Text

Attachments 1, 2 & 3, 4 & 6 Crystal River Unit 3, License Amendment Request #309, Revision 0 Attachment 1, Description of Proposed Change, Background, Justification for the Request, Determination of No Significant Hazards Considerations
	ML11207A443
Person / Time
Site:	Crystal River
Issue date:	06/15/2011
From:	; Progress Energy Florida
To:	; Office of Nuclear Reactor Regulation
References
	3F0611-02
	Download: ML11207A443 (326)
	v • d • e

PROGRESS ENERGY FLORIDA, INC.

CRYSTAL RIVER UNIT 3 DOCKET NUMBER 50-302 /LICENSE NUMBER DPR-72 LICENSE AMENDMENT REQUEST #309, REVISION 0 ATTACHMENT 1 DESCRIPTION OF PROPOSED CHANGE, BACKGROUND, JUSTIFICATION FOR THE REQUEST, DETERMINATION OF NO SIGNIFICANT HAZARDS CONSIDERATIONS

U. S. Nuclear Regulatory Commission Attachment I 3F0611-02 Page 1 of 35 DESCRIPTION OF PROPOSED CHANGE, BACKGROUND, JUSTIFICATION FOR THE REQUEST, DETERMINATION OF NO SIGNIFICANT HAZARDS CONSIDERATIONS

1.0 DESCRIPTION

OF PROPOSED CHANGE The proposed License Amendment Request (LAR) would revise the Crystal River Unit 3 (CR-3)

Operating License (OL) and Improved Technical Specifications (ITS) to increase core power from 2609 megawatts thermal (MWt) to 3014 MWt. The requested change constitutes an Extended Power Uprate (EPU) and is requested to provide greater unit electrical generating capability.

2.0 PROPOSED CHANGE

Table I below presents the proposed changes to the current CR-3 OL and ITS requirements related to this EPU license amendment request and a brief discussion of the basis for the changes. The OL and ITS changes are identified in Attachment 2, "Operating License and Improved Technical Specification Changes (Markup)," and Attachment 3, "Operating License and Improved Technical Specification Changes (Revision Bar Format)". ITS Bases changes are provided for information only, in Attachment 4, "Improved Technical Specification Bases Changes (Markup)". Where indicated below, additional justification is provided in the CR-3 EPU Technical Report (TR) (Attachments 5 and 7).

Additionally, minor editorial and typographical corrections are presented in Table 2 and identified as administrative with an "A" in the ITS Changes Markup (Attachment 2). These changes have been made to obtain consistency with NUREG-1430, "Standard Technical Specifications - Babcock and Wilcox Plants," and TSTF-GG-05-01, "Writer's Guide for Plant-Specific Improved Technical Specifications."

U. S. Nuclear Regulatory Commission Attachment I 3F0611-02 Page 2 of 35

'Table 1 CR-3 Operating License and Technical Specification Technical Changes

,OL/ITS Section '* Description of Cange, Basis ofChang e OL License Condition Revising core power level value The results of the analyses and evaluations 2.C.(1) to the EPU value; 3014 performed and discussed in the CR-3 EPU Megawatts. Additionally, TR demonstrate that the proposed increase deleting unnecessary in power can be safely and acceptably parenthetical statement, "100 achieved by satisfying applicable percent of rated core power acceptance criteria, provided the regulatory level." commitments in Attachment 10 are completed as stated.

OL License Condition Deleting CR-3 OL License During LOCA transients at EPU 2.C.(l 1) Condition 2.C.(1 1). conditions, boron may become concentrated in the reactor core due to boiling in the reactor vessel. Under certain temperature and concentration conditions, boron could precipitate out of solution, potentially reducing core heat transfer. OL Condition 2.C.(l 1) was approved in 1998 to assure the active methodologies for mitigating a boron precipitation condition (Dump-to Sump and Auxiliary Pressurizer Spray) were working effectively and that appropriate flow would be present in those lines. The LPI cross-tie and hot leg injection line will be installed to ensure that a portion of the LPI flow is injected into the hot leg and onto the core resulting in improved mixing and boron concentration control in the core as summarized in TR Appendix E, "Major Plant Modifications." As such, the requirement to maintain the OPERABILITY of the system of thennocouples on the Decay Heat Removal System drop line and the auxiliary pressurizer spray lines is no longer required.

U. S. Nuclear Regulatory Commission Attachment I 3F0611-02 Page 3 of 35 Table I CR-3.Operating License and Technical Specification-Technical Changes OL/ITS Sect'ion

-1...* Description

1. 1 of Change ,T 4,. ,Basis

. *.. of ..Change ITS Section 1.1, Revising DOSE As stated in TR Section 2.9.2, Definitions - DOSE EQUIVALENT 1-13 1 "Radiological Consequence Analyses,"

EQUIVALENT 1-131 definition to eliminate the DOSE EQUIVALENT 1-131 dose reference to thyroid dose conversion factors (DCFs) for inhalation conversion factors as listed in were extracted from EPA Federal ICRP 30 and revise wording to Guidance Report (FGR) No. 11 and the reference CEDE dose DCFs are unchanged from those approved conversion factors per EPA in CR-3 License Amendment 199 Federal Guidance Report No. regarding Alternate Source Term (AST)

11. EPU definition is modified and Control Room Emergency Ventilation as shown below. Revised System dated September 17, 2001. The wording is indicated in italics. NRC concluded in the NRC SE issuing Amendment 199 that CR-3 complies with DOSE EQUIVALENT 1-131 the requirements of 10 CFR 50.67 and that shall be that concentration of the licensing action is considered a full 1-13]1 (microcuries per gram) implementation of AST. The change to the that alone would produce the same dose when inhaled as definition of DOSE EQUIVALENT 1-131 is being made to be consistent with the the combined activities of AST requirements. This change does not iodine isotopes 1-131, 1-132, represent a technical change to the CR-3 1-133, 1-134, and 1-135 licensing basis in accordance with the NRC actually present. The SE issuing CR-3 License Amendment 199 determination of DOSE and is made to obtain consistency with the EQUIVALENT 1-131 shall be DOSE EQUIVALENT 1-131 DCFs used in petformed using Committed the EPU dose analyses.

Effective Dose Equivalent (CEDE)dose conversion factorsfrom Table 2.1 of EPA FederalGuidance Report No.

11, 1988, "Limiting Values of Radionuclide Intake and Air Concentrationand Dose Conversion Factorsfor Inhalation,Submersion, and Ingestion."

ITS Section 1.1, Modifying the MWt value from The proposed license amendment request Definitions - 2609 MWt to 3014 MWt and increases the authorized maximum power EFFECTIVE FULL modifying the MWhr from level from 2609 MWt to 3014 MWt.

POWER DAY (EFPD) 62616 to 72,336. Therefore, EFPDs will be calculated based on the new EPU power level. EFPD will continue to be calculated in the same manner as previously described. As a result, ITS Surveillance Frequencies based on EFPDs will continue to be performed consistent with current intervals.

U. S. Nuclear Regulatory Commission Attachment I 3F0611-02 Page 4 of 35 Table I CR-3 Operating License and Technical Specification Technical Changes OL/[TS sectiono Description of Change .Basis.of Change ITS Section 1.1, Revising core power value to The results of the analyses and evaluations Definitions - RATED the EPU value; 3014 MWt. performed and discussed in the CR-3 EPU THERMAL POWER TR demonstrate that the proposed increase (RTP) in power can be safely and acceptably achieved by satisfying applicable acceptance criteria.

ITS Figure 2.1.1-1 Replace current Figure with The new SL Figure matches the pressure Reactor Coolant System new EPU Figure. temperature limits calculated by the DNB DNB Safety Limits analyses at EPU conditions as summarized in TR Section 2.8.3, "Thermal and Hydraulic Design."

The new figure continues to ensure that the pressure/temperature operating region will preclude the reactor from exceeding a safety limit when operating up to EPU power.

U. S. Nuclear Regulatory Commission Attachment I 3F0611-02 Page 5 of 35 Table I CR-3 Operating.License and Technical Specification Technical Changes.

OL../ITS Section Description of Change Basis of Change ITS 3.1.1, SHUTDOWN Revise the LCO to relocate the Although the specific SDM value in MARGIN (SDM) minimum limit of 1.0 % Ak/k to MODES 3, 4, and 5 is not changing during the COLR. EPU conditions, the cycle-specific value of LCO 3.1.1 is being removed from ITS and controlled in the COLR. During EPU conditions, the SDM requirement in ITS 3.1.4, 3.1.5, and 3.2.1 is increased from 1.0 % Ak/k to 1.3% Ak/k. The increase in shutdown margin was required for the mitigation of the steam line break event to prevent post-trip return to criticality. The change to ITS 3.1.1 is being made to provide a consistent presentation with ITS 3.1.4, 3.1.5, and 3.2.1 as provided in NUREG-1430. The removal of the cycle-specific SDM limit from the ITS to the COLR is acceptable because SDM limits are developed under NRC-approved methodologies which ensure that the safety limits are met. These NRC-approved methodologies and associated SDM limit will continue to be adequately controlled in the COLR under the requirements provided in ITS 5.6.2.18, "CORE OPERATING LIMITS REPORT (COLR)." Additionally, the wording of LCO 3. 1.1 already requires SDM to be within the limits specified in the COLR. As such, the SDM value(s) specified in the COLR will continue at EPU conditions to ensure that the reactor is or would be subcritical from any plant condition in MODES 3., 4, and 5 assuming all control rods are fully inserted except for the single control rod of highest reactivity worth, which is assumed to be fully withdrawn.

U. S. Nuclear Regulatory Commission Attachment I 3F061 1-02 Page 6 of 35 Table I CR.3 Operating Licenseand Technical.Specification Technical Changes .

OL/ITS Section . Description of Change Basis of Change ITS 3.1.3, Moderator Revise the maximum positive During EPU conditions, the most limiting Temperature Coefficient MTC limit when < 95% RTP core overheating event, rod withdrawal (MTC) from < 0.9E-4 Ak/k/°F to accident from zero power (also referred to

< 0.75E-4 Ak/k/°F. as a startup accident), assumes a maximum positive MTC of 0.75 E-4 Ak/k/°F as summarized in TR Section 2.8.5.4.1, "Uncontrolled Rod Withdrawal from a Subcritical or Low-Power Startup Condition."

ITS 3.1.4, Control Rod Revise Required Actions The minimum SDM requirement assumed Group Alignment Limits A.2. 1.1, C. 1.1, and D. 1.1 to to ensure that the reactor can be made eliminate the SDM value and subcritical from EPU operating conditions verify SDM is, "within limits during the main steam line break accident, specified in the COLR." is increased from 1.0 % Ak/k to 1.3% Ak/k; refer to EPU TR Sections 2.8.5.0, Non-LOCA Analysis Introduction," and 2.8.5.1.2, "Steam System Piping Failures Inside and Outside Containment."

However, these changes are being made consistent with a similar change to LCO 3.11 and NUREG-1430, which specifies the limits in the COLR. The SDM value(s) specified in the COLR will continue at EPU conditions to ensure that the reactor is or can be made subcritical from any plant condition in MODES I and 2 assuming all control rods are fully inserted except the single highest reactivity worth control rod is fully withdrawn. Consistent with the current ITS, the SDM value(s) specified in the COLR will continue to assume the fuel and moderator temperatures are changed to the post-trip Reactor Coolant System (RCS) average temperature.

U. S. Nuclear Regulatory Commission Attachment I 3F0611-02 Page 7 of 35 Table 1 CR-3 Operating License and Technical Specification Technical Changes OL/ITS Section Description of Change Basis of Change ITS 3.1.5, Safety Rod Revise Required Actions The minimum SDM requirement assumed Insertion Limits A.2. 1.1 and B. 1.1 to eliminate to ensure that the reactor can be made the SDM value and verify SDM subcritical from EPU operating conditions is, "within limits specified in during the main steam line break accident, the COLR." is increased from 1.0 % Ak/k to 1.3% Ak/k.

Refer to EPU TR Sections 2.8.2, Nuclear Design, and 2.8.5.1.2, Steam System Piping Failures Inside and Outside Containment. However, these changes are being made consistent with a similar change to LCO 3.1.1, which relocates the specific SDM value to the COLR, and consistent with NUREG-1430. The SDM value(s) specified in the COLR will continue at EPU conditions to ensure that the reactor is or can be made subcritical from any plant condition in MODES I and 2 assuming all control rods are fully inserted except the single highest reactivity worth control rod is fully withdrawn.

Consistent with the current ITS, the SDM value(s) specified in the COLR will continue to assume the fuel and moderator temperatures are changed to the post-trip RCS average temperature.

ITS 3.1.8, PHYSICS Revise LCO 3.1.8.d The minimum SDM requirement assumed TESTS Exception - requirement to eliminate the to ensure that the reactor can be made MODE I SDM value and require SDM subcritical from EPU operating conditions is, "within limits specified the during the main steam line break accident, COLR." is increased from 1.0 % Ak/k to 1.3% Ak/k.

Also revise SR 3.1.8.4 to Refer to EPU TR Sections 2.8.2, Nuclear eliminate the SDM value and Design, and 2.8.5.1.2, Steam System verify SDM is, "within limits Piping Failures Inside and Outside specified in the COLR." Containment. However, these changes are being made consistent with the relocation of the specific SDM value to the COLR in ITS 3.1.4, ITS 3.1.5, and ITS 3.2.1.

U. S. Nuclear Regulatory Commission Attachment I 3F0611-02 Page 8 of 35 tC,11-3 Operating License and TFechnicall S-pecificatiou Technical Changes~

Q.l...TS Section Description of Change_ Basis of..hange ITS 3.1.9, PHYSICS Revise LCO 3.1 .9.c The minimirum SDM requirement assumed TESTS Exception - requirement to eliminate the to ensure that the reactor can be mnade MODE 2 SDM value and require SDM subcritical f-rom EPU operating conditions is, "within limits specified in during the main steamn line break accident, the COLR." is increased from 1.0 % Ak/k to 1,.3% Ak/k.

Also revise SR 3.1.9.3 to Refer to EPU TR Sections 2.8.2, Nuclear eliminate the SDM value and Design. and 2.8.5.1.2, Steam System verify SDM is, "within limits Piping Failures Inside and Outside spescrifiin the COLR." Containment. However, these changes are specfiedbeing made consistent with the relocation of the specific SDM value to the COLR in ITS 3.1.4, ITS 3.1.5. and ITS 3.2.1.

ITS 3.2.1, Regulating Revise Required Action C.I to The minimum SDM requirement assumed Rod Insertion Limits eliminate the SDM value and to ensure that the reactor can be made initiate boration to restore SDM subcritical from EPU operating conditions to, "within limits." during the main steam line break accident, Also revise SR 3.2.1.3 to is increased from 1.0 % Ak/k to 1.3% Ak/k.

eliminate the SDM value and Refer to EPU TR Sections 2.8.2, Nuclear verify SDM is, "within lidmts Design, and 2.8.5.1.2, Steam System specified in the COLR." Piping Failures Inside and Outside Containment. However, these changes are being made consistent with a similar change to LCO 3. 1.1, which relocates the specific SDM value to the COLR, and consistent with NUREG-1430. TheSDM value(s) specified in the COLR will Continue at EPU conditions to ensure that the reactor is or can be made subcritical from any plant condition in MODES I and 2 assuming all control rods are fully inserted except the single highest reactivity worth control rod is fully withdrawn.

Consistent with the Current ITS, the SDM value(s) specified in the COLR will continue to assume the fuel and moderator temperatures are changed to the post-trip RCS average temperature.

U. S. Nuclear Regulatory Commission Attachment I 3F0611-02 Page 9 of 35 r"Table P CR-3 Operating License and Technical Specification Technical Changes OL/ITS Section Description of Change Basis of Change.

ITS 3.3.1, Reactor Modified Required Action J. l Since CR-3 License Amendment 228 was Protection System (RPS) from "< 2568 MWth" to implemented, the secondary heat balance is

"<2965 MWt." calculated using high accuracy instrumentation with a 0.4% uncertainty.

However, without the high accuracy instrumentation, the secondary heat balance uncertainty is 2.0%, which is larger than the analysis assumptions; 1.6% larger uncertainty. As such, Required Action J.1 is modified to reduce THERMAL POWER 1.6% RTP (2965 MWt) to preserve EPU core power analysis assumption (112%

RTP) as identified in EPU TR Section 2.8.5.0, "Non-LOCA Analyses Introduction."

ITS 3.3.9, Source Range Revise Required Action B.4 to Although the specified value of 1.0 % Ak/k Neutron Flux eliminate the SDM value and is not changing as a result of EPU for the initiate boration to restore SDM source range neutron flux instrumentation, to, "within limits specified in this change to ITS 3.3.9 Required Action the COLR." B.4 is being made consistent with a similar change to LCO 3.1.1, which relocates the specific SDM value to the COLR, and consistent with NUREG-1430.

ITS 3.3.17, Post Modifying Table 3.3.17-1, As summarized in EPU TR Appendix E, Accident Monitoring Function 12, Not Used, to add "Major Plant Modifications," the HPI Flow (PAM) Instrumentation the HPI Flow Margin Function. Margin channels are used by the operator The new Function requires two in conjunction with other existing PAM channels to be OPERABLE in parameters (e.g., degrees of subcooling) to MODES 1, 2, and 3. ensure automatic actuation of the Fast Additionally, applicable Cooldown System (FCS) during a small ACTIONS and SRs are also break (SB) LOCA upon detecting a added. sustained loss of subcooling margin and inadequate HPI System flow. The HPI Flow Margin Function meets Regulatory Guide 1.97 Category I criteria. Refer below to Section 4.0, "Justification For Change," and to Attachment 4, "Improved Technical Specification Bases Changes (Markup)" for additional information regarding the basis for the HPI Flow Margin Function.

U. S. Nuclear Regulatory Commission Attachment I 3F0611-02 Page 10of35

Table 1.

CR-3 Operating License and Tecdhnical;Specification Technical Changes

,..:_ _,... Section

.. Change Basis_ of Ch:a:ng..e:_

j*OL/ITS

. .Section. Description .of Chag ., >>..;*.,Basis of Change

_ __:_ __. I _._ __._-_ _ _ ... _ _,. _ __.._ __._*

ITS 3.3.19, Inadequate Adding a new Technical Automatic opening of both ADVs is Core Cooling Specification; ITS 3.3.19, required for RCS fast cooldown during a Monitoring System Inadequate Core Cooling SBLOCA with sustained loss of subcooling (ICCMS) Monitoring System (ICCMS) margin and inadequate HPI System flow to Instrumentation Instrumentation. The ICCMS ensure 10 CFR 50.46 criteria are met with Instrumentation Technical core power > 2609 MWt. Therefore, the Specification requires channels ICCMS instrumentation channels required for each Function listed in to automatically initiate the FCS must be Table 3.3.19-1 to be OPERABLE when operating at a power OPERABLE as applicable in level > 2609 MWt.

Table 3.3.19-1. Appropriate Additionally, in certain spectrum of ACTIONS and SRs have been LOCAs, the reactor coolant pumps (RCPs) added.

are assumed to be tripped and Steam Generator (OTSG) secondary side water level raised to the inadequate subcooling margin (ISCM) level following a sustained loss of subcooling margin.

Refer below to Section 4.0, "Justification For Change," for a detailed summary regarding the basis for this change.

Refer to EPU TR Section 2.8.5.6.3, "Emergency Core Cooling System and Loss of Coolant Accidents," for summary of the LOCA assumptions.

Also, refer to Attachment 4, "Improved Technical Specification Bases Changes (Markup)" for additional information regarding the basis for the ITS ACTIONS and SRs.

U. S. Nuclear Regulatory Commission Attachment I 3F0611-02 Page 11 of 35

.Table.l . : i, CR-3 Operating License and Technical. Specification TechnichI Changes OL/ITS Section .. Description of Change J . Basis of Change ITS 3.3.20, Inadequate Adding a new Technical Automatic opening of both ADVs is Core Cooling Specification; ITS 3.3.20, required for RCS fast cooldown during a Monitoring System Inadequate Core Cooling SBLOCA with sustained loss of subcooling (ICCMS) Automatic Monitoring System (ICCMS) margin and inadequate HPI System flow to Actuation Logic Automatic Actuation Logic. ensure 10 CFR 50.46 criteria are met with The ICCMS Automatic core power > 2609 MWt (approximately Actuation Logic Technical 86.5% of EPU power). Therefore, the Specification requires two ICCMS actuation logic required to trains for each Function listed automatically initiate the FCS must be in Table 3.3.20-1 to be OPERABLE when operating at a power OPERABLE as applicable in level> 2609 MWt.

Table 3.3.20-1. Appropriate Additionally, in certain spectrum of ACTIONS and SRs have been LOCAs, the RCPs are assumed to be added.

tripped and OTSG secondary side water level raised to the ISCM level following a sustained loss of subcooling margin.

Refer below to Section 4.0, "Justification For Change," for a detailed summary regarding the basis for this change.

Refer to EPU TR Section 2.8.5.6.3, "Emergency Core Cooling System and Loss of Coolant Accidents," for summary of the LOCA assumptions.

Also, refer to Attachment 4, "Improved Technical Specification Bases Changes (Markup)" for additional information regarding the basis for the ITS ACTIONS and SRs.

ITS 3.4.1, RCS Pressure, SR 3.4.1.2 and SR 3.4.1.3: RCS total flow rate and RCS hot leg Temperature, and Flow Increase temperature limit to temperature limits have been modified to Departure From 611.2 0 F in SR 3.4.1.2 and ensure DNBR criteria are met at EPU Nucleate Boiling (DNB) increasing RCS total flow rate conditions in the event of a DNB-limited Limits for four RCP operation to 139.4 transient as summarized in EPU TR E6 lb/hr and three RCP Section 2.8.3, "Thermal and Hydraulic operation to 104.2 E6 lb/hr in Design."

SR 3.4.1.3.

U. S. Nuclear Regulatory Commission Attachment I 3F0611-02 Page 12 of 35

'Table I CR-3 Operating License and Technical Specification Techniical Changes OL/TS'Section Description of Change Basis of Change ITS 3.4.13, RCS Modifying the leakage criteria As described in EPU TR Appendix E, Pressure Isolation Valve in LCO 3.4.13 and SR 3.4.13.1. "Major Plant Modifications," a line will be (PIV) Leakage Revised wording is in stkeout installed from the proposed LPI System and italics: cross-connect to the decay heat drop line to "Leakage fromn each RCS PIV allow direct LPI-hot leg injection. This shall be:ý 5-gpm within ihnits flow path will mitigate boron precipitation.

and Automatic Closure and Two check valves will be installed to Interlock System (ACIS) shall prevent reverse flow into the LPI headers be OPERABLE." and provide an ASME Section XI boundary between RCS Loop B hot leg and Verify equivalent leakage from the LPI System boron precipitation each RCS PIV is within limit connection. As such, these valves are equivalent to < 0.5 gpm per considered RCS pressure isolation valves nominal inch of valve size up to and requirements are added to verify the a maximum of 5 gpm at an RCS leakage of these valves. Since these valves pressure of 2155 psig. are smaller than the existing PIVs and, therefore the leakage acceptance criteria is less than 5 gpm, the proposed wording of the LCO and SR is modified to reflect ASME Section XI requirements and to be consistent with NUREG 1430.

ITS 3.4.15, RCS SR 3.4.15.2, and Figure 3.4.15- The changes to the DEI-131 limits Specific Activity; 1; and Conditions A and B: specified in ITS 3.4.15 are being made to Modifying DOSE be conservative with respect to the initial EQUIVALENT 1-131 (DEl- RCS specific activity assumptions of 131) limit from 1.0 pCi/grn to 0.35 pCi/gm and 21 pCi/gm as summarized in EPU TR Section 2.9.2, 0.25, modi/gingSRo3.4.15.. t "Radiological Consequences Analyses."

Refer to EPU TR Section 2.9.2 for a be consistent with this change. summary of offsite and control radiological Additionally, eliminating ITS dose results at EPU conditions Figure 3.4.15-1 and providing a maximum accident limit of In addition, ITS Figure 3.4.15-1 is being 15 pCi/gm in ITS Required deleted. The proposed maximum accident Action A. I and Condition B. DEI-1 31 limit will no longer vary with power. The maximunlm accident DEI-l31 limit is based on accident analyses cases that assume 60 times the initial value due to an iodine spike caused by a reactor or an RCS transient prior to the accident.

U. S. Nuclear Regulatory Commission Attachment I 3F0611-02 Page 13 of 35 Table I CR-3 Operating License and Technical Specification Technical Changes OLUITS Section Description of Change Basis of Change ITS 3.5.1, Core Flood SR 3.5.1.4: The minimum boron concentration Tanks (CFTs) Raising the lower boron requirement is being increased to ensure Rnnaising thethat the reactor, under EPU conditions, will concentration260limi oremain subcritical during the reflood stage 2270 ppm to 2600 ppm. of a large break LOCA as summarized in EPU TR Section 2.8.2, "Nuclear Design."

ITS 3.5.2, Emergency Adding SR 3.5.2.8 to require; As described in EPU TR Section 2.8.5.6.3 Core Cooling System "Verify the following valves in "Emergency Core Cooling System and (ECCS) - Operating the LPI flow path are locked, Loss of Coolant Accidents," certain spectra of LOCAs assume LPI flow via the LPI sealed or ositherwis: scross-tie line. To ensure the LPI cross-tie the correct position: line flow path is available, this change is

a. DHV-500; made to ensure the proper LPI valve lineup

b. DHV-501; for ECCS OPERABILITY. The 24 month

c. DHV-600; and Frequency is based on the need to perforn

d. DHV-601." this Surveillance under the conditions that apply during a plant outage and the The Frequency of the new SR is potential for an unplanned transient if the 24 months. Surveillance were performed with the reactor at power.

ITS 3.5.4, Borated Water SR 3.5.4.3: The minimum boron concentration Storage Tank (BWST) Raising the lower boron requirement is being increased to ensure concentration limit of that, following a LOCA at EPU conditions, 2270 nppc to 2600 ppm. with a minimum BWST level, the reactor will remain subcritical in the cold shutdown condition following mixing of the BWST and RCS water volumes as summarized in EPU TR Section 2.8.2, "Nuclear Design."

ITS 3.6.4, Containment LCO 3.6.4 and SR 3.6.4. 1: To ensure adequate margin to peak Pressure Lowering the initial pressure and temperature acceptance criteria at EPU conditions during a LOCA, contaimient positive pressure the initial containment pressure assumed in limit of +3.0 psig to +1.5 psig. the containment overpressure analyses is lowered to + 16.2 psia (+1.5 psig) as summarized in EPU TR Section 2.6.1, "Primary Containment Functional Design."

U. S. Nuclear Regulatory Commission Attachment I 3F0611-02 Page 14of35 Table I :

CR3 Operating LicenSe and Technical Specification Technical Changes "OL/ITSSection.. 4Description of Change Basis of Change ITS 3.7.5., Emergency Adding a new SR; SR 3.7.5.7. As summarized in EPU TR Appendix E, Feedwater (EFW) "Major Plant Modifications," EFW flow The new SR requires a System requirements are increased roughly performance of a CHANNEL proportion to decay heat at EPU CALIBRATION of the required conditions. The current EFW flow EFW pump flow requirement for Loss of Feedwater is 275 instrumentation every 24 gpm per OTSG. At EPU conditions, the months.

EFW flow requirement increases to 330 gpm per OTSG. In order to increase the flow sufficiently the EFW pump low flow instrumentation will be modified to automatically isolate recirculation flow when the EFW pumps are automatically actuated and flow reaches an appropriate range. Refer to Section 2.8.5.2.3, "Loss of Normal Feedwater," for summary of the LOFW assumptions.

SR 3.7.5.7 is added to ensure the EFW pump minimum flow instruments open the associated EFW pump recirculation line isolation valves to provide pump low flow protection and close the associated EFW pump recirculation line isolation valves in time to ensure adequate EFW discharge flow to the OTSGs as assumed in the safety analysis. The Frequency is based on the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift in the EFW pump low flow instrumentation calculations.

U. S. Nuclear Regulatory Commission Attachment I 3F0611-02 Page 15 of 35 Table I CR-3 Operating License and Technical Specification Technical Changes.

OL/ITS Section Description of.Change Basis of Change ITS 3.7.14, Spent Fuel Applicability and Required As summarized in EPU TR Section Pool Boron Actions: 2.8.6.2., "Spent Fuel Storage," the spent Concentration Modifying Applicability to fuel storage criticality analyses indicate the state: "When fuel assemblies limiting boron concentration assumptions are stored in the spent fuel of 203 ppm for nonrnal conditions and 571 eppm for accident conditions in Pool B are required to meet the criticality design Also, eliminating Required requirements. Therefore, this change is Action A.2.2 and renumbering made to require spent fuel pool boron Required Action A.2.1 to A.2. concentration to be maintained within the limit at all times while fuel assemblies are stored in the spent fuel pool to ensure both CR-3 fuel storage pools remain subcritical under all CR-3 licensing basis conditions.

Required Action A.2.2 is being eliminated and Required Action A.2.1 renumbered to A.2 to reflect the change to the Applicability.

ITS 3.7.19, Diesel Condition A and SR 3.7.19.1: To ensure there is adequate inventory of Driven EFW (DD-EFW) Modifying Condition A, DD- fuel oil in the DD-EFW supply tank to Pump Fuel Oil, Lube Oil EFW Supply tank Volume support operation of the DD-EFW pump and Starting Air values from 9,480 and 8,335 to for 7 days and 6 days, assuming no offsite 9800 and 8600, respectively, power and 10 CFR 50 Appendix K decay Modifying SR 3.7.19.1 volume heat removal EFW flow requirements value associated with the DD- during EPU conditions, the DD-EFW value assuppy wtankhrom9 D the supply tank volume values are increased as EFW supply tank from 9,480 to summarized in EPU TR Section 2.5.4.5.

9800. "Emergency Feedwater System."

U. S. Nuclear Regulatory Commission Attachment I 3F0611-02 Page 16 of 35

,Tablei.

CR-3'Operating License and Technical Specification TechnicaI Changes OL/ITS Section Description of Change Basis of Change ITS 3.7.20, Fast Adding a new Technical Automatic opening of both ADVs is Cooldown System (FCS) Specification; ITS 3.7.20., Fast required for RCS fast cooldown during a Cooldown System (FCS). The SBLOCA with sustained loss of subcooling FCS Technical Specification margin and inadequate HPI flow to ensure requires the FCS to be 10 CFR 50.46 criteria are met with core OPERABLE when THERMAL power > 2609 MWt (approximately POWER > 2609 MWt. 86.5% of EPU power). Therefore, the FCS Appropriate ACTIONS and function of the ADVs must be OPERABLE SRs have been added. when operating at a power level

> 2609 MWt. Refer to EPU TR Section 2.8.5.6.3, "Emergency Core Cooling System and Loss of Coolant Accidents,"

for summary of the SBLOCA assumptions.

Refer below to Section 4.0, "Justification For Change," for a detailed summary regarding the basis for this change.

Also, refer to Attachment 4, "Improved Technical Specification Bases Changes (Markup)" for additional information regarding the basis for the ITS ACTIONS and SRs.

ITS 4.3.1, Criticality Revising as following: As summarized in EPU TR Section ITS 4.3. 1.Lb - Modifying k*f 2.8.6.2., "Spent Fuel Storage," the spent 0TS.95 to b 1fuel Modifn k storage criticality analyses indicate that to maintain keff < 0.95 under normal Adding ITS 4.3. 1.1 .c - Keff< conditions, boron concentration must be at 0.95 if flooded with borated least 141 ppm in Pool A and 203 ppm in water at a soluble boron Pool B, including uncertainty as allowed concentration of 141 ppm in the per CR-3 FSAR Section 9.6. Additionally, A pool and 203 pprn in the B if fully flooded with unborated water, spent pool, which includes an fuel storage criticality analyses indicate allowance for uncertainties as kef- will remain below 1.0. including described in Section 9.6 of the uncertainty as allowed per CR-3 FSAR FSAR; and Section 9.6. Therefore, these changes are Renumbering ITS 4.3. 1. I .c and made to reflect the EPU fuel storage 4.3.1.1 .d to ITS 4.3.1 .1.d and criticality safety analyses. Also, ITS 4.3.1.1Le, respectively. 4.3.1.1 .c and 4.3.1.1 .d are renumbered to ITS 4.3.1. l.d and 4.3.1. .e, respectively to reflect the addition of ITS 4.3. 1. 1.c.

U. S. Nuclear Regulatory Commission Attachment I 3F0611-02 Page 17 of 35

".Table1 CR-3 Operating License and Technical Specification Technical Changes OL/ITS Section 'Descriptiii of Change Basis of Change ITS 5.7.2, Special Modifying first sentence of ITS New specifications related to ICCMS are Reports 5.7.2.a. being added as a result of EPU; ITS 3.3.19 and ITS 3.3.20. The ACTIONS require Revised wording is in st4keeu initiating action in accordance with and italics:

Specification 5.7.2.a. This change is made When a Special Report is to refer to the specific Required Actions in required by Condition B or F of ITS 3.3.19 and ITS 3.3.20 consistent with LCO 3.3.17, "Post Accident the current ITS 5.7.2.a presentation.

Monitoring (PAM)

Instrumentation-- ," requiredby Condition C of LCO 3.3.19, "InadequateCore Cooling Monitoring System (JCCMS)

Instrumentation; "or required by Condition C of LCO 3.3.20, "InadequateCore Cooling Monitoring System (ICCMS)

Automatic Actuation Logic:" a report shall be submitted within the following 14 days.

U. S. Nuclear Regulatory Commission Attachment 1 3F0611-02 Page 18 of 35 Table 2 CR-3 Operating License and Technical Specification Administrative Changes OL/ITS Section Descriptionf Change . Basis of Change.

ITS Table Of Contents Delete ITS Table Of Contents The ITS TOC does not provide (TOC). any technical information and revisions to the ITS TOC have no impact on operational safety. As such, the ITS TOC will be removed from the ITS.

Revisions to the TOC will made using CR-3 administrative processes.

This change does not result in a technical change and is administrative in nature.

ITS 3.1.1, SHUTDOWN Revise the wording of the LCO The changes to ITS 3.1.1 are MARGIN (SDM) and SR. The LCO and SR are being made to provide consistent revised as indicated below, presentation as provided in Revised wording is in strkeeat NUREG-1430. The removal of and italics, the cycle-specific SDM limit from the ITS to the COLR is discussed in Table I, CR-3 "The SDM shall be g.eate.. *,aft Operating License and Technical of-equa4lte he within limits Specification Changes." These specified in the COLR." changes do not result in a technical change and are administrative in nature.

"Verify SDM is greater thanm equ-ial

.t the within limits specified in the COLR."

ITS 3.1.3, Moderator LCO 3.1.3: In this proposed EPU license Temperature Coefficient (MTC) Damendment request, this change Deleted space between Ak in two is made to correct a format error.

places. This change does not result in a technical change and is administrative in nature.

ITS 3.3.1, Reactor Protection SR 3.3.1.2: In this proposed EPU license System (RPS) Instrumentation Correcting typographical error; amendment request, this change Deletingis made to correct a typographical error. This change does not result in a technical change and is administrative in nature.

U. S. Nuclear Regulatory Commission Attachment I 3F0611-02 Page 19 of 35 Table 2 CR-3 Operating License and Technical Specification Administrative Changes

.OL/TSSecIin .. .. pDescpiton of Change' Basis.of Change ITS 3.3.17, Post Accident SR 3.3.17.2 Notes: In this proposed EPU license Monitoring (PAM) Refornatted and numbered the amendment request, this Instrumentation Notes of SR 3.3.17.2. presentation preference is made to obtain consistency with NUREG-1430. This change does not result in a technical change and is administrative in nature.

ITS 3.5.1 Core Flood Tanks Adding a line to separate In this proposed EPU license (CFTs) Condition A from Condition B, amendment request, these adding a period after last word in changes are made to correct Required Actions A.], B.l, and typographical errors. The SR 3.5.1.2. changes do not result in a technical change and are administrative in nature.

ITS 3.5.2, Emergency Core SR 3.5.2.6: In this proposed EPU license Cooling System (ECCS) Added "and" to list of LPI amendment request, this change Addotled "an olist is made to obtain consistency with SR 3.5.2.5, NUREG-1430, and the ITS Writer's Guide. This change does not result in a technical change and is administrative in nature.

ITS 3.5.4, Borated Water Storage Adding a close parenthesis In this proposed EPU license Tank (BWST) symbol after BWST. amendment request, this change is made to correct a typographical error. This change does not result in a technical change and is administrative in nature.

ITS 3.7.1, Main Steam Safety Table 3.7.1-1: In this proposed EPU license Valves (MSSVs) Adding a period between the amendment request, this change seven and the one instead of a is made to correct a hyphen in the Table number. typographical error. This change does not result in a technical change and is administrative in nature.

U. S. Nuclear Regulatory Commission Attachment I 3F0611-02 Page 20 of 35

>>>.Table'?2 ... ... 4>

CR-3 Operating License andTechnical Specification Administrative Changes .

OLA/TS Section Description of Change Basis of Change ITS 3.7.5, Emergency Feedwater Making formatting corrections; In this proposed EPU license (EFW) System Adding a line space; and amendment request, this change is made to obtain consistency Capitalizing the word "Mode" with NUREG-1430 and the ITS (MODE) in ACTION C. Writer's Guide. This change does not result in a technical change and is administrative in nature.

ITS 3.7.14, Spent Fuel Pool LCO 3.7.14; In this proposed EPU license Boron Concentration Adding a space between the amendment request, this change greater than symbol and the 1925 is made to correct a grevalue.t stypographical does not resulterror. This change in a technical change and is administrative in nature.

ITS 3.7.19, Diesel Driven EFW Making formatting corrections: In this proposed EPU license (DD-EFW) Pump Fuel Oil, Lube Modifying words "Diesel Driven amendment request, this change Oil and Starting Air EFW" to "DD-EFW" in Header is made to obtain consistency title; with NUREG- 1430 and the ITS Writer's Guide. This change Adding line spaces in three does not result in a technical places; and change and is administrative in Adding hanging indent to nature.

Applicability statement.

In summary, CR-3 has reviewed the OL and ITS and has determined that only the OL and ITS revisions described in Table I above are required to properly control plant operations and configuration under EPU conditions. Plant documents will be revised, as necessary, after approval of this LAR. Markups of the proposed OL and ITS pages are provided in Attachment 2 and revised (Revision Bar) pages are provided in Attachment 3. A copy of the proposed markup of the ITS Bases is provided in Attachment 4 and is provided for information only.

Additional license basis changes are requested in support of this EPU submittal. These requests consist of the following changes:

0 Credit the use of the ICCMS, FCS, and ADVs to assist the ECCS during a SBLOCA;

U. S. Nuclear Regulatory Commission Attachment I 3F0611-02 Page 21 of 35

" Credit the new LPI System HLI line as the primary method of boron precipitation mitigation during a LOCA, thereby eliminating the need for the two active methods currently credited and allowing deletion of CR-3 OL License Condition 2.C.1 1;

Credit the use of the LPI System cross-tie line in the mitigation of a core flood tank (CFT) line break accident;

Credit the use of soluble boron in the spent fuel pool to preclude spent fuel pool criticality accidents as allowed by 10 CFR 50.68(b)(4); and

Revise the RCS pressure acceptance criterion for feedwater line break (FWLB) accident consistent with the criterion in NUREG-0800, "Standard Review Plan" (SRP), Section 15.2.8, "Feedwater System Pipe Break Inside And Outside Containment (PWR),"

Revision 2 (March 2007).

3.0 BACKGROUND

CR-3 proposes to operate the reactor at 3014 MWt, an approximate 15.5% increase from the current authorized OL reactor core power level. CR-3 has defined this power increase as an EPU consistent with the guidance of the Office of Nuclear Reactor Regulation's Review Standard (RS)-001, "Review Standard for Extended Power Uprates," Revision 0.

Florida Power Corporation (FPC) has evaluated the proposed EPU for the applicable systems, structures, components, and safety analyses at CR-3 in accordance with the guidance of RS-00 1.

The results of these evaluations are described in the CR-3 EPU TR (Attachments 5 and 7). The EPU TR provides the technical details that support the requested OL and ITS changes and, in concert with the other attachments, provide a comprehensive evaluation of the effects of the proposed EPU on CR-3 plant operation.

4.0 JUSTIFICATION FOR THE CHANGE The acceptability for each proposed OL and ITS change is addressed in Tables I and 2 in Section 2.0 above. Additional details and justification are provided below for the additional licensing basis items. The EPU TR summarizes the evaluations performed to assure acceptable unit operation at EPU conditions and is therefore referenced throughout this section as additional technical justification for the EPU related changes. Additional detail is also provided for the plant modifications in EPU TR Appendix E, "Major Plant Modifications."

4.1 ICCMS. ADVs and FCS CR-3 requests approval to credit the use the ICCMS and the FCS function of the ADVs to assure adequate core cooling during a SBLOCA at EPU conditions. The FCS is assumed in the SBLOCA analyses to open both ADVs to depressurize the secondary plant and ultimately the RCS which will allow ECCS to provide adequate core cooling in the event of a single failure of an HPI train as summarized in EPU TR Section 2.8.5.6.3, "ECCS and Loss of Coolant

U. S. Nuclear Regulatory Commission Attachment I 3F0611-02 Page 22 of 35 Accidents," and TR Appendix E. A new ICCMS will provide instrumentation to automatically initiate the FCS and provide indication to ensure the ICCMS actions are performed.

The ICCMS will also automatically trip the RCPs and send a signal to the Emergency Feedwater Initiation and Control (EFIC) System which will raise OTSG secondary side level to the inadequate subcooling margin (ISCM) level to support certain spectrum of LOCAs as summarized in EPU TR Section 2.8.5.6.3. The automatic actions to trip the RCPs and adjust the EFIC System to the ISCM level setting replace the current actions performed by the operator, thus reducing the reliance on manual operator action for event mitigation.

The FCS function of the ADVs will assure that CR-3 is capable of mitigating the effects of a SBLOCA at EPU conditions. Preliminary analysis indicated that for the range of SBLOCA events, the HPI System flow, using single failure considerations, is not sufficient for core cooling in the early stages of all accident. Additionally, the initial pressure in the RCS remains too high for the CFTs to provide adequate flow to the core. Inadequate HPI System flow would result in elevated peak clad temperatures and oxidation levels prior to achieving RCS conditions where sufficient core cooling can be provided.

The FCS will automatically actuate safety-related ADVs to rapidly reduce secondary pressure in the Main Steam System which increases primary-to-secondary heat transfer thereby decreasing temperature and pressure in the RCS. The intent of this plant modification is to rapidly reduce the RCS pressure to below the CFT discharge pressure which would increase ECCS flow to the reactor vessel and maintain the fuel within limits. LOCA analyses at EPU conditions assume both HPI pumps with adequate flow or one HPI pump and two ADVs are available to ensure sufficient core cooling.

The FCS will initiate within 10 minutes of the onset of sustained loss of sub-cooling margin and inadequate HPI flow. By rapidly reducing and controlling the secondary pressure in the OTSG, the RCS pressure has been analytically demonstrated to decrease sufficiently to allow timely addition of CFT liquid and additional flow from the HPI System to begin injecting into the core.

The analysis performed for this event shows that the results are acceptable and all 10 CFR 50.46 acceptance criteria are satisfied. Enclosure 2 of EPU TR Appendix E provides specific information related to the ADVs and FCS plant modification.

The ICCMS monitors specific parameters; HPI System flow, RCS pressure, and core exit thermocouples (CETs) to determine core degrees of subcooling and to determine if a loss of subcooling margin (SCM) exists. Additionally, the total HPI flow is compared to a generated curve of minimum HPI flow versus RCS pressure to determine inadequate HPI flow.

Following a sustained loss of SCM and inadequate HPI flow, ICCMS initiates FCS within 10 minutes which automatically opens both ADVs to ensure sufficient core cooling during a SBLOCA. Additionally, upon a sustained loss of SCM, the ICCMS will automatically trip the RCPs within one minute and within 10 minutes send a signal to the Emergency Feedwater

U. S. Nuclear Regulatory Commission Attachment I 3F0611-02 Page 23 of 35 Initiation and Control (EFIC) System which will raise OTSG secondary side level to the ISCM level. These automatic actions replace the current actions performed by the operator, thus reducing the reliance on manual operator action for event mitigation. Enclosure 3 of EPU TR Appendix E provides specific information related to the ICCMS plant modification.

ITS 3.3.17, "Post Accident Monitoring (PAM) Instrumentation," will be revised to include an additional instrument function (HPI Flow Margin) which, along with existing PAM instruments, will provide operators with indication necessary to ensure FCS initiates when required. The new ICCMS will provide redundant displays consistent with the criteria of Regulatory Guide 1.97.

The ICCMS computes HPI flow margin, degrees of subcooling, and will provide operators with a fully qualified, safety related method of monitoring these parameters and determining inadequate HPI flow and a loss of subcooling margin, thereby ensuring initiation of the FCS in a timely manner.

Refer to Attachment 4, "Improved Technical Specification Bases Changes (Markup)," for further basis information related to revisions to ITS 3.3.17.

ITS 3.3.19, "Inadequate Core Cooling Monitoring System (ICCMS) Instrumentation," and ITS 3.3.20, "Inadequate Core Cooling Monitoring System (ICCMS)," will be added to address the requirements related to the automatic initiation of FCS, RCP trip, and OTSG ISCM level setpoint adjustment.

Regarding proposed ITS 3.3.19 and ITS 3.3.20:

Applicability of the FCS instrument functions and logic is consistent with current licensed power level (2609 MWt) to support the FCS function of the ADVs. The Applicability is considered acceptable since with power at or below 2609 MWt, the ECCS can provide sufficient core cooling during a LOCA assuming a single failure of one HPI subsystem without the need for the FCS function of the ADVs.

Applicability of the RCP Trip and OTSG ISCM Level Setpoint Actuation instrument functions and logic is consistent with the Applicability of ITS 3.3.17. These automatic functions are intended to reduce the reliance on manual operator action and therefore, the Applicability is considered acceptable since it is equivalent to the Applicability of the current indication requirements necessary to perform these actions manually.

Appropriate ITS ACTIONS are provided to address inoperability the ICCMS instrumentation and logic. The proposed Required Actions and Completion Times are consistent with the current licensing basis ACTIONS, which rely on PAM instrumentation for credited manual operator actions for these same and similar functions.

ITS 3.3.17, which provide PAM instrument requirements needed to support current credited manual operator actions, will continue to require a plant shutdown if required PAM instrumentation is not available to perform these manual actions. Also, proposed ITS 3.3.17, which provides an additional PAM instrument requirement to support manual

U. S. Nuclear Regulatory Commission Attachment I 3F0611-02 Page 24 of 35 actuation of FCS, will require a power reduction to a level where the FCS function of the ADVs is no longer required if the PAM instrument is not available to manually actuate the FCS.

o With one or more required channels or logic trains inoperable, the inoperable equipment must be restored to OPERABLE status within 30 days. The 30 day Completion Time takes into account the provisions to support manual actuation of the FCS, RCP trip, and OTSG ISCM Setpoint adjustment. The 30 day Completion Time is also considered acceptable based on maintaining FCS actuation capability and the low probability of an event requiring the ICCMS during this time period.

o For the RCP Trip and OTSG ISCM Level Setpoint Actuation instrument functions and logic, if an associated channel or logic train is not restored to OPERABLE status within the allowed Completion Time, action must be initiated in accordance with Specification 5.7.2, "Special Reports," to submit a special report to the NRC within 14 days. The special report will discuss the preplanned alternate method of monitoring, the cause of the inoperability, and provide a schedule for restoring the ICCMS instruments and logic to OPERABLE status.

This proposed Required Action is considered acceptable since the CR-3 current licensing basis credits manual operator action for RCP trip and OTSG ISCM Setpoint adjustment. ITS 3.3.17, which provide PAM instrument requirements needed to support the current credited manual operator actions, will continue to require a plant shutdown if appropriate PAM instrumentation is not available to perform these manual actions.

o For the FCS Actuation instrument functions and logic, if an associated channel or logic is not restored to OPERABLE status within the allowed Completion Time or automatic FCS actuation capability is not maintained, the FCS function of the ADVs will be immediately declared inoperable and action taken in accordance with the requirements of ITS 3.7.20.

Appropriate SRs are provided to ensure the ICCMS instruments and logic trains are capable of performing their intended safety function. CHANNEL CHECK, CHANNEL FUNCTIONAL TEST, and CHANNEL CALIBRATION tests are provided to verify the functionality of the ICCMS instrumentation and automatic actuation logic. Additional automatic actuation logic CHANNEL FUNCTIONAL TESTS are added to verify RCP breaker actuation and OTSG ISCM level setpoint actuation every refueling interval since these end devices have no other Technical Specification testing requirements. ADV actuation testing is performed in accordance with surveillances specified in ITS 3.7.20.

Refer to Attachment 4, "Improved Technical Specification Bases Changes (Markup)," for further basis information related to proposed ITS 3.3.19 and ITS 3.3.20.

U. S. Nuclear Regulatory Commission Attachment I 3F0611-02 Page 25 of 35 ITS 3.7.20, "Fast Cooldown System (FCS)," will be added to address the requirements for the FCS function of the safety related ADVs.

Regarding proposed ITS 3.7.20:

" Applicability of proposed ITS 3.7.20 is consistent with current licensed power level (2609 MWt) to support the FCS function of the ADVs. The Applicability is considered acceptable since with power at or below 2609 MWt, the ECCS can provide sufficient core cooling during a LOCA assuming a single failure of one HPI subsystem without the need for the FCS function of the ADVs.

" Appropriate ITS ACTIONS are provided in ITS 3.7.20 to address inoperability of the FCS function of the ADVs and the impact on SBLOCA event mitigation.

o With the FCS inoperable due to inoperable backup air supply, 7 days is provided to restore the inoperable backup air supply to OPERABLE status. The 7 day Completion Time is consistent with Completion Times in NUREG-1430 for similar levels of system degradation and is acceptable based on multiple sources of air that can provide the ADVs.

o With the FCS function inoperable for reasons other than backup air supply, 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is provided to restore the FCS to OPERABLE status provided both HPI subsystems are OPERABLE.

" The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is consistent with a single failure Completion Time of one ECCS train inoperable per ITS 3.5.2, "ECCS-Operating," and is considered a reasonable time to repair the inoperable FCS components.

" If either HPI subsystems is determined to be inoperable or the FCS is not restored with the required Completion Time, one hour is provided to reduce power to at or below 2609 MWt. The Required Action to reduce power to the pre-EPU license power level provides an appropriate compensatory measure since below this power the FCS is not required to mitigate a SBLOCA; one HPI train is capable of mitigating the SBLOCA.

The one hour Completion Time will ensure prompt action is taken to reduce power where FCS is no longer required for ECCS to perforn its function during a SBLOCA and is consistent with the one hour provided in LCO 3.0.3 for loss of safety function conditions.

U. S. Nuclear Regulatory Commission Attachment I 3F0611-02 Page 26 of 35 Appropriate SRs are provided to ensure the ADVs and FCS are capable of performing their intended safety function in the event of a SBLOCA. The periodic verification of the Backup Air System pressure and volume is added to ensure the ADVs can maintain at least four hours of operation. A CHANNEL CALIBRATION test is provided to verify the functionality of the FCS automatic actuation circuitry and calibration of the FCS OTSG modulating controller. Two SRs are added to verify the capability and capacity of the FCS backup battery system. An additional SR is added to verify that on actual or simulated actuation signal, the ADVs will open and cycle as required.

Refer to Attachment 4, "Improved Technical Specification Bases Changes (Markup)," for further basis information related to proposed ITS 3.7.20.

4.2 Boron Precipitation Mitigation CR-3 requests approval to credit the LPI System HLI line to prevent boron precipitation in the reactor vessel during design basis accidents at EPU conditions thereby eliminating the need for the current active boron precipitation mitigation methodologies required in the CR-3 OL.

Existing boron precipitation mitigation methodologies at CR-3 consist of two approved, active techniques that provide sufficient liquid movement through the reactor core to preclude boric acid from precipitating out of solution and potentially clogging flow passages in the fuel or settling on the fuel rods causing a decrease in heat transfer. The most likely occurrence of boron precipitation is during the recirculation phase of an accident when the level in the reactor vessel is below the top of the fuel and boiling is in process. The current licensing and design bases methodologies to preclude this condition are: the Dump-to-Sump of RCS fluid from the hot leg to the Reactor Building sump using the Decay Heat Removal (DHR) System drop line; and hot leg injection via the auxiliary pressurizer spray line. These methodologies allow for additional flow through the reactor core that would preclude the precipitation or plating out of the boron.

As stated in the Crystal River Unit 3 Issuance of Exemption from the Requirements of 10 CFR Part 50, Appendix K, Section I.D. I, dated October 29, 1998, the NRC acknowledged that the reactor vessel vent valves may not be effective in preventing boron precipitation for specific break locations. Due to specific vulnerabilities associated with these active methods, a single failure criterion exemption was granted to CR-3. Additionally, evaluation has shown that these methods cannot be expanded to provide sufficient flow at EPU conditions to adequately preclude boron precipitation.

The current exemption related to boron precipitation mitigation methods is associated with the active failure of a single Engineered Safeguards motor control center (MCC) that supplies electrical power to both active methods of preventing boron precipitation. At EPU conditions, prevention of boron precipitation during LOCAs will be accomplished through the use of the LPI System HLI line and CR-3 will no longer require the existing single failure criterion exemption.

Existing procedural guidance requires that the boron precipitation mitigation function occur after a certain boron concentration in the core is reached. The procedure directs that boron

U. S. Nuclear Regulatory Commission Attachment I 3F0611-02 Page 27 of 35 concentration be sampled after the ECCS pump suction swap to the sump is complete and adequate core cooling is not occurring. The currently credited method of determining boron concentration is the Post Accident Sampling System Boronometer. Should the boronometer be unavailable, manual sampling and analysis is also credited.

The new HLI actuation will not be based on core boron concentration and precludes the need for continued use of the boronometer. CR-3 will discontinue reliance on the boronometer once use of the new HLI line is approved and implemented.

The new HLI line provides a flow path for boron precipitation control, thus assuring compliance with the long term core cooling acceptance criterion by providing a flow path to inject a portion of LPI System flow into the DHR System drop line. The HLI line is normally closed, but will be opened by the operators during the transition to the sump recirculation, which will be prior to the occurrence of significant boron concentration in the core. The HLI line is hydraulically designed to provide sufficient flow to prevent boron precipitation for the entire spectrum of LOCA break sizes. For large break LOCAs, the HLI flow exceeds the core boiloff shortly after its initiation.

The excess HLI flow that is not boiled off by the core decay heat dilutes the core boron concentration via reverse core flow prior to the core reaching concentrations that could precipitate. For SBLOCAs, the RCS pressure could be above the LPI pump shutoff head or in the range where the HLI flow does not match core boiloff. However, at these elevated RCS pressures, the solubility limit is above the maximum boron concentration that the core could achieve. The HLI flow will increase as RCS pressure decreases such that the flow matches the core boiloff rate and provide a boron dilution flow prior to reaching the solubility limit. The HLI line design meets the single failure criterion of CR-3 FSAR Criterion 1.4.38. Therefore, the existing single failure criterion exemption is no longer necessary and may be removed from the CR-3 license basis.

EPU TR Section 2.8.5.6.3 provides additional discussion related to boron precipitation mitigation. Enclosure I of the CR-3 EPU TR Appendix E provides specific information related to the LPI System cross-tie line modification, including the HLI line design.

ITS Section 3.4.13, "RCS PIV Leakage," will be revised to address the new series check valves in the HLI line used to provide pressure isolation between high and low pressure systems. These valves are smaller than the current PlVs required in LCO 3.4.13, and as such, the guidance in NUREG 1430 will be incorporated for the LCO and surveillance acceptance criteria related to leakage through the valves. Refer to Attachment 4, "Improved Technical Specification Bases Changes (Markup)," for further information related to proposed changes to ITS 3.4.13.

4.3 Core Flood Line Break Mitigation CR-3 requests approval to credit the use of the LPI System cross-tie line in the mitigation of a CFT line break accident.

U. S. Nuclear Regulatory Commission Attachment I 3F0611-02 Page 28 of 35 During a CFT line break accident coincident with a LOOP assuming one emergency diesel generator (EDG) fails to start, one ECCS train associated with the failed EDG will not be available for coolant injection. The remaining LPI subsystem, powered by the operating EDG, may be unavailable for coolant injection if aligned to the broken CFT line. As a consequence, only one HPI subsystem and one CFT will be available to provide ECCS flow into the RCS. At pre-EPU conditions, the intact CFT flow and HPI flow are adequate to meet the IOCFR50.46 acceptance criteria. However, at EPU conditions, the increased core decay heat power increases the core boil off rates, slowing the RCS depressurization rate and slightly reducing the ECCS flow. As a consequence, one HPI subsystem and the inventory of one CFT are not adequate to mitigate a CFT line break accident. The LPI System cross-tie line modification ensures the availability of some LPI flow for the larger CFT line breaks by providing a passive LPI crossflow path and the CFT line break analyses at EPU conditions continue to demonstrate compliance with 10 CFR 50.46. EPU TR Section 2.8.5.6.3 provides additional discussion related to CFT line break mitigation. Enclosure I of the CR-3 EPU TR Appendix E provides specific information related to the LPI System cross-tie line modification.

ITS Section 3.5.2, "Emergency Core Cooling Systems (ECCS) - Operating," and associated Bases will be revised to add ECCS OPERABILITY requirements associated with the LPI cross-tie line, including an SR to ensure the proper LPI cross-tie line valve lineup. Refer to Attachment 4, "Improved Technical Specification Bases Changes (Markup)," for further information related to proposed changes to ITS 3.5.2.

4.4 Credit Soluble Boron in Spent Fuel Pool CR-3 requests approval to credit the use of soluble boron in the spent fuel pool to preclude spent fuel pool criticality accidents as allowed by 10 CFR 50.68(b)(4).

At pre-EPU conditions, the spent fuel storage criticality analysis does not credit soluble boron when fuel assemblies are loaded in a specific pattern. The reactivity of the fuel racks alone is adequate to preserve the assumptions of the pre-EPU criticality analysis. However, at EPU conditions spent fuel storage criticality analyses rely on crediting sufficient boron concentrations.

EPU TR Section 2.8.6.2, "Spent Fuel Storage," provides additional discussion related to the impact on the spent fuel storage criticality analysis as a result of EPU.

ITS Section 3.7.14, "Spent Fuel Pool Boron Concentration," will be revised to be applicable whenever fuel assemblies are stored in the spent fuel pool and ITS 4.3.1, "Criticality," will be revised to reflect the keff criteria of 10 CFR 50.68(b)(4). Refer to Attachment 4, "Improved Technical Specification Bases Changes (Markup)," for further basis information related to proposed changes to ITS 3.7.14..

U. S. Nuclear Regulatory Commission Attachment I 3F0611-02 Page 29 of 35 4.5 Revise RCS Pressure Acceptance Criterion for FWLB Accident CR-3 requests approval to of the RCS pressure acceptance criterion for the feedwater line break (FWLB) accident to be consistent with the criterion in SRP, Section 15.2.8, Revision 2.

The FWLB is considered a limiting fault event per the CR-3 FSAR, Section 14.2.2.9.2. The FSAR acceptance criteria for this limiting fault include an RCS pressure criterion of 110% of design pressure (2750 psig). For EPU conditions, CR-3 requests revising the FWLB accident acceptance criterion to reflect an RCS pressure limit of 120% of design pressure (3000 psig).

This is consistent with acceptance criteria specified in SRP, Section 15.2.8 for the FWLB event.

EPU TR Section 2.8.5.2.4, "Feedwater System Pipe Breaks Inside and Outside Containment,"

provides further discussion related to revising the FWLB accident RCS pressure acceptance criterion and the associated plant impact as a result of EPU.

4.6 Conclusion The CR-3 EPU has been evaluated for impact on the plant and the OL. With implementation of plant modifications described in the EPU TR, analyses demonstrate that the plant will maintain the capability for safe operation and the mitigation of postulated accident scenarios at EPU conditions. The proposed Technical Specification changes will assure that the plant and its SSC remain within acceptable limits at all times. Procedure changes and training will be implemented prior to plant startup under EPU conditions and will assure that plant personnel are capable of operating the plant and responding to abnormal or emergency conditions.

U. S. Nuclear Regulatory Commission Attachment I 3F0611-02 Page 30 of 35 5.0 NO SIGNIFICANT HAZARDS CONSIDERATION Florida Power Corporation (FPC) has evaluated the proposed License Amendment Request (LAR) against the criteria of 10 CFR 50.92(c) to determine if any significant hazards consideration is involved. FPC has concluded that this proposed LAR does not involve a significant hazards consideration. The following is a discussion of how each of the 10 CFR 50.92(c) criteria is satisfied.

(1) Does not involve a significant increase in the probabilityor consequences of an accident previously evaluated?

The impacts of the proposed Extended Power Uprate (EPU) on plant systems, structures, and components (SSCs) were reviewed with respect to SSC design capability, and it was determined that following completion of plant changes to support the EPU, no SSC would exceed its design conditions or limits. Evaluations supporting those conclusions were performed and demonstrate that the equipment reliability and structural integrity will not be adversely affected by EPU. Control system studies demonstrated that plant response to operational transients tinder EPU conditions does not significantly increase reactor trip frequency, so there will be no significant increase in the frequency of SSC challenges caused by a reactor trip. The EPU does not create new failure modes for existing SSCs and eliminates the need for a single failure exemption currently in the Crystal River Unit 3 (CR-3) licensing basis for boron precipitation mitigation. A new potential inter-system loss-of-coolant accident (LOCA) mechanism is created by the installation of the HLI flow path, but the probability of an inter-system LOCA occurring has not significantly increased. Additionally, new pressure isolation valves installed in series between reactor coolant system (RCS) high and low pressure piping will minimize the likelihood of an inter-system LOCA. ASME Boiler and Pressure Vessel Code requirements for procurement, installation, and testing of the new pressure isolation valves will be followed. Also, a new potential steam line break mechanism is created by the inadvertent opening of both Atmospheric Dump Valves (ADVs) simultaneously. A new Inadequate Core Cooling Monitoring System (ICCMS) and Fast Cooldown System (FCS) are being installed which will automatically open both ADVs to support a small break LOCA in the event of a single failure in the Emergency Core Cooling System (ECCS). Modifications to ADVs and procurement, installation, testing and operation of the ICCMS and FCS will ensure that the potential inadvertent opening of both ADVs is minimized. Also, any adverse consequences of inadvertent opening both ADVs are bounded by the consequences of the main steam line break accident.

The fission product barriers; fuel cladding, RCS pressure boundary, and the containment building, remain fully capable of performing their design functions. The spectrum of previously analyzed postulated accidents and transients was evaluated, and effects on the fuel, the RCS pressure boundary, and the containment were determined. Specific accident scenarios (small break LOCA, locked reactor coolant pump rotor, and rod

U. S. Nuclear Regulatory Commission Attachment 1 3F0611-02 Page 31 of 35 ejection accident) have been determined to potentially cause cladding rupture under EPU conditions in limited amounts, but the quantity of the failures and the consequences are bounded by the large break LOCA analysis. The fuel remains within the acceptance criteria of 10 CFR 50.46, the RCS pressure will not increase for normal operation as a result of EPU, and accident conditions remain within the ASME Boiler and Pressure Vessel Code limits as well as SSC design limits. Analysis has also confirmed that during the worst case accident (large break LOCA), the containment building remains within its design limit. These analyses were performed and demonstrate that existing RCS pressure boundary and containment limits are met and the effects on the fuel are such that dose consequences meet existing criteria at EPU conditions.

With the exception of the steam generator tube rupture (SGTR) accident, the EPU analyses have been performed using conservative methodologies, as specified in Regulatory Guide 1.183, "Alternative Radiological Source Term for Evaluating Design Basis Accidents at Nuclear Power Reactors." The SGTR analyses were performed using current licensing basis methodologies. Safety margins have been evaluated and margin has been retained to ensure that the analyses adequately bound the postulated limiting event scenarios. These analyses indicate increased doses for certain analyzed accidents.

Various factors contribute to these increases. Several actions have been taken to limit the increased consequences. Modifications to the Low Pressure Injection (LPI) and ADV systems are being made to ensure that the consequences of previously evaluated accidents are not significantly increased. Specifically, these modifications will enhance the plant response capabilities to a small break LOCA and improve the method for boron precipitation mitigation. The proposed amendment reduces the maximum allowed RCS specific activity. The limits on specific activity ensure that the doses remain within the regulatory limits during analyzed transients and accidents. The maximum allowed operating containment pressure is being reduced from 3.0 psig to 1.5 psig; thereby ensuring that maximum peak containment internal pressure does not exceed limits in the event of a design basis accident.

The revised accident analyses demonstrate that the plant site and the dose-mitigating Engineered Safety Features remain acceptable with respect to the radiological consequences of postulated DBAs since the calculated total effective dose equivalent (TEDE) at the exclusion area boundary (EAB), at the low population zone (LPZ) outer boundary, and in the control room meet the exposure guideline values specified in 10 CFR Part 50.67 "Alternative source term,". Therefore, the consequences of analyzed accidents are not significantly impacted by the proposed EPU.

Based on the above, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.

U. S. Nuclear Regulatory Commission Attachment I 3F0611-02 Page 32 of 35 (2) Does not create the possibility of a new or different kind of accidentfrom any accident previously evaluated?

Equipment that could be affected by EPU has been evaluated. No new operating mode, or accident scenario was identified. The LPI, HLI, and ADV systems will be modified and an ICCMS and FCS will be installed to better respond to accident and non-accident conditions. The full spectrum of accident considerations has been evaluated and no new or different kind of accident has been identified. The limiting accident remains the large break LOCA and analysis results are acceptable under EPU conditions. EPU uses developed technology and applies it within capabilities of existing or modified plant safety-related equipment in accordance with the regulatory criteria (including NRC approved codes, standards and methods). Modifications to existing SSCs and installation of new SSCs are designed in accordance with regulatory criteria to minimize equipment failures. Potential equipment failures of new or modified SSCs have been evaluated and postulated failures are equivalent or bounded by existing equipment failures or effects of these equipment failures are bounded by previously evaluated accidents. No new accidents or event precursors have been identified.

The Technical Specification (TS) revisions required to implement EPU continue to assure that the plant is operated within the limits established for safe operation of the plant.

Additionally, the limits in the TS reflect the initial conditions for the safety analyses performed to demonstrate the plant can mitigate the effects of accidents and ensure public safety by maintaining offsite doses within the limits in 10 CFR 50.67. The revisions have been assessed and it was determined that the proposed change will not introduce a different accident than that previously evaluated.

Based on the above, the proposed changes do not create the possibility of a new or different kind of accident from any accident previously evaluated.

(3) Does not involve a significant reduction in a margin of safety?

Structural evaluations performed at EPU conditions demonstrated that calculated loads on affected SSCs after modification, if necessary, remain within their design allowable for all design basis event categories. ASME Code requirements continue to be met.

Fuel performance evaluations were performed using parameter values appropriate for a reload core operating at EPU conditions. Those evaluations demonstrate that fuel performance acceptance criteria continue to be met. Core reload evaluation processes ensure that the planned fuel load in the first reactor core to be operated at the increased power level, will meet applicable regulatory criteria.

LOCA and non-LOCA safety analyses were performed under EPU conditions. ECCS performance was shown to meet the criteria of 10 CFR 50.46. Small break LOCA, locked rotor, and rod ejection scenarios may, under EPU conditions, have some potential

U. S. Nuclear Regulatory Commission Attachment I 3F0611-02 Page 33 of 35 of resulting in a limited amount of fuel cladding failure, but the analyses conclude that the plant remains within the acceptance criteria of 10 CFR 50.46. Large break LOCA scenarios also satisfy the criteria of 10 CFR 50.46 under EPU conditions, and the large break LOCA remains the most limiting accident at EPU conditions. LOCA analyses indicate a small reduction in margin (< 5%) related to maximum local clad oxidation and hydrogen generation at EPU conditions and a slight improvement in peak clad temperature margin based on minor changes in LOCA design inputs and modifications that will enhance the plant response capabilities to LOCAs and improve the method for boron precipitation mitigation. The non-LOCA events identified in the CR-3 Final Safety Analysis Report were shown to meet existing acceptance criteria.

The containment building response to mass and energy releases was evaluated under EPU conditions. The evaluations indicated that temperature and pressure limits were met.

No plant changes associated with the EPU reduce the degree of component or system redundancy. The small break LOCA response will require two High Pressure Injection (HPI) pumps injecting. In the event of inadequate HPI and loss sub-cooling margin (SCM), secondary depressurization will be achieved via a new ICCMS and FCS, which includes automatic actuation of the ADVs, thereby assuring that the reactor core receives the necessary ECCS flow to minimize core damage and satisfy the requirements of 10 CFR 50.46. The features required to automatically open ADVs during a small break LOCA are incorporated into proposed TS 3.3.19, "Inadequate Core Cooling Monitoring System (ICCMS) Instrumentation," and TS 3.3.20, "Inadequate Core Cooling Monitoring System (ICCMS)," and TS 3.7.20, "Fast Cooldown System (FCS)." The ICCMS and FCS are configured and supported such that a single failure will not prevent completion of the ECCS safety function.

To support this enhancement, operators will be provided indication of subcooling margin and HPI System flow adequacy to ensure actuation of the FCS. A new safety related display system will be available to determine when insufficient subcooling margin is available and HPI System flow is inadequate. Additional modifications will, upon indication of loss of subcooling margin, automatically trip the RCPs and raise steam generator secondary side level to the inadequate subcooling margin level. These automatic actions replace the current actions performed by the operator, thus reducing the reliance on manual operator action for event mitigation.

Operator training programs will be revised in accordance with the industry standard systematic approach to training process and appropriate training will be provided on all plant modifications, administrative/technical requirement changes, Technical Specification revisions, and procedure revisions. The CR-3 simulator will be updated and tested in sufficient time to provide effective reinforcement of procedure and plant physical changes as well as build proficiency with required manual operator actions.

U. S. Nuclear Regulatory Commission Attachment 1 3F061 1-02 Page 34 of 35 Based on the above, the proposed change does not involve a significant reduction in a margin of safety.

Based on the above, CR-3 concludes that the proposed LAR presents a no significant hazards consideration under the standards set forth in 10 CFR 50.92(c), and, accordingly, a finding of"no significant hazards consideration" is justified.

6.0 ENVIRONMENTAL IMPACT EVALUATION The environmental considerations evaluation is contained in Attachment 9, "Supplemental Environmental Report Extended Power Uprate." It concludes that the EPU will not result in a significant change in non-radiological impacts on land use, water use, waste discharges, terrestrial and aquatic biota, transmission facilities, or social and economic factors, and will have no non-radiological impacts other than those evaluated in the Supplemental Environmental Report. The Supplemental Environmental Report further concludes that the EPU will not introduce any new radiological release pathways, will not result in a significant increase in occupational or public radiation exposures, and will not result in significant additional fuel cycle environmental impacts.

Therefore, the proposed amendment does not involve a significant change in the types or significant increase in the amounts of any effluent that may be released offsite nor does it involve a significant increase in individual or cumulative occupational radiation exposure.

7.0 APPLICABLE REGULATORY REQUIREMENTS/CRITERIA The proposed changes have been evaluated to determine whether applicable regulations and requirements continue to be met.

CR-3 has determined that the proposed changes do not require any exemptions or relief from regulatory requirements and do not adversely affect conformance with any regulatory requirements differently than described in the CR-3 Final Safety Analysis Report. The exemption to 10 CFR 50 Appendix K, Item I.D.1, requirements for single failure considerations is being deleted due to a modification to the plant that will adequately provide the boron precipitation mitigation function and is designed to remain functional even with a single failure condition.

U. S. Nuclear Regulatory Commission Attachment I 3F0611-02 Page 35 of 35 This LAR will not reduce the effectiveness of the safety related systems, structures, or components and will not require the plant to operate outside of analyzed limits. Therefore, based on the considerations discussed above:

1) There is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner;

2) Such activities will be conducted in compliance with the Commission's regulations; and

3) Issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.

PROGRESS ENERGY FLORIDA, INC.

CRYSTAL RIVER UNIT 3 DOCKET NUMBER 50-302/LICENSE NUMBER DPR-72 LICENSE AMENDMENT REQUEST #309, REVISION 0 ATTACHMENT 2 OPERATING LICENSE AND IMPROVED TECHNICAL SPECIFICATION CHANGES (MARKUP)

of the Act and to the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:

2.C.(1) Maximum Power Level Florida Power Corporation is authorized to operate the facility at a steady state reactor core power level not in excess of 2609 Megawatts (4O0-perGent-ef-Gated-GeFe-pewer level).

\ 3014 2.C.(2) Technical Specifications The Technical Specifications contained in Appendices A and B, as revised through Amendment No. 23-7 , are hereby incorporated in the license. Florida Power Corporation shall operate the facility in accordance with the Technical Specifications.

The Surveillance Requirements contained in the Appendix A Technical Specifications and listed below are not required to be performed immediately upon implementation of Amendment 149. The Surveillance Requirements shall be successfully demonstrated prior to the time and condition specified below for each.

a) SR 3.3.8.2.b shall be successfully demonstrated prior to entering MODE 4 on the first plant start-up following Refuel Outage 9.

b) SR 3.3.11.2, Function 2, shall be successfully demonstrated no later than 31 days following the implementation date of the ITS.

c) SR 3.3.17.1, Functions 1, 2, 6, 10, 14, & 17 shall be successfully demonstrated no later than 31 days following the implementation date of the ITS.

d) SR 3.3.17.2, Function 10 shall be successfully demonstrated prior to entering MODE 3 on the first plant start-up following Refuel Outage 9.

e) SR 3.6.1.2 shall be successfully demonstrated prior to entering MODE 2 on the first plant start-up following Refuel Outage 9.

f) SR 3.7.12.2 shall be successfully demonstrated prior to entering MODE 2 on the first plant start-up following Refuel Outage 9.

g) SR 3.8.1.10 shall be successfully demonstrated prior to entering MODE 2 on the first plant start-up following Refuel Outage 9.

h) SR 3.8.3.3 shall be successfully demonstrated prior to entering MODE 4 on the first plant start-up following Refuel Outage 9.

Amendment No. 23-7

5-2.C.(6) Deleted per Amendment No. 21, 7-3-79 2.C.(7) Prior to startup following the first regularly scheduled refueling outage, Florida Power Corporation shall modify to the satisfaction of the Commission, the reactor coolant system flow indication to meet the single failure criterion with regard to pressure sensing lines to the flow differential pressure transmitters.

2.C.(8) Within three months of issuance of this license, Florida Power Corporation shall submit to the Commission a proposed surveillance program for monitoring the containment for the purpose of determining any future delamination of the dome.

2.C.(9) Fire Protection Florida Power Corporation shall implement and maintain in effect all provisions of the approved fire protection program as described in the Final Safety Analysis Report for the facility and as approved in the Safety Evaluation Reports, dated July 27, 1979, January 22, 1981, January 6, 1983, July 18, 1985, and March 16,1988, subject to the following provisions:

The licensee may make changes to the approved fire protection program without prior approval of the Commission only if those changes would not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire. (Amdt.

147, 1-22-93) 2.C.(10) The design of the reactor coolant pump supports need not include consideration of the effects of postulated ruptures of the primary reactor coolant loop piping and may be revised in accordance with Florida Power Corporation's amendment request of April 24, 1986. {Added perAmdt. #89, 5-23-86) 2.C.(11) A-system-of-thermocouples-added-to-the-decay-heat-(DH-)drop-and-Auxiliary

"-rssurizer-Spray-(APS)lines,-capable-of-deteting-flow-initiation;-shalIbe-per-able4or-Modes-4-through 1. hannel-checks-of-he4herme-euples-shal-be-perfofmed-o-aa monthly-basis-to-demonstrate-operability; If either-the DH e-APsystem thermecouples-become-ineperable,-operabitity-shall-*e-restored-within-30-days-or-the NRC-shall be-informed;-in a-Special-Report-within-the-following-fourteen -(-14) daysi-of theinoperability-and-the-plans-to-restore-per-abilityý.-Amdt.r-1644-4-27--98 2.C.(12) Deleted per Amendment No. 237 Deleted per Amendment [ , MM/DD..YYY.

Amendment No. 2-3-7

IDelete Page TABLE OF CONTENTS 1.0 USE AND APPLICAT ION .................................... 1.1-1 1\1 Def in it ions ......................................... 1 .1-1

1. Logical Connectors .................................. 1.2-1.3 Complet ion T imes .................................... 1. -1 1 .4 Frequency ........................................... 1. -1 2.0 AFETY LIMITS (SLs)..................................... 2.0-1 2.1 SLs ............................................ .2.0-1 2.2 SL Violations ................................... ... 2.0-1 3.0 LIMI NG CONDITION FOR OPERATION (LCO) APPLICABIL Y ... 3.0-1 3.0 SURVEI LANCE REQUIREMENT (SR) APPLICABILITY ............ 3.0-4 3.1 REAC VITY CONTROL SYSTEMS .......................... 3.1-1 3.1.1 SH DOWN MARGIN (SDM) ............... ........... 3.1-1 3.1.2 Reac ivity Balance .............................. 3.1-2 3.1.3 Moder or Temperature Coefficient TC) ......... 3.1-4 3.1.4 CONTROL ROD Group Alignment Limi .............. 3.1-6 3.1.5 Safety R Insertion Limits ........... ....... 1-10 3.1.6 AXIAL POW SHAPING ROD (APSR Alignment Limits .3.1-12 3.1.7 Position In icator Channels .................... 3.1-14 3.1.8 PHYSICS TEST Exceptions-M E 1 ................ 3.1-17 3.1.9 PHYSICS TESTS xceptions- ODE 2 ................ 3.1-20 3.2 POWER DISTRIBUTION L MITS. ......................... 3.2-1 3.2.1 Regulating Rod Ins rti n Limits ................. 3.2-1 3.2.2 AXIAL POWER SHAPING D (APSR) Insertion Limits . 3.2-4 3.2.3 AXIAL POWER IMBALANE* Operating Limits .......... 3.2-5 3.2.4 QUADRANT POWER TI (Q T) ....................... 3.2-7 3.2.5 Power Peaking Fa tors .... ............. ........... 3.2-11 3.3 INSTRUMENTATION ........ * . . .... ......... 3.3-1 3.3.1 Reactor Prot ction System ( instrumentation . 3.3-1 IS) 3.3.2 Reactor Pr ection System (R ) Manual Reactor Trip .......................................... 3.3-6 3.3.3 Reactor rotection System (RPS) Reactor Trip Modu e (RTM) .................... .............. 3.3-8 3.3.4 CONTR L ROD Drive (CRD) Trip Devic ............ 3.3-10 3.3.5 Engy, eered Safeguards Actuation Syst m ESAS) Instrumentation ............. .........3.3-12 3.3.6 gineered Safeguards Actuation System (ESAS) Manual Initiation .............. ......... 3.3-16 3.3.7 Engineered Safeguards Actuation System (ESAS) Automatic Actuation Logic............ 3.3-18 3.3.8 Emergency Diesel Generator (EDG) Loss of Pow Start (LOPS) ............... ............. 3"3-20 3.3.9 Source Range Neutron Flux ...................... 3.3-22 3.3.10 Intermediate Range Neutron Flux .................. .3-24 (con inued)_

Crystal River Unit 3 Amendment No.82

[~Delete Page OF CONTENTS /TABLE 3.3 INSTRUMENTATION (continued)

.3.11 Emergency Feedwater Initiation and Control (EFIC) System Instrumentation ................ 3.3- 6 3.3.12 Emergency Feedwater Initiation and Control (EFIC) Manual Initiation ...................... 3 3-30 3.3.13 Emergency Feedwater Initiation and Control (EFIC) Automatic Actuation Logic ........... . 3.3-32 3.3.14 Emergency Feedwater Initiation and Control (EFIC)-Emergency Feedwater (EFW)-Vector Valve Logic ............................ ..... 3.3-34 3.3.15 Reactor Building (RB) Purge Isolation-Hi Radiation ............................ ....... 3.3-35 3.3.16 ntrol Room Isolation-High Radiation .......... 3.3-36 3.3.17 Po t Accident Monitoring (PAM) Instru entation 3.3-38 3.3.18 Remo e Shutdown System ............. ............ 3.3-42 3.4 REACTOR C LANT SYSTEM (RCS) ........ ............... 3.4-1 3.4.1 RCS Pre ure, Temperature, and F/ow Departure from N cleate Boiling (DNB) imits ........... 3.4-1 3.4.2 RCS Minimu Temperature for iticality ......... 3.4-3 3.4.3 RCS Pressure and Temperatur (P/T) Limits ....... 3.4-4 3.4.4 RCS Loops- .MO 3 ........ ...................... 3.4-6 3.4.5 RCS Loops-MODE4 .............................. 3.4-8 3.4.6 RCS Loops-MODE Loop Filled................. 3.4-10 3.4.7 RCS Loops--MODE 5, Loo s Not Filled ............. 3.4-13 3.4.8 Pressurizer ................................... 3.4-15 3.4.9 Pressurizer Safety Ives ...................... 3.4-17 3.4.10 Pressurizer Power per ted Relief Valve (PORV). 3.4-19 3.4.11 Low Temperature verpre ure Protection (LTOP) System......... .......................... 3.4-21 3.4.12 RCS Operation I LEAKAGE ... 3.4-22 3.4.13 RCS Pressur Isolation Valv \(PIV) Leakage:::::..:3.4-24 3.4.14 RCS Leakag Detection Instrum ntation ........... 3.4-27 3.4.15 RC pec~ ic Activity ......... .................3.4-30 3.4.16 Steam G nerator (OTSG) Tube Inte rity ........... 3.4-34 3.5 EMERGENC CORE COOLING SYSTEMS (ECCS) .............. 3.5-1 3.5.1 Cor Flood Tanks (CFTs) .........................3.5-1 3.5.2 E S-Operating ...................... ..........3.5-4 3.5.3 CS -Shutdown.....................3.5-7 3.5.4 Borated Water Storage Tank (BWST) ....... ........ 3.5-9 3.6 ONTAINMENT SYSTEMS ................................3.6-1 3.6.1 Containment .................................... 3.6-1 3.6.2 Containment Air Locks ........................ ..3.6-3 3.6.3 Containment Isolation Valves ................... 3.6-8 3.6.4 Containment Pressure ............................. 6-15 3.6. Containment Air Temperature .................... 3 6-16 (co tinued),

Crystal River Unit 3 ii Amendment Noý. 2\23j

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TABLE OF CONTENTS 3.6 CONTAINMENT SYSTEMS (continued) 6.6 Reactor Building Spray and Containment Cooling Systems ............................... 3.6 7 3.6. Containment Emergency Sump pH Control System (CPCS) ................................ .6-21 3.7 PLANT SYSTEMS ..................................... . 3.7-1 3.7.1 Main Steam Safety Valves (MSSVs) ................ 3.7-1 3.7.2 Main Steam Isolation Valves (MSIVs) ........ .... 3.7-4 3.7.3 Main Feedwater Isolation Valves (MFIVs)......... 3.7-6 3.7.4 Turbine Bypass Valves (TBVs) ............ ....... 3.7-8 3.7.5 mergency Feedwater (EFW) System ................ 3.7-9 3.7.6 E ergency Feedwater (EFW) Tank ...... .......... 3.7-13 3.7.7 Nu lear Services Closed Cycle Coolin Wa er (SW) System ............... ............. 3.7-15 3.7.8 Decay eat Closed Cycle Cooling W er (DC) ystem ................................. 3.7-17 3.7.9 Nuclear ervices Seawater Syst ................ 3.7-19 3.7.10 Decay Hea Seawater System ..................... 3.7-21 3.7.11 Ultimate He t Sink (UHS) ... .................... 3.7-23 3.7.12 Control Room mergency Ven lation System (CRE )........

) ... ................... 3.7-24 3.7.13 Fuel Storage Po Water evel ................... 3.7-27 3.7.14 Spent Fuel Pool ron oncentration ............. 3.7-28 3.7.15 Spent Fuel Assembl orage.................... 3.7-30 3.7.16 Secondary Specific tivity.................... 3.7-34 3.7.17 Steam Generator L el ............... ........ 3.7-35 3.7.18 Control Complex oolin System ..................3.7-37 3.7.19 Diesel Driven W (DD-E ) Pump Fuel Oil, Lube Oil and St ting Air .........................3.7-39 3.8 ELECTRCL PO SYSTEMS.......................... 3.8-1 3.8.1 AC Source .-Operating ......... ................. 3.8-1 3.8.2 AC Sour s-Shutdowne........o.. ................ 3.8-11 3.8.3 Diesel uel Oil, Lube Oil , and St rting Air ..... 3.8-14 3.8.4 DC So rces -Operati ng ............. ............. 3.8-17 3.8.5 DC urces -Shutdown ............................3.8-21 3.8.6 B tery Cell Parameters ........................ 3.8-23 3.8.7 verters-Operating ............................3.8-27 3.8.8 nverters -Shutdown ................... 3.8-29 3.8.9 Distribution Systems -Operating .......... ....... 3.8-31 3.8.10 Distribution Systems -Shutdown .................. 3.8-33 3.9 REFUELING OPERATIONS ...............................3.9-1 3.9.1 Boron Concentration ............................ 3.9-1 3.9.2 Nuclear Instrumentation .......................... 9-2 3.9. Containment Penetrations ........................3.9-4 (coitinued) rystal River Unit 3 iii Amendment No. 182

AIDelete Page TABLE OF CONTENTS CicREFUELING OPERATIONS (continued) 3.9.4 Decay Heat Removal (DHR) and Coolant Circulation-High Water Level ................. 3 -6 3.9.5 Decay Heat Removal (DHR) and Cool ant Ci rculation- Low Water Level ................. 39-8 3.9.6 Refueling Canal Water Level .................... 3.9-11 4.0 DES N FEATURES ......................................... 4.0-1 5.0 ADMINI RATIVE CONTROLS ................................ 5.0-1 Crystal River Unit 3 iv Amendment No. 1

A* Delete Page ABL OF CONTENTS B 2.0x SAFETY LIMITS (SLs) .................................. B 2.0-1 B 2.1 1 Reactor Core SLs ........... . . . . . . . . . B 2.0-1 B 2.1. Reactor Coolant System (RCS) Pressure SL ...... B 2.0-B 3.0 L MITING CONDITION FOR OPERATION (LCO) APPLICABILITY . B 3 -1 B 3.0 SU VEILLANCE REQUIREMENT (SR) APPLICABILITY .......... B .0-16 B 3.1 R CTIVITY CONTROL SYSTEMS ........................ 3.1-1 B 3.1.1 HUTDOWN MARGIN (SDM) ......................... B 3.1-1 B 3.1.2 activity Balance ............................. B 3.1-6 B 3.1.3 Mo erator Temperature Coefficient (MTC) .. /.....B 3.1-12 B 3.1.4 CON OL ROD Group Alignment Limits ...... ...... B 3.1-17 B 3.1.5 Safet Rod Insertion Limit ............ ........ B 3.1-27 B 3.1.6 AXIAL WER SHAPING ROD (APSR) Alignm t LimitsB 3.1-31 B 3.1.7 Position Indicator Channels .................... B 3.1-35 B 3.1.8 PHYSICS T TS Exceptions Systems-MM E 1 ....... B 3.1-41 B 3.1.9 PHYSICS TE S Exceptions-MODE 2 .............. B 3.1-48 B 3.2 POWER DISTRIBUTIO LIMITS .......................... B 3.2-1 B 3.2.1 Regulating Rod nsertion Limi s ................ B 3.2-1 B 3.2.2 AXIAL POWER SHAP G ROD (AP ) Insertion LimitsB 3.2-11 B 3.2.3 AXIAL POWER IMBALA CE Oper ting Limits ........ B 3.2-17 B 3.2.4 QUADRANT POWER TILT (QPT)..................... B 3.2-26 B 3.2.5 Power Peaking Factors ......................... B 3.2-38 B 3.3 INSTRUMENTATION ................................... B 3.3-1 B 3.3.1 Reactor Protection ystem (RPS)

Instrumentation .......... .................. B 3.3-1 B 3.3.2 Reactor Protecti n System (R S) Manual Reactor Trip ....... //.............. *x................ B 3.3-31 B 3.3.3 Reactor Prote tion System (RPS) Reactor Trip Module (R M) ................. ............. B 3.3-34 B 3.3.4 CONTROL RO Drive (CRD) Trip Devices .......... B 3.3-38 B 3.3.5 Engineere Safeguards Actuation Sys m (ESA Instrumentation ......... B 3.3-44 B 3.3.6 Engine red Safeguards Actuation System

( AS) Manual Initiation ................... B 3.3-57 B 3.3.7 Engineered Safeguards Actuation System (ESAS) Automatic Actuation Logic ....... ... B 3.3-61 B 3.3.8 ergency Diesel Generator (EDG) Loss of Pow r Start (LOPS) .............................. .. B 3.3-65 B 3.3.9 Source Range Neutron Flux ..................... .. 3.3-73 B 3.3.10 Intermediate Range Neutron Flux ............... B 3.3-78 B 3.3.11 Emergency Feedwater Initiation and Control (EFIC) Instrumentation ..................... B 3. -82 (contin 8d) rystal River Unit 3 v Amendment No. 182X\

A IDelete Page

TABLE OF CONTENTS /

Bl3 NSTRUMENTATION (continued)

B 3. .12 Emergency Feedwater Initiation and Control (EFIC) Manual Initiation ................... B .3-100 B 3.3. Emergency Feedwater Initiation and Control (EFIC) Automatic Actuation Logic ......... .. /B 3.3-105 B 3.3.14 Emergency Feedwater Initiation and Control /

(EFIC)-Emergency Feedwater (EFW) -Vector Valve Logic ........................... .... B 3.3-110 B 3.3.15 Reactor Building (RB) Purge Isolation-Hi h Radiation ........................... ..... B 3.3-114 B 3.3.16 ntrol Room Isolation-High Radiation ........ B 3.3-119 B 3.3.17 Po Accident Monitoring (PAM) Instr mentation B 3.3-124 B 3.3.18 Remo e Shutdown System ............ . .......... B 3.3-145 B 3.4 REACTOR CO ANT SYSTEM (RCS) ....... ............... B 3.4-1 B 3.4.1 RCS Pres re, Temperature, and low Departure from Nu leate Boiling (DNB Limits .......... B 3.4-1 B 3.4.2 RCS Minimum Temperature for riticality ........ B 3.4-6 B 3.4.3 RCS Pressure nd Temperatu e (P/T) Limits ...... B 3.4-9 B 3.4.4 RCS Loops- OMO 3 ...... .. ..................... B 3.4-17 B 3.4.5 RCS Loops-MODE . ............................. B 3.4-22 B 3.4.6 RCS Loops-MODE 5, Loo s Filled ................ B 3.4-27 B 3.4.7 RCS Loops-MODE 5, ps Not Filled ............ B 3.4-33 B 3.4.8 Pressurizer.................................. B 3.4-37 B 3.4.9 Pressurizer Safet Va yes ...................... B 3.4-43 B 3er ed Relief Valve (PORV). B 3.4-47 B 3.4.11 Low Temperar verpres ure Protection (LTOP) Systm.................... B 3.4-52 B 3.4.12 RCS Operatiq al LEAKAGE.... ................... B 3.4-53 B 3.4.13 RCS Pressuye Isolation Valve PIV) Leakage ..... B 3.4-58 B 3.4.14 RCS Leak e Detection Instrume tation .......... B 3.4-65 B 3.4.15 RCS Spe fic Activity .......... ............... B 3.4-71 B 3.4.16 Steam/enerator (OTSG) Tube Integ\ity .......... B 3.4-75 B 3.5 EMERGE Y CORE COOLING SYSTEMS (ECCS)............. B 3.5-1 B 3.5.1 C9 e Flood Tanks (CFTs) .. ............ ......... B 3.5-1 B 3.5.2 CS-Operating ................................ B 3.5-9 B 3.5.3 ECCS-Shutdown .......................... ..... B 3.5-20 B 3.5.4 Borated Water Storage Tank (BWST) ........ ..... B 3.5-24 B 3.6 CONTAINMENT SYSTEMS...............................B 3.6-1 B 3.6.1 Containment...................................B 3.6-1 B 3.6.2 Containment Air Locks..........................B 3.6-6 B 3.6. Containment Isolation Valves .................... 3.6-15 B 3. .4 Containment Pressure ...........................B .6-29 B 3 6.5 Containment Air Temperature ....................B 3.'6-32 B .6.6 Reactor Building Spray and Containment Cooling Systems ............................. B 3.6- 5 (conti edl Crystal River Unit 3 vi Amendment No.

A Delete Page TABLE OF CONTENTS 3.6 CONTAINMENT SYSTEMS (continued)

B .6.7 Containment Emergency Sump pH Control (CPCS) ... B 3.6-4 B 3.7 PLANT SYSTEMS...................................B 3.7 1 B 3.7. Main Steam Safety Valves (MSSVs)............... B 3 -1 B 3.7.2 Main Steam Isolation Valves (MSIVs) ............ B .7-7 B 3.7.3 Main Feedwater Isolation Valves (MFIVs) ........ .3.7-13 B 3.7.4 Turbine Bypass Valves (TBVs) .................. B 3.7-19 B 3.7.5 Emergency Feedwater (EFW) System ............... B 3.7-23 B 3.7.6 Emergency Feedwater Tank (EFT-2) ........... ...B 3.7-32 B 3.7.7 uclear Services Closed Cycle Cooling Water System (SW) ................... ...... B 3.7-36 B 3.7.8. De y Heat Closed Cycle Cooling Water S tem ... B 3.7-41 B 3.7.9 Nucl r Services Seawater System .............. B 3.7-46 B 3.7.10 Decay eat Seawater System ......... ........... B 3.7-51 B 3.7.11 Ultimat Heat Sink (UHS) ...................... B 3.7-56 B 3.7.12 Control om Emergency Ventilatio System CREVS) .............................. B 3.7-60 B 3.7-13 Fuel Storag Pool Water Level ................. B 3.7-66 B 3.7.14 Spent Fuel Po 1 Boron Concentr tion ............ B 3.7-69 3.7-15 Spent Fuel Ass bly Storage................... B 3.7-72 3.7.16 Secondary Speci fc Activit ................... B 3.7-77 B 3.7.17 Steam Generator L el ........................ B 3.7-81 3.7.18 Control Complex Co ing ystem ................ B 3.7-85 B 3.7.19 Diesel Driven EFW (D- W) Pump Fuel Oil, Lube Oil and Starting A ........................ 3.7-89 B 3.8 ELECTRICAL POWER SYSTE ... ........................ B 3.8-1 B 3.8.1 AC Sources-Operating ..... ..................... B 3.8-1 B 3.8.2 AC Sources-Shut wn ............................B 3.8-24 B 3.8.3 Diesel Fuel Oi , Lube Oil, a Starting Air .... B 3.8-30 B 3.8.4 DC Sources-O rating ...........................B 3.8.39 B 3.8.5 DC Sources- utdown ............ ...............B 3.8-49 B 3.8.6 Battery C 1 Parameters ........................B 3.8-52 B3.8.7 Inverter -Operating ............... ............B 3.8-59 B 3.8.8 Inverte s-Shutdown ..... ........... ........... B 3.8-64 B3.8.9 Distr~ ution Systems-Operating ....... ......... B 3.8-67 B 3.8.10 Dist ibution Systems-Shutdown ......... ........ B 3.8-77 B 3.9 REFUE NC OPERATIONS ...............................B 3.9-1 B 3.9.1 oron Concentration ....................... ....B 3.9-1 B 3.9.2 Nuclear Instrumentation ........................B 3.9-5 B 3.9.3 Containment Penetrations ..................... .B 3.9-9 B 3.9.4 Decay Heat Removal (DHR) and Coolant Circulation-High Water Level .................. 3.9-14 B 3.9.5 Decay Heat Removal (DHR) and Coolant Circulation-Low Water Level ................. B 39-1-8 B 3.9 Refueling Canal Water Level ....................B 3. -23 Crystal River Unit 3 vii Amendment No. 1

DeFinitions 1.1 when inhaled as the combined

1. 1 Definitions (continued) atvies of iodine isotopes CONTROL RODS CONTROL RODS shall be all Full length safety and regulating rods that are used to shut down the reactor and control power level during maneuvering operations.

CORE ALTERATION CORE ALTERATION shall be the movement of any Fuel, sources, or other reactivity control components, within the reactor vessel with the vessel head removed and Fuel in the vessel. Suspension of CORE ALTERATIONS shall not preclude completion of movement of a component to a safe position.

CORE OPERATING LIMITS The COLR is the unit specific document that REPORT (COLR) provides cycle specific parameter limits For the current reload cycle. These cycle specific limits shall be determined For each reload cycle in accordance with Specification 5.6.2.18. Plant operation within these limits is addressed in p individual SpeciFications.

DOSE EQUIVALENT 1-131 DOSE EQUIVALENT 1-131,shall be that concentration of 1-131 (microcuries/-gram) that alone would produce the same thyr-o dose e-te-quat-ind

-bsoep-bc--m-i-x~-e-e-f I-131, 1-132, 1-133, 1-134, and 1-135 actually present. e-t**l r-e4d--d-ese lnsertDE131-1 eenve#=s-i--Faetess-ee ea-/-eit4-a/-t-Jior--ýsa44 be hs i-ie in l-enat-ienaq--C-emmq*t-tee---en 67fweý*

I e3 W ,z?-,--~emet--Eo-P6,r 4--page-im92-2-12ý--Tabe-Iled- "Gemm4-t-t-ed-Dese

,Ebuva-b-ea-t-i-n--T-ar-get--Or"gans--ot=-,';-Tsstes--per--k'i7-t-ak-e o-F-Unt--- t-i.v*.-"-p-AVERAGE E shall be the average (weighted in proportion DISINTEGRATION ENERGY to the concentration of each radionuclide in the reactor coolant at the time of sampling) of the sum of the average beta and gamma energies per disintegration (in MeV) For isotopes, other than iodines, with half lives > 15 minutes, making up at least 95% of the total non-iodine activity in the coolant.

EFFECTIVE FULL POWER EFPD shall be the ratio of the number of hours DAY (EFPD) of production of a given THERMAL POWER to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , multiplied by the ratio of the given THERMAL POWER to the RTP. One EFPD is equivalent to the thermal energy produced by operating the (continued)

Crystal River Unit 3 1. 1-3 Amendment No. 449

Insert DEI 131-1 The determination of DOSE EQUIVALENT 1-131 shall be performed using Committed Effective Dose Equivalent (CEDE) dose conversion factors from Table 2.1 of EPA Federal Guidance Report No. 11, 1988, "Limiting Values of Radionuclide Intake and Air Concentration and Dose Conversion Factors for Inhalation, Submersion, and Ingestion."

Definitions 1.1

1. 1 Definitions EFFECTIVE FULL POWER reactor core at RTP for one full day. (One EFPD is DAY (EFPD) -2609 MWt times 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or 62646 MWhr.)

(cont i nued) 3 EMERGENCY FEEDWATER The EFIC RESPONSE TIME shall be that time INITIATION AND CONTROL interval from when the monitored parameter (EFIC) RESPONSE TIME exceeds its EFIC actuation setpoint at the channel sensor until the emergency Feedwater equipment is capable of performing its safety Function (i.e.,

valves travel to their required positions, pump discharge pressures reach their required values, etc.) Times shall include diesel generator starting and sequence loading delays, where applicable. The response time may be measured by means of any series of sequential, overlapping, or total steps so that the entire response time is measured.

ENGINEERED SAFETY The ESF RESPONSE TIME shall be that time interval FEA TURE (ESF) RESPONSE from when the monitored parameter exceeds its ESF TIME actuation setpoint at the channel sensor until the ESF equipment is capable of performing its safety Function (i.e., the valves travel to their required positions, pump discharge pressures reach their required values, etc.). Times shall include diesel generator starting and sequence loading delays, where applicable. The response time may be measured by means of any series of sequential, overlapping, or total steps so that the entire response time is measured.

LEAKAGE LEAKAGE shall be:

a. Identified LEAKAGE

1. LEAKAGE, such as that from pump seals or valve packing, that is captured and conducted to collection systems or a sump or collecting tank; or

2. LEAKAGE into the containment atmosphere from sources that are both specifically located and quantified and known not to interfere with the operation of leakage detection systems and not to be pressure boundary LEAKAGE; or (continued)

Crystal River Unit 3 1.1-4 Amendment No. 2-28

Definitions 1.1

1. 1 Definitions PHYSICS TESTS These tests are:

(continued)

a. Described in Chapter 13, "Initial Tests and Operation" of the FSAR;

b. Authorized under the provisions of 10 CFR 50.59; or

c. Otherwise approved by the Nuclear Regulatory Commission.

PRESSURE AND The PTLR is the unit specific document that TEMPERA TURE L I M I TS provides the reactor vessel pressure and REPORT (PTLR) temperature limits, including heatup and cooldown rates, For the current reactor vessel fluence period. These pressure and temperature limits shall be determined for each fluence period in accordance with Specification 5.6.2.19. Plant operation within these operating limits is addressed in LCO 3.4.3, "RCS Pressure and Temperature Limits."

QUADRANT POWER TILT QPT shall be defined by the following equation and (QPT) is expressed as a percentage.

Q Power In Any Core Quadrant

=Average Power of all Quadrants RATED THERMAL POWER RTP shall be a total reactor core heat transfer (RTP) rate to the reactor coolant of 26091 REACTOR PROTECTION The RPS RESPONSE TIME shall be that time interval SYSTEM (RPS) RESPONSE from when the monitored parameter exceeds its RPS TIME trip setpoint at the channel sensor until electrical power is interrupted at the control rod drive trip breakers. The response time may be measured by means of any series of sequential, overlapping, or total steps so that the entire response time is measured.

SHUTDOWN MARGIN (SDM) SDM shall be the instantaneous amount of reactivity by which the reactor is subcritical or (continued)

Amendment No. 228 1.1-6 Unit 3 River Unit Crystal River 3 1.1-6 Amendment No. 2-28

2300 - ION Af ACCEPI ABLE 2 - PERA ION 2200 - /

12000 LDSWT UMIT 1900 iPTABLE OPER MION 1800 -UNACC 1700 .

580 590 00 610 20 630 640 Reactor Outlet Temperature, Figure 2.1.1-1 (page 1 of 1)

/eactor Coolant System DNB Safety Limi Unit 3 2.0-3

jInsert Figure 2.1.1-11 SLs 2.0 2400 2300 2200 2100 0) 9)

2000 0~

C-)

1900 1800 1700 580 590 600 610 620 630 640 Reactor Outlet Temperature, OF Figure 2.1.1-1 (page 1 of 1)

Reactor Coolant System Departure From Nucleate Boiling Safety Limits Crystal River Unit 3 2.0-3 Amendment No.

SDM 3.1.1

3. 1 REACTIVITY CONTROL SYSTEMS 3.1.1 SHUTDOWN MARGIN (SDM)

A within LCO 3.1.1 The SDM sha II be gier specified in the COLR. r:l-,* lFtl-11lF---I-i-IT/V* Fl.'#./--t--Fjl*

1, 1.0% Ak/lk.

APPLICABILITY: MODES 3, 4, and 5.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. SDM not within limit. A. 1 Initiate boration to 15 minutes restore SDM to within limit.

0 SURVEILLANCE REQUIREMENTS _ _ _

SURVEILLANCE FREQUENCY SR 3. 1. 1. 1 Ver i fy SDM is g1-eatei*-eh,-&r--equa4----eht / 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months limit specified in the COLR.

Crystal River Unit 3 3.1-1 Amendment No. 449

MTC 3.1.3

3. 1 REACTI VI TY CONTROL SYSTEMS 3.1.3 Moderator Temperature Coefficient (MTC)

LCO 3.1.3 The MTC shall be maintained within the limits specified in the COLR. The maximum positive I imit sha I be

0.0 A-k/ktoF at > 95% RTP and 5 9-9 E-4 A-k/kP°F at < 95% RTP.

APPL I CAB I L I TY:

MODES 1 and 2. *Deletespace.

M I

-Delete space.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. MTC not within limits. A. I Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.1.3.1 Verify MTC is within the upper limit Prior to specified in the COLR. entering MODE 1 after each fuel loading (continued)

Crystal River Unit 3 3.1-4 Amendment No. 449

CONTROL ROD Group Alignment Limits 3.1.4

3. 1 REACTIVITY CONTROL SYSTEMS 3.1.4 CONTROL ROD Group Alignment Limits LCO 3.1.4 Each CONTROL ROD shall be OPERABLE and aligned to within 6.5%of its group average height.

APPLICABILITY: MODES 1 and 2.

ACTIONS CONDITION REQUIRED ACTION I COMPLETION TIME A. One trippable CONTROL A. 1 Align all CONTROL 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months ROD inoperable, or not RODS in the group to aligned to within 6.5% within 6.5%of the of its group average group average height, height, or both. while maintaining the rod insertion, group sequence, and group overlap limits in accordance with LCO 3.2.1, "Regulating Rod Insertion Limits."

OR A.2. 1. 1 Verify SDM is 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months

_ 4-4% Mk-/I&

AND Once per within limits specified 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months in the COLR.

thereafter OR A.2.1.2 Initiate boration to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months restore SDM to within Iimit.

AND (continued)

Crystal River Unit 3 3. 1-6 Amendment No. -149

CONTROL ROD Group Alignment Limits 3.1.4 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.2.2 Reduce THERMAL POWER 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months to

60% of the ALLOWABLE THERMAL POWER.

AND A.2.3 Reduce the nuclear 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months overpower trip setpoint to *_ 70% of the ALLOWABLE THERMAL POWER.

AND A.2.4 Verify the potential 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months ejected rod worth is within the assumptions of the rod ejection ana lysi s.

AND A. 2.5 Perform SR 3.2.5. 1. 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months B. Required Action and B. 1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time for Condition A not met.

C. More than one C. 1. 1 Verify SDM is 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months trippable CONTROL ROD _ 4-% A-I/-.

inoperable, or not aligned within 6.5%of OR its group average within limits specified height, or both.

in thetCOLRd (continued)

Crystal River Unit 3 3.1-7 Amendment No. 449

CONTROL ROD Group Alignment Limits 3.1.4 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. (continued) C. 1.2 Initiate boration to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months restore SDM to within limit.

AND C.2 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months D. One or more CONTROL D. 1. 1 VeriFy SDM is 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months RODS untrippable. Ž!4%6 Ak/k--.

OR D. 1.2 Initiate boration to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months restore SDM to within limit.

AND D.2 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Crystal River Unit 3 3. 1-8 Amendment No. 49

Safety Rod Insertion Limits 3.1.5 3.1 REACTIVITY CONTROL SYSTEMS 3.1.5 Safety Rod Insertion Limits LCO 3.1.5 Each safety rod shall be fully withdrawn.

APPLICABILITY: MODES 1 and 2.

NOTE-This LCO is not applicable while performing SR 3.1.4.2.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One safety rod not A. 1 Withdraw the rod 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months fully withdrawn. fully.

OR A.2.1.1 Verify SDM is 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months within limits specified OR in the COLR.

A.2.1.2 Initiate boration to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months restore SDM to within limit.

AND A.2.2 Declare the rod 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months inoperable.

(continued)

Crystal River Unit 3 3. 1-10 Amendment No. 49

Safety Rod Insertion Limits 3.1.5 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B More than one safety B. 1. 1 Verify SDM is 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months rod not fully withdrawn.- 4- -k4k-/.

_

withdawn.withinORt limits specified OR in t~he COLR.

B. 1.2 Initiate boration to I hour restore SDM to within limit.

AND B.2 Be in MODE 3 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.1.5. 1 Verify each safety rod is fully withdrawn. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Crystal River Unit 3 3.1-11 Amendment No. 449

PHYSICS TESTS Exceptions - MODE 1 3.1.8 3.1 REACTIVITY CONTROL SYSTEMS 3.1.8 PHYSICS TESTS Exception - MODE 1 LCO 3.1.8 During the performance of PHYSICS TESTS, the requirements of LCO 3.1.4, "CONTROL ROD Alignment Limits";

LCO 3.1.5, "Safety Rod Insertion Limits";

LCO 3.1.6, "AXIAL POWER SHAPING ROD (APSR) Alignment Limits";

LCO 3.2. 1, "Regulating Rod Insertion Limits," for the restricted operation region only; LCO 3.2.3, "AXIAL POWER IMBALANCE Operating Limits"; and LCO 3.2.4, "QUADRANT POWER TILT (QPT) "

may be suspended, provided:

a. THERMAL POWER is maintained

85% RTP;

b. Reactor trip setpoints on the nuclear overpower channels are set < 10% RTP higher than the THERMAL POWER at which the test is performed, with a maximum setting of 90%

RTP;

c. F0 (Z) and FH are maintained with the limits specified in the COLR; and

d. SDM i s/Ž 4q- .*0/o..

APPLICABILITY: MODE 1 during PHYSICS TESTS.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. SDM not within limit. A.1 Initiate boration to 15 minutes restore SDM to within limit.

AND A.2 Suspend PHYSICS TESTS 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months exceptions.

(continued)

Crystal River Unit 3 3.1-17 Amendment No. 44-9

PHYSICS TESTS Exceptions - MODE 1 3.1.8 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.1.8.4 Ver-i fy SDM is Ž_ 7_-a06o Akl-k-- 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months wit~hin lim~it~sspe~ciffied inýthe CýOLR.

Crystal River Unit 3 3.71-19 Amendment No. 449

PHYSICS TESTS Exceptions - MODE 2 3.1.9

3. 1 REACTIVITY CONTROL SYSTEMS 3.1.9 PHYSICS TESTS Exceptions - MODE 2 LCO 3.1.9 During performance of PHYSICS TESTS, the requirements of LCO 3.1.3, "Moderator Temperature Coefficient (MTC)";

LCO 3.1.4, "CONTROL ROD Group Alignment Limits";

LCO 3.1.5, "Safety Rod Insertion Limits";

LCO 3.1.6, "AXIAL POWER SHAPING ROD (APSR) Alignment Limits";

LCO 3.2. 1, "Regulating Rod Insertion Limits, " for the restricted operation region only; and LCO 3.4.2, "RCS Minimum Temperature for Criticality" may be suspended, provided:

a. THERMAL POWER is

5% RTP;

b. Reactor trip setpoints on the nuclear overpower channels are set to < 25% RTP; and

c. SDM is -1 %

4_ lE/km APPL ICABI L I TY: MODE 2 during PHYSICS TESTS.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. THERMAL POWER not A.1 Open control rod Immediately within limit, drive trip breakers.

(continued)

Crystal River Unit 3 3.17-20 Amendment No. 449

PHYSICS TESTS Exceptions - MODE 2 3.1.9 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. SDM not within limit. B. 1 Initiate boration to 15 minutes restore SDM to within limit.

AND B.2 Suspend PHYSICS TESTS 7 hour8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months except ions C. Nuclear overpower trip C. 1 Suspend PHYSICS TESTS 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months setpoint not within exceptions.

limit.

SURVEILLANCE REQUIREMENTS SURVE ILLANCE FREQUENCY SR 3. 1.9. 1 Verify THERMAL POWER is *_ 5% RTP. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months SR 3. 1.9.2 Verify nuclear overpower trip setpoint is 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months

< 25% RTP.

SR 3.1.9.3 Verify SDM isk_ -O% A1k/1-- 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months tspecified in the COLR.

Crystal River Unit 3 3. 1-21 Amendment No. 4-9

Regulating Rod Insertion Limits 3.2.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. Regulating rod groups C.1 Initiate boration to 15 minutes inserted in restore SDM to unacceptable i -104 A1-i operational region. within limits.

AND C.2.1 Restore regulating 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months rod groups to within restricted operating region.

OR C.2.2 Reduce THERMAL POWER 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months to less than or equal to the THERMAL POWER allowed by the regulating rod group insertion limits.

D. Required Action and D.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition C not met.

Crystal River Unit 3 3.2-2 Amendment No. 449

Regulating Rod Insertion Limits 3.2.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.2.1.1 Verify regulating rod groups are within the 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months when sequence and overlap limits as specified in the CONTROL ROD the COLR. drive sequence alarm is inoperable AND 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months when the CONTROL ROD drive sequence alarm is OPERABLE i

SR 3.2.1.2 Verify regulating rod groups meet the 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months when insertion limits as specified in the COLR the regulating rod insertion limit alarm is inoperable AND 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months when the regulating rod insertion limit alarm is OPERABLE SR 3.2.1.3 Verify SDM 40

-% k-/-. Within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months prior to achieving criticality Crystal River Unit 3 3.2-3 Amendment No. 4A-9

RPS Instrumentation 3.3.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME F. As required by F.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Required Action D.1 and referenced in AND Table 3.3.1-1 or by Required Action E.2. F.2 Open all CONTROL ROD 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months drive (CRD) trip breakers.

G. As required by G.1 Open all CRD trip 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Required Action D.1 breakers.

and referenced in Table 3.3.1-1.

H. As required by H.1 Reduce THERMAL POWER 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Required Action D.1 < 45% RTP.

and referenced in Table 3.3.1-1.

I. As required by 1.1 Reduce THERMAL POWER 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Required Action D.1 < 20% RTP.

and referenced in Table 3.3.1-1.

J. Secondary heat balance J.1 Reduce THERMAL POWER 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months not based on required to _--2-568-MWth high accuracy instrumentation. AND J.2 Reduce Nuclear 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months Overpower - High Setpoint to < 103.3%

RTP.

K. Required Action and K.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition J AND not met. K.2 Open all Control Rod 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months drive (CRD) trip breakers.

Crystal River Unit 3 3.3-2 Amendment No. -228

RPS Instrumentation 3.3.1 SURVEILLANCE REQUIREMENTS

NOTE Refer to Table 3.3.1-1 to determine which SRs apply to each RPS Function.

SURVEILLANCE FREQUENCY SR 3.3.1.1 Perform CHANNEL CHECK. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.1.2 ------------------ NOTES---------------------

1. Not required to be performed until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after THERMAL POWER is _>15% RTP.

G 1.2. High accuracy instrumentation is K> required to be utilized when performing calorimetric secondary heat balance comparison unless Condition J has been entered.

Verify calorimetric secondary heat balance is 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months

< 2% RTP greater than power range channel output. Adjust power range channel output if calorimetric exceeds power range channel output by > 2% RTP.

SR 3.3.1.3 ------------------ NOTE-----------------------

Not required to be performed until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after THERMAL POWER (TP) is > 30% RTP.

Compare out of core measured AXIAL POWER 31 days IMBALANCE (API 0 ) to incore measured AXIAL POWER IMBALANCE (APId) as follows:

(RTP/TP)(APIo - API,) = imbalance error Perform CHANNEL CALIBRATION if the absolute value of the imbalance error is > 2.5% RTP.

SR 3.3.1.4 Perform CHANNEL FUNCTIONAL TEST. 45 days on a STAGGERED TEST BASIS (continued)

Crystal River Unit 3 3.3-3 Amendment No. M

Source Range Neutron Flux 3.3.9 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) B.4 Verify SDM is 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months

% Ak/k- --

> AND within 1imits specified in Once per the COLR. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.9.1 Perform CHANNEL CHECK. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.9.2 ------------------ NOTE---------------------

Neutron detectors are excluded from CHANNEL CALIBRATION.

Perform CHANNEL CALIBRATION. 24 months SR 3.3.9.3 Verify at least one decade overlap with Once each intermediate range neutron flux channels. reactor startup prior to source range counts exceeding 106 cps if not performed within the previous 7 days Crystal River Unit 3 3.3-23 Amendment No. S-2

PAM Instrumentation 3.3.17 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D. Required Action and D.1 Enter the Condition Immediately associated Completion referenced in Time of Condition C Table 3.3.17-1 for not met. the Function.

E. As required by E.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Required Action D.1 and referenced in AND Table 3.3.17-1.

E.2 Be in MODE 4. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months F. As required by F.1 Initiate action in Immediately Required Action D.1 accordance with and referenced in Specification Table 3.3.17-1. 5.7.2.a.

Crystal River Unit 3 3.3-39 Amendment No. -149

Insert 3.3.17-1 G. As required by Required G.1 Reduce THERMAL 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Action D.1 and POWER < 2609 MWt.

referenced in Table 3.3.17-1.

PAM Instrumentation 3.3.17 SURVEILLANCE REQUIREMENTS NOTE----------------------------------

These SRs apply to each PAM instrumentation Function in Table 3.3.17-1.

SURVEILLANCE FREQUENCY SR 3.3.17.1 -------------------- NOTE-------------------

Not required for Function 4.

Perform CHANNEL CHECK for each required 31 days instrumentation channel that is normally energized. A SR 3.3.17.2 ------------------ NOTE - --

~Neutron detectors are excluded from CHANNEL CALIBRATION.

-- NE- -- 2-- ---

2 ---

gy__ Not required for Functions 23 and 25.

Perform CHANNEL CALIBRATION. 24 months SR 3.3.17.3 ------------------ NOTE-------------------

Only required for Functions 23 and 25.

Perform CHANNEL FUNCTIONAL TEST. 24 months Crystal River Unit 3 3.3-40 Amendment No. 2-16

PAM Instrumentation 3.3.17 Table 3.3.17-1 (page 1 of 1)

Post Accident Monitoring Instrumentation CONDITIONS REFERENCED FROM FUNCTION REQUIRED CHANNELS REQUIRED ACTION D.1

1. Wide Range Neutron Flux 2 E

2. RCS Hot Leg Temperature 2 E

3. RCS Pressure (Wide Range) 2 E

4. Reactor Coolant Inventory 2 F

5. Borated Water Storage Tank LeveT 2 E HPI)

6. High Pressure Injection Flow 2 per injection line E

7. Containment Sump Water Level (Flood Level) 2 E

8. Containment Pressure (Expected Post-Accident 2 E Range)

9. Containment Pressure (Wide Range) 2 E

10. Containment Isolation Valve Position 2 per penetration',)b" E

11. Containment Area Radiation (High Range) 2 F

12. Not UsHPI Flow Margin E

13. Pressurizer Level 2 E

14. Steam Generator Water Level (Start-up Range) 2 per OTSG E

15. Steam Generator Water Level (Operating Range) 2 per OTSG E

16. Steam Generator Pressure 2 per OTSG E

17. Emergency Feedwater Tank Level 2 E

18a. Core Exit Temperature (Thermocouple) 2 thermocouples per core quadrant E

18b. Core Exit Temperature (Recorder) 2 E

19. Emergency Feedwater Flow 2 per OTSG E

20. Low Pressure Injection Flow 2 E

21. Degrees of Subcooling 2 E

22. Emergency Diesel Generator kW Indication 2*

E

23. LPI Pump Run Status 2 E

24. DHV-42 and DHV-43 Open Position 2 E

25. HPI Pump Run Status 2 2 E

26. RCS Pressure (Low Range)

(a) Only one position indication is required for penetrations with one Control Room indicator.

(b) Not required for isolation valves whose associated penetration is isolated by at least one closed and deactivated automatic valve, closed manual valve, blind flange, or check valve with flow through the valve secured.

(c) One indicator per EDG.

Crystal River Unit 3 3.3-41 Amendment No. 2-16

Remote Shutdown System 3.3.18 Table 3.3.18-1 (page 1 of 1)

Remote Shutdown System Instrumentation REQUIRED FUNCTION/INSTRUMENT NUMBER OF CHANNELS

1. Reactivity Control

a. Reactor Trip Breaker (RTB) Position 1 per trip breaker

b. Source Range Neutron Flux

2. Reactor Coolant System (RCS) Pressure Control

a. RCS Wide Range Pressure

3. RCS Temperature Control via Steam Generators (OTSGs)

a. Reactor Coolant Hot Leg Temperature 1 per loop

b. Reactor Coolant Cold Leg Temperature 1 per loop

c. OTSG Pressure 1 per OTSG

d. OTSG Level 1 Low Range and 1 High Range per OTSG

e. Emergency Feedwater Flow 1 per OTSG

f. Emergency Feedwater Tank Level 1

4. RCS Inventory Control

a. Pressurizer Level 1

b. High Pressure Injection Flow 1 per injection line Insert lOOMS: Next Page Crystal River Unit 3 3.3-44 Amendment No. 1%

Insert ICCMS I ICCMS Instrumentation 3.3.19 3.3 INSTRUMENTATION 3.3.19 Inadequate Core Cooling Monitoring System (ICCMS) Instrumentation LCO 3.3.19 The ICCMS instrumentation channels for each Function in Table 3.3.19-1 shall be OPERABLE.

APPLICABILITY: According to Table 3.3.19-1.

ACTIONS

NOTES-----------------------------------

1. Separate Condition entry is allowed for each Function.

2. Enter applicable Conditions and Required Actions of LCO 3.3.17, "Post Accident Monitoring (PAM) Instrumentation," when required PAM channel(s) are inoperable.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required A.1 Restore required 30 days channels inoperable, channel to OPERABLE status.

B. Required Action and B.1 Enter the Condition Immediately associated Completion referenced in Time of Condition A Table 3.3.19-1 for not met. the Function.

OR Fast Cooldown System (FCS) actuation capability not maintained.

(continued)

Crystal River Unit 3 3.3-45 Amendment No.

Ilnsert ICCMS I ICCMS Instrumentation 3.3.19 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. As required by C.1 Initiate action in Immediately Required Action B.1 accordance with and referenced in Specification Table 3.3.19-1. 5.7.2.a.

D. As required by D.1 Declare FCS Immediately Required Action B.1 inoperable.

and referenced in Table 3.3.19-1.

SURVEILLANCE REQUIREMENTS

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

Refer to Table 3.3.19-1 to determine which SRs apply for each ICCMS Instrumentation Function.

SURVEILLANCE FREQUENCY SR 3.3.19.1 Perform CHANNEL CHECK. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.19.2 Perform CHANNEL FUNCTIONAL TEST. 92 days (continued)

Crystal River Unit 3 3.3-46 Amendment No.

Insert ICCMS ICCMS Instrumentation 3.3.19 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY

-I-SR 3.3.19.3 ------------------ NOTES----------------

1. If the as-found channel setpoint is conservative, but outside its predefined as-found acceptance criteria band, then the channel should be evaluated to verify that it is functioning as required before returning the channel to service. If the as-found instrument channel is not conservative, the channel shall be declared inoperable.

2. The instrument channel shall be reset to within, or more conservative than, the pre-established as-left tolerance:

otherwise the channel shall not be returned to OPERABLE status. The pre-established tolerance and methodology used to determine the predefined as-found and as-left acceptance criteria are specified in the FSAR.

Perform CHANNEL CALIBRATION. 24 months Crystal River Unit 3 3.3-47 Amendment No.

[Insert ICCMS I ICCMS Instrumentation 3.3.19 Table 3.3.19-1 (page 1 of 2)

Inadequate Core Cooling Monitoring System (ICCMS) Instrumentation APPLICABLE CONDITION REQUIRED MODES OR REFERENCED CHANNELS OTHER FROM PER ICCMS SPECIFIED REQUIRED INITIATION S URVEILLANCE FUNCTION CONDITIONS ACTION B.1 CHANNEL RIEQUIREMENTS

1. Fast Cooldownn System Actuation

a. High Press ure Injection (HPI) (a) D 4 S R 3.3.19.1 Flow SR 3.3.19.2 SR 3.3.19.3

b. Reactor Coolant Pressure - Low (a) D 1 S R 3.3.19.1 Range SR 3.3.19.2 S R 3.3.19.3

c. Reactor Co)olant Pressure - Wide (a) D 1 S R 3.3.19.1 Range S R 3.3.19.2 S R 3.3.19.3

d. Core Exit Thermocouples (CETs) (a) D 1 per S*R 3.3.19.1 quadrant S*R 3.3.19.2 S*R 3.3.19.3

e. Loss of Suubcooling Margin (a) 0 1 S.R 3.3.19.1 S.R 3.3.19.2 S.R 3.3.19.3

f. Inadequate HPI Flow (a) D 1 SR 3.3.19.1 S.R 3.3.19.2 SR 3.3.19.3

g. Reactor Tr rip Status (a) D 6 S*R 3.3.19.2

2. Reactor Cool ant Pump (RCP)Trip

a. Reactor Coolant Pressure - Low 1, 2, 3 C 1S R 3.3.19.1 Range S R 3.3.319.2 S R 3.3.19.3

b. Reactor Co)olant Pressure - Wide 1, 2, 3 C S R 3.3.19.1 Range S R 3.3.19.2 S R 3.3.19.3

c. CETs 1, 2, 3 C 1 per SR 3.3.19.1 quadrant S R 3.3.19.2 S R 3.3.19.3 (continued)

(a) THERMAL POWER > 2609 MWt.

Crystal River Unit 3 3.3-48 Amendment No.

lInsert ICCMS I ICCMS Instrumentation 3.3.19 Table 3.3.19-1 (page 2 of 2)

Inadequate Core Cooling Monitoring System (ICCMS) Instrumentation APPLICABLE CONDITION REQUIRED MODES OR REFERENCED CHANNELS OTHER FROM PER ICCMS SPECIFIED REQUIRED INITIATION SURVEILLANCE FUNCTION CONDITIONS ACTION B.1 CHANNEL REQUIREMENTS

2. RCP Trip (continued)

d. Loss of Subcooling Margin 1, 2, 3 C 1 SR 3.3.19.1 SR 3.3.19.2 SR 3.3.19.3

e. Reactor Trip Status 1, 2, 3 C 6 SR 3.3.19.2

3. Steam Generator Inadequate Subcooling Margin Level Setpoint Actuation

a. Reactor Coolant Pressure - Low 1, 2, 3 C 1 SR 3.3.19.1 Range SR 3.3.19.2 SR 3.3.19.3

b. Reactor Coolant Pressure - Wide 1, 2, 3 C 1 SR 3.3.19.1 Range SR 3.3.19.2 SR 3.3.19.3

c. CETs 1, 2, 3 C 1 per SR 3.3.19.1 quadrant SR 3.3.19.2 SR 3.3.19.3

d. Loss of Subcooling Margin 1, 2, 3 C 1 SR 3.3.19.1 SR 3.3.19.2 SR 3.3.19.3

e. Reactor Trip Status 1, 2, 3 C 6 SR 3.3.19.2 (a) THERMAL POWER > 2609 MWt.

Crystal River Unit 3 3.3-49 Amendment No.

Insert ICCMS I ICCMS Automatic Actuation Logic 3.3.20 3.3 INSTRUMENTATION 3.3.20 Inadequate Core Cooling Monitoring System (ICCMS) Automatic Actuation Logic LCO 3.3.20 Two ICCMS automatic actuation logic trains for each Function listed in Table 3.3.20-1 shall be OPERABLE.

APPLICABILITY: According to Table 3.3.20-1.

ACTIONS

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

Separate Condition entry is allowed for each Function.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more A.1 Restore automatic 30 days Functions with one actuation logic or more automatic train to OPERABLE actuation logic status.

trains inoperable.

B. Required Action and B.1 Enter the Condition Immediately associated referenced in Completion Time of Table 3.3.20-1 for Condition A not met. the Function.

OR Fast Cooldown System (FCS) actuation capability not maintained.

(continued)

Crystal River Unit 3 3.3-50 Amendment No.

Insert ICCMS7 ICCMS Automatic Actuation Logic 3.3.20 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. As required by C.1 Initiate action in Immediately Required Action B.1 accordance with and referenced in Specification Table 3.3.20-1. 5.7.2.a.

D. As required by D.1 Declare FCS Immediately Required Action B.1 inoperable.

and referenced in Table 3.3.20-1.

SURVEILLANCE REQUIREMENTS

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

Refer to Table 3.3.20-1 to determine which SRs apply for each ICCMS automatic actuation logic Function.

SURVEILLANCE FREQUENCY SR 3.3.20.1 Perform CHANNEL FUNCTIONAL TEST. 92 days on a STAGGERED TEST BASIS SR 3.3.20.2 Perform automatic actuation logic CHANNEL 24 months FUNCTIONAL TEST including reactor coolant pump breaker actuation.

SR 3.3.20.3 Perform automatic actuation logic CHANNEL 24 months FUNCTIONAL TEST including steam generator inadequate subcooling margin level setpoint actuation.

Crystal River Unit 3 3.3-51 Amendment No.

Insert ICMS ICCMS Automatic Actuation Logic 3.3.20 Table 3.3.20-1 (page 1 of 1)

Inadequate Core Cooling Monitoring System Automatic Actuation Logic APPLICABLE MODES CONDITION OR OTHER REFERENCED FROM SPECIFIED REQUIRED ACTION SURVEILLANCE FUNCTION CONDITIONS B.1 REQUIREMENTS

1. Fast Cooldown System Actuation (a) D SR 3.3.20.1

2. Reactor Coolant Pump Trip 1, 2, 3 C SR 3.3.20.1 SR 3.3.20.2

3. Steam Generator Inadequate 1, 2, 3 C SR 3.3.20.1 Subcooling Margin Level Setpoint SR 3.3.20.3 Actuation (a) THERMAL POWER > 2609 MWt.

Crystal River Unit 3 3.3-52 Amendment No.

RCS Pressure, Temperature, and Flow DNB Limits 3.4.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.1.1 -------------------- NOTE-------------------

With three RCPs operating, the limit is applied to the loop with two RCPs in operation.

Verify RCS loop pressure meets the RCS loop 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months pressure limits specified in the COLR.

SR 3.4.1.2 ------------------- NOTE------------------

With three RCPs operating, the limit is applied to the loop with two RCPs in operation.

Verify RCS hot leg temperature meet5-+h*e 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

-t--he-COLR-RT-AN*-i-i _<60-5-.-8& *e-r SR 3.4.1.3 Verify RCS total flow rate meets-0-re--K-S 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

t*-&t--fw rate I 4M m-t-s--se-i-f-i-ed-4ith OR 9I -1 4-3-3-.3 E6 lb/hr with four RCPs operating or > 99- E6 lb/hr with three RCPs operating A">fj SR 3.4.1.4 ------------------- NOTE------------------

Only required to be performed when stable thermal conditions are established > 90% of ALLOWABLE THERMAL POWER.

Verify RCS total flow rate is within limit 24 months by measurement.

Crystal River Unit 3 3.4-2 Amendment No. 2-04

RCS PIV Leakage 3.4.13 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.13 RCS Pressure Isolation Valve (PIV) Leakaae within limits 4

LCO 3.4.13 Leakage from each RCS PIV shall be .-f-gpm andithe Automatic Closure and Interlock System (ACIS) shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3, MODE 4, except valves in the decay heat removal (DHR) flow path when in, or during the transition to or from the DHR mode of operation.

ACTIONS

NOTES------------------------------

1. Separate Condition entry is allowed for each flow path.

2. Enter applicable Conditions and Required Actions for systems made inoperable by an inoperable PIV.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more flow paths ------------ NOTE-----------

with leakage from one Each valve used to satisfy or more RCS PIVs not Required Action A.1 and within limit. Required Action A.2 must have been verified to meet SR 3.4.13.1 and be on the high pressure portion of the system.

I_ _(continued)

Crystal River Unit 3 3.4-24 Amendment No. -149

RCS PIV Leakage 3.4.13 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3 .4.13.1 ----------------- NOTE--------------------

Not required to be performed in MODES 3 and 4.

Verify eq-ui-va4-,e leakage from each RCS PIV In accordance is Hw H mi4 at an RCS pressure of 2155 with the Inservice Testing Program AND equivalent to ý<0.5 gpm per nominal inch of valve size up to a Prior to maxximum of 5 gpm entering MODE 2 whenever the unit has been in MODE 5 for 7 days or more, if leakage testing has not been performed in the previous 9 months SR 3.4.13.2 Verify ACIS prevents the valves from being 24 months opened with a simulated or actual RCS pressure signal of 284 psig (nominal).

SR 3.4.13.3 Verify ACIS causes the valves to close 24 months automatically with a simulated or actual RCS pressure signal of 284 psig (nominal).

Crystal River Unit 3 3.4-26 Amendment No. 4-9

RCS Specific Activity 3.4.15 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.15 RCS Specific Activity LCO 3.4.15 The specific activity of the reactor coolant shall be within limits.

APPLICABILITY: MODES 1 and 2, MODE 3 with RCS average temperature (T...) > 500°F.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. DOSE EQUIVALENT 1-131 ------------ NOTE----------

> .0 pCi/gm. LCO 3.0.4.c is applicable.

A.1 Verify DOSE Once per 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months EQUIVALENT 1-131 wi thin the -a&ccetal goen-ef AND % -56 AND< 15 pCi/gmn.

A.2 Restore DOSE 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months EQUIVALENT 1-131 to within limit.

B. Required Action and B.1 Be in MODE 3 with 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Tavg < 500 0 F.

Time of Condition A not met.

OR DOSE EQUIVALENT 1-131 i n-ts-he#-u4gc-re 3e.or1S1 (continued)

L 15 hi/rn Crystal River Unit 3 3.4-30 Amendment No. 2-1-5

RCS Specific Activity 3.4.15 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. Gross specific C.1 Perform SR 3.4.15.2. 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months activity of the coolant not within AND limit.

C.2 Be in MODE 3 with 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months T avg < 5000 F.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.15.1 Verify reactor coolant gross specific 7 days activity < 100/E pCi/gm.

SR 3.4.15.2 --------------------NOTE---------------

Only required to be performed in MODE 1.

Verify reactor coolant DOSE EQUIVALENT 14 days 1-131 specific activity < -.. O pCi/gm.

AND Between 2 and 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after THERMAL POWER change of > 15%

RTP within a 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months period (continued)

Crystal River Unit 3 3.4-31 Amendment No. -149

THIS PAGE INTENTIONALLY LEFT BLANK.

RCS Specific Activity 3.4.15 200 150 100 50 02 Figure 3.4.15-1 (page 1 of 1) eactor Coolant DOSE EQUIVALENT 1-131 Specific Activity Li It ersus Percent of RATED THERMAL POWER With Reactor Coola t Specific Activity >1.0 pCi/gm DOSE EQUIVALENT 1-131 Crystal River Unit 3 3.4-33 Amendment No. 149

CFTs 3.5.1 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 3.5.1 Core Flood Tanks (CFTs)

LCO 3.5.1 Two CFTs shall be OPERABLE.

APPLICABILITY: MODES 1 and 2, MODES 3 with Reactor Coolant System (RCS) pressure

> 750 psig.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. CFT inoperable due to A.1 Restore boron A 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months boron concentration concentration t not within limits, within limits B. CFT inoperable for B.1 Restore CFT(s) to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months reasons other than OPERABLE status Condition A.

OR Two CFTs inoperable.

C. Required Action and C.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met. AND C.2 Reduce RCS pressure 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to

750 psig.

Crystal River Unit 3 3.5-1 Amendment No. -149

CFTs 3.5.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.1.1 Verify each CFT isolation valve is fully 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months open.

SR 3.5.1.2 Verify borated water volume in each CFT is 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

> 7255 gallons and < 8005 gallons __)

SR 3.5.1.3 Verify nitrogen cover pressure in each CFT 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is >_ 577 psia and < 653 psia.

SR 3.5.1.4 Verify boron concentration in each CFT is 31 days

Ž 2-270 ppm and < 3500 ppm.

AND 2600- NOTE ------

Only required to be performed for affected CFT Once within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after each solution volume increase of

_ 80 gallons that is not the result of addition from the borated water storage tank (continued)

Crystal River Unit 3 3.5-2 Amendment No. -149

ECCS - Operating 3.5.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.2.6 Verify the flow controllers for the 24 months following LPI throttle valves operate properly:

a. DHV-110

b. DHV-111 SR 3.5.2.7 Verify, by visual inspection, each ECCS 24 months train reactor building emergency sump suction inlet is not restricted by debris and suction inlet trash racks and screens show no evidence of structural distress or abnormal corrosion.

SR 3.5.2.8 Verify the following valves in the LPI flow pt "are locked, sealed or otherwise secured in the correct Sposition:

a. DHV-500, 24 months

b. DHV-501,

c. DHV-600, and

d. DHV-601.

Crystal River Unit 3 3.5-6 Amendment No. 49

BWST 3.5.4 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 3.5.4 Borated Water Storage Tank (BWST I K-)

LCO 3.5.4 The BWST shall be OPERABLE.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. BWST boron A.1 Restore BWST to 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months concentration not OPERABLE status.

within limits.

OR BWST water temperature not within limits.

B. BWST inoperable for B.1 Restore BWST to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months reasons other than OPERABLE status.

Condition A.

C. Required Action and C.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met. AND C.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months Crystal River Unit 3 3.5-9 Amendment No. -149

BWST 3.5.4 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.4.1 -------------------- NOTE-------------------

Only required to be performed when ambient air temperature is < 40°F or > 1O0OF.

Verify BWST borated water temperature is 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months

> 40°F and < 100F.

SR 3.5.4.2 Verify BWST borated water volume is 7 days

> 415,200 gallons and < 449,000 gallons.

SR 3.5.4.3 Verify BWST boron concentration is 31 days

> 27-0 ppm and < 3000 ppm.

AND Once within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after each solution volume increase of > 4000 gallons Crystal River Unit 3 3.5-10 Amendment No. 49

Containment Pressure 3.6.4 3.6 CONTAINMENT SYSTEMS 3.6.4 Containment Pressure LCO 3.6.4 Contai nment pressure shall be > -2.0 psig and A - Epsig.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Containment pressure A.1 Restore containment 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months not within limits, pressure to within limits.

B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met. AND B.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.4.1 Verify containment pressure is > -2.0 psig 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and < +3.0 psig.

+1.5 Crystal River Unit 3 3.6-15 Amendment No. 14-9

EFW System e ine Space 3.7.5 A l ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. Required Action and C.1 Be in M 3 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion 6 or Time of Condition A or AND B not met. MODE C.2 Be in ModeV4. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months D. Two EFW trains D.1 Initiate action to Immediately inoperable, restore one EFW train to OPERABLE status.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.5.1 Verify each EFW manual, power operated, and 45 days automatic valve in each water flow path, in both steam supply flow paths to the turbine driven pump, and starting air and fuel oil flow path for the diesel driven EFW pump that is not locked, sealed, or otherwise secured in position, is in the correct position.

SR 3.7.5.2 ----------------NOTE----------------------

Not required to be performed for the turbine driven EFW pump, until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after entering MODE 3.

Verify the developed head of each EFW pump In accordance at the flow test point is greater than or with the equal to the required developed head. Inservice Testing Program (continued)

Crystal River Unit 3 3.7-10 Amendment No. 2-3-1

EFW System 3.7.5 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.7.5.3 ------------------ NOTE-----------------------

Not required to be performed until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after entering MODE 3.

Verify each EFW automatic valve that is not 24 months locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal.

SR 3.7.5.4 ------------------ NOTE---------------------

Not required to be performed until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after entering MODE 3.

Verify each EFW pump starts automatically 24 months on an actual or simulated actuation signal.

SR 3.7.5.5 Verify proper alignment of the EFW flow Prior to paths by verifying flow from the EFW tank entering MODE 2 to each steam generator. whenever plant has been in MODE 5 or 6 for

> 30 days SR 3.7.5.6 Verify adequate battery terminal voltage. 7 days Crystal River Unit 3 3.7-11 Amendment No. 1 Insert 3.7.5-1 SR 3.7.5.7 Perform CHANNEL CALIBRATION of required EFW 24 months pump flow instrumentation.

Spent Fuel Pool Boron Concentration 3.7.14 3.7 PLANT SYSTEMS 3.7.14 Spent Fuel Pool Boron Concentration Add space.

LCO. 3.7.14 The spent fuel pool boron concentration shall be Ž1925 ppm.

APPLICABILITY: When fuel assemblies are stored in the spent fuel pool arA-a

_'1 t -,e liasnn mpovemecntf f asrumu I -s l, c peel*e+.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Spent fuel pool boron ------------- NOTE----------

concentration not LCO 3.0.3 is not applicable.

within limit.

A.1 Suspend movement of Immediately fuel assemblies in the spent fuel pool.

AND A.2-4 Initiate action to Immediately restore spent fuel pool boron concentration to within limit.

OR A,.-*. Ve-r*f-b -I-mmedli-a-t-el-y a--ter-age-1ot--A--and S-te-age-P-e1-B

-spe, fu&e-ooT 4-,atA-E&i-h~is--bee-R performed since the as5-emb*l4-es Crystal River Unit 3 3.7-28 Amendment No. 93

Di-ese! B-Z4 FW Pump Fuel Oil, Lube Oil and Starting Ai r InsertLine Space I -e Space _3.7.19 3.7 PLANT SYSTEMS 3.7.19 Diesel Driven EFW (DD-EFW) Pump Fuel Oil, Lube Oil and Starting Air LCO 3.7.19 The stored diesel fuel oil, lube oil, and starting air subsystems shall be within limits for the DD-EFW Pump.

APPLICABILITY: When the associated DD-EFW Pump is required to be Insert 2 Line Spaces I (* IERABLE.

Hanging-Indent]

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. DD-EFW Pump fuel oil A.1 Restore fuel oil level 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months supp y tank to within limits.

level -&J9-,480 gal and

> 8,-335 gal in the 8storageý ank.

B. With stored DD-EFW Pump B.1 Restore stored lube 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months diesel lube oil oil inventory to inventory < 207 gal and within limits.

> 178 gal.

C. DD-EFW Pump with C.1 Restore fuel oil total 7 days stored fuel oil total particulates to within particulates not limits.

within limits.

D. DD-EFW Pump with new D.1 Restore stored fuel 30 days fuel oil properties oil properties to not within limits, within limits.

E. DD-EFW Pump with E.1 Restore starting air 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months starting air receiver receiver pressure to pressure < 177 psig within limits.

and > 150 psig.

(continued)

Crystal River Unit 3 3.7-39 Amendment No. 215

Di csel Dr'DEW Pump Fuel Oil, Lube Oil and Starting Air 0 3.7.19 Insert Lin e Sp-a ce -- >'

ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME F. Required ACTION and F.1 Declare DD-EFW Pump Immediately associated Completion inoperable.

Time not met.

OR For DD-EFW Pump fuel oil, lube oil or starting air subsystems not within limits for reasons other than Conditions A, B, C, D or E.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.19.1 Verify DD-EFW Pump fuel oil storage tank 31 days contains >_ 9-,"S gal of fuel.

D9800 SR 3.7.19.2 Verify DD-EFW Pump stored lube oil inventory 31 days is > 207 gal.

SR 3.7.19.3 Verify DD-EFW Pump fuel oil properties of new In accordance and stored fuel oil are tested in accordance with the with, and maintained within the limits of the Diesel Fuel Diesel Fuel Oil Testing program. Oil Testing Program SR 3.7.19.4 Verify DD-EFW Pump starting air receiver 31 days pressure is > 177 psig.

Inef 3..0 Crystal River Unit 3 3.7-40 Amendment No. 2-1-5

Ilnsert ITS 3.7.201 FCS 3.7.20 3.7 PLANT SYSTEMS 3.7.20 Fast Cooldown System (FCS)

LCO 3.7.20 FCS shall be OPERABLE.

APPLICABILITY: THERMAL POWER > 2609 MWt.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. FCS inoperable due to A.1 Restore backup air 7 days inoperable backup air supply to OPERABLE supply. status.

B. FCS inoperable for B.1 Verify by Immediately reasons other than administrative means Condition A. both high pressure injection subsystems OPERABLE.

AND B.2 Restore FCS to OPERABLE 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months status.

C. Required Action and C.1 Reduce THERMAL 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months associated Completion POWER < 2609 MWt.

Time not met.

Crystal River Unit 3 3.7-41 Amendment No.

Insert ITS 3.7.20 FCS 3.7.20 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.20.1 Verify backup air supply pressure and volume 7 days for each atmospheric dump valve (ADV) are within limits.

SR 3.7.20.2 Verify each required FCS pressure controller 7 days battery terminal voltage is adequate.

SR 3.7.20.3 Perform FCS pressure controller CHANNEL 24 months CALIBRATION.

SR 3.7.20.4 Verify the capacity of each required FCS 24 months pressure controller battery is adequate to supply the required duty cycle when subjected to a battery service test.

SR 3.7.20.5 Verify each ADV actuates on an actual or 24 months simulated FCS actuation signal.

Crystal River Unit 3 3.7-42 Amendment No.

Design Features 4.0 4.0 DESIGN FEATURES

4. 3 Fuel Storage 4.3.1 Criticality 4.3.1.1 The spent fuel storage racks are designed and shall be maintained with:

a. Fuel assemblies having a maximum U-235 enrichment of 5.0 weight percent;

b. keffý-ý 0-.-9-5, if fully flooded with unborated water,

c. Keff K e :5 0.95 if flooded ed d which includes an allowance for uncertainties as with borated bh a ed water at a e0flaat described in Section 9.6 of the FSAR; soluble u boronn b

concentration ntc e n0 ati 0 n of 141 40 pprn ppm c-. A nominal 9.11 inch center to center distance between I 20 innth thee A pool wa and ndft203 r 3 fuel assemblies placed in the B pool; rn i pprn in Poo , i

'e the B pool, which 0 00 I ow an ce chor Twh to Acenter distance between r uncertainties r as ifS Is 10.5 inch assemblies center placed in the pool.

i d-. Afuelnominal 0csc rt po Idescribed includes anin allowance Section 0 99.6for f

of the FSAR;9t 4.3.1.2 The new fuel storage racks are designed and shall be maintained with:

a. Fuel assemblies having a maximum U-235 enrichment of 5.0 weight percent;

b. koff

0.95 is fully flooded with unborated water, which includes an allowance for uncertainties as described in Section 9.6 of the FSAR;

c. kef

0.98 if moderated by aqueous foam, which includes an allowance for uncertainties as described in Section 9.6 of the FSAR; and

d. A nominal 21.125 inch center to center distance between fuel assemblies placed in the storage racks.

(continued)

Crystal River Unit 3 4.0-2 Amendment No. 9-3

Reporting Requirements 5.7 5.7 Reporting Requirements 5.7.1.2 Not Used 5.7.2 Special Reports Special Reports shall be submitted in accordance with 10 CFR 50.4 within the time period specified for each report.

The following Special Reports shall be submitted:

"required by a. When a Special Report is required by Condition B or F of LCO 3.3.17, "Post Accident Monitoring (PAM)

Condition C of LCO Instrumentatiori*- a report shall be submitted within the 3.3.19, "Inadequate following 14 days. The report shall outline the preplanned Core Cooling alternate method of monitoring, the cause of the Monitoring System inoperability, and the plans and schedule for restoring the (ICCMS) instrumentation channels of the Function to OPERABLE status.

Instrumentation;"

or required by b. Any abnormal degradation of the containment structure found Condition C of LCO during the inspection performed in accordance with ITS 3.3.20, "Inadequate 5.6.2.8 shall be reported to the NRC within 30 days of the Core Cooling current surveillance completion. The abnormal degradation shall be defined as findings such as delamination of the Monitoring System dome concrete, widespread corrosion of the liner plate, (ICCMS) Automatic corrosion of prestressing elements (wires, strands, bars) or Actuation Logic;-" anchorage components extending to more than two tendons and group tendons force trends not meeting the requirements of 10CFR50.55a(b)(2)(ix)(B). The report shall include the description of degradation, operability determination, root cause determination and the corrective actions.

c. A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with the Specification 5.6.2.10, Steam Generator (OTSG) Program. The report shall include:

1. The scope of inspections performed on each OTSG,

2. Active degradation mechanisms found,

3. Nondestructive examination techniques utilized for each degradation mechanism,

4. Location, orientation (if linear), and measured sizes (if available) of service induced indications, (continued)

Crystal River Unit 3 5.0-28 Amendment No. 2-23

PROGRESS ENERGY FLORIDA, INC.

CRYSTAL RIVER UNIT 3 DOCKET NUMBER 50-302/LICENSE NUMBER DPR-72 LICENSE AMENDMENT REQUEST #309, REVISION 0 ATTACHMENT 3 OPERATING LICENSE AND IMPROVED TECHNICAL SPECIFICATION CHANGES (REVISION BAR FORMAT)

of the Act and to the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:

2.C.(1) Maximum Power Level Florida Power Corporation is authorized to operate the facility at a steady state reactor core power level not in excess of 3014 Megawatts.

2.C.(2) Technical Specifications The Technical Specifications contained in Appendices A and S, as revised through Amendment No. ,are hereby incorporated in the license. Florida Power Corporation shall operate the facility in accordance with the Technical Specifications.

The Surveillance Requirements contained in the Appendix A Technical Specifications and listed below are not required to be performed immediately upon implementation of Amendment 149. The Surveillance Requirements shall be successfully demonstrated prior to the time and condition specified below for each.

a) SR 3.3.8.2.b shall be successfully demonstrated prior to entering MODE 4 on the first plant start-up following Refuel Outage 9.

b) SR 3.3.11.2, Function 2, shall be successfully demonstrated no later than 31 days following the implementation date of the ITS.

c) SR 3.3.17.1, Functions 1, 2, 6,10,14, & 17 shall be successfully demonstrated no later than 31 days following the implementation date of the ITS.

d) SR 3.3.17.2, Function 10 shall be successfully demonstrated prior to entering MODE 3 on the first plant start-up following Refuel Outage 9.

e) SR 3.6.1.2 shall be successfully demonstrated prior to entering MODE 2 on the first plant start-up following Refuel Outage 9.

f) SR 3.7.12.2 shall be successfully demonstrated prior to entering MODE 2 on the first plant start-up following Refuel Outage 9.

g) SR 3.8.1.10 shall be successfully demonstrated prior to entering MODE 2 on the first plant start-up following Refuel Outage 9.

h) SR 3.8.3.3 shall be successfully demonstrated prior to entering MODE 4 on the first plant start-up following Refuel Outage 9.

Amendment No.

2.C.(6) Deleted per Amendment No. 21, 7-3-79 2.C.(7) Prior to startup following the first regularly scheduled refueling outage, Florida Power Corporation shall modify to the satisfaction of the Commission, the reactor coolant system flow indication to meet the single failure criterion with regard to pressure sensing lines to the flow differential pressure transmitters.

2.C.(8) Within three months of issuance of this license, Florida Power Corporation shall submit to the Commission a proposed surveillance program for monitoring the containment for the purpose of determining any future delamination of the dome.

2.C.(9) Fire Protection Florida Power Corporation shall implement and maintain in effect all provisions of the approved fire protection program as described in the Final Safety Analysis Report for the facility and as approved in the Safety Evaluation Reports, dated July 27, 1979, January 22, 1981, January 6, 1983, July 18, 1985, and March 16, 1988, subject to the following provisions:

The licensee may make changes to the approved fire protection program without prior approval of the Commission only if those changes would not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire. {Amdt. #147, 1-22-93) 2.C.(10) The design of the reactor coolant pump supports need not include consideration of the effects of postulated ruptures of the primary reactor coolant loop piping and may be revised in accordance with Florida Power Corporation's amendment request of April 24, 1986. [Added per Amdt. #89, 5-23-86) 2.C.(1 1) Deleted per Amendment [ ], MM/DD/YYYY.

2.C.(12) Deleted per Amendment No. 237 Amendment No.

Definitions 1.1 1.1 Definitions (continued)

CONTROL RODS CONTROL RODS shall be all full length safety and regulating rods that are used to shut down the reactor and control power level during maneuvering operations.

CORE ALTERATION CORE ALTERATION shall be the movement of any fuel, sources, or other reactivity control components, within the reactor vessel with the vessel head removed and fuel in the vessel. Suspension of CORE ALTERATIONS shall not preclude completion of movement of a component to a safe position.

CORE OPERATING LIMITS The COLR is the unit specific document that REPORT (COLR) provides cycle specific parameter limits for the current reload cycle. These cycle specific limits shall be determined for each reload cycle in accordance with Specification 5.6.2.18. Plant operation within these limits is addressed in individual Specifications.

DOSE EQUIVALENT 1-131 DOSE EQUIVALENT 1-131 shall be that concentration of 1-131 (microcuries per gram) that alone would produce the same dose when inhaled as the combined activities of iodine isotopes 1-131, 1-132, 1-133, 1-134, and 1-135 actually present. The determination of DOSE EQUIVALENT 1-131 shall be performed using Committed Effective Dose Equivalent (CEDE) dose conversion factors from Table 2.1 of EPA Federal Guidance Report No. 11, 1988, "Limiting Values of Radionuclide Intake and Air Concentration and Dose Conversion Factors for Inhalation, Submersion, and Ingestion."

E - AVERAGE E shall be the average (weighted in proportion DISINTEGRATION ENERGY to the concentration of each radionuclide in the reactor coolant at the time of sampling) of the sum of the average beta and gamma energies per disintegration (in MeV) for isotopes, other than iodines, with half lives > 15 minutes, making up at least 95% of the total non-iodine activity in the coolant.

EFFECTIVE FULL POWER EFPD shall be the ratio of the number of hours DAY (EFPD) of production of a given THERMAL POWER to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , multiplied by the ratio of the given THERMAL POWER to the RTP. One EFPD is equivalent (continued)

Crystal River Unit 3 1.1-3 Amendment No.

Definitions 1.1 1.1 Definitions EFFECTIVE FULL POWER to the thermal energy produced by operating the DAY (EFPD) reactor core at RTP for one full day. (One EFPD (continued) is 3014 MWt times 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or 72,336 MWhr.)

EMERGENCY FEEDWATER The EFIC RESPONSE TIME shall be that time INITIATION AND CONTROL interval from when the monitored parameter (EFIC) RESPONSE TIME exceeds its EFIC actuation setpoint at the channel sensor until the emergency feedwater equipment is capable of performing its safety function (i.e.,

valves travel to their required positions, pump discharge pressures reach their required values, etc.) Times shall include diesel generator starting and sequence loading delays, where applicable. The response time may be measured by means of any series of sequential, overlapping, or total steps so that the entire response time is measured.

ENGINEERED SAFETY The ESF RESPONSE TIME shall be that time interval FEATURE (ESF) RESPONSE from when the monitored parameter exceeds its ESF TIME actuation setpoint at the channel sensor until the ESF equipment is capable of performing its safety function (i.e., the valves travel to their required positions, pump discharge pressures reach their required values, etc.). Times shall include diesel generator starting and sequence loading delays, where applicable. The response time may be measured by means of any series of sequential, overlapping, or total steps so that the entire response time is measured.

LEAKAGE LEAKAGE shall be:

a. Identified LEAKAGE

1. LEAKAGE, such as that from pump seals or valve packing, that is captured and conducted to collection systems or a sump or collecting tank; or

2. LEAKAGE into the containment atmosphere from sources that are both specifically located and quantified and known not to interfere with the operation of leakage detection systems and not to be pressure boundary LEAKAGE; or (continued)

Crystal River Unit 3 1.1-4 Amendment No.

Definitions 1.1 1.1 Definitions PHYSICS TESTS These tests are:

(continued)

a. Described in Chapter 13, "Initial Tests and Operation" of the FSAR;

b. Authorized under the provisions of 10 CFR 50.59; or

c. Otherwise approved by the Nuclear Regulatory Commission.

PRESSURE AND The PTLR is the unit specific document that TEMPERATURE LIMITS provides the reactor vessel pressure and REPORT (PTLR) temperature limits, including heatup and cooldown rates, for the current reactor vessel fluence period. These pressure and temperature limits shall be determined for each fluence period in accordance with Specification 5.6.2.19. Plant operation within these operating limits is addressed in LCO 3.4.3, "RCS Pressure and Temperature Limits."

QUADRANT POWER TILT QPT shall be defined by the following equation and (QPT) is expressed as a percentage.

QPT = 100 Power In Any Core Quadrant S1)

Average Power of all Quadrants RATED THERMAL POWER RTP shall be a total reactor core heat transfer (RTP) rate to the reactor coolant of 3014 MWt.

REACTOR PROTECTION The RPS RESPONSE TIME shall be that time interval SYSTEM (RPS) RESPONSE from when the monitored parameter exceeds its RPS TIME trip setpoint at the channel sensor until electrical power is interrupted at the control rod drive trip breakers. The response time may be measured by means of any series of sequential, overlapping, or total steps so that the entire response time is measured.

SHUTDOWN MARGIN (SDM) SDM shall be the instantaneous amount of reactivity by which the reactor is subcritical or (continued)

Crystal River Unit 3 1.1-6 Amendment No.

SLs 2.0 2400 (633.2,2385.V 2300 I^

2200 CL)

Acceptable Operation 2100 C/)

2000 0~

0 Safety Limit Curve 1900 Unacceptable Operation 1800 (595.8, 1735.3) 1700 580 590 600 610 620 630 640 Reactor Outlet Temperature, OF Figure 2.1.1-1 (page 1 of 1)

Reactor Coolant System Departure From Nucleate Boiling Safety Limits Crystal River Unit 3 2.0-3 Amendment No.

SDM 3.1.1 3.1 REACTIVITY CONTROL SYSTEMS 3.1.1 SHUTDOWN MARGIN (SDM)

LCO 3.1.1 The SDM shall be within limits specified in the COLR.

APPLICABILITY: MODES 3, 4, and 5.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. SDM not within limit. A.1 Initiate boration to 15 minutes restore SDM to within limit.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.1.1.1 Verify SDM is within limits specified in 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months the COLR.

Crystal River Unit 3 3.1-1 Amendment No.

MTC 3.1.3 3.1 REACTIVITY CONTROL SYSTEMS 3.1.3 Moderator Temperature Coefficient (MTC)

LCO 3.1.3 The MTC shall be maintained within the limits specified in the COLR. The maximum positive limit shall be

0.0 Ak/k/°F at

> 95% RTP and

0.75 E-4 Ak/k/°F at < 95% RTP.

APPLICABILITY: MODES 1 and 2.

ACTIONS CONDITION T REQUIRED ACTION COMPLETION TIME A. MTC not within limits. {A.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.1.3.1 Verify MTC is within the upper limit Prior to specified in the COLR. entering MODE 1 after each fuel loading (continued)

Crystal River Unit 3 3.1-4 Amendment No.

CONTROL ROD Group Alignment Limits 3.1.4 3.1 REACTIVITY CONTROL SYSTEMS 3.1.4 CONTROL ROD Group Alignment Limits LCO 3.1.4 Each CONTROL ROD shall be OPERABLE and aligned to within 6.5% of its group average height.

APPLICABILITY: MODES 1 and 2.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One trippable CONTROL A. 1 Align all CONTROL 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months ROD inoperable, or not RODS in the group to aligned to within 6.5% within 6.5% of the of its group average group average height, height, or both. while maintaining the rod insertion, group sequence, and group overlap limits in accordance with LCO 3.2.1, "Regulating Rod Insertion Limits."

OR A.2.1.1 Verify SDM is 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months within limits specified in the AND COLR.

Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter OR A.2.1.2 Initiate boration to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months restore SDM to within limit.

AND (continued)

Crystal River Unit 3 3.1-6 Amendment No.

CONTROL ROD Group Alignment Limits 3.1.4 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.2.2 Reduce THERMAL POWER 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months to

60% of the ALLOWABLE THERMAL POWER.

AND A.2.3 Reduce the nuclear 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months overpower trip setpoint to

70% of the ALLOWABLE THERMAL POWER.

AND A.2.4 Verify the potential 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months ejected rod worth is within the assumptions of the rod ejection analysis.

AND A.2.5 Perform SR 3.2.5.1. 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time for Condition A not met.

C. More than one C.1.1 Verify SDM is 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months trippable CONTROL ROD within limits inoperable, or not specified in the aligned within 6.5% of COLR.

its group average height, or both. OR (continued)

Crystal River Unit 3 3.1-7 Amendment No.

CONTROL ROD Group Alignment Limits 3.1.4 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. (continued) C.1.2 Initiate boration to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months restore SDM to within limit.

AND C.2 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months D. One or more CONTROL D.1.1 Verify SDM is 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months RODS untrippable. within limits specified in the COLR.

OR D.1.2 Initiate boration to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months restore SDM to within limit.

AND D.2 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Crystal River Unit 3 3.1-8 Amendment No.

Safety Rod Insertion Limits 3.1.5 3.1 REACTIVITY CONTROL SYSTEMS 3.1.5 Safety Rod Insertion Limits LCO 3.1.5 Each safety rod shall be fully withdrawn.

APPLICABILITY: MODES 1 and 2.

NOTE This LCO is not applicable while performing SR 3.1.4.2.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One safety rod not A.1 Withdraw the rod 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months fully withdrawn. fully.

OR A.2.1.1 Verify SDM is 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months within limits specified in the COLR.

OR A.2.1.2 Initiate boration to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months restore SDM to within limit.

AND A.2.2 Declare the rod 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months inoperable.

(continued)

Crystal River Unit 3 3.1i-10 Amendment No.

Safety Rod Insertion Limits 3.1.5 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B More than one safety B.1.1 Verify SDM is 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months rod not fully within limits withdrawn. specified in the COLR.

OR B.1.2 Initiate boration to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months restore SDM to within limit.

AND B.2 Be in MODE 3 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.1.5.1 Verify each safety rod is fully withdrawn. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Crystal River Unit 3 3.1-11 Amendment No.

PHYSICS TESTS Exceptions - MODE 1 3.1.8 3.1 REACTIVITY CONTROL SYSTEMS 3.1.8 PHYSICS TESTS Exception - MODE 1 LCO 3.1.8 During the performance of PHYSICS TESTS, the requirements of LCO 3.1.4, "CONTROL ROD Alignment Limits";

LCO 3.1.5, "Safety Rod Insertion Limits";

LCO 3.1.6, "AXIAL POWER SHAPING ROD (APSR) Alignment Limits";

LCO 3.2.1, "Regulating Rod Insertion Limits," for the restricted operation region only; LCO 3.2.3, "AXIAL POWER IMBALANCE Operating Limits"; and LCO 3.2.4, "QUADRANT POWER TILT (QPT)"

may be suspended, provided:

a. THERMAL POWER is maintained

85% RTP;

b. Reactor trip setpoints on the nuclear overpower channels are set

10% RTP higher than the THERMAL POWER at which the test is performed, with a maximum setting of 90%

RTP;

c. FQ(Z) and FNAH are maintained with the limits specified in the COLR; and

d. SDM is within limits specified in the COLR.

APPLICABILITY: MODE 1 during PHYSICS TESTS.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. SDM not within limit. A.1 Initiate boration to 15 minutes restore SDM to within limit.

AND A.2 Suspend PHYSICS TESTS 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months exceptions.

(continued)

Crystal River Unit 3 3.1-17 Amendment No.

PHYSICS TESTS Exceptions - MODE 1 3.1.8 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.1.8.4 Verify SDM is within limits specified in 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months the COLR.

Crystal River Unit 3 3.1-19 Amendment No.

PHYSICS TESTS Exceptions - MODE 2 3.1.9 3.1 REACTIVITY CONTROL SYSTEMS 3.1.9 PHYSICS TESTS Exceptions - MODE 2 LCO 3.1.9 During performance of PHYSICS TESTS, the requirements of LCO 3.1.3, "Moderator Temperature Coefficient (MTC)";

LCO 3.1.4, "CONTROL ROD Group Alignment Limits";

LCO 3.1.5, "Safety Rod Insertion Limits";

LCO 3.1.6, "AXIAL POWER SHAPING ROD (APSR) Alignment Limits";

LCO 3.2.1, "Regulating Rod Insertion Limits," for the restricted operation region only; and LCO 3.4.2, "RCS Minimum Temperature for Criticality" may be suspended, provided:

a. THERMAL POWER is

5% RTP;

b. Reactor trip setpoints on the nuclear overpower channels are set to 5 25% RTP; and

c. SDM is within limits specified in the COLR.

APPLICABILITY: MODE 2 during PHYSICS TESTS.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. THERMAL POWER not A.1 Open control rod Immediately within limit, drive trip breakers.

(continued)

Crystal River Unit 3 3.1-20 Amendment No.

PHYSICS TESTS Exceptions - MODE 2 3.1.9 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. SDM not within limit. B.1 Initiate boration to 15 minutes restore SDM to within limit.

AND B.2 Suspend PHYSICS TESTS 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months exceptions C. Nuclear overpower trip C.1 Suspend PHYSICS TESTS 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months setpoint not within exceptions.

limit.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.1.9.1 Verify THERMAL POWER is

5% RTP. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months SR 3.1.9.2 Verify nuclear overpower trip setpoint is 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months

< 25% RTP.

SR 3.1.9.3 Verify SDM is within limits specified in 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months the COLR.

Crystal River Unit 3 3.1-21 Amendment No.

Regulating Rod Insertion Limits 3.2.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. Regulating rod groups C.1 Initiate boration to 15 minutes inserted in restore SDM to unacceptable within limits.

operational region.

AND C.2.1 Restore regulating 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months rod groups to within restricted operating region.

OR C.2.2 Reduce THERMAL POWER 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months to less than or equal to the THERMAL POWER allowed by the regulating rod group insertion limits.

D. Required Action and D.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition C not met.

Crystal River Unit 3 3.2-2 Amendment No.

Regulating Rod Insertion Limits 3.2.1 SURVEILLANCE REOUIREMENTS SURVEILLANCE FREQUENCY SR 3.2.1.1 Verify regulating rod groups are within the 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months when sequence and overlap limits as specified in the CONTROL ROD the COLR. drive sequence alarm is inoperable AND 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months when the CONTROL ROD drive sequence alarm is OPERABLE SR 3.2.1.2 Verify regulating rod groups meet the 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months when insertion limits as specified in the COLR the regulating rod insertion limit alarm is inoperable AND 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months when the regulating rod insertion limit alarm is OPERABLE SR 3.2.1.3 Verify SDM is within limits specified in Within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months the COLR. prior to achieving criticality Crystal River Unit 3 3.2-3 Amendment No.

RPS Instrumentation 3.3.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME F. As required by F.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Required Action D.1 and referenced in AND Table 3.3.1-1 or by Required Action E.2. F.2 Open all CONTROL ROD 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months drive (CRD) trip breakers.

G. As required by G.1 Open all CRD trip 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Required Action D.1 breakers.

and referenced in Table 3.3.1-1.

H. As required by H.1 Reduce THERMAL POWER 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Required Action D.1 < 45% RTP.

and referenced in Table 3.3.1-1.

I. As required by 1.1 Reduce THERMAL POWER 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Required Action D.1 < 20% RTP.

and referenced in Table 3.3.1-1.

J. Secondary heat balance J.1 Reduce THERMAL POWER 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months not based on required to < 2965 MWt.

high accuracy instrumentation.

AND J.2 Reduce Nuclear 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months Overpower - High Setpoint to < 103.3%

RTP.

K. Required Action and K.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition J AND not met.

K.2 Open all Control Rod 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months drive (CRD) trip breakers.

Crystal River Unit 3 3.3-2 Amendment No.

RPS Instrumentation 3.3.1 SURVEILLANCE REQUIREMENTS

NOTE Refer to Table 3.3.1-1 to determine which SRs apply to each RPS Function.

SURVEILLANCE FREQUENCY SR 3.3.1.1 Perform CHANNEL CHECK. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.1.2 ------------------ NOTES---------------------

1. Not required to be performed until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after THERMAL POWER is Ž 15% RTP.

2. High accuracy instrumentation is required to be utilized when performing calorimetric secondary heat balance comparison unless Condition 3 has been entered.

Verify calorimetric secondary heat balance is 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months

2% RTP greater than power range channel output. Adjust power range channel output if calorimetric exceeds power range channel output by > 2% RTP.

SR 3.3.1.3 ------------------ NOTE---------------------

Not required to be performed until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after THERMAL POWER (TP) is Ž 30% RTP.

Compare out of core measured AXIAL POWER 31 days IMBALANCE (API.) to incore measured AXIAL POWER IMBALANCE (API 1 ) as follows:

(RTP/TP)(APIo - API) = imbalance error Perform CHANNEL CALIBRATION if the absolute value of the imbalance error is e 2.5% RTP.

SR 3.3.1.4 Perform CHANNEL FUNCTIONAL TEST. 45 days on a STAGGERED TEST BASIS (continued)

Crystal River Unit 3 3.3-3 Amendment No.

Source Range Neutron Flux 3.3.9 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) B.4 Verify SDM is 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months within limits specified in AND the COLR.

Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.9.1 Perform CHANNEL CHECK. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.9.2 ------------------- NOTE---------------------

Neutron detectors are excluded from CHANNEL CALIBRATION.

Perform CHANNEL CALIBRATION. 24 months SR 3.3.9.3 Verify at least one decade overlap with Once each intermediate range neutron flux channels. reactor startup prior to source range counts exceeding 106 cps if not performed within the previous 7 days Crystal River Unit 3 3.3-23 Amendment No.

PAM Instrumentation 3.3.17 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D. Required Action and D.1 Enter the Condition Immediately associated Completion referenced in Time of Condition C Table 3.3.17-1 for not met. the Function.

E. As required by E.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Required Action D.1 and referenced in AND Table 3.3.17-1.

E.2 Be in MODE 4. 12 hours F. As required by F.1 Initiate action in Immediately Required Action D.1 accordance with and referenced in Specification Table 3.3.17-1. 5.7.2.a.

G. As required by G.1 Reduce THERMAL POWER 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Required Action D.1 < 2609 MWt.

and referenced in Table 3.3.17-1.

Crystal River Unit 3 3.3-39 Amendment No.

PAM Instrumentation 3.3.17 SURVEILLANCE REQUIREMENTS NOTE--------------------------------------

These SRs apply to each PAM instrumentation Function in Table 3.3.17-1.

SURVEILLANCE FREQUENCY SR 3.3.17.1 --------------------- NOTE--------------------

Not required for Function 4.

Perform CHANNEL CHECK for each required 31 days instrumentation channel that is normally energized.

SR 3.3.17.2 ------------------ NOTES--------------------

1. Neutron detectors are excluded from CHANNEL CALIBRATION.

2. Not required for Functions 23 and 25.

Perform CHANNEL CALIBRATION. 24 months SR 3.3.17.3 ------------------ NOTE-------------------

Only required for Functions 23 and 25.

Perform CHANNEL FUNCTIONAL TEST. 24 months Crystal River Unit 3 3.3-40 Amendment No.

PAM Instrumentation 3.3.17 Table 3.3.17-1 (page 1 of 1)

Post Accident Monitoring Instrumentation CONDITIONS REFERENCED FROM FUNCTION REQUIRED CHANNELS REQUIRED ACTION D.1

1. Wide Range Neutron Flux 2 E

2. RCS Hot Leg Temperature 2 E

3. RCS Pressure (Wide Range) 2 E

4. Reactor Coolant Inventory 2 F

5. Borated Water Storage Tank Level 2 E

6. High Pressure Injection (HPI) Flow 2 per injection line E

7. Containment Sump Water Level (Flood Level) 2 E

8. Containment Pressure (Expected Post-Accident 2 E Range)

9. Containment Pressure (Wide Range) 2 E

10. Containment Isolation Valve Position 2 per penetration"a)(b) E

11. Containment Area Radiation (High Range) 2 F

12. HPI Flow Margin 2 G

13. Pressurizer Level 2 E

14. Steam Generator Water Level (Start-up Range) 2 per OTSG E

15. Steam Generator Water Level (Operating Range) 2 per OTSG E

16. Steam Generator Pressure 2 per OTSG E

17. Emergency Feedwater Tank Level 2 E 18a. Core Exit Temperature (Thermocouple) 2 thermocouples per E core quadrant 18b. Core Exit Temperature (Recorder) 2 E

19. Emergency Feedwater Flow 2 per OTSG E

20. Low Pressure Injection Flow 2 E

21. Degrees of Subcooling 2 E

22. Emergency Diesel Generator kW Indication 2 () E

23. LPI Pump Run Status 2 E

24. DHV-42 and DHV-43 Open Position 2 E

25. HPI Pump Run Status 2 E

26. RCS Pressure (Low Range) 2 E (a) Only one position indication is required for penetrations with one Control Room indicator.

(b) Not required for isolation valves whose associated penetration is isolated by at least one closed and deactivated automatic valve, closed manual valve, blind flange, or check valve with flow through the valve secured.

(c) One indicator per EDG.

Crystal River Unit 3 3.3-41 Amendment No.

ICCMS Instrumentation 3.3.19 3.3 INSTRUMENTATION 3.3.19 Inadequate Core Cooling Monitoring System (ICCMS) Instrumentation LCO 3.3.19 The ICCMS instrumentation channels for each Function in Table 3.3.19-1 shall be OPERABLE.

APPLICABILITY: According to Table 3.3.19-1.

ACTIONS

NOTES-----------------------------------

1. Separate Condition entry is allowed for each Function.

2. Enter applicable Conditions and Required Actions of LCO 3.3.17, "Post Accident Monitoring (PAM) Instrumentation," when required PAM channel(s) are inoperable.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required A.1 Restore required 30 days channels inoperable, channel to OPERABLE status.

B. Required Action and B.1 Enter the Condition Immediately associated Completion referenced in Time of Condition A Table 3.3.19-1 for not met. the Function.

OR Fast Cooldown System (FCS) actuation capability not maintained.

(continued)

Crystal River Unit 3 3.3-45 Amendment No.

ICCMS Instrumentation 3.3.19 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. As required by C.1 Initiate action in Immediately Required Action B.1 accordance with and referenced in Specification Table 3.3.19-1. 5.7.2.a.

D. As required by D.1 Declare FCS Immediately Required Action B.1 inoperable.

and referenced in Table 3.3.19-1.

SURVEILLANCE REQUIREMENTS

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

Refer to Table 3.3.19-1 to determine which SRs apply for each ICCMS Instrumentation Function.

SURVEILLANCE FREQUENCY SR 3.3.19.1 Perform CHANNEL CHECK. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.19.2 Perform CHANNEL FUNCTIONAL TEST. 92 days (continued)

Crystal River Unit 3 3.3-46 Amendment No.

ICCMS Instrumentation 3.3.19 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.19.3 -----------------

NOTES----------------

1. If the as-found channel setpoint is conservative, but outside its predefined as-found acceptance criteria band, then the channel should be evaluated to verify that it is functioning as required before returning the channel to service. If the as-found instrument channel is not conservative, the channel shall be declared inoperable.

2. The instrument channel shall be reset to within, or more conservative than, the pre-established as-left tolerance:

otherwise the channel shall not be returned to OPERABLE status. The pre-established tolerance and methodology used to determine the predefined as-found and as-left acceptance criteria are specified in the FSAR.

Perform CHANNEL CALIBRATION. 24 months Crystal River Unit 3 3.3-47 Amendment No.

ICCMS Instrumentation 3.3.19 Table 3.3.19-1 (page 1 of 2)

Inadequate Core Cooling Monitoring System (ICCMS) Instrumentation APPLICABLE CONDITION REQUIRED MODES OR REFERENCED CHANNELS OTHER FROM PER ICCMS SPECIFIED REQUIRED INITIATION SI URVEILLANCE FUNCTION CONDITIONS ACTION B.1 CHANNEL RIEQUIREMENTS

1. Fast Cooldownn System Actuation

a. High Presssure Injection (HPI) (a) D 4 S.R 3.3.19.1 Flow S.R 3.3.19.2 S.R 3.3.19.3

b. Reactor Coolant Pressure - Low (a) D 1 SR 3.3.19.1 Range S.R 3.3.19.2 S.R 3.3.19.3

c. Reactor Coolant Pressure - Wide (a) D 1 S*R 3.3.19.1 Range S.R 3.3.19.2 S.R 3.3.19.3

d. Core Exit Thermocouples (CETs) (a) D 1 per S*R 3.3.19.1 quadrant SR 3.3.19.2 SR 3.3.19.3

e. Loss of Suubcooling Margin (a) D 1S R 3.3.19.1 S R 3.3.19.2 S R 3.3.19.3

f. Inadequate HPI Flow (a) D 1S R 3.3.19.1 S R 3.3.19.2 SR 3.3.19.3

g. Reactor Tr rip Status (a) D 6 SR 3.3.19.2

2. Reactor Coolaant Pump (RCP)Trip

a. Reactor Coolant Pressure - Low 1, 2, 3 C SR 3.3.19.1 Range SR 3.3.19.2 SR 3.3.19.3

b. Reactor Coolant Pressure - Wide 1, 2, 3 C 1S R 3.3.19.1 Range S R 3.3.19.2 S R 3.3.19.3

c. CETs 1, 2, 3 C 1 per SR 3.3.19.1 quadrant S R 3.3.19.2 S.R 3.3.19.3 (continued)

(a) THERMAL POWER > 2609 MWt.

Crystal River Unit 3 3.3-48 Amendment No.

ICCMS Instrumentation 3.3.19 Table 3.3.19-1 (page 2 of 2)

Inadequate Core Cooling Monitoring System (ICCMS) Instrumentation APPLICABLE CONDITION REQUIRED MODES OR REFERENCED CHANNELS OTHER FROM PER ICCMS SPECIFIED REQUIRED INITIATION SURVEILLANCE FUNCTION CONDITIONS ACTION B.1 CHANNEL REQUIREMENTS

2. RCP Trip (continued)

d. Loss of Subcooling Margin 1, 2, 3 C 1 SR 3.3.19.1 SR 3.3.19.2 SR 3.3.19.3

e. Reactor Trip Status 1, 2, 3 C 6 SR 3.3.19.2

3. Steam Generator Inadequate Subcooling Margin Level Setpoint Actuation

a. Reactor Coolant Pressure - Low 1, 2, 3 C 1 SR 3.3.19.1 Range SR 3.3.19.2 SR 3.3.19.3

b. Reactor Coolant Pressure - Wide 1, 2, 3 C 1 SR 3.3.19.1 Range SR 3.3.19.2 SR 3.3.19.3

c. CETs 1, 2, 3 C 1 per SR 3.3.19.1 quadrant SR 3.3.19.2 SR 3.3.19.3

d. Loss of Subcooling Margin 1, 2, 3 C 1 SR 3.3.19.1 SR 3.3.19.2 SR 3.3.19.3

e. Reactor Trip Status 1, 2, 3 C 6 SR 3.3.19.2 (a) THERMAL POWER > 2609 MWt.

Crystal River Unit 3 3.3-49 Amendment No.

ICCMS Automatic Actuation Logic 3.3.20 3.3 INSTRUMENTATION 3.3.20 Inadequate Core Cooling Monitoring System (ICCMS) Automatic Actuation Logic LCO 3.3.20 Two ICCMS automatic actuation logic trains for each Function listed in Table 3.3.20-1 shall be OPERABLE.

APPLICABILITY: According to Table 3.3.20-1.

ACTIONS

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

Separate Condition entry is allowed for each Function.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more A.1 Restore automatic 30 days Functions with one actuation logic or more automatic train to OPERABLE actuation logic status.

trains inoperable.

B. Required Action and B.1 Enter the Condition Immediately associated referenced in Completion Time of Table 3.3.20-1 for Condition A not met. the Function.

OR Fast Cooldown System (FCS) actuation capability not maintained.

(continued)

Crystal River Unit 3 3.3-50 Amendment No.

ICCMS Automatic Actuation Logic 3.3.20 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. As required by C.1 Initiate action in Immediately Required Action B.1 accordance with and referenced in Specification Table 3.3.20-1. 5.7.2.a.

D. As required by D.1 Declare FCS Immediately Required Action B.1 inoperable.

and referenced in Table 3.3.20-1.

SURVEILLANCE REQUIREMENTS

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

Refer to Table 3.3.20-1 to determine which SRs apply for each ICCMS automatic actuation logic Function.

SURVEILLANCE FREQUENCY SR 3.3.20.1 Perform CHANNEL FUNCTIONAL TEST. 92 days on a STAGGERED TEST BASIS SR 3.3.20.2 Perform automatic actuation logic CHANNEL 24 months FUNCTIONAL TEST including reactor coolant pump breaker actuation.

SR 3.3.20.3 Perform automatic actuation logic CHANNEL 24 months FUNCTIONAL TEST including steam generator inadequate subcooling margin level setpoint actuation.

Crystal River Unit 3 3.3-51 Amendment No.

ICCMS Automatic Actuation Logic 3.3.20 Table 3.3.20-1 (page 1 of 1)

Inadequate Core Cooling Monitoring System Automatic Actuation Logic APPLICABLE MODES CONDITION OR OTHER REFERENCED FROM SPECIFIED REQUIRED ACTION SURVEILLANCE FUNCTION CONDITIONS B.1 REQUIREMENTS

1. Fast Cooldown System Actuation (a) D SR 3.3.20.1

2. Reactor Coolant Pump Trip 1, 2, 3 C SR 3.3.20.1 SR 3.3.20.2

3. Steam Generator Inadequate 1, 2, 3 C SR 3.3.20.1 Subcooling Margin Level Setpoint SR 3.3.20.3 Actuation (a) THERMAL POWER > 2609 MWt.

Crystal River Unit 3 3.3-52 Amendment No.

RCS Pressure, Temperature, and Flow DNB Limits 3.4.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.1.1 -------------------- NOTE-------------------

With three RCPs operating, the limit is applied to the loop with two RCPs in operation.

Verify RCS loop pressure meets the RCS loop 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months pressure limits specified in the COLR.

SR 3.4.1.2 -------------------- NOTE-------------------

With three RCPs operating, the limit is applied to the loop with two RCPs in operation.

Verify RCS hot leg temperature 5 611.2 0 F. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.4.1.3 Verify RCS total flow rate > 139.4 E6 lb/hr 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months with four RCPs operating or Ž 104.2 E6 lb/hr with three RCPs operating.

SR 3.4.1.4 -------------------- NOTE-------------------

Only required to be performed when stable thermal conditions are established > 90% of ALLOWABLE THERMAL POWER.

Verify RCS total flow rate is within limit 24 months by measurement.

Crystal River Unit 3 3.4-2 Amendment No.

RCS PIV Leakage 3.4.13 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.13 RCS Pressure Isolation Valve (PIV) Leakage LCO 3.4.13 Leakage from each RCS PIV shall be within limits and the Automatic Closure and Interlock System (ACIS) shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3, MODE 4, except valves in the decay heat removal (DHR) flow path when in, or during the transition to or from the DHR mode of operation.

ACTIONS

NOTES------------------------------

1. Separate Condition entry is allowed for each flow path.

2. Enter applicable Conditions and Required Actions for systems made inoperable by an inoperable PIV.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more flow paths ------------ NOTE-----------

with leakage from one Each valve used to satisfy or more RCS PIVs not Required Action A.1 and within limit. Required Action A.2 must have been verified to meet SR 3.4.13.1 and be on the high pressure portion of the system.

I _(continued)

Crystal River Unit 3 3.4-24 Amendment No.

RCS PIV Leakage 3.4.13 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.13.1 ----------------- NOTE-Not required to be performed in MODES 3 and 4.

Verify leakage from each RCS PIV is In accordance equivalent to < 0.5 gpm per nominal inch of with the valve size up to a maximum of 5 gpm at an Inservice RCS pressure of 2155 psig. Testing Program AND Prior to entering MODE 2 whenever the unit has been in MODE 5 for 7 days or more, if leakage testing has not been performed in the previous 9 months SR 3.4.13.2 Verify ACIS prevents the valves from being 24 months opened with a simulated or actual RCS pressure signal of 284 psig (nominal).

SR 3.4.13.3 Verify ACIS causes the valves to close 24 months automatically with a simulated or actual RCS pressure signal of 284 psig (nominal).

Crystal River Unit 3 3.4-26 Amendment No.

RCS Specific Activity 3.4.15 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.15 RCS Specific Activity LCO 3.4.15 The specific activity of the reactor coolant shall be within limits.

APPLICABILITY: MODES 1 and 2, MODE 3 with RCS average temperature (Tavg) Ž 5001F.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. DOSE EQUIVALENT 1-131 ------------ NOTE----------

> 0.25 pCi/gm. LCO 3.0.4.c is applicable.

A.1 Verify DOSE Once per 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months EQUIVALENT 1-131

< 15 pCi/gm.

AND A.2 Restore DOSE 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months EQUIVALENT 1-131 to within limit.

B. Required Action and B.1 Be in MODE 3 with 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion T < 500'F.

Time of Condition A not met.

OR DOSE EQUIVALENT 1-131

> 15 pCi/gm.

(continued)

Crystal River Unit 3 3.4-30 Amendment No.

RCS Specific Activity 3.4.15 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. Gross specific C.1 Perform SR 3.4.15.2. 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months activity of the coolant not within AND limit.

C.2 Be in MODE 3 with 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months T avg < 500'F.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.15.1 Verify reactor coolant gross specific 7 days activity < 100/E tuCi/gm.

SR 3.4.15.2 --------------------NOTE---------------

Only required to be performed in MODE 1.

Verify reactor coolant DOSE EQUIVALENT 14 days 1-131 specific activity < 0.25 /Ci/gm.

AND Between 2 and 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after THERMAL POWER change of > 15%

RTP within a 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months period (continued)

Crystal River Unit 3 3.4-31 Amendment No.

RCS Specific Activity 3.4.15 THIS PAGE INTENTIONALLY LEFT BLANK.

Crystal River Unit 3 3.4-33 Amendment No.

CFTs 3.5.1 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 3.5.1 Core Flood Tanks (CFTs)

LCO 3.5.1 Two CFTs shall be OPERABLE.

APPLICABILITY: MODES 1 and 2, MODES 3 with Reactor Coolant System (RCS) pressure

> 750 psig.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. CFT inoperable due to A.1 Restore boron 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months boron concentration concentration to not within limits, within limits.

B. CFT inoperable for B.1 Restore CFT(s) to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months reasons other than OPERABLE status.

Condition A.

OR Two CFTs inoperable.

C. Required Action and C.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met. AND C.2 Reduce RCS pressure 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to

750 psig.

Crystal River Unit 3 3.5-1 Amendment No.

CFTs 3.5.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.1.1 Verify each CFT isolation valve is fully 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months open.

SR 3.5.1.2 Verify borated water volume in each CFT is 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

Ž 7255 gallons and

8005 gallons.

SR 3.5.1.3 Verify nitrogen cover pressure in each CFT 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is Ž 577 psia and

653 psia.

SR 3.5.1.4 Verify boron concentration in each CFT is 31 days 2600 ppm and

3500 ppm.

AND

NOTE ------

Only required to be performed for affected CFT Once within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after each solution volume increase of

Ž 80 gallons that is not the result of addition from the borated water storage tank (continued)

Crystal River Unit 3 3.5-2 Amendment No.

ECCS - Operating 3.5.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.2.6 Verify the flow controllers for the 24 months following LPI throttle valves operate properly:

a. DHV-110, and

b. DHV-111.

SR 3.5.2.7 Verify, by visual inspection, each ECCS 24 months train reactor building emergency sump suction inlet is not restricted by debris and suction inlet trash racks and screens show no evidence of structural distress or abnormal corrosion.

SR 3.5.2.8 Verify the following valves in the LPI flow 24 months path are locked, sealed or otherwise secured in the correct position:

a. DHV-500,

b. DHV-501,

c. DHV-600, and

d. DHV-601.

Crystal River Unit 3 3.5-6 Amendment No.

BWST 3.5.4 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 3.5.4 Borated Water Storage Tank (BWST)

LCO 3.5.4 The BWST shall be OPERABLE.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. BWST boron A.1 Restore BWST to 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months concentration not OPERABLE status.

within limits.

OR BWST water temperature not within limits.

B. BWST inoperable for B.1 Restore BWST to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months reasons other than OPERABLE status.

Condition A.

C. Required Action and C.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met. AND C.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months Crystal River Unit 3 3.5-9 Amendment No.

BWST 3.5.4 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.4.1 ------------------- NOTE-------------------

Only required to be performed when ambient air temperature is < 401F or > 1001F.

Verify BWST borated water temperature is 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 2 40°F and

1000 F.

SR 3.5.4.2 Verify BWST borated water volume is 7 days

Ž 415,200 gallons and

449,000 gallons.

SR 3.5.4.3 Verify BWST boron concentration is 31 days 2600 ppm and

3000 ppm.

AND Once within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after each solution volume increase of > 4000 gallons Crystal River Unit 3 3.5-10 Amendment No.

Containment Pressure 3.6.4 3.6 CONTAINMENT SYSTEMS 3.6.4 Containment Pressure LCO 3.6.4 Containment pressure shall be Ž -2.0 psig and * +1.5 psig.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Containment pressure A.1 Restore containment 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months not within limits, pressure to within limits.

B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met. AND B.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.4.1 Verify containment pressure is > -2.0 psig 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and < +1.5 psig.

Crystal River Unit 3 3.6-15 Amendment No.

EFW System 3.7.5 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. Required Action and C.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition A or AND B not met.

C.2 Be in MODE 4. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months D. Two EFW trains D.1 Initiate action to Immediately inoperable, restore one EFW train to OPERABLE status.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.5.1 Verify each EFW manual, power operated, and 45 days automatic valve in each water flow path, in both steam supply flow paths to the turbine driven pump, and starting air and fuel oil flow path for the diesel driven EFW pump that is not locked, sealed, or otherwise secured in position, is in the correct position.

SR 3.7.5.2 ---------------- NOTE----------------------

Not required to be performed for the turbine driven EFW pump, until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after entering MODE 3.

Verify the developed head of each EFW pump In accordance at the flow test point is greater than or with the equal to the required developed head. Inservice Testing Program (continued)

Crystal River Unit 3 3.7-10 Amendment No.

EFW System 3.7.5 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.7.5.3 ------------------ NOTE-----------------------

Not required to be performed until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after entering MODE 3.

Verify each EFW automatic valve that is not 24 months locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal.

SR 3.7.5.4 ------------------ NOTE---------------------

Not required to be performed until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after entering MODE 3.

Verify each EFW pump starts automatically 24 months on an actual or simulated actuation signal.

SR 3.7.5.5 Verify proper alignment of the EFW flow Prior to paths by verifying flow from the EFW tank entering MODE 2 to each steam generator. whenever plant has been in MODE 5 or 6 for

> 30 days SR 3.7.5.6 Verify adequate battery terminal voltage. 7 days SR 3.7.5.7 Perform CHANNEL CALIBRATION of required EFW 24 months pump flow instrumentation.

Crystal River Unit 3 3.7-11 Amendment No.

Spent Fuel Pool Boron Concentration 3.7.14 3.7 PLANT SYSTEMS 3.7.14 Spent Fuel Pool Boron Concentration LCO. 3.7.14 The spent fuel pool boron concentration shall be

> 1925 ppm.

APPLICABILITY: When fuel assemblies are stored in the spent fuel pool.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Spent fuel pool boron ------------- NOTE----------

concentration not LCO 3.0.3 is not applicable.

within limit.

A.1 Suspend movement of Immediately fuel assemblies in the spent fuel pool.

AND A.2 Initiate action to Immediately restore spent fuel pool boron concentration to within limit.

Crystal River Unit 3 3.7-28 Amendment No.

DD-EFW Pump Fuel Oil, Lube Oil and Starting Air 3.7.19 3.7 PLANT SYSTEMS 3.7.19 Diesel Driven EFW (DD-EFW) Pump Fuel Oil, Lube Oil and Starting Air LCO 3.7.19 The stored diesel fuel oil, lube oil, and starting air subsystems shall be within limits for the DD-EFW Pump.

APPLICABILITY: When the associated DD-EFW Pump is required to be OPERABLE.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. DD-EFW Pump fuel oil A.1 Restore fuel oil level 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months supply tank to within limits.

level < 9800 gal and

> 8600 gal in the storage tank.

B. With stored DD-EFW Pump B.1 Restore stored lube 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months Diesel lube oil oil inventory to inventory < 207 gal and within limits.

> 178 gal.

C. DD-EFW Pump with C.1 Restore fuel oil total 7 days stored fuel oil total particulates to within particulates not limits.

within limits.

D. DD-EFW Pump with new D.1 Restore stored fuel 30 days fuel oil properties oil properties to not within limits, within limits.

E. DD-EFW Pump with E.1 Restore starting air 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months starting air receiver receiver pressure to pressure < 177 psig within limits.

and > 150 psig.

(continued)

Crystal River Unit 3 3.7-39 Amendment No.

DD-EFW Pump Fuel Oil, Lube Oil and Starting Air 3.7.19 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME F. Required ACTION and F.1 Declare DD-EFW Pump Immediately associated Completion inoperable.

Time not met.

OR For DD-EFW Pump fuel oil, lube oil or starting air subsystems not within limits for reasons other than Conditions A, B, C, D or E.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.19.1 Verify DD-EFW Pump fuel oil storage tank 31 days contains > 9800 gal of fuel.

SR 3.7.19.2 Verify DD-EFW Pump stored lube oil inventory 31 days is > 207 gal.

SR 3.7.19.3 Verify DD-EFW Pump fuel oil properties of new In accordance and stored fuel oil are tested in accordance with the with, and maintained within the limits of the Diesel Fuel Diesel Fuel Oil Testing program. Oil Testing Program SR 3.7.19.4 Verify DD-EFW Pump starting air receiver 31 days pressure is Ž 177 psig.

Crystal River Unit 3 3.7-40 Amendment No.

FCS 3.7.20 3.7 PLANT SYSTEMS 3.7.20 Fast Cooldown System (FCS)

LCO 3.7.20 FCS shall be OPERABLE.

APPLICABILITY: THERMAL POWER > 2609 MWt.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. FCS inoperable due to A.1 Restore backup air 7 days inoperable backup air supply to OPERABLE supply. status.

B. FCS inoperable for B.1 Verify by Immediately reasons other than administrative means Condition A. both high pressure injection subsystems OPERABLE.

AND B.2 Restore FCS to OPERABLE 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months status.

C. Required Action and C.1 Reduce THERMAL 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months associated Completion POWER

2609 MWt.

Time not met.

Crystal River Unit 3 3.7-41 Amendment No.

FCS 3.7.20 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.20.1 Verify backup air supply pressure and volume 7 days for each atmospheric dump valve (ADV) are within limits.

SR 3.7.20.2 Verify each required FCS pressure controller 7 days battery terminal voltage is adequate.

SR 3.7.20.3 Perform FCS pressure controller CHANNEL 24 months CALIBRATION.

SR 3.7.20.4 Verify the capacity of each required FCS 24 months pressure controller battery is adequate to supply the required duty cycle when subjected to a battery service test.

SR 3.7.20.5 Verify each ADV actuates on an actual or 24 months simulated FCS actuation signal.

Crystal River Unit 3 3.7-42 Amendment No.

Design Features 4.0 4.0 DESIGN FEATURES 4.3 Fuel Storage 4.3.1 Criticality 4.3.1.1 The spent fuel storage racks are designed and shall be maintained with:

a. Fuel assemblies having a maximum U-235 enrichment of 5.0 weight percent;

b. keff < 1.0 if fully flooded with unborated water, which includes an allowance for uncertainties as described in Section 9.6 of the FSAR;

c. K < 0.95 if flooded with borated water at a soluble boron concentration of 141 ppm in the A pool and 203 ppm in the B pool, which includes an allowance for uncertainties as described in Section 9.6 of the FSAR;

d. A nominal 9.11 inch center to center distance between fuel assemblies placed in the B pool; and

e. A nominal 10.5 inch center to center distance between fuel assemblies placed in the A pool.

4.3.1.2 The new fuel storage racks are designed and shall be maintained with:

a. Fuel assemblies having a maximum U-235 enrichment of 5.0 weight percent;

b. koff < 0.95 is fully flooded with unborated water, which includes an allowance for uncertainties as described in Section 9.6 of the FSAR;

c. kef _<0.98 if moderated by aqueous foam, which includes an allowance for uncertainties as described in Section 9.6 of the FSAR; and

d. A nominal 21.125 inch center to center distance between fuel assemblies placed in the storage racks.

(continued)

Crystal River Unit 3 4.0-2 Amendment No.

Reporting Requirements 5.7 5.6 Reporting Requirements 5.7.1.2 Not Used 5.7.2 Special Reports Special Reports shall be submitted in accordance with 10 CFR 50.4 within the time period specified for each report.

The following Special Reports shall be submitted:

a. When a Special Report is required by Condition B or F of LCO 3.3.17, "Post Accident Monitoring (PAM)

Instrumentation;" required by Condition C of LCO 3.3.19, "Inadequate Core Cooling Monitoring System (ICCMS)

Instrumentation;" or required by Condition C of LCO 3.3.20, "Inadequate Core Cooling Monitoring System (ICCMS) Automatic Actuation Logic;" a report shall be submitted within the following 14 days. The report shall outline the preplanned alternate method of monitoring, the cause of the inoperability, and the plans and schedule for restoring the instrumentation channels of the Function to OPERABLE status.

b. Any abnormal degradation of the containment structure found during the inspection performed in accordance with ITS 5.6.2.8 shall be reported to the NRC within 30 days of the current surveillance completion. The abnormal degradation shall be defined as findings such as delamination of the dome concrete, widespread corrosion of the liner plate, corrosion of prestressing elements (wires, strands, bars) or anchorage components extending to more than two tendons and group tendons force trends not meeting the requirements of 10CFR50.55a(b)(2)(ix)(B). The report shall include the description of degradation, operability determination, root cause determination and the corrective actions.

c. A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with the Specification 5.6.2.10, Steam Generator (OTSG) Program. The report shall include:

1. The scope of inspections performed on each OTSG,

2. Active degradation mechanisms found,

3. Nondestructive examination techniques utilized for each degradation mechanism,

4. Location, orientation (if linear), and measured sizes (if available) of service induced indications, (continued)

Crystal River Unit 3 5.0-28 Amendment No.

PROGRESS ENERGY FLORIDA, INC.

CRYSTAL RIVER UNIT 3 DOCKET NUMBER 50-302/LICENSE NUMBER DPR-72 LICENSE AMENDMENT REQUEST #309, REVISION 0 ATTACHMENT 4 IMPROVED TECHNICAL SPECIFICATION BASES CHANGES (MARKUP) - FOR INFORMATION ONLY

Reactor Core SLs B 2.1.1 BASES APPLICABLE The RPS setpoints (Ref. 2), in combination with the DNB SAFETY ANALYSES operating limits LCO (LCO 3.4.1), are designed to prevent any anticipated combination of transient conditions for Reactor Coolant System (RCS) temperature, pressure, and THERMAL POWER level that would result in a departure from nucleate boiling ratio (DNBR) of less than the DNBR limit and preclude the existence of flow instabilities.

Automatic enforcement of these reactor core SLs is provided by the following:

a. RCS High Pressure trip;

b. RCS Low Pressure trip;

c. Nuclear Overpower trip;

d. RCS Variable Low Pressure trip; (RCPPM)

e. Reactor Coolant Pump to Power rip; and

f. Nuclear Overpower RCS Flow and AXIAL POWER IMBALANCE trip.

Measured The SL represents a design requirement for establishing the RPS trip setpoints identified previously.

Safety Limits that preclude fuel cladding failure are required to be included in the Technical Specifications pursuant to 10 CFR 50.36 (Ref. 5).

SAFETY LIMITS SL 2.1.1.1, SL 2.1.1.2, and SL 2.1.1.3 ensure that the minimum DNBR is not less than the safety analyses limit and that fuel centerline temperature stays below the melting point, or the average enthalpy in the hot leg is less than or equal to the enthalpy of saturated liquid, or the exit quality is within the limits defined by the DNBR correlation. In addition, SL 2.1.1.3 addresses the pressure/temperature operating region that keeps the reactor from reaching an SL when operating up to design power.

(continued)

Crystal River Unit 3 B 2.0-3 Revision No. 34

Reactor Core SLs B 2.1.1 BASES (continued)

SAFETY LIMITS Examination of the limit curve in Figure 2.1.1-1 reveals that the temperatures corresponding to the pressures vary between 20 and J-O°F below the saturation temperature of the 2 coolant at thai~pressure, thus ensuring an even greater margin to DNB.

The fuel centerline melt and DNBR SLs are not directly monitorable by installed plant instrumentation. Instead, the SLs are preserved by monitoring the process variable AXIAL POWER IMBALANCE to ensure that the core operates within the fuel design criteria. With AXIAL POWER IMBALANCE within the protective limits, fuel centerline temperature and DNBR are also within limits. AXIAL POWER IMBALANCE protective limits are provided in the COLR.

The AXIAL POWER IMBALANCE protective limits are preserved by their corresponding RPS setpoints in LCO 3.3.1, "Reactor Protection System (RPS) Instrumentation," as specified in the COLR. The trip setpoints are derived by adjusting the measurement system independent AXIAL POWER IMBALANCE protective limit given in the COLR to allow for measurement system observability (the fact there are a finite number of detectors) and instrumentation errors. The AXIAL POWER IMBALANCE protective limits are separate and distinct from the AXIAL POWER IMBALANCE operating limits defined by LCO 3.2.3, "AXIAL POWER IMBALANCE Operating Limits." The AXIAL POWER IMBALANCE operating limits in LCO 3.2.3, also specified in the COLR, preserve initial conditions of the safety analyses but are not reactor core SLs.

RCS pressure, temperature and flow DNB operating limits are defined by LCO 3.4.1.

APPLICABILITY SL 2.1.1.1, SL 2.1.1.2, and SL 2.1.1.3 only apply in MODES 1 and 2 because these are the only MODES in which the reactor is critical. Automatic protection functions are required to be OPERABLE during MODES 1 and 2 to ensure operation within the reactor core SLs. The automatic protection actions serve to prevent RCS heatup to reactor core SL conditions by initiating a reactor trip which forces the plant into MODE 3. Setpoints for the reactor trip functions are specified in LCO 3.3.1.

(continued)

Crystal River Unit 3 B 2.0-4 Revision No. 34

SDM B 3.1.1 BASES (continued)

APPLICABLE The minimum required SDM is assumed as an initial condition SAFETY ANALYSES in safety analysis. The safety analysis (Ref. 2) establishes an SDM that ensures specified acceptable fuel design limits are not exceeded for normal operation and AOOs, with assumption of the highest worth rod stuck out following a reactor trip.

The acceptance criteria for SDM requirements are established to ensure specified acceptable fuel design limits are maintained. The SDM requirements must ensure that:

a. The reactor can be made subcritical from all operating conditions, transients, and Design Basis Events;

b. The reactivity transients associated ith postulated accident conditions are controllableNw-th acceptable limits (departure from nucleate boiling ratio (DNBR),

limi fuel centerline temperature limits for AO0s, and

280-ea-l-ýgm fuel-ent,-py for the rod ejection accident); and

c. The reactor will be maintained sufficiently subcritical to preclude inadvertent criticality in the shutdown condition.

The most limiting accident for the SDM requirements is based on an MSLB, as described in the accident analysis (Ref. 2).

In addition to the limiting MSLB transient, the SDM requirement was an initial condition assumption in the analysis of the following:

a. Inadvertent boron dilution;

b. An uncontrolled rod withdrawal from a subcritical or low power condition;

c. Rod ejection; and

d. Return to criticality if an MSLB occurs during high steam generator level operations in MODE 3, 4, or 5.

To compensate for the potential heat removal associated with an MSLB accident when high steam generator levels exist (continued)

Crystal River Unit 3 B 3. 1-2 Amendment No. 149

SDM B 3.1.1 BASES APPLICABLE during secondary system chemistry control and steam SAFETY ANALYSIS generator cleaning, the initial SDM in the core must be (continued) adjusted. The basis for the SDM shutdown requirement when high steam generator levels exist is the heat removal potential in the secondary system fluid and the negative reactivity added via MTC. At any given initial primary system temperature and its associated secondary system pressure, the secondary system liquid levels can be equated to a final primary system temperature assuming the entire mass is boiled. The resulting RCS temperature determines the required SDM.

SDM satisfies Criterion 2 of the NRC Policy Statement.

LCO SDM requirements assume the highest worth rod is stuck in the fully withdrawn position to account for a postulated untrippable rod prior to reactor shutdown.

A figure in the COLR, or boration of the RCS to SDM requirements for 73°F is used to define the SDM when high steam generator levels exist during secondary system chemistry control and steam generator cleaning in MODES 3, 4, and 5. This represents a series of initial conditions that ensure the core will remain subcritical following an MSLB accident initiated from those conditions. Be-a-t-i-eo-f 4e-R-S-4tG-% A k-/--SDM-f-&r -17330F k-iF 4-by--p--abt-e c-o-leown-3ee edu,.rme--i4-r--te-bypa-s--f--EFC--aet-Ft-in-on+-l-ow s~~-e .p-~sse=

APPLICABILITY In MODES 3, 4, and 5, the SDM requirements ensure sufficient negative reactivity to meet the assumptions of the safety analysis discussed above. In MODES 1 and 2, SDM is ensured by complying with LCO 3.1.5 and LCO 3.2.1. In MODE 6, the shutdown reactivity requirements are given in LCO 3.9.1, "Boron Concentration."

ACTIONS A.1 If the SDM requirements are not met, boration must be initiated promptly. A Completion Time of 15 minutes is adequate for an operator to correctly align and start the required systems and components. It is assumed that boration to restore SDM will be continued until the SDM requirements are met. If the SDM is less than the limit (continued)

Crystal River Unit 3 B 3.1-3 Revision No. 22

SDM B 3.1.1 BASES ACTIONS A.1 (continued) for the steam generator level and RCS temperature specified in the COLR &F-4% A 4/0(, RCS boration must be continued until the applicable limit is met.

In the determination of the required combination of boration flow rate and boron concentration, there is no unique requirement that must be satisfied. Since it is imperative to raise the boron concentration of the RCS as soon as possible, the boron concentration should be a highly concentrated solution, such as that normally found in the boric acid storage tank or the borated water storage tank.

The operator should borate with the best source available given the existing plant conditions.

In determining the boration flow rate, the time in core life must be considered. For instance, the most difficult time in core life to increase the RCS boron concentration is at the beginning of cY cle, when the boron concentration may approach or excee -OOO ppm. For example, pumping a boric acid solution with 11,600 ppm boron at 10 gpm will result in 180 the addition of 1% A k/k negative reactivity in approximately1-2-O minutes at typical BOC conditions.

Slightly shorter times can be achieved when the same negative reactivity addition is made later in the fuel cycle when the initial RCS boron concentration is lower. Other flowrates and boric acid supply concentrations can be used to provide equivalent results.

SURVEILLANCE SR 3.1.1.1 REQUIREMENTS The SDM is verified by performing a reactivity balance calculation, considering the following reactivity effects:

a. RCS boron concentration;

b. Regulating rod position;

c. RCS average temperature;

d. Fuel burnup based on gross thermal energy generation;

e. Xenon concentration; and

f. Samarium concentration.

(continued)

Crystal River Unit 3 B 3.1-4 Revision No. 17

MTC B 3.1.3 BASES APPLICABLE MTC values are bounded in reload safety evaluations, SAFETY ANALYSES assuming steady state conditions at BOC and EOC. A near EOC (continued) measurement is conducted at conditions when the RCS boron concentration reaches approximately 300 ppm. The measured value is extrapolated to project the EOC value, or the Surveillance repeated, in order to confirm reload design predictions.

MTC satisfies Criterion 2 of the NRC Policy Statement.

LCO LCO 3.1.3 requires the MTC to be within specified limits in the COLR to ensure the core operates within the assumptions of the accident analysis. During the reload core safety evaluation, the MTC is analyzed to determine that its values remain within the bounds of the original accident analysis during operation. The LCO establishes a maximumvp ositive +.

value that can not be exceeded. The limit of +O1-9E-4 Ak/k/°F on positive MTC, when THERMAL POWER is < 95% RTP, ensures that core overheating accidents will not violate the accident analysis assumptions. The requirement for a negative MTC, when THERMAL POWER is Ž 95% RTP, ensures that steady state core operation will be stable at higher power levels. The negative MTC limit for EOC specified in the COLR ensures that core overcooling accidents will not violate the accident analysis assumptions.

MTC is a core physics parameter determined by the fuel and fuel cycle design and cannot be easily controlled once the core design is fixed during operation. Therefore, the LCO can only be ensured through measurement. The BOC and EOC surveillance checks on MTC provide confirmation that the MTC is behaving as anticipated, and the acceptance criteria of the reload safety analysis are met.

APPLICABILITY In MODE 1, the limits on MTC must be maintained to ensure that any accident initiated from THERMAL POWER operation will not violate the design assumptions of the accident analysis. In MODE 2, the limits must also be maintained to ensure that startup and subcritical accidents, such as the uncontrolled CONTROL ROD assembly or group withdrawal, will not violate the assumptions of the accident analysis. In MODES 3, 4, 5, and 6, this LCO is not applicable, since no Design Basis Accidents (DBAs) using the MTC as an analysis (continued)

Crystal River Unit 3 B 3.1-14 Amendment No. 149

CONTROL ROD Group Alignment Limits B 3.1.4 BASES APPLICABILITY in the boron concentration of the RCS. See LCO 3.1.1, (continued) "SHUTDOWN MARGIN (SDM)," for SDM in MODES 3, 4, and 5, and LCO 3.9.1, "Boron Concentration," which ensures SDM during refueling.

ACTIONS A.1 Alignment of the inoperable or misaligned CONTROL ROD may be accomplished by either moving the single CONTROL ROD to the group, or by moving the remainder of the group to the position of the single inoperable or misaligned CONTROL ROD.

Either action can be used to restore the CONTROL RODS to a radially symmetric pattern. However, this must be done without violating the CONTROL ROD group sequence, overlap, and insertion limits of LCO 3.2.1, "Regulating Rod Insertion Limits," given in the COLR. This may necessitate THERMAL POWER must also be reduced, to maintain compliance with the insertion limits of LCO 3.2.1. The Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is acceptable because local xenon redistribution during this short interval will not cause a significant increase in LHR. Moving the remainder of the group to meet Required Action A.1 is not allowed if a safety rod is misaligned, since the limits of LCO 3.1.5, "Safety Rod Insertion Limits," would be violated.

A.2.1.1 and A.2.1.2 If realignment of the CONTROL ROD to the group average or alignment of the group to the misaligned CONTROL ROD cannot be completed within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , SDM must be evaluated. Ensuring the SDM meets the minimum requirement within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is adequate to determine that further degradation of the SDM is

r* not occurring.

not within the limits specified If SDM i <--% A k/k-, RCS boration must occur as described intheCOLR, in the Bases for Specification 3.1.1. Increasing the RCS boron concentration will restore SDM to within limit and is necessary since the CONTROL ROD may remain misaligned and not be providing its normal negative reactivity on tripping.

The Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months to initiate boration is reasonable, based on the time required for potential xenon redistribution, the low probability of an accident occurring, and the steps required to complete the action.

This allows the operator sufficient time for aligning the chosen boration source injection. Boration will continue until the required SDM is restored.

(continued)

Crystal River Unit 3 B 3.1-21 Amendment No. 149

CONTROL ROD Group Alignment Limits B 3.1.4 BASES ACTIONS A.2.2, A.2.3, A.2.4, and A.2.5 (continued)

Reduction of THERMAL POWER to

60% of the ALLOWABLE THERMAL POWER ensures that local LHR, due to a misaligned rod, will not cause the core design criteria to be exceeded. The Completion Time of 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months allows the operator sufficient time for reducing THERMAL POWER.

Reduction of the nuclear overpower trip setpoint to

70% of the ALLOWABLE THERMAL POWER, after THERMAL POWER has been reduced to 60% of the ALLOWABLE THERMAL POWER, maintains both core protection and an operating margin at reduced power similar to that at RTP. The Completion Time of 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months allows a minimum of 8 additional hours after completion of the THERMAL POWER reduction in Required Action A.2.2 to adjust the trip setpoin LIt__e n 3 The existing CONTROL ROD configuration must be evaluated to verify the potential ejected rod worth *\swithin the assumption of the rod ejection analysis. The*r-od--wot*

d for -hi,"&&u-m aci-dent-ar 5-% o---R-T-P--,--

k-pekra(Ref. 51)*. This evaluation may require a computer calculation of the maximum ejected rod worth based on nonstandard configurations of the CONTROL ROD groups.

The evaluation must determine the ejected rod worth for the remainder of the fuel cycle to ensure a valid evaluation.

Should fuel cycle conditions at some later time become more bounding than those at the time of the rod misalignment this verification should be reviewed to ensure its continued validity. The Completion Time of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is acceptable because LHRs are limited by the THERMAL POWER reduction and sufficient time is provided to perform the required evaluation.

Performance of SR 3.2.5.1 provides a determination of the power peaking factors using the Incore Detector System.

Verification of FQ(Z) and FN from an incore power AH distribution map ensures that excessive local LHRs will not occur due to CONTROL ROD misalignment. This is necessary because the assumption that all CONTROL RODS are aligned (used to determine the regulating rod insertion, AXIAL POWER IMBALANCE, and QPT limits and bound power peaking limits) is not valid when the CONTROL RODS are not aligned. The Completion Time of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is acceptable because LHRs are limited by the THERMAL POWER reduction. The Frequency also allows adequate time to obtain an incore power distribution map.

(continued)

Crystal River Unit 3 B 3.1-22 Amendment No. 149

CONTROL ROD Group Alignment Limits B 3.1.4 BASES ACTIONS B.1 (continued)

With the Required Action and associated Completion Time for Condition A not met, the plant must be placed in a MODE in which the LCO does not apply. To achieve this status, the plant must be placed in at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The allowed Completion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is reasonable, based on operating experience, for reaching MODE 3 from full power conditions in an orderly manner and without challenging plant systems.

C.1.1, C.1.2, and C.2 More than one trippable CONTROL ROD inoperable or not aligned within 6.5% of their group average position, or both, may potentially violate the minimum SDM requirement.

Therefore, SDM must be evaluated. Ensuring the SDM meets the minimum requirement within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months allows the operator notwithinthe adequate time to determine the SDM.

limits specified If SDM i --

k< A kA/-- RCS boration must occur as described intheCOLR, in Bases Section 3.1.1. Increasing the RCS boron concentration provides negative reactivity. The Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months for initiating boration is reasonable, based on the time required for potential xenon redistribution, the low probability of an accident occurring, and the steps required to complete the action. This allows the operator sufficient time for aligning the chosen boration source and beginning injection. Boration will continue until the required SDM is restored.

Continued operation of the reactor in this condition may cause the misalignment to increase, as the regulating rods insert or withdraw to control reactivity. If the CONTROL ROD misalignment increases, local power peaking may also increase, and local LHRs will also increase if the reactor continues operation at THERMAL POWER. The SDM is decreased when one or more CONTROL RODS become inoperable at a given THERMAL POWER level, or if one or more CONTROL RODS become misaligned by insertion from the group average position.

Therefore, it is prudent to place the reactor in MODE 3.

The allowed Completion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is reasonable, based on operating experience, for reaching MODE 3 from full power conditions in an orderly manner and without challenging plant systems.

(continued)

Crystal River Unit 3 B 3.1-23 Amendment No. 149

PHYSICS TESTS Exceptions-MODE 1 B 3.1.8 BASES APPLICABLE This is acceptable as long as the fuel design criteria are SAFETY ANALYSES not violated. When one or more of the limits specified in:

(continued)

LCO 3.1.4, "CONTROL ROD Group Alignment Limits";

LCO 3.1.5, "Safety Rod Insertion Limits";

LCO 3.1.6, "AXIAL POWER SHAPING ROD (APSR) Alignment Limits";

LCO 3.2.1, "Regulating Rod Insertion Limits," for the restricted operation region only; LCO 3.2.3, "AXIAL POWER IMBALANCE Operating Limits"; or LCO 3.2.4, "QUADRANT POWER TILT (QPT)"

are suspended for PHYSICS TESTS, the fuel design criteria are preserved by maintaining the nuclear hot channel factors within their limits, maintaining ejected rod worth within limits by restricting regulating rod insertion to within the acceptable operating region or the restricted operating region, by limiting maximum THERMAL POWER, resetting the nuclear overpower trip setpoint and by maintaining SDM 2! 1. 0 A4fk-. Therefore, surveillance of FQ(Z), FN , and SDM specified within the in the limits AH COLR. is required to verify that their limits are not exceeded.

The limits for the nuclear hot channel factors are specified in the COLR. Refer to the Bases for LCO 3.2.5 for a complete discussion of FQ(Z) and FN

During PHYSICS TESTS, AH one or more of the LCOs that normally preserve the FQ(Z) and FNAH limits may be suspended. However, the results of the safety analysis are not adversely impacted if verification that FQ(Z) and FN are within their limits is obtained, AH while one or more of the LCOs is suspended. Therefore, SRs are placed on FQ(Z) and FNA*H during MODE 1 PHYSICS TESTS to verify that these factors remain within their limits.

Periodic verification of these factors allows PHYSICS TESTS to be conducted while continuing to maintain the design criteria.

PHYSICS TESTS include measurement of core nuclear parameters and exercise of control components that affect process variables. Among the process variables involved are AXIAL POWER IMBALANCE and QPT, which represent initial condition input (power peaking) for the accident analysis. Also involved are the movable control components, i.e., the regulating rods and the APSRs, which affect power peaking and shutdown of the reactor. The limits for these variables are specified for each fuel cycle in the COLR.

(continued)

Crystal River Unit 3 B 3.1-42 Amendment No. 149

PHYSICS TESTS Exceptions-MODE 1 B 3.1.8 BASES APPLICABLE PHYSICS TESTS satisfy Criteria 2 and 3 of the NRC Policy SAFETY ANALYSES Statement.

(continued)

LCO This LCO permits individual CONTROL RODS to be positioned outside of their specified group alignment and withdrawal limits and to be assigned to other than specified CONTROL ROD groups, and permits AXIAL POWER IMBALANCE and QPT limits to be exceeded during the performance of PHYSICS TESTS. In addition, this LCO permits verification of the fundamental core characteristics and nuclear instrumentation operation.

The requirements of LCO 3.1.4, LCO 3.1.5, LCO 3.1.6, LCO 3.2.1 (for the restricted operation region only),

LCO 3.2.3, and LCO 3.2.4 may be suspended during the performance of MODE 1 PHYSICS TESTS provided:

a. THERMAL POWER is maintained

85% RTP;

b. Nuclear overpower trip setpoint on the nuclear power range channels is : 10% RTP higher than the THERMAL POWER at which the test is performed, with a maximum setting of 90% RTP;

c. FQ(Z) and FN are maintained within the limits HAH specified in the COLR; and within the limits dspecified in the

d. SDM is maintained : -&% Wk-kk' COLR Operation with THERMAL POWER

85% RTP during PHYSICS TESTS provides an acceptable thermal margin when one or more of the applicable LCOs is out of specification. Eighty-five percent RTP is consistent with the maximum power level for conducting the intermediate core power distribution test specified in Reference 1. The nuclear overpower trip setpoint is reduced so that a similar margin exists between the steady state condition and trip setpoint as exists during normal operation at RTP.

(continued)

Crystal River Unit 3 B 3. 1-43 Amendment No. 149

PHYSICS TESTS Exceptions-MODE 2 B 3.1.9 BASES APPLICABLE LCO 3.4.2, "RCS Minimum Temperature for Criticality."

SAFETY ANALYSES (continued) Even if an accident occurs during PHYSICS TESTS with one or more LCOs suspended, fuel damage criteria are preserved because the limits on THERMAL POWER and shutdown capability are maintained during the PHYSICS TESTS.

Shutdown capability is preserved by limiting maximum obtainable THERMAL POWER and maintaining adequate SDM, while invoking MODE 2 PHYSICS TESTS exceptions.

PHYSICS TESTS include measurement of core nuclear parameters or exercise of control components that affect process variables.

PHYSICS TESTS satisfy Criteria 2 and 3 of the NRC Policy Statement.

LCO This LCO permits individual CONTROL RODS to be positioned outside of their specified group alignment and withdrawal limits and to be assigned to other than specified CONTROL ROD groups during the performance of PHYSICS TESTS. In addition, this LCO permits verification of the fundamental core characteristics.

This LCO also allows suspension of LCO 3.1.3, LCO 3.1.4, LCO 3.1.5, LCO 3.1.6, LCO 3.2.1, and LCO 3.4.2, provided:

a. THERMAL POWER is < 5% RTP;

b. Nuclear overpower trip setpoints on the nuclear power range channels are set to < 25% RTP; and within the limits C. SDM i*s mai ntaioned Ao0(e in theespecified COLR APPLICABILITY This LCO is applicable in MODE 2 when the reactor is either sub-critical or THERMAL POWER is _< 5% RTP. This LCO is applicable for initial criticality or low power testing, as defined by Regulatory Guide 1.68 (Ref. 4). In MODE 1, (continued)

Crystal River Unit 3 B 3. 1-49 Amendment No. 149

Regulating Rod Insertion Limits B 3.2.1 BASES BACKGROUND LCO 3.2.1, "Regulating Rod Insertion Limits," LCO 3.2.2, (continued) "AXIAL POWER SHAPING ROD (APSR) Insertion Limits,"

LCO 3.2.3, "AXIAL POWER IMBALANCE Operating Limits," and LCO 3.2.4, "QUADRANT POWER TILT (QPT)," provide limits on control component operation and on monitored process variables to ensure that the core operates within the F,(Z) and FN limits in the COLR. Operation within the F,(Z)

AH limits given in the COLR prevents power peaks that would exceed the loss of coolant accident (LOCA) limits derived from the analysis of the Emergency Core Cool ing Systems (ECCS). Operation within the FN limits given in the COLR AH prevents departure from nucleate boiling (DNB) during a loss of forced reactor coolant flow accident. In addition to the F0 (Z) and F N limits, certain reactivity limits are met by AH regulating rod insertion limits. The regulating rod insertion limits also restrict the ejected CONTROL ROD worth to the values assumed in the safety analysis and maintain the minimum required SDM in MODES 1 and 2.

This LCO is required to minimize fuel cladding failures that breach the primary fission product barrier and release fission products into the reactor coolant in the event of a LOCA, loss of flow accident, ejected rod accident, or other postulated accidents requiring termination by a Reactor Protection System trip function.

APPLICABLE The fuel cladding must not sustain damage as a result of SAFETY ANALYSES normal operation (Condition I) or anticipated operational occurrences (Condition II). The LCOs governing regulating rod insertion, APSR position, AXIAL POWER IMBALANCE, and QPT preclude core power distributions that violate the following fuel design criteria:

a. During a large break LOCA, the peak cladding temperature must not exceed 2200'F (Ref. 2);

b. During a loss of forced reactor coolant flow accident, there must be at least 95% probability at the 95%

confidence level (the 95/95 DNB criterion) that the hot fuel rod in the core does not experience a DNB condition (Refs. 7 and 8); and coolability limits for the fuel cladding must not be c. During an ejected rod accident*, t-&-f-ueA-entha~py-must exceeded. not--e-eeed-2-8--ea--gm (Ref. 3).

(continued)

Crystal River Unit 3 B 3.2-2 Revision No. 45

APSR Insertion Limits B 3.2.2 BASES APPLICABLE The fuel cladding must not sustain damage as a result of SAFETY ANALYSES normal operation (Condition I) or anticipated operational occurrences (Condition II). Acceptance criteria for the safety and regulating rod insertion, APSR position, AXIAL POWER IMBALANCE, and QPT LCOs preclude core power distributions that violate the following fuel design criteria:

a. During a large break LOCA, the peak cladding temperature must not exceed 2200'F (Ref. 2);

b. During a loss of forced reactor coolant flow accident, there must be at least 95% probability at the 95%

confidence level (the 95/95 DNB criterion) that the hot fuel rod in the core does not experience a DNB condition (Refs. 4 and 5); and C. During an ejected rod accident,-the-fue+-ent-h**-4--must limits

=coolability fuel cladding must the be!

for not net-e*eeed-2-80-ea /gm (Ref. 3).

exceeded.

Fuel cladding damage does not occur when the core is operated outside these LCOs during normal operation.

However, fuel cladding damage could result should an accident occur simultaneously with violation of one or more of these LCOs. This potential for fuel cladding damage exists because changes in the power distribution can cause increased power peaking and corresponding increased local linear heat rates.

Operation at the APSR insertion limits may approach the maximum allowable linear heat generation rate or peaking factor with the allowed QPT present.

The APSR insertion limits satisfy Criterion 2 of the NRC Policy Statement.

LCO The limits on APSR physical insertion as defined in the COLR must be maintained because they serve the function of controlling the power distribution within an acceptable range.

Measurement system-independent limits for APSR insertion are provided in the COLR. Measurement system-dependent maximum allowable setpoints are derived by adjustment of the measurement system-independent limits to allow for THERMAL POWER level uncertainty and rod position errors.

(continued)

Crystal River Unit 3 B 3.2-12 Revision No. 45

RPS Instrumentation B 3.3.1 BASES APPLICABLE 4. RCS Low Pressure (continued)

SAFETY ANALYSES, LCO, and conditions necessary for DNB. The RCS Low Pressure APPLICABILITY setpoint Allowable Value is selected to ensure that a reactor trip occurs before RCS pressure is reduced below the lowest point at which the RCS Variable Low Pressure trip is analyzed. The RCS Low Pressure trip provides protection for Primary system depressurization events and is credited in the accident analysis calculations for small break loss of coolant accidents (SBLOCAs). Consequently, harsh RB conditions created as a result of SBLOCAs can potentially affect performance of the RCS pressure sensors and transmitters. Therefore, degraded environmental conditions are considered in the Allowable Value determination.

5. RCS Variable Low Pressure The RCS Variable Low Pressure trip, in conjunction with the RCS High Outlet Temperature and RCS Low Pressure trips, provide protection for the DNBR SL.

The Allowable Value is selected such that a trip is initiated whenever RCS pressure and temperature approach the conditions necessary for DNB. The RCS Variable Low Pressure trip provides a varying low pressure trip based on the RCS High Outlet Temperature within the range specified by the RCS High Outlet Temperature and RCS Low Pressure trips.

The RCS Variable Low Pressure trip i credited in for the Control =RodtesatyaV71t&p#rinoth ciet:; *jcion tte safet-y a-n-ay-s-i-s- theref-er-e, deter6 f'acon of the EjectionAccident; setpoint Allowable Value does not account for errors induced by a harsh RB environmenT

6. Reactor Building High Pressure linLce LIte LIIp Will dLacUdLt prior to degraded The Reactor Building High Pressure trip provides an environmental conditions early indication of a high energy line break (HELB) are reached inside the RB. By detecting changes in the RB pressure, the RPS can provide a reactor trip before the other RCS parameters have varied significantly; thus, minimizing accident consequences. This trip Function also provides a backup to RPS trip strings exposed to an RB HELB environment.

(continued)

Crystal River Unit 3 B 3. 3-14 Revision No. 22

RPS Instrumentation B 3.3.1 BASES ACTIONS H.1 (continued)

If the Required Action and associated Completion Time of Condition A or B are not met and Table 3.3.1-1 directs entry into Condition H, the plant must be placed in a MODE in which the specified RPS trip Function is not required to be OPERABLE. To achieve this status, THERMAL POWER must be reduced < 45% RTP. The allowed Completion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is reasonable, based on operating experience, to reach 45% RTP from full power conditions in an orderly manner without challenging plant systems.

1.1 If the Required Action and associated Completion Time of Condition A or B are not met and Table 3.3.1-1 directs entry into Condition I, the plant must be placed in a MODE in which the specified RPS trip Function is not required to be OPERABLE. To achieve this status, THERMAL POWER must be reduced < 20% RTP. The allowed Completion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is reasonable, based on operating experience, to reach 20% RTP from full power conditions in an orderly manner without challenging plant systems.

3014 J.1 and 3.2 If the required high accuracy secondary heat balan e instrumentation is not available, neither the Nuc ear Overpower - High Setpoint Allowable Value of 104 % RTP in Table 3.3.1-1, nor a nominal power level of 2-6G0 MWt will support extended operation. The Nuclear Overpower - High Setpoint and the appropriate reactor power ensure actuation of the RPS prior to the power level assumed in the accident analysis. Therefore, Condition J must be entered.

Condition J reduces reactor thermal power to 2-5-68 MWt within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and requires the selection of an In-Plank St associated with an Allowable Value of 103.3% RTP. *_42965 The Allowable Values for the Nuclear Overpower - High Setpoint MWt. are given in Table 3.3.1-1 for 2-6O9 d MWt and 2-5%68 s~

The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and 48 hour5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months timeframes are adequate because overpower trip is not directly dependent on the high accuracy secondary heat balance instrumentation. The secondary heat balance is used to assure the nuclear instrumentation is adjusted as needed to the appropriate thermal power level every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months per SR 3.3.1.2. Failure (continued)

Crystal River Unit 3 B 3.3-25 Revision No. 70

RPS Instrumentation B 3.3.1 BASES APPLICABLE 11. Shutdown Bypass RCS High Pressure (continued)

SAFETY ANALYSES, LCO, and 7. Reactor Coolant Pump Over/Under Power; and APPLICABILITY

8. Nuclear Overpower RCS Flow and Measured AXIAL POWER IMBALANCE.

Functions 1, 4, 5, 7, and 8 may be bypassed in MODE 2 or below (higher numerical MODE) when RCS pressure is below 1820 psig, provided the Shutdown Bypass RCS High Pressure and the Nuclear Overpower-Low setpoint trip are placed in operation. Under these conditions, the Shutdown Bypass RCS High Pressure trip and the Nuclear Overpower-Low setpoint trip prevent conditions from reaching a point where actuation of these Functions is necessary.

Two other Functions are required to be OPERABLE during portions of MODE 1. These are the Main Turbine Trip (Control Oil Pressure) and the Loss of Main Feedwater Pumps Reference 5 (Control Oil Pressure) trip. These Functions are required to be OPERABLE above \5% RTP and 20% RTP, respectively.

Analyses presented in AW-e1893-- showed that for operation below these power levels, these trips are not necessary to minimize challenges to the PORVs as required by NUREG-0737 (Ref. 4).

Because the only safety function of the RPS is to interrupt power to the CONTROL RODS, the RPS is not required to be OPERABLE in MODE 3, 4, or 5 if the reactor trip breakers are open, or the CRDCS is incapable of rod withdrawal.

Similarly, the RPS is not required to be OPERABLE in MODE 6 when the CONTROL RODS are decoupled from the CRDs. However, in MODE 2, 3, 4, or 5, the Shutdown Bypass RCS High Pressure and Nuclear Overpower-Low Setpoint trip Functions are required to be OPERABLE if the CRD trip breakers are closed and the CRDCS is capable of rod withdrawal. Under these conditions, the Shutdown Bypass RCS High Pressure and Nuclear Overpower-Low setpoint trips are sufficient to prevent an approach to conditions that could challenge SLs.

(continued)

Crystal River Unit 3 B 3. 3-21 Amendment No. 178

RPS Instrumentation B 3.3.1 BASES asmto f32.

ACTIONS J.1 and J.2 (continued) or unavailability of the required high accuraa instrumentation has no impact on the reactor rip setpoint 2965 *nuclear instrumentation indic tion of reactor power. Lowering p6--r-tr-2-S-68 MWt enables the alternate secondary heat balance instrumentation (2 accuracy) to ensure the plant is maintained below 26-19 MWt. If the required high accuracy secondary heat balance instrumentation remains unavailable, an In-Plant Setpoint associated with a 103.3% of RTP Allowable Value must be established. The 48 hour5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months Completion Time period is acceptable because of the low probability of significant drift of the nuclear instrumentation indication or setpoint in that short time period. The 12 and 48 hour5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months time periods provide adequate time to either restore the required equipment or take the Required Actions in an orderly manner.

These completion times are to allow for orderly reactivity control and work management.

K.1 and K.2 If the Required Action and associated Completion Time of Condition I are not met, the plant must be placed in a MODE in which the specified RPS trip Functions are not required to be OPERABLE. The allowed Completion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and to open the CRD trip breakers without challenging plant systems.

SURVEILLANCE The SRs are modified by a note indicating the SR required REQUIREMENTS for each RPS Function are identified by the SRs column of Table 3.3.1-1. Most Functions are subject to CHANNEL CHECK, CHANNEL FUNCTIONAL TEST, and CHANNEL CALIBRATION, with those credited in the accident analysis also requiring RPS RESPONSE TIME testing.

Table 3.3.1-1 has footnotes d and e that describe the conditions for selecting which Allowable Value for the Nuclear Overpower - High Trip setpoint is appropriate.

Additionally, footnotes f and g are applicable to the Nuclear Overpower-High Trip setpoint as the associated pre-established In-Plant Setpoint is a Limiting Safety System Setting (LSSS).

SR 3.3.1.5 is modified by 2 footnotes as identified in Table 3.3.1-1. The first footnote requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable (continued)

Crystal River Unit 3 B 3. 3-26 Revision No. 70

RPS Instrumentation B 3.3.1 BASES SURVEILLANCE SR 3.3.1.1 (continued)

REQUIREMENTS Acceptance criteria for the CHANNEL CHECK are determined by the plant staff and presented in the Surveillance Procedure.

The criteria may consider, but is not limited to channel instrument uncertainties, including isolation, indication, and readability. If a channel is outside the acceptance criteria, it may be an indication that the transmitter or the signal processing equipment has excessively drifted. If the channels are within the acceptance criteria, it is an indication that the channels are OPERABLE.

The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is based on operating experience that demonstrates channel failure is an infrequent occurrence.

SR 3.3.1.2 This surveillance is modified by a Note that states that the surveillance is required to be performed with the required high accuracy secondary heat balance instrumentation unless Condition J has been entered, in which case the nozzle based heat balance can be used. Condition J has requirements for lowering power to 2-*&8 MWt and resetting the Nuclear Overpower - High Setp nt when the required high accuracy instrumentation is unav ilable as input into the secondary heat balance calculation.\ 2 SR 3.3.1.2 is a secondary heat balance comparison to the power range nuclear instrumentation channels. The heat balance is performed once every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months when reactor power is > 15%

RTP and consists of a comparison of the results of the calorimetric with each power range channel output. The outputs of the power range channels are normalized to the calorimetric. If the calorimetric exceeds the NI channel output by > 2% RTP, the NI must be adjusted. In this Condition, the trip Functions which receive an input from the NI are not considered inoperable provided the channel is adjusted to within the limit. A Note clarifies that this Surveillance is required only when reactor power is > 15%

RTP and that 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is allowed for performing the first Surveillance after reaching 15% RTP. This SR 3.0.4 type allowance is provided since at lower power levels, calorimetric comparison data tends to be more variable and the RPS trip is ensured prior to 2-0G9 Wt. 3014 The power range channel's output must be adjusted consistent with the calorimetric results if the calorimetric exceeds the power range channel's output by > 2% RTP. The value of (continued)

Crystal River Unit 3 B 3. 3-28 Revision No. 70

RPS Instrumentation B 3.3.1 BASES SURVEILLANCE SR 3.3.1.2 (continued)

REQUIREMENTS 2% is consistent with the value assumed in the safety analyses of FSAR, Chapter 14 (Ref. 2) accidents. These checks and, if necessary, the adjustment of the power range channels ensure that channel accuracy is maintained within the error margins assumed in the analysis. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is adequate, based on plant operating experience, which demonstrates the change in the difference between the power range indication and the calorimetric results rarely exceeds a small fraction of 2% in any 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months period.

Furthermore, the control room operators monitor redundant indications and alarms to detect deviations in channel outputs.

Operation at CO9 MWt (100% RTP) requires that this surveillance be performed with the required high accuracy secondary heat balance instrumentation (0.4% accuracy). If the required high accuracy secondary heat balance instrumentation is unavailable, this surveillance must be performed using alternative heat balance instrumentation (2.0% accuracy) at 2S68 MWt.

SR 3.3.1.3 A comparison of power range nuclear instrumentation channels (excores) against incore detectors shall be performed at a 31 day Frequency when reactor power is > 30% RTP. A Note clarifies that 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is allowed for performing the first Surveillance after reaching 30% RTP. If the absolute difference between the power range and incore measurements is > 2.5% RTP, the trip Functions which receive an input from the NI are not considered inoperable, but a CHANNEL CALIBRATION that adjusts the measured imbalance to agree with the incore measurements is necessary. If the power range channel cannot be properly recalibrated, the channel is declared inoperable. The calculation of the Allowable Value envelope assumes a difference in out of core to incore measurements of 2.5%. Additional inaccuracies beyond those that are measured are also included in the setpoint envelope calculation. The 31 day Frequency is adequate, considering that long term drift of the excore linear amplifiers is small and depletion of the detectors is slow. Also, the excore readings are a strong function of the power produced in the peripheral fuel bundles, and do not represent an integrated reading across the core. The slow changes in neutron flux during the fuel cycle can also be detected at this interval.

(continued)

Crystal River Unit 3 B 3. 3-29 Revision No. 70

RPS Instrumentation B 3.3.1 BASES SURVEILLANCE SR 3.3.1.6 (continued)

REQUIREMENTS A Note to the Surveillance indicates that neutron detectors and RCPPM current and voltage sensors are excluded from CHANNEL CALIBRATION. In the case of the neutron detectors, this Note is necessary because of the difficulty in generating an appropriate detector input signal. Excluding the detectors is acceptable because the principles of detector operation ensure a virtually instantaneous response. RCPPM current and voltage sensors are excluded due to the fact no adjustments can be made to these sensors.

SR 3.3.1.7 This SR verifies individual channel actuation response times are less than or equal to the maximum values assumed in the accident analysis. Individual component response times are not modeled in the analyses. The analyses model the overall, or total, elapsed time from the point at which the parameter exceeds the analytical limit at the sensor to the point of rod insertion. Response time testing acceptance criteria are included in Reference 1.

A Note to the Surveillance indicates that neutron detectors and RCPPM current and voltage sensors and the watt transducer are excluded from RPS RESPONSE TIME testing. This Note is necessary because of the difficulty in generating an appropriate detector input signal. Excluding the detectors is acceptable because the principles of detector operation ensure a virtually instantaneous response.

Response time tests are conducted on an 24 month STAGGERED TEST BASIS. This results in testing all four RPS channels every 96 months. The 96 month Frequency is based on operating experience, which shows that random failures of instrumentation components causing serious response time degradation, but not channel failure, are infrequent occurrences.

REFERENCES 1. FSAR, Chapter 7.

2. FSAR, Chapter 14.

3. 10 CFR 50.49.

4. NUREG-0737, November 1979.

Rt BAW--89-3.

6. NRC SER for BAW-10167, Supplement 2, July 8, 1992.

7. NRC SER for BAW-10167A and Supplement 1, December 5, 1988.

8. Amendment No. 56 to the CR-3 Technical Specifications, dated July 16, 1982.

9. Amendment No. 152 to the CR-3 Technical Specifications, dated February 13, 1996.

Crystal River Unit 3 B 3.3-31 Revision No. 70

ESAS Instrumentation B 3.3.5 BASES APPLICABLE Accident analyses rely on automatic ESAS actuation for SAFETY ANALYSES protection of the core temperature and containment pressure limits and for limiting off site dose levels following an accident. These include LOCA, SLB, and feedwater line break events that result in RCS inventory reduction or severe loss of RCS cooling.

The following ESAS Functions are assumed to operate to mitigate design basis accidents.

High Pressure Injection The ESAS actuation of HPI has been assumed for core cooling in the small break LOCA analysis and is credited in the SLB analysis for the purposes of adding boron and negative reactivity. HPI is also credited in the Steam Generator Tube Rupture (SGTR) accident analysis.

Manual actuation of HPI may be relied upon whenever ESAS signal are bypassed during heatup or cooldown, or when in Mode 4.

Low Pressure Injection The ESAS actuation of LPI has been assumed for large break LOCAs.

Manual actuation of HPI may be relied upon whenever ESAS signal are bypassed during heatup or cooldown, or when in Mode 4.

Reactor Building Spray, Reactor Building Cooling, and Reactor Building Isolation ESAS actuation of the RB coolers and RB Spray is credited in RB analysis for LOCAs, both for RB performance and equipment environmental qualification pressure and temperature Specifically for the LOCA envelope definition. Accident dose calculations credit RB dose analysis, the mini-purge Isolation and RB Spray*. 1 valves are assumed to close Emergency Diesel Generator Start within 5 seconds.

The ESAS initiated EDG Start has been assumed in the LOCA analysis to ensure that emergency power is available throughout the limiting LOCA scenarios.

The large break LOCA analyses assume a conservative 35 second delay time for the actuation of LPI in FSAR, Chapter 6, (Ref. 3). The small break LOCA analyses assume a conservative 67 second delay time for the actuation of HPI.

(continued)

Crystal River Unit 3 B 3. 3-48 Revision No. 22

ESAS Instrumentation B 3.3.5 BASES APPLICABLE Emergency Diesel Generator Start (continued)

SAFETY ANALYSES These delay times include allowances for EDG starting, EDG output breaker closure, EDG voltage recovery, EDG loading, Emergency Core Cooling Systems (ECCS) pump starts, and valve openings. Similarly, RB Isolation and Cooling, and RB Spray have been analyzed with delays appropriate for the entire system analyzed. Values used in the analysis are 25 seconds for RB Cooling, 60 seconds for RB Isolation, and 90 seconds for RB Spray.

ESAS instrumentation channels satisfy Criterion 3 of the NRC Policy Statement.

_________... except mini purge lines, 5 seconds for RB mini purge lines...

LCO The LCO requires the specified ESAS instrumentation for each Parameter in Table 3.3.5-1 to be OPERABLE. Failure of any instrument renders the affected channel inoperable and reduces the margin to meeting the single failure criteria for the affected Functions.

Three channels of RCS Pressure ESAS instrumentation and two channels of ESAS RB pressure instrumentation in each actuation train shall be OPERABLE to ensure that a single failure in one channel will not result in loss of the ability to automatically actuate the required safety function.

The bases for the LCO on ESAS Parameters include the following.

Reactor Coolant System Pressure Three channels each of RCS Pressure-Low and RCS Pressure-Low-Low are required to be OPERABLE. Each channel includes a sensor, trip bistable, bypass bistable, bypass relays, and bistable trip auxiliary relays. In addition, each RCS Pressure-Low channel also includes time delay auxiliary relays. The analog portion of each pressure channel is common to both trains of both RCS Pressure Parameters. Therefore, failure of one analog channel renders one channel of the low pressure and low low pressure Functions in each train inoperable. The bistable portions of the channels are Function and train specific.

(continued)

Crystal River Unit 3 B 3.3-49 Revision No. 23

Source Range Neutron Flux B 3.3.9 BASES (continued)

ACTIONS A.1 With one channel of the source range neutron flux indication inoperable, any action to increase reactor power must be suspended until the channel is restored to OPERABLE status.

This Action restricts THERMAL POWER increases in a range of operation where the source range instrumentation are the primary means of neutron power level indication.

Furthermore, it ensures that power remains below the point where the intermediate range channels come on-scale until both source range channels are available to support the overlap verification required by SR 3.3.9.3. This ensures a transition from one monitoring instrument to another of different range with the reactivity conditions on both sides of the core known.

B.1, B.2, B.3, and B.4 With both source range neutron flux channels inoperable, action is required to preclude increases in neutron count rate requiring source range monitoring capability. This is accomplished by immediately suspending positive reactivity additions and initiating action to insert all CONTROL RODS, and opening the CONTROL ROD driv tyithin 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . Periodic SDM verificatio (-of _ % Ak-/-k ýs then required to provide a means for dpet-R&

reactivity changes that could be caused by mechanisms other than CONTROL ROD withdrawal or positive reactivity insertions. Since the source range instrumentation provides the primary indication of power in this plant operating condition, the verification of SDM must continue every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months until at least one channel of source range instrumentation is returned to OPERABLE status. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time for Required Action B.3 and Required Action B.4 are based upon providing sufficient time to accomplish the actions. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency for performing the SDM verification is considered adequate to detect any reactivity changes which do occur before SDM limits are approached.

(continued)

Crystal River Unit 3 B 3. 3-75 Revision No. 7

EFIC Instrumentation B 3.3.11 BASES BACKGROUND circulation. This initiation, utilizing the RPS signal for (continued) reactor coolant pump (RCP) status, ensures EFW is available to automatically raise OTSG levels to natural circulation cooling. Finally, EFIC initiates EFW when an actuation is received on HPI Channel A and B. This ensures EFW is available under the worst-case, small break loss of coolant wetting of tubes near and below the EFW discharge nozzles MonitoringSystem (ICCMS) are necessary for primary to secondary heat transfer. If will automatically initiate and adequate ubcooling margin is lost, t-he-e-rat&r-aemu-s-send a signal to the EFIC ma-nu-a]l-ly select the inadequate subcooling margin setpoint e t-so-$.ee~ FIC will ea- automatically raise levels to this

Requirements associated with _poin the ICCMS instrumentation EFIC also isolates main steam and MFW to an OTSG that has and automatic actuation logic lost pressure control. With the loss of pressure control, are provided in LCO 3.3.19, temperature control is also lost and the heat removal rate "Inadequate Core Cooling becomes excessive. Main steam and MFW are isolated to the Monitoring System (ICCMS) affected OTSG when steam pressure reaches a low setpoint, a Instrumentation," and LCO condition which is well below the normal operating pressure 3.3.20, "Inadequate Core of the secondary system.

Cooling Monitoring System (ICCMS) Automatic Actuation EFIC also performs an EFW control function to avoid Logic." delivering EFW to a depressurized OTSG when the other OTSG remains pressurized. This feed-only-the-good-generator (FOGG) logic is consistent with the design goal of isolating functional components whose pressure cannot be controlled.

FOGG logic precludes delivery of emergency feedwater to a depressurized OTSG, thereby preventing an uncontrolled cooldown as long as the other OTSG remains pressurized.

When both OTSGs are depressurized, the EFIC logic provides EFW flow to both OTSGs until a significant pressure difference develops between the two, thereby ensuring that core cooling is maintained.

Each EFW actuation logic train actuates on a one-out-of-two taken twice combination of trip signals from the instrumentation channels. Each EFIC channel can issue an initiate command, but an EFIC actuation will take place only if at least two channels issue initiate commands. The one-out-of-two taken twice logic combinations are transposed between trains so that failure of two channels prevents actuation of, at most, one train of EFW.

More detailed descriptions of the EFIC instrumentation are provided next.

(continued)

Crystal River Unit 3 B 3. 3-83 Revision No. 83

EFIC Instrumentation B 3.3.11 BASES BACKGROUND d. RCP Status (continued)

A loss of power to all four RCPs is an immediate indication of a pending loss of forced flow in the Reactor Coolant System. The RPS acts as the sensor for this EFIC Function by providing a loss of RCP indication for each pump to each EFIC channel.

When a minimum of two EFIC channels recognize the loss of all RCPs, EFIC will automatically actuate EFW and control level to natural circulation value in the OTSG. This higher setpoint provides a thermal center in the OTSG at a higher elevation than that of the reactor to ensure natural circulation as long as adequate subcooling margin is maintained.

To allow RCS heatup and cooldown without actuation, a bypass permissive of 10% RTP is used. The 10% bypass permissive was chosen because it was an available, qualified Class 1E signal at the time the EFIC System was designed.

When the first RCP is started, the "loss of four RCPs" initiation signal may be manually reset.

If the bypass is not manually reset, it will be automatically reset at 10% RTP. During cooldown, the bypass may be inserted at any time THERMAL POWER has been reduced below 10%. However, for most operating conditions, it is recommended that this trip function remain active until after the Decay Heat Removal System has been placed in operation and just prior to tripping the last RCP. This trip function must be bypassed prior to stopping the last RCP in order to avoid an EFW actuation.

(continued)

Crystal River Unit 3 B 3.3-86 Revision No. 17

EFIC Instrumentation B 3.3.11 BASES APPLICABLE 1. EFW Initiation (continued)

SAFETY ANALYSES evaluation of this event. If the loss of feedwater is a direct result of a loss of the MFW pumps, EFW will be actuated much earlier than assumed in the analysis. This would increase OTSG heat transfer capability sooner in the event and would lessen the severity of the transient.

OTSG Pressure-Low is a primary indication and provides the actuation signal for SLBs or MFW line breaks.

Only one of the four SLB cases examined in the FSAR assumes normal automatic actuation of EFW. The other three cases assume manual initiation after 15 minutes.

For small breaks, which do not depressurize the OTSG or take a long time to depressurize, automatic actuation is not required. The operator has sufficient time to diagnose the problem and take the appropriate actions.

Loss of four RCPS is a primary indicator of the need for EFW in the Safety analyses for loss of electric power and loss of coolant flow.

2. EFW Vector Valve Control T-h4-s-4s-doeumetc in AREg i inicrn-n-f Re~ed-541-a-14-1OO0R-3-ROSG&--- u pp 1t-L , -t-ed ze-edw-a-t-ef-an-d-M-a4-Th-Stam were crdit -- h-ed-O-Geed Gene -~ate-(OC) ogc a aSO credited for t-e-rPm-en--~-eR-oan-eoverfeed conditioen for e ,thcr IS d-k+Fr-ng-p0&--t-Li-Va-ted-DC-ewer a-i4tAw-e-s--

3, 4. Main Steam Line and MFW Isolation Insert B 3.3.11-2 b-4-1-i-t" i-f--sy-s-tems-a-nd-t-h ei---seiate-r er-se-t+me&-s Th is45*---doE)-u mc-nAed-A4r"REVA-E-ngi-n~ee-i4ng-4Inf&r-ma-t-ion Rege-pd--491 f108715 00C Scope--DGE-.2- nt-h-i-s -an-0-y s-is-, E--fsola-0no Mi-1eedwa-t-c--a-d-Ma4-n-ear-we-a.-ipr-e -c-r-e~ht-ed-- T-he-wo-r~-s-t 1ase!a-evaluayt-ed wi digeter- ne eb ofalure ttheteda---

M-FP--e--t-r-4-p- Th4s EE dnt as e r-b -bythe

-&1esn--&--i--NF--su-t~onval yes--and-t-he-dw-n-tfe-am bl-ocA-k-va:-Te5--are-ne- c red i ted bec-iu-se-t-e-b-1-eek-v-a1-ies ean-ne-t-E-l-,&s-e (continued)

(conti nued)

Crystal River Unit 3 B 3.3-90 Revision No. 83

Insert B 3.3.11-1 The SLB analysis credited EFIC for isolation of Main Feedwater and Main Steam. The Feed Only Good Generator (FOGG) logic was also credited for termination of an overfeed condition for either OTSG during postulated DC power failures (Ref 7).

Insert B 3.3.11-2 The SLB analysis credited EFIC isolation of Main Feedwater and Main Steam while determining the limiting single failure, with respect to both the core response and the mass and energy releases, to be a failure of the MFP to trip (Ref 7).

EFIC Instrumentation B 3.3.11 BASES APPLICABLE 3, 4. Main Steam Line and MFW Isolation (continued)

SAFETY ANALYSES gainst PMFP -disha-rg pressure. Hewever, because of oeEuringaEross the slo-er 4n_ w-1blk vall'ves nce -the suctiem- Gva~es -- eose, terminating emaA -l-e *e-o5Twer-F-Ec5-l-ftg9 leadblc V~jjve&sW4 ".. -ee. rgle failure of the suet-in

"-The valv~e fa-Pi1-i-ne-&o-jese-ihaMP trFp_and r a n-Iee upn- e,-we-r--c-l-es4*-g---I-ew--t-e"-b ~cqa ,,,es--*.

-aecd-~e-i~e-rn-A-I-eo isbunded by the MFP fa-i-l--i-ng-t-e ae y--- deil-a-se -feor -

-- e -se-- n d--

~e-t- i-.p- i-. f r -

The EFIC System satisfies Criterion 3 of the NRC Policy Statement.

LCO All instrumentation performing an EFIC System Function listed in Table B 3.3.11-1 shall be OPERABLE. Four channels are required OPERABLE for all EFIC instrumentation channels to ensure that no single failure prevents actuation of a train. Each EFIC instrumentation channel is considered to include the sensors and measurement channels for each Function, the operational bypass switches, and permissives.

Failures that disable the capability to place a channel in operational bypass, but which do not disable the trip Function, do not render the protection channel inoperable.

The Bases for the LCO requirements of each specific EFIC Function are discussed next.

Loss of MFW Pumps Four EFIC channels shall be OPERABLE with MFW pump turbines A and B control oil low pressure actuation setpoints of > 55 psig. The 55 psig setpoint is about half of the normal operating control oil pressure. The 55 psig setpoint Allowable Value appears to gave been arbitrarily chosen as a good indication of the Loss of MFW Pumps.

Analysis Only assumes Loss of MFW Pumps and a specific value of MFW pump control oil pressure is not used in the analysis. Further, since the setpoint is so much less than (continued)

Crystal River Unit 3 B 3.3-91 Revision No. 17

EFIC Instrumentation B 3.3.11 BASES LCO Loss of MFW Pumps (continued) operating control oil pressure, instrument error is not a consideration. The Loss of MFW Pumps Function includes a bypass enable and removal function utilizing the same bistable and auxiliary relay used in the NI/RPS bypass reactor trip on loss of both MFW pumps. However, the EFIC bypass is a logic requiring neutron flux to be < 20% RTP and the RPS to be in shutdown bypass. Practically speaking, the status of the bypass is strictly a function of the RPS shutdown bypass (i.e., required to be OPERABLE down into MODE 3).

OTSG Level -Low Four EFIC dedicated low range level transmitters per OTSG shall be OPERABLE with OTSG Level- Low actuation setpoints of > 0 inches indicated (nominally 8 inches above the top of the bottom tube sheet), to generate the signals used for detection for low level conditions for EFW Initiation.

There is one transmitter for each of the four channels A, B, C, and D. The signals are also used after EFW is actuated to control at the low level setpoint of a nominal 32 inches above the lower tubesheet when one or more RCPs are in operation. In the determination of the low level setpoint, it is desired to place the setpoint as low as possible, considering instrument errors, to give the maximum operating margin between the ICS low load control setpoint and the EFW initiation setpoint. This minimizes spurious or unwanted initiation of EFW. To meet this criteria, a nominal setpoint of 8 inches indicated was selected, adjusted for potential instrument error, and shown to be conservative to the specified Allowable Value. Credit is only taken for low level actuation for those transients which do not involve a degraded environment. Therefore, normal environment errors only are used for determining the OTSG Level-Low Allowable Value.

OTSG Pressure-Low Four OTSG Pressure-Low EFIC channels per OTSG shall be OPERABLE with an allowable value of > 600 psig. The actual plant-setpoint is'Net highe 4o account for instrument loop uncertainties an calibration tolerances. The setpoint is chosen to avoid ctuationinder Ac i (conti nued)

Crystal River Unit 3 B 3. 3-92 Revision No. 83

EFIC Instrumentation B 3.3.11 BASES SURVEILLANCE SR 3.3.11.4 REQUIREMENTS (continued) This SR verifies individual channel response times are less than or equal to the maximum value assumed in the accident analysis. Individual component response times are not modeled in the analysis. The analysis models the overall or total elapsed time from the point at which the parameter exceeds the actuation setpoint value at the sensor, to the point at which the end device is actuated.

EFIC RESPONSE TIME tests are conducted on an 24 month STAGGERED TEST BASIS. Testing of the final actuation devices, which make up the bulk of the EFIC RESPONSE TIME, is included in the testing of each channel. Therefore, staggered testing results in response time verification of these devices every 24 months. The 24 month test Frequency is based on operating experience, which shows that random failures of instrumentation components causing serious response time degradation, but not channel failure, are infrequent occurrences. EFIC RESPONSE TIMES cannot be determined at power since equipment operation, which would induce undesired plant transients, is required.

The SR is modified by a Note indicating the SR is not required to be performed prior to entry into MODE 2. This is due to the fact that secondary side (Main Steam) supply pressure for the turbine driven pump is not sufficient to perform the test until after entering MODE 3. The SR 3.0.4 type allowance is also applicable to the MFW and Main Steam Line isolation Functions, consistent with the allowances provided for the end devices in their respective Specifications (Specifications 3.7.2 and 3.7.3).

REFERENCES 1. FSAR, Section 14.1

2. 10 CFR 50.49.

3. FSAR, Chapter 7.

4. IEEE-279-1971.

5. B&W Document 51-1123786-01, "FOGG Verification Study",

May 4, 1981.

6. Amendment No. 152 to the CR-3 Technical Specifications, dated February 13, 1996.

7. CR-3 EPU Technical Report, Section 2.8.5.1.2.

Crystal River Unit 3 B 3. 3-99 Revision No. 23

EFIC Automatic Actuation Logic B 3.3.13 BASES BACKGROUND Main Steam Line and Main Feedwater (MFW) Isolation (continued)

OTSG B MFW and Main Steam Line Isolation automatic actuation logics respond similarly for the OTSG B valves and MFW pump B.

Emergency Feedwater (EFW) Actuation The four EFIC instrumentation channels or each of the parameters being sensed input their inj,tiate commands to the trip logic modules. FSAR Figure 7-26 ef. 1) illustrates the EFW initiation logic. These trip logic modules are physically located in the "A" and "B" EF C channel cabinets.

EFW Actuation functions are the same logic combinations as MFW and Main Steam Line Isolation. Although not part of this Specification, EFW initiation also occurs on high pressure injection (HPI) actuation. Both channels of HPI actuation are input into each EFW actuation trip logic channel.

Vector Valve Enable Logic The EFW module logic is responsible for sending open or 0close signals to the EFW control and block valves. FSAR Figure - Ref.1) illustrates the vector valve logic.

The vector valve logic outputs are in a neutral state (neither commanding open nor close) until a signal is received from the vector valve enable Logic. The vector valve enable logic monitors the channel A and B EFW Actuation logics. When an EFW Actuation occurs, the vector enable logic enables the vector valve logic to generate open or close signals to the EFW valves depending on the relative values of OTSG pressures. l APPLICABLE Automatic isolation of MFW and main steam line is assumed SAFETY ANALY! SES in the safety analyses\ to mitigate the consequences of main steam line or MFW T-i-ne breaks. The--SL-B-anraTy-s-*as--r--e-En}srtB 3.-3.1 3-1 pere-redFedz-ti-igj-a-a-as-

-- -i-I. syeun-te4m-and-i-n-tr4 ope*-i *-ed-&t e sO -s--i-E-ng4-eei.*-1normat-i-o r- R~ecor-d-5-l--90.8-&* 1 O*- 3-RO-G

&U"pot L4**OEh SE)saal ,-1 The-wor-s-t-ease-e*-o--.-at-e-se-n -l-e--f--i--e-"-I dwa-te rrl to--t-r-ph--aee t-- t~erm-i-

-- *d-ythe--eT~ng of#the MoS acEo-t-

,E-,e-d4-te~d (conti nued)

Crystal River Unit 3 B 3. 3-106 Revision No. 83

Insert B 3.3.13-1 The steam line break analysis credits EFIC for isolation of main feedwater and main steam, and the limiting single failure, with respect to both the core response and the mass and energy releases, is a failure of the main feedwater pump to trip. The limiting cases were evaluated at the EPU conditions in Reference 2.

Control of the vector valves is also credited in the MSLB with a MFP trip failure event (Ref. 2) since the Feed Only Good Generator (FOGG) logic is assumed in the termination of an overfeed condition for either OTSG during postulated DC power failures.

EFIC Automatic Actuation Logic B 3.3.13 BASES APPLICABLE bcus -- h- blok valves can nlt, Elese -aga, ~tM-F-P SAFETY ANALYSES di-sc-he-pe..... e.e.-..beEauso.f he--seower-- E 4g (continued) 1 ow1ad bleek--va-ves--the-sttu-ad-r-muý a4-n-bloeck--Ean Elose be... e trT-n6- 0 1g ac.nO S.S the slower E...e " atin -f-eedw-ae- **w.,--the slower- closing low "term' 4,oa4-bThe~k-valves Wi-TI-E-lose. The single failure of the S'UEti.en valve failing toco, with a MFos-ead relianee upene.e..ead "I Ek valves fo r-ac--i dnt t-e-nmi-ne-t-i-on---i-s-botM-ded-y the l-1P-fa-1-Hng tO trnip. The ma-e-a*",ener,.y-Fe-l-ee-fer-the-MFIIP f-1 g*

-..e- -1rp IT bou-ndi*-aei-idewt--r-esponse fore a SLB-.

he-Ve- rVal .e.ntrol 1,gi c waS a-se-cc-Tef-ed Th-e-Feed On1y--eed-Gen~er-at-&F-ýFOGG)-o-ie-was-edi-ted-f-er-t-ervm* -t-A o n -f---an-eve ---a----tc-ti-n-fr-f-e-i-t-lver--TG-o*F4 p*st,,*a-te -DC-p er fiue..... No operator action was credited or required.

Automatic initiation of EFW is credited in the loss of main feedwater analysis. The automatic actuation was based on the SG low level function of EFIC, although EFIC would initiate EFW based on the loss of both MFW pumps as well.

EFIC logic satisfies Criterion 3 of the NRC Policy Statement.

LCO Two channels each of MFW and Main Steam Line Isolation, Vector Valve Enable, and EFW Actuation logics shall be OPERABLE. There are only two channels of automatic actuation logic per Function. Therefore, failure to meet this LCO would make the plant susceptible to a single failure in the OPERABLE actuation Channel precluding the Function.

APPLICABILITY The MFW and Main Steam Line Isolation automatic actuation logics shall be OPERABLE in MODES 1, 2, and 3 because OTSG inventory can be at a high energy level and can contribute significantly to the peak containment pressure and reactor overcooling during a secondary system line break. In MODES 4, 5, and 6, the energy level is low, feedwater flow rate is low or nonexistent, and the Function is not required to be OPERABLE.

(continued)

Crystal River Unit 3 B 3.3-107 Revision No. 17

EFIC Automatic Actuation Logic B 3.3.13 BASES ACTIONS B.1 and B.2 (conti nued)

If Required Action A.1 cannot be met within the associated Completion Time, the plant must be placed in a MODE in which the LCO does not apply. To achieve this status, the plant must be placed in at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in MODE 4 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required MODES from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.3.13.1 REQUIREMENTS This SR requires the performance of a CHANNEL FUNCTIONAL TEST to ensure that the channels can perform their intended functions. This test verifies MFW and Main Steam Line Isolation and EFW initiation automatic actuation logics are functional. This test simulates the required inputs to the logic circuit and verifies successful operation of the automatic actuation logic. The test need not include actuation of the end device. This is due to the risk of a plant transient caused by the closure of valves associated with MFW and Main Steam Line Isolation or actuation of EFW during testing at power. The Frequency of 31 days is based on operating experience, which has demonstrated the failure of more than one channel failing within the same 31 day interval is unlikely.

REFERENCES 1. FSAR, Chapter 7.

2CR3EPU Tec hnical Repo~rt, ýSection 2.8.5.1.2 Crystal River Unit 3 B 3. 3-109 Amendment No. 149

EFIC-EFW-Vector Valve Logic B 3.3.14 BASES BACKGROUND The valve open/close commands are determined by the relative (continued) values of OTSG pressures as follows:

VECTOR VALVES PRESSURE STATUS "A" "B" If OTSG "A" & OTSG "B" Open Open

> 600 psig If OTSG "A" > 600 psig & Open Close OTSG "B" < 600 psig If OTSG "A" < 600 psig & Close Open OTSG "B" > 600 psig If OTSG "A" & OTSG "B"

< 600 psig AND OTSG "A" & OTSG "B" within Open Open 125 psid OTSG "A" 125 psid > OTSG "B" Open Close OTSG "B" 125 psid > OTSG "A" Close Open APPLICABLE The SLB analysis was re performed crediting all "as built" SAFETY ANALYSES sys-tem&-and-t-he-i-r-associ at- -dpons-eitimes.-rhq--is 914874JS-000,--týý 3 Supo[FAmied-&eope-DGE-"

rC 4'TS 4*i Insert B 3.3.14-1 -t -- a -ys-4s, EFIC isclt-i fMncwa*-er-anMl- i

-at-eam-w*er-e-er-etede-.The-V-te-oE--F-ed-**, Fed -OTy-Geod Generator (cFoCC was Eredited for i -term4*at-n of an over-fed c-ndi-ten for- either rDG-powe-F u "Tc ostulatd f-ai-u-r-e-s. No operator action was credited or required.

EFW vector valve logic response time is included in the response time for each EFW instrumentation Function and is The limiting cases were not specified separately.

evaluated at EPU conditions in Reference 1.

(continued)

Crystal River Unit 3 B 3.3-111 Revision No. 83

Insert B 3.3.14-1 The steam line break analysis credits EFIC for isolation of main feedwater and main steam (Ref. 1). Control of the vector valves via the Feed Only Good Generator (FOGG) logic is assumed in the termination of an overfeed condition for either OTSG during postulated DC power failures.

EFIC-EFW-Vector Valve Logic B 3.3.14 BASES ACTIONS A.1 (continued)

With one channel inoperable, the system cannot meet the single-failure criterion and still satisfy the dual functional criteria described above. Therefore, when one vector valve logic channel is inoperable, the channel must be restored to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . This Condition is analogous to having one EFW train inoperable; wherein a 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is provided by the Required Actions of LCO 3.7.5, "EFW System." As such, the Completion Time of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is based on engineering judgment.

B.1 and B.2 If Required Action A.1 cannot be met within the associated Completion Time, the plant must be placed in a MODE in which the LCO does not apply. To achieve this status, the plant must be placed in at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in MODE 4 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.3.14.1 REQUIREMENTS SR 3.3.14.1 is the performance of a CHANNEL FUNCTIONAL TEST every 31 days. This test demonstrates that the EFIC-EFW-vector valve logic is capable of performing its intended function. The Frequency is based on operating experience that demonstrates failure of more than one channel within the same 31 day interval is unlikely.

REFERENCES Crystal River Unit 3 B 3.3-113 Revision No. 35

PAM Instrumentation B 3.3.17 BASES The following table identifies the specific instrument tag numbers for PAM instrumentation identified in Table 3.3.17-1.

FUNCTION CHANNEL A CHANNEL B

1. Wide Range Neutron Flux NI-15-NI-1 or NI-15-NIR NI-14-NI-I

2. RCS Hot Leg Temperature RC-4A-TI4-1 RC-4B-TIR1

3. RCS Pressure(Wide Range) RC-158-P12 or RC-158-PIR RC-159-PI2

4. Reactor Coolant RC-163A-LR1 (Hot leg level) and RC-163B-LR1 (Hot leg level) and Inventory RC-164A-LR1 (Vessel Head level) RC-164B-LR1 (Vessel Head level)

5. Borated Water Storage DH-7-LI or DH-7-LIR1 DH-37-LI Tank Level

6. High Pressure Injection Al: MU-23-FI8-1 Al: MU-23-FI12 Flow (-- A2: MU-23-FI10 A2: MU-23-FI6-1 BI: MU-23-FI9 BI: MU-23-FI5-1 B2: MU-23-FI7-1 B2: MU-23-FIll

7. Containment Sump Water WD-303-LI or WD-303-LR WD-304-LI or WD-304-LR Level (Flood Level)

8. Containment Pressure BS-16-PI BS-17-PI (Expected Post-Accident Range)

9. Containment Pressure BS-90-PI or BS-90-PR BS-91-PI or BS-91-PR (Wide Range)

10. Containment Isolation ES Light Matrix "A": AHV-1B/lC; ES Light Matrix "B": AHV-IA/1D; Valve Position CAV-1/3/4/5/126; CAV-2/6/7/431; CFV-11/12/15/16; LRV-70/72; MUV- CFV-29/42; LRV-71/73; MUV-258 thru -261/567;WDV-3/60/94/ 18/27/49/253; WDV-4/61/62/405; 406; WSV-3/5 WSV-4/6 ES Light Matrix "AB": CFV-25 thru-28; CIV-34/35/40/41; DWV-160; MSV-130/148; SWV-47 thru 50/79 thru 86/109/110

11. Containment Area RM-G29-RI or RM-G29-RIR RM-G30-RI Radiation (High Range)

12. Not--Used, 13 Pressurizer Level R 1-LIR-1 C-1-LIR-3

14. Steam Ge erator Water OTS A: SP-25-LI1 or TSG A: SP-26-LI1 Level (Startup Range) SP-25-LIR TSG B: SP-30-LI1 OTSG : SP-29-LI1 OR SP-29-LIR F[Indication Tag to be added later.]

[Indication Tag to be added later.]

(conti nued)

Crystal River Unit 3 B 3. 3-125A Revision No. 54

PAM Instrumentation B 3.3.17 BASES FUNCTION CHANNEL A CHANNEL B

15. Steam Generator Water OTSG A: SP-17-LII or OTSG A: SP-18-LI1 Level (Operating Range) SP-17-LIR OTSG B: SP-22-LI1 OTSG B: SP-21-LII or SP-21-LIR

16. Steam Generator OTSG A: MS-106-PI1 or OTSG A: MS-107-PII or Pressure MS-106-PIR, MS-107-PIR OTSG B: MS-110-PIl or OTSG B: MS-111-PIl or MS-110-PIR MS-111-PIR

17. Emergency Feedwater EF-98-LI1 EF-99-LII Tank Level 18a. Core Exit Quadrant Temperature WX IM-5G-TE/IM-6C-TE IM-7F-TE/IM-2G-TE (Thermocouple) XY IM-9E-TE/IM-13G-TE IM-1OC-TE/IM-11G-TE YZ IM-9H-TE/IM-100-TE IM-10M-TE/IM-13L-TE ZW IM-3L-TE/IM-60-TE IM-4N-TE/IM-6L-TE I- - -

18b. Core Exit Temperature RC-171-TR RC-172-TR [Ilndication Tag to be added (Recorder)

I- I. later.

ýý

19. Emergency Feedwater OTSG A: EF-2S-FI1 OTSG A: EF-26-F1l Flow OTSG B: EF-23-FIl OTSG B: EF-24-FIl

20. Low Pressure Injection DH-1-FI1 DH-1-F12 Flow

21. Degrees of Subcooling 4 A&--O-i-s p~ayed-on-EMEO-3 9 detcr1 A~- ntye~-ono-4GMO--3-87.7#

Note' cnt-r-y---tnta-L-CO-3.-3-~41-i-s F 9de-o-RF-Pf-a"--Ofg-e 4e iFdiF-any e-. the-Fo4-4w~ng

ýaeo-RECALL Pomnt- arc C0ut

[Indication Tag to be added later. Haedtware H~ar-dware Mu-Vt-i-p ewx-e-EMC-O-17+41-8 7 9 Mu-4-t-ip1-xeF"s-EMCO--26/27/2-8 C-own H4U8-E-MCG-O8/2-9 Gewput-er-EWO-0-217L40 C-ompu'te-r--s---EMCO -0/4-3 Men-4or--- EMGO-3-8 MoniorEMCO.3 T-roasmi-t-tef-EMCG--7-2 T-ransm4Af-e-f"--EC-ReceiveF EMCO-7-3 Re~eiver EMCO75 Reeo-der--R&4-74-TR ReEor-de*'-RCZ-472--TR RE-CAt-Pa-i-n~t RC-S-41-iesaur-c--L-R-REEL--24-3 PC-S-P-'esm~-hR-REL-40 RC-S-Pi"es&*r-e--WR-REC-L--4 T-Ho~t-R-ECL--Lz/439 T-Ho-t--R&C-6-l-8/NO4

22. Emergency Diesel EGDG-1A Wattmeter SSF-AH Main EGDG-1B Wattmeter SSF-AX Main Generator kW Indication control board indicator control board indicator

23. LPI Pump Run Status ESFA-LX3 (Red Light) or ESFB-LX3 (Red Light) or ESFA-HU (ES Light Matrix "A") ESFB-HU (ES Light Matrix "B")

24. DHV-42 and DHV-43 ESFA-KN3 (Red Light) ESFB-KN3 (Red Light)

Open Position

25. HPI Pump Run Status HPI Pump IA: HPI Pump 1C:

ESFA-MF7 (Red Light) or ESFB-MF7 (Red Light) or ESFA-AH (ES Light Matrix "A") ESFB-AH (ES Light Matrix "B")

OR OR HPI Pump IB: HPI Pump IB:

ESFA-MN7 (Red Light) or ESFB-MV7 (Red Light) or ESFA-AJ (ES Light Matrix "A") ESFB-AJ (ES Light Matrix "B")

26. RCS Pressure RC-147-PI1 RC-148-PI1 (Low Range)

NOTES: For Function 18a, each quadrant requires at least 2 OPERABLE detectors, one froipeach channel.

OPERABILITY of only one detector for any quaorant constitutes entry into Condition A of LCO 3.3.17.

Any quadrant with no OPERABLE detector constitutes entry into Condition C if LCO 3.3.17. Separate Condition entry is allowed for each quadrant.

For Function 25, D0CERILIlY of indication is required only for the one ES selected FE pItpin each channel.

(continued)

Crystal River Unit 3 B 3. 3-125B Revision No. 46

PAM Instrumentation B 3.3.17 BASES LCO 12. Net-4sed IAnsert B 3.3.17-1

13. Pressurizer Level Pressurizer level is indicated to provide information on proper operation of the pressurizer for a variety of anticipated transients. These include decreasing feedwater temperature, excessive main feedwater flow, decreasing steam flow, small steam leaks, loss-of-offsite power (and subsequent natural circulation ensured by pressurizer heater operation), loss of condenser vacuum, as well as several others. For these events, pressurizer level is expected to remain on-scale for the installed indication.

For severe transients or accidents such as a steam line break, steam generator tube rupture, and many small break LOCAs, the pressurizer will void. For the case of a loss of main feedwater, the pressurizer could potentially be made water-solid. This is undesirable in that RCS pressure control is degraded and the potential for passing liquid through the pressurizer safety valves is increased. Studies have shown the safeties have a higher potential to fail to re-seat (creating an unisolable LOCA) if this condition were to occur.

Two channels of pressurizer level, each covering a range of 0 to 320 inches, are indicated and recorded in the control room. These instruments are not assumed to provide information required by the operator to take a mitigation action specified in the safety analysis. As such, they are not Type A variables. However, the monitors are deemed risk significant (Category 1) and are included within the LCO based upon this consideration.

The following instrument associated with primary coolant system operation monitoring would be rendered non-functional due to the dynamic effects of a LOCA:

- RC-1-LT3 RC-1-LT3 is a transmitter used in providing pressurizer level indication (RC-1-LIR-3) in one of two RG 1.97 compliant instrument strings. There is also a third non-safety related pressurizer level instrument string. Pressurizer level is classified as a Type D variable that is used to indicate proper (continued)

Crystal River Unit 3 B 3.3-133 Revision No. 54

Insert B 3.3.17-1 HPI Flow Margin Two channels of HPI System flow margin are provided. These channels are indicated on redundant safety related digital displays, Inadequate Core Cooling System (ICCMS) displays, on the main control board. For each channel, four low range HPI System flow instruments (Function 6), along with RCS pressure inputs (Functions 3 and 26), are combined to compare the required HPI System flow (based on RCS pressure) to actual HPI System flow.

On sustained loss of subcooling margin and inadequate HPI System flow, the Fast Cooldown (FCS) automatically initiates and opens the ADVs to allow rapid RCS cool down. The HPI Flow Margin channels are used by the operator to ensure automatic actuation of the FCS and opening of the ADVs. Therefore, these channels are deemed risk significant (Category 1) and are included within the LCO based upon this consideration.

PAM Instrumentation B 3.3.17 BASES LCO 21. Degrees of Subcoolinq (continued)

FInser B 3.3.17-ý2 *~The subcooling margin monitors are used to verify the existence of, or to take actions to ensure the kljý17ý restoration of subcooling margin. Specifically, a loss of adequate subcooling margin during a LOCA requires the operatorI o reactor o-a-t-pumpt{R1~s~t esrhgh 4 or, low pre i-nj-~to~;--aRdfe-sie--e-s-te- -gcncr-ator levels to the

-nadequ~a-esubEri l l. Si dnE-Z t ype T"" 1 n-wh Eh

, hcopcat0r-baes-mýftnu-a1---actiens required for- event mi- igatien for-whiEh no aut-temati-e-eeft-r-e1-s-a--e-pi~e 4ded it-h 4- as--beenl 4 A A 4.-. +.-"4.- I /-A

22. Emeraencv Diesel Generator. kW Indication The Emergency Diesel Generator (EDG) provides standby (emergency) electrical power in the case of Loss of Offsite Power (LOOP). EDG kW indication is provided in the control room to monitor the operational status of the EDG.

EDG Power (kW) output indication is a type A variable because EDG kW indication provides the control room operator EDG load management capabilities. EDG load management enables the operator to base manual actions of load start and stop for event mitigation.

(continued)

Crystal River Unit 3 B 3. 3-138B Amendment No. 174

Insert B 3.3.17-2 Two channels of subcooling margin with temperature inputs from RCS hot legs (Function 2) and core exit thermocouples (Functions 18a and 18b), along with RCS pressure inputs (Functions 3 and 26) are provided. These channels are indicated on redundant safety related digital displays, ICCMS displays, on the main control board. When selected, multiple core exit temperatures are auctioneered with only the highest temperature being input to the subcooling calculation.

Insert 3.3.17-3 HPI and LPI subsystem actuations. Additionally, a loss of adequate subcooling margin following a reactor trip results in an automatic trip of reactor coolant pumps (RCPs), steam generator level control automatically transfers to the inadequate subcooling margin level setpoint, and, when combined with inadequate HPI System flow, results in automatic actuation of the FCS which opens the ADVs. The Degrees of Subcooling channels are used by the operators to ensure these automatic actions occur. Therefore, these channels are deemed risk significant (Category 1) and are included within the LCO based upon this consideration.

PAM Instrumentation B 3.3.17 BASES ACTIONS F.1 (continued)

In the case of reactor vessel level, Reference 4 demonstrated that from a risk perspective, the appropriate Required Action was not to mandate a plant shutdown, but rather to follow the actions of Specification 5.7.2.a.

SURVEILLANCE As noted at the beginning of the SRs, the SRs apply REQUIREMENTS to each PAM instrumentation Function in Table 3.3.17-1, except as noted.

SR 3.3.17.1 Performance of the CHANNEL CHECK once every 31 days for each required instrumentation channel that is normally energized ensures that a gross failure of the instrumentation has not occurred. A CHANNEL CHECK is a comparison of the parameter indicated on one channel with a similar parameter on other channels. It is based on the

,assumption that instrument channels monitoring the same parameter should read approximately the same value.

Significant deviations between the two instrument channels could be an indication of excessive instrument drift in one of the channels or of something even more serious.

Acceptance criteria are determined by the plant staff, and are presented in the Surveillance Procedures. The criteria may consider, but is not limited to, channel instrument uncertainties, including indication and readability. If a channel is outside the acceptance criteria, it may be an indication that the sensor or the signal processing equipment has excessively drifted. If the channels are within the acceptance criteria, it is an indication that the channels are OPERABLE. If the channels are normally off-scale when the Surveillance is performed, the CHANNEL CHECK will only verify that they are off-scale in the same direction. Off-scale low current loop channels are verified to be reading at the bottom of the range and not failed downscale.

The Frequency is based on operating experience that demonstrates channel failure is an uncommon event.

(continued)

Crystal River Unit 3 B 3.3-142 Revision No. 11

Insert B 3.3.17-4 G.1 If the Required Action and associated Completion Time of Condition C is not met and Table 3.3.17-1 directs entry into Condition G, THERMAL POWER must be reduced to

< 2609 MWt. FCS is only applicable with THERMAL POWER > 2609 MWt as defined in Technical Specification (TS) 3.7.20, "Fast Cooldown System (FCS)." Therefore, reducing THERMAL POWER < 2609 MWt is acceptable since the HPI Flow Margin is required for the operator to ensure automatic actuation of the FCS and opening of the ADVs.

The one hour Completion Time is consistent with the Completion Time allowed by TS 3.7.20 and is a reasonable time to achieve the required THERMAL POWER level.

Remote Shutdown System B 3.3.18 Table B 3.3.18-1 Remote Shutdown System Instrumentation FUNCTION INSTRUMENT NUMBER

1. Reactivity Control

a. Reactor Trip Breaker Position CB-1 CB-2 CB-3 CB-4 A

B

b. Source Range Neutron Flux NI-O14-NI2

2. Reactor Coolant System Pressure Control

a. RCS Wide Range Pressure RC-158-PI1 OR RC-159-PI1

3. RCS Temperature Control

a. RCS Hot Leg Temperature "A" Loop: RC-4A-TI3-2 "B" Loop: RC-4B-TI4-2

b. RCS Cold Leg Temperature "A" Loop: RC-5A-TI2-2 "B" Loop: RC-5B-TI4-2

c. OTSG Pressure "A" OTSG: MS-106-PI2 OR MS-107-PI2 "B" OTSG: MS-110-P12 OR MS-111-P12

d. OTSG Level "A" OTSG Low Range Level: SP-25-LI2 OR SP-26-LI2 "B" OTSG Low Range Level: SP-29-LI2 OR SP-30-LI2 "A" OTSG High Range Level: SP-17-LI2 OR SP-18-LI2 "B" OTSG High Range Level: SP-21-LI2 OR SP-22-LI2

e. Emergency Feedwater Flow "A" OTSG: EF-25-FI2 OR EF-26-FI2 "B" OTSG: EF-23-FI2 OR EF-24-FI2

f. Emergency Feedwater Tank Level EF-98-LI2 OR EF-99-LI2

4. RCS Inventory Control

a. Pressurizer Level RC-1-LIl-2 OR RC-1-LI3-2

b. High Pressure Injection Flow Al Injection Line: MU-23-FI8-2 A2 Injection Line: MU-23-FI6-2 B1 Injection Line: MU-23-FI5-2 B2 Injection Line: MU-23-FI7-2 Crystal River Unit 3 B 3. 3-150 Amendment No. 196

linsert B ICCMS I ICCMS Instrumentation B 3.3.19 B 3.3 INSTRUMENTATION B 3.3.19 Inadequate Core Cooling Monitoring System (ICCMS)

Instrumentation BASES BACKGROUND The ICCMS provides mitigation functions to protect the fuel cladding and limit the amount of energy released in an accident.

The ICCMS actuates the following:

" Fast Cooldown System (FCS),

" Reactor coolant pump (RCP) trip, and

" Steam Generator (OTSG) Inadequate Subcooling Margin (ISCM) level setpoint adjustment.

The ICCMS is an analog system and consists of three initiation channels for each Function; FCS actuation, RCP trips, and OTSG ISCM level setpoint actuation.

For each Function, three initiation channels provide input to two actuation logic trains. Each actuation logic train is initiated by two-out-of-three ICCMS initiation channels. Either actuation logic train initiates the associated equipment (Ref. 1).

Requirements associated with the ICCMS automatic actuation logic are provided in LCO 3.3.20, "Inadequate Core Cooling Monitoring System (ICCMS)

Automatic Actuation Logic."

ICCMS displays provide operators with indications of degrees of subcooling and high pressure injection (HPI) flow margin to evaluate ICCMS status and to ensure each of the ICCMS automatic actuations occur within their allotted time. Requirements associated with ICCMS displays and parameter indicators are provided in LCO 3.3.17, "Post Accident Monitoring (PAM) Instrumentation."

The following parameters are monitored and provide input to the ICCMS to be used as required to determine Crystal River Unit 3 B 3.3-151 Revision No. XX

lnsert B lCCMS ICCMS Instrumentation B 3.3.19 BASES BACKGROUND FCS actuation, RCP trip, and OTSG ISCM level setpoint (continued) actuation:

HPI Flow,

" Reactor Coolant System (RCS) Pressure - Low Range,

" RCS Pressure - Wide Range,

Core Exit Thermocouples (CETs), and

" Reactor Trip Status.

HPI Flow Three flow transmitters monitor the flow in each of four HPI lines. The four signals being summed together to produce a total HPI flow signal per ICCMS initiation channel.

RCS Pressure Each ICCMS initiation channel monitors two independent pressure sensors - a low range sensor (0-600 psig) and a wide range sensor (0-2500 psig).

For RCS pressures of 500 psig and below, the low range signal is used; above 500 psig, the wide range signal is used.

The selected RCS pressure is an input to function generators used to derive the degrees of subcooling, degrees of superheat, and required HPI flow.

CETs Each ICCMS initiation channel receives input from eight Type K incore thermocouples. To accommodate the occasional failure of a CET, provisions for Crystal River Unit 3 B 3.3-152 Revision No. XX

nseBICCMS ICCMS Instrumentation B 3.3.19 BASES BACKGROUND CETs (continued) bypassing a failed thermocouple are provided. The ICCMS circuitry selects the highest of the remaining CETs signals for use.

The input parameters are processed in the ICCMS circuitry to determine subcooling margin and HPI flow margin.

Degrees of Subcoolinq Monitor Subcooling margin is the difference between saturation temperature for a given pressure as compared to the actual temperature corrected for instrument uncertainty. Each ICCMS initiation channel receives input from the CETs and RCS pressure instruments to generate core degrees of subcooling values and to determine if a loss of subcooling margin (SCM) exists. When inadequate SCM is coincident with a reactor trip signal, each ICCMS initiation channel will generate a loss of SCM signal. Two-out-of-three ICCMS channels in trip results in two actuation logic trains tripped, each of which provide an RCP trip within one minute and also results in raising the OTSG secondary side water level control setting to the ISCM level.

HPI Flow Margin Monitor Each ICCMS initiation channel associated with the FCS actuation Function also receives HPI flow input from each of the four HPI System injection lines.

The four signals are summed and the total HPI flow is compared to a generated curve of minimum HPI flow versus RCS Pressure to determine inadequate HPI flow. This curve also includes adjustments for instrument uncertainty. Upon a sustained loss of SCM and inadequate HPI flow, each ICCMS initiation channel will generate a trip signal. Two-out-of-three ICCMS channels in trip results in two actuation logic trains tripped, each of which initiates the FCS (Ref. 1).

Crystal River Unit 3 B 3.3-153 Revision No. XX

Insert B ICCMS ICCMS Instrumentation B 3.3.19 BASES BACKGROUND Reactor Trip Status (continued)

Each ICCMS channel monitors auxiliary contacts from each of six CONTROL ROD drive (CRD) trip breakers:

A - Main CRD supply breaker,

B - Secondary CRD supply breaker,

C1 and C2 - Main DC Hold supply breaker pair, and

" D1 and D2 - Secondary DC Hold supply breaker pair.

The ICCMS circuitry indicates that a reactor trip has occurred if: 1) CRD trip breakers A and B are open; 2) CRD trip breakers A and D1 and D2 are open; 3) CRD trip breakers B and C1 and C2 are open; or 4) CRD trip breakers C1 and C2 and D1 and D2 are open.

APPLICABLE The following ICCMS Functions have been assumed within SAFETY the accident analyses.

ANALYSES

1. FCS Actuation For a specific range of small break loss of coolant accidents (LOCAs), HPI flow (assuming worse case single failure) by itself may not be sufficient to protect the core. Both ADVs are assumed to actuate following a sustained loss of SCM to cool down the RCS following a small break LOCA when HPI flow is inadequate (Ref. 2). The ICCMS automatically actuates the FCS to support the safety analysis.

In the initiating event, the ICCMS will detect a loss of SCM concurrent with inadequate HPI flow and reactor trip status. Following a sustained loss of SCM and inadequate HPI flow, the ICCMS automatically initiates FCS, which opens both ADVs, to allow rapid RCS cool down.

The FCS and operation of both ADVs are credited with THERMAL POWER > 2609 MWt (pre-EPU power level) to assure sufficient core cooling during a SBLOCA assuming single failure of one HPI subsystem. With THERMAL POWER < 2609 MWt, the Emergency Core Cooling System (ECCS) provides sufficient core cooling during a small break LOCA assuming single Crystal River Unit 3 B 3.3-154 Revision No. XX

[Insert B ICCMS I ICCMS Instrumentation B 3.3.19 BASES (continued)

APPLICABLE 1. FCS Actuation (continued)

SAFETY ANALYSES failure of one HPI subsystem without the need for the FCS and ADVs (Refs. 2 and 3). Requirements associated with the FCS function of the ADVs are provided in LCO 3.7.20, "Fast Cooldown System (FCS)."

2. RCP Trip The core flood line break analysis requires the trip of the RCPs within one minute following a sustained loss of SCM in order to minimize the rate of inventory loss which would reduce the time to the core becoming uncovered. In the initiating event, the ICCMS will detect a loss of SCM and reactor trip status. Following a sustained loss of SCM, the ICCMS automatically opens the RCP breakers within one minute (Ref. 2).

3. OTSG ISCM Level Setooint Actuation Small break LOCA analysis requires the raising of the OTSG secondary side water level to the ISCM level. This level is necessary in the boiler condenser phase of accident mitigation to promote natural circulation within the RCS. In the initiating event, the ICCMS will detect a loss of SCM and reactor trip status. Following a sustained loss of SCM, the ICCMS within 10 minutes automatically sends a signal to the Emergency Feedwater Initiation and Control (EFIC) System which raises OTSG secondary side level to the ISCM level (Ref. 2).

The ICCMS instrumentation channels satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).

LCO The ICCMS channels for each Function specified in Table 3.3.19-1 are required to be OPERABLE to ensure that a single failure of one required channel will not result in loss of the ability to automatically actuate the required safety systems. Each ICCMS instrument channel is considered to include the associated sensors and measurement channels for each Function, Crystal River Unit 3 B 3.3-155 Revision No. XX

[Insert B ICCMS I ICCMS Instrumentation B 3.3.19 BASES LCO maintenance bypass switches, time delays, and (continued) permissives to ensure the channel performs its related support functions.

1.a HPI Flow Four channels (one sensor on each HPI System injection line) of HPI Flow are required to be OPERABLE per ICCMS initiation channel of FCS Actuation Function.

Each HPI Flow channel includes a sensor, square root extractor, summer, and associated analog modules. All four HPI Flow channels per ICCMS initiation channel must be OPERABLE to determine total HPI Flow. The analog and bistable portions of each flow channel are ICCMS initiation channel specific. Therefore, failure of one channel renders one channel of the HPI Flow Function in one ICCMS initiation channel inoperable to each ICCMS actuation logic train.

1.b, 2.a, 3.a Reactor Coolant Pressure - Low Range One channel of Reactor Coolant Pressure - Low Range is required to be OPERABLE per ICCMS initiation channel.

Each Reactor Coolant Pressure - Low Range channel includes a sensor, function generator, and associated analog modules. The analog and bistable portions of each pressure channel are ICCMS initiation channel specific. Therefore, failure of one channel renders one channel of the Reactor Coolant Pressure - Low Range in one ICCMS initiation channel inoperable to each ICCMS actuation logic train.

Reactor Coolant Pressure - Low Range Function is automatically selected when RCS pressure is

< 500 psig. To ensure the Reactor Coolant Pressure -

Low Range Function is not bypassed when required to be OPERABLE by the safety analysis, each channel is required to be capable of automatically enabling on lowering RCS pressure when above the enabling setpoi nt.

1.c. 2.b. 3.b Reactor Coolant Pressure - Wide Range One channel of Reactor Coolant Pressure - Wide Range is required to be OPERABLE per ICCMS initiation channel. Each Reactor Coolant Pressure - Wide Range Crystal River Unit 3 B 3.3-156 Revision No. XX

Insert B ICCMS I ICCMS Instrumentation B 3.3.19 BASES LCO 1.c. 2.b, 3.b Reactor Coolant Pressure - Wide Range (continued) channel includes a sensor, function generator, and associated analog modules. The analog and bistable portions of each pressure channel are ICCMS initiation channel specific.

Therefore, failure of one channel renders one channel of the Reactor Coolant Pressure - Wide Range in one ICCMS initiation channel inoperable to each ICCMS actuation logic train.

Reactor Coolant Pressure - Wide Range Function is automatically selected when RCS pressure is

> 500 psig. To ensure the Reactor Coolant Pressure -

Wide Range Function is not bypassed when required to be OPERABLE by the safety analysis, each channel is required to be capable of automatically enabling on increasing RCS pressure when below the enabling setpoi nt.

1.d. 2.c, 3.c Core Exit Thermocouples (CETs)

One of two channels per core quadrant of CETs is required to be OPERABLE per ICCMS initiation channel.

Each CET channel includes a sensor, temperature transmitter, and associated analog modules. Each CET channel is ICCMS initiation channel specific.

Therefore, failure of one required CET in a core quadrant renders one required channel in one ICCMS initiation channel inoperable to each ICCMS actuation logic train.

1.e, 2.d. 3.d Loss of Subcooling Margin One channel of Loss of Subcooling Margin is required to be OPERABLE per ICCMS initiation channel. Inputs are provided from the CETs and RCS pressure instruments. Actual saturation temperature is compared to a reference saturation temperature curve to determine a loss of subcooling margin. Each Loss of Subcooling Margin channel includes a comparator, function generator, and associated analog modules.

Failure of one channel renders one ICCMS initiation channel inoperable to each ICCMS actuation logic train.

Crystal River Unit 3 B 3.3-157 Revision No. XX

IMnsert B ICCMS ICCMS Instrumentation B 3.3.19 BASES LCO 1.f Inadequate HPI Flow (continued)

One channel of Inadequate HPI Flow is required to be OPERABLE per ICCMS initiation channel of the FCS Actuation Function. The total HPI flow input is compared to a generated curve of HPI flow versus RCS Pressure to determine inadequate HPI flow. Each Inadequate HPI Flow channel includes an actual HPI flow input, reference RCS pressure input, comparator, function generator, and associated analog modules.

Failure of one channel renders one ICCMS initiation channel inoperable to each FCS actuation logic train.

1.g, 2.e, 3.e Reactor Trip Status Six channels of Reactor Trip Status are required to be OPERABLE per ICCMS initiation channel. Each Reactor Trip Status channel includes an auxiliary contact and associated analog modules. Each ICCMS initiation channel receives six independent auxiliary contacts from the CRD trip breakers. Therefore, the auxiliary contacts of the Reactor Trip Status Function channels are ICCMS initiation channel specific. Failure of an auxiliary contact renders one Reactor Trip Status Function channel in one ICCMS initiation channel inoperable.

APPLICABILITY The ICCMS instrumentation channels are applicable as specified in Table 3.3.19-1.

FCS Actuation Functions The ICCMS instrumentation required to actuate FCS shall be OPERABLE with THERMAL POWER > 2609 MWt. The FCS and operation of the ADVs are assumed with THERMAL POWER > 2609 MWt. With THERMAL POWER < 2609 MWt, the ECCS provides sufficient core cooling during a small break LOCA assuming a single failure of one HPI subsystem without the need for the FCS function of the ADVs.

RCP Trip Functions The ICCMS instrumentation required to trip the RCPs shall be OPERABLE in MODES 1, 2, and 3 to minimize the rate of inventory loss which would reduce the time to the core becoming uncovered during a LOCA.

Crystal River Unit 3 B 3.3-158 Revision No. XX

Insert B ICCMS ICCMS Instrumentation B 3.3.19 BASES APPLICABILITY RCP Trip Functions (continued)

In MODES 4, 5, and 6, the plant operating conditions are such that the likelihood of an event occurring that would require ICCMS automatic actuation is low.

OTSG ISCM Level Setpoint Actuation Functions The ICCMS instrumentation required to automatically send a signal to the EFIC System which adjusts the OTSG setpoint to the ISCM level shall be OPERABLE in MODES 1, 2, and 3 to promote natural circulation during the RCS boiler condenser phase of accident mitigation.

In MODES 4, 5, and 6, the plant operating conditions are such that the likelihood of an event occurring that would require ICCMS automatic actuation is low.

ACTIONS A Note has been provided to modify the ACTIONS related to ICCMS instrument Function. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable ICCMS instrument Functions provide appropriate compensatory measures for separate inoperable Functions. As such, a Note has been provided that allows separate Condition entry for each inoperable ICCMS instrumentation Function.

A second Note is provided to ensure appropriate remedial actions are taken, if necessary, when required PAM indication channels are rendered inoperable by ICCMS instrument inoperabilities.

Crystal River Unit 3 B 3.3-159 Revision No. XX

lInse B ICCMS ICCMS Instrumentation B 3.3.19 BASES ACTIONS A.1 (continued)

With one or more required channels inoperable, the inoperable channel must be restored to OPERABLE status within 30 days. The 30 day Completion Time takes into account the provisions to support manual actuation of the FCS, RCP trip, and OTSG ISCM Setpoint adjustment.

The 30 day Completion Time is also considered acceptable based on maintaining FCS actuation capability and the low probability of an event requiring the ICCMS instrumentation during this time period.

B.1 This Required Action directs entry into the appropriate Condition referenced in Table 3.3.19-1.

The applicable Condition referenced in the Table is Function dependent. Each time an inoperable channel has not met the Required Action of Condition A and the associated Completion Time has expired, Condition B is entered for that channel and provides for transfer to the appropriate subsequent Condition.

Additionally, multiple inoperable, untripped channels may result in a loss of FCS actuation capability.

Therefore, Condition B is entered and provides for transfer to the appropriate subsequent Condition. For ICCMS instrumentation, automatic FCS actuation capability is considered not maintained when multiple inoperable channels result in two or more ICCMS initiation channels inoperable and untripped to the FCS automatic actuation logic trains.

C.1 If a channel is not restored to OPERABLE status within the allowed Completion Time, this Required Action specifies initiation of action in accordance with Specification 5.7.2.a, which requires a written special report to be submitted to the NRC. Since several alternate means of manually tripping the RCPs and adjusting the OTSG secondary side water level to Crystal River Unit 3 B 3. 3-160 Revision No. XX

Insert B ICCMS ICCMS Instrumentation B 3.3.19 BASES ACTIONS C.1 (continued) the ISCM setpoint are available, the Required Action does not prescribe a plant shutdown, but rather requires following the directions of Specification 5.7.2.a. The special report discusses the results of the root cause evaluation of the inoperability, identifies proposed restorative actions, and provides a schedule for restoring the ICCMS channels to OPERABLE status.

D.1 With the Required Action and associated Completion Time of Condition A not met or automatic FCS actuation capability not maintained, declaring the associated supported feature (i.e., FCS function of the ADVs) inoperable ensures the appropriate Required Actions are performed for the supported feature per LCO 3.0.6.

In this situation (Required Actions and associated Completion Time of Condition A not met or automatic FCS actuation capability not maintained), continued operation at 100% RTP is not appropriate. Therefore, the FCS must be immediately declared inoperable and the appropriate ACTIONS of Specification 3.7.20 performed.

SURVEILLANCE A Note indicates that the SRs for each ICCMS REQUIREMENTS instrument Function are identified in the SRs column of Table 3.3.19-1. The various SRs account for individual functional differences and for test frequencies applicable specifically to the Functions listed in Table 3.3.19-1.

SR 3.3.19.1 Performance of the CHANNEL CHECK every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the two Crystal River Unit 3 B 3.3-161 Revision No. XX

1lnsert B ICCMS ICCMS Instrumentation B 3.3.19 BASES SURVEILLANCE SR 3.3.19.1 (continued)

REQUIREMENTS instrument channels could be an indication of excessive instrument drift in one of the channels or of something more serious. CHANNEL CHECK will detect gross channel failure; therefore, it is key in verifying that the instrumentation continues to operate properly between each CHANNEL CALIBRATION.

Agreement criteria are determined based on a combination of the channel instrument uncertainties, including isolation, indication, and readability. If a channel is outside the criteria, it may be an indication that the transmitter or the signal processing equipment has drifted outside its limit.

If the channels are normally off scale during times when surveillance is required, the CHANNEL CHECK will only verify that they are off scale in the same direction. Off scale low current loop channels are verified to be reading at the bottom of the range and not failed downscale.

For Loss of Subcooling Margin (Functions 1.e, 2.d, 3.d) and Inadequate HPI Flow (Function 1.f) Functions, the Degrees of Subcooling and HPI Flow Margin indicators may be used to perform the required CHANNEL CHECK.

The Frequency, about once every shift, is based on operating experience that demonstrates channel failure is rare. Since the probability of two random failures in redundant channels in any 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months period is extremely low, the CHANNEL CHECK minimizes the chance of loss of protective function due to failure of redundant channels. The CHANNEL CHECK supplements less formal, but more frequent, checks of channel OPERABILITY during normal operational use of the displays associated with the LCO's required channels.

SR 3.3.19.2 A CHANNEL FUNCTIONAL TEST is performed on each required ICCMS channel to ensure the entire channel will perform the intended functions. Analog and contact inputs may be simulated at the analog input or contact input to the ICCMS initiation channel.

Crystal River Unit 3 B 3.3-162 Revision No. XX

lInsert B ICCMS ICCMS Instrumentation B 3.3.19 BASES SURVEILLANCE SR 3.3.19.2 (continued)

REQUIREMENTS Actuation of the channel trip module is verified along with all event points, annunciator alarms, and main control board status lights. Any setpoint adjustment shall be consistent with the assumptions of the safety analyses in which the ICCMS Functions are assumed.

The Frequency is based on engineering judgment of the reliability of the components and minimizing the possibility of inadvertent FCS actuation, RCP trip, or OTSG ISCM level setpoint actuation.

SR 3.3.19.3 CHANNEL CALIBRATION is a complete check of the instrument channel, including the sensor. The test verifies that the channel responds to a measured parameter within the necessary range and accuracy.

CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drift to ensure that the instrument channel remains operational between successive tests. CHANNEL CALIBRATION shall find that measurement errors and bistable setpoint errors are within the assumptions of the ICCMS instrumentation calculations. CHANNEL CALIBRATIONS must also be performed consistent with the assumptions of the safety analyses in which the ICCMS Functions are assumed.

This Frequency is justified by the assumption of a 24 month calibration interval to determine the magnitude of equipment drift in the ICCMS instrumentation calculations.

This SR is modified by two Notes. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative. Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the ICCMS Crystal River Unit 3 B 3. 3-163 Revision No. XX

Insert B ICCMS ICCMS Instrumentation B 3.3.19 BASES SURVEILLANCE SR 3.3.19.3 (continued)

REQUIREMENTS instrument calculations. The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service.

For channels determined to be OPERABLE but degraded after returning the channel to service, the performance of these channels will be evaluated under the plant Corrective Action Program (CAP). Entry into the CAP will ensure required review and documentation of the condition.

The second Note requires the as-left setting for the channel be returned to within, or more conservative than, the pre-established as-left tolerance. Where a setpoint more conservative than the pre-established as-left tolerance is used in the plant surveillance procedures, the as-left and as-found tolerances, as applicable will be applied to the surveillance procedure setpoint. This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit is maintained. If the as-left channel setting cannot be returned to a setting within the pre-established as-left tolerance, then the channel shall be declared inoperable. The second Note also requires the pre-established tolerance and the methodologies for calculating the as-left and the as-found tolerances be in the FSAR (Ref. 1).

REFERENCES 1. FSAR, Section [7.3.4].

2. CR-3 EPU Technical Report, Section 2.8.5.6.3.

3. FSAR, Chapter 14.2.2.

Crystal River Unit 3 B 3.3-164 Revision No. XX

[Insert B ICCMS I ICCMS Automatic Actuation Logic B 3.3.20 B 3.3 INSTRUMENTATION B 3.3.20 Inadequate Core Cooling Monitoring System (ICCMS) Automatic Actuation Logic BASES BACKGROUND The ICCMS provides mitigation functions to protect the fuel cladding and limit the amount of energy released in an accident.

The ICCMS actuates the following:

" Fast Cooldown System (FCS),

Reactor coolant pump (RCP) trip, and

Steam Generator (OTSG) Inadequate Subcooling Margin (ISCM) level setpoint adjustment.

The ICCMS is an analog system and consists of three initiation channels for each Function; FCS actuation, RCP trips, and OTSG ISCM level setpoint actuation.

For each Function, three initiation channels provide input to two actuation logic trains. Each actuation logic train is initiated by two-out-of-three ICCMS initiation channels. Either actuation logic train initiates the associated equipment (Ref. 1).

It should be noted that OPERABLE automatic actuation logic trains alone will not ensure that each Function can be activated; the instrumentation channels and actuated equipment associated with each Function must also be OPERABLE to ensure that the Functions can be automatically initiated during an accident. This specification covers only the automatic actuation logic that initiates these Functions. LCO 3.3.19, "Inadequate Core Cooling Monitoring System (ICCMS)

Instrumentation," provides requirements associated with the instrumentation and initiation channels that input to the automatic actuation logic.

Bypass capability is provided for the automatic Crystal River Unit 3 B 3.3-165 Revision No. XX

[Insert B ICCMS I ICCMS Automatic Actuation Logic B 3.3.20 BASES BACKGROUND actuation logic trains to allow for maintenance.

(continued) Bypassing one automatic actuation logic train does not prevent actuation of the associated equipment since the other automatic actuation logic train remains available to each component.

Each of three ICCMS cabinets is independently powered from battery backed vital power sources. If power is lost to an ICCMS initiation channel, both actuation trains of each ICCMS Function receives a trip signal.

If power is lost to an automatic actuation logic train, the actuation logic train to each ICCMS Function fails in the untripped state.

APPLICABLE The following ICCMS Functions have been assumed within SAFETY the accident analyses.

ANALYSES

1. FCS Actuation For a specific range of small break loss of coolant accidents (LOCAs), HPI flow (assuming worse case single failure) by itself may not be sufficient to protect the core. Both ADVs are assumed to actuate following a sustained loss of SCM to cool down the RCS following a small break LOCA when HPI flow is inadequate (Ref. 2). The ICCMS automatically actuates the FCS to support the safety analysis.

In the initiating event, the ICCMS will detect a loss of SCM concurrent with inadequate HPI flow and reactor trip status. Following a sustained loss of SCM and inadequate HPI flow, the ICCMS automatically initiates FCS, which opens both ADVs, to allow rapid RCS cool down.

The FCS and operation of both ADVs are credited with THERMAL POWER > 2609 MWt (pre-EPU power level) to assure sufficient core cooling during a SBLOCA assuming single failure of one HPI subsystem. With THERMAL POWER

2609 MWt, the Emergency Core Cooling System (ECCS) provides sufficient core cooling during a small break LOCA assuming single failure of one HPI subsystem without the need for the FCS and ADVs (Refs. 2 and 3). Requirements associated with the FCS and ADVs are provided in LCO 3.7.20, "Fast Cooldown System (FCS)."

Crystal River Unit 3 B 3.3-166 Revision No. XX

Insert B ICCMS]

ICCMS Automatic Actuation Logic B 3.3.20 BASES APPLICABLE 2. RCP Trip SAFETY ANALYSES The core flood line break analysis requires the (continued) trip of the RCPs within one minute following a sustained loss of SCM in order to minimize the rate of inventory loss which would reduce the time to the core becoming uncovered. In the initiating event, the ICCMS will detect a loss of SCM and reactor trip status. Following a sustained loss of SCM, the ICCMS automatically opens the RCP breakers within one minute (Ref. 2).

3. OTSG ISCM Level Setpoint Actuation Small break LOCA analysis also requires the raising of the OTSG secondary side water level to the ISCM level. This level is necessary in the boiler condenser phase of accident mitigation to promote natural circulation within the RCS. In the initiating event, the ICCMS will detect a loss of SCM and reactor trip status. Following a sustained loss of SCM, the ICCMS within 10 minutes automatically sends a signal to the Emergency Feedwater Initiation and Control (EFIC) System which raises OTSG secondary side level to the ISCM level (Ref. 2).

The ICCMS automatic actuation logic satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).

LCO The ICCMS automatic actuation logic trains for each Function specified in Table 3.3.20-1 are required to be OPERABLE to ensure that a single failure of one train will not result in loss of the ability to automatically actuate the required safety systems.

Each automatic actuation logic train receives input from three ICCMS initiation channels and actuates on a two-out-of-three logic.

Each ICCMS automatic actuation logic train is considered to include the associated ICCMS initiation channel inputs, maintenance bypass switches, time delays, and permissives to ensure the logic train performs its related support function.

Crystal River Unit 3 B 3. 3-167 Revision No. XX

Insert B ICCMS ICCMS Automatic Actuation Logic B 3.3.20 BASES (continued)

APPLICABILITY The ICCMS automatic actuation logic trains are applicable as specified in Table 3.3.20-1.

FCS Actuation Logic The ICCMS automatic actuation logic required to actuate FCS shall be OPERABLE with THERMAL POWER

> 2609 MWt. The FCS and operation of the ADVs are assumed with THERMAL POWER > 2609 MWt. With THERMAL POWER < 2609 MWt, the ECCS provides sufficient core cooling during a small break LOCA assuming a single failure of one HPI subsystem without the need for the FCS function of the ADVs.

RCP Trip Logic The ICCMS automatic actuation logic required to trip the RCPs shall be OPERABLE in MODES 1, 2, and 3 to minimize the rate of inventory loss which would reduce the time to the core becoming uncovered during a LOCA.

In MODES 4, 5, and 6, the plant operating conditions are such that the likelihood of an event occurring that would require ICCMS automatic actuation is low.

OTSG ISCM Level Setpoint Actuation Logic The ICCMS automatic actuation logic required to automatically send a signal to the EFIC System which adjusts the OTSG setpoint to the ISCM level shall be OPERABLE in MODES 1, 2, and 3 to promote natural circulation during the RCS boiler condenser phase of accident mitigation.

In MODES 4, 5, and 6, the plant operating conditions are such that the likelihood of an event occurring that would require ICCMS automatic actuation is low.

ACTIONS A Note has been provided to modify the ACTIONS related to ICCMS automatic actuation logic trains. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition.

Crystal River Unit 3 B 3.3-168 Revision No. XX

Insert MS ICCMS Automatic Actuation Logic B 3.3.20 BASES ACTIONS Section 1.3 also specifies that Required Actions of (continued) the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable ICCMS automatic actuation logic provide appropriate compensatory measures for separate inoperable Functions. As such, a Note has been provided that allows separate Condition entry for each inoperable Function.

A.1 With one or more Functions with one or more automatic actuation logic trains inoperable, the inoperable train must be restored to OPERABLE status within 30 days. The 30 day Completion Time takes into account the provisions to support manual actuation of the FCS, RCP trip, and OTSG ISCM Setpoint adjustment.

The 30 day Completion Time is also considered acceptable based on maintaining FCS actuation capability and the low probability of an event requiring the ICCMS logic during this time period.

B.1 This Required Action directs entry into the appropriate Condition referenced in Table 3.3.20-1.

The applicable Condition referenced in the Table is Function dependent. Each time an inoperable train has not met the Required Action of Condition A and the associated Completion Time has expired, Condition B is entered for that train and provides for transfer to the appropriate subsequent Condition.

Additionally, two inoperable FCS automatic actuation logic trains results in a loss of FCS actuation capability. Therefore, Condition B is entered and provides for transfer to the appropriate subsequent Condition. Automatic FCS actuation capability is considered not maintained when both FCS automatic actuation logic trains are inoperable and untripped.

Crystal River Unit 3 B 3. 3-169 Revision No. XX

linsert B ICCMS ICCMS Automatic Actuation Logic B 3.3.20 BASES ACTIONS C.1 (continued)

If a logic train is not restored to OPERABLE status within the allowed Completion Time, this Required Action specifies initiation of action in accordance with Specification 5.7.2.a, which requires a written special report to be submitted to the NRC. Since several alternate means of manually tripping the RCPs and adjusting the OTSG secondary side water level to the ISCM setpoint are available, the Required Action does not prescribe a plant shutdown, but rather requires following the directions of Specification 5.7.2.a. The special report discusses the results of the root cause evaluation of the inoperability, identifies proposed restorative actions, and provides a schedule for restoring the ICCMS channels to OPERABLE status.

D.1 With the Required Action and associated Completion Time of Condition A not met or automatic FCS actuation capability not maintained, declaring the associated supported feature (i.e., FCS function of the ADVs) inoperable ensures the appropriate Required Actions are performed for the supported feature per LCO 3.0.6.

In this situation (Required Actions and associated Completion Time of Condition A not met or automatic FCS actuation capability not maintained), continued operation at 100% RTP is not appropriate. Therefore, the FCS must be immediately declared inoperable and the appropriate ACTIONS of Specification 3.7.20 performed.

SURVEILLANCE A Note indicates that the SRs for each ICCMS automatic REQUIREMENTS actuation logic Function are identified in the SRs column of Table 3.3.20-1. The various SRs account for individual functional differences and for test frequencies applicable specifically to the Functions listed in Table 3.3.20-1.

Crystal River Unit 3 B 3. 3-170 Revision No. XX

Insert B ICCMS ICCMS Automatic Actuation Logic B 3.3.20 BASES SURVEILLANCE SR 3.3.20.1 REQUIREMENTS (continued) This SR is the performance of a CHANNEL FUNCTIONAL TEST on a 92 day STAGGERED TEST BASIS. The test demonstrates that every automatic actuation logic combination associated with one of the two ICCMS automatic actuation logic trains successfully performs the two-out-of-three logic combinations every 92 days.

All automatic actuation logics are thus tested every 184 days. The test simulates the required two-out-of-three inputs to the logic circuit and verifies the successful operation of the automatic actuation logic.

The outputs of the actuation logic train trip modules are not actuated. Also, the FCS transfer relay is not normally energized with RCS temperature > 200'F.

Therefore, it is not tested by this SR. This is acceptable because the actuation logic downstream of the actuation logic train trip modules is verified by other Technical Specification tests at least once per refueling interval with applicable extensions.

Additionally, to minimize the potential for an unplanned transient the end devices are not actuated during this test. The end devices are tested at least once per refueling interval.

The Frequency is based on engineering judgment of the reliability of the components and minimizing the possibility of inadvertent FCS actuation, RCP trip, or OTSG ISCM level setpoint actuation.

SR 3.3.20.2 This SR demonstrates the OPERABILITY of the automatic actuation logic trains to the actuated component.

This CHANNEL FUNCTIONAL TEST includes the trip of the RCP breakers as a part of this test, overlapping the CHANNEL FUNCTIONAL TEST, to provide complete testing of the associated safety function. The test includes verifying overlap with each automatic actuation logic train tested in SR 3.3.20.1. If a RCP breaker is incapable of automatically opening, the associated automatic actuation logic train would be inoperable.

The 24 month Frequency is based on the need to perform Crystal River Unit 3 B 3. 3-171 Revision No. XX

lInsert B ICCMS ICCMS Automatic Actuation Logic B 3.3.20 BASES SURVEILLANCE SR 3.3.20.2 (continued)

REQUIREMENTS this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Industry operating experience has shown components of this type usually pass the Surveillance when performed at the 24 month Frequency.

SR 3.3.20.3 This SR demonstrates the OPERABILITY of the automatic actuation logic trains to the actuated component.

This CHANNEL FUNCTIONAL TEST includes the OTSG ISCM level setpoint actuation as a part of this test, overlapping the CHANNEL FUNCTIONAL TEST, to provide complete testing of the associated safety function.

The test includes verifying overlap with each automatic actuation logic train tested in SR 3.3.20.1.

If ICCMS is incapable of providing an OTSG ISCM level setpoint actuation signal to the EFIC System, the associated automatic actuation logic train would be inoperable.

The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Industry operating experience has shown components of this type usually pass the Surveillance when performed at the 24 month Frequency.

REFERENCES 1. FSAR, Section [7.3.4].

2. CR-3 EPU Technical Report, Section 2.8.6.5.3.

3. FSAR, Chapter 14.2.2.

Crystal River Unit 3 B 3.3-172 Revision No. XX

RCS Minimum Temperature for Criticality B 3.4.2 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.2 RCS Minimum Temperature for Criticality BASES BACKGROUND The value for the minimum temperature for reactor criticality was established based upon considerations for:

a. operation within the existing instrumentation ranges and accuracies; The Reactor Protection System (RPS) receives inputs from the narrow range hot leg temperature detectors, which have a range of 520°F to 620 0 F. The integrated control system (ICS) controls average temperature (Ta.0) using instrumentation with the same range.

b. making the reactor critical under "hot" RCS conditions.

c. assuring stable reactivity control when reactivity changes are induced by temperature changes during a beginning of core life start-up.

Nominal T vg for making the reactor critical is 532°F.

APPLICABLE There are no accident analyses that specify a minimum SAFETY ANALYSES temperature for criticality, but all low power safety analyses assume initial temperatures near the 525°F limit.

The reactor coolant moderator temperature coefficient used in core operating and accident analysis is typically defined for the normal operating temperature range (532 0 F to -594).

RCS minimum temperature for criticality satisfies Criterion 2 of the NRC Policy Statement.

LCO The purpose of the LCO is to prevent criticality outside the normal operating range (532 0 F to -7o99+) and to prevent operation in an unanalyzed condition.

(continued)

Crystal River Unit 3 B 3.4-6 Amendment No. 149

Pressurizer B 3.4.8 BASES BACKGROUND A minimum required available capacity of 252 kW is based on (continued) total heat loss through the pressurizer insulation and ensures that the RCS can be maintained at hot standby conditions. Inability to control the system pressure and maintain subcooling under conditions of natural circulation flow in the primary system could lead to loss of single phase natural circulation and decreased capability to remove core decay heat.

The 252 kW value is based, in part, on CR-3 pre-operational test data of measured pressurizer heat losses with the RCS at hot standby conditions, a subsequent performance test to validate heat losses, plus some margin for heater and insulation degradation over time. Although 252 kW can be supplied by two full banks of pressurizer heaters, additional heaters can be energized to account for increased heater degradation or pressurizer heat losses, provided no more than 378 kW of heaters is energized from an emergency power source.

Pressurizer heater power supply design provides the capability to supply, from either the offsite power source or either emergency power source (when offsite power is not available), sufficient heater capacity and associated controls. The minimum heater capacity and associated controls are connected to the emergency buses in a manner to provide redundant power supply capability.

APPLICABLE In MODES 1 and 2, the LCO requirement for a steam bubble is SAFETY ANALYSES reflected implicitly in the accident analyses. All analyses performed from a critical reactor condition assume the existence of a steam bubble and saturated conditions in the pressurizer. In making this assumption, the analyses neglect the small fraction of noncondensible gases normally present.

Safety analyses presented in the FSAR do not take credit for However, evaluations to pressurizer heater operation, however, an implicit initial condition assumption of the safety analyses is that the RCS establish the pressurizer water is operating at normal pressure.

level upper limit were performed from atransientpressurizer Conservative safety analyses assumptions for the loss of water level of 290 inches main feedwater (LMFW) event indicate that it produces the (indicated) and furthermore key argest increase of pressurizer level of any moderate input parameters and initial requency event. Thus, this event has been selected to conditions weretassumed at stablish the pressurizer water level upper limit. A-s-um4h*

nominal values. This evaluation - the level limit prevents demonstrated that (continued)

Crystal River Unit 3 B 3.4-38 Revision No. 29

(i.e., 290 inches indicated is Pressurizer the LCO upper limit). B 3.4.8

((paragraphbreak))

Additionally, the...

BASES APPLICABLE water relief through the pressu izer safety valves. Since SAFETY ANALYSIS prevention of water relief is a goal for abnormal transient (continued) operation, rather than an accep ance criterion, the--nm4fta vaue-for the pressurizer level limit is not required to be adjusted for instrument error=- fh-e analysis performed to substantiate the 29 upper limit (Ref. 3) assumed the ireactor trippe on igh RCS pressure n*ss-t-ent--t-1h

.. serIE Had the anticipatory reactor trip (ART) on loss of both feedwater pumps been modeled, the reactor would have tripped much sooner in the event, terminating the nuclear chain reaction

290 ice idctd s the *-theresooner,i s thereby margin in limiting RCS heatup (and insurge).

the* analysis Thus, to subostanti ate the ueof tLCO. upper limit; ** ~ n epa-e-&*~-r4t&r-}e, however additional margin is conservatively applied by

' ses administratively adjusting the limit for 1eve1 measurement

Safetyanalyse. uncertainty (Ref. 4). and energ

mass relas es anintial rsuie performed for he design asils large break loss L* . The pressurizer level assumed

- for the LOC is the partial basis for the volume of reactor massndenrgycoo ant re eased to the containment following the accident.

reesanalysis The containment analysis performed using the mass and energy release demonstrated that the maximum resulting containment d

pressure was within design limits. 1fraiiicevl"Li The requirement for redundant emergency power supplies is based on NUREG-0578 (Ref.coolant 1). The maintaining the reactor in aintent is to condition subcooled allow with natural circulation for an undefined, time period but extended, after a loss of offsite power.

The maximum pressurizer water levely-1-m-i- satisfies Criterion 2 of the NRC Policy Statement. Although the heaters need to are not specifically subcooling inused maintain the inlong accident analysis, term during the loss of offsite power, as indicated in NUREG-0578 (Ref. 1), is the reason for providing a limit on this feature.

LCO For the pressurizer to be OPERABLE, water level must be maintained _i 290 inches and a minimum of 252 kW of pressurizer heaters are to be capable of being powered from each emergency power supply. Limiting the maximum operating water level preserves the steam space for pressure control and ensures the capability to establish and maintain pressure control for steady state operation and to minimize the consequences of potential overpressure transients.

(continued)

Crystal River Unit 3 B 3.4-39 Revision No. 47

Pressurizer B 3.4.8 BASES ACTIONS (conti nued) C.1 and C.2 If pressurizer heater capability or water level cannot be restored within the allowed Completion Time, the plant must be placed in a MODE in which the LCO does not apply. To achieve this status, the plant must be placed in MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 4 within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The Completion Times are reasonable, based on operating experience, to reach the specified MODES from full power conditions in an orderly manner and without challenging plant systems.

In the case of water level, reducing THERMAL POWER and RCS Tave will tend to restore level and also reduce the thermal energy of the reactor coolant mass for potential LOCA mass and energy releases.

SURVEILLANCE SR 3.4.8.1 REQUIREMENTS This SR requires that pressurizer water level be monitored every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months in order to verify operation is maintained below the nominal upper limit. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency has been shown by operating experience to be sufficient to regularly assess the level for deviations and trends, and verify that operation is within -aet-y-analyses assumptions.

Alarms are also available for early detection of abnormal level indications.

SR 3.4.8.2 This SR verifies minimum redundant pressurizer heater capacity is capable of being powered from its associated emergency power supply. (This may be done by testing the power supply output and by performing an electrical check on eater element continuity and resistance.) The Frequency of 24 months is considered adequate to detect heater degradation and has been shown by operating experience to be acceptable.

REFERENCES 1. NUREG-0578, July 1979, "TMI-2 Lessons Learned Task Force Status Report and Short Term Recommendations."

2. NUREG 0737, "Clarification of TMI Action Plan Requirements", November, 1980.

4. Calculation M97-0064,-Rev-iý , "Pressurizer Level vs. Tave for Power Operations."

Crystal River Unit 3 B 3.4-41 Revision No. 47

LTOP System B 3.4.11 BASES APPLICABLE large temperature mismatch between the primary and secondary SAFETY ANALYSES coolant systems, and adding nitrogen to the pressurizer.

(continued)

HPI actuation and CFT discharge are the transients that result in exceeding P/T limits within < 10 minutes, in which time no operator action is assumed to take place. In the rest, operator action after that time precludes overpressurization. The analyses demonstrate that the time allowed for operator action is adequate, or the events are self limiting and do not exceed LTOP limits.

The following are required during the LTOP MODES to ensure that transients do not occur, which either of the LTOP overpressure protection means cannot handle:

a. Deactivating all but one makeup pump;

b. Deactivating HPI; and

c. Immobilizing CFT discharge isolation valves in their closed positions, when CFT pressure is greater than the PTLR limit.

The Reference 3 analyses demonstrate the PORV can maintain RCS pressure below limits when only one makeup pump is actuated. Consequently, the LCO allows only one makeup pump to be OPERABLE in the LTOP MODES.

Inadvertent actuation of HPI can cause the RCS pressure to exceed the LTOP limits determined by Reference 3 sooner than the 10 minutes allowed. Consequently, HPI must be deactivated by assuring that an inadvertent HPI actuation can not inject water into the RCS through the HPI valves.

The isolated CFTs must have their discharge valves closed and the valve power breakers in their open positions. The analyses show the effect of CFT discharge is over a narrower RCS temperature range (208'F and below) than that of the LCO (264°F and below).

Analyses performed per Reference 1 established the temperature of LTOP Applicability at 263°F at the vessel quarter-t location. The LTOP enable temperature of < 264 0 F includes correction for instrument uncertainty. The vessel materials were assumed to have a neutron irradiation accumulation equal to 3- effective full power years (EFPYs) of operation and plan operation is assumed to be in compliance with the RCS\ eatup and cooldown limitations of 27.5 k-A-k-ý(conti nued)

Crystal River Unit 3 B 3.4-52C Amendment No. 183

LTOP System B 3.4.11 BASES REFERENCES 1. ASME Code Case N-514, "Low Temperature Overpressure Protection Section XI, Division 1".

2. Generic Letter 88-11, "NRC Position on Radiation Embrittlement of Reactor Vessel Materials and its Impact on Plant Operations".

3. P* rCi t 1--8-O3,"CR 3 32 EFPY /-r4 -

4. B&W Nuclear Services (FTI) Document 51-1176431-01, 1-"Crystal River 3 Reactor Vessel Low Temperature Overpressure Protection (LTOP)".

CR-3 EPU Technical Report, Section 2.8.4.3.

Crystal River Unit 3 B 3.4-52L Amendment No. 183

The dose analysis (Ref. 7) assumes one gpm primary to secondary LEAKAGE from the RCS Operational LEAKAGE affected OTSG and an Operational LEAKAGE B 3.4.12 of 150 gpd from the unaffected OTSG for the Steam Line Break (SLB) (Ref. 8)._

APPLICABLE that primary to secondary -EAKAGF/ from all steam generators SAFETY ANALYSES (0TSGs) is one gallon per/minute -orincreases to one 9~-

(continued) pe...int as a result of/accident induced conditions. *The LCO requirement to limit primary to secondary LEAKAGE gn-through any one OTSG to ess than or equal to 150 gallons gpm per day, is significantl less than the conditions assumed in the afety analysis. r(gpd The FSAR (Ref. 3) analysis for steam generator tube rupture (SGTR) assumes the contaminated secondary fluid is only briefly released via safety valves and the majority is steamed to the condenser. The -1 pm primary to secondary LEAKAGE safety analysis assumptii is relatively inconsequential in terms of offsite dose.

The safety analysis for the S-team-i-+ne-S-eak {SLB} accident assumes the entire 1 gpm primary to secondary LEAKAGE is through the affected eflte-r-ateG-,s an initial condition (Ref. 4). The dose consequences resulting from the SLBOS accident meet the acceptance criteria defined in 10 CFR The dose analysis 50.67.a assumes one gpm from the affectedOTSGand RCS operational LEAKAGE satisfies Criterion 2 of the NRC 150 gpd from the Policy Statement.

unaffected OTSG (Ref. 7).

LCO RCS operational LEAKAGE shall be limited to:

a. Pressure Boundary LEAKAGE No pressure boundary LEAKAGE is allowed, being indicative of material deterioration. LEAKAGE of this type is unacceptable as the leak itself could cause further deterioration, resulting in higher LEAKAGE.

Violation of this LCO could result in continued degradation of the reactor coolant pressure boundary (RCPB). LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE.

b. Unidentified LEAKAGE One gx1e--pe*--m4rtut-e(-gpm*- of unidentified LEAKAGE is allowed as a reasonable minimum detectable amount that the containment atmosphere and sump level monitoring equipment can detect within a reasonable time period.

Violation of this LCO could result in continued degradation of the RCPB, if the LEAKAGE is from the pressure boundary.

(continued)

Crystal River Unit 3 B 3.4-54 Revision No. 65

RCS Operational LEAKAGE B 3.4.12 BASES LCO c. Identified LEAKAGE (conti nued)

Up to 10 gpm of identified LEAKAGE is considered allowable because LEAKAGE is from known sources that do not interfere with the detection of unidentified LEAKAGE and is well within the capability of the RCS makeup system. Identified LEAKAGE includes LEAKAGE to the containment from specifically known and located sources, but does not include pressure boundary LEAKAGE or controlled reactor coolant pump (RCP) seal leakoff (a normal function not considered LEAKAGE).

Violation of this LCO could result in continued degradation of a component or system.

d. Primary to Secondary V. LEAKAGE through Any One OTSG The limit of 150 l-loens--ped-ay per OTSG is base,5 on the operational LEAKAGE performance criterion in NEI 97-06, Steam Generator Program Guidelines (Ref. 5).

The Steam Generator Program operational LEAKAGE performance criterion in NEI 97-06 states, "The RCS g ,

operational primary to secondaryVAeakage through an' one SG shall be limited to 150 g el5-o pe ." The limit is based on operating experience with OTSG tube degradation mechanisms that result in tube leakage.

The operational leakage rate criterion in conjunction with the implementation of the Steam Generator Program is an effective measure for minimizing the frequency of steam generator tube ruptures.

APPLICABILITY In MODES 1, 2, 3, and 4, the potential for RCPB LEAKAGE or an event that challenges OTSG tube integrity is greatest since the RCS is pressurized. In MODES 5 and 6, LEAKAGE limits and OTSG OPERABILITY are not required because the reactor coolant pressure is far lower, resulting in lower stresses and reduced potentials for LEAKAGE or failure.

LCO 3.4.13, "RCS Pressure Isolation Valve (PIV) Leakage,"

measures leakage through each individual PIV and can impact this LCO. Of the two PIVs in series in each line, leakage measured through one PIV does not result in RCS LEAKAGE when the other is leaktight. If both valves leak and result in a loss of mass from the RCS, the loss must be included in the determination of allowable identified LEAKAGE.

(continued)

Crystal River Unit 3 B 3.4-55 Revision No. 65

RCS Operational LEAKAGE B 3.4.12 BASES SURVEILLANCE SR 3.4.12.1 (continued)

REQUIREMENTS The RCS water inventory balance must be performed with the reactor at steady state operating conditions and with RCS temperature greater than 400'F. The test must be performed prior to entry into MODE 2 if it has not been performed within the past 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months near normal operating pressure.

This surveillance is modified by two notes. Note 1 states that it is not required to be performed for entry into MODE 4 or for non-steady state conditions in MODE 3, but must be performed in MODE 3 above 400'F if 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months of steady state operation are achieved. If the test is not performed prior to all other requirements for entry into MODE 2 being satisfied, entry into MODE 2 must be delayed until steady state operation is established and the requirements of SR 3.0.4 are satisfied.

Steady state operation is required to perform a meaningful water inventory balance; calculations during maneuvering are not useful. For RCS operational LEAKAGE determination by water inventory balance, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP pump seal injection and return flows.

Note 2 states that this SR is not applicable to primary to secondary LEAKAGE because LEAKAGE of 150 a14-T e-if--day cannot be measured accurately by an RCS water inventory balance.gPd The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Frequency is reasonable to trend LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents.

SR 3.4.12.2 _ (OTSG)

This SR verifies tha ,primary to secondary LEAKA is less than or equal to 150 gloen-s-per--d-ay through any one OTSG.

Satisfying the primary to secondary LEAKAGE limi t ensures that the operational LEAKAGE performance trite ion in the Steam Generator Program is met. If this SR i_ not met, compliance with LCO 3.4.16, "Steam Generator Tube gpd Integrity," should be evaluated. The 150 gal-lnspe.F--ay limit is measured at room temperature as described in Reference 6. The operational LEAKAGE rate limit applies to (continued)

Crystal River Unit 3 B 3.4-56 Revision No. 65

RCS Operational LEAKAGE B 3.4.12 BASES SURVEILLANCE SR 3.4.12.2 (continued)

REQUIREMENTS LEAKAGE through any one OTSG. If it is not practical to assign the LEAKAGE to an individual OTSG, all the primary to secondary LEAKAGE should be conservatively assumed to be from one OTSG.

The Surveillance is modified by a Note which states that the Surveillance is not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of steady state operation. For RCS primary to secondary LEAKAGE determination, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows.

The Surveillance Frequency of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is a reasonable interval to trend primary to secondary LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents. The primary to secondary LEAKAGE is determined using continuous process radiation monitors or radiochemical grab sampling in accordance with the EPRI guidelines (Ref. 6).

REFERENCES 1. 10 CFR 50, Appendix A, GDC 30.

2. Regulatory Guide 1.45, May 1973.

3. FSAR, Section 14.2.2.2.

4. FSAR, Section 14.2.2.1.

5. NEI 97-06, "Steam Generator Program Guidelines."

6. EPRI, "Pressurized Water Reactor Primary-to-Secondary Leak Guidelines."

7. CR-3 EPUI Technical Report, Section 2.9.2.

8. rU.S. NRC Regulatory Issue Summary, RIS 2007-020, Implementation of Primary to Secondary Leakage Performance Criteria, August 23, 2007.

Crystal River Unit 3 B 3.4-57 Revision No. 65

RCS PIV Leakage B 3.4.13 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.13 RCS Pressure Isolation Valve (PIV) Leakage BASES DHV-611, and DHV-612 BACKGROUND For the purposes of this Technical Specification, RCS PIVs are defined as any two in-series check valves within the RCS pressure boundary that separate the high pressure RCS from an attached low pressure system, a failure of which, woul cause overpressurization of the low pressure system and a LOCA that bypasses containment. The only valves address d by this Specification are DHV-1, DHV-2, CFV-1, and CFV-3 .

During the valves operating life time, varying amounts of reactor coolant leakage past the valve occurs through either normal operational wear or mechanical deterioration. The RCS PIV Leakage LCO allows RCS high pressure operation when leakage through these valves exists in amounts that do not compromise safety.

The PIV leakage limit applies to each individual valve.

Leakage through both series PIVs in a line must be included as part of the identified LEAKAGE, governed by LCO 3.4.12, "RCS Operational LEAKAGE." This is true during operation only when the loss of RCS mass through two series valves is determined by a water inventory balance (SR 3.4.12.1). A known component of the identified LEAKAGE before operation begins is the least of the two individual leakage rates determined for leaking series PIVs during the required surveillance testing; leakage measured through one PIV in a line is not RCS operational LEAKAGE if the other is leaktight.

Although this Specification provides a limit on allowable PIV leakage rate, its main purpose is to prevent overpressure failure of the low pressure portions of connecting systems. The leakage limit is an indication that the PIVs between the RCS and the connected systems are degraded or degrading. PIV leakage could lead to overpressure of the low pressure piping or components.

Failure consequences could be a loss of coolant accident (LOCA) outside of containment, an unanalyzed accident.

The basis for this LCO is the 1975 NRC "Reactor Safety Study" (Ref. 1). This study identified potential intersystem LOCAs as a significant contributor to the risk (continued)

Crystal River Unit 3 B 3.4-58 Amendment No. 149

RCS PIV Leakage B 3.4.13 BASES (continued)

LCO The LCO PIV leakage limit o#-5--5*pm is based on 0.5 gpm per nominal inch of valve size with a maximum limit of 5 gpm.

Since the- al 4_ - 4hi n the Scope of this

&pee--fi-a*-i-en are located on 10 and 14 inch lines, vavsDV1 H-, -ec-i--i1y 5 the 5 gpm limit is appropriate. Thept~vi~&us CFV-1,1 and cFv-3 *__-* --

__ -- m--fo__--- l1-- -le-_--z s--_____l-a

........... 'nju-st-ifi ed penal ty on the l arger- -- e~-ite*-* -*i Thn-f~a-tewenonpe-te -ta! valve -Zj -erdt-o-l re - e-!4-led-i-n Since DHV-61 1 and Violation of this LCO could result in continued degradation a4inch line, the 2 gpm of a PIV, which could lead to overpressurization of a low limit is appropriate. pressure system and the loss of the integrity of a fission product barrier.

Requiring the ACIS to be OPERABLE ensures the DHR ystem, via the drop line, is protected against design system overpressurization. Both channels of ACIS are required to be OPERABLE to provide redundant diverse means of isolating the decay heat drop line.

APPLICABILITY In MODES 1, 2, 3, and 4, the PIV leakage potential and the need for ACIS is greatest with the RCS pressurized in excess of the limiting DHR System design pressure. In MODE 4, valves in the DHR flow path are not required to meet the requirements of this LCO when in the DHR mode of operation, or during the transition to or from this means of core cooling. This allows the DHR System to be put in service in the lower portions of MODE 4, eliminating the need to operate an RCS loop and reactor coolant pumps all the way down into MODE 5.

In MODES 5 and 6, leakage limits are not required because the lower reactor coolant pressure results in a reduced potential for leakage and for a LOCA outside the containment. In MODES 5 and 6, the reactor coolant system is less likely to experience rapid pressure increases and the magnitude of these increases is less. Thus, ACIS is not required in these MODES.

(continued)

Crystal River Unit 3 B 3.4-60 Amendment No. 149

RCS PIV Leakage B 3.4.13 BASES (continued)

ACTIONS The ACTIONS are modified by two Notes. Note 1 is added to provide clarification that the Conditions of this Specification are entered separately for each flow path.

This is allowed based upon the relative independence of the flow paths as leakage pathways. Note--2 q -*-h Gonditins in*"=*>'*'*of

. .. and . I-e l-i-r-ed-Ac-t-i-ens

... ÷ ____. of 5 Qf ,-_4= systems

_ ..... -- ,-4,,.r bef-ed

ente-r-ed._ ,,*.,,,

Th4--4s-rae asuaredsunltsoato fOae -- lcln-1ew-pth aeE& "da-ee- -teh--thse-R-equ4-r-ed Act i eeu-1 d-res IIn

.n.s , -t-inopral .... iy e f -1 w Pr-essure in'---o.1 Lh ...

.i-s t..--

i-s-the Eas-e----th-pp-~epr-iate Actions-of Specification_ e 3.5.2, I -cdtt 1 11y NEW-I-U-V VV1-t7FtMVL---tH (2 1 e , L=ý=V Note 2 requires an ~~u-weu-n~~t-~t-RE--h*;-+/--hy t-em5n~-eEa evaluation of te DHR . -_ I _- I r~T .. L......-----L1 A

,A,,ý ý ý 4- , C- , - , In R.gzIt:jý_ n JJ...T----L*m lU I tII .if I .4 .JI.J1/4.'.. I I 1/4./*Lt1/4 l l yV I LII 'll1 11/4 . L- .. 4 . . 4 C11./3I lII I-'.11 lJp~l I (3411/4.

System if a PIV or ACIS is inoperable. The leakage may have affected LPI System A.1 and A.2 OPERABILITY, or With one or more flowpaths with leakage from one or more PIV isolation of a leaking in excess of the &--jpm limit, the affected flow path must be flow path with an isolated by two valves in order to continue power operation.

alternate valve may Required Actions A.1 and A.2 are modified by a Note that the have degraded the valves used for isolation must meet the same leakage ability of one or both LPI requirements as the PIVs and must be on the high pressure subsystems to perform portion of the DHR system.

their safety function.

Required Action A.1 requires that the isolation with one valve must be performed within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . Four hours provides time to reduce leakage in excess of the allowable limit or to isolate the affected system if leakage cannot be reduced.

The action to isolate the high pressure portion from the low pressure portion does not apply to the piping leading to the CFTs. This position is consistent with the intent of this LCO to minimize the potential for a LOCA that bypasses containment. Thus, the affected DHR System flow paths are the only ones required to be isolated.

Required Action A.2 specifies that the two valve isolation barrier be restored by closing some other valve qualified for isolation or restoring one leaking PIV. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months (continued)

Crystal River Unit 3 B 3.4-61 Amendment No. 149

RCS PIV Leakage B 3.4.13 BASES ACTIONS A.1 and A.2 (continued)

Completion Time considers the time required to complete the Action and the low probability of a second valve failing during this time period. C-lAs-ng and de aEci-vating-te

,s-odvlvew4--.-e----asse~td-L-PI-s-ubsys4--em B.1 and B.2 If leakage cannot be restored, or the Required Actions accomplished, the plant must be placed in a MODE in which the requirement does not apply.

To achieve this status, the plant must be placed in MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . These Required Actions will tend to reduce the leakage and also the potential for a LOCA outside the containment. The allowed Completion Times are reasonable based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

C.1 Inoperability of one or more channels of ACIS renders DHV-3 or DHV-4 incapable of automatically isolating in response to a high pressure condition and preventing inadvertent opýjnins of the valves at RCS pressures in excess of the DHR ystem (*

design pressure. If the ACIS is inoperable, operation may continue as long as the DHR suction penetration is isolated by at least one closed manual or deactivated automatic valve within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . This action in effect accomplishes the purpose of the autoclosure function.

SURVEILLANCE SR 3.4.13.1 REQUIREMENTS Performance of leakage testing on each RCS PIV is required to verify that leakage is below the specified limit and to identify each leaking valve. T-e-aae-1mI-t--#--5--ipm a,-eý-*e-aci--ve-e (continued)

Crystal River Unit 3 B 3.4-62 Amendment No. 149

RCS PIV Leakage B 3.4.13 BASES SURVEILLANCE SR 3.4.13.1 (continued)

REQUIREMENTS For the two PIVs in series, the leakage requirement applies to each valve individually and not to the combined leakage across both valves. If the PIVs were not individually leakage tested, one valve could have failed completely and not detected provided the other valve in series met the leakage requirement. In this situation, the protection provided by redundant valves would be lost.

The ASME OM Code (Ref. 3) permits leakage testing at a lower pressure differential than between the specified maximum RCS pressure and the normal pressure of the connected system during RCS operation (the maximum pressure differential).

Reference 3 allows this reduced pressure testing for those types of valves in which the higher service pressure will tend to diminish the overall leakage channel opening, e.g.,

check valves. In such cases, the observed rate should be adjusted to the maximum pressure differential by assuming leakage is directly proportional to the pressure differential to the one half power.

The Frequency of testing is a combination of ASME Code and PIV Order requirements.

The Inservice Testing Program implements the ASME OM Code (Ref. 3), cold shutdown performance requirement. This requirement is based on the need to perform this Surveillance under conditions that apply during an outage and the potential for an unplanned transient if the Surveillance were performed with the plant at power.

The Frequency of prior to entering MODE 2 whenever the plant has been in MODE 5 for 7 days or more, if leakage testing has not been performed in the previous 9 months w"s contained in the April 20, 1981 PIV Order (Ref. *6W.It was-intended to provide confidence the valves re-seated following any period of extended operation with flow through the valves. The 7 day value is based on NUREG 1366 recommendations (Ref. 4).

Entry into MODES 3 and 4 is allowed to establish the necessary differential pressures and stable RCS conditions to allow for performance of this Surveillance. The Note (continued)

Crystal River Unit 3 B 3.4-63 Revision No. 79

RCS PIV Leakage B 3.4.13 BASES SURVEILLANCE SR 3.4.13.1 (continued)

REQUIREMENTS that allows this provision is complimentary to the Frequency of prior to entry into MODE 2 whenever the unit has been in MODE 5 for 7 days or more, if leakage testing has not been performed in the previous 9 months.

SR 3.4.13.2 and SR 3.4.13.3 S

Verifying ACIS is OPERAv Lensures that RCS pressure will not pressurize the DHR system beyond its design pressure of 330 psig on the suction side and 450 psig on the discharge side of the pump. The setpoint is adjusted to account for elevation differences between the pressure instrument and the drop line and is set so RCS hot leg pressure must be

< 284 psig to open the valves. This setpoint ensures the DHR design pressure will not be exceeded and the DHR relief valves will not lift. The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage. The 24 month Frequency is also acceptable based on consideration of the design reliability (and confirming operating experience) of the equipment.

REFERENCES 1. NUREG-75/014, Appendix V, October 1975.

2. NUREG-0677, NRC, May 1980.

3. ASME Code for the Operation and Maintenance of Nuclear Power Plants (ASME OM Code).

4. NUREG-1366, December 1992.

6. NRC Order for Modification of License Concerning Primary Coolant System Pressure Isolation Valves dated 4/20/81. Includes Technical Evaluation Report, "Primary Coolant System Pressure Isolation Valves,"

prepared by the Franklin Research Center.

Crystal River Unit 3 B 3.4-64 Revision No. 79

RCS Specific Activity B 3.4.15 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.15 RCS Specific Activity BASES BACKGROUND The limits on specific activity ensure that the doses are within the 10 CFR 50.67 limits during analyzed transients

.. n r and accidents (Ref. 1).

osraie The LCO contains specific activity limits for both DOSE awihaesectot~eEQUIVALIENT 1-131 and gross specific activity.

APPLICABLE The LCO limits nthe specific activity of the reactor SAFETY ANALYSES coolant ensure t at the resulting doses will not exceed the 10 CFR 50.67 dose limits. These values represent reasonable operat ng capability rather than a specific/

lytia Ldfla lesult. RCS specific activity is an input to the dose anal es for a Steam Generator Tube Rupture Main (Ref. 2).

, which ensures that offsite SemLn ra~adLtonLn Brea land Letdown Line Rupture utr Rf )

andcontrolroomdose Line RCS Specific Activity satisfies Criterion 2 of the NRC erlSteam meet the appropriate Pol i cy Statement. f e LCO The specific iodine activity is limited to& pCi/gm DOSE EQUIVALENT 1-131, and the gross specific activity in the primary coolant is limited to the number of pCi/gm equal to 100 divided by E (average disintegration energy of the sum of the average beta and gamma energies of the coolant nuclides in terms of MeV). These values represent a reasonable operating capability rather than a specific analytical result.

Violation of the LCO may result in reactor coolant radioactivity levels that could, in the event of an accident, lead to site boundary doses that exceed the applicable dose limits of 10 CFR 50.67.

APPLICABILITY In MODES 1 and 2, and in MODE 3 with RCS average temperature

> 500'F, the energy in the RCS is sufficient to lift secondary side relief valves in the event of a SGTR.

For operation in MODE 3 with RCS average temperature

< 500'F, and in MODES 4 and 5, the release of radioactivity in the event of an SGTR is unlikely since the saturation pressure of the reactor coolant is below the lift pressure settings of the atmospheric dump valves and main steam safety valves.

(continued)

Crystal River Unit 3 B 3.4-71 Revision No. 37

RCS Specific Activity B 3.4.15 BASES ACTIONS A.1 and A.2 With the DOSE EQUIVALENT 1-131 greater than the LCO limit, the 15 pCi/gm DOSE samples at intervals of 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months sa must be taken to demonstrate EQUVA ENe Tm-3 of- Figure 3D..15 e not exceeded. The limit is Completion Time of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is required to obtain and analyze a sample. Sampling must continue for trending purposes.

The DOSE EQUIVALENT 1-131 must be restored to limits within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months . The Completion Time of 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months limits operation in the Condition, but provides a reasonable time for temporary coolant activity increases (iodine spiking or crud bursts) to be cleaned up with processing systems. As such, the Completion Time is based on engineering judgment.

A Note permits the use of the provisions of LCO 3.0.4.c.

This allowance permits entry into the applicable MODE(S) while relying on the ACTIONS.

B.1 If either Required Action and associated Completion Time of exceeds 1 Condition A is not met or if the DOSE EQUIVALENT 1-131 1 '-i the una.ceptable re gin o Figure 3.. .15-1, the reactor must be placed in MODE 3 with RCS average temperature < 500°F within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The Completion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is required to get to MODE 3 below 500'F without challenging plant systems.

C.1 and C.2 With gross specific activity in excess of the allowed limit, an analysis must be performed within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to determine DOSE EQUIVALENT 1-131. The Completion Time of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is required to obtain and analyze a sample.

(continued)

Crystal River Unit 3 B 3.4-72 Revision No. 55

RCS Specific Activity B 3.4.15 BASES ACTIONS C.1 and C.2 (continued)

In addition, the plant must be placed in MODE 3 with RCS average temperature less than 500'F within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

The 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months action to place the plant in MODE 3 with RCS average temperature < 500°F lowers the saturation pressure of the reactor coolant below the setpoints of the main steam safety valves and the atmospheric dump valves, and prevents venting the OTSG to the environment in an SGTR event. The Completion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is required to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.4.15.1 REQUIREMENTS SR 3.4.15.1 requires performing a gamma isotopic analysis as a measure of the gross specific activity of the reactor coolant at least once per 7 days. While basically a quantitative measure of radionuclides with half lives longer than 15 minutes, excluding iodines, this measurement is the sum of the degassed gamma activities and the gaseous gamma activities in the sample taken. This Surveillance provides an indication of any increase in gross specific activity.

The 7 day Frequency considers the unlikelihood of a gross fuel failure during that time period and is adequate based on operating history.

SR 3.4.15.2 This Surveillance is only required to be performed in MODE 1 since this is when iodine production mechanisms are large enough to yield meaningful Surveillance results. This reqprrTý ýTd-ip events from greater than 15r1-at-ed--t*e**a-powef--(RTP4. This ensures the iodine remL. "mal operation and following fast power changes when the stresses on the nuclear fuel are the greatest. The 14 day Frequency is adequate to trend changes in the iodine activity level considering gross specific activity is monitored every 7 days. The Frequency of between 2 and 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after a (continued)

Crystal River Unit 3 B 3.4-73 Revision No. 37

RCS Specific Activity B 3.4.15 BASES SURVEILLANCE SR 3.4.15.2 (continued)

REQUIREMENTS change of > 15% RTP within a 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months period is established because the iodine levels in the core peak during this time.

If fuel failure were to occur, this period of time would be the most conservative time (levels would be highest) to measure iodine concentration.

A single performance of SR 3.4.15.2 can satisfy Surveillance Requirements for multiple 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months periods of

> 15% RTP power change; providing the sample is obtained and analyzed at a time that meets the 2 to 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months frequency for each hourly period it satisfies.

Changes of > 15% RTP are changes in power of > 15% RTP in one direction. A 8% RTP power increase followed by a 8%

RTP power decrease is not, by itself, a >_ 15% RTP change.

SR 3.4.15.3 SR 3.4.15.3 requires radiochemical analysis for E every 184 days (6 months) with the plant operating in MODE 1 equilibrium conditions. The E determination directly relates to the LCO and is required to verify plant operation within the specific gross activity LCO limit. The analysis for E is a measurement of the average energies per disintegration for isotopes with half lives longer than 15 minutes, excluding iodines. The Frequency of 184 days recognizes E does not change rapidly.

This SR has been modified by a Note that indicates the SR is only required to be performed 31 days after a minimum of 2 EFPD and 20 days of MODE 1 operation have elapsed since the reactor was last subcritical for at least 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months .

This SR 3.0.4 type exception ensures the radioactive materials are at equilibrium so the analysis for E is representative and not skewed by a crud burst or other similar abnormal event.

REFERENCES 1. 10 CFR 50.67.

2. *AR--*-Se t4,_ .- 14.2.2.1, 14. 2..2, -14.2L.-26 Crystal River Unit 3 B 3.4-74 Revision No. 37

OTSG Tube Integrity B 3.4.16 BASES BACKGROUND performance criteria are described in Specification (continued) 5.6.2.10. Meeting the OTSG performance criteria provides reasonable assurance of maintaining tube integrity at normal and accident conditions.

The processes used to meet the OTSG performance criteria are defined by the Steam Generator Program Guidelines (Ref. 1).

APPLICABLE The steam generator tube rupture (SGTR) accident is the SAFETY ANALYSES limiting design basis event for OTSG tubes and avoiding an SGTR is the basis for this Specification. The analysis of condenser prior to reactor a SGTR event assumes a bounding primary to secondary Thereafter, the steam LEAKAGE rate equal to the operational LEAKAGE rate limits in LCO 3.4.12, "RCS Operational LEAKAGE," plus the leakage released from the affected rate associated with a double-ended rupture of a single OTSGisreleasedtothe tube. The accident analysis for a SGTR assumes the environment via main contaminated secondary fluid is only briefly released to steam safety valves and the a e*pi-e a-sa--t L d-the--ýa-o the atmospheric dump -diPget-t--he-mail-E ense*. The valve until the affected OTSG is isolated by the The analysis for design basis accidents and transients operator 7minutes after other than a SGTR assume the OTSG tubes retain their Sreactor trip rattprupture). structural integrity (i.e., they re assumed not toto In these analys-, th steam discharge the atmosphere is based on the total primary to secondar i gpi 7

- afc LEAKAGE froq- OTSGs of one gallon per minuteZr is affected assume to increase to one g-14on-pe*r---m+R+t-e as a result of Insert B3.4.16-1 accident induced conditi F r accidents tha

.involve fuel damage, the primary coolant activity level ofg Iew Paragraph DOSE EQUIVALENT 1-131 is assumed to be ecftiq-a to the LCO H3.4.15, "RCS Specific Activity," limi . For accidents conservative that assume fuel dama e, the rimary oolant activity is a wihunction of t e amount o activity released from the t damaged fuel. The dose consequences of these events are within the limits of GDC 19 (Ref. 2), 10 CFR 50.67 (Ref. 3) or the NRC approved licensing bases (e.g., a small fraction of these limits).

Steam generator tube integrity satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).

LCO The LCO requires that OTSG tube integrity be maintained.

The LCO also requires that all OTSG tubes that satisfy the repair criteria be plugged in accordance with the Steam Generator Program.

(continued)

Crystal River Unit 3 B 3.4-76 Revision No. 83

Insert B 3.4.16-1 for the MSLB only. The Locked Rotor and Control Rod Ejection accident (Ref. 7) assume 150 gallons per day (gpd) per OTSG. The accident induced conditions that result in one gpm primary to secondary leakage are conditions that result in high differential pressure/temperature across the OTSGs tubes. Accident conditions with high tube-to-shell delta temperature and high differential pressure between the primary and secondary sides of the OTSG results in the existing gaps opening and provides sufficient motive force for the primary to secondary leakage to increase to one gpm. These conditions only exist in the MSLB. The Locked Rotor and Control Rod Ejection accidents do no exhibit the thermal-hydraulic conditions that would result in the primary to secondary leakage exceeding the value of 150 gpd per OTSG. Therefore, the primary to secondary LEAKAGE from the unaffected OTSGs for these accidents is assumed to be 150 gpd for the dose analyses (Ref. 7).

OTSG Tube Integrity B 3.4.16 BASES LCO is considered significant when the addition of such loads (continued) in the assessment of the structural integrity performance criterion could cause a lower structural limit or limiting burst/collapse condition to be established." For tube integrity evaluations, except for circumferential degradation, axial thermal loads are classified as secondary loads. For circumferential degradation, the classification of axial thermal loads as primary or secondary loads will be evaluated on a case-by-case basis.

The division between primary and secondary classifications will be based on detailed analysis and/or testing.

Structural integrity requires that the primary membrane stress intensity in a tube not exceed the yield strength for all ASME Code,Section III, Service Level A (normal operating conditions) and Service Level B (upset or abnormal conditions) transients included in the design specification. This includes safety factors and applicable design basis loads based on ASME Code,Section III, Subsection NB (Ref. 4) and Draft Regulatory Guide 1.121 (Ref. 5).

The accident induced leakage performance criterion ensures that the primary to secondary LEAKAGE caused by a design basis accident, other than a SGTR, is within the accident analysis assumptions. The accident analysis assumes that r`eý accident induced leakage does not exceed one ga-o4en-pef gpM m-if-n4e per OTSG. The accident induced leakage rate includes any primary to secondary LEAKAGE existing prior to the accident in addition to primary to secondary LEAKAGE induced during the accident.

The operational LEAKAGE performance criterion provides an observable indication of OTSG tube conditions during plant operation. The limit on operational LEAKAGE is contained in LCO 3.4.12, "RCS Operational LEAKAGE," and limits primary to secondary LEAKAGE through any one OTSG to 150 ga-l-ons-pe-r--da-y. This limit is based on the assumption that a single crack leaking this amount would not propagate to a SGTR under the stress conditions of a LOCA or a main steam line break. If this amount of LEAKAGE is due to more than one crack, the cracks are very small, and the above assumption is conservative.

(continued)

Crystal River Unit 3 B 3.4-78 Revision No. 83

OTSG Tube Integrity B 3.4.16 BASES SURVEILLANCE SR 3.4.16.2 (continued)

REQUIREMENTS The Frequency of prior to entering MODE 4 following a OTSG inspection ensures that the Surveillance has been completed and all tubes meeting the repair criteria are plugged prior to subjecting the OTSG tubes to significant primary to secondary pressure differential.

REFERENCES 1. NEI 97-06, "Steam Generator Program Guidelines."

2. 10 CFR 50 Appendix A, GDC 19.

3. 10 CFR 50.67.

4. ASME Boiler and Pressure Vessel Code, Section III, Subsection NB.

5. Draft Regulatory Guide 1.121, "Basis for Plugging Degraded Steam Generator Tubes," August 1976.

6. EPRI, "Pressurized Water Reactor Steam Generator Examination Guidelines."

ý7. CRý-3EPU ýTechn~ical R~eport, S~ection 2.9.2.

Crystal River Unit 3 B 3.4-82 Revision No. 83

CFTs B 3.5.1 BASES APPLICABLE No operator action is assumed during the blowdown stage of SAFETY ANALYSIS a large break LOCA.

(continued)

The small break LOCA analysis also assumes a time delay after ESAS actuation before pumped flow reaches the core.

For the2 larger range of small breaks (between - 0.2 ft 2 and 0.5 ft ), the rate of blowdown is such that the increase in fuel clad temperature is terminated by the CFTs, with pumped flow then providing continued cooling. As break size decreases (- 0.02 ft2 and 0.2 ft 2 ), the CFTs av&"-44P--pUiuPS both play a part in terminating the rise in clad

,HPIpumps,dump Satmospheric and temperature. As break size continues to decrease, the role valves (ADVs) of the CFTs continues to decrease until the tanks are not required and the HPI pumps, with the help of EFW for steam generator cooling, become responsible for termin ing the temperature increase. a This LCO helps to ensure that the following acceptance criteria for the ECCS established by 10 CFR 50.46 (Ref. 2) will be met following a LOCA:

a. Maximum fuel element cladding temperature of 2200OF;

b. Maximum cladding oxidation of < 0.17 times the total cladding thickness before oxidation;

c. Maximum hydrogen generation from a zirconium water reaction of < 0.01 times the hypothetical amount that would be generated if all of the metal in the cladding cylinders surrounding the fuel, excluding the cladding surrounding the plenum volume, were to react; and

d. Core maintained in a coolable geometry.

Since the CFTs discharge during the blowdown and reflood phases of a LOCA, they do not contribute to the long term cooling requirements of 10 CFR 50.46.

The limits for operation with a CFT that is inoperable for any reason other than the boron concentration not being within limits minimize the time that the plant is exposed to a LOCA event occurring coincident with inoperability of a CFT, which might result in unacceptable peak cladding temperatures. If a closed isolation valve cannot be opened, (continued)

Crystal River Unit 3 B 3.5-3 Revision No. 17

CFTs B 3.5.1 BASES APPLICABLE or the proper water volume or nitrogen cover pressure cannot SAFETY ANALYSIS be restored, the full capability of one CFT is not available (continued) and prompt action is required to place the reactor in a MODE in which this capability is not required.

The minimum volume requirement for the CFTs ensures that both CFTs can provide adequate inventory to reflood the core and downcomer following a LOCA. The downcomer then remains flooded until the HPI and LPI systems start to deliver flow.

The maximum volume limit is based upon the need to maintain adequate gas volume to ensure proper injection, ensure the ability of the CFTs to fully discharge, and limit the maximum amount of boron inventory in the CFTs. Values of 7255 gallons and 8005 gallons are specified.

The minimum nitrogen cover pressure requirement of 577 psia ensures that the contained gas volume will generate discharge flow rates during injection that are consistent with those assumed in the safety analysis. The maximum nitrogen cover pressure limit of 653 psia ensures that the amount of CFT inventory that is discharged while the RCS depressurizes, and is therefore lost through the break, will not be larger than that predicted by the safety analysis.

The minimum boron requirement of 2-2 ppm is selected to ensure that the reactor will remain subcritical during the reflood stage of a large break LOCA. The maximum allowable boron concentration of 3500 ppm in the CFTs ensures that the sump pH will be maintained between 7.0 and 11.0 following a LOCA (Ref. 5).

The numerical values of the parameters stated in the LCO are analysis values and do not include a specific allowance for instrument error. However, the nitrogen cover pressure and tank volume limits were subsequently re-analyzed to address the issue. These re-analyses were performed in order to error-adjust the surveillance procedure acceptance criteria while maintaining an acceptable operating band for the parameter. The nitrogen cover pressure analysis limits include approximately +/- 12 psig allowance for instrument error. Tank volume analysis (Ref. 4) epe-etk-up--t*e provides an uPPe-r--14m*-w operating band byfl*hn-e approximately 7 3O gallonsT al-t-heg--he 750 (conti nued)

Crystal River Unit 3 B 3. 5-4 Revision No. 17

ECCS- Ope rati ng B 3.5.2 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)

B 3.5.2 ECCS-Operating BASES BACKGROUND The function of the ECCS is to provide core cooling to ensure that the reactor core is protected after any of the following accidents:

1. Loss of coolant accident (LOCA);

2. Steam generator tube rupture (SGTR); and

3. Steam line break (SLB).

There are two modes of ECCS operation: injection and recirculation. In the injection phase, all injection is initially added to the Reactor Coolant System (RCS) from the borated water storage tank (BWST). This injection flow is added via the RCS cold legs and core flood nozzles to the reactor vessel. After the BWST has been depleted to < 15 feet but > 7 feet, the ECCS recirculation phase is entered as the ECCS suction is manually transferred to the reactor building emergency surmg.

and =boron precipitation control Two redundant, 100% capacity trains are provided. Each train consists of high pressure injection (HPI) and low isinitiated. pressure injection (LPI) subsystems. In MODES 1, 2, and 3, both trains must be OPERABLE. This ensures that 100% of the core cooling requirements can be provided even in the event of a single active failure.

Certain size small break LOCA scenarios require emergency feedwater-to maintain steam generator cooling until core and atmospheric ecay eat can be removed solely by ECCS cooling.

dump valves (ADVs) ! A suction header supplies water from the BWST or the reactor building emergency sump to the ECCS pumps. Separate piping supplies each train. Each HPI subsystem discharges into each of the four RCS cold legs between the reactor coolant pump and the reactor vessel. Each LPI subsystem discharges into its associated core flood nozzle on the reactor vessel and discharges into the vessel downcomer area. Control valves are set to balance the HPI flow to the RCS. This flow balance directs sufficient flow to the core to meet the analysis assumptions following a small break LOCA in one of the RCS cold legs near an HPI nozzle.

The HPI pumps are capable of discharging to the RCS at an RCS pressure above the opening setpoint of the pressurizer (continued)

Crystal River Unit 3 B 3.5-9 Amendment No. 182

ECCS-Operati ng B 3.5.2 BASES BACKGROUND safety valves. The LPI pumps are capable of discharging to (continued) the RCS at an RCS pressure of approximately 200 psia. When the BWST has been nearly emptied, the suction for the LPI pumps is manually transferred to the reactor building emergency sump. The HPI pumps cannot take suction directly from the sump. If HPI is still needed, a cross connect from the discharge side of the LPI pump to the suction of the HPI pumps would be opened. This is known as "piggy backing" HPI to LPI, and enables continued HPI to the RCS, if needed, after the BWST is emptied to the switchover point.

In the long term cooling period, flow paths in the LPI System can be established to preclude the possibility of boric acid in the core region reaching an unacceptably high r concentration. LI-Ean be-a-l14gned-te-prov-ide-f&---t-we-ae-t-:i-ve met-hed-s--*fhr-a-rd4q-l-u.Aon-. *-I-ne-met-hodPe-deeayhea+/-e nsaerB 3.5.2ý-1 ý -ys-tem- e-op-l-A4e-s-a44gRed--to-t-he-RR-sump-t--a1-l-ow-gvit-y f-ee-fre m--t-h-e -e. The-e-the---met-h con z-i- -+-f

-n*e t~en-o-f-be-r-Go--i-i-u-e-waeP-~-i+-to-he--het-A~-* 1though important to long-term cooling, t-hese flowpa-hs ar-eot considered to be part of the irsuccess Pt §fo-r-ILOCA, SGTR, or SLB mitigation, this

Bo-t4i-a-et-i-ve--me-t-hods-may-b e-a-f-eeted-by--a-fa4-1-u-re--&f-H ver-, --deu-t-e-c-"-e*"a-54t-e rent i n the aa wehdomans-a-te - ffectivess of t-e-se-a1mhods-ieoab-le--asstnr-a-et*-he-c"--re r-ese--a-n-ac-t-v met-hod-befo e-beoee--te-m-er-e Coo4*g ent-s-

£)CFR5-Ape **-a eC-r-4ter4o, "w-l aF

-o pr*ptte "--ýs "O_ ERPlw& -&nted HPI also functions to supply borated water to the reactor core following increased heat removal events, such as large SLBs.

During a large break LOCA, RCS pressure will decrease to

< 200 psi a in < 20 seconds. The ECCS is actuated upon receipt of an Engineered Safeguards Actuation System (ESAS) signal. The actuation of safeguard loads is accomplished in a programmed time sequence. If offsite power is available, the safeguard loads start immediately (in the programmed sequence). If offsite power is not available, the engineered safety feature (ESF) buses shed normal operating loads and are connected to the diesel generators. Safeguard loads are then actuated in the programmed time sequence.

The time delay associated with diesel starting, sequenced loading, and pump starting determines the time required (continued)

Crystal River Unit 3 B 3. 5-10 Revision No. 37

Insert B 3.5.2-1 Boron precipitation control is accomplished via the LPI cross-tie line and the boron precipitation connection, which allows a portion of the LPI flow to be injected into the reactor core through the RCS hot leg. Because this flow will enter the hot leg (via the Decay Heat Removal System drop line) and exit through the break in the cold leg at a lower elevation, the boron concentration in the core will be controlled during the accident. The common hot leg injection (HLI) line is designed with two normally closed parallel safety-related motor-operated isolation valves that are used to initiate and terminate HLI as required during a LOCA.

ECCS- Ope rati ng B 3.5.2 relc`r'ý BASES or LPI sT and LPI LCO Not all portions of the HP lwpatah , y the EGStan (continued) independence criteria discussed above. Sp cificall , t* e HPI flow path downstream of the HPI/Make-pW pumps is not F separable into two distinct trains, and is therefor , not ForLPI, analysis shows independent. This conclusion is based upon analysi which that in the event of a shows, that in the event of a postulated break in t e HPI core flood line break the injection piping, injection flow is required throug a LPI cross-tie line will minimum of three (3) injection legs, assuming one pu p provide some LPI flow to operation, or through a minimum two (2) injection legs, each core flood nozzle assuming two HPI pump operation. When considering their reven with a single failure impact of inoperabilities i thi-s portion f the system, t e of .of twoL

. LPI same concept of maintai n-'4 single activ ilure prote ion subysems.n o must be applied. Wh components become in erable, n

_subsystems. assessment of the Insy-*Iems ability to perfo +t- safety function muste per rmed. If t-he--sys-tem can co inue to these perform itsafety function, wi out assuming a sin e E*j~active ailure, en the 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months loss of redundancy A ONC s is appropriate If the inoperab lity renders the &ys-tem, as is, incapabl of performing its afety function, ithout postulatin a single active fail re, then the p ant is in a condition outside the safet a al sis and must nter LCO and LPI subsystems -

3.0.3 ediately. an EGOS train EGGS train In MODES 1, 2, and 3, an ECCS train consists of an HPI subsystem and an LPI subsystem. Each train includes the piping, instruments, and controls to ensure an OPERABLE flow

'Tfhe LPI subsystem requires path capable of taking suction from the BWST upon an ESAS thIeHLlmotoroperated signal and manually transferring sucp*R to the reactor is olation valves to be closed -building emergency sump.A J*The flowpaxthsiused to establi to ensure adequate LPI flow either active method of boron precipYtA~ion control, iS diuring initial stages of a although important to long-term core cooling, ars-e ot L(OCA. required to be OPERABLE in order to satisfy this LCO.

During an event requiring ECCS actuation, a flow path is provided to ensure an abundant supply of water from the BWST to the RCS via the HPI and LPI pumps and their respective discharge flow paths to each of the four cold leg injection nozzles and the reactor vessel. In the long term, this flow path may be manually transferred to take its supply from the reactor building emergency sump and to supply its flow to the RCS vi-a-t-we-paat-hs* e-..dscribed in--t-he-Bac-kot The flow ath for each train must maintain its designed degree of failure independenc tto can disable both ECCS ensure that no single active trains.

(continued)

Crystal River Unit 3 B 3. 5-13 Revision No. 37

ECCS - Operating B 3.5.2 BASES SURVEILLANCE SR 3.5.2.5 REQUIREMENTS (continued) Verification of the positions of the listed valves in the HPI flowpath ensures adequate flow resistance in the overall system and the individual HPI lines. MaI-neen-an&e e-f-adequa-te-f-ew--es-i-s--amýe--a dpres u-re drop- --- 4e-i .ýJ

-El--p--v-id-ct--e-r--p~-f-fe-w-s-p14-t--be4-ween-4-ni-ec-t-4en-pei n-ts

-a-l--5e,-51--(-e2-)--ph-.'e-a, ascs--t-4-bl-slel of tot-a---E-(C--S f-Te all injection points equal to or above vaue-s E)-t a-s-s-ume~d-i-n te FECS-L-OCA analses; f'2 en~s-u-e-adequ-a-t-e

-i-fl-*g--fw---t- P1-pump-mec~-a--a! seals-; and-(44 prevent--H P-I-pump-f-l-w--fr-om-e--eeei-ng-600-pm-whe-n-t-he

-ys-t-em--*-n-+---s--mni-mu m-fes-i-s-t-ar c-e-eonf=-g w.a-a0-&6OO-jpm 4-s-t-he-ram.um-R --pump--fl-ow r-a-es-es-i-g c--a-lt-P---a-t--i-ore---s-oeei-alew4-i-h- Emer-ge-n*-y-I*4-e-s-e-l--Gene--at-&r 1-&"a 4 tng,*c-S--pu.m~p-a-a-i-Ta l-e-N-P-SH , A M--4a--

,---t--aI--(- N al wable overpressure v..sus level). This 24 month Frequency is acceptable based on consideration of the design reliability of valves that are locked, sealed, or otherwise secured in position.

Verification of correct valve position will be accomplished by assuring the mechanism that locks, seals or secures the valves is intact. if the Stop EheEck**- ves -t--e valves are rcpves ,,, e ,e,,e t thcir correct position and thn secured. This "as left" Pos! crifcto Veo enue he [PT flow asswu-pt-iens-4 e-- c-s de-nt--an-a-l-ysi s -a-c--ma-i-n-taJ-ft-ed--

SR 3.5.2.6 This Surveillance ensures that the flow controllers for the LPI throttle valves will automatically control the LPI train flow rate in the desired range and prevent LPI pump runout as RCS pressure decreases after a LOCA. The 24 month Frequency is acceptable based on consideration of the design reliability (and confirming operating experience) of the equipment.

(continued)

Crystal River Unit 3 B 3.5-18 Amendment No. 182

ECCS-Operati ng B 3.5.2 BASES SURVEILLANCE SR 3.5.2.7 REQUIREMENTS (continued) Periodic inspections of the reactor building emergency sump suction inlet ensure that it is unrestricted and stays in proper operating condition. The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and to preserve access to the location. This Frequency has been found to be nsufficient to detect abnormal degradation and has been confirmed by operating experience.

REFERENCES 1. 10 CFR 50.46.

2. FSAR, Section 6.1.

3. NRC Memorandum to V. Stello, Jr., from R.L. Baer, "Recommended Interim Revisions to LCOs for ECCS Components," December 1, 1975.

4. American Society of Mechanical Engineers, Code for the Operation and Maintenance of Nuclear Power Plants (ASME OM Code).

5. BAW-2295-A, Revision 1, Justification for Extension of Allowed Outage Time for Low Pressure Injection and Reactor Building Spray Systems.

6. FSAR, Section 4.3.10.1.

7. Letterrf#em-NRC-te-FPC, 3N1098-4-5S--datedEt-ober-29 5 998-,

i sunc-e-o#-E-x-empt~e-ffem-t-R-equ,-r-ements oef 1O0-C-FR--SOT, Append*x*-K, S on__t . 1- -- r- i-U-i-t-3--(A e--

IEInformation Notice 87-01, RHR Valve Misalignment Cauýses Degradation of ECOS in PWRs, January 6, 1987.

Crystal River Unit 3 B 3. 5-19 Revision No. 79

Insert B SR 3.5.2.8-1 SR 3.5.2.8 Verification of proper valve position ensures that the LPI cross-tie flow path between LPI trains is maintained. Misalignment of these valves could render both ECCS trains inoperable.

Securing these valves in position by assuring the mechanism that locks, seals or secures the valves is intact ensures that the valves cannot change position as the result of an active failure.

These valves are similar to the type described in Reference 7, which can disable the function of both ECCS trains and invalidate the accident analyses. The 24 month Frequency is acceptable based on consideration of the design reliability of valves that are locked, sealed, or otherwise secured in position. The 24 month Frequency is also based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

BWST B 3.5.4 BASES APPLICABLE positive suction head (NPSH) for the LPI and RB spray pumps.

SAFETY ANALYSIS This NPSH calculation is described in the FSAR (Ref. 1), and (continued) the amount of water that enters the sump from the BWST and other sources is one of the input assumptions. Since the BWST is the main source that contributes to the amount of water in the sump following a LOCA, the calculation does not take credit for more than the minimum volume of usable water from the BWST.

The third factor is that the volume of water in the BWST must be within a range that will ensure the solution in the sump following a LOCA is within a specified pH range (7.0 to 11.0) that will minimize the evolution of iodine and the effect of chloride and caustic stress corrosion cracking on the mechanical systems and components.

Although not related to ECCS, the volume range also ensures that refueling requirements are met and that the capacity of the BWST is not exceeded. Note that the volume limits refer to total, rather than usable, volume required to be in the BWST; a certain amount of water is unusable because of tank discharge line location or other physical characteristics.

T 2-2 ppm limit for minimum boron concentration was established to ensure that, following a LOCA, with a minimum BWST level, the reactor will remain subcritical in the cold condition following mixing of the BWST and Reactor Coolant System (RCS) water volumes. Large break LOCAs assume that all control rods remain withdrawn from the core during the initial phases of the event, particularly blowdown. Long-term shutdown does require the negative reactivity from half or more (cycle-specific) of the rods.

The minimum and maximum concentration limits both ensure that the solution in the sump following a LOCA is within a specified pH range (7.0 to 11.0) that will minimize the evolution of iodine and the effect of chloride and caustic stress corrosion cracking on the mechanical systems and components.

The 3000 ppm maximum limit for boron concentration in the BWST is also based on the potential for boron precipitation in the core during the long term cooling period following a LOCA. For a cold leg break, the core dissipates heat by pool nucleate boiling. Because of this boiling phenomenon in the core, the boric acid concentration will increase in (continued)

Crystal River Unit 3 B 3.5-26 Amendment No. 149

BWST B 3.5.4 BASES APPLICABLE this region. If allowed to proceed in this manner, a SAFETY ANALYSIS point may be reached where boron precipitation will occur in (continued) the core. Post LOCA emergency procedures direct the operator to establish dilution flow paths in the LPI System to prevent this condition by establishing a forced flow path through the core regardless of break location. These procedures are based on the minimum time in which precipitation could occur, aissuming that maximum boron concentrations exist in the borated water sources used for injection following a LOCA. Boron concentrations in the BWST in excess of the limit could result in precipitation earlier than assumed in the analysis.

The 40°F lower limit on the temperature of the solution in the BWST was established to ensure that the solution will not freeze. This temperature also helps prevent boron precipitation and ensures that water injection in the reactor vessel will not be colder than the lowest bounded by temperature assumed in reactor vessel stress analysis. The 100OF upper limit on the temperature of the BWST contents is ce-ons-iet-e -ih the maximum injection water temperature assumed in the Containment Structural analyses. An the of-o " "e M -OWT pefrature rm 9OF--+°e cn ca!EUl "OOT ei---Eewta-t

-5.-&9-psi-q. The upper temperature limit also ensures the BWST temperature assumed in the LOCA analysis is preserved.

A BWST temperature of 120OF has been qualified for core cooling (Ref. 2).

The numerical values of the parameters stated in the SRs are analysis values and do not include allowance for instrument errors.

The BWST satisfies Criterion 3 of the NRC Policy Statement.

LCO OPERABILITY of the BWST ensures that an adequate supply of borated water is available to cool and depressurize the containment in the event of a DBA; to cool and cover the core in the event of a LOCA, to ensure the reactor remains subcritical following a small break LOCA and Steam Line Break; and to ensure an adequate level exists in the containment sump to support ECCS and RB spray pump operation in the recirculation mode. To be considered OPERABLE, the (continued)

Crystal River Unit 3 B 3.5-27 Amendment No. 149

Containment B 3.6.1 BASES BACKGROUND b. Each air lock is OPERABLE, except as provided in (continued) LCO 3.6.2, "Containment Air Locks".

APPLICABLE The safety design basis for the containment is that the SAFETY ANALYSES containment must withstand the pressures and temperatures of the limiting DBA without exceeding the design leakage rate.

The DBAs that result in a challenge to containment from high pressures and temperatures are a loss of coolant accident (LOCA), a steam line break, and a rod ejection accident (REA) (Ref. 2). In addition, release of significant fission product radioactivity within containment can occur from a LOCA or REA. In the analyses of DBAs involving release of fission product radioactivity, it is assumed that the containment is OPERABLE so that the release to the environment is controlled by the rate of containment leakage. The containment was designed with an allowable leakage rate of 0.25% of containment air weight per day (Ref. 3). This leakage rate, used in the evaluation of offsite doses resulting from accidents, is defined in 10 CFR 50, Appendix J, Option B kR-f--Re* , as La: the maximum allowable leakage rate at the calculated maximum peak containment pressure (P.) resulting from the limiting DBA. The allowable leakage rate represented by L forms the basis for the acceptance criteria imposed on all containment leakage rate testing. La is assumed to be 0.25% of wcontainment air weight per day in the safety analysis at with respect to the a psig(Ref.

Scalculated peak The dose acceptance criteria applied to accidental releases containment pressure. of radioactive material to the environment are given in 10 CFR 50.67 (Ref. 5).

The containment satisfies Criterion 3 of the NRC Policy Statement.

(continued)

Crystal River Unit 3 B 3.6-2 Revision No. 37

Containment Air Locks B 3.6.2 BASES APPLICABLE The DBAs analyzed for dose consequences that result in a SAFETY ANALYSES release of radioactive material within containment are a loss of coolant accident (LOCA) and a rod ejection accident (Ref. 2). In the analysis of each of these accidents, it is assumed that containment is OPERABLE so that release of fission products to the environment is controlled by the rate of containment leakage. The containment was designed with an allowable leakage rate of 0.25% of containment air weight per day (Ref. 3). This leakage rate is defined in 10 CFR 50, Appendix J (Ref. 1), as La: the maximum allowable containment leakage rate at the calculated maximum peak containment pressure (P.) following a DBA. This allowable leakage rate forms the basis for the acceptance criteria which is imposed on the SRs associated with the air lock. L is 0.25%

conservative with of containment air weight per day and Pa is 54.2 psig, respect to re&s{l-t-iRg-n--room the limiting design basis LOCA.

The dose acceptance criteria applied to DBA releases of radioactive material to the environment are given in 10 CFR 50.67 (Ref. 4).

The containment air locks satisfy Criterion 3 of the NRC Policy Statement.

LCO Each containment air lock forms part of the containment pressure boundary. As a part of containment, the air lock safety function is related to control of the containment leakage rate resulting from a DBA. Thus, each air lock's structural integrity and leak tightness are essential to the successful mitigation of such an event.

(continued)

Crystal River Unit 3 B 3.6-7 Revision No. 37

Containment Pressure B 3.6.4 B 3.6 CONTAINMENT SYSTEMS B 3.6.4 Containment Pressure BASES BACKGROUND The containment pressure is limited during normal operation to preserve the initial conditions assumed in the accident analyses for a loss of coolant accident (LOCA) or steam line break (SLB). These limits also prevent the containment pressure from exceeding the containment design negative pressure differential with respect to the outside atmosphere in the event of inadvertent actuation of the Reactor Building Spray System.

Containment pressure is a process variable that is monitored and controlled. The containment pressure limits are derived from the input conditions used in the containment functional analyses and the containment structure external pressure analysis. Should operation occur outside these limits coincident with a Design Basis Accident (DBA), post accident pressures could exceed calculated values.

APPLICABLE Containment internal pressure is an initial condition used SAFETY ANALYSES in the DBA analyses to establish the maximum peak containment internal pressure. The limiting DBAs Tconsidered, relative to containment pressure, are the LOCA ein tpressurecondition and SLB. The worst-case LOCA generates larger mass and cusedaintheLOCA s energy release than the worst-case SLB. Thus, the LOCA containment analysis was event bounds the SLB event from the containment peak 16.2.psa(1.5psig) and pressure standpoint (Ref. 1).

e initial pressure condition used in theontainment with The LOCA analysis was 17.7 psia (3.0 psig). O 5- -Teed-i-n--a containment analysis maximum peak pressure f-Fem-a--60CA o 5.-2 psig. The LCO resulted in a higher 1 limit o f3r. psig ensures that, in the event of an peak pressure with a... E accident, the design pressure of 55 psig for containment is Wnot exceeded. In addition, the building was designed foeva*

'nternal pressure equal to 3 psig above external pressure e ve during a tornado. The containment was also designed for a negative internal pressure below external pressure, to withstand the resultant pressure drop from an accidental actuation of the Reactor Building Spray System. The pressure drop has been evaluated for operating within LCO 3.6.4 Containment pressures and the resulting pressure drop due to building spray actuation was found to be acceptable.

(continued)

Crystal River Unit 3 B 3.6-29 Revision No. 30

Containment Air Temperature B 3.6.5 BASES APPLICABLE the LOCA analysis, the reactor building design condition SAFETY ANALYSES will not be exceeded. = =

(continued) with respect to temperature The LOCA that was identified as preslentingthhegreatest double end rupture of challenge to containment OPERABILIT Vwas a ee-ld leg ,R-e-aýctew System hot leg near E ant e p ......

SUE--

the steam generator.

teContainment average air temperature satisfies Criterion 2 of the NRC Policy Statement.

LCO During a DB , with an initial containment arithmetic average air temperature less than or equal to the LCO temperature limit, the resultant peak accident temperature is maintained below the containment design temperature. As a result, the ability of containment to perform its design function is ensured.

The numerical limit in the LCO has not been adjusted to account for instrument error.

APPLICABILITY In MODES 1, 2, 3, and 4, a DBA could cause a release of radioactive material to containment. In MODES 5 and 6, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES.

Therefore, maintaining containment average air temperature within the limit is not required in MODE 5 or 6.

ACTIONS A.1 When containment average air temperature is not within the limit of the LCO, it must be restored within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . This Required Action is necessary to return operation to within the bounds of the containment analysis. The 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time is acceptable considering the sensitivity of the containment analysis to variations in this parameter and provides sufficient time to correct minor problems.

(continued)

Crystal River Unit 3 B 3.6-33 Amendment No. 149

Reactor Building Spray and Containment Cooling Systems B 3.6.6 BASES BACKGROUND Containment Cooling System (continued)

Upon receipt of a high reactor building pressure ES signal (4 psig), the two operating cooling fans running at high speed will automatically stop. One cooling unit fan will automatically restart and run at low speed, provided normal or emergency power is available. In post accident operation following an actuation signal, one Containment Cooling System fan will start automatically in slow speed if one is not already running. If the lead fan fails to start or trips, a second fan will automatically start in slow speed.

A fan is operated at the lower speed during accident conditions to prevent motor overload from the higher density atmosphere. The automatic changeover valves operate to provide Nuclear Service Closed Cycle Cooling (SW) System flow to the cooling units and isolate the CI System flow.

APPLICABLE The RB Spray System and Containment Cooling System limit the SAFETY ANALYSES temperature and pressure that could be experienced following Ta DBA. The limiting DBAs considered are the loss of coolant accident (LOCA) and the steam line break. The postulated considered in the DBAs are analyzed, with regard to containment ES systems-analyses. Onecase ia-s-s' the loss of one ES bus. This is the w -ase considered s-igl a.tiv. fa...... resulting in one train of the RB Spray System and one train of the Containment Coolin System The second case being inoperable. 278.9 54.0 considered the loss of The analysis and evaluation show that, under the worst-case all RB cooling trains, scenario, the highest peak co ainment pressure is -542 psig resulting in two RB (experienced during a LOCA). The analysis shows that the spray trains available peak containment temperature is2-7-8.4°F (experienced during to limittemperature a LOCA). Both results are less than the design values.

and aLCO pressure. (See the Bases for LCO 3.6.4, "Containment Pressure," and 3.6.5, "Containment Air Temperature," for a detailed discussion.) The analyses and evaluations assume a power level of -&J"9- MWt, one RB spray train and one RB cooling train operating, and initial (pre-accident) conditions of 130°F and + psia. The analyses also assume a response time delayed initiation to provide conservative peak E- -calculated ontainment pressure and temperature responses.

16.2 (conti nued)

Crystal River Unit 3 B 3.6-37 Revision No. 83

Reactor Building Spray and Containment Cooling Systems B 3.6.6 BASES APPLICABLE The effect of an inadvertent RB spray actuation has also SAFETY ANALYSIS been analyzed. An inadvertent spray actuation results in a (continued) 2.5 psig containment pressure drop and is associated with the sudden cooling effect in the interior of the leak tight containment. Additional discussion is provided in the Bases for LCO 3.6.4.

The modeled RB Spray System actuation from the containment analyses is based on a response time associated with exceeding the RB pressure High-High setpoint coincident with a high pressure injection start permit actuation signal to achieve full flow through the containment spray nozzles.

The Containment Spray System total response time of 90 seconds includes emergency diesel generator (EDG) startup (for loss of offsite power), block loading of equipment, spray pump startup, and spray line filling (Ref. 2).

The analysis results also indicate that with Containment cooling train performance for post accident Sno RB cooling trains conditions is given in Reference 3. The result of the analysis is that one train of RB cooling will contribute OPERABLE, two trains sufficient peak cooling capacity during the post accident 0of RB spray will condition in conjunction with one RB spray train to successfully limit peak successfully limit pea 'cQtainment pressure and temperature containment pressure to less than design value-. The train post accident cooling capacity under varying containment ambient conditions, Land temperature to less required to perform the accident analyses, is also shown in than design values. Reference 4.

The modeled Containment Cooling System actuation from the containment analysis is based on a response time associated with exceeding the containment pressure high setpoint to achieve full Containment Cooling System air and safety grade cooling water flow. The Containment Cooling System total response time of 25 seconds includes signal delay, EDG startup (for loss of offsite power), and service water pump startup times (Ref. 3).

The Reactor Building Spray System and the Containment Cooling System satisfy Criterion 3 of the NRC Policy Statement.

LCO During a DBA, a minimum of one containment cooling train and one RB spray train are required to maintain the containment peak pressure and temperature below the design limits.

Additionally, one RB spray train is required to remove (continued)

Crystal River Unit 3 B 3.6-38 Revision No. 34

MSSVs B 3.7.1 B 3.7 PLANT SYSTEMS B 3.7.1 Main Steam Safety Valves (MSSVs)

BASES BACKGROUND The principal function of the main steam safety valves (MSSVs) is to provide overpressure protection for the Main Steam (MS) System. In doing so, the MSSVs also provide a heat sink for removal of energy from the Reactor Coolant System (RCS) should the preferred heat sink provided by the main condenser and Circulating Water System not be available.

There are a total of 16 MSSVs, four located on each main steam line upstream of the main steam isolation valves within the intermediate building. The MSSV capacity and pressure relief setpoints are determined in accordance with Section III of the ASME Boiler and Pressure Vessel Code, 1971 Edition (Ref. 1). This Code specifies that sufficient relief capacity must be provided to prevent transient pressures from exceeding 110% of the MS System design pressure. Additionally, the Code requires that at least one MSSV be set at or below the MS System design pressure.

Therefore, the lowest relief setpoint valves (two per OTSG) are set at 1050 psig. The remaining MSSVs are set at staggered lift setpoints up to 1100 psig so that only the number of valves needed to provide relief capacity will be actuated. The use of staggered setpoints also reduces the potential for valve chattering and provides for a more controlled release of steam than would occur if all MSSVs actuated at the same pressure.

The MSSVs are designed to be capable of relieving approximately 11.9 million lbm/hr steam at the MS System design pressure of 1050 psig. This relief capacity *s app3r-exrm-4e1-122 % of the 1S-1s-t-em-desi-ng-f~lew--fate, provides *pr-evi-d4-n~g allowance for the nuclear overpower trip setting and associated instrument error (Ref. 2). At 1145 psig, all MSSVs are expected to be open providing a total relief capacity of 13 million lbm/hr whi-c-h-s-appr-exim-týý

-f--- t-et-s c-d s~~-~ea*

-w-a-t--RAT-ED-THERMA-L--0WE-R.

Fourteen of the 16 MSSVs are identical in design, having only relief setpoint differences. Each of these valves has an orifice size of 4.515 inches and a relief capacity of (continued)

Crystal River Unit 3 B 3.7-1 Amendment No. 149

MSSVs B 3.7.1 BASES BACKGROUND 845,759 Ibm/hr at design conditions. The remaining two (continued) MSSVs (MSV-40 and MSV-48) provide less relief capacity than the others, having a flow orifice of 3.750 inches and a relief capacity of 583,574 ibm/hr at design conditions.

APPLICABLE The design basis of the MSSVs is established by the ASME SAFETY ANALYSIS Code and is to provide overpressure protection for the MS System and steam generators (OTSGs). The events which challenge the MSSV relieving capabilities are those resulting in decreased RCS heat removal. Typical events analyzed include:

0 Turbine generator trip (Ref. 3) 0 Loss of offsite power (Ref. 4) 0 Loss of main feedwater (Ref. 5) 0 Steam generator tube rupture (Ref. 6)

Of these events, the transient which results in the largest pressure spike and therefore the most severe challenge to the MSSV relief capacity was the turbine generator trip (Ref. 3). For this event the overpressure protection analysis assumed that the plant was operating just under the nuclear overpower reactor trip setpoint and the turbine bypass valves did not actuate (Ref. 7). The OPERABILITY of the MSSVs was required to prevent the MS System from exceeding 110% of system design pressure.

MSSV relief capacity is adequate to prevent MS System overpressurization eve ,-ey o e-t--

open following the most severe transient analyzed (Ref. 2-).

The MSSVs satisfy Criterion 3 of the NRC Policy Statement>. I-LCO The MSSV setpoints are established to prevent overpressurization as discussed in the Applicable Safety Analysis section of these Bases. The LCO requires a varying secondary side relief capacity (number of MSSVs required to be OPERABLE) dependent on power level and nuclear overpower trip setpoint. Additionally, one valve on each OTSG must have a lift setpoint of 1050 psig (+/- 3%) in order to meet Code requirements. Two valves are set to a nominal lift (continued)

B 3.7-2 Amendment No. 149 Crystal River Unit Crystal River Unit 3 3 B 3.7-2 Amendment No. 149

MSSVs B 3.7.1 BASES (continued)

ACTIONS The ACTIONS table is modified by a Note indicating that separate Condition entry is allowed for each MSSV.

A.1 and A.2 An alternative to restoring the inoperable MSSV(s) to OPERABLE status is to reduce power so that the available MSSV relief capacity meets ASME Code requirements for the existing power level. Operation may continue, provided the THERMAL POWER and RPS nuclear overpower trip setpoint are reduced by the application of the following formulas:

Y RP =- X 100%

z and SP =- X W where:

RP = Reduced power limit (not to exceed RTP);

SP = Nuclear overpower trip setpoint (not to exceed W);

W= Nuclear overpower trip setpoint for four pump operation as specified in Table 3.3.1-1 of LCO 3.3.1, "Reactor Protection System (RPS)";

Y= Total OPERABLE MSSV relief capacity per OTSG based on a summation of individual OPERABLE MSSV relief capacities per OTSG (Ibm/hour); and Z = Required relief capacity per OTSG of 6,160,000 lbm/hour at1-12%o-ef-fRTP (Ref. 7).

The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time for Required Action A.1 is a reasonable time period to reduce power level and is based on the low probability of an event occurring during this period that would require activation of the MSSVs. An additional 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months is allowed for Required Action A.2 to reduce the RPS nuclear overpower trip setpoints.

(continued)

Crystal River Unit 3 B 3.7-4 Amendment No. 149

MSSVs B 3.7.1 BASES SURVEILLANCE SR 3.7.1.1 (continued)

REQUIREMENTS The ANSI/ASME Standard requires the testing of all valves every 5 years, with a minimum of 20% of the valves tested every 24 months. Reference 8 provides the activities and frequencies necessary to satisfy the requirements.

Table 3.7.1-1 allows a +/- 3% setpoint tolerance for OPERABILITY; however, valves removed for maintenance or testing are required to be reset to +/- 1% following re-installation in order to allow for drift. Administrative limits on the as-left low-end MSSV setpoint (i.e. 1050 psig,

-1%) have been established to reduce the probability of an inadvertent opening of the valve during normal plant operation.

This SR is modified by a Note that provides an SR 3.0.4 type exception and allows entry into and operation in MODE 3 prior to performing the SR. The MSSVs may be either bench tested or tested in situ at hot conditions using an assist device to simulate lift pressure. If the MSSVs are not tested at hot conditions, the lift setting pressure is corrected to ambient conditions of the valve at operating temperature and pressure.

REFERENCES 1. ASME, Boiler and Pressure Vessel Code, Section III, Article NC-7000, 1971.

2. B&W Document 51-1174336-00, March 2, 1989.

3. FSAR, Section 10.3.5.

4. FSAR, Section 14.1.2.8.

5. FSAR, Section 14.2.2.9.

6. FSAR, Section 14.2.2.2.

7. SER on Amendment 77, dated April 25, 1985.

8. ASME Code for the Operation and Maintenance of Nuclear Power Plants (ASME OM Code).

9. Deleted.

10. B&W Document 86-1219188-00.

Crystal River Unit 3 B 3.7-6 Revision No. 79

MSIVs B 3.7.2 B 3.7 PLANT SYSTEMS B 3.7.2 Main Steam Isolation Valves (MSIVs)

BASES BACKGROUND The principal function of the main steam isolation valves (MSIVs) is to isolate steam flow from the secondary side of the steam generators (OTSGs) following a steam line break (SLB). A transient such as increased steam flow through the turbine bypass valves causing low steam generator pressure would also be terminated by closure of the MSIVs.

One MSIV is located in each of four main steam lines outside, but close to, containment. The MSIVs are located downstream of the main steam safety valves (MSSVs) and steam supply lines to the emergency feedwater (EFW) pump turbine to prevent isolation of these critical steam loads in the event of MSIV closure. Closure of the MSIVs isolates the OTSGs from the turbine, turbine bypass valves, and other auxiliary steam loads.

The MSIVs are spring actuated, pneumatically-operated valves which are opened/assisted-closed by instrument air pressure (Ref. 1). These valves close on receipt of a main steam line isolation signal generated by the Emergency Feedwater Initiation and Control (EFIC) System based upon low OTSG pressure. The main steam lines can also be manually isolated from the control room.

A description of the MSIVs is contained in FSAR, Section 10.2.1.4 (Ref. 2). In isolating the main steam lines, the MSIVs satisfy 10 CFR 50 Appendix A General Design Criteria (GDC) 57 requirements for isolation of closed system lines which penetrate containment (Ref. 3).

APPLICABLE The SLB analysis -

SAFETY ANALYSIS sys-c-em-*r-nd-as i-ated en-s-e--tes- Thi-s--

doc-ume- ted n-AR-EA-Eng-ncer-i-n Informat-i-o-Rec-oR-*d---- r ep ff -nai-ys--s, EFIC isolation of ain Feedwater and Main Steal e-es~e~ " -. The require s-t-r-oke time of the MSIVs is six second, which includes an EFIC signal process delay and from the time t valve closure/ -r-em--t4+e time of--OT-SG%--ow-p-r-ess*u-r-ef--5.9-5 we ts tonT a ps 4-g. The required ITS EFIC actuation on OTSG low pressure is Ci a1s ea ressureiscE rvat greater than or equal to 600 psi . The T-owe-F anal sis stylower than 600 psig.

(conti nued)

Crystal River Unit 3 B 3.7-7 Revision No. 83

MSIVs B 3.7.2 BASES APPLICABLE There are several reasons why all MSIVs are isolated on an SAFETY ANALYSIS EFIC MS isolation, including those on the intact generator.

(continued) Restricting the blowdown to a single OTSG is necessary to limit the positive reactivity effects associated with the resulting Reactor Coolant System (RCS) cooldown, as well as to prevent containment overpressurization in the event of a break within the reactor building coincident with the failure of feedwater to isolate. (Ref. 4). Additionally, MSIV closure ensures that at least one OTSG remains available for RCS cooldown and capable of supplying steam to the turbine driven EFW pump.

Several SLB variations are considered in the accident analysis. Steam line isolation prevents a single break from affecting both OTSGs, allowing the unaffected OTSG to be used for RCS heat removal. A controlled cooldown can then be maintained, through operation of the EFW system and steam relief through the atmospheric dump valves or turbine bypass valves.

In the event of a single MSIV failure coincident with an SLB accident, closure of the three remaining MSIVs will prevent continued, simultaneous blowdown of both OTSGs. Thus, the accident analysis has shown the SLB can be mitigated even with the failure of a single MSIV.

In contrast with the postulate SLB events, the MSIVs are assumed to be open following steam generator tube rupture (SGTR) accident. Followin SGTR, activity and inventory contained within the RCS eaked into the MS System, where l-s

+-i-t- then available for release to the environment. In the evaluation of offsite dose following a SGTR, the turbine bypass valves (TBVs) were used to establish and maintain RCS cooldown, directing the leaked reactor coolant to the condenser. Within the condenser, a partial removal of iodine was considered, effectively reducing the total quantity of radioactivity contributing to the post-accident offsite dose. Although the resultant offsite dose is predicted to be c-s-ie-s T-ab1-y less than the guidelines of 10 CFR 50.67, the ability to maintain the MSIVs open is essential to keeping offsite doses within analyzed values (Ref. 5).

The MSIVs satisfy Criterion 3 of the NRC Policy Statement.

(continued)

Crystal River Unit 3 B 3.7-8 Revision No. 37

B 3.7.3 BASES APPLICABLE Closure of the MFIVs terminates the addition of feedwater to SAFETY ANALYSES an affected OTSG. This limits the mass and energy releases for breaks within containment, reduces cooldown effects, and reduces the potential for a return to power due to a return to critical following reactor trip.

The SLB analysis n I

&teM&i-i-andtir a~ss.-- atd rv se t4mes . -Th4-s--4s. response doeu-men e... ... I C-4 er,_,_

, I ,_,'-f-n, tci-o -eneEO... ..

Systems 9I-O-7T--OO0, "CR 3oROTSC Sp&i.-t ec-sedc- DoE- Iff t EFIC isolation of ain Feedwater and Main Stea rwe-re E-e*d4 . The require s-t--ree time of the MFIVsT assumed from the time e-x-eep- foer the- !oew-1;ad bl -kval' e ,o d-WV--2, is of the OTSG low 34--sec-a*& which includes an EFIC signal process delay and rpressure actuation valve closure f-r-em-+-the time ef--GT-SG--ew-p I signal, ..... . psg. The actual EFIC actuation on OTSG low pressure is greater than or equal to 600 psig. The -Twe-r analysis pressure is conscr-ative. The low loal;adcblock--va-s *WV-31 and FWV-3 re rtequire to s5-aek-e close in 67 seconds conservatively lower +fl n-E-F-IG.,ai- d r--eay-a-&nd--

[than 6:00 psig.T The MFIVs satisfy Criterion 3 of the NRC Policy Statement.

assumed LCO This LCO ensures that the MFIVs will isolate MFW flow to the OTSGs following a FWLB or a main steam line break. The following valves are addressed by this LCO:

OTSG A OTSG B FWV-14 and FWV-15 are assumed to close in FWV-30 Main block valve FWV-29 20 seconds. FWNV-28, FWV-31 Low load block valve FWV-32 FVVV-29, FVVV-30, FWV-36 Startup block valve FWV-33 FVVV-33, and FWV-36 FWV-14 MFW pump suction valve FWV-15 are assumed to close in 31 seconds.

FWV-28 MFW cross connect valve (continued)

Crystal River Unit 3 B 3.7-14 Revision No. 83

MFIVS B 3.7.3 BASES ACTIONS B.1 and B.2 (continued)

With one or more flow paths not capable of isolating within the required isolation time, action must be taken to restore one valve to within the required closure time or to isolate the affected flow path. The Required Actions are the same as those specified in Condition A of this Specification, except the Completion Time for B.1 is reduced to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time reflects analysis that demonstrated reduced stroke times will not likely challenge the containment analysis. However, the level of degradation represented by this Condition is considered more serious than Condition A.

When in Condition B, the Required Actions of Condition A are also applicable.

C.1 With two inoperable valves in the same flow path, valve isolation capability has been lost. Under these conditions, at least one of the affected valves in each flow path must be restored to OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . The 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time is reasonable, based on operating experience.

AGTI-N-S D.1

,{Eenti ed With a startup block valve (FWV-33,-36) in one or more flow paths inoperable, action must be taken to restore the affected valves to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . In this Condition, valve closure or isolation is not an acceptable alternative action because the ICS controlled startup control valves are necessary to provide and control main feedwater following a reactor trip. Closure of the startup block valves would preclude this function post-trip and potentially challenge Emergency Feedwater System operation.

(continued)

Crystal River Unit 3 B 3.7-17 Revision No. 1

MFIV-S B 3.7.3 BASES ACTIONS D.1 (continued)

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time takes into account the redundancy afforded by the remaining OPERABLE valve in the flowpath, the MFW ump trip feature provided on low OTSG pressure, and the low probability of an event occurring during this time period that would require isolation of the MFW flow paths.

E.1 and E.2 If the MFIVs cannot be restored to OPERABLE status, or closed, or isolated within the associated Completion Time, the plant must be placed in a MODE in which the LCO does not apply. To achieve this status, the plant must be placed in at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in MODE 4 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.7.3.1 REQUIREMENTS This SR verifies that MFIV closure time is within the acceptance criteria in the Inservice Testing Program. 4-n MFIV isolation times -ere-r--t-e-eons4-i--ea-t--, he safe-eP l-ys4-sas are assumed in the oc-ume.R-EV-

r-i-g--I-fer-ma-tin-R-eeer-d-5-1--

accident and 1 Ou V0 7 5e-0SG-Suppert- -- e4m -Seepe-DOE." h containment analyses. -

bWek-k val- es- 132,an iWs 33!

-em--t-he--te--ef--OT-SG-l-ew-pese-e-o-9"-"5--gi. The a-et-u-1.

t--a-----

I e r ----

*f-

__ s sw r--t-s -

ee-ense-ve-0-.e-.-T-he l-ew lead bleek val vCs -FWv31 n---d-FWV-32 e-e-qu-red-le strokc cl-e in 7 s"nel-des Surveillance is normally performed upon returning the plant operation following a refueling outage. The MFIVs should I t be tested at power since even a part stroke exercise Urreases the risk of a valve closure, and the risk of a plant transient with the plant generating power. As these valves are not tested at power, they are exempt from the ASME OM Code (Ref. 3) quarterly valve stroke requirements.

This SR is modified by a Note that allows entry into and operation in MODE 3 prior to performing the SR. This allows delaying testing until MODE 3 in order to establish the test conditions mostrepresentative of those under which the acceptance criterion was generated.

(continued)

Crystal River Unit 3 B 3.7-18 Revision No. 83

'S PAGE INTENTIONALLY LEFT EWANK Unit 3 B 3.7-18B

TBVs B 3.7.4 B 3.7 PLANT SYSTEMS B 3.7.4 Turbine Bypass Valves (TBVs)

BASES BACKGROUND The TBVs provide a method for cooling the plant to Decay Heat Removal (DHR) System entry conditions via the main condenser. Following an accident, this is done in conjunction with the Emergency Feedwater (EFW) System, providing flow from the EFW tank (EFT-2). There are four air-operated TBVs, two per steam generator (OTSG). The 5.68 TBVs are located downstream of the main steam isolation valves (MSIVs) and other remote power-operated isolation valves to permit the valves t be isolated if necessary.

0 ach TBV is sized to pass .3-7-5%of rated main steam flow

(*JI O lbm/hr at normal steam conditions) and combined,

-1&

the valves are capable of cooling down the plant at the design rate of 100°F/hour (Ref. 1). All four TBVs are controllable from the Main Control Board as well as local manual at the valves themselves. The TBVs are not available following a loss of offsite power (LOOP) due to the loss of the Circulating Water System and eventually the condenser. However, the licensing basis for the Steam Generator Tube Rupture (SGTR) accident does not require a LOOP be assumed.

th~e even-, of a LOOP, -te 1 MphE-IDU

.A /-alves--ADVS}

weu~d-be - -eI~4-ed--u-pn4e-e- &rmt~-cG~aysd~e 1 1%R--5O--6-7 ffi-ts.- -Hevwev, h cfst dose weufl-be Tfin-AD-h-i-gr--ant~-e--a-i--p--te avs-seei-atd-wit h-a TB'm bp ed valrolers to-pav-ed-w-t4--ctrol of-~ p y---e-f-betnrt-le. The epert-~e-the--ADVon--&e--~en--o"es-ste-Rimia4

&u-f-f4-cten t preFsu riz-e-as-e -Fpate the Dsfrte-hourns, the tie ý GeADV-t-e--Fi-4-e-Ruj3-th-e-r-wdi-othe-i-a- P-a---censequc-d-e-s--i-§1-ta-n 1i Ee n-s -5 55 enawr-i-o-(continued)

Crystal River Unit 3 B 3.7-19 Revision No. 37

TBVs B 3.7.4 BASES (continued)

APPLICABLE The TBVs are assumed to be used by the operator to cool down SAFETY ANALYS 'IS the plant following the design basis SGTR event (Ref. 2).

The initiating event is a double-ended rupture of a single OTSG tube, resulting in a primary to secondary leak rate ef 43-5--"pm; too large for normal makeup to compensate. RCS pressure decreases to the Reactor Protection System (RPS) low-pressure trip setpoint and the reactor is automatically shut down. In turn, the turbine trips and the OTSGs are isolated. Prior to operator actions to cool down the unit, Iover a short period the TBVs, ADVs, and the main steam safety valves (MSSVs) are assumed to operate automatically to relieve steam and maintain the OISG's pressure an temp ,ature below the immediately following design value. This is assumed to occur ev-e-i--p Med ef-e Sthe reactor trip 4 4- 1 . I I 1 11 1 1 VF A e nnt-e- -n e the event, ,he-an -ys-s---a s e secondary side pressure has decreased to below the ADV and MSSV Ssetpoints and - the direct release to the environment is the ADVsand MSSVs close terminated From his point au s-t-ain-ef--the- event, both OTSGs are continuously steamed to the condenser in order to remove decay heat and cooldown/

For the purposes of de-pressurize the RCS to DHR System entry conditions. The offsitedose analysis assumes all four TBVs are available to perform this os OTSG function At--8 hours into the event, offsite radioactivity releases are terminated as DHR is ass-umed-ote-be in break flow is assumed to be 435 conservatively operation.(

The proper hr~fe'r Lt b gpm and it is assumed faulted and intact (assumed he TBVs allows both 0TSGs, both the r24...na to have a 1 gpm primary to at at24... secondary leak rate), to be steamed to the condenser. This is significant in terms of offsite dose consequences resulting from the SGTR. A gas-liquid partition factor for iodine of 1.0 E-4 was assumed for releases occurring through the condenser. Releases directly to the atmosphere assume a partition factor of 1.0. Offsite doses calculated from the event are directly proportional to the value assumed for the partition factor. Thus, proper operation of the TBVs is necessary to maintain econsequences associated with a SGTR to a minimum (Ref.

4)

The TBVs satisfy Criterion 3 of the NRC Policy Statement.

(continued)

Crystal River Unit 3 B 3.7-20 Revision No. 12

TBVs B 3.7.4 BASES (continued)

LCO Each TBV (two per OTSG) is required to be OPERABLE for this LCO. Failure to meet the LCO can result in the inability to cooldown to DHR System entry conditions following a SGTR event while maintaining offsite doses to a minimum. A TBV is considered OPERABLE when it is capable of providing a controlled relief of the main steam flow, and is capable of fully opening and closing when manually commanded to do so by the operator.

APPLICABILITY In MODES 1, 2, and 3, the pressures and temperatures in the RCS are high enough to initiate a SGTR and require secondary side depressurization. Therefore, the TBVs are required to be OPERABLE in these MODES.

In MODES 4, 5, and 6, a SGTR is not a credible event due to the reduced stresses in the generator tubes and low driving head for release to the environment.

ACTIONS A.1 and A.2 With one or more TBV(s) inoperable, action must be taken to restore all TBVs to OPERABLE status. The 7 day Completion Time is reasonable to repair inoperable TBVs, based on the availability of other means of depressurizing the RCS following a SGTR, and the low probability of this event occurring during the 7 day period. As an alternative to restoring the TBV(s) to OPERABLE status, the associated OTSG nADV must be verified to be OPERABLE within 7 days. Thi-s entails verifying that SR 3.7.4.1- is "current" for the ADV-,

satisfy the ACTIONS of this Speeification is considered

-a-c--eqt-ab4eý n-+-ht-ea-F-a+'+aII-ys-+.

B.1 and B.2 If the TBVs cannot be restored to OPERABLE status within the associated Completion Time, the plant must be placed in a MODE in which the LCO does not apply. To achieve this status, the plant must be placed in at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , and in MODE 4 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The allowed (continued)

Crystal River Unit 3 B 3.7-21 Revision No. 12

Insert B 3.7.4-1 This may be performed as an administrative check by examining logs or other information to determine if the associated ADV is out of service for maintenance or other reasons. It does not mean to perform the Surveillances needed to demonstrate the OPERABILITY of the ADVs. If the OPERABILITY of associated ADV cannot be verified or if the ADV is discovered inoperable following entry into Condition A, Condition B must be entered.

TBVs B 3.7.4 BASES ACTIONS B.1 and B.2 (continued)

Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.7.4.1 REQUIREMENTS To perform a controlled cooldown of the RCS, the TBVs must be able to be opened remotely and throttled through their full range. This SR ensures that the TBVs are tested through a full control cycle at least once per fuel cycle.

Cycling TBVs during plant heatup satisfies this requirement.

Operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

REFERENCES 1. FSAR, Section 10.2.1.4.

2. FSAR, Section 14.2.2.2.

3. - PC-C-a-l-eul-ati-n-N-00-OO04-.

CR-3 EPU Technical Report, Section 2.8.5.6.2.

4. CR-3 EPU Technical Report, Section 2.9.2.

Crystal River Unit 3 B 3.7-22 Revision No. 37

EFW System B 3.7.5 BASES BACKGROUND The preferred water source for both EFW pump trains is the (continued) Seismic Class I, missile protected dedicated EFW tank.

Backup supplies of emergency feedwater are provided by the condensate storage tank and the Fire Service Water Storage Tanks. The main condenser hotwell can also supply the turbine driven EFW pump and the defense-in-depth motor driven EFW pump.

The pumps and OTSGs are protected from excessively high flow induced problems by cavitating venturis (EF-62-FO, EF-63-FO, and EF-64-FO) in the pump discharge lines, designed to limit EFW flow to the steam generators regardless of steam generator pressure (Ref. 7). In addition, the interlock between the motor driven and diesel driven EFW pumps and administrative controls preclude excessively high flow to the OTSGs from concurrent operation of all three EFW pumps.

DC powered block and control valves are actuated to feed the appropriate steam generator by the Emergency Feedwater Initiation and Control (EFIC) System. The capacity of either EFW pump is sufficient to remo 'e decay heat and cool the plant until the Reactor Coolant S tem (RCS) pressure and temperature are low enough to plac the Decay Heat Removal (DHR) System in service or until ore decay heat can be removed solely by ECCS.

inimum flow instruments are provided to protect the associated EFW pump from overheating when the pump is operating and the associated injection flow to the OTSGs is low. The pump recirculation the line valve is opened valve is automatically closed when the low EFW flow ispump sensed, flow and is adequate to protect the pump.

(continued)

Crystal River Unit 3 B 3.723A Amendment No. 182

Delete PageI THIS _LY LEFT BLANK B 3.7-23B

EFW System B 3.7.5 BASES APPLICABLE The EFW System is designed to remain functional following SAFETY ANALYSES the maximum hypothetical earthquake. It will also remain (continued) functional following a single failure in addition to any of the above events. No single failure prevents EFW from being supplied to the intact OTSG nor allows EFW to be supplied to the faulted OTSG. Note that in most cases of a main feedwater break or a steam line break, the depressurization of the affected OTSG would cause the automatic initiation of EFW. However, there will be some small break sizes for which automatic detection will not be possible. For these small breaks, the operator will have sufficient time in which to take appropriate action to terminate the event (Ref. 1).

The EFW System satisfies Criterion 3 of the NRC Policy Statement.

LCO Two independent emergency feedwater pumps and their associated flow paths are required to be OPERABLE. The OPERABILITY of the EFW pumps requires that each be capable of developing its required discharge pressure and flow.

Additionally, the OPERABILITY of the turbine driven pump requires that it be capable of being powered from an OPERABLE steam supply through ASV-5. ASV-204 was installed to improve EFW reliability and is not required for OPERABILITY.

The motive power for the turbine driven pump is steam supplied from either OTSG from a main steam header upstream of the main steam isolation valves so that their closure does not isolate the steam supply to the turbine. Both steam supply flow paths through MSV-55 and MSV-56 (Condition A) to the turbine driven pump are required to be OPERABLE.

The OPERABILITY of the associated EFW flow paths requires all valves be in their correct positions or be capable of sactuating to their correct positions on a valid actuation

,signal.

The diesel driven EFW pump has a starting air system consisting of a safety-related air receiver that is maintained pressurized by a non-safety-related air compressor. The requirements for the air receiver are covered by Specification 3.7.19. The air is delivered to the diesel engine through DC powered valves. The DC power is provided by the diesel driven EFW pump DC distribution system battery.

(continued)

Crystal River Unit 3 B 3.7-25 Amendment No. 182

Insert B 3.7.5-1 Additionally, EFW pump low flow instrumentation is required to be OPERABLE and capable of opening the associated recirculation line isolation valve to ensure pump protection and closing the associated recirculation line isolation valve in sufficient time to ensure that EFW discharge flow to the OTSGs as assumed during transients and accidents is met.

EFW System B 3.7.5 BASES SURVEILLANCE SR 3.7.5.5 (continued)

REQUIREMENTS of EFW flow paths must be demonstrated before sufficient core heat is generated that would require the operation of the EFW System during a subsequent shutdown. The Frequency is reasonable, based on engineering judgment, in view of other administrative controls to ensure that the flow paths are OPERABLE. To further ensure EFW System alignment, flow path OPERABILITY is verified, following extended outages to determine no misalignment of valves has occurred. This SR ensures that the flow path from the EFW tank to the OTSGs is properly aligned. This requirement is based upon the recommendation of NUREG 0737. The Frequency was modified slightly during ITS development (prior to entering MODE 2) to provide an SR 3.0.4 type exception. As written, the SR allows the plant to achieve and maintain MODE 3 conditions in order to perform the verification.

SR 3.7.5.6 Verifying battery terminal voltage ensures the ability of the battery to perform the intended function. The voltage requirements are based on the nominal design voltage of the InsrbBSR 3 7 5 j-2 attery. The 7 day frequency is consistent with IEEE-450.

REFERENCES 1. Enhanced Design Basis Document for the Emergency Feedwater and Emergency Feedwater Initiation and Control System.

2. BAW-10043, "Overpressure Protection for B&W Reactors,"

dated May 1972.

3. FSAR, Section 10.5.

4. 10 CFR 50, Appendix A.

5. ASME Code for the Operation and Maintenance of Nuclear Power Plants (ASME OM Code).

6. Deleted.

7. FPC calculation 187-0008, Rev. 6.

Crystal River Unit 3 B 3.7-31 Revision No. 79

Insert B SR 3.7.5-2 SR 3.7.5.7 The CHANNEL CALIBRATION of the required EFW pump low flow instrumentation ensures the EFW pump minimum flow instruments open the associated EFW pump recirculation line isolation valves to provide pump low flow protection and close the associated EFW pump recirculation line isolation valves in time to ensure adequate EFW discharge flow to the OTSGs as assumed in the safety analysis.

CHANNEL CALIBRATION is a complete check of the instrument channel including the sensor.

The test verifies the channel responds to a measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channels adjusted to account for instrument drift to ensure that the instrument channel remains operational between successive tests. CHANNEL CALIBRATION shall find that measurement errors and bistable setpoint errors are within the assumptions of the EFW pump low flow instrumentation calculations. CHANNEL CALIBRATIONS must be performed consistent with the assumptions of the loss of feedwater and main feedwater line break accident analysis.

The Frequency is based on the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift in the EFW pump low flow instrumentation calculations.

EE A EmeragenEy Feedwat-e Tank B 3.7.6 BASES APPLICABLE was not used as an input to these safety analyses, SAFETY ANALYSES OPERABILITY of the EFW System, and therefore the (continued) EFW tank, is essential to the mitigation of the following events (Ref. 3):

M Loss of main feedwater (LMFW)

M LMFW with a loss of offsite power M Main feedwater line break 0 Main steam line break M Small break loss of coolant accident (LOCA) atleastl1 The required minimum volume of usable condensate in/the EFW tank is 150,000 gallons. This amount is sufficient to remove decay heat for a period of appr-*-i-matelSy-4 hours at MODE 3 conditions (Ref. 4). This time period is considered adequate to allow plant conditions to be stabilized and another source of water to be made available for natural circulation cooldown until MODE 4 is achieved. In MODE 4, the RCS pressure will be decreased to the point that allows the alignment of the Decay Heat Removal (DHR) System to the RCS.

Although the single failure criteria is applicable to the EFW System in the evaluation of the previously mentioned events, the EFW tank performs its safety function in a passive manner and is thereby excluded from application of the single failure criterion.

The EFW tank satisfies Criterion 3 of the NRC Policy Statement.

LCO In the event of a loss of offsite power, or other condition resulting in a complete loss of main feedwater, a means of removing heat from the RCS must be immediately available.

The EFW tank minimum usable water volume limit of 150,000 gallons is necessary to provide assurance that the EFW System can supply the volume of secondary coolant needed to remove decay heat in MODE 3 conditions for approex-imat-eLqy-y- I hours (Ref. 4) while other sources of water are made available for subsequent cooldown to below 280 degrees, if required. a 0 Compliance with the LCO is verified by maintaining tank level at or above the minimum required level.

(continued)

Crystal River Unit 3 B 3.7-33 Revision No. 16

CREVS B 3.7.12 BASES BACKGROUND exhaust fan are de-energized and their corresponding (continued) isolation dampers close. The return fan, normal filters, normal fan, and the cooling (or heating) coils remain in operation in a recirculating mode.

Upon detection of high radiation by RM-A5 the system switches to the emergency recirculation mode. In this mode, the dampers that isolate the CCHE from the surroundings will automatically close. The CA fume hood exhaust fan, CA fume hood auxiliary supply fan, CA exhaust fan, normal supply fan, and return Van are tripped and their corresponding isolation dampers close. Manual action is required to restart the return fan and place the emergency fans and filters in operation. The cooling (or heating) coils remain in operation.

The CREVS is designed to maintain a habitable envi ronment in the CCHE for 30 days of continuous occupancy after a DBA, without exceeding a 5 rem total effective dose equivalent (TEDE).

Qualitative limits for chemical hazards and smoke were established based on the May 12, 2006 NRC meeting minutes located in the NRC Agencywide Documents and Access and Management System (ADAMS) Accession No. ML061310293.

APPLICABLE During emergency operations the design basis of the CREVS and SAFETY ANALYSIS the CCHE is to provide radiation protection to the control room occupants. The limiting accident which may threaten the habitability of the control room (i.e., accidents resulting in release of airborne radioactivity) is the postulated Cd Ej."tion accident. The consequences of this ey.nt result in the limiting radiological source loss of coolant of......nt i-ter-m-The CREVS the the CCHEroom and control habitability evaluation (Ref. 2).

ensures that the control room will accident remain habitable following all postulated design basis events, maintaining exposures to control room occupants within the limits of GDC 19 of 10 CFR 50 Appendix A (Ref.

3).

The analysis for toxic gas states that dangerous chemicals are not stored at the Crystal River Enerqy Complex in sufficient quantities to exceed established limits in the CCHE. However, the analysis of hazardous chemical releases also demonstrates operator actions can be taken to ensure that the toxicity limits are not exceeded prior to donning protective equipment in the CCHE following a hazardous chemical release.

The method of detection will be nasal detection. The CREVS can also be used to provide protection from smoke hazards for the CCHE occupants. Upon nasal detection of smoke outside of the CCHE, the Control Room staff will isolate the CCHE in the recirculation mode of CREVs as necessary, based on changing environmental conditions.

The CREVS is not in the primary success path for any accident analysis. However, the Control Room Emergency Ventilation System meets Criterion 3 of the NRC Policy Statement since long term control room habitability is essential to mitigation of accidents resulting in atmospheric fission product release.

(continued)

Crystal River Unit 3 B 3.7-62 Revision No. 77

CREVS B 3.7.12 BASES SURVEILLANCE SR 3.7.12.4 (continued)

REQUIREMENTS (continued) than the assumed flow rate, Condition B must be entered.

Required Action B.3 allows time to restore the CCHE boundary to OPERABLE status provided mitigating actions can ensure that the CCHE remains within the licensing basis habitability limits for the occupants following an accident. Compensatory measures are discussed in Regulatory Guide 1.196, Section C.2.7.3, (Ref. 5) which endorses, with exceptions, NEI 99-03, Section 8.4 and Appendix F (Ref. 6). These compensatory measures may also be used as mitigating actions as required by Required Action B.2. Temporary analytical methods may also be used as compensatory measures to restore OPERABILITY (Ref. 7).

Options for restoring the CCHE boundary to OPERABLE status include changing the licensing basis DBA consequence analysis, repairing the CCHE boundary, or a combination of these actions. Depending upon the nature of the problem and the corrective action, a full scope in-leakage test may not be necessary to establish that the CCHE boundary has been restored to OPERABLE status.

REFERENCES 1. FSAR, Section 9.7.2.1.g.

CR-3 EPU Report, Technical Section 2.9.2.

2. n--N-Q0--fl W-1-k 'EZ-

3. 10 CFR 50, Appendix A, GDC 19.

4. Regulatory Guide 1.52, Rev. 3, 2001.

5. Regulatory Guide 1.196

6. NEI 99-03, "Control Room Habitability Assessment,"

June 2001.

7. Letter from Eric J. Leeds (NRC) to James W. Davis (NEI) dated January 30, 2005, "NEI Draft White Paper, Use of generic letter 91-18 Process and Alternative Source Terms in the Context of Control Room Habitability." (ADAMS Accession No. ML040300694).

Crystal River Unit 3 B 3.7-6513 Revision No. 77

Fuel Storage Pool Water Level B 3.7.13 B 3.7 PLANT SYSTEMS B 3.7.13 Fuel Storage Pool Water BASES BACKGROUND The water contained in the spent fuel pool provides a medium for removal of decay heat from the stored fuel elements, normally via the spent fuel cooling system. In the event fuel pool cooling is lost when the pool is 140°F, assuming a full core is discharged under the conditions of Reference 1, the pool volume provides approximately 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months before boiling would occur (Ref. 1). The spent fuel pool water also provides shielding to reduce the general area radiation dose during both spent fuel handling and storage.

Although maintaining adequate spent fuel pool water level is essential to both decay heat removal and shielding effectiveness, the Technical Specification minimum water level limit is based upon maintaining the pool's iodine retention effectiveness consistent with that assumed in the evaluation of a fuel handling accident (FHA). The fuel handling accident described in FSAR Section 14.2.2.3 (Ref.

2), assumes that a minimum of 23 feet of water is maintained above the stored fuel. This assumption allows the use of the pool iodine decontamination factor used in the associated offsite dose calculation.

APPLICABLE The minimum water level in the fuel storage pool meets the SAFETY ANALYSES assumptions of the FHA described in FSAR Section 14.2.2.3.

The resultant 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months dose to a person at the exclusion area boundary and the 30 day dose at the low population zone are much less than 10 CFR 50.67 (Ref. 4) limits.

Although the water level above a damaged assembly lying on itop of the fuel storage racks may be less than 23 feet, an e*ot*-a-p&-a$+on of the iodine removal efficiency factors conservativ indicates that the iodine removal factor used in the dose calculations will still be---envoe-sat4ve at water levels as low as 2- feet (Ref. -5). The 23 foot criteria above the fuel i the racks wil ensure at least 2-1 feet above the dam assembly. F (continued)

Crystal River Unit 3 B 3.7-66 Revision No. 37

Fuel Storage Pool Water Level B 3.7.13 BASES SURVEILLANCE SR 3.7.13.1 REQUIREMENTS The water level in the fuel storage pool must be checked periodically. Since there is no mechanism for inadvertently lowering the level during normal operations (changes in level are procedurally controlled) and there is a low level alarm should pool level drop to approximately 24 feet above the stored fuel assemblies, a 7 day Frequency is sufficient to provide assurance of adequate water level. The Frequency is based on engineering judgment and industry-accepted practice. When refueling operations are taking place, the level in the fuel pool is at equilibrium with that in the refueling canal and in the reactor vessel. The level in the refueling canal is verified daily by the performance of SR 3.9.6.1.

REFERENCES 1. FSAR, Section 9.3.1.

2. FARSecton 4.2.-3. CR-3 EPU Technical

2. FARSecton 4.2..3. Report, Section 2.9.2.

3. Ge-t-ed--

4. 10 CFR 50.67.

. FP-C--Ca1--u-Tla-t4en-N-N0-O--.

Crystal River Unit 3 B 3.7-68 Revision No. 37

Spent Fuel Pool Boron Concentration B 3.7.14 B 3.7 PLANT SYSTEMS B 3.7.14 Spent Fuel Pool Boron Concentration BASES BACKGROUND As described in the Bases for LCO 3.7.15, "Spent Fuel Assembly Storage," fuel assemblies are stored in the high-density region of the spent fuel pool storage racks in accordance with criteria based on initial weight-percent enrichment and discharge burnup. A o-theugh-the .at.rin the Insert B 3.7.14-1 tr-iteria tl 1n--t-he of a f e a -- m :y-- t-speE-.-f-ie-atk l ocation (ci-cHiyaayss-r Effs--.-v.a.-vely witht

,deveopedti c it for th be-oon n-- he pe ,water.

APPLICABLE The acceptance criteria for the fuel storage pool SAFETY ANALYSIS criticality analyses is that a keffof < 0.95 must be maintained for all postulated events. The storage racks are Insert B 3.7.14-2 - A4w -_ nrat v4 pok w4*a at-ha-t-ef-aýes--y4evi-oe---c--a-'-e--"

a.....a! -ster-age-, e3.I-en.-wi-54l--e- result n a1inc-Iease-+o t-oakenf-r the- e--s**enc-ofibi-t-y---.F-*-t.ce-k-peve-ae,--s-c i-Rce-in ne tthec enthe ts es pe o ontagins

r~a

¢ee*- *-Jt ,--c-ed-hIe--aee-e-dew-s-t-*a-eth The concentration of dissolved boro n the fuel storage pool satisfies Criterion 2 of the NRC Policy Statement.

abv~~T4--cn-epeseatofi-be-f--4n-t4se1-- n~oni-s-tIe LCO The required concentration of dissolved boron in the fuel storage pool of > 1925 ppm preserves *teh--a'umpt4-&n--ea-d+

t-he-ana1-y-se5of--t-e-peit-eB-v--ae-r The cncentationof disolve bornsite B 3.7.14-3

-c-i-ntna-ios ue deE

_A4bed m-n-i-mum--equi4e a*o-ev-ee -e-eoeec1-e-Fa-t-i-e-t-aI_n--#e-r--f-I-n-t-hea+e-1--bbyctF a I- e-l -m y-te-aEe (continued)

Crystal River Unit 3 B 3.7-69 Amendment No. 193

Insert B 3.7.14-1 The soluble boron concentration required to maintain keff < 0.95 under normal conditions in Pool A is 141 ppm and in Pool B is 203 (Ref. 1). Safe operation of the spent fuel pools requires the specified fuel pool boron concentration be maintained at all times when fuel assemblies are stored in the spent fuel pool.

Insert B 3.7.14-2 (Ref. 2). The amount of soluble boron required to maintain the spent fuel storage rack multiplication factor, keff, 5 0.95 with the worst case misloaded fuel assembly is > 198 ppm in Pool A and > 571 ppm in Pool B. The limit specified in the LCO conservatively assures keff is maintained within the limit for the worst case misloaded fuel assembly accident (Ref. 1).

Insert B 3.7.14-3 assumptions used in the analyses of the fuel handling accidents as discussed in the FSAR (Ref. 3) and worst case misloaded fuel assembly accident (Ref. 1). In addition, soluble boron is credited to maintain keff < 0.95 during normal operating conditions whenever fuel is stored in the fuel storage pool.

Spent Fuel Pool Boron Concentration

-** R _7_14 B 3 7 14 to ensure kef is maintained <-0.95 during normal operating as well as for potential BASES criticality accident scenarios.

APPLICABILITY T~his LCO iaplcbehnyrýulssemblies are stored in the spent fuel poolt-unt-41i Eompl-ete--spemt-f-u-el-po&T ver rfEat bee.

,*onhas d-o],, w-gt....

,,, lIast.

, ,,,ement efuffe-s s e... ,e-s i-n-the spent fuel pe- .This,C doe Altouh wthno not-apply fo!oi ng-the veri fi catiFn since

_h re no.d" A'.ri tIh ful fi cati ea sem -i-es- -

ith~e WI.-..

l fw hefuel assembly movement in progress- there is It I eotential for a misloaded fuel assembly or a dropped fuel is eliminated, boron assembly aeid the reactivity of the racks alone is _dequate concentration must be to prese ve assumptions of the criticality analysno maintained since ACTIONS A.1-. A.-2.1. and A.2-4-;

When the concentration of boron in the fuel storage pool is less than required, immediate action must be taken to

it is assumed preclude the occurrence of an accident. This is most efficiently achieved by immediately suspending the movement that action will of fuel assemblies within the pool. This Action does not be continued preclude movement of a fuel assembly to a safe position.

until pool boron concentration Additionally, action must be initiated immediately to is restored restore pool boron concentrat on to w-+" i- -

within the limit. per-f. I*-er of-1ese-Actvions will restore compliance with the LCOr This Specification addresses t--e-L-C-O-doee-net--Eur--~et~e*i-s-t-the potential for inadvertent The Required Actions are odified by a Note indicating that criticality and the possibility LCO 3.0.3 does not apply. f--mev4-nR--4-rrad4-aa-td e--fuc or consequences of this .s semb" Ee-s 2, 3,h 1,4--4 3, c, e r1*-, t e lyievemeflt-+s event are independent of a ne f reator operation. There.. e, pacing the plant MODE. Therefore, a-eaEt-er-p-+n-ewn--eend 4i on 4 n the-eve Ian- -nabra 1ty there is no reason to shut t-&u-s-pend-t--f fuel a.- -ssemb not-,

"*,e-""**

down the plant if the LCO or eomp-pe-sate-fof-the-R-eq a on-not met. It is therefore Required Actions cannot be inappropriate to subject the plant to a shutdown transient in this condition. T--MOE*5 -*- --6-T, LCO 3.0.3 is not applicable..

in MODES 5 and 6 SURVEILLANCE SR 3.7.14.1 REQUIREMENTS This SR verifies that the concentration of boron in the fuel storage pool is within the required limit. This is accomplished by sampling representative samples of the pool.

(continued)

Crystal River Unit 3 B 3.7-70 Revision No. 23

Spent Fuel Pool Boron Concentration B 3.7.14 BASES SURVEILLANCE SR 3.7.14.1 (continued)

REQUIREMENTS Operating experience has shown significant differences between boron measured near the top of the pool and that measured elsewhere. As long as this SR is met, the analyzed events are fully bounded. The 7 day Frequency is acceptable because no major replenishment of pool water is expected to take place over this period of time.

REFERENCES 1 - . 1 ý -v.,t-. +H- of-he Pool1-A-Spe-n-t--F-ue-T St )-agR-ac-ks-n-C ysta1--R. VeF unitýE Jwt YW uc-I- Of

.E. Turn e r ,H-14&-ee--epe-t-4-HI Insert B 3.7.14-4 931li1-,--Dec-ember-1993.-

Fuel Stee---R aEsT-P- of G-ytstlal -vR er Unit 3,

ý10 CFR 50.68 (b)(4) S. E.T+ ner-,--He-te-v I , -918 Ma-4 3Pe-T-A--for-Stoe-age 3- Eri-ehed--Mark B 11 Fuel i n of 517,046 FASection 14.2.2.3. ChXk rbadA geme-#t-ac Fr F%-le- s,-- l---t"o-AEe ReýPOrt HI 992285, August 1999.

4-- Criticality EYai-ie of CR SpneulPo trage

~T -)Ab-)-)AA'7 2-D~eeumen-tatien of Acceptlability to Receive and Stree 144(--B-/ýýr

.6--1 l----y

ýr-i- y -s-PAdd-- - Paterns for 2-G63559,Sept-embe-20t46-Crystal River Unit 3 B 3.7-71 Revision No. 67

Insert B 3.7.14-4 Criticality Analysis of Additional Patterns for Crystal River 3 Pools A & B for Progress Energy, Holtec Report No. HI- 2063559, Holtec International, October 2009.

Spent Fuel Assembly Storage B 3.7.15 BASES (Rf.5)

BACKGROUND Both of the spent fuel pools are constructed of reinforced (continued) concrete and lined with stainless steel plate. They are located in the fuel handling area of the auxiliary buildingi New fuel storage requirements are addressed in Section 4.0, "Design Features".

APPLICABLE The function of the spent fuel storage racks is to support SAFETY ANALYSES and protect spent fuel assemblies from the time they are placed in the pool until they are shipped offsite. The spent fuel assembly storage LCO was derived from the need to establish limiting conditions on fuel storage to assure sufficient safety margin exists to prevent inadvertent criticality. The spent fuel assemblies are stored entirely underwater in a configuration that has been shown to result in a reactivity of less than or equal to 0.95 under worse case conditions (Ref. 1, 2, 6, 7, 8 and 9). The spent fuel assembly enrichment requirements in this LCO are required to ensure inadvertent criticality does not occur in the spent fuel pool.

Inadvertent criticality within the fuel storage area could result in offsite radiation doses exceeding 10 CFR 50.67 limits (

The spent fuel assembly storage satisfies Criterion 2 of the NRC Policy Statement.

LCO Limits on the new and irradiated fuel assembly storage in high density racks were established to ensure the assumptions of the criticality safety analysis of the spent fuel pools is maintained.

Limits on initial fuel enrichment and burnup for both new and for spent fuel stored in pool A have been established.

Two limits are defined:

1. Initial fuel enrichment must be less than or equal to 5.0 weight percent U-235, and (continued)

Crystal River Unit 3 B 3.7-73 Revision No. 67

Secondary Specific Activity B 3.7.16 BASES APPLICABLE A complete loss of AC power and a steam generator tube SAFETY ANALYSIS rupture (SGTR) are two events that also result in offsite (continued) release of secondary coolant activity through the MSSVs and atmospheric dump valves. In the case of a complete loss of AC power, the quantity of secondary coolant released to the atmosphere could be greater than during a SLB. However, the overall offsite dose is considerably lower, since the primary to secondary leakage path will be isolated much earlier following an AC power loss than after a SLB (Ref.

6). The specific activity limit on secondary coolant helps ensure the dose from a loss of AC power will be bounded by a SLB accident.

In the case of a SGTR, the activityyre cased from secondary side pre-break activity is *-ns c compared to the activity released from the primary to secondary break flow.

LCO The specific activity of the secondary coolant system is required to be < 4.5 E-4 microcuries per gram DOSE EQUIVALENT 1-131 (Ref. 7).

A secondary coolant system specific activity within this limit ensures that the offsite dose contribution of the secondary coolant activity does not exceed values considered in the safety analysis. Maintaining steam generator specific activity within this limit will ensure that the postulated post-accident doses will remain significantly less than the guideline values of 10 CFR 50.67 (Ref. 8).

APPLICABILITY The limits for secondary coolant specific activity apply whenever the steam generators are required for RCS heat removal. During these conditions, the potential exists for radioactive releases to the environment via normal steam, condensate, and feedwater leakage, or as the result of a steam line failure.

In MODES 5 and 6, the steam generators are not required for RCS heat removal. Both the RCS and secondary coolant systems are depressurized, and the potential for primary to secondary leakage is minimal.

(continued)

Crystal River Unit 3 B 3.7-79 Revision No. 67

Secondary Specific Activity B 3.7.16 BASES ACTIONS A.1 and A.2 DOSE EQUIVALENT 1-131 exceeding the allowable value in the secondary coolant would result in unanalyzed offsite doses in the event of an accident. Thus, the plant must be placed in at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , and in MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.7.16.1 REQUIREMENTS This SR verifies that the secondary specific activity is within the limits of the accident analysis. A gamma isotopic analysis of the secondary coolant, which determines DOSE EQUIVALENT 1-131, confirms the validity of the safety analysis assumptions with respect to offsite releases. It also aids in the trending and identification of increasing isotopic concentrations that might indicate changes in reactor coolant LEAKAGE. The 31 day Frequency is based on the existence of other Surveillance Requirements to monitor activity and primary to secondary leakage rate and the existence of alarms and indications of these parameters in the control room.

REFERENCES 1. 10 CFR 50, Appendix I.

2. Deleted.

3. FSAR, Table 14-28.

4. FSAR, Section 14.2.2.

CR-3 EPU Technical 5. Del eted.

FSAR, Section 14.1.2.

7. FPFue-Is-C~e&Vat-e Q~C-3-,-PRev4-s G-,--da-ted-M-a-r-c-li

8. 10 CFR 50.67.

Crystal River Unit 3 B 3. 7-80 Revision No. 67

Steam Generator Level B 3.7.17 B 3.7 PLANT SYSTEMS B 3.7.17 Steam Generator Level BASES BACKGROUND The principal operational function of the steam generators (OTSGs) is to provide superheated steam at a constant pressure (900 psia) over the power range. OTSG water inventory is maintained large enough to provide adequate primary to secondary heat transfer. Mass inventory and indicated water level in the OTSG increases with load as the length of the four heat transfer regions within the OTSG vary. Inventory is controlled indirectly as a function of power and maintenance of a constant average primary system temperature by the feedwater controls in the Integrated Control System.

The maximum operating OTSG level is based primarily on preserving the initial condition assumptions for OTSG inventory used in the FSAR steam line break (SLB) analysis (Ref. 1). An inventory of 62,600 lbm was used in this initial analysis for the original OTSG. The 62,600 lbm was Fb-e-leteExtra Space based upon concerns of a possible return to criticality because of primary sid cooling following an SLB and the maximum pressure in the reactor building. S . A -eqteltZT, v'a-l nes iý-

am !+#rinfef'a-ten e -tupdaed an the SLB -as r-e-ana1-y~e~d-i t~e 4ý- t--p

- - 1el 1

0w uprate power a conditio // bT-S&-w c nsnswhieh-i~d~ea~ed-it-was-Re~-

ndi iddene pas-s~bq-e-4e-p-62-,6OOTm-limitss thelevel to 96%t Operatingin e a0tt n 4se EErs Iim pRange Range t extended -"540-e-em-F-s- --- f- -- Additionall pefor the 0s OTSG V0 th Ibm) replacement for r1 0 For a clean original OTSG, the mass inventory in the OTSG (68,000 xc9 operating at 100% power is approximately 39,000 lbm to 63,000 preclude introduction 1 of 40,000 Ibm. For a clean replacement OTSG, thej ass water in the steam inventory at 100% power is approximately 48,G0OO lbm. As an lines.

analysis F OTSG becomes fouled and the operating level approaches the limit of 96%, the mass inventory in the downcomer region increases approximately 7-0OO lbm (Ref-.--2-), and adds to the I r-cy-y-ly, total mass inventory ofi/Ahe OTSG. In matching unit data of 5000 startup level versus power, OTSG performance codes have shown that fouling of the lower tube support plates does not significantly change the heat transfer characteristics of generator. Thus, the steam temperature, or superheat, is not degraded due to the fouling of the tube support plates, and mass inventory changes are mainly due to the added level in the downcomer.

Analytically, increasing the fouling of the OTSG tube surfaces degrades the heat transfer capability, increases the mass inventory, and decreases the steam superheat at (continued)

Crystal River Unit 3 B 3.7-81 Revision No. 83

Steam Generator Level B 3.7.17 BASES BACKGROUND 100% power. The results were presented as the amount of (continued) mass inventory in each steam generator versus operating range level and steam superheat.

The limiting curve, which was determined from several steam generator performance code runs at a power level of 100%,

conservatively bounds steam generator mass inventory value when operating at power levels < 100%. 680001bm The points displayed in Figure 3.7.17-1,\/in the accompanying LCO, are the intercept points of the 56,340 1b-mas-s value and the operating range level and steam superheat values for the er!?,inaj _fTSGs. or ~the--replacc-Ement OTFSGs a s-e..nda.ry si.de i.nv.nt.ry of 62,0 1..bm-4s-be*.d.ed 'F1-.y

,t 3.7.17 4. The-upd-a-t-ed-SLB -Isis usin g.se.. .. - de

+iew*w 6Ž2-,040 lbr i-4n -hec replacement OT-SG slows all

-ace-e-t-ante-e----e-Er-i-e 4a fo r the-event--wer-e-me-t---(-PRef-e-r-efve-3-*)

The OTSG performance analysis also indicated that startup and full range level instruments are inadequate indicators of steam generator mass inventory at high power levels due to the combination of static and dynamic pressure losses.

If the water level should rise above the 96% upper limit, the steam superheat would tend to decrease due to reduced feedwater heating through the aspirator ports. Normally, a reduction in water level is manually initiated to maintain steam flow through the aspirator port by reducing the power level. Thus, the superheat versus level limitation also tends to ensure that, in normal operation, water level will remain clear of the aspirator ports.

Feedwater nozzle flooding would impair feedwater heating, and could result in excessive tube to shell temperature differentials, excessive tubesheet temperature differentials, and large variations in pressurizer level.

APPLICABLE The limiting Design Basis Accident with respect to OTSG SAFETY ANALYSES operating level is a steam line break (Reference 1). The parameter of interest is the mass of water, or inventory, contained in the steam generator due to its role in lowering Reactor Coolant System (RCS) temperature (return to criticality concern), and in raising containment pressure during an SLB accident. A larger inventory causes the 6effects of the accident to be more severe. Figure 3.7.17-1, in the accompanying LW, was evaluated gr the replacement OTSGs based upon maintaining inventory < 62--O*0 Ibm. The replacee,,Tl SGinexn fy-as e-,aluated for SLB as des-r~-i-be*

eankffe renc 3 ad--fmd-te-be--aeEeptabf4e-whe-n c-onpafret -thea-*Ee--p-& 1-1er4a--E--R).-ee-r-Ee (continued)

Crystal River Unit 3 B 3.7-82 Revision No. 83

Steam Generator Level B 3.7.17 BASES ACTIONS B.1 (continued)

It is likely that as power is reduced, OTSG level will be restored to within the limit of Figure 3.7.17-1. When this occurs and level is restored to within the limit, the power reduction may be terminated in accordance with LCO 3.0.2.

SURVEILLANCE SR 3.7.17.1 REQUIREMENTS This SR verifies OTSG level to be within acceptable limits.

The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is adequate considering levels vary very little while operating at steady-state conditions.

During non-steady state conditions, the operator would likely be aware of any significant variations in OTSG level.

Furthermore, the 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to OTSG level status.

REFERENCES 1. FSAR, Section 14.2.2.1.

2-. Ca1-Eu1a-at-e-M09 0012, R--TS-- Th-e-rmx0-Iydf-a-av1 P-e-r--#e-Pman 0 "i "r4 Fulel Pwev--an-M"UR--Gen4i-t4ei+5

. CaI-EUatien M09 001:9, ROTSG -s A 1Iwi _f Events, A-t-ac-hmeFtt--

Crystal River Unit 3 B 3. 7-84 Amendment No. 83

Diesl D EFW Pump Fuel Oil, Lube Oil and Starting Air B 3.7.19 BASES LCO inventory supports the availability of the DD-EFW Pump to (continued) fulfill its mission of supplying EFW flow to one or both steam generators. The DD-EFW pump is required to provide emergency feedwater to one or two steam generators under the EFIC flow control scheme for an anticipated operational occurrence (AO0) or a postulated DBA with loss of offsite power.

The starting air system is required to have a minimum capacity for six successive engine start attempts without recharging the air start receivers. As such, the air start compressors are not addressed as a part of this (or any other) LCO.

APPLICABILITY Emergency feedwater flow is required during a Small Break LOCA or loss of main feedwater in order to cool and depressurize one or both generators which supports the reactor shut down and maintains it in a safe shutdown condition after an AO0 or a postulated DBA. Since stored diesel fuel oil, lube oil, and the starting air subsystem support DD-EFW Pump OPERABILITY, these features are required to be within limits whenever the DD-EFW pump is required to be OPERABLE.

ACTIONS A.1 ý8600 ~9O With total fuel oil volume in the supply tank <

gallons and > -,335 gallons, there is enough fuel oil available to operate the DD-EFW pump for 6 days. However, the Condition is restricted to fuel oil level reductions, that maintain at least a combined 6 day supply. In this Condition, a period of 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months is allowed prior to declaring the associated DD-EFW Pump inoperable.

The 48 hour5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months Completion Time allows sufficient time for obtaining the requisite replacement volume and performing the analyses required prior to addition of fuel oil to the tank. This period is acceptable based on the remaining capacity (> 6 days), the actions that will be initiated to obtain replenishment, and the low probability of an event occurring during this brief period.

(continued)

Crystal River Unit 3 B 3.7-91 Revision No. 25

Diesel Driven EFW Pump Fuel Oil, Lube Oil and Starting Air B 3.7.19 BASES ACTIONS D.1 With the new fuel oil properties defined in the Bases for SR 3.7.19.3 (fuel oil surveillance testing) not within the required limits, a period of 30 days is allowed for restoring the stored fuel oil properties prior to declaring the associated DD-EFW Pump inoperable. This period provides sufficient time to test the stored fuel oil to determine that the new fuel oil, when mixed with previously stored fuel oil, remains acceptable, or to restore the stored fuel oil properties. This restoration may involve feed and bleed, filtering, or combinations of these procedures. Even if the DD-EFW Pump start and load was required during this time and the fuel oil properties were outside limits, there is a high likelihood that the DD-EFW Pump would still be capable of performing its intended function.

E.1 EFP-3 is equipped with two redundant banks of starting air receivers and associated components (air start motors, solenoid valves, etc.). Only one of these banks is requi red for pe--a- M-]-.

FOPERABI'LITY With starting air receiver pressure < 177 psig, sufficient capacity for six successive DD-EFW Pump start attempts does not exist. However, as long as the receiver pressure is >

150 psig, there is adequate capacity for at least one start attempt, and the DD-EFW Pump can be considered OPERABLE while the air receiver pressure is restored to the required limit.

A period of 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months is considered sufficient to complete restoration to the required pressure prior to declaring the DD-EFW Pump inoperable. This period is acceptable based on the remaining air start capacity, the fact that most diesel engine starts are accomplished on the first attempt, and the low probability of an event occurring during this brief period.

F.1 With a Required Action and associated Completion Time not met, with fuel oil, lube oil, or starting air subsystems not within limits for reasons other than addressed by Conditions A through E, the DD-EFW Pump must be immediately declared inoperable. In this case, the ACTION for Specification 3.7.5, is entered.

(continued)

Crystal River Unit 3 B 3.7-93 Revision No. 25

Diesel D -*ienEFW Pump Fuel Oil, Lube Oil and Starting Air B 3.7.19 BASES SURVEILLANCE SR 3.7.19.1 REQUIREMENTS This SR provides verification that there is an 1CFR50 ade uate inventor of fuel oil in the supply tank to support operation of the DD-EFW pump for 7 days, assuming no offsite power and Appendix K decay heat removal EFW flow requirements. The 7 days is sufficient time to place the plant in a safe shutdown condition and to bring in replenishment fuel from an offsite location.

The 31 day Frequency is adequate to ensure that a sufficient supply of fuel oil is available, since low level alarms are provided and the likelihood of any large reductions (use or leakage) of fuel oil during this period would be detected.

SR 3.7.19.2

ý10CFR50 This Surveillance ensures that sufficient lube oil inventory is available to support at least 7 days of operation of DD-EFW Pump assumingýAppendix K decay heat removal EFW flow requirements. The 207 gallon requirement is based on DD-EFW Pump lube oil consumption test data.

The stored lube oil volume does not include the lube oil contained in the sump.

A 31 day Frequency is adequate to ensure that a sufficient lube oi l supply is onsite, since DD-EFW pump starts and run time are closely monitored by the plant staff.

SR 3.7.19.3 The tests listed below are a means of determining whether new fuel oil is of the appropriate grade and has not been contaminated with substances that would have an immediate, detrimental impact on diesel engine performance. If results from these tests are within acceptable limits, the fuel oil may be added to the storage tanks without concern for contaminating the entire volume of fuel oil in the storage tanks. These tests are to be conducted prior to adding the (continued)

Crystal River Unit 3 B 3.7-94 Amendment No. 192

Diesel Driv* EFW Pump Fuel Oil, Lube Oil and Starting Air B 3.7.19 BASES REFERENCES 1. FSAR, Section 10.5.

2. Regulatory Guide 1.137.

3. ANSI N195-1976, Appendix B.

4. FSAR, Chapter 6.

5. FSAR, Chapter 14.

6. ASTM Standard, D4057-06.

7. ASTM Standard, D975-06b.

8. ASTM Standard, D2500-05.

9. ASTM Standard, D4737-04.

10. ASTM Standard, D613-05.

11. ASTM Standard, D2709-96(2006).

12. Deleted.

13. Deleted.

14. ASTM Standard, D445-06.

15. ASTM Standard, D2161-05.

16. ASTM Standard, D93-06.

17. ASTM Standard, D287-92(2006).

18. ASTM Standard, D1298-99(2005).

19. ASTM Standard, D4176-04e1.

20. ASTM Standard, D1500-004a.

21. ASTM Standard, D2276-91, Method A.

De-l-et-ed-.

Inser B 3.7.20 Nxt Pg Crystal River Unit 3 B 3.7-98 Revision No. 72

linsert B 3.7.20 1 FCS B 3.7.20 B 3.7 PLANT SYSTEMS B 3.7.20 Fast Cooldown System (FCS)

BASES BACKGROUND The atmospheric dump valves (ADVs) may be required to mitigate the effects of a small break loss-of-coolant accident (SBLOCA) when THERMAL POWER is above the pre-extended power uprate (EPU) power limit of 2609 MWt.

On loss of sustained sub-cooling margin (SCM) and inadequate High Pressure Injection (HPI) System flow, secondary depressurization is achieved via the FCS, which includes automatic actuation of the ADVs.

There are two air-operated ADVs, one per Once Through Steam Generator (OTSG). Each ADV is equipped with two pressure controllers to permit control of OTSG pressure. The ADVs are normally controlled by the Emergency Feedwater Initiation and Control (EFIC)

System pressure controllers and are equipped with control stations in the control room should manual control be necessary. The EFIC System pressure controllers and manual control stations are not considered part of this Specification.

When fast RCS cooldown is required, control of ADVs is automatically transferred to the FCS pressure controllers. Upon an FCS actuation, each FCS controller automatically modulates its ADV to maintain the associated OTSG at the required pressure.

Instrumentation requirements associated with FCS actuation are provided in LCO 3.3.19,"Inadequate Core Cooling Monitoring System (ICCMS) Instrumentation,"

and LCO 3.3.20, "Inadequate Core Cooling Monitoring System (ICCMS) Automatic Actuation Logic."

The FCS automatic transfer circuit and pressure controllers are provided with dedicated 24 VDC power supplies (two batteries and associated chargers to each ADV) which ensure power is available to the FCS during an event concurrent with a loss of offsite power (LOOP). During a SBLOCA, the FCS is assumed to be energized to its proper voltage from the associated safety related batteries, with one battery per ADV Crystal River Unit 3 B 3.7-99 Revision No. XX

[Insert B 3.7.20 1 FCS B 3.7.20 BASES BACKGROUND being sufficient to support the FCS for a minimum of (continued) four hours (Ref. 1).

The normal air supply for operation of the valves is provided from the plant non-safety-related Instrument Air System. A safety related Backup Air System dedicated to the ADVs consists of five compressed air cylinders per ADV. Five air cylinders are sufficient to provide a source of control air allowing operation of the ADVs for at least four hours (Ref. 1).

Manual block valves are located upstream of the ADVs.

These valves provide the ability to isolate the ADVs for maintenance or repair.

A description of the ADVs is found in Reference 2.

APPLICABLE The FCS is assumed in the mitigation of a SBLOCA under SAFETY ANALYSIS certain conditions. Within 10 minutes following a sustained loss of SCM and inadequate HPI flow, the FCS automatically actuates, which opens the ADVs, to allow rapid RCS cool down and automatically modulates the ADVs to maintain the associated OTSG pressure

< 350 psig. The FCS and operation of both ADVs are credited with THERMAL POWER > 2609 MWt (pre-EPU power level) to assure sufficient core cooling during a SBLOCA assuming single failure of one HPI subsystem.

With THERMAL POWER

2609 MWt, the Emergency Core Cooling System (ECCS) provides sufficient core cooling during a SBLOCA assuming single failure of one HPI subsystem without the need for the FCS and ADVs.

Opening the ADVs induce additional primary to secondary cooling for the smaller sized breaks and a corresponding increase in ECCS flow. For the intermediate and larger size breaks, opening the ADVs decreases the energy in the secondary side.

Depressurizing the OTSGs during a SBLOCA allows the RCS pressure to decrease resulting in sufficient core cooling to provide adequate margin to the 10CFR 50.46 limits.

The FCS function of the ADVs satisfies Criterion 3 of 10 CFR 50.36 (c)(2)(ii).

Crystal River Unit 3 B 3.7-100 Revision No. XX

[Insert B 3.7.207 FCS B 3.7.20 BASES (continued)

LCO The FCS function of both ADVs is required to be OPERABLE following a SBLOCA with a sustained loss of SCM and inadequate HPI flow. Failure to meet the LCO can result in the inability to mitigate a SBLOCA with THERMAL POWER above 2609 MWt.

The FCS is considered OPERABLE when it is capable of actuating both ADVs on an FCS actuation signal and maintaining the required OTSG pressure during a SBLOCA. Additionally, five compressed air cylinders providing backup air supply are required for each ADV.

Also, the associated FCS automatic transfer circuit and pressure controller for each ADV are required to be capable of being powered by one of two safety related batteries per ADV.

APPLICABILITY With THERMAL POWER > 2609 MWt, the FCS is assumed to open both ADVs following a sustained loss of SCM to cool down the RCS following a SBLOCA when HPI flow is inadequate. Therefore, the FCS is required to be OPERABLE.

With THERMAL POWER < 2609 MWt, the Emergency Core Cooling System (ECCS) provides sufficient core cooling during a SBLOCA assuming single failure of one HPI subsystem without the need for the FCS function of the ADVs.

ACTIONS A. 1 If the Backup Air System in inoperable to either ADV, the system must be restored to OPERABLE status within 7 days to ensure pneumatic control is available to the ADV during an event concurrent with a LOOP.

The 7 day Completion Time is reasonable to repair the inoperable Backup Air System and is based on a highly reliable and diverse normal instrument air supply, availability of alternate instrument air (e.g.,

alternate diesel backed air compressor), and the low probability of an event concurrent with a LOOP occurring that would require the FCS function of the ADVs.

B.1 and B.2 With the FCS inoperable for reasons other than Condition A and both HPI subsystems are verified to be OPERABLE, the FCS must be restored to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

Crystal River Unit 3 B 3.7-101 Revision No. XX

[Insert B 3.7.20 1 FCS B 3.7.20 BASES ACTIONS B.1 and B.2 (continued)

In this Condition, adequate core cooling is assured by verifying the OPERABILITY of both HPI subsystems.

This may be performed as an administrative check by examining logs or other information to determine if one or both HPI subsystems are out of service for maintenance or other reasons. It does not mean to perform the Surveillances needed to demonstrate the OPERABILITY of the HPI subsystems. If the OPERABILITY of both HPI subsystems cannot be verified or if one or more HPI subsystems are discovered inoperable following entry into Condition B, Condition C must be entered.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is consistent with the Completion Time of one ECCS train inoperable per TS 3.5.2, "ECCS- Operating," and is a reasonable time to repair FCS components to one or both ADVs. This Completion Time is also based on the low probability of an event occurring during this period that would require-the FCS.

C.1 If Required Actions cannot be performed within their associated Completion Time, the plant must be placed in a condition in which the LCO does not apply.

Reducing THERMAL POWER < 2609 MWt ensures the ECCS can provide sufficient core cooling during a SBLOCA without the need for the FCS function of the ADVs.

The one hour Completion Time is based on a reasonable time to reach the required power level and the low probability of an accident occurring in this relatively short time period.

SURVEILLANCE SR 3.7.20.1 REQUIREMENTS This Surveillance ensures that, without the need of the refill, sufficient backup air capacity is available from five in-service compressed air cylinders for each ADV. The minimum backup system supply pressure downstream of the pressure regulator and compressed air cylinder header pressure and volume Crystal River Unit 3 B 3.7-102 Revision No. XX

Ilnsert B 3.7.20 FCS B 3.7.20 BASES SURVEILLANCE SR 3.7.20.1 (continued)

REQUIREMENTS (i.e., at least five air cylinders in service) ensure the ADVs can maintain at least four hours of operation. The backup system supply pressure value and compressed air cylinder header pressure values are provided in plant procedures.

The 7 day Frequency is based on industry operating experience, which shows that backup air supply pressure does not change appreciably over this time period and takes into account the capacity and availability of a local air compressor.

SR 3.7.20.2 Verifying the FCS controller battery terminal voltage indicates the required battery can perform its intended function. The voltage requirement is based on the design voltage of the battery. The 7 day Frequency is consistent with manufacturer recommendations and IEEE-450 (Ref. 3).

SR 3.7.20.3 A CHANNEL CALIBRATION is a complete check of each FCS OTSG pressure control channel, including the sensors.

The test verifies that the channel responds to the measured parameter within the necessary range and accuracy.

CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drift to ensure that the instrument channel remains operational between successive tests. CHANNEL CALIBRATION shall find that measurement errors and FCS controller setting errors are within the assumptions of the FCS instrumentation calculations. CHANNEL CALIBRATIONS must be performed consistent with the assumptions of the SBLOCA analysis.

The Frequency is justified by the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift in the FCS instrumentation calculations.

Crystal River Unit 3 B 3.7-103 Revision No. XX

Insert B 3.7.20 1 FCS B 3.7.20 BASES SURVEILLANCE SR 3.7.20.4 REQUIREMENTS (continued) A battery service test is a test of the battery capability, as found, to satisfy the design requirements (battery duty cycle) of the required FCS batteries. The discharge rate and test length should correspond to the design duty cycle requirements as specified in Reference 3.

The 24 month Frequency is consistent with the recommendations of Regulatory Guide 1.129 (Ref. 4),

which states that the battery service test should be performed during refueling operations, or at some other outage.

SR 3.7.20.5 This SR demonstrates that each ADV actuates and controls at its associated OTSG pressure setpoint on an actual or simulated FCS actuation signal at least once per fuel cycle. The test includes verifying overlap with each required FCS actuation logic train tested in SR 3.3.20.1 and FCS controller circuit to ensure the entire FCS circuit will perform the intended function.

An overlapping test of the automatic FCS actuation circuit is included as part of this test to provide complete testing of the associated safety function.

The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance is performed with the reactor at power.

REFERENCES 1. CR-3 EPU Technical Report, Section 2.3.5.

2, FSAR, Section 10.2.1.4.

3. IEEE 450-1995, IEEE Recommended Practice for Maintenance, Testing, and Replacement of Vented Lead-Acid Batteries for Stationary Applications.

4. Regulatory Guide 1.129, December 1974.

Crystal River Unit 3 B 3.7-104 Revision No. XX

Boron Concentration B 3.9.1 B 3.9 REFUELING OPERATIONS B 3.9.1 Boron Concentration BASES BACKGROUND The limit on the boron concentration of the Reactor Coolant System (RCS) and the refueling canal ensures that the reactor remains subcritical during MODE 6. Refueling boron concentration is the soluble boron concentration in the coolant in each of these volumes having direct access to the reactor core during refueling.

The soluble boron concentration offsets the core reactivity and is measured by chemical analysis of a representative sample of the coolant in each of the volumes. The refueling boron concentration limit is specified in the COLR. Plant procedures ensure the specified boron concentration in order to maintain an* overall core reactivity 4

of

÷.. keff * < 0.95 D =ev#en 1

with control rods i f4 all ,¢-*.4....

rrmo

-inserted in the most i lC ROL RODS arc withdrawn from the cOrc (Ref. 1)r adverse 10 CFR 50, Appendix A, GDC 26, requires that two independent configuration (least reactivity control systems of different design principles be negative reactivity) provided (Ref. 2). One of these systems must be capable of allowed by unit holding the reactor core subcritical under cold conditions.

procedures. The Makeup and Purification and Chemical Addition Systems serve as the systems capable of maintaining the reactor subcritical in cold conditions by maintaining the boron concentration.

The pumping action of the DHR System in the RCS, and the natural circulation due to thermal driving heads in the reactor vessel ensures a relatively uniform boron concentration of the water in the refueling canal. The DHR System is in operation during refueling (see LCO 3.9.4, "DHR and Coolant Circulation - High Water Level," and LCO 3.9.5, "DHR and Coolant Circulation - Low Water Level") to provide forced circulation in the RCS and assist in maintaining the boron concentrations in the RCS and the refueling canal above the COLR limit.

APPLICABLE During refueling operations, the reactivity condition of the SAFETY ANALYSES core is consistent with the initial conditions assumed for the boron dilution accident in the accident analysis and is (continued)

Crystal River Unit 3 B 3.9-1 Amendment No. 149

Boron Concentrat ion B 3.9.1 BASES APPLICABLE conservative for MODE 6. The boron concentration limit SAFETY ANALYSES specified in the COLR is based on the core reactivity at the (continued) beginning of each fuel cycle (the end of refueling) and includes a conservative uncertainty allowance of 50 ppm.

The required boron concentration and the refueling procedures (including full core mapping) ensure the keff of the core will remain

0.95 during the refueling operation.

Hence, a minimum 5% Ak/k margin to criticality is established during refueling.

During refueling, the water volume in the fuel transfer canal and the reactor vessel are interconnected such that they form a single mass. As a result, the soluble boron concentration is relatively the same in each of these volumes.

RCS boron concentration satisfies Criterion 2 of the NRC Policy Statement.

LCO The LCO requires that a minimum boron concentration be m-Y*-*Y*maintained in the RCS and the refueling canal while in with controlrods MODE 6. The boron concentration limit specified in the COLR ensures a core kef of

0.95 is maintained during fuel adverse handling operations TdEepeide-n--e-f-*o*-en--e-l-e-ed-aesembl"-y configuration (least posi-negative reactivity) allowed by unit Violation of the LCO results in uncertainty with respect to procedures. the degree of sub-criticality during MODE 6.

APPLICABILITY This LCO is applicable in MODE 6 to ensure that the fuel in the reactor vessel will remain subcritical during CORE ALTERATIONS. In other than MODE 6, LCO 3.1.1, "SHUTDOWN MARGIN (SDM)," LCO 3.1.5, "Safety Rod Insertion Limits" and LCO 3.2.1, "Regulating Rod Insertion Limits" are the primary means of ensuring that an adequate amount of negative reactivity is available to shut down the reactor and to maintain it subcritical under all plant conditions.

(continued)

Crystal River Unit 3 B 3.9-2 Amendment No. 149

Containment Penetrations B 3.9.3 BASES APPLICABLE During movement of fuel assemblies within containment, SAFETY ANALYSES the most severe radiological consequences result from a fuel handling accident involving handling recently i r radiated fuel. o ye-(-i4c-l --the---:-eow-1-g r-?ef-~J4ng-oE~t-age)-e-ope-ra-t-e d t-o r-4b-T-I RAT-ED irradiated fuel is the fuel that has occupied part of a critical reactor core within the previous 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . Fuel handling accidents include dropping a single irradiated fuel assembly and handling tool or a heavy object onto other irradiated fuel assemblies. The requirements of LCO 3.9.6, "Refueling Canal Water Level," in conjunction with the administrative limit on minimum decay time prior to irradiated fuel movement ensure that the release fission product radioactivity subsequent to a fuel handling accident results in doses that are within the requirements specified in 10 CFR 50.67 even without containment closure.

Containment penetrations satisfy Criterion 3 of the NRC Policy Statement.

LCO This LCO limits the consequences of a fuel handling accident involving handling recently irradiated fuel in containment by limiting the potential escape paths for fission product radioactivity from containment. The LCO requires any penetration providing direct access from the containment atmosphere to the outside atmosphere, including the equipment hatch or the Outage Equipment Hatch, to be closed except for penetrations containing an OPERABLE purge or mini-purge valve. For the containment purge and mini-purge valves to be considered OPERABLE, at least one valve in each penetration must be automatically isolable on an RB Purge-high radiation isolation signal.

The definition of "direct access from the containment atmosphere to the outside atmosphere" is any path that would allow for transport of containment atmosphere to any atmosphere located outside the containment structure. This includes the Auxiliary Building. As a general rule, closed or pressurized systems do not constitute a direct path (continued)

Crystal River Unit 3 B 3.9-11 Revision No. 81

Refueling Canal Water Level B 3.9.6 B 3.9 REFUELING OPERATIONS B 3.9.6 Refueling Canal Water Level BASES BACKGROUND The movement of irradiated fuel assemblies within containment requires a minimum refueling canal water level of 156 ft plant datum. This maintains sufficient water level above the fuel contained in the vessel and the bottom of the fuel transfer canal, and the spent fuel pool to ensure iodine fission product activity is retained in the water to a level consistent with the dose analysis of a fuel handling accident (Ref. 4). Sufficient iodine activity would be retained to/limit offsite doses from the accident to well within 10CFR\50.67 limits (Ref. 3).

APPLICABLE During movement of irradiated fuel assemblies, the water SAFETY ANALYSES level in the refueling canal is an assumed initial condition in the analysis of the fuel handling accident in containment. This relates to the assumption that 99% of the total iodine released from the fuel is retained by the refueling canal water. There are postulated drop scenarios where there is < 23 ft above the top of the fuel bundle and the surface. In particular, this is the case for the period of time during which the assembly travels between the cavity and the deep end of the refueling canal. During this time, there is potentially 21 feet of water between the reactor vessel flange (135 ft plant datum) and the surface of the pool. The iodine retention factors used in D he dose assessment are still conservet--ve-at* water levels of feet above the da aged fuel (Ref. 4). The 156 ft value was chosen to be consistent with tI4 level specified for LCO 3.7.13, "Fuel torage Pool Water Level" and plant configuration.

relative to (continued)

Crystal River Unit 3 B 3.9-23 Amendment No. 208

Refuel ing Canal Water Level B 3.9.6 BASES FT-7 APPLICABLE The fuel handling accide analysis inside containment is SAFETY ANALYSES described in Reference 4. With a minimum water level of (continued) 23 ft above the stored fuel, and the administrative limit on minimum decay time of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months prior to movement of irradiated fuel in the vessel, analyses demonstrate that the iodine release due to a postulated fuel handling accident is adequately captured by the water such that offsite doses are maintained within allowable limits (Ref. 3).

Refuel ing canal water level satisfies Criterion 2 of the NRC Policy Statement.

LCO A minimum refueling canal water level of 156 ft plant datum is required to ensure that the radiological consequences of a postulated fuel handling accident inside containment are within acceptable limits. This minimum level also ensures an adequate operational window between the surface of the pool and the transfer winch for the RB fuel handling equipment.

APPLICABILITY This Specification is applicable when moving irradiated fuel assemblies within the containment. The LCO minimizes the potential of a fuel handling accident in containment which results in offsite doses greater than those calculated by the safety analysis. If irradiated fuel is not present in containment, there can be no significant radioactivity release as a result of a postulated fuel handling accident. Water level requirements for fuel handling accidents postulated to occur in the spent fuel pool are addressed by LCO 3.7.13, "Fuel Storage Pool Water Level."

ACTIONS A.1 With a refueling canal water level of < 156 ft plant datum, all movement of irradiated fuel assemblies shall be suspended immediately to preclude a fuel handling accident from occurring. The suspension of fuel movement shall not preclude completion of movement of a component to a safe position.

(continued)

Crystal River Unit 3 B 3.9-24 Amendment No. 208

Refueling Canal Water Level B 3.9.6 BASES ACTIONS A.2 In addition to immediately suspending movement of irradiated fuel, actions to restore refueling canal water level must be initiated immediately. The immediate Completion Time is based on engineering judgment. When increasing refueling canal water level the boron concentration of the make-up and the effect of this concentration on the minimum specified in the COLR (Ref. LCO 3.9.1) must be considered.

SURVEILLANCE SR 3.9.6.1 REQUIREMENTS Verification of a minimum refueling canal water level of 156 ft plant datum ensures that the design basis for the postulated fuel handling accident analysis during refueling operations is met. Water at the required level above the top of the reactor vessel flange limits the consequences of damaged fuel rods that are assumed to result from a postulated fuel handling accident inside containment (Ref. 2).

The Frequency of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is based on engineering judgment and is considered adequate in view of the large volume of water and the normal procedural controls of valve positions, which make significant unplanned level changes unlikely.

REFERENCES 1. De4-eted-. CR-3EPU Technical~

Report, Section 2.9.2.

2. FSAR Section 14.2.2.3.

3. 10 CFR 50.67.

4-.- FPC--a-eu4---i-en-N-0O-OO4-1*.

Crystal River Unit 3 B 3.9-25 Amendment No. 208

PROGRESS ENERGY FLORIDA, INC.

CRYSTAL RIVER UNIT 3 DOCKET NUMBER 50-302/LICENSE NUMBER DPR-72 LICENSE AMENDMENT REQUEST #309, REVISION 0 ATTACHMENT 6 AFFIDAVIT FOR WITHHOLDING PROPRIETARY INFORMATION FROM PUBLIC DISCLOSURE

AFFIDAVIT COMMONWEALTH OF VIRGINIA )

) ss.

CITY OF LYNCHBURG )

1. My name is Gayle F. Elliott. I am Manager, Product Licensing, for AREVA NP Inc. (AREVA NP) and as such I am authorized to execute this Affidavit.

2. I am familiar with the criteria applied by AREVA NP to determine whether certain AREVA NP information is proprietary. I am familiar with the policies established by AREVA NP to ensure the proper application of these criteria.

3. I am familiar with the AREVA NP information contained in Engineering Information Records 51-9076487-000 entitled "Crystal River Unit 3 Extended Power Uprate Technical Report," dated March 2010, 51-9150228-000 entitled "Additional Input to CR-3 EPU LR Re: TACO3/GDTACO/COPERNIC (CO-45)," dated December 2010, and 51-9163143-000 entitled, "CR-3 EPU Technical Report Revision Sections," dated June 2011 and referred to herein as "Documents." Information contained in these Documents has been classified by AREVA NP as proprietary in accordance with the policies established by AREVA NP for the control and protection of proprietary and confidential information.

4. These Documents contain information of a proprietary and confidential nature and is of the type customarily held in confidence by AREVA NP and not made available to the public. Based on my experience, I am aware that other companies regard information of the kind contained in these Documents as proprietary and confidential.

5. These Documents have been made available to the U.S. Nuclear Regulatory Commission in confidence with the request that the information contained in these Documents

be withheld from public disclosure. The request for withholding of proprietary information is made in accordance with 10 CFR 2.390. The information for which withholding from disclosure is requested qualifies under 10 CFR 2.390(a)(4) "Trade secrets and commercial or financial information."

6. The following criteria are customarily applied by AREVA NP to determine whether information should be classified as proprietary:

(a) The information reveals details of AREVA NP's research and development plans and programs or their results.

(b) Use of the information by a competitor would permit the competitor to significantly reduce its expenditures, in time or resources, to design, produce, or market a similar product or service.

(c) The information includes test data or analytical techniques concerning a process, methodology, or component, the application of which results in a competitive advantage for AREVA NP.

(d) The information reveals certain distinguishing aspects of a process, methodology, or component, the exclusive use of which provides a competitive advantage for AREVA NP in product optimization or marketability.

(e) The information is vital to a competitive advantage held by AREVA NP, would be helpful to competitors to AREVA NP, and would likely cause substantial harm to the competitive position of AREVA NP.

The information in these Documents is considered proprietary for the reasons set forth in paragraphs 6(b) and 6(c) above.

7. In accordance with AREVA NP's policies governing the protection and control of information, proprietary information contained in these Documents have been made available, on a limited basis, to others outside AREVA NP only as required and under suitable agreement providing for nondisclosure and limited use of the information.

8. AREVA NP policy requires that proprietary information be kept in a secured file or area and distributed on a need-to-know basis.

9. The foregoing statements are true and correct to the best of my knowledge, information, and belief.

SUBSCRIBED before me this day of iIiTV" e 2011.

U Sherry L. McFaden NOTARY PUBLIC, COMMONWEALTH OF VIRGINIA MY COMMISSION EXPIRES: 10/31/14 Reg. # 7079129

- p I

SHERRY L. MCFADEN Notary Public Commonwealth of Virginia 7079129 My Commission Expires Oct 31, 2014 1

3F0611-02, Attachments 1, 2 & 3, 4 & 6 Crystal River Unit 3, License Amendment Request 309, Revision 0 Attachment 1, Description of Proposed Change, Background, Justification for the Request, Determination of No Significant Hazards Considerations

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3F0611-02, Attachments 1, 2 & 3, 4 & 6 Crystal River Unit 3, License Amendment Request 309, Revision 0 Attachment 1, Description of Proposed Change, Background, Justification for the Request, Determination of No Significant Hazards Considerations

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3.0 BACKGROUND

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