office, Jacksonville. Available at http://www.fws.gov/northflorida/WoodStorks/Documents/20100224 map WOST FL Nesti ng Colonies Foraging Areas.pdf. Accessed January 23, 2011. 10-4 April 2011 References 10-4 April 2011
Crystal River Unit 3 Extended Power Uprate USGS (U.S. Geological Survey). 2006. "Gulf Sturgeon Facts." Prepared by Florida Integrated Science Center, U.S. Department of the Interior, U.S. Geological Survey, Gainesville, Florida. Waldemar, J. 2009. "Current Real Estate Taxes Collected for Tax years 2001-2008." Facsimile transmission from Janice Waldemar, Citrus County Tax Collector's Office, Citrus County, Florida, to E. N. Hill, TtNUS, Inc. September 8. References 10-5 April 2011
PROGRESS ENERGY FLORIDA, INC. CRYSTAL RIVER UNIT 3 DOCKET NUMBER 50-302/LICENSE NUMBER DPR-72 LICENSE AMENDMENT REQUEST #309, REVISION 0 ATTACHMENT 10 LIST OF REGULATORY COMMITMENTS
U. S. Nuclear Regulatory Commission Attachment 10 3F0611-02 Page 1 of I LIST OF REGUALTORY COMMITMENTS The following table identifies those actions committed to by Florida Power Corporation (FPC) in this document. Any other statements in this submittal are provided for information purposes and are not considered to be regulatory commitments. Please notify the Superintendent, Licensing and Regulatory Programs of any questions regarding this document or any associated regulatory commitments. Regulatory Commitments Due Date/Event CR-3 will evaluate and implement the applicable reactor Prior to exceeding 2609 MWt vessel internals management guidelines pertinent to CR-3. A CR-3 unit specific internals aging management plan, based on the generic EPRI Reactor Vessels Materials Reliability Program (MRP) -227 inspection and evaluation guidelines, will become the new licensing basis for the EPU cycles. (See TR Section 2.1.4) CR-3 will implement all EPU modifications. This includes Prior to exceeding 2609 MWt installation of the modifications in TR Attachment E as well as associated simulator upgrades, program updates, procedure changes and training in accordance with the Progress Energy Design Control Processes. Vibration monitoring, transient testing, and power ascension Prior to exceeding 2609 MWt testing will be performed as described in TR Section 2.12.1. A separate LAR will be submitted to revise the LTOP At least one year prior to setpoint in ITS 3.4.11 exceeding 27.5 EFPY}}