ML110700304

Independent Spent Fuel Storage Installation, EAL Comparison Matrix. Part 2 of 13

ML110700304
Person / Time
Site:	Calvert Cliffs
Issue date:	02/01/2011
From:	Constellation Energy Nuclear Group, Calvert Cliffs, EDF Development
To:	Office of Nuclear Material Safety and Safeguards, Office of Nuclear Reactor Regulation
References
Download: ML110700304 (997)

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{{#Wiki_filter:0Constellation Calvert Cliffs NuclearEnergy Power Plant EAL Comparison Matrix Revision 0 [Draft D3 1/6/11]

EAL Comparison Matrix OSSI Project #09-0803 CCNPP Table of Contents Section Paqe Int ro d u ct io n - -- . . . . . . . . . .. . .. ..-.

                                                                                                - - --        . ..-.                 -..-.                 .-.-                                      .. .      . . - -. - - -.- . ..-  --          ----       1 Comparison Matrix Format --.--           -----... -----................-------                .-.                                                                                                                                                4 EAL Wording              -.   --

EAL Emphasis Techniques -. ............----------- - ---.-. --.---- ---.. -------------------------------------------------- -------------- -1 "0 Global Differences ---------.................--- Differences and Deviations- -------------------- '2 Category R - Abnormal Rad Levels / Rad Effluents .- .- ---- ------- - ---- - - -- --- ---------- - ------- - -- 14 Category C - Cold Shutdown / Refueling System Malfunction ---- o 5------30 Category D - Permanently Defueled Station Malfunction -..---.---- ------------- -------- ----- -- --- --- ------------- -- -- 51 Category E - Events Related to Independent Spent Fuel Storage Installations - - Category F - Fission Product Barrier Degradation --------------....... ---------- - --- -- ----------------------- -- -- -- Category H - Hazards and Other Conditions Affecting Plant SafetyF.-.-.-.-....---- .......................................----.--------- 7R Category S - System Malfunction -.....................------------- ------------ ---------- -- ---- -------- ------------------- -------- --102 Table 1 - CCNPP EAL Categories/Subcategories - -------

                                                                                                                                                                                                                                   ---------------           6

_7 Table 2 - NEI / CCNPP EAL Identification Cross-Reference Table 3 - Summary of Deviations -.....................------ .13 i ofi

EAL Comparison Matrix OSSI Project #09-0803 CCNPP Introduction procedures which most closely correspond to the conditions under which This document provides a line-by-line comparison of the Initiating Conditions EALs must be used) should be the norm for each utility." (ICs), Mode Applicability and Emergency Action Levels (EALs) in NEI 99-01 To assist the Emergency Director (ED), the CCNPP EALs have been written Rev. 5 Final, Methodology for Development of Emergency Action Levels, in a clear and concise style (to the extent that the differences from the NEI February 2008 (ADAMS Accession Number ML080450149), and the Calvert EAL wording could be reasonably documented and justified). As a result, Cliffs Nuclear Power Plant (CCNPP) ICs, Mode Applicability and EALs. This unnecessary words have been removed from the CCNPP EALs to reduce document provides a means of assessing CCNPP differences and deviations EAL-user reading burden to the extent practicable. from the NRC endorsed guidance given in NEI 99-01. Discussion of CCNPP The wording reduction gained from elimination of a few characters in a given EAL bases and lists of source document references are given in the EAL EAL may not appear to be advantageous within the context of one EAL. Technical Bases Document. It is, therefore, advisable to reference the EAL When applied to the composite set of EALs, however, significant gains are Technical Bases Document for background information while using this realized and reading efficiency is improved. This supports timely and document. accurate classification in the tense atmosphere of an emergency event. The EAL differences introduced to reduce reading burden comprise almost all of Comparison Matrix Format the differences justified in this document. The ICs and EALs discussed in this document are grouped according to NEI 99-01 Recognition Categories. Within each Recognition Category, the ICs EAL Emphasis Techniques and EALs are listed in tabular format according to the order in which they are Due to the width of the table columns and table formatting constraints in this given in NEI 99-01. Generally, each row of the comparison matrix provides document, line breaks and indentation may differ slightly from the the following information: appearance of comparable wording in the source documents. NEI 99-01 is

    "   NEI EAL/IC identifier                                                          the source document for the NEI EALs; the CCNPP EAL Technical Bases Document for the CCNPP EALs.

• NEI EAL/IC wording Development of the CCNPP IC/EAL wording has attempted to minimize
• CCNPP EAL/IC identifier inconsistencies and apply sound human factors principles. As a result,

    "   CCNPP EAL/IC wording                                                           differences occur between NEI and CCNPP ICs/EALs for these reasons alone. When such difference may infer a technical difference in the

• Description of any differences or deviations associated NEI IC/EAL, the difference is identified and a justification provided.

EAL Wording The print and paragraph formatting conventions summarized below guide presentation of the CCNPP EALs in accordance with the EAL writing criteria. In Section 4.2, NEI recommends the following: "The method of [EAL] Space restrictions in the EAL table of this document sometimes override this presentation should be one with which the operations and health physics criteria in cases when following the criteria would introduce undesirable staff are comfortable. As is the case for emergency procedures, bases for complications in the EAL layout. steps should be in a separate (or separable) document suitable for training and for reference by emergency response personnel and offsite agencies.

• Upper case print is reserved for system abbreviations, logic terms Each nuclear plant should already have presentation and human factors (and, or, etc. when not used as a conjunction), annunciator window standards as part of its procedure writing guidance. EALs that are consistent engravings.

with those procedure writing standards (in particular, emergency operating " Bold font is used for logic terms, negative terms (not, cannot, etc.), ANY, all. 1 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP

• Underscore is avoided as it can interfere with text in narrow line
• NEI Recognition Category A "Abnormal Radiation Levels/

spacing. Radiological Effluents" has been changed to Category R

    "   Three or more items in a list are normally introduced with "ANY of                "Abnormal Rad Levels / Rad Effluents." The designator "R" is the following" or "all of the following." Items of the list begin with             more intuitively associated with radiation (rad) or radiological bullets when a priority or sequence is not inferred.                              events. NEI IC designators beginning with "A" have likewise been changed to "R."

• The use of AND/OR logic within the same EAL has been avoided when possible. When such logic cannot be avoided, indentation and " NEI 99-01 defines the thresholds requiring emergency separation of subordinate contingent phrases is employed. classification (example EALs) and assigns them to ICs which, in turn, are grouped in "Recognition Categories." The Recognition Categories, however, are so broad and the IC descriptions are Global Differences so varied that an EAL is difficult to locate in a timely manner The differences listed below generally apply throughout the set of EALs and when the EAL-user must refer to a set of EALs with the NEI are not repeated in the Justification sections of this document. The global organization and identification scheme. The NEI document differences do not decrease the effectiveness of the intent of NEI 99-01. clearly states that the EAL/IC/Recognition Category scheme is not intended to be the plant-specific EAL scheme for any plant,

1. The NEI phrase "Notification of Unusual Event" has been changed to and appropriate human factors principles should be applied to "Unusual Event" or abbreviated "UE" to reduce EAL-user reading development of an EAL scheme that helps the EAL-user make burden. timely and accurate classifications. CCNPP endeavors to

2. NEI 99-01 IC Example EALs are implemented in separate plant improve upon the NEI EAL organization and identification EALs to improve clarity and readability. For example, NEI lists all IC scheme to enhance usability of the plant-specific EAL set. To HUI Example EALs under one IC. The corresponding CCNPP EALs this end, the CCNPP IC/EAL scheme includes the following appear as unique EALs (e.g., HU1.1 through HU1.5). features:

3. Mode applicability identifiers (numbers/letter) modify the NEI 99-01 a. Division of the NEI EAL set into three groups:

mode applicability names as follows: 1 - Power Operation, 2 - o EALs applicable under all plant operating modes - Startup, 3 - Hot Standby, 4 - Hot Shutdown, 5 - Cold Shutdown, 6 - This group would be reviewed by the EAL-user any Refuel, D - Defueled. NEI 99-Oldefines Defueled as follows: time emergency classification is considered.

       "Reactor Vessel contains no irradiated fuel (full core off-load during refueling or extended outage)."                                                           o    EALs applicable only under hot operating modes -

This group would only be reviewed by the EAL-user

4. NEI 99-01 uses the terms greater than, less than, greater than or when the plant is in Hot Shutdown, Hot Standby, equal to, etc. in the wording of some ICs and example EALs. For Startup or Power Operation mode.

consistency and reduce EAL-user reading burden, CCNPP has adopted use of boolean symbols in place of the NEI 99-01 text o EALs applicable only under cold operating modes - modifiers. This group would only be reviewed by the EAL-user when the plant is in Cold Shutdown, Refuel or

5. "min." is the standard abbreviation for "minutes" and is used to Defueled mode.

reduce EAL user reading burden. The purpose of the groups is to avoid review of hot

6. IC/EAL identification: condition EALs when the plant is in a cold condition and avoid review of cold condition EALs when the plant is in a 2 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP hot condition. This approach significantly minimizes the The EAL identifier is designed to fulfill the following total number of EALs that must be reviewed by the EAL- objectives: user for a given plant condition, reduces EAL-user o Uniqueness - The EAL identifier ensures that there reading burden and, thereby, speeds identification of the can be no confusion over which EAL is driving the EAL that applies to the emergency. need for emergency classification.

b. Within each of the above three groups, assignment of o Speed in locating the EAL of concern - When the EALs to categories/subcategories - Category and EALs are displayed in a matrix format, knowledge subcategory titles are selected to represent conditions of the EAL identifier alone can lead the EAL-user to that are operationally significant to the EAL-user.

the location of the EAL within the classification Subcategories are used as necessary to further divide the matrix. The identifier conveys the category, EALs of a category into logical sets of possible emergency classification thresholds. The CCNPP EAL subcategory and classification level. This assists ERO responders (who may not be in the same categories/subcategories and their relationship to NEI facility as the ED) to find the EAL of concern in a Recognition Categories are listed in Table 1. timely manner without the need for a word

c. Unique identification of each EAL - Four characters description of the classification threshold.

comprise the EAL identifier as illustrated in Figure 1. o Possible classification upgrade - The category/subcategory/identifier scheme helps the Figure 1- EAL Identifier EAL-user find higher emergency classification EALs that may become active if plant conditions worsen. EAL Identifier XXX.X Note that the NEI 99-01 identifier only identifies the IC, Category (R. H. E. S. F. C) - L Sequential number within subcategorylclassification not the specific example EAL threshold. The NEI scheme, Emergency classification (G. S. A. U) Subcategory number (1 if no subcategory) therefore, does not fulfill the above objectives which are desirable in facilitating timely and accurate emergency classification. The first character is a letter associated with the category in which the EAL is located. The second character is a Table 2 lists the CCNPP ICs and EALs that correspond to letter associated with the emergency classification level the NEI ICs/Example EALs when the above EAL/IC (G for General Emergency, S for Site Area Emergency, A organization and identification scheme is implemented. for Alert, and U for Notification of Unusual Event). The third character is a number associated with one or more subcategories within a given category. Subcategories are Differences and Deviations sequentially numbered beginning with the number 1". If a In accordance NRC Regulatory Issue Summary (RIS) 2003-18 "Use of category does not have a subcategory, this character is Nuclear Energy Institute (NEI) 99-01, Methodology for Development of assigned the number "l". The fourth character is a Emergency Action Levels" Supplements 1 and 2, a difference is an EAL number preceded by a period for each EAL within a change in which the basis scheme guidance differs in wording but agrees in subcategory. EALs are sequentially numbered within the meaning and intent, such that classification of an event would be the same, emergency classification level of a subcategory beginning whether using the basis scheme guidance or the CCNPP EAL. A deviation is with the number "1". an EAL change in which the basis scheme guidance differs in wording and is altered in meaning or intent, such that classification of the event could be 3 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP different between the basis scheme guidance and the CCNPP proposed o Ensure that the resulting EAL scheme is complete (i.e., EAL. classifies all potential emergency conditions). Administrative changes that do not actually change the textual content are The following are examples of deviations: neither differences nor deviations. Likewise, any format change that does not " Use of altered mode applicability. alter the wording of the IC or EAL is considered neither a difference nor a deviation.

• Altering key words or time limits.

The following are examples of differences:

• Changing words of physical reference (protected area, safety-related

    "   Choosing the applicable EAL based upon plant type (i.e., BWR vs.                        equipment, etc.).

PWR). " Eliminating an IC. This includes the removal of an IC from the

• Using a numbering scheme other than that provided in NEI 99-01 Fission Product Barrier Degradation category as this impacts the that does not change the intent of the overall scheme. logic of Fission Product Barrier ICs.
• Changing a Fission Product Barrier from a Loss to a Potential Loss

    "   Where the NEI 99-01 guidance specifically provides an option to not include an EAL if equipment for the EAL does not exist at CCNPP                         or vice-versa.

(e.g., automatic real-time dose assessment capability).

• Not using NEI 99-01definitions as the intent is for all NEI 99-01 users
• Pulling information from the bases section up to the actual EAL that to have a standard set of defined terms as defined in NEI 99-01.

does not change the intent of the EAL. Differences due to plant types are permissible (BWR or PWR). Verbatim compliance to the wording in NEI 99-01 is not necessary as

    "   Choosing to state ALL Operating Modes are applicable instead of                         long as the intent of the defined word is maintained. Use of the stating N/A, or listing each mode individually under the Abnormal                       wording provided in NEI 99-01 is encouraged since the intent is for Rad Level/Radiological Effluent and Hazard and Other Conditions                         all users to have a standard set of defined terms as defined in NEI Affecting Plant Safety sections.                                                        99-01.

• Using synonymous wording (e.g., greater than or equal to vs. at or
• Any change to the IC and/or EAL, and/or basis wording as stated in above, less than or equal vs. at or below, greater than or less than NEI 99-01 that does alter the intent of the IC and/or EAL, i.e., the IC vs. above or below, etc.) and/or EAL:
• Adding CCNPP equipment/instrument identification and/or noun o Does not classify at the classification level consistent with names to EALs. NEI 99-01.

    "   Combining like ICs that are exactly the same but have different                              o   Is not logically integrated with other EALs in the EAL operating modes as long as the intent of each IC is maintained and                               scheme.

the overall progression of the EAL scheme is not affected. o Results in an incomplete EAL scheme (i.e., does not classify

• Any change to the IC and/or EAL, and/or basis wording, as stated in all potential emergency conditions).

NEI 99-01, that does not alter the intent of the IC and/or EAL, i.e., The "Difference/Deviation Justification" columns in the remaining sections of the IC and/or EAL continues to: this document identify each difference between the NEI 99-01 IC/EAL o Classify at the correct classification level. wording and the CCNPP IC/EAL wording. An explanation that justifies the reason for each difference is then provided. If the difference is determined to o Logically integrate with other EALs in the EAL scheme. be a deviation, a statement is made to that affect and explanation is given that states why classification may be different from the NEI 99-01 IC/EAL and 4 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP the reason for its acceptability. In all cases, however, the differences and deviations do not decrease the effectiveness of the intent of NEI 99-01. A summary list of CCNPP EAL deviations from NEI 99-01 is given in Table 3. 5 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP Table 1 - CCNPP EAL Categories/Subcategories CCNPP EALs NEI Category Subcategory Recognition Category Group: Any Operating Mode: R - Abnormal Rad Release/Rad 1 - Offsite Rad Conditions Abnormal Rad Levels/Radiological Effluent 2 - Onsite Rad Conditions & Spent Effluent EALs Fuel Events 3 - CR/CAS/SAS Rad H - Hazards and Other Conditions 1 - Natural or Destructive Hazards and Other Conditions Affecting Plant Safety Phenomena 2 - Fire or Explosion Affecting Plant Safety EALs 3 - Hazardous Gas 4 - Security 5 - Control Room Evacuation 6 - Judgment None ISFSI EALs E - ISFSI Group: Hot Conditions: S - System Malfunction 1- Loss of AC Power System Malfunction EALs 2- Loss of DC Power 3- Criticality & RPS Failure 4- Inability to Reach or Maintain Shutdown Conditions 5 - Instrumentation 6 - Communications 7 - Fuel Clad Degradation 8 - RCS Leakage F - Fission Product Barrier None Fission Product Barrier EALs Group: Cold Conditions: C - Cold Shutdown/Refuel System 1- Loss of AC Power Cold Shutdown./ Refueling System Malfunction 2- Loss of DC Power Malfunction EALs 3- RCS Level 4- RCS Temperature 5- Communications 6- Inadvertent Criticality 6 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP Table 2 - NEI / CCNPP EAL Identification Cross-Reference NEI CCNPP Example Category and Subcategory EAL EAL AU1 1 R - Abnormal Rad Release / Rad Effluent, 1 - Offsite Rad Conditions RUI.1 AU1 2 R - Abnormal Rad Release / Rad Effluent, 1 - Offsite Rad Conditions RU1.2 AU1 3 R - Abnormal Rad Release / Rad Effluent, 1 - Offsite Rad Conditions RU1.3 AU1 4 N/A N/A AU1 5 N/A N/A AU2 1 R - Abnormal Rad Release / Rad Effluent, 2 - Onsite Rad Conditions & RU2.1 Spent Fuel Events AU2 2 R - Abnormal Rad Release / Rad Effluent, 2 - Onsite Rad Conditions & RU2.2 Spent Fuel Events AAW 1 R - Abnormal Rad Release / Rad Effluent, 1 - Offsite Rad Conditions RA1.1 AA1 2 R - Abnormal Rad Release / Rad Effluent, 1 - Offsite Rad Conditions RA1.2 AA1 3 R -Abnormal Rad Release / Rad Effluent, 1 - Offsite Rad Conditions RA1.3 AA1 4 N/A N/A AA1 5 N/A N/A AA2 1 R - Abnormal Rad Release / Rad Effluent, 2 - Onsite Rad Conditions & RA2.2 Spent Fuel Events AA2 2 R - Abnormal Rad Release / Rad Effluent, 2 - Onsite Rad Conditions & RA2.1 Spent Fuel Events 7 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI CCNPP Example Category and Subcategory EAL EAL AA3 1 R - Abnormal Rad Release / Rad Effluent, 2 - Onsite Rad Conditions & RA2.3 Spent Fuel Events AS1 1 R - Abnormal Rad Release / Rad Effluent, 1 - Offsite Rad Conditions RS1.1 AS1 2 R - Abnormal Rad Release / Rad Effluent, 1 - Offsite Rad Conditions RS1.2 AS1 3 N/A N/A AS1 4 R - Abnormal Rad Release / Rad Effluent, 1 - Offsite Rad Conditions RS1.3 AG1 1 R-Abnormal Rad Release / Rad Effluent, 1 -Offsite Rad Conditions RG1.1 AG1 2 R - Abnormal Rad Release / Rad Effluent, 1 - Offsite Rad Conditions RG1.2 AG1 3 N/A N/A AG1 4 R - Abnormal Rad Release / Rad Effluent, 1 - Offsite Rad Conditions RG1.3 CUl 1 C - Cold SD/ Refuel System Malfunction, 3 - PCS Level CU3.1 CU2 1 C - Cold SD/ Refuel System Malfunction, 3 - PCS Level CU3.2 CU2 2 C - Cold SD/ Refuel System Malfunction, 3 - PCS Level CU3.3 CU3 1 C - Cold SD/ Refuel System Malfunction, 1 - Loss of AC Power CU1.1 CU4 1 C - Cold SD/ Refuel System Malfunction, 4 - PCS Temperature CU4.1 CU4 2 C - Cold SD/ Refuel System Malfunction, 4 - PCS Temperature CU4.2 CU6 1, 2 C - Cold SD/ Refuel System Malfunction, 5 - Communications CU5.1 CU7 1 C - Cold SD/ Refuel System Malfunction, 2 - Loss of DC Power CU2.1 CU8 1 N/A N/A 8 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI CCNPP Example Category and Subcategory EAL EAL CU8 2 C - Cold SD/ Refuel System Malfunction, 6 - Inadvertent Criticality CU6.1 CA1 1, 2 C - Cold SD/ Refuel System Malfunction, 3 - PCS Level CA3.1 CA3 1 C - Cold SD/ Refuel System Malfunction, 1 - Loss of Power CA1.1 CA4 1, 2 C - Cold SD/ Refuel System Malfunction, 4 - PCS Temperature CA4.1 CS1 1 C - Cold SD/ Refuel System Malfunction, 4 - PCS Temperature CA4.2 CS1 2 C - Cold SD/ Refuel System Malfunction, 3 - PCS Level CS3.1 CS1 3 C - Cold SD/ Refuel System Malfunction, 3 - PCS Level CS3.2 CG1 1 C - Cold SD/ Refuel System Malfunction, 3 - PCS Level CS3.3 CG1 2 C - Cold SD/ Refuel System Malfunction, 3 - PCS Level CG3.1 D-AU1 N/A N/A D-AU2 D-SU1 D-HU1 D-HU2 D-HU3 D-AA1 D-AA2 D-HA1 D-HA2 E-HU1 1 E - ISFSI EU1.1 FU1 1 F - Fission Product Barriers FU1.1 9 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI CCNPP Example Category and Subcategory EAL EAL FA1 1 F - Fission Product Barriers FA1.1 FS1 1 F - Fission Product Barriers FS1.1 FG1 1 F - Fission Product Barriers FG1.1 HU1 1 H - Hazards, 1 - Natural or Destructive Phenomena HU1.1 HUl 2 H - Hazards, 1 - Natural or Destructive Phenomena HU1.2 HU1 3 H - Hazards, 1 - Natural or Destructive Phenomena HU1.3 HU1 4 H - Hazards, 1 - Natural or Destructive Phenomena HU1.4 HU1 5 H - Hazards, 1 - Natural or Destructive Phenomena HU1.5 HU2 1 H - Hazards, 2 - Fire or Explosion HU2.1 HU2 2 H - Hazards, 2 - Fire or Explosion HU2.2 HU3 1 H - Hazards, 3 - Hazardous Gas HU3.1 HU3 2 H - Hazards, 3 - Hazardous Gas HU3.2 HU4 1,2,3 H - Hazards, 4 - Security HU4.1 HU5 1 H - Hazards, 6 - Judgment HU6.1 HA1 1 H - Hazards, 1 - Natural or Destructive Phenomena HA1.1 HA1 2 H - Hazards, 1 - Natural or Destructive Phenomena HA1.2 HA1 3 H - Hazards, 1 - Natural or Destructive Phenomena HA1.3 HA1 4 H - Hazards, 1 - Natural or Destructive Phenomena HA1.4 10 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI CCNPP Example Category and Subcategory EAL EAL HAl 5 H - Hazards, 1 - Natural or Destructive Phenomena HA1.6 HAl 6 H - Hazards, 1 - Natural or Destructive Phenomena HA1.5 HA2 1 H - Hazards, 2 - Fire or Explosion HA2.1 HA3 1 H - Hazards, 3 - Hazardous Gas HA3.1 HA4 1, 2 H - Hazards, 4 - Security HA4.1 HA5 1 H - Hazards, 5 - Control Room Evacuation HA5.1 HA6 1 H - Hazards, 6 -Judgment HA6.1 HS2 1 H - Hazards, 5 - Control Room Evacuation HS5.1 HS3 1 H - Hazards, 6 - Judgment HS6.1 HS4 1 H - Hazards, 4 - Security HS4.1 HG1 1 H - Hazards, 4 - Security HG4.1 HG1 2 H - Hazards, 4 - Security HG4.2 HG2 1 H - Hazards, 6 - Judgment HG6.1 SUl 1 S - System Malfunction, 1 - Loss of AC Power SU1.1 SU2 1 S - System Malfunction, 4 - Inability to Reach or Maintain Shutdown SU4.1 Conditions SU3 1 S - System Malfunction, 5 - Instrumentation SU5.1 SU4 1 S - System Malfunction, 7 - Fuel Clad Degradation SU7.2 SU4 2 S - System Malfunction, 7- Fuel Clad Degradation SU7.1 11 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI CCNPP Example Category and Subcategory EAL EAL SU5 1, 2 S - System Malfunction, 8 - RCS Leakage SU8.1 SU6 1,2 S - System Malfunction, 6 -Communications SU6.1 SU8 1 (BWR) N/A N/A SU8 1 (PWR) S - System Malfunction, 3 - Criticality & RPS Failure SU3.1 SA2 1 S - System Malfunction, 3 - Criticality & RPS Failure SA3.1 SA4 1 S - System Malfunction, 5 - Instrumentation SA5.1 SA5 1 S - System Malfunction, 1 - Loss of AC Power SA1.1 SS1 1 S - System Malfunction, 1 - Loss of AC Power SS1.1 SS2 1 S - System Malfunction, 3 - Criticality & RPS Failure SS3.1 SS3 1 S - System Malfunction, 1 - Loss of DC Power SS2.1 SS6 1 S - System Malfunction, 5 - Instrumentation SS5.1 SG1 1 S - System Malfunction, 1 - Loss of AC Power SG1.1 SG2 1 S - System Malfunction, 3 -Criticality & RPS Failure SG3.1 12 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP Table 3 - Summary of Deviations NEI CCNPP IC Example EAL EAL Description SU5 1, 2 SU8.1 The phrase "for ; 15 min.(Note 4)" has been added to the CCNPP EAL to allow mitigation by operating procedures prior to declaration. This is a deviation from NEI 99-01 Revision 5. HU2 1 HU2.1 The third paragraph of the NEI basis has been edited to clarify the significance of the 15-minute duration. Ifthe alarm cannot be verified by redundant Control Room or nearby Fire Panel indications, notification from the field that a fire exists starts the concurrent 15-minute classification and fire suppression clocks. This change is consistent with the manner in which the Control Room and Fire Brigade leaders verify fires. This change is necessary to avoid declaring Unusual Event emergencies for spurious alarms that, due to the sensor location, cannot be verified within 15 minutes of receipt of the alarm. This is a deviation from NEI 99-01 Revision 5. 13 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP Category R Abnormal Rad Levels / Radiological Effluents 14 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI IC# NEI IC Wording and Mode CCNPP CCNPP IC Wording and Mode Difference/Deviation Justification Applicability IC#(s) Applicability AU1 Any release of gaseous or liquid RU1 ANY release of gaseous or liquid The CCNPP ODCM limits provide the site-specific radioactivity to the environment radioactivity to the environment Radiological Effluent Technical Specifications. greater than 2 times the greater than 2 times the ODCM for 60 Radiological Effluent Technical minutes or longer Specifications/ODCM for 60 MODE: All minutes or longer. MODE: All NEI EALEx. E CCNPP NEI Example EAL Wording EAL # CCNPP EAL Wording Difference/Deviation Justification 1 VALID reading on ANY of the RU1.1 ANY gaseous monitor reading > Table The NEI phrase "VALID reading on ANY..." has been following radiation monitors R-1 column "UE" for > 60 min. (Note 2) changed to "ANY... reading." All EAL thresholds assume greater than the reading shown Note 2: The ED should not wait until valid readings for emergency classification. This change for 60 minutes or longer: the applicable time has elapsed, but implements EAL FAQ #4. (site specific monitor list and should declare the event as soon as it The NEI phrase "...of the following radiation monitors greater threshold values) is determined that the release duration than the reading shown ... (site specific monitor list and Note: The Emergency Director has exceeded, or will likely exceed, the threshold values)" has been replaced with "...Gaseous should not wait until the applicable time. In the absence of data monitors > Table R-1 column "UE"..." UE, Alert, SAE and GE applicable time has elapsed, but to the contrary, assume that the thresholds for all CCNPP continuously monitored gaseous should declare the event as soon release duration has exceeded the release pathways are listed in Table R-1 to consolidate the as it is determined that the applicable time if an ongoing release is information in a single location and, thereby, simplify release duration has exceeded, detected and the release start time is identification of the thresholds by the EAL user. The values or will likely exceed, the unknown. shown in Table R-1 column "UE", consistent with the NEI applicable time. In the absence of bases, represent two times the ODCM release limits for both data to the contrary, assume that liquid and gaseous release. the release duration has exceeded the applicable time if Gaseous release is emphasized in this EAL to be consistent an ongoing release is detected with the NEI basis, which states: "Some sites may find it and the release start time is advantageous to address gaseous and liquid releases with unknown. separate initiating conditions and EALs." The NEI phrase "...for 60 minutes or longer" has been replaced with "... 60 min." to reduce EAL user reading 15 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI EALEx.

     #                                      EALPP NEI Example EAL Wording        CCNPP           CCNPP EAL Wording                               Difference/Deviation Justification burden. The symbol ">" means "greater than or equal to" and thus implements the intent of the NEI phrase.

Reference to the NEI note is included in the EAL wording

                                                                                           "(Note 2)." Numbering the note facilitates referencing in the EAL matrix.

2 VALID reading on any effluent RU1.2 Liquid monitor reading > Table R-1 The NEI phrase "VALID reading on any..." has been monitor reading greater than 2 column "UE" for > 60 min. (Note 2) changed to "Liquid monitor reading." All EAL thresholds times the alarm setpoint Note 2: The ED should not wait until assume valid readings for emergency classification. This established by a current the applicable time has elapsed, but change implements EAL FAQ #4. radioactivity discharge permit for should declare the event as soon as it The NEI phrase "...effluent monitor reading greater than 2 60 minutes or longer. is determined that the release duration times the alarm setpoint established by a current radioactivity Note: The Emergency Director has exceeded, or will likely exceed, the discharge permit..." has been replaced with "... liquid monitor should not wait until the applicable time. In the absence of data > Table R-1 column "UE". UE and Alert thresholds for all applicable time has elapsed, but to the contrary, assume that the CCNPP effluent pathways governed by a radioactivity should declare the event as soon release duration has exceeded the discharge permit are listed in Table R-1 to consolidate the as it is determined that the applicable time if an ongoing release is release duration has exceeded, information in a single location and, thereby, simplify detected and the release start time is or will likely exceed, the identification of the thresholds by the EAL user. The values unknown. applicable time. In the absence of shown in Table R-1 column "UE", consistent with the NEI data to the contrary, assume that bases, represent two times the ODCM release limits for both the release duration has liquid and gaseous release. exceeded the applicable time if Liquid release is emphasized in this EAL to be consistent an ongoing release is detected with the NEI basis, which states "This alarm setpoint may be and the release start time is associated with a planned batch release, or a continuous unknown. release path." Liquid releases at CCNPP are the only planned batch releases subject to the discharge permit process. This change is also consistent with the NEI basis, which states "Some sites may find it advantageous to address gaseous and liquid releases with separate initiating conditions and EALs." The NEI phrase "...for 60 minutes or longer" has been replaced with "... 60 min." to reduce EAL user reading burden. The symbol ">" means "greater than or equal to" and thus implements the intent of the NEI phrase. The phrase "*with Waste Water effluent discharge not isolated" 16 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI EALEx. E IICCNPPNEI Example EAL Wording _EAL CCNPP EAL Wording Difference/Deviation Justification has been associated with the liquid release path in Table R-

1. At low classification levels, NEI states in the AU1/AA1 bases that the concern for classification is the continuing, uncontrolled release of radioactivity and not the magnitude of the release. When the liquid release is isolated, the release is no longer continuing nor is it uncontrolled. Therefore, the classification is not appropriate when the liquid release is isolated.

Reference to the NEI note is included in the EAL wording

                                                                                                  "(Note 2)." Numbering the note facilitates referencing in the EAL matrix.

t * + + 3 Confirmed sample analyses for RU1.3 Confirmed sample analyses for The CCNPP ODCM is the site-specific radiological effluent gaseous or liquid releases gaseous or liquid releases indicate Technical Specifications. indicates concentrations or concentrations or release rates > 2 x The NEI phrase "2 times" has been replaced with phrase "2 release rates greater than 2 ODCM limits for > 60 min. (Note 2) x" to reduce EAL user reading burden. The phrases have the times (site specific RETS values) Note 2: The ED should not wait until same meaning. for 60 minutes or longer. the applicable time has elapsed, but The NEI phrase "The NEI phrase "...for 60 minutes or longer" Note: The Emergency Director should declare the event as soon as it has been replaced with "...> 60 min." to reduce EAL-user should not wait until the is determined that the release duration reading burden. The symbol ">"means "greater than or equal applicable time has elapsed, but has exceeded, or will likely exceed, the to" and thus implements the intent of the NEI phrase. should declare the event as soon applicable time. In the absence of data as it is determined that the to the contrary, assume that the Reference to the NEI note is included in the EAL wording release duration has exceeded, release duration has exceeded the "(Note 2)." Numbering the note facilitates referencing in the or will likely exceed, the applicable time if an ongoing release is EAL matrix. applicable time. In the absence of detected and the release start time is data to the contrary, assume that unknown. the release duration has exceeded the applicable time if an ongoing release is detected and the release start time is unknown. 4 VALID reading on perimeter N/A N/A Deleted NEI Example EAL #4 because the plant is not radiation monitoring system equipped with a perimeter radiation monitoring system. This reading greater than 0.10 mR/hr threshold is properly addressed by the radiation monitors above normal* background for 60 17 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI EALEx. CCNPP

    #       NEI Example EAL Wording             EAL #              CCNPP EAL Wording                               Difference/Deviation Justification minutes or longer. [for sites                                                             listed in Table R-1 and dose assessment capabilities.

having telemetered perimeter monitors] 5 VALID indication on automatic N/A N/A Deleted NEI Example EAL #5 because the plant is not real-time dose assessment equipped with real-time dose assessment. This threshold is capability indicating greater than properly addressed by the radiation monitors listed in Table (site specific value) for 60 R-1 and dose assessment capabilities. minutes or longer. [for sites having such capability] Table R-1 Effluent Monitor Classification Thresholds Monitor GE I SAE Alert [ UE Gaseous WRNGM 3.2E+09 pCi/sec 3.2E+08 pCi/sec 3.2E+07 pCi/sec 3.2E+05 pCi/sec (RIC-5415) Main Steam Effluent 40.0 rem/hr 4.0 rem/hr 0.40 rem/hr N/A (RI-5421, RI-5422) Main Vent N/A N/A N/A 2.0E+05 cpm (RI-5415) Waste Processing N/A N/A N/A 4.OE+05 cpm (RI-541 0) Fuel Handling Area Vent N/A N/A N/A 3.4E+05 cpm (RI-5420) Liquid Liquid Waste Disch* N/A N/A off-scale hi 8.4E+05 cpm (RE-2201)

                                                                                                . with effluent discharge not isolated 18 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI IC# NEI IC Wording and Mode CCNPP CCNPP IC Wording and Mode Difference/Deviation Justification Applicability IC#(s) Applicability AU2 UNPLANNED rise in plant RU2 Unplanned rise in plant radiation levels None radiation levels MODE: All MODE: All NEI EA Ex. E EALPP NEI Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification EAL # EAL # 1 a. UNPLANNED water level RU2.1 UNPLANNED water level drop in a The site specific level or indication of an unplanned water drop in a reactor refueling reactor refueling pathway as indicated level drop that may result in increased area radiation are pathway as indicated by (site by ANY of the following (Note 3): either: the inability to restore and maintain SFP water level > specific level or indication).

• Inability to restore and maintain Technical Specifications (65 ft 8.5 in.), the inability to restore AND SFP level > Technical Specification and maintain RFP level > Technical Specification limit (56 ft limit (65 ft 7 in) 8.5 in) or report of visual observation of an uncontrolled drop

b. VALID Area Radiation in water level in the RFP or SFP.

Monitor reading rise on (site

• Inability to restore and maintain specific list). RFP level > Technical The NEI term "VALID" has been deleted. All EAL thresholds Specification limit (56 ft 8.5 in) assume valid readings for emergency classification. This

                                                      . Report of visual observation of an    change implements EAL EAQ #4.

uncontrolled drop in water level in The site specific area radiation monitors are listed. the RFP or SFP Note 3 has been added to the plant EAL wording to ensure AND subcategory C.3 EALs are reviewed when loss of water Area radiation monitor reading rise on shielding above spent fuel adversely affects area radiation ANY of the following: levels.

                                                      " SFP Area RM-320 EL-69 (RI-7024)
                                                      " Spent Fuel Handling Machine (RI-7025)
                                                      " Unit 1/2 CNTMT EL-69 (RI-5316A/B/C/D)

Note 3: If loss of water level in the refueling pathway occurs while in Mode 5, 6 or D, consider classification 19 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP under EALs CU3.1, CU3.2 or CU3.3 I. .4 4 4 2 UNPLANNED VALID Area RU2.2 UNPLANNED area radiation readings The NEI term "monitor" has been deleted to clarify that Radiation Monitor readings or increases by a factor of 1,000 over radiation readings obtained by portable survey instruments survey results indicate a rise by NORMAL LEVELS are an acceptable source for assessing this EAL. a factor of 1000 over normal* levels. The NEI term "VALID" has been deleted. All EAL thresholds

          *Normal can be considered as                                                       assume valid readings for emergency classification. This change implements EAL FAQ #4.

the highest reading in the past twenty-four hours excluding the Deleted the asterisk phrase and added the defined phrase to current peak value. the EAL Technical Bases: "Normal Levels As applied to radiological IC/EALs, the highest reading in the past twenty-four hours excluding the current peak value." This change implements EAL FAQ #5. 20 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP CCNPP NEI IC# NEI IC Wording IC#(s) CCNPP IC Wording Difference/Deviation Justification AA1 Any release of gaseous or liquid RA1 ANY release of gaseous or liquid The CCNPP ODCM limits provide the site-specific radioactivity to the environment radioactivity to the environment Radiological Effluent Technical Specifications. greater than 200 times the greater than 200 times the ODCM for Radiological Effluent Technical 15 minutes or longer Specifications/ODCM for 15 MODE: All minutes or longer. MODE: All NEI Ex. NEI Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification EAL # EAL # 1 VALID reading on ANY of the RA1.1 ANY gaseous monitor reading > Table The NEI phrase "VALID reading on ANY..." has been following radiation monitors R-1 column "Alert" for _>15 min. (Note changed to "ANY... reading." All EAL thresholds assume valid greater than the reading shown 2) readings for emergency classification. This change for 15 minutes or longer: implements EAL FAQ #4. (site specific monitor list and Note 2: The ED should not wait until The NEI phrase "... of the following radiation monitors greater threshold values) the applicable time has elapsed, but than the reading shown ... " has been replaced with Note: The Emergency Director should declare the event as soon as it ... gaseous monitors > Table R-1 column "Alert"..." should not wait until the is determined that the release duration The CCNPP radiation monitors that detect radioactivity applicable time has elapsed, but has exceeded, or will likely exceed, the effluent release to the environment are listed in Table R-1. should declare the event as soon applicable time. In the absence of data UE, Alert, SAE and GE thresholds for all CCNPP continuously as it is determined that the to the contrary, assume that the monitored gaseous release pathways are listed in Table R-1 release duration has exceeded, release duration has exceeded the to consolidate the information in a single location and, or will likely exceed, the applicable time if an ongoing release is thereby, simplify identification of the thresholds by the EAL-applicable time. In the absence of detected and the release start time is user. data to the contrary, assume that unknown. The values shown in Table R-1 column "Alert", consistent with the release duration has the NEI bases, represent two hundred times the ODCM exceeded the applicable time if release limits for both liquid and gaseous release. an ongoing release is detected and the release start time is The NEI phrase "...for 15 minutes or longer" has been unknown. replaced with .. > 15 min." to reduce EAL-user reading burden. The symbol ">" means "greater than or equal to" and thus implements the intent of the NEI phrase. 21 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP Reference to the NEI note is included in the EAL wording

                                                                                                   "(Note 2)." Numbering the note facilitates referencing in the EAL matrix.
      +                                    4-       4-                                          4-2     VALID reading on any effluent         RA1.2    Liquid monitor reading > Table R-1          The NEI phrase "VALID reading on any..." has been changed monitor reading greater than 200               column "Alert" for > 15 min. (Note 2)       to "Liquid monitor reading." All EAL thresholds assume valid times the alarm setpoint                                                                   readings for emergency classification. This change Note 2: The ED should not wait until established by a current                                                                   implements EAL FAQ #4.

the applicable time has elapsed, but radioactivity discharge permit for should declare the event as soon as it The NEI phrase "...effluent monitor reading greater than 200 15 minutes or longer. is determined that the release duration times the alarm setpoint established by a current radioactivity Note: The Emergency Director has exceeded, or will likely exceed, the discharge permit ... " has been replaced with "...liquid should not wait until the applicable time. In the absence of data monitors > Table R-1 column "ALERT" for > 15 min ... " applicable time has elapsed, but to the contrary, assume that the UE, Alert, SAE and GE thresholds for all CCNPP continuously should declare the event as soon release duration has exceeded the monitored release pathways are listed in Table R-1 to as it is determined that the applicable time if an ongoing release is consolidate the information in a single location and, thereby, release duration has exceeded, detected and the release start time is simplify identification of the thresholds by the EAL user. or will likely exceed, the unknown. applicable time. In the absence of Liquid release is emphasized in this EAL to be consistent with data to the contrary, assume that the NEI basis, which states "This alarm setpoint may be the release duration has associated with a planned batch release, or a continuous exceeded the applicable time if release path." Liquid releases at CCNPP are the only planned an ongoing release is detected batch releases subject to the discharge permit process. This and the release start time is change is also consistent with the NEI basis, which states unknown. "Some sites may find it advantageous to address gaseous and liquid releases with separate initiating conditions and EALs." The phrase "with Waste Water effluent not isolated" has been associated with the liquid release path. At low classification levels, NEI states in the RUl/RA1 bases that the concern for classification is the continuing, uncontrolled release of radioactivity and not the magnitude of the release. When the liquid release is isolated, the release is no longer continuing nor is it uncontrolled. Therefore, the classification is not appropriate when the liquid release is isolated. The NEI phrase "...for 15 minutes or longer" has been replaced with "... 15 min." to reduce EAL-user reading burden. The symbol ">"means "greater than or equal to" and thus implements the intent of the NEI phrase. Reference to the NEI note is included in the EAL wording 22 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP

                                                                                          "(Note 2)." Numbering the note facilitates referencing in the EAL matrix.

3 Confirmed sample analyses for RA1.3 Confirmed sample analyses for The NEI phrase "200 times" has been replaced with phrase gaseous or liquid releases gaseous or liquid releases indicate "200 x" to reduce EAL-user reading burden. The phrases indicates concentrations or concentrations or release rates > 200 x have the same meaning. release rates greater than 200 ODCM limits for > 15 min. The CCNPP ODCM is the site-specific effluent Technical times (site specific RETS values) Note 2: The ED should not wait until Specifications. for 15 minutes or longer. the applicable time has elapsed, but The NEI phrase "...for 15 minutes or longer" has been Note: The Emergency Director should declare the event as soon as it repiaced with "...2 15 min." to reduce EAL-user reading should not wait until the is determined that the release duration applicable time has elapsed, but has exceeded, or will likely exceed, the burden. The symbol "->"means "greater than or equal to" and should declare the event as soon applicable time. In the absence of data thus implements the intent of the NEI phrase. as it is determined that the to the contrary, assume that the Reference to the NEI note is included in the EAL wording release duration has exceeded, release duration has exceeded the "(Note 2)." Numbering the note facilitates referencing in the or will likely exceed, the applicable time if an ongoing release is EAL matrix. applicable time. In the absence of detected and the release start time is data to the contrary, assume that unknown. the release duration has exceeded the applicable time if an ongoing release is detected and the release start time is unknown. 4 VALID reading on perimeter N/A N/A Deleted NEI Example EAL #4 because the plant is not radiation monitoring system equipped with a perimeter radiation monitoring system. This reading greater than 10.0 mR/hr threshold is properly addressed by the radiation monitors above normal* background for 15 listed in Table R-1 and dose assessment capabilities. minutes or longer. [for sites having telemetered perimeter monitors] 5 VALID indication on automatic N/A N/A Deleted NEI Example EALs #5 because the plant is not real-time dose assessment equipped with and real-time dose assessment. This threshold capability indicating greater than is properly addressed by the radiation monitors listed in Table (site specific value) for 15 R-1 and dose assessment capabilities. minutes or longer. [for sites having such capability] 23 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI IC# NEI IC Wording CCNPP CCNPP IC Wording Difference/Deviation Justification IC#(S) AA2 Damage to irradiated fuel or RA2 Damage to irradiated fuel or loss of None loss of water level that has water level that has resulted or will resulted or will result in the result in the uncovering of irradiated fuel uncovering of irradiated fuel outside the Reactor Vessel. outside the reactor vessel. MODE: All MODE: All NEI EALEx. E CCNPP NEI Example EAL Wording EAL # CCNPP EAL Wording Difference/Deviation Justification A water level drop in the reactor RA2.2 A water level drop in a reactor The terms "reactor refueling cavity, spent fuel pool or fuel refueling cavity, spent fuel pool refueling pathway that will result in transfer canal" have been replaced with the term "reactor or fuel transfer canal that will irradiated fuel becoming uncovered refueling pathway" to encompass all three volumes where result in irradiated fuel becoming irradiated fuel may be located. This change implements EAL uncovered. FAQ #6. 2 A VALID alarm or (site specific RA2.1 Alarm on ANY of the following The NEI term "VALID" has been deleted. All EAL thresholds elevated reading) on ANY of the radiation monitors due to damage to assume valid readings for emergency classification. This following irradiated due fuel toordamage to loss of water irradiated fuel or loss of water level: change implements EAL FAQ #4. level. f Fuel Handling Area Vent (RI- The EAL provides a site-specific list of radiation monitors 5420) applicable to this threshold. (site specific radiation monitors)

• SFP Area RM-320 EL-69 (RI-7024)
• Spent Fuel Handling Machine (RI-7025)
• Unit 1/2 CNTMT EL-69 (RI-5316AIB/ClD) 24 of 125

EAL Comparison Matrix OSSE Project #09-0803 CCNPP NEI IC# NEI IC Wording CCNPP CCNPP IC Wording Difference/Deviation Justification IC#(s) AA3 Rise in radiation levels within the RA3 Rise in radiation levels within the None facility that impedes operation of facility that impedes operation of systems required to maintain systems required to maintain plant plant safety functions safety functions MODE: All MODE: All NEI EALEx. E CCNPP NEI Example EAL Wording EAL # CCNPP EAL Wording Difference/Deviation Justification VALID (site-specific) radiation RA3.1 Dose rates > 15 mRem/hr in ANY of The NEI term "VALID" has been deleted. All EAL thresholds monitor readings GREATER the following areas requiring assume valid readings for emergency classification. This THAN 15 mR/hr in areas continuous occupancy to maintain change implements EAL FAQ #4. requiring continuous occupancy plant safety functions: The words "VALID (site-specific) radiation monitor readings to maintain plant safety functions: 0 Control Room GREATER THAN" was replaced with "Dose rates >..." It (Site-specific) list

• CAS doesn't matter if the 15 mRem/hr was measured with an ARM
• SAS or survey instrument, therefore, the term radiation monitor was deleted to not confuse those who may think that only implies a fixed ARM. The symbol '5"means "greater than."

The Control Room, CAS and SAS are the CCNPP areas requiring continuous occupancy to maintain plant safety functions. Since all three areas require continuous occupancy, elevated dose rates in any one area could preclude occupancy and, therefore, satisfy the intent of the IC. 25 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP CCNPP NEI IC# NEI IC Wording IC#(s) CCNPP IC Wording Difference/Deviation Justification AS1 Off-site dose resulting from an RS1 Offsite dose resulting from an actual or The NEI abbreviation "mrem" has been replaced with the plant actual or IMMINENT release of imminent release of gaseous abbreviation "mRem" to agree with units of measure given in gaseous radioactivity greater radioactivity exceeds 100 mRem the EPA PAGs. This change implements EAL FAQ #8. than 100 mrem TEDE or 500 TEDE or 500 mRem thyroid CDE for The phrase "using actual meteorology" has been added to the mrem Thyroid CDE for the actual the actual or projected duration of the CCNPP IC for consistency with RG1.1 IC wording. This or projected duration of the release using actual meteorology change implements EAL FAQ #9. release. MODE: All MODE: All MODE: All NEI EALEx. E EALPP NEI Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification 1 VALID reading on ANY of the RS1.1 ANY radiation monitor reading > Table The NEI phrase "VALID reading on ANY..." has been following radiation monitors R-1 column "SAE" for _>15 min. (Note changed to "ANY... reading." All EAL thresholds assume valid greater than the reading shown 1) readings for emergency classification. This change for 15 minutes or longer:

• Do not delay declaration implements EAL FAQ #4.

(site specific monitor list and awaiting dose assessment The NEI phrase "...of the following.., the reading shown..." threshold values) results has been replaced with "...Table R-1 column "SAE"..." The Note: The Emergency Director If dose assessment results are site-specific list is provided in Table R-1. should not wait until the available, declaration should be The NEI phrases "greater than" and "... 15 minutes or longer" applicable time has elapsed, but based on dose assessment have been replaced with ">" and "... 15 min.", respectively, to should declare the event as instead of radiation monitor reduce EAL-user reading burden. The symbols implement the soon as it is determined that the values (see EAL RS1.2) intent of the NEI phrase. condition will likely exceed the applicable time. If dose Note 1:The ED should not wait until Reference to the NEI note is included in the EAL wording assessment results are the applicable time has "(Note 1)." Numbering the note facilitates referencing in the elapsed, but should declare the EAL matrix. available, declaration should be based on dose assessment event as soon as it is The second and third sentences of the NEI note have been instead of radiation monitor determined that the condition incorporated in the wording of the CCNPP EAL for values. Do not delay declaration will likely exceed the applicable clarification. EAL validation exercises demonstrated the need awaiting dose assessment time to emphasis this information in a form other than a note. results. 26 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP 2 Dose assessment using actual RS1.2 Dose assessment using actual The NEI abbreviation "mrem" has been replaced with the plant meteorology indicates doses meteorology indicates doses > 100 abbreviation "mRem" to agree with units of measure given in greater than 100 mrem TEDE or mRem TEDE or 500 mRem thyroid the EPA PAGs. This change implements EAL FAQ #8. 500 mrem thyroid CDE at or CDE at or beyond the site boundary beyond the site boundary. 3 VALID perimeter radiation N/A N/A Deleted NEI Example EAL #3 because the plant is not monitoring system reading equipped with a perimeter radiation monitoring system. This greater than 100 mR/hr for 15 threshold is properly addressed by the radiation monitors minutes or longer. [for sites listed in Table R-1 and dose assessment capabilities. having telemetered perimeter monitors] 4 Field survey results indicate RS1.3 Field survey results indicate closed Split the example into two logical conditions separated by the closed window dose rates window dose rates > 100 mRem/hr "OR" logical connector for usability. greater than 100 mR/hr expected expected to continue for 2!60 min. at or The NEI abbreviation "R" has been replaced with the plant to continue for 60 minutes or beyond the site boundary abbreviation "Rem" to agree with units of measure given in the longer; or analyses of field survey samples indicate thyroid OR EPA PAGs. This change implements EAL FAQ #8. CDE greater than 500 mrem for Analyses of field survey samples The NEI phrase "one hour" has been abbreviated "1 hr" to one hour of inhalation, at or indicate thyroid CDE > 500 mRem for reduce EAL-user reading burden. beyond the site boundary. 1 hr of inhalation at or beyond the site Reference to the NEI note is included in the EAL wording boundary (Note 1) "(Note 1)." Numbering the note facilitates referencing in the EAL matrix. 27 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP CCNPP NEI IC# NEI IC Wording IC#(s) CCNPP IC Wording Difference/Deviation Justification AG1 Off-site dose resulting from an RG1 Offsite dose resulting from an The NEI abbreviation "mrem" has been replaced with the plant actual or IMMINENT release of actual or imminent release of abbreviation "mRem" to agree with units of measure given in the gaseous radioactivity greater gaseous radioactivity greater than EPA PAGs. than 1000 mrem TEDE or 5000 1,000 mRem TEDE or 5,000 mrem Thyroid CDE for the mRem thyroid CDE for the actual actual or projected duration of or projected duration of the the release using actual release using actual meteorology meteorology. MODE: All MODE: All NEI EALEx. E CCNPP NEI Example EAL Wording EAL # CCNPP EAL Wording Difference/Deviation Justification 1 VALID reading on ANY of the RG1.1 ANY radiation monitor reading > The NEI phrase "VALID reading on ANY..." has been changed to following radiation monitors Table R-1 column "GE" for > 15 "ANY... reading." All EAL thresholds assume valid readings for greater than the reading shown min. (Note 1) emergency classification. This change implements EAL FAQ #4. for 15 minutes or longer: 0 Do not delay declaration The NEI phrase "...of the following.., the reading shown..." has (site specific monitor list and awaiting dose assessment been replaced with "...Table R-1 column "GE"..." The site-specific threshold values) results list is provided in Table R-1. Note: The Emergency 0 If dose assessment results The symbol ">"means "greater than." Director should not wait until the are available, declaration The NEI phrases "greater than" and "... 15 minutes or longer" have applicable time has elapsed, but should be based on dose been replaced with ">" and "...> 15 min.", respectively, to reduce should declare the event as assessment instead of EAL-user reading burden. The symbols implement the intent of the soon as it is determined that the radiation monitor values NEI phrase. condition will likely exceed the (see EAL RG1.2) applicable time. If dose Reference to the NEI note is included in the EAL wording "(Note 1)." assessment results are Note 1:The ED should not wait Numbering the note facilitates referencing in the EAL matrix. available, declaration should be until the applicable time The second and third sentences of the NEI note have been based insteadonof dose assessment radiation monitor has elapsed, declare but should the event as soon incond incorporated in the thirding wording of of thethe NEI EAL for CCNPP h clarification. ave en EAL instad onior f rdiaion eclre te eentas oon validation exercises demonstrated the need to emphasis this values. Do not delay declaration as it is determined that the information in a form other than a note. awaiting dose assessment condition will likely exceed results. the applicable time 28 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP 2 Dose assessment using actual RG1.2 Dose assessment using actual The NEI phrase "greater than" has been replaced with the symbol meteorology indicates doses meteorology indicates doses > '5"to reduce EAL-user reading burden. The symbol '5"means greater than 1000 mrem TEDE 1,000 mRem TEDE or 5,000 "greater than" and thus implements the intent of the NEI phrase. or 5000 mrem thyroid CDE at or mRem thyroid CDE at or beyond beyond the site boundary. the site boundary 3 VALID perimeter radiation N/A N/A Deleted NEI Example EAL #3 because the plant is not equipped monitoring system reading with a perimeter radiation monitoring system. This threshold is greater than 1000 mRlhr for 15 properly addressed by the radiation monitors listed in Table R-1 and minutes or longer. [for sites dose assessment capabilities. having telemetered perimeter monitors] 4 Field survey results indicate RG1.3 Field survey results indicate Split the example into two logical conditions separated by the "OR" closed window dose rates closed window dose rates > 1,000 logical connector for usability. greater than 1000 mR/hr mRem/hr expected to continue for The NEI abbreviation "R" has been replaced with the plant expected to continue for 60 > 60 min. at or beyond the site abbreviation "Rem" to agree with units of measure given in the EPA minutes or longer; or analyses boundary PAGs. This change implements EAL FAQ #8. of field survey samples indicate thyroid CDE greater than 5000 OR The NEI phrase "one hour" has been abbreviated "1 hr" to reduce mrem for one hour of inhalation, Analyses of field survey samples EAL-user reading burden. at or beyond site boundary. indicate thyroid CDE > 5,000 Reference to the NEI note is included in the EAL wording "(Note 1)." mRem for 1 hr of inhalation at or Numbering the note facilitates referencing in the EAL matrix. beyond the site boundary (Note 1) 29 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP Category C Cold Shutdown / Refueling System Malfunction 30 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI IC# NEI IC Wording CCNPP CCNPP IC Wording Difference/Deviation Justification IC#(s) CUl RCS Leakage CU3 RCS Leakage None MODE: Cold Shutdown MODE: 5 - Cold Shutdown NEI EALEx. E CCNPP NEI Example EAL Wording EAL # CCNPP EAL Wording Difference/Deviation Justification 1 Note: The Emergency Director CU3.1 RCS leakage results in the The BWR portion of the NEI EAL has not been implemented because should not wait until the inability to maintain or CCNPP is a PWR. applicable time has elapsed, restore EITHER of the following The site-specific pressurizer low level heater trip actuation setpoint is but should declare the event as for > 15 min. (Note 4): specified. soon as it is determined that the Pressurizer level> 101 in. condition will likely exceed the The NEI phrase "15 minutes or longer" has been replaced with "> 15 applicable time. OR min." to reduce EAL-user reading burden. The symbol "Z"means

1. RCS leakage results in RCS level within the target "greater than or equal to" and thus implements the intent of the NEI the inability to maintain or band established by phrase.

restore RPV level greater than procedure (when the level Reference to the NEI note is included in the EAL wording "(Note 4)." (site specific low level RPS band was established below Numbering the note facilitates referencing in the EAL matrix. actuation setpoint) for 15 101 in.) minutes or longer. [BWR] Note 4: The ED should not wait

1. RCS leakage results in the until the applicable time has inability to maintain or restore elapsed, but should declare the level within (site specific event as soon as it is pressurizer or RCS/RPV level determined that the condition target band) for 15 minutes or has exceeded, or will likely longer. [PWR] exceed, the applicable time 31 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI IC# NEI IC Wording CCNPP CCNPP IC Wording Difference/Deviation Justification IC#(S) CU2 UNPLANNED loss of RCS/RPV CU3 RCS leakage IC wording aligned with NEI IC CUl to support grouping NEI IC CUl inventory, Mand CU2 EALs under the same subcategory. There is no EMODE: 6 - Refuel fundamental difference between an unplanned loss of RCS MODE: Refueling inventory and RCS leakage. This change implements EAL FAQ #41. NEI Ex. NEI Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification EAL # EAL # Note: The Emergency Director CU3.2 UNPLANNED RCS level drop The NEI abbreviation "RCS/RPV" has been changed to "RCS" to should not wait until the below EITHER of the following use terminology commonly accepted at PWRs. applicable time has elapsed, but for > 15 min. (Note 4): The NEI phrase 15 minutes or longer"has been replaced with '5 15 should declare the event as Reactor Vessel flange (44 ft) mhe o preue EAL-user readngbe. Thesyb ola mean wit soon as it is determined that the (when the level band was min." to reduce EAL-user reading burden. The symbol "Z'means condition will likely exceed the established above the flange) "greater than or equal to" and thus implements the intent of the NEI applicable time. OR phrase. UNPLANNED RCS/RPV level Target band (when the level Reference to the NEI note is included in the EAL wording "(Note 4)." drop as indicated by either of the band was established below Numbering the note facilitates referencing in the EAL matrix. following: the flange) The NEI phrase "RPV flange" has been replaced with "Reactor

• RCS/RPV water level drop Note 4: The ED should not wait Vessel flange" to use terminology commonly accepted at PWRs.

below the RPV flange for until the applicable time has In the second bullet, the NEI phrase "RCS level band" has been 15 minutes or longer when elapsed, but should declare the replaced with "Target band" for consistency with terminology used in the RCS/RPV level band is event as soon as it is determined EAL CU3.1. established above the RPV that the condition has exceeded, The NEI introductory clause and the two NEI bulleted conditions flange. or will likely exceed, the have been reworded for clarification.

             " RCS/RPV water level drop             applicable time.

below the RCS level band for 15 minutes or longer when the RCS/RPV level band is established below the RPV flange. 2 RCS/RPV level cannot be CU3.3 RCS level cannot be monitored The NEI abbreviation "RCS/RPV" has been changed to "RCS" to monitored with a loss of with a loss of RCS inventory as II 32 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP RCS/RPV inventory as indicated indicated by an unexplained use terminology commonly accepted at PWRs. by an unexplained level rise in level rise in ANY Table C-2 The NEI phrase "(site-specific sump or tank)" has been replaced (site specific sump or tank). sump / tank attributable to RCS with "ANY Table C-2 sump / tank attributable to RCS leakage" for leakage clarification. The list of sumps and tanks is too large to include within the wording of the EAL and maintain readability. Table C-2 contains the site-specific list of sumps and tanks. Table C-2 RCS Leakage Indications

                                         " Containment sump

• Auxiliary Building sumps

                                         " Miscellaneous Waste System Tanks

• RWT
• RC Waste System Tank 33 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP CCNPP NEI IC# NEI IC Wording IC#(s) CCNPP IC Wording Difference/Deviation Justification CU3 AC power capability to CU1 AC power capability to 4kV vital "...emergency busses..." replaced with "...4kV vital buses..." as the emergency busses reduced to a buses reduced to a single power site specific terminology for emergency buses. single power source for 15 source for > 15 min. such that "... station blackout." replaced with "...a complete loss of all 4kV vital minutes or longer such that any ANY additional single failure bus power" as this describes the intended condition for CCNPP. additional single failure would would result in a complete loss result in station blackout. of all 4kV vital bus power The NEI phrase "15 minutes or longer' has been replaced with "_>15 min." to reduce EAL-user reading burden. The symbol "'" means RODEfe Refueling RldShutdowODE:

                                                                 - D   eled S        n     "greater than or equal to" and thus implements the intent of the NEI Refuel, D - Defueled              phrase.

Added "D - Defueled" to the mode applicability to correct omission in NEI 99-01. NEI EALEx. E CCNPP NEI Example EAL Wording EAL # CCNPP EAL Wording Difference/Deviation Justification 1 Note: The Emergency Director CU1.1 AC power capability to 4kV vital The NEI phrase "15 minutes or longer" has been replaced with "> 15 should not wait until the buses 11(21) and 14(24) min." to reduce EAL-user reading burden. The symbol "Z"means applicable time has elapsed, reduced to a single power "greater than or equal to" and thus implements the intent of the NEI but should declare the event source, Table C-1, for _>15 min. phrase. as soon as it is determined (Note 4) 4kV vital buses 11(21) and 14(24) are the CCNPP emergency that the condition will likely exceed the applicable time. AND buses. ANY additional single power Table C-1 provides a list of CCNPP onsite and offsite AC power source failure will result in a sources.

a. AC power capability to complete loss of all 4kV vital bus "..station blackout." replaced with "...a complete loss of all 4kV vital (site specific emergency power bus power" as this describes the intended condition for CCNPP. This busses) reduced to a single power source for 15 Note 4: The ED should not wait change implements EAL FAQ #36.

minutes or longer, until the applicable time has Reference to the NEI note is included in the EAL wording "(Note 4)." AND elapsed, but should declare the Numbering the note facilitates referencing in the EAL matrix. event as soon as it is determined

b. Any additional single power that the condition has exceeded, source failure will result in or will likely exceed, the station blackout. applicable time.

34 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP Table C-I AC Power Sources

• 1(2)A DG 0

1(2)B DG O OC DG, ifaligned

• 500kV transmission line 5051"
• 500kV transmission line 5052*
• 500kV transmission line 5072*

0 SMECO line, if aligned

• A credited 500kV line must have an independent 13kV service transformer 35 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP CCNPP NEI IC# NEI IC Wording IC#(s) CCNPP IC Wording Difference/Deviation Justification CU4 UNPLANNED loss of decay heat CU4 Unplanned loss of decay heat The NEI acronym "RPV" has been replaced with the phrase removal capability with irradiated removal capability "Reactor Vessel" to use terminology commonly accepted at PWRs. fuel in the RPV. MODE: 5 - Cold Shutdown, 6 - The NEI phrase "with irradiated fuel in the Reactor Vessel" has MODE: Cold Shutdown, Refuel been deleted to implement EAL FAQ #11. Refueling I I II NEI Ex. NEI Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification EAL # EAL # 1 UNPLANNED event results in CU4.1 UNPLANNED event results in The NEI phrase "...exceeding the Technical Specification cold RCS temperature exceeding the RCS temperature > 200OF shutdown temperature limit" has been replaced with "> 2000 F." Technical Specification cold >200°F is the Technical Specification cold shutdown temperature shutdown temperature limit, limit and is specified in the EAL instead of the NEI wording to reduce EAL-user reading burden. 2 Note: The Emergency Director CU4.2 Loss of all RCS temperature and The NEI abbreviation "RCS/RPV" has been changed to "RCS" to should not wait until the RCS level indication for _>15 min. use terminology commonly accepted at PWRs. applicable time has elapsed, but (Note 4) The NEI phrase "15 minutes or longer" has been replaced with '> should declare the event as soon ashitus detarmed that entheaNote 4: The ED should not wait 15 min." to reduce EAL-user reading burden. The symbol "Z" conditi wil letemikelye the until the applicable time has means "greater than or equal to" and thus implements the intent of condition will likely exceed the elapsed, applicable time. event as butsoonshould as it isdeclare the determined the NEI phrase. even assoo asit i deermned Reference to the NEI note is included in the EAL wording "(Note Loss of all RCS temperature and that the condition has exceeded, 4"ueringthe note is ref in the EAL matr RCS/RPV level indication for 15 or will likely exceed, the Numbering the note facilitates referencing in the EAL matrix. minutes or longer, applicable time. 36 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP CCNPP NEI IC# NEI IC Wording IC#(s) CCNPP IC Wording Difference/Deviation Justification CU6 Loss of all On-site or Off-site CU5 Loss of all onsite or offsite None communications capabilities, communications capabilities MODE: Cold Shutdown, MODE: 5 - Cold Shutdown, 6 - Refueling, Defueled Refuel, D - Defueled NEI Ex. NEI Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification EAL # EAL # 1 Loss of all of the following on-site CU5.1 Loss of all Table C-5 onsite CU5.1 implements Example EALs #1 and #2. These were communication methods affecting (internal) communication methods combined for improved usability. the ability to perform routine affecting the ability to perform The NEI example EALs specify site-specific lists of onsite and operations: routine operations offsite communications methods. The CCNPP EAL lists these (site specific list of OR methods in Table C-5 because the number of communications communications methods) Loss of all Table C-5 offsite methods is too long to include within the text of the EAL. of the following off-site (external) communication The adjectives "(internal)" and "(external)" have been added to the 2 2Loss of all Lommuncation mtheol gaffecting methods affecting the ability to CCNPP EAL for clarification. The terms "onsite/offsite" could be communication methods affecting perform offsite notifications to any interpreted as the location in which the communication originates notifications: agency instead of the location to which communication is directed. (site specific list of Added the words "...to any agency" to clarify the intent of the communications methods) bases statement: "The availability of one method of ordinary off-site communications is sufficient to inform federal, state, and local authorities of plant issues." 37 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP Table C-5 Communications Systems Onsite Offsite System (internal) (external) Commercial phone system X X Plant page system X Microwave telephone (Hot-Lines) (EOB) X X Dedicated offsite agency telephone system X FTS 2001 telephone system X CCNPP Radio System X X Satellite Phone System X Cellular Phone System X X 38 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI IC# NEI IC Wording CCNPP CCNPP IC Wording Difference/Deviation Justification IC#(s) CU7 Loss of required DC power for CU2 Loss of required DC power for The NEI phrase "15 minutes or longer" has been replaced with "_>15 15 minutes or longer. _>15 min. min." to reduce EAL-user reading burden. The symbol "Z"means MODE: Cold Shutdown, MODE: 5 - Cold Shutdown, 6 - "greater than or equal to" and thus implements the intent of the NEI Refueling Refuel phrase. NEI EALEx. E EALPP NEI Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification Note: The Emergency CU2.1 < 105 VDC for 2! 15 min. on the The NEI IC phrase "less than" has been replaced with "<" to reduce Director should not wait until the 125 VDC buses (11, 12, 21 or EAL-user reading burden. The symbol "<" means "less than" and thus applicable time has elapsed, but 22) that are required to monitor implements the intent of the NEI phrase. should declare the event as and control the removal of "105 VDC" is the site-specific bus voltage indication. soon as awitit is ildetermined sondiion deteredthat the thatthe decay heat (Note 4) deEmergency DC Buses (125V) 11, 12, 21 and 22 are the CCNPP vital condition will likely exceed the Note 4: The ED should not wait DC buses. applicable time. until the applicable time has elapsed, but should declare the The NEI phrase "15 minutes or longer" has been replaced with ">_ 15 Less than (site specific bus event as soon as it is min." to reduce EAL-user reading burden. The symbol "Z"means voltage indication) on required determined that the condition "greater than or equal to" and thus implements the intent of the NEI (site specific Vital DC busses) has exceeded, or will likely phrase. for 15 minutes or longer, exceed, the applicable time. The phrase "that are required to monitor and control the removal of decay heat" has been added to the EAL wording for clarification. It was not clear during EAL validation exercises which vital DC buses may be "required." The added phrase implements the first sentence of the NEI basis. Reference to the NEI note is included in the EAL wording "(Note 4)." Numbering the note facilitates referencing in the EAL matrix. 39 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI IC# NEI IC Wording CCNPP CCNPP IC Wording Difference/Deviation Justification IC#(s) CU8 Inadvertent Criticality CU6 Inadvertent criticality None MODE: Cold Shutdown, MODE: 5 - Cold Shutdown, 6 - Refueling Refueling NEI EALEx. E CCNPP NEI Example EAL Wording EAL # CCNPP EAL Wording Difference/Deviation Justification 1 UNPLANNED sustained positive N/A N/A NEI Example EAL #1 has not been implemented because it applies period observed on nuclear only to BWR plants. CCNPP is a PWR. PWRs are not equipped with instrumentation. (BWR) period meters. 2 UNPLANNED sustained positive CU6.1 An UNPLANNED sustained None startup rate observed on nuclear positive startup rate observed on instrumentation. (PWR) nuclear instrumentation 40 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI IC# NEI IC Wording CCNPP CCNPP IC Wording Difference/Deviation Justification IC#(s) CA1 Loss of RCS/RPV inventory. CA3 Loss of RCS inventory The NEI abbreviation "RCS/RPV" has been changed to "RCS" to use MODE: Cold Shutdown, MODE: 5 - Cold Shutdown, 6 - terminology commonly accepted at PWRs. Refueling Refuel NEI EALEx. E EALPP NEI Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification Loss of RCS/RPV inventory as CA3.1 Loss of inventory as indicated CA3.1 implements Example EALs #1 and #2. These were combined indicated by level less than (site by RCS water level < 35.6 ft (29 for improved usability. specific level), in. 6th alarm on RVLMS) The NEI abbreviation "RCS/RPV" has been changed to "RCS" to use [Low-Low ECCS actuation OR terminology commonly accepted at PWRs. setpoint / Level 2 (BWR)] RCS level cannot be monitored The bottom ID of the RCS hot leg is indicated by RFP level at [Bottom ID of the RCS loop for _>15 min. with a loss of RCS 35.6 ft or 29 in. (6th alarm) on RVLMS. (PWR)] inventory as indicated by an CCNPP is a PWR and is not equipped with the BWR low-low ECCS unexplained level rise in ANY actuation setpoint. should not wait until the ctorbTable C-2 sump /tank The NEI phrase "15 minutes or longer" has been replaced with ">_15 applicable time has elapsed, but attributable to RCS leakage min." to reduce EAL-user reading burden. The symbol "Z"means should declare the event as (Note 4) "greater than or equal to" and thus implements the intent of the NEI soon as it is determined that the Note 4: The ED should not wait phrase. condition will likely exceed the until the applicable time has applicable time. elapsed, but should declare the The NEI phrase "(site-specific sump or tank)" has been replaced with RCSIRPV level cannot beodetermined event as soon as it is "ANY Table C-2 sump / tank attributable to RCS leakage" for monitored foraninutbes that the condition clarification. The list of sumps and tanks is too large to include within monitored for 15 minutes or has exceeded, or will likely the wording of the EAL and maintain readability. Table C-2 contains longer with a loss of RCSIRPV exceed, the applicable time. the site-specific list of sumps and tanks as well as observation of inventory as indicated by an unisolable RCS leakage. unexplained level rise in (site Reference to the NEI note is included in the EAL wording "(Note 4)." specific sump or tank). Numbering the note facilitates referencing in the EAL matrix. 41 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI IC# NEI IC Wording CCNPP CCNPP IC Wording Difference/Deviation Justification IC#(S) CA3 Loss of all Off-site and all On- CA1 Loss of all offsite and all onsite "...emergency busses..." replaced with "...4kV vital buses..." as the Site AC power to emergency AC power to 4kV vital buses for site specific terminology for emergency buses. busses for 15 minutes or longer. > 15 min. The NEI phrase "15 minutes or longer" has been replaced with "_>15 MODE: Cold Shutdown, MODE: 5 - Cold Shutdown, 6 - min." to reduce EAL-user reading burden. The symbol "Z"means Refueling, Defueled Refuel, D - Defueled "greater than or equal to" and thus implements the intent of the NEI phrase. NEI Ex. NEI Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification EAL # EAL # 1 Note: The Emergency Director CA1.1 Loss of all offsite and all onsite The NEI phrase "15 minutes or longer" has been replaced with "_>15 should not wait until the AC power, Table C-1, to 4kV min." to reduce EAL-user reading burden. The symbol "Z"means applicable time has elapsed, but vital buses 11(21) and 14(24) "greater than or equal to" and thus implements the intent of the NEI should declare the event as for _>15 min. (Note 4) phrase. soon as it is determined that the Note 4: The ED should not wait 4kV vital buses 11(21) and 14(24) are the CCNPP emergency buses. condition will likely exceed the until the applicable time has applicable time. elapsed, but should declare the Table C-i provides a list of CCNPP onsite and offsite AC power Loss of all Off-Site and all On- event as soon as it is sources. Site AC Power to (site specific determined that the condition Reference to the NEI note is included in the EAL wording "(Note 4)." emergency busses) for 15 has exceeded, or will likely Numbering the note facilitates referencing in the EAL matrix. minutes or longer, exceed, the applicable time. 42 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI IC# NEI IC Wording CCNPP CCNPP IC Wording Difference/Deviation Justification IC#(S) CA4 Inability to maintain plant in cold CA4 Inability to maintain plant in cold None shutdown. shutdown MODE: Cold Shutdown, MODE: 5 - Cold Shutdown, 6 - Refueling Refuel NEI Ex. NEI Example EAL Wording EALCCNPP CCNPP EAL Wording Difference/Deviation Justification An UNPLANNED event results CA4.1 An UNPLANNED event results CA4.1 implements NEI EALs #1 and #2. The NEI example EALs in RCS (site temperature specific greater than Technical in EITHER: have been combined for simplification. Specification cold shutdown RCS temperature > 200OF The NEI phrase "greater than" has been replaced with ">" to reduce temperature limit) for greater for > Table C-4 duration EAL-user reading burden. The symbol ">" means "greater than" and thus implements the intent of the NEI phrase. than the specified duration on OR table. The NEI phrase "...exceeding the Technical Specification cold RCS pressure increase > 10 shutdown temperature limit" has been replaced with "> 2000 F." 200°F 2 An UNPLANNED event results psi due to an unplanned loss is the Technical Specification cold shutdown temperature limit. in RCS pressure increase of decay heat removal NEI criteria associated with RCS temperature exceeding the greater than 10 psi due to a loss capability (this condition is Technical Specification cold shutdown temperature limit are given in of RCS cooling. (PWR-This EAL not applicable in solid plant Table C-. does not apply in Solid Plant conditions) conditions.) The NEI phrase "An UNPLANNED event results in RCS pressure increase greater than 10 psi due to a loss of RCS cooling" has been changed to "RCS pressure increase > 10 psi due to an unplanned loss of decay heat removal capability" for clarification. This change implements EAL FAQ #13. The CCNPP pressure of 10 psig is the site-specific RCS pressure based on the accuracy of RCS pressure instruments P1-103, P1-1 03-1 and P1-105. 43 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP Table: RCS Reheat Duration Thresholds RCS Containment Closure Duration Intact (but not RCS Reduced N/A 60 minutes Inventory [PWR]) Not intact or RCS Reduced Established 20 minutes-Inventory (PWR) Not Established 0 minutes

• If an RCS heat removal system is in operation within this time frame and RCS temperature is being reduced, the EAL is not applicable.

Table C-4 RCS Reheat Duration Thresholds RCS Status Containment Closure Duration Status Intact AND not reduced inventory Not intact OR reduced Established 20 min.* inventory Not established 0 min.

• If an RCS heat removal system is in operation within this time frame and RCS temperature is being reduced, the EAL is not applicable.

44 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP CCNPP NEI IC# NEI IC Wording IC#(s) CCNPP IC Wording Difference/Deviation Justification CS1 Loss of RCS/RPV inventory CS2 Loss of RCS inventory affecting The NEI abbreviation "RCS/RPV" has been changed to "RCS" to use affecting core decay heat core decay heat removal terminology commonly accepted at PWRs. removal capability capability MODE: Cold Shutdown, MODE: 5 - Cold Shutdown, 6 - Refueling Refuel NEI EALEx.

     #     NEI Example EAL Wording     CCNPP EAL #        CCNPP EAL Wording                                 Difference/Deviation Justification 1    With CONTAINMENT                CS3.1  With CONTAINMENT                    The NEI abbreviation "RCS/RPV" has been changed to "RCS" to use CLOSURE not established,               CLOSURE not established,            terminology commonly accepted at PWRs.

RCS/RPV level less than (site RCS level < 34.7 ft (19 in. 7th 10 inches below the bottom ID of the RCS hot leg loop is indicated by specific level), alarm on RVLMS) the 7th alarm (19 in. above TOAF) on RVLMS. This value was [6" below the bottom ID of the selected instead of 6 in. below the hotleg as it is operationally RCS loop (PWR)] significant and readily recognized on RVLMS. [6" below the low-low ECCS CCNPP is a PWR and is not equipped with the BWR low-low ECCS actuation setpoint (BWR)] actuation setpoint. 2 With CONTAINMENT CS3.2 With CONTAINMENT The NEI abbreviation "RCS/RPV" has been changed to "RCS" to use CLOSURE established, CLOSURE established, RCS terminology commonly accepted at PWRs. RCS/RPV level less than (site level < 32.9 ft (10 in. last alarm The site-specific level for TOAF is 32.9 ft RFP. The lowest RVLMS specific level for TOAF). light on RVLMS (Note 6)) indicating light is 10 in. light which indicates at 10 in. above TOAF. Note 6: The lowest RVLMS This information is provided in Note 6. indication is the 10 in. alarm, which is 10 in. above top of active fuel. Therefore, this indicator should only be used when a valid RFP/RCS level indication is not available. 3 Note: The Emergency Director CS3.3 RCS level cannot be monitored The NEI abbreviation "RCS/RPV" has been changed to "RCS" to use should not wait until the for _>30 min. with a loss of RCS terminology commonly accepted at PWRs. 45 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP applicable time has elapsed, but inventory as indicated by ANY The NEI phrase "30 minutes or longer" has been replaced with ">_30 should declare the event as of the following (Note 4): min." to reduce EAL-user reading burden. The symbol "Z"means soon as it is determined that the "greater than or equal to" and thus implements the intent of the NEI condition will likely exceed the

• Containment radiation > 6 R/hr phrase.

applicable time. Reference to the NEI note is included in the EAL wording "(Note 4)." RCS/RPV level cannot be " Erratic WRNI indication Numbering the note facilitates referencing in the EAL matrix. monitored for 30 minutes or " Unexplained level rise in longer with a loss of RCS/RPV Containment radiation is indicated on 1(2)-RI-5317 A&B. Typical ANY Table C-2 sump / tank Containment radiation readings at full power are 1 to 1.2 R/hr. The inventory as indicated by ANY of attributable to RCS leakage the following: Containment radiation monitors alarm at 6 R/hr. The 6 R/hr setpoint Note 4: The ED should not wait has been selected to be operationally significant and above that

           *    (Site specific radiation    until the applicable time has     expected under normal plant conditions while in the Refuel mode.

monitor) reading greater elapsed, but should declare the than (site specific value). The NEI phrase "(site-specific sump or tank)" has been replaced with event as soon as it is "ANY Table C-2 sump / tank attributable to RCS leakage" for

           "    Erratic Source Range        determined that the condition     clarification. The list of sumps and tanks is too large to include within Monitor Indication.           has exceeded, or will likely      the wording of the EAL and maintain readability. Table C-2 contains exceed, the applicable time.      the site-specific list of sumps and tanks as well as observation of

• Unexplained level rise in (site specific sump or tank). unisolable RCS leakage.

46 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP CCNPP NEI IC# NEI IC Wording IC#(s) CCNPP IC Wording Difference/Deviation Justification CG1 Loss of RCS/RPV inventory CG3 Loss of RCS inventory affecting The NEI abbreviation "RCS/RPV" has been changed to "RCS" to affecting fuel clad integrity with fuel clad integrity with use terminology commonly accepted at PWRs. containment challenged. Containment challenged MODE: Cold Shutdown, MODE: 5 - Cold Shutdown, 6 - Refueling Refueling NEI EALEx. E CCNP# NEI Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification Note: The Emergency Director CG3.1 RCS level < 32.9 ft (10 in. alarm The NEI abbreviation "RCS/RPV" has been changed to "RCS" to should not wait until the on RVLMS, Note 6) for > 30 min. use terminology commonly accepted at PWRs. applicable time has elapsed, but (Note 4) The site-specific level for TOAF is 32.9 ft RFP. The lowest RVLMS should declare the event as soon indicating light is the 10 in. light which indicates at 10 in. above as it is determined that the AND TOAF. This information is provided in Note 6. condition will likely exceed the ANY Containment Challenge The NEI phrase '30 minutes or longer" has been replaced with applicable time. Indication, Table C-3ThNEphae"0mntsolngrhabenelcdwih> a.plRcabPeleess the. Indiiot ThleE s303 min." to reduce EAL-user reading burden. The symbol "Z"

a. RCS/RPV level less than (site Note 4: The ED should not wait means specific level for TOAF) for 30 until the applicable time has the NEI "greater phrase. than or equal to" and thus implements the intent of minutes or longer, elapsed, but should declare the AND event as soon as it is determined Reference to the NEI note is included in the EAL wording "(Note

b. ANY containment challenge that the condition has exceeded, 4)." Numbering the note facilitates referencing in the EAL matrix.

indication (see Table): or will likely exceed, the Table C-3 lists the Containment Challenge indications. "Secondary applicable time. Containment radiation monitor reading above" has not been Note 6: The lowest RVLMS incorporated in Table C-3 because CCNPP is a PWR and not indication is the 10 in. alarm, equipped with a secondary Containment. which is 10 in. above top of The site-specific level for TOAF is 32.9 ft RFP. The lowest RVLMS active fuel. Therefore, this indicating light is 10 in. light which indicates at 10 in. above TOAF. indicator should only be used This information is provided in Note 6. when a valid RFP/RCS level indication is not available. 2 a. RCS/RPV level cannot be CG3.2 RCS level cannot be monitored The NEI abbreviation "RCS/RPV" has been changed to "RCS" to monitored with core uncovery IIII 47 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP indicated by ANY of the following with core uncovery indicated by use terminology commonly accepted at PWRs. for 30 minutes or longer. ANY of the following for _>30 The NEI phrase "30 minutes or longer" has been replaced with">

             "   (Site specific radiation min. (Note 4):                    30 min." to reduce EAL-user reading burden. The symbol "Z" monitor) reading greater

• Containment radiation > 6 means "greater than or equal to" and thus implements the intent of than (site specific R/hr the NEI phrase.

setpoint).

• Erratic WRNI indication Reference to the NEI note is included in the EAL wording "(Note
• Erratic source range 4)." Numbering the note facilitates referencing in the EAL matrix.

monitor indication Unexplained level rise in ANY Table C-2 sump / tank Containment radiation is indicated on 1(2)-RI-5317 A&B. Typical

• UNPLANNED level rise in attributable to RCS leakage Containment radiation readings at full power are 1 to 1.2 R/hr. The (site specific sump or Containment radiation monitors alarm at 6 R/hr. The 6 R/hr tank). AND setpoint has been selected to be operationally significant and

             *   [Other site specific     ANY Containment Challenge         above that expected under normal plant conditions while in the Indication, Table C-3             Refuel mode.

indications] The NEI term "UNPLANNED" has been changed to "Unexplained" AND Note 4: The ED should not wait for consistency with NEI IC CS1 Example EAL #3f.

b. ANY containment challenge until the applicable time has elapsed, but should declare the The NEI phrase "(site-specific sump or tank)" has been replaced indication (see Table):

event as soon as it is determined with "ANY Table C-2 sump / tank attributable to RCS leakage" for that the condition has exceeded, clarification. The list of sumps and tanks is too large to include or will likely exceed, the within the wording of the EAL and maintain readability. Table C-2 a*plicable time contains the site-specific list of sumps and tanks as well as observation of unisolable RCS leakage. Other site-specific indications of core uncovery could not be identified. Table C-3 lists the Containment Challenge indications. "Secondary Containment radiation monitor reading above" has not been incorporated in Table C-3 because CCNPP is a PWR and not equipped with a secondary containment. 48 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP Table: Containment Challenge Indications

                     " CONTAINMENT CLOSURE not established.
                     * (Site specific explosive mixture) inside containment.
                     " UNPLANNED rise in containment pressure.
                     " Secondary containment radiation monitor reading above (site specific value). [BWR only]

Table C-3 Containment Challenge Indications

• Containment closure not established

                                       "  Hydrogen concentration in Containment >- 4%

• Unplanned rise in Containment pressure 49 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP Category D Permanently Defueled Station Malfunction 50 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI IC# NEI IC Wording CCNPP CCNPP IC Wording Difference/Deviation Justification IC#(s) D-AU1 Recognition Category D N/A N/A NEI Recognition Category D ICs and EALs are applicable only to D-AU2 Permanently Defueled Station permanently defueled stations. CCNPP is not a defueled station. D-SU1 Malfunction D-HU1 D-HU2 D-HU3 D-AA1 D-AA2 D-HA1 D-HA2 51 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP Category E Events Related to Independent Spent Fuel Storage Installations 52 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP CCNPP NEI IC# NEI IC Wording IC#(s) CCNPP IC Wording Difference/Deviation Justification E-HU1 Damage to a loaded cask EU1 Damage to a loaded cask None CONFINEMENT BOUNDARY confinement boundary MODE: Not applicable NEI EALEx. E ICCNPP NEI Example EAL Wording EAL # CCNPP EAL Wording Difference/Deviation Justification 1 Damage to a loaded cask EU1.1 Damage to a loaded cask None CONFINEMENT BOUNDARY CONFINEMENT BOUNDARY 53 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP Category F Fission Product Barrier Degradation 54 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI IC# NEI IC Wording CCNPP CCNPP IC Wording Difference/Deviation Justification IC#(s) FU1 ANY Loss or ANY Potential Loss FU1 ANY loss or ANY potential loss None of Containment of Containment MODE: Power Operation, Hot MODE: 1 - Power Operation, 2 - Standby, Startup, Hot Shutdown Startup, 3 - Hot Standby, 4 - Hot Shutdown NEI EALEx. E NEI Example EAL Wording EALPP CCNPP CCNPP EAL Wording Difference/Deviation Justification 1 ANY Loss or ANY Potential Loss FUI.1 ANY loss or ANY potential loss Table F-1 contains the loss and potential loss thresholds for the three of Containment of Containment (Table F-i) fission product barriers and is the plant representation of NEI Table 5-F-3. 55 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI IC# NEI IC Wording CCNPP CCNPP IC Wording Difference/Deviation Justification IC#(s) FA1 ANY Loss or ANY Potential Loss FA1 ANY loss or ANY potential loss None of EITHER Fuel Clad OR RCS of either Fuel Clad or RCS MODE: Power Operation, Hot MODE: 1 - Power Operation, 2 - Standby, Startup, Hot Shutdown Startup, 3 - Hot Standby, 4 - Hot Shutdown NEI Ex. NEI Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification EAL # EAL # 1 ANY Loss or ANY Potential Loss FAI.1 ANY loss or ANY potential loss Table F-1 contains the loss and potential loss thresholds for the three of EITHER Fuel Clad OR RCS of either Fuel Clad or RCS fission product barriers and is the plant representation of NEI Table 5-(Table F-i) F-3. 56 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI IC# NEI IC Wording CCNPP CCNPP IC Wording Difference/Deviation Justification IC#(s) FS1 Loss or Potential Loss of ANY FS1 Loss or potential loss of ANY two None Two Barriers barriers MODE: Power Operation, Hot MODE: 1 - Power Operation, 2 - Standby, Startup, Hot Shutdown Startup, 3 - Hot Standby, 4 - Hot Shutdown NEI Ex. NEI Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification EAL # EAL # 1 Loss or Potential Loss of ANY FS1.1 Loss or potential loss of ANY Table F-1 contains the loss and potential loss thresholds for the three Two Barriers two barriers (Table F-I) fission product barriers and is the plant representation of NEI Table 5-F-3. 57 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI IC Wording CCNPP CCNPP IC Wording Difference/Deviation Justification IC#(s) Loss of ANY Two Barriers AND FG1 Loss of ANY two barriers and None Loss or Potential Loss of Third loss or potential loss of the third Barrier barrier MODE: Power Operation, Hot MODE: 1 - Power Operation, 2 - Standby, Startup, Hot Shutdown Startup, 3 - Hot Standby, 4 - Hot Shutdown NEI Ex. NEI Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification EAL # EAL # 1 Loss of ANY Two Barriers AND FG1.1 Loss of ANY two barriers Table F-1 contains the loss and potential loss thresholds for the three Loss or Potential Loss of Third fission product barriers and is the plant representation of NEI Table 5-Barrier AND F-3. Loss or potential loss of the third barrier (Table F-I) 58 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI Ex. NEI Table 5-F-1 Notes CCNPP CCNPP EAL Notes Difference/Deviation Justification EAL # EAL # N/A NOTES FU1.1 The logic used for Category F First bullet: The NEI parenthetical phrase "See Sections 3.4 and 3.8" FA1.1 EALs reflects the following has been deleted because it refers to NEI EAL developmental The logic used for these initiating considerations: information. conditions reflects the FS1.1 First bullet: The NEI acronym "NOUE" has been implemented as following considerations: FG1.1

• The Fuel Clad Barrier and "UE" for simplification. The NEI abbreviation "ICs" has been changed the RCS Barrier are to "EALs" for clarification.
• The Fuel Clad Barrier and the weighted more heavily than RCS Barrier are weighted the Containment Barrier. UE Second bullet: The NEI abbreviation "EALs" has been changed to more heavily than the EALs associated with RCS "thresholds" for clarification.

Containment Barrier (See and Fuel Clad Barriers are The second sentence in the fourth bullet of the NEI notes "When no Sections 3.4 and 3.8). NOUE addressed under Category event is in progress (Loss or Potential Loss of either Fuel Clad and/or ICs associated with RCS and S. RCS) the Containment Barrier status is addressed by Technical Fuel Clad Barriers are Specifications" has been deleted to implement EAL FAQ #14. addressed under System " At the Site Area Emergency Malfunction ICs. level, there must be some ability to dynamically assess

       "   At the Site Area Emergency                    how far present conditions level, there must be some                     are from the threshold for a ability to dynamically assess                 General Emergency. For how far present conditions are                example, if Fuel Clad and from the threshold for a                      RCS Barrier "Loss" General Emergency. For                       thresholds existed, that, in example, if Fuel Clad and                    addition to off-site dose RCS Barrier "Loss" EALs                      assessments, would require existed, that, in addition to off-           continual assessments of site dose assessments, would                  radioactive inventory and require continual assessments                Containment integrity.

of radioactive inventory and Alternatively, if both Fuel containment integrity. Clad and RCS Barrier Alternatively, if both Fuel Clad "Potential Loss" thresholds and RCS Barrier "Potential existed, the ED would have Loss" EALs existed, the more assurance that there Emergency Director would was no immediate need to have more assurance that escalate to a General there was no immediate need 59 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP to escalate to a General Emergency. Emergency.

                                            " The ability to escalate to
      "    The ability to escalate to         higher emergency higher emergency                   classification levels as an classification levels as an        event deteriorates must be event deteriorates must be         maintained. For example, maintained. For example,           RCS leakage steadily RCS leakage steadily               increasing would represent increasing would represent an      an increasing risk to public increasing risk to public health   health and safety.

and safety.

                                            " The Containment Barrier

• The Containment Barrier should not be declared lost should not be declared lost or or potentially lost based on potentially lost based on exceeding Technical exceeding Technical Specification action Specification action statement statement criteria, unless criteria, unless there is an there is an event in progress event in progress requiring requiring mitigation by the mitigation by the Containment Containment barrier.

barrier. When no event is in progress (Loss or Potential Loss of either Fuel Clad and/or RCS) the Containment Barrier status is addressed by Technical Specifications. 60 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP Table F-1 Fission Product Barrier Matrix Fuel Clad Barrier Reactor Coolant System Barrier Containment Barrier Category Loss Potential Loss Loss Potential Loss Loss Potential Loss

1. OTCC flow established

1. CET readings > 700*F 2. RCS heat removal cannot be 1. CET readings cannot be restored established <1,200°F within 15 min.

A 2. RCS heat removal cannot be AND EITHER: RCS pressure > PORV Core established setpoint None 2. CET readings > 700*F Cooling / 1. CET readings > 1,200°F AND EITHER: None OR AND Heat RCS pressure > PORV RCS subcooling < 25°F setpoint Reactor vessel water level cannot Removal OR be restored > RVLMS 10 in. alarm RCS subcooling < 25F 3. Uncontrolled RCS cooldown and to within 15 min. left of Max Operating Pressure Curve (EOP Attachment 1, RCS Pressure Temperature Limits)

1. A Containment pressure rise followed by a rapid unexplained drop in Containment pressure 3. Containment pressure > 50 psig and rising

2. Containment pressure or sump level response not consistent 4. Containment hydrogen

1. RCS leak rate > available with LOCA conditions concentration > 4%

amakeup loss of capacity as indicated by RCS subcooling None Nonr 3. RVLMS level lSin, alarm (<25F) R 4. RCS leak rate > 50 gpm with 3. RUPTURED S/G is also 5. Containment pressure > 4.25 letdown isolated FAULTED outside of psig AND cannot meet ANY of Inventory Containment the following conditions: 2.RUPTURED S/G results in an ECCS (SIAS) actuaton 2 Containment Spray Pumps

4. Primary-to-secondary leakrate > Operating 10 gpm

• 3 CACs Operating AND
• 1 Containment Spray Pump Unisolable prolonged steam and 2 CACs Operating release from affected S/G to the environment

2. Containment radiation monitor (5317A[B) reading > 3,500 R/hr C ~~ ~ ~ ~ ~ ~ .Containment radiation monitorCotimnraainmnto Radiation 3. Post-accident sample dose rate None (5317.n ) reading monitor 6. Containment radiation monitor I Coolant a 40 mRem/hr (1 ft from sample) 5) (5317A/B) reading> 14.000 R/hr Activityr 4. Coolant activity >300 pCi/cc DEQ 1-131

5. Failure of all valves in ANY one

      '1                                                                                                                                                                          line to close None                                 None                                         None                                         None                       AND                                               None Isolation                                                                                                                                                                         Direct downstream pathway to Status                                                                                                                                                                          the environment exists after Containment isolation signal

5. ANY condition in the opinion of 4. ANY condition in the opinion of 4. ANY condition in the opinion of 5. ANY condition in the opinion of the 6. ANY condition in the opinion of 7. ANY condition in the opinion of the E the Emergency Director that indicates loss of the fuel dad the Emergency Director that indicates potential loss of the fuel the Emergency Director that te loss of th at Emergency Director that indicates potency lossof thatCindier the Emergency Director that indicates loss of the Containment Emergency Director that indicates potential loss of the Containment Judgment barrier dad barrier indicates loss of the RCS barrer potential loss of the RCS barrer barrier barrier 61 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP Fuel Clad Fission Product Barrier Degradation Thresholds NEI CCNPP FPB NEI Threshold Wording FPB CCNPP FPB Wording Difference/Deviation Justification FPB# FP13 #(s) FC Loss Critical Safety Function N/A N/A CCNPP is a Combustion Engineering (CE) designed PWR. CCNPP 1 Status does not implement Westinghouse Owners Group (WOG) Critical A. Core-Cooling Red Entry Safety Function Status Trees and therefore this threshold is not Conditions Met. applicable to CCNPP. FC Loss Primary Coolant Activity FC Loss Coolant activity > 300 pCi/cc 300 pCi/gm dose equivalent 1-131 is the site-specific value for 2 Level C.4 DEQ 1-131 coolant activity. A. Coolant activity greater than The NEI phrase "greater than" has been replaced with ">" to reduce (site specific value). EAL-user reading burden. The symbol ">" means "greater than" and thus implements the intent of the NEI phrase. FC Loss Core Exit Thermocouple FC Loss CET readings > 1,200'F CETs is the CCNPP equivalent of NEI "thermocouple readings." 3 Readings A.1 The NEI phrase "greater than" has been replaced with ">" to reduce A. Core exit thermocouples EAL-user reading burden. The symbol ">" means "greater than" and reading greater than (site thus implements the intent of the NEI phrase. specific degree F). The NEI word "degree" has been replaced with "I"to reduce EAL-user reading burden. The symbol "0"is commonly understood to mean "degree." 1,200°F is the CCNPP specific temperature corresponding to significant core exit superheating and core uncovery. FC Loss Reactor Vessel Water Level N/A N/A N/A 4 Not Applicable FC Loss Not Applicable N/A N/A N/A 5 Not Applicable 62 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI CCNPP FPB NEI Threshold Wording FPB CCNPP FPB Wording Difference/Deviation Justification FPB# FPB #(s) FC Loss Containment Radiation FC Loss Containment radiation monitor .The NEI phrase "greater than" has been replaced with ">" to reduce 6 Monitoring C.2 (5317ANB) reading > 3,500 R/hr EAL-user reading burden. The symbol '5"means "greater than" and A. Containment radiation thus implements the intent of the NEI phrase. monitor reading greater than 3,500 R/hr is the site-specific Containment rad monitor reading. (site specific value). FC Loss Other (Site-Specific) FC Loss Post-accident sample dose rate A shielded 12.5 ml pressurized bomb sample would read 40 7 Indications C.3 - 40 mRem/hr (1 ft from sample) mRem/hr at one foot from the sample (168 mRem/hr unshielded) for A. (Site-specific ) as 5% fuel cladding damage. When reactor coolant activity reaches applicable this level, significant clad heating has occurred and thus the Fuel Cladding barrier is considered lost per BG&E Fuel Degradation EALs Calculation Worksheet, JSB Associates, February 18, 1993. FC Loss Emergency Director FC Loss ANY condition in the opinion of None 8 Judgment E.5 the Emergency Director that A. Any condition in the opinion indicates loss of the Fuel Clad of the Emergency Director that barrier indicates Loss of the Fuel Clad Barrier. FC Critical Safety Function N/A N/A CCNPP is a Combustion Engineering (CE) designed PWR. CCNPP P-Loss Status does not implement Westinghouse Owners Group (WOG) Critical 1 A. Core Cooling-Orange Entry Safety Function Status Trees and therefore this threshold is not Conditions Met. applicable to CCNPP. OR B. Heat Sink-Red Entry Conditions Met. FC Primary Coolant Activity N/A N/A N/A P-Loss Level 2 Not Applicable 63 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI FPB NEI Threshold Wording CCNPP FPB# FPB #(s) FPB CCNPP FPB Wording Difference/Deviation Justification FC Core Exit Thermocouple FC CET readings > 700*F CET is the CCNPP equivalent of NEI "thermocouple readings." P-Loss Readings P-Loss The NEI phrase "greater than" has been replaced with ">"to reduce 3 A.. Core exit thermocouples A.1 EAL-user reading burden. The symbol ">"means "greater than" and reading greater than (site thus implements the intent of the NEI phrase. specific degree F). The NEI word "degree" has been replaced with '"0to reduce EAL-user reading burden. The symbol "I" is commonly understood to mean "degree." Core Exit Thermocouples (CETs) are a component of the Inadequate Core Cooling Instrumentation and provide an indirect indication of fuel cladding temperature by measuring the temperature of the reactor coolant that leaves the core region. The RCS Pressure Safety Limit is 2750 psia per CCNPP Technical Specifications. The saturation temperature for this pressure is 682.2°F. Per Action Value Bases Document EOP-24.33, the uncertainty on CET Temperature is +/- 39.8°F. If one or more CETs indicate 722°F (682.2 + 39.8), subcooling has been lost for at least some locations in the core. CET indications at or above 722°F are a clear sign that core heat removal capability is lost or greatly reduced and one fission product barrier, the fuel clad, is threatened due to elevated fuel temperatures. 700°F qualifies as a condition representing a potential loss of the fuel clad barrier. 64 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI FPB CCNPP NEI Threshold Wording FPB CCNPP FPB Wording Difference/Deviation Justification FPB# FPB #(s) FC Reactor Vessel Water Level FC RVLMS < 10 in. alarm The NEI phrase "RCS/RPV" has been replaced with "RVLMS" to P-Loss A. RCS/RPV level less than P-Loss use terminology consistent with the CCNPP EOPs. 4 (site specific level for TOAF). B.3 The NEI phrase "less than" has been replaced with "<" to reduce EAL-user reading burden. The symbol "<" means "less than" and thus implements the intent of the NEI phrase. The Reactor Vessel Level Monitoring System (RVLMS) is based on the CE Heated Junction Thermocouple (HJTC) system. The HJTC system measures reactor coolant liquid inventory with discrete HJTC sensors located at different levels within a separator tube ranging from the fuel alignment plate (i.e., near top of active fuel) to the top of the Reactor Vessel head. The basic principle of system operation is detection of a temperature difference between heated and unheated thermocouples. When Reactor Vessel/RCS water level drops to 32.9 ft el., core uncovery is about to occur. The closest RVLMS indication is the 10 in. alarm. This signals inadequate coolant inventory, loss of subcooling and the occurrence of possible fuel cladding damage. FC Not Applicable N/A N/A N/A P-Loss Not Applicable 5 FC Containment Radiation N/A N/A N/A P-Loss Monitoring 6 Not Applicable 65 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI FPB CCNPP NEI Threshold Wording FPB CCNPP FPB Wording Difference/Deviation Justification FPB# FPB #(s)

                                              )FC   RCS heat removal cannot be      If RCS pressure approaches the PORV setpoint (2400 psia), heat FC    Other (Site-Specific)                 FC    esthed                          input to the RCS is likely raising pressure instead of reaching the P-Loss  Indications                         P-Loss  established                     ultimate heat sink. If RCS subcooling approaches 25°F, the margin 7    A.   (Site-specific) as applicable   A.2    AND EITHER:                     to superheated conditions is being reduced. Following an RCS pressure > PORV          uncomplicated reactor trip, subcooling margin should be in excess 0

setpoint of 50°F. Subcooling margin greater than 25 F ensures the fluid surrounding the core is sufficiently cooled and provides margin for OR reestablishing flow should subcooling deteriorate when SI flow is RCS subcooling < 25°F secured. Voids may exist in some parts of the RCS (e.g., Reactor Vessel head) but are permissible as long as core heat removal is maintained. The combination of these conditions indicates the ultimate heat sink function is under extreme challenge. This threshold addresses loss of functions required for hot shutdown with the reactor at pressure and temperature and thus a potential loss of the Fuel Cladding barrier. FC Emergency Director FC ANY condition in the opinion of None P-Loss Judgment P-Loss the Emergency Director that 8 A. Any condition in the opinion E.4 indicates potential loss of the of the Emergency Director that Fuel Clad barrier indicates Potential Loss of the Fuel Clad Barrier. 66 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP RCS Fission Product Barrier Degradation Thresholds NEI IC Wording CCNPP FPB Wording Difference/Deviation Justification FPNE# FPB #(s) RCS Critical Safety Function Status N/A N/A None Loss Not Applicable 1 RCS RCS Leak Rate RCS Loss RCS leak rate > available The NEI phrase "greater than" has been replaced with '5"to Loss A. RCS leak rate greater than B.1 makeup capacity as indicated reduce EAL-user reading burden. The symbol '5" means "greater 2 available makeup capacity as by a loss of RCS subcooling than" and thus implements the intent of the NEI phrase. indicated by a loss of RCS (< 25°F) AOP-2A, Excessive Reactor Coolant Leakage, provides a list of subcooling. conditions that may be observed when excessive RCS leakage occurs and provides appropriate actions to prevent and mitigate the consequences of RCS leakage. Following an uncomplicated reactor trip, subcooling margin should be in the range of 50°F to 75 0 F. Subcooling margin greater than or equal to 25°F ensures the fluid surrounding the core is sufficiently cooled and provides margin for reestablishing flow should subcooling deteriorate when SIS flow is secured. Voids may exist in some parts of the RCS (e.g., Reactor Vessel head) but are permissible as long as core heat removal is maintained. The loss of subcooling is therefore the fundamental indication that the inventory control systems are incapable of counteracting the mass loss through the leak in the RCS. RCS Not Applicable N/A N/A None Loss Not Applicable 3 RCS SG Tube Rupture RCS Loss RUPTURED S/G results in an SIAS is the site specific name for an SI actuation signal. Loss A. RUPTURED SG results in B.2 ECCS (SIAS) actuation 4 an ECCS (SI) actuation. RCS Not Applicable N/A N/A None Loss Not Applicable 5 67 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI FPB CCNPP NEI IC Wording FPB CCNPP FPB Wording Difference/Deviation Justification FPB# FPB #(s) RCS Containment Radiation RCS Loss Containment radiation monitor The specified reading is based assuming the instantaneous Loss Monitoring C.3 (5317A/B) reading > 6 R/hr release and dispersal of the reactor coolant noble gas and iodine 6 A. Containment radiation (Note 8) inventory associated with normal operating concentrations (i.e., monitor reading greater than Nwithin Technical Specifications) into the Containment atmosphere. (site specific value). Note 8: High temperature in Because of the very high fuel cladding integrity, only small

                                                 .Containment may induce a          amounts of noble gases would be dissolved in the reactor coolant.

current error in the Mineral Only leakage from the RCS is assumed for this barrier loss Insulated (MI) cable running threshold. The Containment radiation monitors alarm at 6 R/hr and through Containment to the so is operationally significant. meter: The CHRRM 1(2)-RI-5317 The NEI phrase "greater than" has been replaced with ">" to A&B may not detect this value (6 reduce EAL-user reading burden. The symbol ">" means "greater R/hr) under these conditions. than" and thus implements the intent of the NEI phrase. When Containment temperature Note 8 has been added to provide guidance on potential effects on Containment radiation indications due to high Containment indicate approximately 40 R/hr for temperatures. a few minutes then drop to approximately 10 R/hr after three hours. This information is to provide guidance on determining the validity of the readings under the specified high temperature conditions. RCS Other (Site-Specific) N/A N/A Other site-specific indications of RCS loss have not been Loss Indications identified. 7 A. (Site-specific) as applicable RCS Emergency Director Judgment RCS Loss ANY condition in the opinion of None Loss A. Any condition in the opinion E.4 the Emergency Director that 8 of the Emergency Director that indicates loss of the RCS indicates Loss of the RCS barrier Barrier. 68 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI CCNPP FPB NEI IC Wording FPB CCNPP FPB Wording Difference/Deviation Justification FPB# FPB #(s) RCS Critical Safety Function Status N/A N/A CCNPP is a Combustion Engineering (CE) designed PWR. P-Loss 1 A. RCS Integrity-Red Entry CCNPP does not implement Westinghouse Owners Group (WOG) Conditions Met. Critical Safety Function Status Trees and therefore this threshold OR is not applicable to CCNPP. B. Heat Sink-Red Entry Conditions Met. RCS RCS Leak Rate RCS RCS leak rate > 50 gpm with The CVCS includes three positive displacement horizontal pumps P-Loss 2 A. RCS leak rate indicated P-Loss letdown isolated with a capacity of 44 gpm each. The single charging pump greater than (site specific B.4 capacity is rounded up to 50 gpm for this threshold and clearly capacity of one charging pump signals that operation of more than one charging pump is needed. in the normal charging mode) with Letdown isolated. RCS Not Applicable N/A N/A N/A P-Loss 3 Not Applicable RCS SG Tube Rupture N/A N/A N/A P-Loss 4 Not Applicable RCS Not Applicable N/A N/A N/A P-Loss 5 Not Applicable RCS Containment Radiation N/A N/A N/A P-Loss 6 Monitoring Not Applicable RCS Other (Site-Specific) RCS OTCC flow established CCNPP is a CE plant with Once Through Core Cooling (OTCC) P-Loss 7 Indications P-Loss capability and has a procedure that intentionally opens the RCS A. (Site-specific) as applicable A.1 barrier to cool the core when normal means fail. This procedure is employed when the heat removal function is extremely challenged. Establishment of OTCC flow represents a potential loss of the RCS barrier due to PORVs being intentionally maintained open to establish adequate core heat removal capability. 69 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI NEI IC Wording CCNPP FPB CCNPP FPB Wording Difference/Deviation Justification FPB# FPB #(s) RCS RCS heat removal cannot be If RCS pressure approaches the PORV setpoint (2400 psia), heat RCSs RCstabliheat roinput to the RCS is likely raising pressure instead of reaching the P-Loss established ultimate heat sink. If RCS subcooling approaches 25 0 F, the A.2 AND EITHER: margin to superheated conditions is being reduced. Following an RCS pressure > PORV uncomplicated reactor trip, subcooling margin should be in excess setpoint of 50°F. Subcooling margin greater than 25°F ensures the fluid surrounding the core is sufficiently cooled and provides margin for OR reestablishing flow should subcooling deteriorate when SI flow is RCS subcooling < 25°F secured. Voids may exist in some parts of the RCS (e.g., Reactor Vessel head) but are permissible as long as core heat removal is maintained. The combination of these conditions indicates the ultimate heat sink function is under extreme challenge. This threshold addresses loss of functions required for hot shutdown with the reactor at pressure and temperature and thus a potential loss of the RCS barrier. RCS Uncontrolled RCS cooldown Among the EOP safety functions to be maintained is RCS and to left of Max Operating Pressure Control. Per EOP-4, Excess Steam Demand Event, the P-Loss Pressure Curve (EOP potential exists for pressurized thermal shock from an excessive Attachment 1, RCS Pressure cooldown rate followed by a repressurization. Temperature Limits) The Max Operating Pressure Curve and RCS cooldown rate limits are established to prevent the effects of pressurized thermal shock. The region to the left of the curve is labeled the "Non-Operating Area." Several curves are included in EOP Attachment 1 based on the combinations of Reactor Coolant Pumps (RCPs) in operation. The combination of the conditions of this potential loss threshold indicates the RCS barrier is under significant challenge. RCS Emergency Director Judgment RCS ANY condition in the opinion of None P-Loss 8 A. Any condition in the opinion P-Loss the Emergency Director that of the Emergency Director that E.5 indicates potential loss of the indicates Potential Loss of the RCS barrier RCS Barrier. 70 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP Containment Fission Product Barrier Degradation Thresholds NEI NEI IC Wording CCNPP FPB CCNPP FPB Wording Difference/Deviation Justification FPB# FPB #(s) CNMT Critical Safety Function Status N/A N/A None Loss Not Applicable 1 CNMT Containment Pressure CNMT A Containment pressure rise followed The NEI threshold has been divided into two CCNPP Loss A. A containment pressure rise Loss by a rapid unexplained drop in thresholds to improve clarity. 2 followed by a rapid unexplained B.1 Containment pressure drop in containment pressure. OR CNMT Containment pressure or sump level The NEI threshold has been divided into two CCNPP Loss response not consistent with LOCA thresholds to improve clarity. B. Containment pressure or sump B.2 conditions level response not consistent with LOCA conditions. CNMT Core Exit Thermocouple Readings N/A N/A N/A Loss Not applicable 3 CNMT SG Secondary Side Release with P- CNMT RUPTURED S/G is also FAULTED None Loss to-S Leakage Loss outside of Containment 4 A. RUPTURED SG is also FAULTED B.3 71 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI CCNPP FPB NEI IC Wording FPB CCNPP FPB Wording Difference/Deviation Justification FPB# FPB #(s) outside of containment. CNMT Primary-to-secondary leakrate > 10 The NEI threshold has been divided into two CCNPP OR Loss gpm thresholds to improve clarity. B. a. Primary-to-Secondary leakrate B.4 AND The NEI phrase "greater than" has been replaced with greater than 10 gpm. UNISOLABLE or prolonged steam ">toreduce EAL-user reading burden. The symbol AND release from affected S/G to the '5" means "greater than" and thus implements the

b. UNISOLABLE steam release environment intent of the NEI phrase.

from affected SG to the "Prolonged" as used here is in the context meaning environment. that the release from the affected S/G within the time frame expected when implementing EOP-6 Steam Generator Tube Rupture or EOP-8 Functional Recovery Procedure. Cooldowns conducted to allow controlled isolation of the affected S/G per emergency procedures are not considered prolonged releases. The criterion for prolonged release is met if the objective of EOP-6 or EOP-8 to isolate the affected S/G cannot be met. CNMT Containment Isolation Failure or CNMT Failure of all valves in ANY one line to None Loss Bypass Loss close 5 A. a. Failure of all valves in any one D.5 AND line to close. Direct downstream pathway to the AND environment exists after Containment isolation signal

b. Direct downstream pathway to the environment exists after containment isolation signal.

CNMT Containment Radiation Monitoring N/A N/A N/A Loss Not Applicable 6 CNMT Other (Site-Specific) Indications N/A N/A Other site-specific indications of Containment loss Loss A. (Site-specific) as applicable have not been identified. 7 72 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI FPB CCNPP NEI IC Wording FPB CCNPP FPB Wording Difference/Deviation Justification FPB# FPB #(s) CNMT Emergency Director Judgment CNMT ANY condition in the opinion of the None Loss A. Any condition in the opinion of the Loss Emergency Director that indicates loss 8 Emergency Director that indicates Loss E.6 of the Containment barrier of the Containment Barrier. CNMT Critical Safety Function Status N/A N/A CCNPP is a Combustion Engineering (CE) designed P-Loss PWR. CCNPP does not implement Westinghouse A. Containment-Red Entry Conditions Owners Group (WOG) Critical Safety Function Status 1 Met. Trees and therefore this threshold is not applicable to CCNPP. CNMT Containment Pressure CNMT Containment pressure ->50 psig and The NEI threshold has been divided into three plant P-Loss A. Containment pressure greater than P-Loss rising thresholds to improve clarity. 2 (site specific value) and rising. B.3 This threshold is the Containment design pressure and OR is in excess of that expected from the design basis B. Explosive mixture exists inside loss of coolant accident (LOCA). The pressure-time containment. responses for the spectrum of LOCAs considered in the plant design basis are described in Section 14 of OR the UFSAR. C. a. Pressure greater than containment depressurization CNMT Containment hydrogen concentration _ The NEI threshold has been divided into three CCNPP actuation setpoint. P-Loss 4% thresholds to improve clarity. AND B.4 Containment hydrogen concentration of 4% is the

b. Less than one full train of minimum concentration associated with an explosive mixture.

73 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI CCNPP FPB NEI IC Wording FPB CCNPP FPB Wording Difference/Deviation Justification FPB# FPB #(s) depressurization equipment CNMT Containment pressure > 4.25 psig AND The NEI threshold has been divided into three CCNPP operating. P-Loss cannot meet ANY of the following thresholds to improve clarity. B.5 conditions: The word "Containment" has been added to the plant

• 2 Containment Spray Pumps threshold for clarification.

Operating The Containment pressure setpoint (4.25 psig) is the

• 3 CACs Operating Containment depressurization actuation setpoint.

The NEI phrase "greater than" has been replaced with

• 1 Containment Spray Pump and 2 ">" to reduce EAL-user reading burden. The symbol CACs Operating ">" means "greater than" and thus implements the intent of the NEI phrase.

The phrase "Less than one full train of depressurization equipment operating" has been replaced with the site specific minimum required depressurization equipment per FSAR accident analysis. CNMT Core Exit Thermocouple Readings CNMT CET readings cannot be restored The NEI threshold has been divided into two CCNPP P-Loss A. a. Core exit thermocouples in P-Loss < 1,200°F within 15 min. thresholds to improve clarity. 3 excess of (site specific) I F. A.1 "CET" is the CCNPP equivalent of NEI "Core exit AND thermocouples."

b. Restoration procedures not The NEI phrase "in excess of (site specific) I F AND effective within 15 minutes. Restoration procedures not effective..." has been OR replaced with "cannot be restored < 1,200°F...'.. The B. a Core exit thermocouples in phrase "cannot be restored <" infers CET readings have exceeded the threshold temperature and excess of (site-specific) F. procedural guidance used to restore RCS inventory AND has been attempted but is thus far unsuccessful.

b. Reactor vessel level below Whether or not guidance is effective should be (site specific level), apparent within fifteen minutes.

74 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI NEI IC Wording CCNPP CCNPP FPB Wording Difference/Deviation Justification FPB# FPB #(s) AND CNMT CET readings > 700°F The NEI threshold has been divided into two CCNPP

c. Restoration procedures not P-Loss AND thresholds to improve clarity.

effective within 15 minutes. A.2 Reactor vessel water level cannot be "CET" is the CCNPP equivalent of NEI "Core exit restored > RVLMS 10 in. alarm within thermocouples." 15 min. The NEI phrase "in excess of (site specific) 0 F AND reactor vessel level below...AND Restoration procedures not effective..." has been replaced with "CET readings indicate superheat AND Reactor vessel water level cannot be restored > RVLMS 10 in. alarm..." Core Exit Thermocouples (CETs) are a component of the Inadequate Core Cooling Instrumentation and provide an indirect indication of fuel cladding temperature by measuring the temperature of the reactor coolant that leaves the core region. The RCS Pressure Safety Limit is 2750 psia per CCNPP Technical Specifications. The saturation temperature for this pressure is 682.2°F. Per Action Value Bases Document EOP-24.33, the uncertainty on CET Temperature is +/- 39.80F. If one or more CETs indicate 722°F (682.2 + 39.8), subcooling has been lost for at least some locations in the core. CET indications at or above 722°F are a clear sign that core heat removal capability is lost or greatly reduced and one fission product barrier, the fuel clad, is threatened due to elevated fuel temperatures. 700OF qualifies as a condition representing a potential loss of the fuel clad barrier. The phrase "cannot be restored >" infers RVLMS level readings have exceeded the threshold level and procedural guidance used to restore RCS inventory has been attempted but is thus far unsuccessful. Whether or not guidance is effective should be apparent within fifteen minutes. 75 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI NEI IC Wording CCNPP FPB CCNPP FPB Wording Difference/Deviation Justification FPB# FPB #(s) CNMT SG Secondary Side Release with P- N/A N/A N/A P-Loss to-S Leakage 4 Not applicable CNMT Containment Isolation Failure or N/A N/A N/A P-Loss Bypass 5 Not Applicable CNMT Containment Radiation Monitoring CNMT Containment radiation monitor The NEI phrase "greater than" has been replaced with P-Loss A. Containment radiation monitor P-Loss (5317A/B) reading > 14,000 RPhr ">"to reduce EAL-user reading burden. The symbol 6 reading greater than (site specific C.6 ">" means "greater than" and thus implements the value). intent of the NEI phrase. 14,000 RPhr is the site-specific Containment rad monitor reading corresponding to -20% clad damage per ERPIP-801 Core Damage Assessment Using Containment Radiation Dose Rates. CNMT Other (Site-Specific) Indications N/A N/A Other site-specific indications of Containment potential P-Loss A. (Site-specific) as applicable loss have not been identified. 7 CNMT Emergency Director Judgment CNMT ANY condition in the opinion of the None P-Loss A. Any condition in the opinion of the P-Loss Emergency Director that indicates 8 Emergency Director that indicates E.7 potential loss of the Containment barrier Potential Loss of the Containment Barrier. 76 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP Category H Hazards and Other Conditions Affecting Plant Safety 77 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEINEI IC Wording CCNPP CCNPP IC Wording Difference/Deviation Justification IC# IC#(s) HU1 Natural or destructive phenomena HU1 Natural or destructive phenomena None affecting the PROTECTED AREA. affecting the Protected Area MODE: All MODE: All NEI EALEx. E CCNPP NEI Example EAL Wording EAL # CCNPP EAL Wording Difference/Deviation Justification 1 Seismic event identified by ANY 2 HU1.1 Seismic event identified by ANY Actuation of the CCNPP Seismic Acceleration Recorder (0-YRC-of the following: two of the following: 001) Event Indicator provides the site specific indication or method

• Seismic event
• Seismic Acceleration of detecting a seismic event.

confirmed by (site Recorder (0-YRC-001) Event Note 7 provides guidance for contacting the NEIC and verifying specific indication or Indicator alarms indicate seismic activity near the CCNPP site. method) seismic event detected

                  "   Earthquake felt in

• Earthquake felt in plant plant
• National Earthquake
• National Earthquake Center Information Center (Note 7)

Note 7: The NEIC can be contacted by calling (303) 273-8500. Select option #1 and inform the analyst you wish to confirm recent seismic activity in the vicinity of Calvert Cliffs Nuclear Power Plant. Provide the analyst with the following CCNPP coordinates: 380 25' 39.7" north latitude, 760 26' 45" west longitude. 2 Tornado striking within HU1.2 Tornado striking within The NEI phrase "greater than" has been replaced with the symbol PROTECTED AREA boundary or PROTECTED AREA boundary ">" to reduce EAL-user reading burden. The symbol means "greater high winds greater than (site OR than" and thus implements the intent of the NEI phrase. specific mph). SuThe wind speed of 45 m/sec (100 mph) is the sustained design Sustained high winds > 45 i/sec wind speed for Class 1 safe shutdown structures 30 ft above 78 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP (100 mph) ground and incorporates a gust factor of 1.1. 3 Internal flooding that has the HU1.3 Internal flooding that has the The NEI phrase "safety related equipment" has been changed to potential to affect safety related potential to affect ANY SAFETY- "ANY SAFETY-RELATED STRUCTURE, SYSTEM, OR equipment required by Technical RELATED STRUCTURE, COMPONENT ..." for clarification Specifications for the current SYSTEM, OR COMPONENT CCNPP areas containing safety related equipment are specified in operating mode in ANY of the required by Technical following areas: Specifications for the current (site specific area list) operating mode in ANY Table H-1 area 4 Turbine failure resulting in casing HU1.4 Turbine failure resulting in casing None penetration or damage to turbine penetration or damage to turbine or generator seals. or generator seals 5 (Site specific occurrences HU1.5 Bay water level > bottom of the +120 in. (12 ft) MSL (approximately bottom of the travelling screen affecting the PROTECTED traveling screen cover housing (+ cover) is the still water level used for the Intake Structural Analysis. AREA). 120 in. Mean Sea Level) This value was selected to be anticipatory to the design level of 18 OR ft MSL (top of the travelling screen cover). Bay water level < 13.6 ft below The predicted extreme low tide elevation is -43.2 in. (-3.6 ft) MSL. intake concrete level (- 43.2 in. However, the plant has been designed for -4.0 ft MSL and can Mean Sea Level) continue to operate with an extreme low water Elevation of -6.0 ft MSL. The top of the saltwater pump intakes is at -9.5 ft MSL. 79 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI IC# NEI IC Wording CCNPP CCNPP IC Wording Difference/Deviation Justification IC#(s) HU2 FIRE within the PROTECTED HU2 Fire within the Protected Area AREA not extinguished within 15 not extinguished within 15 min. minutes of detection or of detection or explosion within EXPLOSION within the the Protected Area PROTECTED AREA. MODE: All MODE: All NEI ENEIEx. NECxapeNAPorigPA Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification EAL # EAL # 1 FIRE not extinguished within 15 HU2.1 FIRE not extinguished within 15 The NEI phrase "of the following areas...(site specific area list)" has minutes of control room min. of Control Room notification been changed to "in the North Service Building, Turbine Building or notification or verification of a or verification of a Control Room ANY Table H-1 area." The areas listed in Table H-1 are areas control room FIRE alarm in ANY fire alarm in the North Service containing functions and systems required for safe shutdown. This of the following areas: Building, Turbine Building, Butler change implements EAL FAQ #44. (site specific area list) Building* or ANY Table H-1 area The North Service Building, Turbine Building and Butler Building (Note 4) (only when in modes 4, 5 or D) are adjacent structures.

• Butler Building is only Note 4 has been added consistent with other NEI based EALs that considered adjacent in Modes include the 15 min. transitory condition exclusion.

5, 6 and D. The third paragraph of the NEI basis has been edited to clarify the Note 4: The ED should not wait significance of the 15-minute duration. If the alarm cannot be until the applicable time has verified by redundant Control Room or nearby Fire Panel elapsed, but should declare the indications, notification from the field that a fire exists starts the event as soon as it is determined concurrent 15-minute classification and fire suppression clocks. that the condition has exceeded, This change is consistent with the manner in which the Control or will likely exceed, the Room and Fire Brigade leaders verify fires. This change is applicable time. necessary to avoid declaring Unusual Event emergencies for spurious alarms that, due to the sensor location, cannot be verified within 15 minutes of receipt of the alarm. This is a deviation from NEI 99-01 Revision 5. 2 EXPLOSION within the HU2.2 EXPLOSION within the None 80 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP PROTECTED AREA. PROTECTED AREA 81 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP Table H-1 Safe Shutdown Areas

                     " Control Room

• Containment

                     " Auxiliary Building

• Diesel Generator Rooms

                     " Intake Structure
                     " 1A/OC DG Buildings
                     " RWT
                     " RWT Rooms

• CST No. 12
• FOSTNo. 21

                     " Auxiliary Feed Pump Rooms 82 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP CCNPP NEI IC# NEI IC Wording IC#(s) CCNPP IC Wording Difference/Deviation Justification HU3 Release of toxic, corrosive, HU3 Release of toxic, corrosive, None asphyxiant, or flammable gases asphyxiant or flammable gases deemed detrimental to NORMAL deemed detrimental to normal PLANT OPERATIONS. plant operations MODE: All MODE: All NEI Ex. NEI Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification EAL # EAL # 1 Toxic, corrosive, asphyxiant or HU3.1 Toxic, corrosive, asphyxiant or None flammable gases in amounts that flammable gases in amounts that have or could adversely affect have or could adversely affect NORMAL PLANT OPERATIONS. NORMAL PLANT OPERATIONS 2 Report by local, county or state HU3.2 Recommendation by local, Reworded EAL for readability. officials for evacuation or county or state officials to sheltering of site personnel based evacuate or shelter site on an off-site event, personnel based on offsite event 83 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP I CCNPP NEI IC# NEI IC Wording IC#(s) CCNPP IC Wording Difference/Deviation Justification HU4 Confirmed SECURITY HU4 Confirmed security condition or None CONDITION or threat which threat which indicates a potential indicates a potential degradation degradation in the level of safety in the level of safety of the plant. of the plant MODE: All MODE: All NEI EA Ex. E EALPP NEI Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification EAL # EAL # 1 A SECURITY CONDITION that HU4.1 A SECURITY CONDITION that The NEI Example EALs have been combined in one plant EAL for does NOT involve a HOSTILE does not involve a HOSTILE simplification. ACTION as reported by the (site ACTION as reported by Security Security Shift Supervisor" is the site-specific security supervision specific security shift supervision). Shift Supervisor that are qualified and trained to confirm that a security event is OR occurring or has occurred. A credible site-specific security threat notification 2 A credible site specific security OR threat notification. A validated notification from 3 A validated notification from NRC NRC providing information of an providing information of an aircraft aircraft threat threat. 84 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP CCNPP NEI IC# NEI IC Wording IC#(s) CCNPP IC Wording Difference/Deviation Justification HU5 Other conditions exist which in HU6 Other conditions existing that in The NEI acronym "NOUE" has been implemented as "UE" for the judgment of the Emergency the judgment of the Emergency simplification. Director warrant declaration of a Director warrant declaration of a Replaced the word "which" with "that" for proper grammar. NOUE. UE MODE: All MODE: All NEI EA EEx. CCNPP NEI Example EAL Wording EAL CCNPP EAL Wording Difference/Deviation Justification EAL # EAL # 1 Other conditions exist which in HU6.1 Other conditions exist which in Reformatted for readability. the judgment of the Emergency the judgment of the Emergency Director indicate that events are Director indicate that events are in progress or have occurred in progress or have occurred which indicate a potential which: degradation of the level of safety Indicate a potential of the plant or indicate a security degradation of the level of threat to facility protection has safety of the plant been initiated. No releases of radioactive material requiring off- OR site response or monitoring are Indicate a security threat to expected unless further facility protection has been degradation of safety systems initiated occurs. No releases of radioactive material requiring offsite response or monitoring are expected unless further degradation of safety systems occurs 85 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI IC# NEI IC Wording CCNPP CCNPP IC Wording Difference/Deviation Justification IC#(s) HA1 Natural or destructive phenomena HA1 Natural or destructive None affecting VITAL AREAS phenomena affecting Vital Areas MODE: All MODE: All NEI EA Ex. EALPP NEI Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification EAL # EAL # 1 a. Seismic event greater than HA1.1 EITHER: The site-specific instrumentation used to indicate a seismic event > Operating Basis Earthquake (OBE) Seismic Acceleration OBE cannot be analyzed in a timely manner. To allow for timely as indicated by (site specific seismic Recorder (0-YRC-001) classification under this threshold, actual indication of degraded instrumentation) reading (site Event Indicator indicates performance of safety-related structures systems or component specific OBE limit), seismic event > OBE (0.08 g has been included as a primary indicator of exceeding the OBE AND horizontal, 0.053g vertical) threshold. The site-specific instrumentation used to indicate a seismic event > OBE is the Seismic Acceleration Recorder (0-

b. Earthquake confirmed by OR YRC-001) Event Indicator indicates seismic event > OBE (0.08 g ANY of the following: Control Room indication of horizontal, 0.053g vertical).

           " Earthquake felt in plant                        degraded performance of              The NEI phrase "greater than" has been replaced with the symbol ANY SAFETY-RELATED                   ">" to reduce EAL-user reading burden. The symbol means STRUCTURE, SYSTEM,                   "greater than" and thus implements the intent of the NEI phrase.

• Control Room indication of OR COMPONENT Note 7 provides guidance for contacting the NEIC for confirmation degraded performance of AND of seismic activity in the vicinity of CCNPP.

systems required for the safe shutdown of the plant. Earthquake confirmed by The NEI phrase "systems required for the safe shutdown of the EITHER: plant" has been changed to "ANY SAFETY-RELATED Earthquake felt in plant STRUCTURE, SYSTEM, OR COMPONENT" to be consistent with OR the definition of visible damage and related HA1 EAL thresholds. National Earthquake Information Center (Note 7) Note 7: The NEIC can be contacted by calling (303) 273-8500. Select option #1 and inform the analyst you wish to confirm recent seismic activity inthe vicinity of Calvert Cliffs 86 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP Nuclear Power Plant. Provide the analyst with the following CCNPP coordinates: 380 25' 39.7" north latitude, 760 26' 45" west longitude 2 Tornado striking or high winds HA1.2 Tornado striking or sustained The NEI phrase "greater than" has been replaced with the symbol greater than (site specific mph) high winds > 45 m/sec (100 '5" to reduce EAL-user reading burden. The symbol means mph) resulting in EITHER: "greater than" and thus implements the intent of the NEI phrase. resulting in VISIBLE DAMAGE to ANY of the following structures VISIBLE DAMAGE to ANY The wind speed of 45 m/sec (100 mph) is the sustained design containing safety systems or SAFETY-RELATED wind speed for Class 1 safe shutdown structures 30 ft above components OR control room STRUCTURE, SYSTEM, OR ground and incorporates a gust factor of 1.1. indication of degraded performance COMPONENT within ANY of those safety systems: The logic term "EITHER" has been added to the threshold so that Table H-1 area the two indicated results of the tornado/high wind could be (site specific structure list) OR presented in list format. Control Room indication of The NEI phrase "ANY of the following structures containing safety degraded performance of ANY systems or components" has been changed to "ANY SAFETY-SAFETY-RELATED RELATED STRUCTURE, SYSTEM, OR COMPONENT within ANY STRUCTURE, SYSTEM, OR Table H-1 area" to be consistent with the definition of visible COMPONENT within ANY damage and related HA1 EAL thresholds. This also permits Table H-1 area presentation of the site specific list in a table. Table H-1 provides the list of structures containing safety systems or components. This change implements EAL FAQ #44. The NEI phrase "those safety systems" has been changed to "ANY SAFETY-RELATED STRUCTURE, SYSTEM, OR COMPONENT within ANY Table H-1 area" for clarification. 3 Internal flooding in ANY of the HA1.3 Internal flooding in ANY Table CCNPP areas containing safety related equipment are specified in following areas resulting in an H-1 area resulting in EITHER: Table H-I. This change implements EAL FAQ #44. electrical shock hazard that An electrical shock hazard The logic term "EITHER" has been added to the threshold so that precludes access to operate or that precludes access to the two indicated results of the flooding could be presented in list monitor safety equipment OR control thatpr acesto the tw room indication of degraded operate or monitor ANY format. performance of those safety SAFETY-RELATED The NEI phrase "those safety systems" has been changed to "ANY systems: sytes:OR COMPONENT STRUCTURE, within SYSTEM, within ANY Table H-iSTRUCTURE, SAFETY-RELATED SYSTEM, OR COMPONENT area" for clarification. (site specific area list) ANY Table H-1 area OR Control Room indication of 87 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP degraded performance of ANY SAFETY-RELATED STRUCTURE, SYSTEM, OR COMPONENT within ANY Table H-1 area 4 Turbine failure-generated HA1.4 Turbine failure-generated The logic term "EITHER" has been added to the threshold so that PROJECTILES resulting in VISIBLE PROJECTILES resulting in the two indicated results of the flooding could be presented in list DAMAGE to or penetration of ANY EITHER: format. of the following structures containing VISIBLE DAMAGE to or The NEI phrase "ANY of the following structures containing safety safety systems or components OR penetration of ANY systems or components" has been changed to "ANY SAFETY-control room indication of degraded RELATED STRUCTURE, SYSTEM, OR COMPONENT within ANY SAFETY-RELATED performance of those safety STRUCTURE, SYSTEM, Table H-1 area" to be consistent with the definition of visible systems: OR COMPONENT within damage and related HA1 EAL thresholds. This also permits (site specific structure list) ANY Table H-1 area presentation of the site specific list in a table. OR Table H-1 provides the list of areas/structures containing safety systems or components. This change implements EAL FAQ #44. Control Room indication of degraded performance of The NEI phrase "those safety systems" has been changed to "ANY ANY SAFETY-RELATED SAFETY-RELATED STRUCTURE, SYSTEM, OR COMPONENT STRUCTURE, SYSTEM, within ANY Table H-1 area" for clarification. OR COMPONENT within ANY Table H-1 area 5 Vehicle crash resulting in VISIBLE HA1.6 Vehicle crash resulting in The logic term "EITHER" has been added to the threshold so that DAMAGE to ANY of the following EITHER: the two indicated results of the flooding could be presented in list structures containing safety systems format. VISIBLE DAMAGE to ANY or components OR control room SAFETY-RELATED The NEI phrase "ANY of the following structures containing safety indication of degraded performance STRUCTURE, SYSTEM, OR systems or components" has been changed to "ANY safety-related of those safety systems: COMPONENT within ANY structure, system, or component within ANY Table H-1 area" to be (site specific structure list) Table H-1 area consistent with the definition of visible damage and related HA1 OR EAL thresholds. This also permits presentation of the site specific list in a table. Control Room indication of degraded performance of Table H-1 provides the list of areas/structures containing safety ANY SAFETY-RELATED systems or components. This change implements EAL FAQ #44. STRUCTURE, SYSTEM, OR The NEI phrase "those safety systems" has been changed to "ANY COMPONENT within ANY safety-related structure, system, or component within ANY Table 88 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP Table H-1 area H-1 area" for clarification. 6 (Site specific occurrences) resulting HA1.5 Bay water level ->top of the 18 ft (top of the traveling screen cover) is the design flood level. in VISIBLE DAMAGE to ANY of the traveling screen cover housing following structures containing OR The predicted extreme low tide elevation is (-) 3.6 ft Mean Sea safety systems or components OR Level (MSL). However, the plant has been designed for (-) 4.0 ft control room indication of degraded Bay water level or inside MSL and can continue to operate with an extreme low water performance of those safety traveling screen water level < Elevation of -6.0 ft MSL. This EAL criterion is met if the water is 16 systems: 16.0 ft below intake concrete ft below the intake (-72 in. MSL) concrete level by observation. This level (-72.0 in. Mean Sea Level) measurement requires judgment because the Bay surface is not normally still. The top of the saltwater pump intakes is at -9.5 ft MSL. 89 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP Table H-I Safe Shutdown Areas

                     " Control Room

• Containment
• Auxiliary Building

                     " Diesel Generator Rooms

• Intake Structure

                     " 1A/OC DG Buildings
                     " RWT
                     " RWT Rooms

• CST No. 12

                     " FOSTNo. 21
                     " Auxiliary Feed Pump Rooms 90 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI IC# NEI IC Wording CCNPP CCNPP IC Wording Difference/Deviation Justification IC#(s) HA2 FIRE or EXPLOSION affecting HA2 Fire or explosion affecting the None the operability of plant safety operability of plant safety systems systems required to establish or required to establish or maintain maintain safe shutdown safe shutdown MODE: All MODE: All NEI EALEx. E EALPP NEI Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification FIRE or EXPLOSION resulting HA2.1 FIRE or EXPLOSION resulting in The logic term "EITHER" has been added to the threshold so that in VISIBLE DAMAGE to ANY of EITHER: the two indicated results of the fire/explosion could be presented in the following structures VISIBLE DAMAGE to ANY list format. containing safety systems or SAFETY-RELATED The NEI phrase "ANY of the following structures containing safety components OR control room STRUCTURE, SYSTEM, OR systems or components" has been changed to "ANY safety-related indication of degraded COMPONENT within ANY structure, system, or component within ANY Table H-1 area" so that performance of those safety Table H-1 area the site specific list could be presented in a table. systems: (site specific structure list) OR Table H-1 provides the list of areas/structures containing safety Control Room indication of systems or components. This change implements EAL FAQ #44. degraded performance of The NEI phrase "those safety systems" has been changed to "ANY ANY SAFETY-RELATED safety-related structure, system, or component within ANY Table H-STRUCTURE, SYSTEM, OR 1 area" for clarification. COMPONENT within ANY Table H-1 area 91 of 125

EAL Comparison Matrix - OSSI Project #09-0803 CCNPP Table H-I Safe Shutdown Areas

                       " Control Room

• Containment
• Auxiliary Building
• Diesel Generator Rooms
• Intake Structure
• 1A/OC DG Buildings

                       " RWT

• RWT Rooms

                       " CST No. 12

• FOST No. 21

                       " Auxiliary Feed Pump Rooms 92 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI IC# NEI IC Wording CCNPP CCNPP IC Wording Difference/Deviation Justification IC#(s) HA3 Access to a VITAL AREA is HA3 Access to a Vital Area is None prohibited due to toxic, corrosive, prohibited due to toxic, corrosive, asphyxiant or flammable gases asphyxiant or flammable gases which jeopardize operation of which jeopardize operation of operable equipment required to operable equipment required to maintain safe operations or maintain safe operations or safely safely shutdown the reactor. shutdown the reactor MODE: All MODE: All NEI Ex. NEI Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification EAL # EAL # 1 Note: If the equipment in the HA3.1 Access to ANY Table H-1 area is CCNPP vital areas are specified in Table H-i. This change stated area was already prohibited due to toxic, corrosive, implements EAL FAQ #44. inoperable, or out of service, asphyxiant or flammable gases The NEI phrase "systems required to maintain safe operations or before the event occurred, then which jeopardize operation of safely shutdown the reactor" has been changed to "ANY safety-this EAL should not be declared ANY SAFETY-RELATED related structure, system, or component" for consistency with as it will have no adverse impact STRUCTURE, SYSTEM, OR subcategory H1 and H2 Alert EALs. Safety-related structures, on the ability of the plant to safely COMPONENT (Note 5) systems, and components are systems that are required to maintain operate or safely shutdown Note 5: If the equipment in the safe operations or safely shutdown the reactor. Technical Specifications at the by stated area was already Reference to the NEI note is included in the EAL wording "(Note 5)." timeof te evntbefore time of thecevent, the event inoperable, or outoccurred, of service,then Numbering the note facilitates referencing in the EAL matrix.

1. Access to a VITAL AREA is EAL HA3.1 should not be The NEI phrase "this EAL" has been changed to "EAL HA3.1" for prohibited due to toxic, corrosive, declared as it will have no clarification.

asphyxiant or flammable gases adverse impact on the ability of which jeopardize operation of the plant to safely operate or systems required to maintain safe safely shutdown beyond that operations or safely shutdown the already allowed by Technical reactor. Specifications at the time of the event. 93 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP CCNPP NEI IC# NEI IC Wording IC#(s) CCNPP IC Wording Difference/Deviation Justification HA4 HOSTILE ACTION within the OWNER HA4 Hostile action within the Owner None CONTROLLED AREA or airborne attack Controlled Area or airborne attack threat. threat. MODE: All MODE: All NEI Ex. NEI Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification EAL # EAL # 1 A HOSTILE ACTION is occurring or has HA4.1 A HOSTILE ACTION is occurring or has The NEI Example EALs have been combined in one occurred within the OWNER occurred within the Owner Controlled plant EAL for simplification. CONTROLLED AREA as reported by the Area as reported by Security Shift (site specific security shift supervision). Supervisor "Security Shift Supervisor" security supervision that areis qualified the site-specific and trained to OR confirm that a security event is occurring or has A validated notification from NRC of an occurred. 2 A validated notification from NRC of anAILNRatcthetwhi30m.o airliner attack threat within 30 minutes of thE site the site. the site 94 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI IC# NEI IC Wording CCNPP CCNPP IC Wording Difference/Deviation Justification IC#(s) HA5 Control Room Evacuation Has HA5 Control Room evacuation has been None Been Initiated initiated MODE: All MODE: All NEI EA Ex. E EALPP NEI Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification EAL # EAL # 1 (Site-specific procedure) HA5.1 Control Room evacuation has been AOP-9A, Control Room Evacuation and Safe Shutdown Due requires control room initiated to a Severe Control Room Fire and AOP-1 1 Control Room evacuation. Evacuation and Safe Shutdown - Non-Fire Conditions provide specific instructions for evacuating the Control Room if it becomes uninhabitable. The IC wording has been utilized since the intent is to classify the Alert based on Control Room evacuation, regardless whether the associated procedure has been entered or executed. This change implements EAL FAQ #28. 95 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI IC# NEI IC Wording CCNPP CCNPP IC Wording Difference/Deviation Justification IC#(s) HA6 Other conditions exist which in the HA6 Other conditions exist that in the Replaced the word "which" with "that"for proper grammar. judgment of the Emergency judgment of the Emergency Director Director warrant declaration of an warrant declaration of an Alert Alert. MODE: All MODE: All NEI EA Ex. E CCNPP NEI Example EAL Wording CL EAL # EALP# CCNPP EAL Wording Difference/Deviation Justification 1 Other conditions exist which in the HA6.1 Other conditions exist which in the Reformatted for readability. judgment of the Emergency judgment of the Emergency Director EPA PAG values have been added for clarification. Director indicate that events are in indicate that events are in progress or progress or have occurred which have occurred which involve: involve an actual or potential An actual or potential substantial substantial degradation of the A culo oeta usata degradation of the level of safety of the level of safety of the plant or a plant security event that involves probable life threatening risk to OR site personnel or damage to site A security event that involves probable equipment because of HOSTILE life threatening risk to site personnel or ACTION. Any releases are damage to site equipment because of expected to be limited to small HOSTILE ACTION fractions of the EPA Protective Action Guideline exposure levels. ANY releases are expected to be limited to small fractions of the EPA Protective Action Guideline exposure levels (1,000 mRem TEDE and 5,000 mRem thyroid CDE) 96 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP CCNPP NEI IC# NEI IC Wording IC#(s) CCNPP IC Wording Difference/Deviation Justification HS4 A HOSTILE ACTION within the HS4 Hostile action within the Protected Area Deleted unnecessary preposition "A". Protected Area MODE: All MODE: All NEI Ex. NEI Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification EAL # EAL # 1 A HOSITLE ACTION is occurring HS4.1 A HOSTILE ACTION is occurring or has "Security Shift Supervisor" is the site-specific security or has occurred within the occurred within the PROTECTED AREA supervision that are qualified and trained to confirm that a PROTECTED AREA as reported as reported by Security Shift Supervisor security event is occurring or has occurred. by the (site-security shift supervision). 97 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI IC# NEI IC Wording CCNPP CCNPP IC Wording Difference/Deviation Justification IC#(s) HS2 Control room evacuation has HS5 Control Room evacuation has been None been initiated and plant control initiated and plant control cannot be cannot be established, established MODE: All MODE: All NEI Ex. NEI Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification EAL # EAL # 1 a. Control room evacuation HS5.1 Control Room evacuation has been An analysis was performed to determine how quickly control has been initiated, initiated AND EITHER: must be re-established at CCNPP without core uncovery or AND Inability to establish Auxiliary damage. generators RETRAN simulation shows that the steam A go dry at about 47 minutes for the AOP-9 (station

b. Control of the plant cannot be Feedwater to at least one steam fire) scenario. RCS pressure reaches the lowest pressurizer established within (site specific generator within 30 min. (Note 4) safety valve setpoint soon thereafter. Restoring feedwater minutes). OR within 45 minutes assures that RCS pressure remains below Inability to establish reactor coolant the safety valve setpoint thus avoiding inventory loss. The make-up (charging pump flow) within maximum time allowable to restore RCS inventory for 60ke-up (chan pp fAppendix R (station fire) scenarios is 90 minutes. Site 60 min. (Note 4) Emergency declaration at 30 minutes and 60 minutes for Note 4: The ED should not wait until the inability to restore feedwater and RCS make-up respectively applicable time has elapsed, but should thus constitutes a conservative action for emergency declare the event as soon as it is response.

determined that the condition has This EAL is based on analysis and actual procedure walk exceeded, or will likely exceed, the throughs. Licensee Event Report (LER) 50-371/89-009, Rev. applicable time. 2, (transmitted to the NRC on July 7, 1989) documents the analysis that demonstrates the ability to safely shutdown Unit 1 in accordance with AOP-9. Reference to Note 4 has been added to the CCNPP EAL for consistency with other EALs that include a time duration. 98 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI IC# NEI IC Wording CCNPP CCNPP IC Wording Difference/Deviation Justification IC#(s) HS3 Other conditions exist which in HS6 Other conditions existing that in the Replaced the word "which" with "that"for proper grammar the judgment of the Emergency judgment of the Emergency Director Director warrant declaration of a warrant declaration of a Site Area Site Area Emergency. Emergency MODE: All MODE: All NEI EALEx. E CCNPP NEI Example EAL Wording EAL # CCNPP EAL Wording Difference/Deviation Justification 1 Other conditions exist which in HS6.1 Other conditions exist which in the Reformatted for readability. the judgment of the Emergency judgment of the Emergency Director EPA PAG values have been added for clarification. Director indicate that events are indicate that events are in progress or in progress or have occurred have occurred which involve: which involve actual or likely Actual or likely major failures of plant major failures of plant functions functions needed for protection of the needed for protection of the public public or HOSTILE ACTION that results in intentional damage or OR malicious acts; (1) toward site HOSTILE ACTION that results in personnel or equipment that intentional damage or malicious acts; could lead to the likely failure of (1) toward site personnel or equipment or; (2) that prevent effective that could lead to the likely failure of or; access to equipment needed for (2) that prevent effective access to the protection of the public. Any equipment needed for the protection of releases are not expected to the public result in exposure levels which exceed EPA Protective Action ANY releases are not expected to result Guideline exposure levels in exposure levels which exceed EPA beyond the site boundary. Protective Action Guideline exposure levels (1,000 mRem TEDE and 5,000 mRem thyroid CDE) beyond the site boundary. 99 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP CCNPP NEI IC# NEI IC Wording IC#(s) CCNPP IC Wording Difference/Deviation Justification HG1 HOSTILE ACTION resulting in HG4 Hostile action resulting in loss of physical None loss of physical control of the control of the facility facility. MODE: All MODE: All NEI Ex. NEI Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification EAL # EAL # 1 A HOSTILE ACTION has HG4.1 A HOSTILE ACTION has occurred such Safety functions listed in the NEI basis of this EAL that are occurred such that plant that plant personnel are unable to applicable to CCNPP are the following and have been personnel are unable to operate operate equipment required to maintain included for clarification: equipment required to maintain ANY of the following safety function safety functions. acceptance criteria:

• Reactivity control (RC)
• Reactivity control (RC)
• Vital Auxiliaries (VA)

                                                  " Vital Auxiliaries (VA)

• RCS pressure and inventory control (PIC)
• RCS pressure and inventory control
• Core & RCS heat removal (HR)

(PIC)

                                                  " Core & RCS heat removal (HR) 2    A HOSTILE ACTION has caused     HG4.2   A HOSTILE ACTION has caused failure          The logic term "AND" has been added to the threshold for failure of Spent Fuel Cooling           of Spent Fuel Cooling systems                format consistency.

Systems and IMMINENT fuel AND The NEI phrase "for a freshly off-loaded reactor core in pool" has been deleted because any imminent fuel damage loaded reactor core in pool. IMMINENT fuel damage is likely caused by hostile action warrants a GE declaration even if it is not from a freshly off-loaded core in pool. This change implements EAL FAQ # 29. 100 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP CCNPP NEI IC# NEI IC Wording IC#(s) CCNPP IC Wording Difference/Deviation Justification HG2 Other conditions exist which in HG6 Other conditions exist that in the Replaced the word "which" with "that" for proper grammar the judgment of the Emergency judgment of the Emergency Director Director warrant declaration of a warrant declaration of a General General Emergency. Emergency MODE: All MODE: All NEI Ex. NEI Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification EAL # EAL # 1 Other conditions exist which in HG6.1 Other conditions exist which in the Reformatted for readability. the judgment of the Emergency judgment of the Emergency Director EPA PAG values have been added for clarification. Director indicate that events are indicate that events are in progress or in progress or have occurred have occurred which involve: which involve actual or Actual or IMMINENT substantial core IMMINENT substantial core degradation or melting with potential degradation degrdatin or o melting meling with ithfor loss of Containment integrity potential for loss of containment integrity or HOSTILE ACTION OR that results in an actual loss of HOSTILE ACTION that results in an physical control of the facility, actual loss of physical control of the Releases can be reasonably facility expected to exceed EPA Protective Action Guideline Releases can be reasonably expected to exposure levels off-site for more exceed EPA Protective Action Guideline than the immediate site area. exposure levels (1,000 mRem TEDE and 5,000 mRem thyroid CDE) offsite for more than the immediate site area. 101 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP Category S System Malfunction 102 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP CCNPP NEI IC# NEI IC Wording IC#(s) CCNPP IC Wording Difference/Deviation Justification SU1 Loss of all Off-site AC power to SU1 Loss of all offsite AC power to 4 "4 kV vital buses" is the CCNPP specific terminology for "emergency emergency busses for 15 minutes kV vital buses for _>15 min. busses". or longer. MODE: 1 - Power Operation, 2 - The NEI phrase "15 minutes or longer" has been replaced with "> 15 MODE: Power Operation, Startup, Startup, 3 - Hot Standby, 4 - Hot min." to reduce EAL-user reading burden. The symbol "Z"means Hot Standby, Hot Shutdown Shutdown "greater than or equal to" and thus implements the intent of the NEI phrase. NEI EALEx.

     #                                       CCNPP NEI Example EAL Wording           EAL #           CCNPP EAL Wording                                  Difference/Deviation Justification 1    Note: The Emergency Director          SUI.1   Loss of all offsite AC power,           Table S-1 provides a list of onsite and offsite AC power supplies.

should not wait until the Table S-1, to 4kV vital buses 4kV vital buses 11(21) and 14(24) are the CCNPP emergency applicable time has elapsed, but 11(21) and 14(24) for _>15 min. buses. should declare the event as soon (Note 4) as it is determined that the The NEI phrase "15 minutes or longer" has been replaced with "_'15 condition has exceeded, or will Note 4: The ED should not wait until min." to reduce EAL-user reading burden. The symbol "Z"means likely exceed,likly aplicbl xcedth tie.the the applicable time. shouldapplicable declare time has elapsed, the event as soonbut as 1"greater than or equal to" and thus implements the intent of the NEI Loss of all off-site AC power to it is determined that the condition has phrase. (site specific emergency busses) exceeded, or will likely exceed, the Reference to the NEI note is included in the EAL wording "(Note 4)." for 15 minutes or longer. applicable time. Numbering the note facilitates referencing in the EAL matrix. 103 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP Table S-1 AC Power Sources

• 1(2)A DG 1(2)B DG o OC DG, ifaligned
• 500kV transmission line 5051"
• 500kV transmission line 5052*

                     . 500kV transmission line 5072*

0

• SMECO line, if aligned
• A credited 500kV line must have an independent 13kV service transformer 104 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI IC# NEI IC Wording CCNPP CCNPP IC Wording Difference/Deviation Justification IC#(s) SU2 Inability to reach required SU4 Inability to reach required None shutdown within Technical shutdown within Technical Specification limits. Specification limits MODE: Power Operation, MODE: 1 - Power Operation, 2 - Startup, Hot Standby, Hot Startup, 3 - Hot Standby, 4 - Hot Shutdown Shutdown NEI Ex. NEI Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification EAL # EAL # 1 Plant is not brought to required SU4.1 Plant is not brought to required "... required action completion time" is the CCNPP Technical operating mode within Technical operating mode within Technical Specification terminology for "... Action Statement Time." Specifications LCO Action Specifications LCO required Statement Time. action completion time 105 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI IC# NEI IC Wording CCNPP CCNPP IC Wording Difference/Deviation Justification IC#(S) SU3 UNPLANNED loss of safety SU5 Unplanned loss of safety system The NEI phrase "15 minutes or longer" has been replaced with ">_15 system annunciation or indication annunciation or indication in the min." to reduce EAL-user reading burden. The symbol "Z"means in the control room for 15 minutes Control Room for _>15 min. "greater than or equal to" and thus implements the intent of the NEI or longer. MODE: 1 - Power Operation, 2 - phrase. MODE: Power Operation, Startup, Startup, 3 - Hot Standby, 4 - Hot Hot Standby, Hot Shutdown Shutdown NEI Ex. NEI Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification EAL # EAL # 1 Note: The Emergency Director SU5.1 UNPLANNED loss of greater than The NEI phrase "...greater than approximately 75% of the following should not wait until the approximately 75% of safety ... a... b..." has been changed to "...greater than approximately 75% applicable time has elapsed, but system annunciation or indication of safety system annunciation or indication on Control Room panels" should declare the event as soon on Control Room panels for _>15 for simplification. All main control board panels house annunciators as it is determined that the min. (Note 4) and indicators important for control of the plant. A site specific list of condition has exceeded, or will Note 4: The ED should not wait until Control Room safety system annunciation and indication is not listed likely exceed, the applicable time. the applicable time has elapsed, but in this EAL. Safety-related annunciation and indications are UNPLANNED Loss of greater should declare the event as soon as numerous and varied. Just as the Shift Manager is expected to use than approximately 75% of the it is determined that the condition has his/her judgment in assessing the loss of 75% of annunciation and following for 15 minutes or longer: exceeded, or will likely exceed, the indication, the Shift Manager is best situated to assess the Control applicable time. Room panel indicators and annunciation that are important for

a. (Site specific control room control of the plant.

safety system annunciation) The NEI phrase "15 minutes or longer" has been replaced with "_Ž15 OR min." to reduce EAL-user reading burden. The symbol "Z"means

b. (Site specific control room "greater than or equal to" and thus implements the intent of the NEI safety system indication) phrase.

Reference to the NEI note is included in the EAL wording "(Note 6)." Numbering the note facilitates referencing in the EAL matrix. 106 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP CCNPP NEI IC# NEI IC Wording IC#(s) CCNPP IC Wording Difference/Deviation Justification SU4 Fuel Clad Degradation SU7 Fuel clad degradation None MODE: Power Operation, MODE: 1 - Power Operation, 2 - Startup, Hot Standby, Hot Startup, 3 - Hot Standby, 4 - Hot Shutdown Shutdown NEI EALEx. E NEI Example EAL Wording EALPP CCNPP CCNPP EAL Wording Difference/Deviation Justification 1 (Site specific radiation monitor SU7.2 Letdown Monitor (RY-202-1) high The Letdown Radiation Monitor (1(2)-RY-202-1)) gross radiation readings indicating fuel clad alarm (> 1E+06 cpm) channel continuously monitors the activity in a sample drawn from degradation greater than the RCS and actuates an alarm in the Control Room if a Technical Specification predetermined activity level is reached. The sensor is a gross-allowable limits.) gamma plus specific isotope (1-135) monitor; the system is designed to detect activity release from the fuel to the reactor coolant within five minutes of a fuel degradation event. 2 (Site specific coolant sample SU7.1 Coolant activity > ANY of the The specified values are the TS coolant activity limits. activity value indicating fuel clad following: degradation greater than 9 Dose equivalent 1-131 0.5 Technical Specification uCi/gm for 100 hrs. allowable limits.) continuous

                                                       " Dose equivalent 1-131 acceptable region of T.S. Fig.

3.4.15-1

                                                       " Dose equivalent 1-131 137.5 uCi/gm
                                                       " Gross activity 100/E-bar I     uCi/gm 107 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP CCNPP NEI IC# NEI IC Wording IC#(s) CCNPP IC Wording Difference/Deviation Justification SU5 RCS Leakage SU8 RCS leakage None MODE: Power Operation, MODE: 1 - Power Operation, 2 - Startup, Hot Standby, Hot Startup, 3 - Hot Standby, 4 - Hot Shutdown Shutdown NEI EALEx. E EALPP NEI Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification 1 Unidentified or pressure SU8.1 Unidentified or pressure SU8.1 implements Example EALs #1 and #2. These were combined boundary leakage greater than boundary leakage > 10 gpm for > for improved usability. 10 gpm. 15 min. (Note 4) The NEI phrase "greater than" has been replaced with the symbol 2 Identified leakage greater than OR ">" to reduce EAL-user reading burden. The symbol means "greater 25 gpm, Identified leakage > 25 gpm for > than" and thus implements the intent of the NEI phrase. 15 min. (Note 4) The phrase "for > 15 min. (Note 4)" has been added to the CCNPP EAL to allow mitigation by operating procedures prior to declaration. Note 4: The EC should not wait This is a deviation from NEI 99-01 Revision 5. until the applicable time has elapsed, but should declare the event as soon as it is determined that the condition has exceeded, or will likely exceed, the applicable time. 108 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI IC# NEI IC Wording CCNPP CCNPP IC Wording Difference/Deviation Justification IC#(s) SU6 Loss of all On-site or Off-site SU6 Loss of all onsite or offsite None communications capabilities, communications capabilities MODE: Power Operation, MODE: 1 - Power Operation, 2 - Startup, Hot Standby, Hot Startup, 3 - Hot Standby, 4 - Hot Shutdown Shutdown NEI EALEx. E EALPP NEI Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification 1 Loss of all of the following on- SU6.1 Loss of all Table S-3 onsite SU5.1 implements Example EALs #1 and #2. These were combined site communication methods (internal) communication methods for improved usability. affecting the ability to perform affecting the ability to perform The NEI example EALs specify site-specific lists of onsite and offsite routine operations. routine operations communications methods. The CCNPP EAL lists these methods in (site specific list of OR Table S-3 because the number of communications methods is too communications methods) Loss of all Table S-3 offsite long to include within the text of the EAL.

                                                 -(external) communication            The adjectives "(internal)" and "(external)" have been added to the Loss omethods                                       affecting the ability to  CCNPP EAL for clarification. The terms "onsite/offsite" could be site communication methods               perform offsite notifications to any interpreted as the location in which the communication originates affecting the ability to perform         agency                               instead of the location to which communication is directed.

offsite notifications. (site specific list of Added the words "...to any agency" to clarify the intent of the bases communications methods) statement: "The availability of one method of ordinary off-site communications is sufficient to inform federal, state, and local authorities of plant issues." 109 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP Table S-3 Communications Systems Onsite Offsite System (internal) (external) Commercial phone system X X Plant page system X Microwave telephone (Hot-Lines) (EOB) X X Dedicated offsite agency telephone system X FTS 2001 telephone system X CCNPP Radio System X X Satellite Phone System X Cellular Phone System X X 110 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP CCNPP NEI IC# NEI IC Wording IC#(s) CCNPP IC Wording Difference/Deviation Justification SU8 Inadvertent Criticality. SU3 Inadvertent criticality None MODE: Hot Standby, Hot MODE: 3 - Hot Standby, 4 - Hot Shutdown Shutdown NEI EALEx.

     #                                    EANPP NEI Example EAL Wording      CCNPP          CCNPP EAL Wording                            Difference/Deviation Justification 1    UNPLANNED sustained positive        N/A   N/A                              NEI Example EAL #1 has not been implemented because it applies period observed on nuclear                                                 only to BWR plants. CCNPP is a PWR. PWRs are not equipped instrumentation. [BVVR]                                                    with period meters.

1 UNPLANNED sustained positive SU3.1 An UNPLANNED sustained None startup rate observed on nuclear positive startup rate observed on instrumentation. [PWR] nuclear instrumentation 111 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP CCNPP NEI IC# NEI IC Wording IC#(s) CCNPP IC Wording Difference/Deviation Justification SA2 Automatic Scram (Trip) fails to SA3 Automatic reactor trip failed to The term "reactor" has been added to the phrase "automatic... trip" shutdown the reactor and the shut down the reactor and the for clarification. manual actions taken from the manual actions taken from the The term "scram" was replaced with "trip" consistent with PWR reactor control console are reactor control console are successful in shutting down the successful in shutting down the terminology. reactor. reactor The NEI term "fails" has been changed to "failed" for consistency MODE: Power Operation, MODE: 1 - Power Operation with

                                                                                    #31. the example EAL wording. This change implements EAL FAQ Startup The Startup mode has been deleted from the CCNPP EAL. CCNPP Technical Specifications definition of Startup mode is Ke,> 0.99 and rated thermal power < 5%. It is not possible to be in Startup mode with reactor power above 5%.Since the definition of reactor shutdown is reactor power less than or equal to 5% (in accordance with the NEI 99-01 basis for this EAL), this EAL would never be applicable in Startup mode.

NEI EALEx. E EALPP NEI Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification

a. An automatic scram (trip) SA3.1 An automatic trip failed to shut The term "scram" was replaced with "trip" consistent with PWR failed to shutdown the down the reactor terminology.

reactor. AND The NEI phrase "reactor control console" has been replaced with AND Manual actions taken at the "Control Room panels" to use terminology familiar to CCNPP

b. Manual actions taken at the Control Room panels operators.

reactor control console successfully shut down the The power range indication above 5% is greater than the decay heat successfully shutdown the reactor as indicated by reactor which the shutdown systems (Auxiliary Feed Water and reactor as indicated by (site power < 5% Atmospheric Dump Valves) were designed to remove and is specific indications of plant indicative of a condition requiring immediate response to prevent shutdown). subsequent core damage. 112 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP CCNPP NEI IC# NEI IC Wording IC#(s) CCNPP IC Wording Difference/Deviation Justification SA4 UNPLANNED Loss of safety SA5 Unplanned loss of safety system None system annunciation or indication annunciation or indication in the in the control room with EITHER Control Room with either (1) a (1) a SIGNIFICANT TRANSIENT significant transient in progress, or in progress, or (2) compensatory (2) compensatory indicators are indicators unavailable, unavailable MODE: Power Operation, MODE: 1 - Power Operation, 2 - Startup, Hot Standby, Hot Startup, 3 - Hot Standby, 4 - Hot Shutdown Shutdown NEI EA Ex. E CCNPP NEI Example EAL Wording EAL CCNPP EAL Wording Difference/Deviation Justification EAL # EAL # 1 Note: The Emergency Director SA5.1 UNPLANNED loss of greater than The NEI phrase "...greater than approximately 75% of the following should not wait until the approximately 75% of safety ... a... b..." has been changed to "... greater than approximately 75% applicable time has elapsed, but system annunciation or indication of safety system annunciation or indication on Control Room should declare the event as soon on Control Room panels for _>15 panels..." for simplification. All main control board panels house as it is determined that the min. (Note 4) annunciators and indicators important for control of the plant. A site condition has exceeded, or will AND EITHER: specific list of Control Room safety system annunciation and likely exceed, the applicable time. A significant transient is in indication is not listed in this EAL. Safety-related annunciation and

a. UNPLANNED loss of greater progress, Table S-2 indications are numerous and varied. Just as the Shift Manager is than approximately 75% of the OR expected to use his/her judgment in assessing the loss of 75% of following for 15 minutes or longer: Compensatory indications annunciation and indication, the Shift Manager is best situated to are unavailable (Plant assess the Control Room panel indicators and annunciation that

           * (Site specific control room                   Computer, SPDS)                 are important for control of the plant.

OR safety system annunciation) Note 4: The ED should not wait The NEI phrase "15 minutes or longer" has been replaced with">

           * (Site specific control room              until the applicable time has        15 min." to reduce EAL-user reading burden. The symbol "Z" safety system indication)              elapsed, but should declare the       means "greater than or equal to" and thus implements the intent of OR                                           event as soon as it is determined     the NEI phrase.

b. EITHER of the following: that the condition has exceeded, The CCNPP compensatory indications are provided by Plant

           " A SIGNIFICANT     TRANSIENT is inprogessapplicable     or will likelytime.

exceed, the Process Computer and SPDS. is in progress. aReference to the NEI note is included in the EAL wording "(Note

           " Compensatory indications are_

113 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP unavailable. 4)." Numbering the note facilitates referencing in the EAL matrix. Table S-2 provides the list of events that constitute a "significant transient." 10% thermal power oscillations have been deleted because it is not possible for CCNPP to have such power oscillations. Table S-2 Significant Transients

• Automatic turbine runback > 25% thermal power
• Electric load rejection > 25% full electrical load
• Reactor trip
• Safety Injection actuation 114 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP CCNPP NEI IC# NEI IC Wording IC#(s) CCNPP IC Wording Difference/Deviation Justification SA5 AC power capability to SA1 AC power capability to 4kV vital "4kV vital buses" is the CCNPP specific terminology for "emergency emergency busses reduced to a buses reduced to a single power busses". single power source for 15 source for Ž15 min. such that The NEI phrase "15 minutes or longer" has been replaced with "_>15 minutes or longer such that any ANY additional single failure min" to reduce EAL-user reading burden. The symbol "Z"means additional single failure would would result in a complete loss aditional stiongblefaiuout. result in station blackout, wuld rl vintal bpomeer o of, "greater than or equal to" and thus implements the intent of the NEI all 4kV vital bus power phrase. MODE: Power Operation, MODE: 1 - Power Operation, 2 - The phrase "... any additional single failure would result in station Startup, Hot Standby, Hot Startup, 3 - Hot Standby, 4 - Hot blackout." was replaced with "... ANY additional single failure would Shutdown Shutdown result in a complete loss of all 4kV vital bus power." This is consistent with the intent that classification be based on a loss of AC power to emergency buses. A Station Blackout involves a loss of all AC power, not just emergency bus power. This change implements EAL FAQ #36. NEI EALEx. E EALPP NEI Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification 1 Note: The Emergency Director SAI.1 AC power capability to 4kV vital Table S-1 provides a list of onsite and offsite AC power supplies. should not wait until the buses 11(21) and 14(24) 4kV vital buses 11(21) and 14(24) are the CCNPP emergency applicable time has elapsed, but reduced to a single power buses. should declare the event as soon source, Table S-1, for _>15 min. as it is determined that the (Note 4) The NEI phrase"...station blackout" has been replaced with "... a condition has exceeded, or will complete loss of all 4kV vital bus power" as this describes the likely exceed, the applicable AND intended condition for CCNPP. This change implements EAL FAQ time. ANY additional single power #36.

a. AC power capability to source failure will result in a The NEI phrase '15 minutes or longer" has been replaced with "_>15 (site-specific emergency busses) complete loss of all 4kV vital bus min." to reduce EAL-user reading burden. The symbol "Z"means reduced to a single power source power "greater than or equal to" and thus implements the intent of the NEI for 15 minutes or longer. Note 4: The ED should not wait phrase.

until the applicable time has Reference to the NEI note is included in the EAL wording "(Note 4)."

b. Any additional single elapsed, but should declare the Numbering the note facilitates referencing in the EAL matrix.

power source failure will result in event as soon as it is determined 115 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP station blackout. that the condition has exceeded, or will likely exceed, the applicable time. 116 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI IC# NEI IC Wording CCNPP CCNPP IC Wording Difference/Deviation Justification IC#(S) SS1 Loss of all Off-site and all On- SS1 Loss of all offsite and all onsite "4kV vital buses" is the CCNPP specific terminology for "emergency Site AC power to emergency AC power to 4kV vital buses for busses". busses for 15 minutes or longer. 2! 15 min. The NEI phrase "15 minutes or longer" has been replaced with ">_15 MODE: Power Operation, MODE: 1 - Power Operation, 2 - min." to reduce EAL-user reading burden. The symbol "Z"means Startup, Hot Standby, Hot Startup, 3 - Hot Standby, 4 - Hot "greater than or equal to" and thus implements the intent of the NEI Shutdown Shutdown phrase. NEI Ex. NEI Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification EAL # EAL # 1 Note: The Emergency Director SS1.1 Loss of all offsite and all onsite Table S-1 provides a list of onsite and offsite AC power supplies. should not wait until the AC power, Table S-1, to 4kV 4kV vital buses 11 (21) and 14(24) are the CCNPP emergency applicable time has elapsed, but vital buses 11(21) and 14(24) buses. should declare the event as soon for > 15 min. (Note 4) as it is determined that the Note 4: The ED should not wait The NEI phrase "15 minutes or longer" has been replaced with ">_ 15 condition has exceeded, or will until the applicable time has min." to reduce EAL-user reading burden. The symbol "Z"means likely exceed, the applicable elapsed, but should declare the "greater than or equal to" and thus implements the intent of the NEI time. event as soon as it is phrase. Loss of all Off-Site and all On- determined that the condition Reference to the NEI note is included in the EAL wording "(Note 4)." Site AC power to (site specific has exceeded, or will likely Numbering the note facilitates referencing in the EAL matrix. emergency busses) for 15 exceed, the applicable time. minutes or longer. 117 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP CCNPP NEI IC# NEI IC Wording IC#(s) CCNPP IC Wording Difference/Deviation Justification SS2 Automatic Scram (Trip) fails to SS3 Automatic trip and manual The term "scram" was replaced with "trip" consistent with PWR shutdown the reactor and actions taken from the reactor terminology. manual actions taken from the control console failed to shut The NEI phrase "fails to shutdown the reactor and manual actions reactor control console are not down the reactor taken from the reactor control console are not successful in shutting" successful in shutting down the 1 - Power Operation has been changed to "and manual actions taken from the reactor reactor. control console failed to shut" for clarification. This change MODE: Power Operation, implements EAL FAQ #31. Startup The Startup mode has been deleted from the CCNPP EAL. CCNPP Technical Specifications definition of Startup mode is Kef> 0.99 and rated thermal power < 5%. It is not possible to be in Startup mode with reactor power above 5%.Since the definition of reactor shutdown is reactor power less than or equal to 5% (in accordance with the NEI 99-01 basis for this EAL), this EAL would never be applicable in Startup mode. NEI ENEIEx. NECxapeNAPorigPA Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification EAL # EAL # 1 a. An automatic scram (trip) SS3.1 An automatic reactor trip failed The term "reactor" has been added to the phrase "automatic.. .trip" failed to shutdown the reactor. to shut down the reactor as for clarification. AND indicated by reactor power > 5% The term "scram" was replaced with "trip" consistent with PWR

b. Manual actions taken at the AND terminology.

reactor control console do not Manual actions taken at the The phrase "as indicated by reactor power > 5%" has been added to shutdown the reactor as Control Room panels do not the first contingent and the NEI phrase "do not shutdown the reactor" indicated by (site specific shut down the reactor as has been changed to "failed to shut down the reactor" in the second indications of reactor not indicated by reactor power > 5% contingent for clarification and consistency of wording. This change shutdown). implements EAL FAQ #31. The NEI phrase "reactor control console" has been replaced with "Control Room panels" to use terminology familiar to CCNPP operators. The power range indication above 5% is greater than the decay heat which the shutdown systems (Auxiliary Feed Water and Atmospheric 118 of 125

EAL Comparison Matrix EALitComparisonmMatrixs OSSI Project #09-0803 CCNPP Dump Valves) were designed to remove and is indicative of a condition requiring immediate response to prevent subsequent core damage. 119 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP CCNPP NEI IC# NEI IC Wording IC#(s) CCNPP IC Wording Difference/Deviation Justification SS3 Loss of all vital DC power for 15 SS2 Loss of all vital DC power for _ The NEI phrase "15 minutes or longer" has been replaced with "_>15 minutes or longer. 15 min. min." to reduce EAL-user reading burden. The symbol "Z"means MODE: Power Operation, MODE: 1 - Power Operation, 2 - "greater than or equal to" and thus implements the intent of the NEI Startup, Hot Standby, Hot Startup, 3 - Hot Standby, 4 - Hot phrase. Shutdown Shutdown NEI EA Ex. E NEI Example EAL Wording EALPP EAL # CCNPP EAL # CCNPP EAL Wording Difference/Deviation Justification 1 Note: The Emergency Director SS2.1 < 105 VDC on all 125 VDC The NEI IC phrase "less than" has been replaced with "<" to reduce should not wait until the buses (11, 12, 21 and 22) for > EAL-user reading burden. The symbol "<" means "less than" and applicable time has elapsed, but 15 min. (Note 4) thus implements the intent of the NEI phrase. should declare the event as soon Note 4: The ED should not wait "105 VDC" is the site-specific bus voltage indication. as it is determ condition ined that theuni has exceeded, or will th applicable until the ap lc b e time im has h s 125 VDC buses (11, 12, 21 and 22) are the CCNPP vital DC buses. conitol exceted ed ha orpwicall elapsed, but should declare the likely exceed, the applicable event as soon as it is The NEI phrase "15 minutes or longer" has been replaced with "_>15 time. determined that the condition min." to reduce EAL-user reading burden. The symbol "Z"means Less than (site specific bus has exceeded, or will likely "greater than or equal to" and thus implements the intent of the NEI voltage indication) on all (site exceed, the applicable time. phrase. specific Vital DC busses) for 15 Reference to the NEI note is included in the EAL wording "(Note 4)." minutes or longer. Numbering the note facilitates referencing in the EAL matrix. 120 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI IC# NEI IC Wording CCNPP CCNPP IC Wording Difference/Deviation Justification IC#(s) SS6 Inability to monitor a SS5 Inability to monitor a significant None SIGNIFICANT TRANSIENT in transient in progress progress. MODE: 1 - Power Operation, 2 - MODE: Power Operation, Startup, 3 - Hot Standby, 4 - Hot Startup, Hot Standby, Hot Shutdown Shutdown NEI EALEx. E NECxapeNAPorigPA NEI Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification Note: The Emergency Director SS5.1 Loss of greater than The NEI phrase "...greater than approximately 75% of the following should not wait until the approximately 75% of safety ... a. .. b..." has been changed to "...greater than approximately 75% applicable time has elapsed, system annunciation or of safety system annunciation or indication on Control Room panels but should declare the event indication on Control Room ... " for simplification. All main control board panels house as soon as it is determined panels for _>15 min. (Note 4) annunciators and indicators important for control of the plant. A site that the condition has specific list of Control Room safety system annunciation and exceeded, or will likely AND indication is not listed in this EAL. Safety-related annunciation and exceed, the applicable time. A significant transient is in indications are numerous and varied. Just as the Shift Manager is

a. Loss of greater than progress, Table S-2 expected to use his/her judgment in assessing the loss of 75% of approximately 75% of the annunciation and indication, the Shift Manager is best situated to following for 15 minutes or AND assess the Control Room panel indicators and annunciation that are longer: Compensatory indications are important for control of the plant.

            * (Site specific control room          unavailable (Plant Computer,       The NEI phrase "15 minutes or longer" has been replaced with ">_15 safety system                    SPDS)                              min." to reduce EAL-user reading burden. The symbol "Z means annunciation)                                                       "greater than or equal to" and thus implements the intent of the NEI OR                                  Note 4: The ED should not wait     phrase.
            " (Site specific control room          until the applicable time has safety system indication)        elapsed, but should declare the    The CCNPP compensatory indications are provided by Plant AND                                        event as soon as it is             Computer and SPDS.

b. A SIGNIFICANT TRANSIENT determined that the condition Reference to the NEI note is included in the EAL wording "(Note 4)."

is in progress. has exceeded, or will likely Numbering the note facilitates referencing in the EAL matrix. AND exceed, the applicable time. Table S-2 provides the list of events that constitute a "significant

c. Compensatory indications are transient." 10% thermal power oscillations have been deleted 121 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP unavailable. because it is not possible for CCNPP to have such power I oscillations. Table S-2 Significant Transients

                        " Automatic turbine runback > 25% thermal power

• Electric load rejection > 25% full electrical load
• Reactor trip
• Safety Injection actuation 122 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP CCNPP NEI IC# NEI IC Wording IC#(s) CCNPP IC Wording Difference/Deviation Justification SG1 Prolonged loss of all Off-site and SG1 Prolonged loss of all offsite and "4kV vital buses" is the CCNPP specific terminology for "emergency all On-Site AC power to all onsite AC power to 4kV vital busses". emergency busses. buses MODE: Power Operation, MODE: 1 - Power Operation, 2 - Startup, Hot Standby, Hot Startup, 3 - Hot Standby, 4 - Hot Shutdown Shutdown NEI EALEx.

     #      NEI Example EAL Wording EALPP CCNPP           CCNPP EAL Wording                                 Difference/Deviation Justification 1    a. Loss of all off-site and all     SGI.1  Loss of all offsite and all onsite  4kV vital buses 11(21) and 14(24) are the CCNPP emergency on-site AC power to (site               AC power, Table S-1, to 4kV         buses.

specific emergency vital buses 11(21) and 14(24) The NEI phrase "...of the following: .has been deleted. It is busses). AND EITHER: evident from the subsequent paragraphs and indentation applied to AND Restoration of at least one the CCNPP EAL that they follow the previous paragraph.

b. EITHER of the following: 4kV vital bus within 4 hours 4 are the "(site-specific)" hours for station blackout coping. The four-

• Restoration of at least one is not likely hour interval to restore AC power is based on the blackout coping ybus in less emergency bsilesOR analysis performed Regulatory in conformance with 10 CFR 50.63 and Guide 1.155.

than (site specific hours) is not likely. CET readings > 700°F The NEI phrase ... (Site-Specific) Indication of continuing

             *   (Site specific indication of                                              degradation of core cooling based on Fission Product Barrier contific     degradation of                                               monitoring" has been replaced with "CET readings > 7000 F" for continuing dedaon                                                         clarification. This threshold represents the NEI conditions consistent core cooling based on                                                     with the corresponding fission product barrier Fuel Clad Loss and Fission Product Barrier                                                   Potential Loss thresholds.

monitoring.) 123 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP NEI IC# NEI IC Wording CCNPP CCNPP IC Wording Difference/Deviation Justification IC#(s) SG2 Automatic Scram (Trip) and all SG3 Automatic trip and all manual The term "scram" was replaced with "trip" consistent with PWVR manual actions fail to shutdown actions fail to shut down the terminology. the reactor and indication of an reactor and indication of an The Startup mode has been deleted from the CCNPP EAL. CCNPP extreme challenge to the ability extreme challenge to the ability Technical Specifications definition of Startup mode is Keff-> 0.99 and to cool the core exists. to cool the core exists rated thermal power < 5%. It is not possible to be in Startup mode MODE: Power Operation, MODE: 1 - Power Operation with reactor power above 5%.Since the definition of reactor Startup shutdown is reactor power less than or equal to 5% (in accordance with the NEI 99-01 basis for this EAL), this EAL would never be applicable in Startup mode. NEI Ex. NEI Example EAL Wording CCNPP CCNPP EAL Wording Difference/Deviation Justification EAL # EAL # 1 failed

a. to Anshutdown automaticthe scram (trip) reactor. SG3.1 An automatic reactor trip failed The term "reactor" has been added to the phrase "automatic.. .trip" AND to shut down the reactor as for clarification.

b. All manual actions do not indicated by reactor power > 5% The term "scram" was replaced with "trip" consistent with PWR shutdown the reactor as indicated speacific incats ofd bysiutdownte AllAND manual actions fail to shut terminology.

by (site specific indications of The phrase "as indicated by reactor power > 5%" has been added to reactor not shutdown). by reactor power > 5% the REGNPP EAL for clarification. This change implements EAL ANDAND FAQ #31.

c. EITHER of the following ADFQ#1 exist or have occurred due to ANY of the following exist or The power range indication above 5% is greater than the decay heat continued power generation: have occurred: which the shutdown systems (Auxiliary Feed Water and Atmospheric o (Site specific indication that a CET readings > 7001F Dump Valves) were designed to remove and is indicative of a core cooling is extremely

• RCS pressure > PORV condition requiring immediate response to prevent subsequent core challenged.) setpoint damage.

(Site specific indication that

• RCS subcooling <250 F The NEI phrase "do not shutdown" has been changed to "fail to shut heat removal is down" for consistency with the IC wording. This change implements extremely challenged.) EAL FAQ #31.

The NEI phrase "EITHER of the following" has been changed to "ANY of the following" because the three subsequent conditions are equally weighted; one indicative of challenge to core cooling and 124 of 125

EAL Comparison Matrix OSSI Project #09-0803 CCNPP either of the remaining two indicative of challenge to heat removal. The NEI phrase "due to continued power generation" has been deleted because the extreme challenge to heat removal, equivalent to core cooling red, should not be constrained by requiring it to be caused by continued power generation. This change implements EAL FAQ #37. Site-specific indication that core cooling is extremely challenged is reactor power greater than 5% with indications of CET > 700 0 F. Site-specific indication that heat removal is extremely challenged is reactor power greater than 5% with RCS pressure > PORV setpoint or RCS subcooling < 251F. These conditions indicate the core cooling or ultimate heat sink function is under extreme challenge and, therefore, a core melt sequence may exist and rapid degradation of the fuel cladding could begin. 125 of 125

ATTACHMENT (4) I OFFSITE AGENCY APPROVALS Calvert Cliffs Nuclear Power Plant, LLC February 1, 2011

MARYLAND Martin O'Malley, Go.'mar Anthony G.Brown, L!. GoU..xn DEP'TMENT OF John R. Griffin, .5'et:ctoey

• _rNATURAL RESOURCES Joseph P.Gill, **pat:y *'*,crtnry December 17, 2010 Mr. Michael Fick Director, Emergency Planning Calvert Cliffs Nuclear Power Plant 1650 Calvert Cliffs Parkway Lusby, Maryland 20657-4702 RE: Proposed Calvert Cliffs Emergency Action Levels

Dear Mr. Fick:

The Maryland Department of Natural Resources, Power Plant Research Program understands and agrees with the proposed revisions to the Emergency Action Levels and Technical Basis Document, Revision 0, for the Calvert Cliffs Nuclear Power Plant. We appreciate the opportunity to participate and comment on the proposed revision. Sincerely, Susan Gray Manager, Nuclear Programs Power Plant Research Program Tawes State Office Building - 580 Taylor Avenue - Annapolis, Maryland 21401 410-260-BDNR or toll free in Maryland 877-620-8DNR - www.dnr.maryland.qov - TTY Users Call via the Maryland Relay

MARYLAND DEPARTMENT OF THE ENVIRONMENT 1800 Washington Boulevard

• Baltimore MD 21230 MDE 410-537-3000 e 1-800-633-6101 Martin O'Malley Robert M. Summers, Ph.D.

Governor Acting Secretary Anthony G. Brown Lieutenant Governor December 10, 2010 Mr. Michael Fick Director, Emergency Planning Calvert Cliffs Nuclear Power Plant 1650 Calvert Cliffs Parkway Lusby, Maryland 20657-4702 RE: Proposed Calvert Cliffs Emergency Action Levels

Dear Mr. Fick:

The Maryland Department of the Environment understands and agrees with the proposed revisions to the Emergency Action Levels and Technical Basis Document, Revision 0, for the Calvert Cliffs Nuclear Power Plant. We appreciate the opportunity to participate and comment on the proposed revision. Sincerely, Director, Emergency Preparedness Recycled Paper www. mde.state.md.us TrY Users 1-800-735-2258 Via Maryland Relay Service

STATE OF MARYLAND MILITARY DEPARTMENT MARTIN O'MALLEY JAMES A. ADKINS GOVERNOR BRIGADIER GENERAL THE ADJUTANT GENERAL ANTHONY G. BROWN LIEUTENANT GOVERNOR RICHARD G. MUTH DIRECTOR MARYLAND EMERGENCY MANAGEMENT AGENCY State Emergency Operations Center, Camp Fretterd Military Reservation 5401 Rue Saint Lo Drive, Reisterstown, MD 21136 (410) 517-3600 - Fax (410) 517-3610

• Toll Free 1 (877) 636-2872 TTY Users: 1 (800) 735-2258 January 7, 2011 Mr. Michael Fick Director, Emergency Planning Calvert Cliffs Nuclear Power Plant 1650 Calvert Cliffs Parkway Lusby, Maryland 20657-4702 RE: Proposed Calvert Cliffs Emergency Action Levels

Dear Mr. Fick:

The Maryland Emergency Management Agency understands and agrees with the proposed revisions to the Emergency Action Levels and Technical Basis Document, Revision 0, for the Calvert Cliffs Nuclear Power Plant. We appreciate the opportunity to participate and comment on the proposed revision. Sincerely, Richard Muth, Director Maryland Emergency Management Agency

Board of County Commissioners ST. MARY'S COUNTY GOVERNMENT Francis Jack Russell, President DEPARTMENT OF PUBLIC SAFETY Lawrence D. Jarboe, Commissioner DavidD. Zylak, Director Cynthia L. Jones, Commissioner 301-475-4200, Ext. 2111 /FAX301-475-4512 Todd B. Morgan, Commissioner lani*,I T Knrriv Iemm aeirnFnr EMERGENCY COMMUNICATIONS EMERGENCY MANAGEMENT ANIMAL CONTROL Tommy MattinglyJr, CommunicationsManager Jaclyn Shaw, Manager Antonio J. Malaspina, Sr., Supervisor 301-475-4200, Ext. 2121 Main Line: 301-475-4200, Ext. 2125 Main Line: 301-475"018 FAX 301-475-4370 FAX 301-475-4924 FAX: 301-4754924 December 10, 2010 Mr. Michael Fick Director, Emergency Planning Calvert Cliffs Nuclear Power Plant 1650 Calvert Cliffs Parkway Lusby, Maryland 20657-4702 RE: Proposed Calvert Cliffs Emergency Action Levels

Dear Mr. Fick:

The St. Mary's County Emergency Management Agency understands and agrees with the proposed revisions to the Emergency Action Levels and Technical Basis Document, Revision 0, for the Calvert Cliffs Nuclear Power Plant. We appreciate the opportunity to participate and comment on the proposed revision. Sincerely , David D. Zyt , Director Public Safety, St Mary's County P.O.Box 653

• 23090 LEONARD HALL DRIVE, LEONARDTOWN, MD 20650* www.co.saint-marys.md.us

DorchesterCounty Emergency ManagementAgency M. Wayne Robinson, Director 829 FieldcrestRoad Cambridge.Maryland2 1613 Tel: 410-228-1818 E-Mail: dema("*docogonet.com Fax: 410-228-1216 Decebter 17,2010 Mr. Michael Fick Director, Emergency Planning Calvert Cliffs Nuclear Power Plant 1650 Calvert Cliffs Parkway Lusby, Maryland 20657-4702 RE: Proposed Calvert Cliffs Emergency Action Levels

Dear Mr. Fick:

The Dorchester County Emergency Management Agency understands and agrees with the proposed revisions to the Emergency Action Levels and Technical Basis Document, Revision 0, for the Calvert Cliffs Nuclear Power Plant. We appreciate the opportunity to participate and comment on the proposed revision. Sincerely,

                                                                        ~>

Wayne Rif6inson, Director Dorchester County Emergency Management Agency

T Co CALVERT COUNTY 14 DEPARTMENT OF PUBLIC SAFETY EMERGENCY MANAGEMENT AND SAFETY DIVISION 175 Main Street Boardof Commissioners Prince Frederick, Maryland 20678 Gerald W. Clark 410-535-1600

• 301-855-1243
• Ext. 2301 Pat Nutter Fax: 410-535-3997 Susan Shaw Jacqueline K. Vaughan, Director Evan K. Slaughenhoupt Jr.

J.R. Fenwick, Division Chief Steven R. Weems December 10, 2010 Mr. Michael Fick Director, Emergency Planning Calvert Cliffs Nuclear Power Plant 1650 Calvert Cliffs Parkway Lusby, Maryland 20657-4702 RE: Proposed Calvert Cliffs Emergency Action Levels

Dear Mr. Fick:

The Calvert County Emergency Management Agency understands and agrees with the proposed revisions to the Emergency Action Levels and Technical Basis Document, Revision 0, for the Calvert Cliffs Nuclear Power Plant. We appreciate the opportunity to participate and comment on the proposed revision. Sincerel*n [Jo* Robert Fenwick, -Director (C lvert County Emergency anagement Agency Maryland Relay for Impaired Hearing or Speech: 1-800-735-2258

ATTACHMENT (5) EAL SUPPORTING DOCUMENTATION (CD) I 'N Calvert Cliffs Nuclear Power Plant, LLC February 1, 2011

0 Constellation Energy, Constellation Nuclear Generation Station Administrative Procedure CNG-OP-1.01 -2003 ALARM RESPONSE AND CONTROL Revision 00100 This Procedure is Applicable for 10 CFR 50.59 / 10 CFR 72.48 Reviews Tech Spec Related INFORMATION USE Applicable To: 0 Calvert Cliffs Nuclear Power Plant, Unit I and 2 D] Nine Mile Point Nuclear Station, Units 1 and 2 F] R.E. Ginna Nuclear Power Plant El Corporate Offices of CNG Sponsor: Manager - Operations (CCNPP) Approval Authority: Manager - Operations (CCNPP)

ALARM RESPONSE AND CONTROL CNG-OP-1.01-2003 Revision 00100 Page 2 of 17

SUMMARY

OF ALTERATIONS Revision Change Summary of Revision or Change 001 00 Converted procedure to the CNG-PR-1.01-1002, Control of Administrative Procedure Format and Content Immediate Change - Final Approval Coversheet & Section 1.2.C - Removed R.E. Ginna Nuclear Power Plant and Nine Mile Point Nuclear Station. This procedure revision is applicable ONLY to Calvert Cliffs Nuclear Power Plant. Section 5.3, Added

• Local panel tests (except Emergency Diesel Generators) should be staggered throughout the week. However, each local panel shall be tested at least once per week (normally tested on the night shift).

                   " Emergency Diesel Generator remote panels shall be tested daily.

PCR 2008-0219 - to reduce operator burdens and distractions from excessive alarm annunciator checks.

ALARM RESPONSE AND CONTROL CNG-OP-1.01-2003 Revision 00100 Page 3 of 17 TABLE OF CONTENTS SECTION TITLE PAGE 1.0 INTRO DUCTIO N........................................................................................................................... 4 1.1 P u rp o s e ........................................................................................................................ 4 1.2 Scope/Applicability .................................................................................................... 4

2.0 REFERENCES

..............................................................................................................................                4 2.1        Developm ental References .....................................................................................                               4 2.2        Perform ance References ........................................................................................                              4 3.0    DEFINITIONS ...............................................................................................................................              5 4.0    RESPO NSIBILITIES .............................................................................................................                          6 5.0    PROCESS .....................................................................................................................................            7 5.1        Response to Alarm s .................................................................................................                         7 5.2        Annunciator and Recorder Point Control and Flagging ...........................................                                               9.

5.3 Annunciator Test .................................................................................................... 13 6 .0 BAS ES ........................................................................................................................................ 14 7.0 RECO RDS .................................................................................................................................. 14 Attachm ent 1, Alarm Annunciator/Recorder Point O ut of Service Log .............................................. 15 Attachm ent 2, Panel Test Log ................................................................................................................. 16

ALARM RESPONSE AND CONTROL CNG-OP-1.01 -2003 Revision 00100 Page 4 of 17

1.0 INTRODUCTION

1.1 Purpose A. The purpose of this procedure is to ensure that Constellation Nuclear Generation (CNG) Alarm Response and Control Activities are conducted in a consistent professional manner that contributes to safe and reliable station operation. 1.2 Scope/Applicability A. This procedure establishes the organizational and individual responsibilities of the Operations Department and provides administrative instructions necessary for the daily conduct of operator response to alarms and alarm control. B. This procedure applies to all licensed and non-licensed operators and all personnel supporting (directly or indirectly) the Operations Department. C. This procedure applies to: Calvert Cliffs Nuclear Power Plant (CCNPP)

2.0 REFERENCES

2.1 Developmental References A. CNG-HU-1.01-1001, Human Performance Tools and Verification Practices B. 10 CFR 50.54, Conditions of Licenses C. CNG-CA-1.01, Corrective Action Program D. CNG-HU-1.01, Human Performance Program E. Technical Specifications (TS) F. INPO Best Practices Document G. Station Holds/Safety Tagging 2.2 Performance References A. None

ALARM RESPONSE AND CONTROL CNG-OP-1.01-2003 Revision 00100 Page 5 of 17 3.0 DEFINITIONS 3.1 Black Board All annunciator windows extinguished under full power operations. This is the case at Calvert Cliffs and Nine Mile Point Nuclear Stations. Due to the original design, some Ginna Station annunciators are lit. These alarm windows have been fitted with green covers, and appear green when the alarm window is illuminated. 3.2 Black Dot The sticker that is placed on an annunciator window or flag to indicate the following: A. A maintenance activity in the station that causes an alarm on a repeated basis. B. For identification of a locked in alarm that is caused by a current station configuration due to maintenance in the field. C. For placement on alarm windows of nuisance alarms with the approval of the Control Room Supervisor (CRS). 3.3 Blue Dot The sticker placed on an annunciator window to indicate that it is locked-in or annunciator alarm (nuisance) that was taken out of service. 3.4 Compensatory Actions Actions that are implemented to compensate for an annunciator or recorder point that is non-functional or has one or more non-functional inputs. 3.5 Expected Alarm An alarm that occurs in the normal course of equipment operation or testing shall be considered expected if the alarm is discussed with the CRS before receipt. Some examples are: A. Testing of components or equipment calibration. B. Starting or securing equipment. C. Alarm as identified in a procedure. D. Nuisance alarms. E. Alarms discussed during a pre-evolution brief or prior notification received.

ALARM RESPONSE AND CONTROL CNG-OP-1.01-2003 Revision 00100 Page 6 of 17 3.6 Nuisance Alarm Alarms may be considered a nuisance ifthe alarm is:

• Not valid for existing station, system, or equipment conditions
• A result of a loop, circuit, or equipment failure
• Although valid, repeated actuation of an alarm that distracts operators 3.7 Out of Service (OOS)

An annunciator or recorder point is considered out of service when the alarm circuitry has been disabled or has all inputs removed. 3.8 Priority 1 Alarm A process computer designator at Ginna Station for computer alarms labeled with priority importance. 3.9 Red Dot The sticker placed on an annunciator window to indicate that it is part of a Tag Out (according to Site Specific Safety Tagging Procedure). 3.10 Unexpected Alarm Any alarm that does not meet the criteria of an expected alarm. 3.11 Yellow Dot The sticker placed on an annunciator window to indicate that one or more inputs to a multiple input annunciator are out of service. 4.0 RESPONSIBILITIES 4.1 The following individuals have been assigned responsibilities within this procedure: A. Shift Manager (SM) B. Control Room Supervisor (CRS) C. Reactor Operator (RPO) D. Plant Operator/Auxiliary Operator (PO/AO) E. Shift Technical Advisor (STA)

ALARM RESPONSE AND CONTROL CNG-OP-1.01-2003 Revision 00100 Page 7 of 17 5.0 PROCESS 5.1 Response to Alarms A. Operators shall respond promptly to alarm conditions to avoid unwanted or emergency situations, or to mitigate the consequences of an incident or transient. I1. Response to an unexpected alarm - if a Control Room annunciator actuates unexpectedly, then the responding operator performs the following:

a. Identify the alarm by scanning the annunciator panels.

b. RPO reports the alarm window to the CRS (or person with Command and Control), paraphrase is acceptable.

c. Perform Alarm Response actions. Review the associated alarm response even if the alarm clears before the procedure can be completed.

d. When an alarm annunciated more than once during a shift, it is not required that the alarm response procedure be referenced more than once.

2. Response to expected alarms - when a Control Room annunciator actuates, then the responding operator performs the following:

a. Identify the alarm by scanning the annunciator panel.

b. RPO reports the alarm window to the CRS (or person with Command and Control), paraphrase is acceptable.

c. Referencing the alarm response procedure is not required.

3. Response to Nuisance Alarms 0 if a Control Room annunciator actuates frequently due to station conditions/equipment deficiencies, then the responding person performs the following:

a. The CRS classifies the alarm as a nuisance alarm.

b. Ensure appropriate flagging device (black) is installed on annunciator window.

c. Ifthe alarm repeats, then additional alarm description report to the CRS and reference to the alarm response procedure are not required.

d. Ensure efforts have been initiated to correct the condition causing the frequent alarm.

ALARM RESPONSE AND CONTROL CNG-OP-1.01-2003 Revision 00,100 Page 8 of 17

4. Response to Plant Process Computer Systems (PPCS) Alarms (Ginna Station)

a. An Operator or Shift Technical Advisor (STA) reports the PPCS alarm to the CRS (person identified with command and control).

b. State if the alarm is designated Priority 1.

c. If the alarm is anticipated as a result of station operating conditions, then the alarm should be called out as expected.

d. If the alarm is unexpected, the appropriate alarm response procedure (ARP) shall be referenced and the required actions taken. (This may be done by any member of the Control Room staff.)

e. Inform the CRS or SM of what actions are being taken.

f. Submit a Condition Report, if required.

5. Response to Multiple Alarms Due to Operational Transients or Emergencies -

These alarms may be the result of a station transient, electrical bus malfunction, equipment failure, and so forth. The following steps outline the expected actions:

a. RPOs announce that multiple alarms have received, stating the cause if it has been diagnosed.

b. The CRS directs or ensures the RPOs monitor the stations. Typical parameters to monitor are listed below:

PWR - Reactor power, RCS temperature, primary pressure, Net Megawatts. BWR - Reactor power, Reactor pressure, Reactor level.

c. The CRS (or person with Command and Control) directs or ensures the correct procedure is implemented to address the transient, based on their diagnosis of Main Control Board (MCB) alarms, and station monitoring results.

d. RPOs are expected to take manual actions for automatic actions that did not occur as a result of the malfunction, or are occurring that should not (that is, unexpected control rod movement).

e. RPOs take manual actions for auto actions that did not occur as a result of the malfunction, or are occurring and should not be (that is, control rod movement).

f. RPOs periodically evaluate alarm panels to verify active alarms are consistent with station conditions, and implement alarm response procedures for those that are not consistent, as time permits. Results of these evaluations should be included in shift briefings.

ALARM RESPONSE AND CONTROL CNG-OP-1.01-2003 Revision 00100 Page 9 of 17

g. Reactor operators take manual actions for auto actions

6. Guidance for Official Record entries

a. Unexpected Control Board and/or Priority 1 PPCS (Ginna) alarms received requiring operator action shall be entered in the Station Log except as follows:

• Common alarms from alarm panels located outside the Control Room do not need to be logged.
• Alarms recorded in other procedures do not need to be logged.

b. If multiple alarms occur, only the most significant alarm(s) should be logged. The alarm and follow up actions are to be logged AFTER the operating crew responds to the alarm.

5.2 Annunciator and Recorder Point Control and Flagging A. The CRS shall determine whether an annunciator or recorder point(s) requires controls due to:

• Maintenance Order (MO)/Work Order (WO)
• Nuisance alarm
• Circuit failure 0 Alarm in solid for extended time and NOT providing useful information regarding system status 0 Removal of inputs (alarms which receive multiple inputs)
• Safety Tagging
• Condition Report B. Determine required compensatory actions [FB0173] [FBO109]

1. When an annunciator or recorder point is out of service, compensatory actions should be considered if any of the following conditions apply:

• The annunciator/recorder point is required to monitor component/system availability or operability.
• The annunciator/recorder point monitors the performance or condition of operating equipment or equipment that is available for operation.

ALARM RESPONSE AND CONTROL CNG-OP-1.01-2003 Revision 00100 Page 10 of 17 5.2.B.1 (Continued) The annunciator/recorder point is utilized in the Abnormal or Emergency Operating Procedures (AOPs/EOP's/SOP's) for verification or action initiation. No other annunciator/recorder point or computer alarm point is available to monitor the affected parameter. The annunciator has multiple inputs and is locked-in.

2. When compensatory actions are established, consideration should be given to the following:

• An alternate means for monitoring the affected parameter.
• Frequency for monitoring the parameter and identification of parameter limits.

Potential for the affected parameter to change and adverse effects on system/plant operation. Temporary log changes to implement the compensatory actions, if required. Actions that may be required during the implementation of an AOP or EOP with the Annunciator/recorder point out of service.

3. If required, implement compensatory actions as follows:

a. Incorporate the compensatory actions in the appropriate operator logs with a temporary log change, if applicable.

b. If the compensatory actions are required through shift turnover, indicate that those actions are in effect in the appropriate section of the Shift Turnover Information Sheet.

4. Authorize placing the annunciator/recorder point out of service by documenting compensatory actions and initialing the appropriate block on Attachment 1, Alarm Annunciator/Recorder Point Out of Service Log. If compensatory actions are not required, then document the justification for not implementing those actions on Attachment 1.

C. Place the annunciator/recorder point out of service as follows, if required:

1. Defeat the annunciator/recorder point using the appropriate station process.

Examples include:

• Removing the alarm card
• Remove fuses

ALARM RESPONSE AND CONTROL CNG-OP-1.01-2003 Revision 00100 Page 11 of 17 5.2.C.1 (Continued) 0 Open Annunciator slide link

• Lifted lead
• DIP (dual in-line package) switch 0 Open knife switch
• Pulling Alarm Relay

2. Ensure Attachment 1 is completed up to, not including verification.

NOTE Yellow dots are not required if an input is removed from any common/repeater panels. NOTE CRS discretion can be used to determine if a black dot is required (lower mode, frequency of alarms, and so forth). D. Place appropriate flagging tool on the Annunciator window:

1. Flagging Tool

• Black - Maintenance or nuisance 0 Blue - Locked in or removed from service
• Yellow - One or more inputs removed from service
• Red - Out of service due to safety tagging

2. Inform the CRS when the flagging tool has been installed.

E. The Independent Verifier shall: [FB01 72]

1. Verify annunciator window has appropriate flagging tool.

2. If the annunciator has been removed from service, then verify the annunciator is OOS by performing or observing an annunciator test.

3. If a recorder point was removed from service, then verify the proper switch was utilized to disable the point.

ALARM RESPONSE AND CONTROL CNG-OP-1.01-2003 Revision 00100 Page 12 of 17 5.2.E. (Continued)

4. Initial and date as the verifier on Attachment 1.

F. Notify the SM within the same shift of the annunciator status/flagging. G. Annunciator/recorder points are returned to service as follows:

1. The CRS shall direct the operator to restore the annunciator/recorder point.

2. The Operator shall:

a. If an alarm card was removed, then verify that the alarm card switch or jumper is in its normally open or normally closed position.

(1) A Concurrent Verifier shall be present to verify switch/jumper position.

b. Restore the annunciator/recorder point using the appropriate station process. Examples include:

• Install alarm card
• Install fuses
• Land lead
• Close slide link
• Reset recorder DIP switch
• Close knife switch
• Reinstalling Alarm Relay

c. Observe panel to be tested and note current status of all panel annunciators.

d. Test panel annunciators.

e. Confirm panel annunciators respond as designed.

f. Remove the flagging tool.

g. Complete Attachment 1 documentation.

h. Notify the CRS that the annunciator is restored.

ALARM RESPONSE AND CONTROL CNG-OP-1.01-2003 Revision 00100 Page 13 of 17 5.2.G. (Continued)

3. Independent Verifier shall: [FB01 72]

a. Verify annunciator window flagging tool removed.

b. If the annunciator has been returned to service, then verify the annunciator is restored by performing or observing an annunciator test.

c. If a recorder point was returned to service, then verify the proper switch was utilized to restore the point.

d. Initial and date as the verifier on Attachment 1.

e. Notify the CRS that the annunciator has been verified.

4. The CRS shall remove applicable compensatory actions by:

a. Recording the restoration in the appropriate operator log(s).

b. Deleting the applicable entries from the Shift Turnover Information Sheet.

5.3 Annunciator Test A. Annunciators will be tested at the following frequency:

• MCB panels - 1/shift
• Local panel tests (except Emergency Diesel Generators) should be staggered throughout the week. However, each local panel shall be tested at least once per week (normally tested on the night shift).
• Emergency Diesel Generator remote panels shall be tested daily.

B. Operators shall inform the CRS or RPO before testing panels outside the Control Room. These alarms will be treated as expected alarms. C. Operators shall observe panel to be tested and note current status of all panel annunciators prior to testing the panel. D. During the panel test, operators should confirm panel annunciators respond as designed. E. A condition report shall be submitted for any discrepancies noted during the annunciator tests. F. Operators shall inform the Control Room of the completion of local panel tests. G. Document completion of test on a station specific attachment or similar form per example on Attachment 2, Panel Test Log.

ALARM RESPONSE AND CONTROL CNG-OP-1.01 -2003 Revision 00100 Page 14 of 17 H. Replace burned out bulbs with approved replacement.

1. Operators shall inform Control Room upon completion of testing in-plant alarms.

6.0 BASES [FBO109] SOER 94-02, Boration, Dilution Events in Pressurized Water Reactors; Recommendation 4b. [FB0t 72] INPO 85-016/85-031, Section 7/96-008, Chapter 8, Temp Mod control (Installations of Temp Mods be verified independently). [FBO173] SOER 02-3, Large Power Transformer Reliability, Rec. 3.b.4, appropriate compensatory monitoring practices when alarms are OOS or sealed in for other reasons. 7.0 RECORDS 7.1 The following records are generated by use of this procedure and are controlled by CNG-PR-3.01-1000, Records Management: A. Alarm Annunciator/Recorder Point OOS Log Sheets, Attachment 1 B. Annunciator Panel Test Log Sheets, Attachment 2

ALARM RESPONSE AND CONTROL CNG-OP-1.01-2003 Revision 00100 Page 15 of 17 Page 1 of 1 Attachment 1, Alarm Annunciator/Recorder Point Out of Service Log Date Window Window Name or Reason for Placing Compensatory Actions CRS Auth. Alarm Card Ann. Ann. Ann. Ann. No. or Rcdr. Point Annunciator Out of Service or Reason No Comp (Initials/Date) Switch/Jum Input/Rcdr. Input/Rcdr. Pt. InputlRcdr. Input/Rcdr. Rcdr. No. or Bypassing Rcdr. Point Actions are Required per Position Pt. OOS Verified OOS Pt. Returned Pt. Verified NO/NC/NA (Date/Initials) (Date/Initials) to Service Returned to [FBO172] Service [FBO1721 Notes:

1. Ensure Shift Manager is notified and concurs within the same shift.

2. This log shall be maintained in the Control Room.

3. Forward completed log sheet to GS-Operations.

4. Ginna only Category #3.3.45.

ALARM RESPONSE AND CONTROL CNG-OP-11.01-2003 Revision 00100 Page 16 of 17 Page 1 of 2 Attachment 2, Panel Test Log Date Shift 1 2 1 2 1 2 1 2 1 2 1 2 1 2 MAIN CONTROL BOARD (RIGHT) MAIN CONTROL BOARD (MIDDLE) MAIN CONTROL BOARD (LEFT) FIRE DETECTION PANELS METAL IMPACT MONITOR TURBINE PLANT SAMPLE RACK

• STEAM HEADER SUPPORTS PANEL
• MAIN TRANSFORMER 11
• STATION AUX TRANSFORMER 12A
• STATION AUX TRANSFORMER 12B
• STATION AUX XFMR 12A REMOTE
• STATION AUX XFMR 12B REMOTE
• DIESEL GEN A ELCP
• DIESEL GEN A CONTROL PANEL
• ALARM RESPONSE AND CONTROL CNG-OP-1.01-2003 Revision 00100' Page 17 of 17 Page 2 of 2 Attachment 2, Panel Test Log (Continued)

Date Shift 1 2 1 2 1 2 1 2 1 2 1 2 1 2 DIESEL GEN B CONTROL PANEL

• AVT CONDST DI CONTROL PANEL
• HYDROGEN PANEL
• PRIMARY WATER TREATMENT PANEL
• PENETRATION TEMP ALARM PANEL
• WASTE PANEL
• BORIC ACID PANEL
• VOLTAGE REGULATOR ALARM PANEL
• RWST HIGH LEVEL INDICATION LAMP
• GENERATOR STATOR WINDING TEMP PANEL
• SECURITY DIESEL GENERATOR ALARM PANEL
• ANNUNCIATOR PANEL TEST LOG SHEET N/A if not in service
• Test once per day normally on night shift, other shifts may be marked N/A.

Ginna only Category #3.3.25.

Constellation Energy-Calvert Cliffs Nuclear Power Plant Station Administrative Procedure NO-1 -113 CONTROL OF RADIO TRANSMITTERS Revision 00500 Tech Spec Related INFORMATION USE Applicable To: Z Calvert Cliffs Nuclear Power Plant, Unit I and 2 [] Nine Mile Point Nuclear Station, Units I and 2 L] R.E. Ginna Nuclear Power Plant nI Corporate Offices of CNG Sponsor: General Supervisor-System Engineering (CCNPP) Approval Authority: General Supervisor - Shift Operations (CCNPP)

CONTROL OF RADIO TRANSMITTERS NO-1-113 Revision 00500 Page 2 of 15

SUMMARY

OF ALTERATIONS Revision Change Summary of Revision or Change 005 00 Section 1.1 - Deleted information pertaining to Trip Sensitive items. Section 1.2.A - Deleted information pertaining to Trip Sensitive items. Section 5.6 - Management Expectations for Plant Personnel Entering Trip-Sensitive Areas has been deleted due to the implementation of CNG-OP-1.01-1000 Rev. 00200. RPA 2008-0849 Changed the title of the procedure to delete the Trip Sensitive Area part. Deleted definitions associated with Trip Sensitive Areas and Equipment.

CONTROL OF RADIO TRANSMITTERS NO-1 -113 Revision 00500 Page 3 of 15 TABLE OF CONTENTS SECTION TITLE PAGE

1.0 INTRODUCTION

........................................................................................................................                     4 1.1          Purpose [80136] ...................................................................................................                          4 1.2          Scope/Applicability .................................................................................................                        4

2.0 REFERENCES

...........................................................................................................................                    4 2.1          Developmental References ...................................................................................                                 4 2.2          Performance References .......................................................................................                               4 3 .0   DEF INITIONS .............................................................................................................................                5 4.0    RESPONSIBILITIES ...................................................................................................................                      6 5 .0   P R O C E S S ..................................................................................................................................          9 5.1          General Restrictions on Radio Transmitters ..........................................................                                        9 5.2          Use of Portable Radio Transmitters ......................................................................                                   10 5.3          Authorization of New Portable Radio Transm itters ...............................................                                           11 5.4          Changes of Limitations/Restrictions of Authorized PRTs ......................................                                               12 5.5          Assessment of a New Component's Susceptibility to RFI ......................................                                                12 6 .0   BAS E S .....................................................................................................................................            13 7 .0   R EC O R D S ...............................................................................................................................             13 , REQUEST FOR NEW PORTABLE RADIO TRANSMITTERS ...................................                                                                   14 , PORTABLE RADIO TRANSMITTER ASSESSMENT ................................................                                                            15

CONTROL OF RADIO TRANSMITTERS NO-1-113 Revision 00500 Page 4 of 15

1.0 INTRODUCTION

1.1 Purpose [B10136] A. This procedure establishes the requirements and Management's expectations for use of Radio Transmitters (RTs) at Calvert Cliffs. Radio frequency interference (RFI) from RTs can cause induced voltage/current signals in electronic circuitry. Depending on the function of the electronic circuitry, an unexpected plant transient may occur. Restrictions on the type and use of RTs are necessary to prevent plant transients that challenge plant operators and safety systems. 1.2 Scope/Applicability A. This procedure applies to all users of Radio Transmitters. B. The established controls are applicable during all operating modes. This procedure also serves as the technical procedure for portable voice radios and cell phones, unless noted otherwise.

2.0 REFERENCES

2.1 Developmental References A. INPO SER 90-6, Plant Transients and Engineered Safety Feature Actuations Caused by Radio Frequency Interference B. Federal Communications Commission licenses and regulations C. Letter, G: PES911111-302; November 11, 1991; closure of POSRC 01 91-081-03 D. CNG-PR-1.01-1011, Control of Station-Specific Procedure Change Process E. NO-1-100, Conduct of Operations Shift Activities 2.2 Performance References A. EN-1-100, Engineering Service Process Overview B. CNG-OP-1.01-1005, Temporary Notes, Operator Aids, and Permanent Labels C. CNG-PR-1.01, Procedures Program D. CNG-PR-1.01-1011, Control of Station-Specific Procedure Change Process E. CNG-PR-3.01-1000, Records Management

CONTROL OF RADIO TRANSMITTERS NO-1-113 Revision 00500 Page 5 of 15 3.0 DEFINITIONS 3.1 Engineered Safety Features (ESF) Trip Sensitive Areas Areas affected by RFI, as defined in NO-1-1 13 that could actuate Engineered Safety Features Actuation System (ESFAS) components. 3.2 Portable Radio Transmitter (PRT) A head-set or hand-held device which transmits radio frequency signals. There are two basic types of PRTs used at Calvert Cliffs.

1. Portable Voice Radios

a. Hand-held radios which are used for 2-way voice communications throughout the plant and surrounding properties (for example: Security, Operations and Emergency Planning Unit). They operate at no more than 6 watts effective radiated power on frequencies licensed to CEG by the FCC. They may utilize radio repeaters connected to an antenna system which consists of a combination of in-plant radiax antenna and outdoor antenna system.

b. Head-set radios which are used for 2-way voice communications in hands free applications. They may not be licensed and typically operate at no more than 100 milliwatts effective radiated power. They are strictly for portable-to-portable use; no base stations or repeaters can be used. An example of this application is the ALARA radio headsets.

2. Special Purpose Radio Controllers

a. These devices are used to remotely control equipment (for example:

polar cranes). They may operate on licensed or unlicensed frequencies and the power may vary with the application.

b. The radio controllers are transmitting devices only and their area of coverage is very limited. Care must be taken when specifying frequencies to ensure that there is no co-channel interference with other radio controlled equipment.

c. Wireless data transmission devices that are used to transmit and receive data in conjunction with the LAN or WAN. They operate at no more than 500 milliwatts effective radiated power. They may utilize repeaters for increased plant coverage.

d. Cordless telephones, including a head set or hand set radios, which are used for 2-way voice communications. Communications between hand set and base where the base is connected to the plant telephone system.

e. Cellular telephones used for 2-way voice communications. No license required.

CONTROL OF RADIO TRANSMITTERS NO-1 -113 Revision 00500 Page 6 of 15 3.3 Portable Radio Transmitter User An authorized user/owner who is responsible for the conduct and operation of the Portable Radio Transmitter(s), while in their possession, per this procedure. 3.4 Radio Frequency Interference (RFI) RFI is any radio frequency energy that is generated by a device which may cause adverse effects on the operation of another device. The generating device may be an incidental radiator (d.c. motors, power lines, light switches) or an intentional radiator (radios, remote controls, cellular phones, radar). 3.5 Radio Frequency Interference (RFI) Trip Sensitive Equipment RFI Trip Sensitive Equipment is equipment that may actuate under the influence of RFI. 3.6 Radio Transmitter (RT) Any device which is designed to transmit radio frequency signals. 4.0 RESPONSIBILITIES 4.1 General Supervisor - Plant Engineering Section (GS-PES) A. The GS-PES responsibilities include ownership of the program which controls Radio Transmitters at Calvert Cliffs. 4.2 Engineer Supervisor - Electrical & Control Systems Engineering Unit (ES-E&C SEU) A. The ES-E&C responsibilities include:

1. Administration of the program which controls use of Radio Transmitters.

2. Appointing the Site Coordinator for Radio Transmitters.

4.3 All General Supervisors A. All General Supervisors responsibilities include ensuring:

1. Radio Transmitters owned by their section (CEG and contractors) are authorized by the Site Coordinator.

2. Each Radio Transmitter is authorized by the CGG Field Services.

3. All personnel (CEG and contractors) who are issued RTs are familiar with this procedure.

4. Development of implementing procedures/policies for Special Purpose Radio Controllers used by their section.

CONTROL OF RADIO TRANSMITTERS NO-1-113 Revision 00500 Page 7 of 15 4.3.A (Continued)

5. All PRTs brought inside the protected area should be used for company business purposes only.

4.4 Site Coordinator for Radio Transmitters A. The Site Coordinator responsibilities include the following:

1. Maintaining a record of all authorized PRTs with the information found on Attachment 2, Portable Radio Transmitter Assessment.

2. Coordinating the assessment of requests for new PRTs including the definition of restriction for use.

3. Authorizing the use of new PRTs following FCC Licensing and development of an implementing procedure by the user.

4. Providing cross-disciplinary review of implementing procedures/policies for Special Purpose Radio Controllers.

5. Forwarding copies of PRT Assessment Forms to the E&C Design Unit.

4.5 Engineer Supervisor & Controls Design (ES-E&C Design) A. The ES-E&C Design responsibilities include supporting the Site Coordinator in:

1. Identifying those field installed components which could be affected by RFI from PRTs.

2. Assessing the potential affects of RFI on components from PRTs.

4.6 Supervisor-CGG Field Services A. The Supervisor -CGG Field Services responsibilities include:

1. Authorizing the procurement of new PRTs and determining what FCC requirements must be met.

2. Supporting those groups requesting new PRTs in determining an acceptable manufacturer and model, and obtaining FCC Licenses.

3. Assisting in the development of implementing procedures/policies for Special Purpose Radio Controllers.

CONTROL OF RADIO TRANSMITTERS NO-1 -113 Revision 00500 Page 8 of 15 4.7 General Supervisor - Shift Operations (GS-SO) A. The GS-SO responsibilities include:

1. Providing support to the Site Coordinator in identifying those components which could be affected by RFI from PRTs.

2. Ensuring those areas which have been identified as being susceptible to RFI are clearly posted, according to CNG-OP-1.01-1005, Temporary Notes, Operator Aids, and Permanent Labels.

CONTROL OF RADIO TRANSMITTERS NO-1-113 Revision 00500 Page 9 of 15 5.0 PROCESS 5.1 General Restrictions on Radio Transmitters A. Radio Transmitters mounted on vehicles (for example: radios, cellular phones, CBs, radar) shall be turned off prior to the vehicle entering the protected area except for:

1. Site fire truck and site security vehicles which may transmit within the protected area, but must be outdoors (typically near the tank farm).

2. Radio transmitters mounted on off-site emergency vehicles (fire trucks, ambulance, police).

B. Areas identified as being susceptible to RFI have restrictions on use of PRTs. Rooms which are susceptible to RFI shall be posted according to CNG-OP-1.01-1005, Temporary Notes, Operator Aids, and Permanent Labels.

1. Personnel carrying PRTs shall ensure that it is turned off prior to entering the following areas, unless the PRT is specifically authorized for use in the area:

a. Control Room.

b. 500KV Switchyard Control House.

c. Cable Spreading Rooms.

d. 45' and 72' Computer Rooms

2. Personnel carrying RTs shall not transmit or receive messages within 10 feet of (unless testing has been performed to establish a less restrictive boundary)

a. Remote shutdown panels in each Unit's 45' Switchgear Room.

b. 5' and 27' Auxiliary Building West Penetration Room and 27' Letdown Heat Exchanger Room pressure transmitters.

c. Containment pressure transmitters located in the 45' Auxiliary Building East and West Penetration Rooms.

d. Designated locations in the U-1 North and U-2 South, 69' SFP areas.

e. U-2 SG Feed Pumps.

f. Any electronic control cabinet or process measurement transmitter.

CONTROL OF RADIO TRANSMITTERS NO-1-113 Revision 00500 Paae 10 of 15 5.1 (Continued) C. Use of PRTs in Containment shall be limited as follows, unless specifically authorized by the Site Coordinator:

1. Approval to have a PRT inside containment shall be obtained from the Shift Manager and only if the Reactor Trip Circuit Breakers are open.

2. Any PRT used within containment shall be turned off while transporting it to ahd from its area of use. [B0136] [B0568]

3. On the 45' level of Containment, PRT usage shall be limited to the immediate vicinity (within 5 feet) of the Equipment Hatch or Emergency Hatch. [B0568]

D. Use of cellular phones shall be limited as follows, unless specifically authorized by the Site Coordinator:

1. Cell phones may be used in office areas and outside areas where trip sensitive equipment does not exist.

a. Trip Sensitive Equipment is identified with trip sensitive labels or floor marking per CNG-OP-1.01-1000, Conduct of Operations.

2. Cell phones specifically shall not be used in the Turbine Building, Aux. Building, Control Room or Containment and must be turned off when in these areas.

5.2 Use of Portable Radio Transmitters A. Only authorized PRTs shall be used within the protected area.

1. A controlled list of authorized PRTs shall be maintained by the Site Coordinator (except for cellular phones).

2. This list shall include:

• Manufacturer
• Model Number 0 Assigned Calvert Cliffs Number
• Frequency(ies) 0 Power
• Owner
• Any Imposed restrictions, and the implementing procedure

CONTROL OF RADIO TRANSMITTERS NO-1-113 Revision 00500 Page 11 of 15 5.2.A (Continued)

3. Cellular phones may be used inside the protected area without approval per NO-1-113, General Restrictions on Radio Transmitters, Section 5.1, shall be followed when using cell phones.

B. If a new PRT is needed within the protected area, the Site Coordinator's authorization shall be obtained as described in 5.3. C. The General Supervisor of the section using authorized PRTs, shall ensure a procedure/policy which describes the limitations or requirements for using the PRT is implemented, if required by Site Coordinator.

1. For Special Purpose Controllers the procedure shall be prepared according to CNG-PR-1.01-1011, Control of Station-Specific Procedure Change Process.

D. In addition to the general restrictions on PRTs described in 5.1, the following requirements shall also apply to Portable Voice Radio usage:

1. Radio communications should be brief. When possible, use the phone system.

2. Sender and receiver identification shall be included in each message.

3. When taking PRTs inside contaminated areas, the potential for inadvertent transmissions exists due to protective clothing and anti-contamination controls.

To prevent inadvertent transmissions, radios should be turned off when not needed, or carried by holding the bag in lieu of gripping the radio within the bag. [B0568] 5.3 Authorization of New Portable Radio Transmitters NOTE New Portable Radio Transmitters (for example: portable voice radios and special purpose radio controllers) must be approved prior to use within the protected area. Specific approval is necessary to ensure the assumptions made in establishing the general restrictions for RTs (Section 5.1) remain valid. Portable Radio Transmitters with power levels or frequencies which are different then previously assessed could affect equipment/components in areas which were previously identified as not being susceptible to RFI. A. Organizations requesting permission to use a new PRT shall complete and forward Attachment 1, Request for New Portable Radio Transmitters to the Site Coordinator. B. The Site Coordinator shall complete shall complete Attachment 2, Portable Radio Transmitter Assessment, to identify any equipment/components which could potentially be affected by the new PRT.

1. Identification should include a review of prints and walkdowns of the areas where the PRT will be used.

CONTROL OF RADIO TRANSMITTERS NO-1 -113 Revision 00500 Page 12 of 15 5.3.8 (Continued)

2. Operations, E&C Design and CGG Field Services shall provide support to the Site Coordinator, as requested.

3. On approval for use, the Site Coordinator shall forward a copy of Attachment 2 to the requesting organization.

C. The requesting organization shall develop a technical procedure, if required by the site coordinator, for new Special Purpose Radio Transmitters according to CNG-PR-1.01-101 1.

1. Specific restrictions recommended by the Site Coordinator on Attachment 2 shall be used.

2. The Site Coordinator shall provide cross-disciplinary review according to CNG-PR-1.01, Procedures Program.

D. Following procedure approval, a copy of the procedure shall be submitted to the Site Coordinator. E. The Site Coordinator shall update the controlled list of authorized PRTs. 5.4 Changes of LimitationslRestrictions of Authorized PRTs A. All changes to the restrictions contained within this procedure or a Special Purpose Radio Controller's technical procedure shall be reviewed by the Site Coordinator.

1. The assessment of new restrictions shall be documented on Attachment 2.

2. Posted area signs shall be changed according to CNG-OP-1.01-1005, if required.

5.5 Assessment of a New Component's Susceptibility to RFI A. Each new component shall be assessed for susceptibility to RFI according to EN-1-100, Engineering Service Process Overview.

1. The Site Coordinator's controlled list of PRTs and the location of the component shall be used to determine whether additional restrictions are required for existing PRTs.

B. If additional restrictions are required for PRTs, changes to this procedure shall be initiated according to CNG-PR-1.01-1011.

1. Changes to technical procedure(s) for Special Purpose Radio Transmitters shall be initiated according to CNG-PR-1.01-1011.

CONTROL OF RADIO TRANSMITTERS NO-1 -113 Revision 00500 Page 13 of 15 6.0 BASES [B30136] LER 50-318/91-03 and NCR# 12095 - Development of a Site Procedure for Control of RTs. RTs are not allowed inside containment without the Shift Manager's permission. RTs are not allowed in containment. IV Corrective Actions; Actions to Prevent Recurrence; 2. [B0568] 50.59 Evaluation No. 93-B-999-004-ROO. 7.0 RECORDS A. The following records are generated by the use of this procedure and shall be captured and controlled according to CNG-PR-3.01-1000, Records Management.

1. Completed Attachment 2 for each PRT shall be maintained until use of the PRT is discontinued and it is removed from the protected area.

CONTROL OF RADIO TRANSMITTERS NO-1-A113 Revision 00500 Paqe 14 of 15 Page 1 of 1 Attachment 1, REQUEST FOR NEW PORTABLE RADIO TRANSMITTERS DESCRIBE THE USE/APPLICATION OF THE PORTABLE RADIO TRANSMITTER: (If a specific radio is required, include all known information for example: manufacturer, model, power, frequency) PLANT AREAS WHERE THE PORTABLE RADIO TRANSMITTER WILL BE USED: Owner of PRT (Section/General Supervisor):_ User(s) of the PRT (Sections):_______ Point of contact: Phone Number:

CONTROL OF RADIO TRANSMITTERS NO-1 -113 Revision 00500 Page 15 of 15 Page 1 of 1 Attachment 2, PORTABLE RADIO TRANSMITTER ASSESSMENT MANUFACTUREER MODEL POWER (WATT S) FREQUENCY OWNERS OF PRT (Sections) PURPOSE: LOCATION OF USE: PLANNED USAGE PERIOD: PLANT CONDITIONS: SENSITIVE COMPONENTS AT PRT USAGE LOCATION: SPECIFIC RESTRICTIONS FOR PRT USAGE: BASIS FOR RESTRICTIONS:_______________________ SERVI SUPERVISOR-CGG FIELD SUPERVISOR-CGG FIELD SERVII DATE: CONCURRENCE SITE COORDINATOR APPROVAL DATE: CC#:

Constellation Energy-Constellation Nuclear Generation Station Administrative Procedure NO-1 -114 CONTAINMENT CLOSURE Revision 01700 Tech Spec Related INFORMATION USE Applicable To: 0 Calvert Cliffs Nuclear Power Plant, Unit I and 2 D] Nine Mile Point Nuclear Station, Units 1 and 2 E] R.E. Ginna Nuclear Power Plant III Corporate Offices of CNG Sponsor: General Supervisor-Shift Operations (CCNPP) Approval Authority: Manager-Operations (CCNPP)

CONTAINMENT CLOSURE NO-1 -114 Revision 01700 Page 2 of 39

SUMMARY

OF ALTERATIONS Revision Change Summary of Revision or Change 017 00 Section 5.2 - Steps A.3 - Added "Verify personnel are stationed at the COD once per shift during Refueling or if Shutdown Cooling is not in operation per the requirements of TS 3.9.3." This was added per Supervisory Observation. RPA 2009-0278 Step C. 1 - Added "Verify personnel are stationed at the PAL once per shift during Refueling or if Shutdown Cooling is not in operation per the requirements of TS 3.9.3." This was added per Supervisory Observation. RPA 2009-0278 Changed Maintenance Order to Work Order throughout the procedure. RPA 2008-1300

CONTAINMENT CLOSURE NO-1 -114 Revision 01700 Page 3 of 39 TABLE OF CONTENTS SECTION TITLE PAGE 1.0 INTRO DUCTIO N........................................................................................................................... 4 1 .1 P u rp o s e ........................................................................................................................ 4 1.2 Scope/Applicability .................................................................................................... 4

2.0 REFERENCES

..............................................................................................................................                 4 2.1        Developm ental References .....................................................................................                                4 2.2        Perform ance References ........................................................................................                               4 3.0    DEFINITIO NS ...............................................................................................................................              5 4.0    RESPO NSIBILITIES ..............................................................................................................                          7 5.0    PROCESS .....................................................................................................................................             9 5.1        Discussion ...........................................................................................................                         9 5.2        Containm ent Penetrations .....................................................................................                               10 5.3        Status Tracking:......................................................................................................                        16 5.4        Deviations ...................................................................................................................               22 5.5        Closure Restoration ...............................................................................................                           24 5 .6       D rills ............................................................................................................................         25 5.7        Abnorm al Conditions ..............................................................................................                          25 6 .0   BAS ES ........................................................................................................................................         26 7.0    RECO RDS ..................................................................................................................................             27 , CONTAINMENT CLOSURE DEVIATON SHEET [B10138] [B1222] .............................                                                                 28 , INSTRUCTIONS FOR CONTAINMENT CLOSURE DEVIATION SHEET [B1222] ......... 31 Attachm ent 3, LLRT MATRIX (EXAM PLE) .......................................................................................                                   33 , CONTAINMENT CLOSURE STATUS SHEET FOR LLRTS .......................................                                                                36 Attachm ent 5, STPO-55A PERFORMANCE FLOW CHART ..............................................................                                                   37

CONTAINMENT CLOSURE NO-1 -114 Revision 01700 Page 4 of 39

1.0 INTRODUCTION

1.1 Purpose This procedure provides, in addition to the requirements found in operating procedures and Technical Specifications, administrative controls to be used during lower-mode operations to enhance overall nuclear safety with respect to Containment Closure at Calvert Cliffs Nuclear Power Plant (CCNPP). [B0594] [B0595] [B10138] 1.2 Scope/Applicability A. This procedure embodies management expectations regarding the containment closure aspect of shutdown safety at CCNPP. To accomplish safe and controlled outages, management expects full compliance with all procedures. A questioning attitude, coupled with a strong safety-first ethic adopted by all site personnel, will greatly reduce the potential for fission product release during reactor shutdown conditions at CCNPP. B. This procedure applies to the preparation for, and the tracking and restoration of Containment Closure during Lower Mode Operations at CCNPP. Such preliminary action prior to the onset of core boiling will immediately and effectively reduce the likelihood of a radiological release. C. Containment Closure considerations shall remain in effect whenever irradiation fuel is located in the Reactor Vessel or the surrounding Refueling Pool. [B0594]

2.0 REFERENCES

2.1 Developmental References A. NO-1-103, Conduct of Lower Mode Operations B. OM-1-100, Managing Refueling Outages C. OP-7, Shutdown Operations D. CCNPP Technical Specifications E. INPO 92-005, Guidelines for the Management of Planned Outages at Nuclear Power Stations F. NRC Generic Letter 88-17, Loss of Decay Heat Removal G. NUMARC 91-06, Guidelines for Industry Actions to Assess Shutdown Management 2.2 Performance References A. AOP-3B, Abnormal Shutdown Cooling Conditions B. AOP-4A, Loss of Containment Integrity/Closure C. AOP-6D, Fuel Handling Incident D. DOOR-01, Open and Closing of Containment Outage Door E. EN-4-104, Surveillance Testing F. ERPIP-3.0, Immediate Actions G. NO-1 -103, Conduct of Lower Mode Operations H. CNG-OP-1.01-1007, Clearance and Safety Tagging

CONTAINMENT CLOSURE NO-1 -114 Revision 01700 Page 5 of 39 I. CNG-OP-1.01-2002, Operations Shift Turnover and Relief J. OP-7, Shutdown Operations K. STPO-55A, Containment Closure Verification L. STPO-108 series, Local Leak Rate Test Procedures M. CCNPP Technical Specifications N. BGEDRWGs 83018 (U-I) and 83019 (U-2) Sheets 1, Containment Closure Composite Drawing

0. O1-17D, Miscellaneous Waste Processing System 3.0 DEFINITIONS 3.1 Containment Closure The action or condition that ensures Containment and its associated systems, structures, or components (SSC), as listed in STPO-55A, Containment Closure Verification, provide a functional barrier to fission product release. [B0594]

3.2 Containment Closure Deviation Any penetration not meeting the requirements of STPO-55A, Containment Closure Verification. 3.3 Containment Closure Restoration The reinstatement of functional barriers to radioactive release per STPO-55A, Containment Closure Verification. 3.4 Containment Closure Tracking The monitoring of functional barriers to radioactive release providing the flexibility to have the containment building open under appropriate conditions. 3.5 Containment Penetration Status Tracking Board Board modeled after STPO-55A-1 (2) to demonstrate piping and valves for containment penetrations used for containment closure. 3.6 Defueled The condition when all fuel assemblies have been removed from the reactor vessel and the surrounding refueling pool. 3.7 Lower Mode Operations Modes 5 and 6 as defined in the Tech Specs or the Defueled condition as defined above. 3.8 Lower Mode Operations Containment Pressure [B0482] The maximum pressure the Containment may reach with the following conditions:

1. Loss of core cooling due to a Station Black Out (SBO)

2. Initiation of boiling

3. One day after shutdown 12 PSIG with a one hour time to start DG, align it to a bus, and reestablish Core or Containment Cooling.

CONTAINMENT CLOSURE NO-1 -114 Revision 01700 Page 6 of 39 3.9 Reduced Inventory Condition when the reactor vessel contains irradiated fuel assemblies and RCS water level is at or below the 41 foot elevation. 3.10 Restricted Containment Closure Conditions Those lower mode conditions where higher levels of Containment Closure control are required by this procedure: Movement of irradiated fuel in the containment (T.S. 3.9.3)

• Reduced Inventory (GL 88-17)
• No Shutdown Cooling (SDC) available (T.S. 3.9.4/3.9.5) 3.11 Steam Generator Availability A S/G may be considered available for heat removal when all of the following conditions exist (additional conditions are required for OPERABILITY):
• Secondary side actual water level is above -40 inches
• Secondary side intact (for example: no openings)
• Associated Atmospheric Dump Valve is available to relieve steam
• A Steam Driven Auxiliary Feed Water train aligned to Main Steam is available for makeup
• The RCS is capable of being pressurized
• It is preferred to have the S/G tubes full but not required. With the tubes not full, the Time to Boil (TTB) would be less and equilibrium temperature reached in a long-term Loss of Shutdown Cooling (SDC) is higher.

3.12 Temporary Containment Closure Device Any device used to satisfy containment closure requirements in lieu of STPO-55A, Containment Closure Verification, barriers. Temporary Containment Closure Devices shall be capable of withstanding Lower Mode Operations Containment Pressure. [B0138] 3.13 Time to Boil(TTB) Time for the RCS/Refueling Pool mass to reach bulk boiling after loss of SDC as determined by the Figures in OP-7, Shutdown Operations. 3.14 Yellow Caution Tag Definition per CNG-OP-1.01-1007, Clearance and Safety Tagging.

CONTAINMENT CLOSURE NO-1 -114 Revision 01700 Page 7 of 39 4.0 RESPONSIBILITIES 4.1 Operations is responsible for: A. Overall closure of the Containment including inside and outside alignments. B. Tracking and monitoring Containment Closure status by utilizing NO-1-1 14, Containment Closure, and CNG-OP-1.01-1007, Clearance and Safety Tagging (STPO-55A, Containment Closure Verification, is an implementing tool). C. Verifying that all valve alignments necessary to restore Containment Closure within the Time to Boil (TTB), if both S/Gs are not available, and T.S. 3.9.4/3.9.5. This verification can be by an administrative review of Deviation Sheets and/or actual walkdowns. 4.2 Radiation Protection is responsible for: A. Containment evacuation upon initiation of Containment Closure restoration. 4.3 Mechanical Maintenance is responsible for: A. The restoring of equipment and personnel hatches, Main Steam Safeties and temporary covers, and other compensatory measures associated with mechanical maintenance on Containment Systems, Structures, or Components (SSC). 4.4 Maintenance Planning and Work Control is responsible for: A. Identifying all work activities which could affect Containment Closure. 4.5 Outage Management is responsible for: A. Coordinating closure of the Equipment Hatch Door (EHD), Containment Outage Door (COD) and Personnel Airlocks and ensuring tools, materials, and other equipment such as lighting and rigging are properly staged. B. Testing the outage organizations' ability to restore Containment Closure by running drills. C. Ensuring specific responsibilities for the Equipment Hatch and Containment Outage Door are conveyed each shift (liaison with Mechanical Maintenance). D. Verifying capability exists to close required hatches is less than the Time to Boil (TTB) and T.S. 3.9.4/3.9.5 time requirements. (Assume the time to close the Equipment Hatch is approximately 65 minutes with personnel and equipment on station. Add an additional 15 minutes if equipment is stationed and personnel are not.) E. Being cognizant of all potential hatch/airlock/COD obstructions, deviations, and restoration plans, including COD closure swing path remain clear or swing path can be cleared within required closure times. F. Ensuring enough manpower is available and coordinating manpower augmentation if necessary.

CONTAINMENT CLOSURE NO-1lI14 Revision 01700 Page 8 of 39 4.6 Containment Closure Team A. The team is responsible for restoring Containment Closure in less than the Time to Boil (TTB) and T.S. 3.9.4/3.9.5 time requirements. B. The team consists of those members assigned Containment Closure restoration responsibilities per Deviation Sheets:

• Instrument Maintenance
• Mechanical Maintenance
• Operations
• Outage Management
• Radiation Protection
• System Engineering
• Contract Sponsorship C. The team's activities are coordinated by the Control Room and Outage Management.

4.7 Personnel involved with Local Leak Rate Testing (LLRT) are responsible for: A. Continuously attending penetrations where testing is in progress and for being prepared to suspend testing and isolate valves as required to restore Containment Closure. 4.8 All other personnel in Containment and not on the Containment Closure Team are responsible for: A. Upon notification, leaving their work in a safe condition and evacuating.

CONTAINMENT CLOSURE NO-1 -114 Revision 01700 Page 9 of 39 5.0 PROCESS 5.1 Discussion A. The various Shutdown Safety conditions as defined in NO-1-103, Conduct of Lower Mode Operations, are based on relative risk and controlled accordingly with the respective Minimum Essential Equipment Lists in CNG-OP-1.01-2002, Operations Shift Turnover and Relief. Containment Closure conditions as subsets of Shutdown Safety are further simplified by the philosophy of fission product barrier control; the three barriers being fuel cladding, the Reactor Coolant System (RCS), and the Containment. The bases for Containment Closure assume fission products are in the reactor coolant due to some breach of the fuel cladding. Therefore, the RCS and the Containment are the barriers in Modes 5 and 6 that preclude potential fission product release. B. A prolonged loss of Shutdown Cooling (SDC) or an inadvertent fuel handling incident, are the bases for Containment Closure. Therefore, the ability to close the Containment prior to the Time to Boil (TTB) to withstand Lower Mode Operations Containment Pressure is the major consideration which bounds the above events. If an open penetration cannot be adequately controlled in less than the TTB and the T.S. 3.9.4/3.9.5 requirements, then the penetration must remain closed. If a penetration can be closed in less than the TTB and T.S. 3.9.4/3.9.5 requirements, the there are no limits on the duration that the penetration is allowed to be open. [B0596] C. If the RCS is intact (a S/G is available), then Deviation Sheets need to be completed for planned and inadvertent Containment breaches and the ability to restore Containment Closure need only be tracked on the Containment Closure Penetration Status Board. D. When the RCS is not intact (both S/Gs are not available), the last dependable barrier is the Containment. It is paramount that all Containment penetrations opened to the atmosphere be capable of being closed prior to the Time to Boil (TTB) and T.S. 3.9.4./3.9.5 requirements, in the event of a prolonged loss of Shutdown Cooling (SDC).

1. If a Restricted Containment Closure Condition does not exist, then control of the ability to restore Containment Closure is limited to:

• Completing Deviation Sheets
• Tracking penetration status on the Containment Penetration Status Board
• Monitoring the TTB

2. If a Restricted Containment Closure Condition exists, then strict control of the ability to restore Containment Closure requires:

NOTE Containment Deviations are not allowed during T.S. 3.9.3/3.9.4 (NOTE 2) conditions.

• Completing Deviation Sheets
• Tracking penetration status on the Containment Penetration Status Board
• Monitoring the TTB 0 Performing STPO-55A, Containment Closure Verification
• Hanging yellow caution tags

CONTAINMENT CLOSURE NO-1 -114 Revision 01700 Page 10 of 39 5.1 (Continued) E. During Defueled operations, no additional tracking of Containment Closure is required and breaches to containment are allowed. 5.2 Containment Penetrations A. Equipment Hatch Opening

1. Conditions of Operation:

a. During the movement of irradiated fuel assemblies within the containment (LCO 3.9.3), the equipment hatch shall be shut per STPO-55A, Containment Closure Verification, if the Containment Outage Door (COD) is unable to satisfy its "Closed Condition" and "Operational Requirements". (See Section 5.2.A.3)

b. If ERPIP-3.0, Immediate Actions, Attachment titled, Preparing for Severe Weather, is implemented and requires Containment Closure to be -

established then the Equipment Hatch shall be installed per STPO-55A, Containment Verification. In addition, The ERPIP-3.0 may require 20: hatch eyebolts.

2. Equipment Hatch Door (EHD)

a. Currently, the Equipment Hatch Door (EHD) cannot be quickly closed when a loss of power occurs. The equipment hatch should, therefore, be opened only for the time necessary to transport material in and out of the containment and should not normally be opened when fuel is in the reactor vessel with S/Gs not available for decay heat removal. If the hatch is required to be opened when a S/G is not available and the Containment Outage Door (COD) will not be utilized to satisfy closure, then:

(1) The amount of time the hatch is open shall be minimized. (2) The hatch shall only be open when the Time to Boil (TTB) is greaterthan the time required to close the hatch (65 minutes closing time plus 15 minutes if personnel are not on station). (3) The GS-Mechanical Maintenance shall be responsible to ensure qualified personnel are on-site to close the hatch. (4) Two on-site and two off-site power supplies should be available to close the equipment hatch. This is not required when the refueling pool level is greaterthan 57 feet due to the increased TTB. [B0138] [B0483]

b. The equipment hatch may be opened, without imposing the requirements of Section 5.2.A.2, Equipment Hatch, if a S/G is available.

c. If utilized for Containment Closure, the containment equipment hatch shall be capable of being closed prior to the TTB and T.S. 3.9.4/3.9.5, held in place by a minimum of 4 eyebolts with no gaps. [B10138]

CONTAINMENT CLOSURE NO-1-114 Revision 01700 Page 11 of 39 5.2.A.2 (Continued)

d. Deviations for the equipment hatch are not allowed in Reduced Inventory unless:

• The hatch can be closed in less than TTB and T.S. 3.9.4/3.9.5.
• The deviation is approved by the GS-SO.

                          .       A Higher Risk Evolution Contingency Plan is prepared per NO-1-103, Conduct of Lower Mode Operations.

3. Containment Outage Door (COD)

a. Verify personnel are stationed at the COD once per shift during Refueling or if Shutdown Cooling is not in operation per the requirements of TS

    .                     3.9.3.

b. The COD is designed to be a functional equivalent of the Equipment Hatch Door (EHD), for the purposes of achieving containment closure when required during outage conditions.

c. Two Conditions of Operations:

(1) Standby Condition: Allows the passage of equipment and personnel through an 11' by 17' (nominal) door opening in the COD. (2) Closed Condition: Capable of retaining a maximum of 12 PSIG within the containment.

d. Operational Requirements:

(1) During an outage, when the plant enters Modes 5 and 6, the COD will only be used for containment closure at least 24 hours after shutdown. This assures that the decay heat in the core will not result in exceeding the 12 PSIG maximum design pressure for the COD. (2) If ERPIP-3.0, Immediate Actions, Attachment titled; Preparing for Severe Weather, is implemented and requires Containment Closure to be established then the Equipment Hatch shall be installed per STPO-55A, Containment Closure Verification. In addition, the ERPIP-3.0 may require 20 hatch eyebolts. (3) If the COD is required to be open when a S/G is not available then it shall only be opened when the TTB is greaterthan the time required to close the COD (actual COD closure time plus 10 minutes if personnel are not on station). (4) The GS-Mechanical Maintenance shall be responsible to ensure qualified personnel are on-site to close the COD.

CONTAINMENT CLOSURE NO-11-,.114 Revision 01700 Page 12 of 39 5.2.A.3.d (Continued) (5) For Containment Closure the COD shall be capable of being V closed prior to the TTB and within the requirements of T.S. 3.9.4/3.9.5. If the COD is open, Section 5.1.C, 5.1.D or 5.1.E shall be followed, as applicable. The COD door opening, 'laydown area, and/or pathway to the COD within the Equipment Hatch Access Building (Butler Building) must remain clear. If equipment or materials must be located in these areas, where as removal of equipment or materials would take longer than 10 minutes, then a separate Attachment 1, Containment Closure Deviation Sheet shall be required. The group requiring equipment or materials to be located within the COD door opening, laydown area and/or pathway to the COD within the Equipment Hatch Access Building (Butler Building) is responsible for filling out the separate Attachment 1, Containment Closure Deviation Sheet. The purpose of the separate Attachment 1, Containment Closure Deviation Sheet, is to provide methods for ensuring equipment or materials located within the COD door opening, laydown area and/or pathway to the COD within the Equipment Hatch Access Building (Butler Building) can be removed in a prompt manner, such that the COD can be fully shut and dogged prior to the TTB. and/or T.S. 3.9.4/3.9.5. (6) If the time required to close the COD is less than 30 minutes and/or during T.S. 3.9.3/3.9.4 (NOTE 2), the COD shall be manned at all times. For T.S. 3.9.3/3.9.4 (NOTE 2) see Section 5.2.A.3.c(8) for specific requirements. 1The Laydown area is marked as a designated "restricted area."

CONTAINMENT CLOSURE NO-1 -114 Revision 01700 Page 13 of 39 5.2A.3.d (Continued) (7) If the time required to close the COD is greaterthan 30 minutes the COD is not required to be manned, except during T.S. 3.9.3/3.9.4 (NOTE 2). If the time required to close the COD is greaterthan 30 mintues and T.S. 3.9.3/3.9.4 (NOTE 2) are not applicable, the group responsible for opening/closing the COD shall post a sign, per Door-01, Open and Closing of Containment Outage Door, procedure. The sign will describe that prior to placing unattended equipment and materials located in the COD door opening, laydown area and/or pathway to the COD within the Equipment Hatch Access building (Butler Building), requiring qreaterthan 10 minutes to be removed, the owner shall contact the OWC to determine if a separate Attachment 1, Containment Closure Deviation Sheet, is permissible under the current plant conditions and to assist requesting group in determining the desired "Method for Restoration or Closure." This will ensure that the group responsible for closing the door, once notified, will not be impacted by equipment or materials impeding COD closure. The door shall be fully shut and dogged prior to the TTB or T.S. 3.9.4/3.9.5. (8) For T.S. 3.9.3/3.9.4 (NOTE 2) the equipment hatch opening may be open if the Containment Outage Door is operable and capable of being closed by a designated individual who is continuously available, stationed near the door. During these conditions, no cables or hoses are permitted to run through the door opening, the door must remain unblocked (for example: capable of being closed within 30 minutes) and capable of being fully shut and dogged. Containment Outage Door grating or truck ramps may be installed ifthe grating or truck ramps can be removed with the use of a forklift and the door closed within 30 minutes. During these conditions the COD will be tracked by an Attachment 1, Containment Closure Deviation Sheet, for tracking purposes only, to be utilized during Abnormal Conditions. (9) Deviations for the COD are not allowed in Reduced Inventory unless: The COD can be fully shut and dogged in less than TTB and/or T.S. 3.9.4/3.9.5

• The deviation is approved by the GS-SO
• A Higher Risk Evolution Contingency Plan is prepared per NO-1-103, Conduct of Lower Mode Operations.

CONTAINMENT CLOSURE NO-1-114 Revision 01.700 Page 14 of 39 5.2.A.3.d (Continued) (10) As required in Containment Penetrations 5.2.E, temporary pipes and hoses attached to the COD structure must be maintained as closed systems or have the ability to be isolated and/or quickly disconnected to provide a barrier against Lower Mode Operations Containment Pressure. B. Emergency Air Lock (EAL)

1. For Containment Closure, a minimum of one door in the EAL shall be capable of being closed prior to the TTB and within the time requirements of T.S.

3.9.4/3.9.5. [B0606]

2. The Emergency Air Lock temporary door is acceptable to meet T.S. 3.9.3, but it shall have a Containment Closure Deviation Sheet filled out to ensure one Emergency Air Lock door can be closed prior to the TTB and the time requirements of T.S. 3.9.4/3.9.5. This Deviation Sheet shall not be considered a deviation for the movement of irradiated fuel in containment. The temporary door shall also have:

a. Six diametrically opposed C-clamps installed.

b. Each penetration through the temporary door capped; or, if in use, connected to a closed system; or the isolation valve at the penetrationi is shut.

c. The outer door equalizing valve is shut.

3. The temporary door in the Emergency Air Lock (designed for 5 PSIG) is not capable of withstanding Lower Mode Operations Containment Pressure.

a. If required to perform actions to close all penetrations per T.S. 3.9.4/3.9.5, the Emergency Air Lock temporary closure device cannot be credited for Containment Closure for a Loss of Shutdown Cooling event. At least one door in the Emergency Air Lock must be closed to satisfy these action statements.

(1) During Restricted Containment Closure Conditions: [B0859]

• All manually operated valves associated with piping penetrations through the Temporary Door are tagged in accordance with Section 5.3.D, Restricted Containment Closure Conditions.

When the Temporary Door is installed then, ensure green chain barriers are installed at both locations (inside the Containment at the Emergency Air Lock hatch and outside Containment at the door to prevent unauthorized entry in the area). The chains shall have signs to contact OWC prior to entry. C. Personnel Air Lock (PAL)

1. Verify personnel are stationed at the PAL once per shift during Refueling or if Shutdown Cooling is not in operation per the requirements of TS 3.9.3.

CONTAINMENT CLOSURE NO-1-114 Revision 01700 Page 15 of 39 5.2.C (Continued)

2. For Containment Closure, a minimum of one door in the Personnel Airlock shall be capable of being closed prior to the TTB and within the time requirements of T.S. 3.9.4/3.9.5.

During these conditions the PAL will be tracked by an Attachment 1, Containment Closure Deviation Sheet, for tracking purposes only, to be utilized during Abnormal Conditions. NOTE Further restrictions apply for the Containment Outage Door, see 5.2.A.3. D. Equipment shall not be maintained in or through a hatch unless equipment can be removed to support Containment Closure prior to the TTB and within the time requirements of T.S. 3.9.4/3.9.5. NOTE Further restrictions apply for the Containment Outage Door, see 5.2.A.3. E. Temporary pipes and hoses must be maintained as closed systems or have the ability to be isolated and/or quickly disconnected prior to the TTB and within the time requirements of T.S. 3.9.4/3.9.5. F. During Technical Specification 3.9.3 Conditions of Operation, refer to O1-17D for requirements needed to open the Containment Normal Sump Valves. G. During Technical Specification 3.9.4 Conditions of Operation (NOTE 2 or Action "A") or 3.9.5 Conditions of Operation (Action "B"), Containment Normal Sump Valves may not be opened. Containment Normal Sump Valves may be open during all other closure conditions as follows: [B0610] [B0674]

1. Refer to 01-1 7D for draining the Containment Normal Sump.

2. This is considered a deviation for Reduced Inventory conditions. This will require an Attachment 1, Containment Closure Deviation Sheet to track the valve status.

3. If the spring return handswitch is key-overridden open, then an Attachment 1 Containment Closure Deviation Sheet shall be completed to track the valve status when Containment Closure is required.

H. Steam Generator instrument sensing lines may be opened to obtain a Steam Generator level reading of the temporarily installed tygon tubing and reclosed upon completion of the level reading.

1. This is routine, short duration evolution usually conducted during operator containment tours.

2. This is considered a deviation for all Tech Spec closure requirements unless the Steam Generator is open to the Containment atmosphere with closure established accordingly.

CONTAINMENT CLOSURE NO-1 -114 Revision 01700 Page 16 of 39 5.2 (Continued) I. Main Steam Safety Valves may be worked in Reduced Inventory with secondary open to containment ifthe Safety Valves or temporary covers can be installed prior to TTB and T.S. 3.9.4/3.9.5 requirements, per submitted restoration plans (Deviation Sheets) and GS-SO permission is granted. J. Containment Purge Valve(s) seats must be visually inspected, at least once per refueling cycle, prior to crediting them for closure. A verification that no visible gaps exist between the valve seat and the valve disc constitutes a satisfactory closure barrier. Adjustments/Repairs may be made during the inspection to eliminate any gaps in order to achieve a satisfactory inspection. InspectionNerification/Adjustments and repairs are to be performed in accordance with an approved maintenance procedure. [B0611] K. All penetrations as listed in STPO-55A, Containment Closure Verification, which provide access from the Containment atmosphere to the outside atmosphere, shall be capable of being closed by an isolation valve, blind flange, or manual valve prior to the TTB and T.S. 3.9.4/3.9.5 requirements. [B0594]

1. All penetrations shall meet all Tech Spec Containment Closure requirements for Tech Spec 3.9.3, 3.9.4, and 3.9.5 conditions.

NOTE For all closed systems, in or out of service, with Containment penetrations, Containment Closure is met if intact piping and components (even continuous vent valves) can prevent Lower Mode Operations Containment Pressure from relieving to the outside atmosphere.

2. An operating system designed to be a permanent part of the plant meets Containment Closure. [B0607]

3. A non-operating system designed to be a permanent part of the plant meets Containment Closure as long as the piping is intact and the penetration is not.

providing direct access from the Containment to the outside atmosphere. [B0608]

4. SG Sluice hoses connected between a COD penetration and a SG with inside closure (for example: SG closed to the containment atmosphere per STPO-55A) may be considered a closed system as allowed by STPO-55A.

5.3 Status Tracking A. This section provides the administrative means of tracking the status of Containment penetrations during outages. Containment penetration tracking sets the ideal conditions for Containment Closure restoration. Tracking shall be utilized as an aid to ensure a sufficient number of trained individuals are on site to complete restoration of containment openings prior to the TTB if SDC is lost. Tracking shall be accomplished through the use of the Containment Closure Deviation Sheets, the Containment Penetration Status Board (BGEDRWGs 83018 (U-I) and 83019 (U-2) SHOO01) and the Shift Turnover Information Sheet.

CONTAINMENT CLOSURE NO-1 -114 Revision 01700 Page 17 of 39 5.3.A (Continued)

1. Deviation Sheets are used to document personnel notifications and requirements to ensure Containment breaches can be rapidly restored. Deviation Sheets provide the Operator with information describing:

0 Affected penetrations

• Methods of closure
• Times required for closure
• Special protective equipment
• Required tools and materials
• Work group contacts responsible for closure [B10138]

2. The Containment Penetration Status Board is: [B0612]

• A consolidated, controlled, single-line drawing of all primary (first boundaries back from penetration) Containment inside and outside penetrations.
• A human factored format to allow big picture, up-to-the-minute status of Containment Closure.

Maintained in the Operations Work Control Center (OWC) or Control Room.

3. The Shift Turnover Information Sheet shall be used to track active Containment Closure Deviations including administrative deviations, such as PAL, and COD during the movement of irradiated fuel. The Shift Turnover Information Sheet should include the penetration, the action to restore and the responsible individual.

B. If S/Gs are available, all breaches shall be tracked per Section 5.3.A and 5.1 .C above. C. Whenever the S/Gs are not available for decay heat removal, the following actions shall be taken and conditions met in addition to Section 5.3.A:

1. Prior to proceeding to a condition where both S/Gs are unavailable, the CRS shall verify that all current (open) Containment Closure Deviations shall be capable of being restored within the TTB and T.S. 3.9.4/3.9.5 time requirements (Step 3 of Attachment 1). S/G status shall not be altered until closure is restored or all responsible Work Groups have restoration plans to ensure Containment Closure can be restored prior to TTB or 3.9.4/3.9.5 time requirements.

2. Operations shall calculate Time to Boil (TTB):

a. Once per shift, based on existing RCS inventory and assuming shutdown cooling is lost.

(1) A review of T.S. 3.9.4/3.9.5 shall be also conducted while in Mode 6. The lesser time of T.S. 3.9.4/3.9.5 and the TTB, as needed, shall be recorded and updated on the Shift Turnover Information Sheet.

CONTAINMENT CLOSURE NO-1 -114 Revision 01700 Page 18 of 39 5.3.C.2 (Continued)

b. Before draining the RCS 6 inches or more:

(1) The TTB shall be updated based on the anticipated RCS level following the inventory change and shall be updated on the Shift Turnover Information Sheet as needed. (2) The updated TTB shall be compared with T.S. 3.9.4/3.9.5 and the time to restore closure in Step 3 of all existing (open) Attachment 1, Containment Closure Deviation Sheets. Inventory level changes shall not be made until all responsible Work Groups have restoration plans to ensure Containment Closure can be established prior to core boiling or 3.9.4/3.9.5. D. Restricted Containment Closure Conditions

1. Restricted Containment Closure Conditions include: the movement of irradiated fuel in containment, Reduced Inventory as defined in this procedure, and Tech Spec 3.9.4/3.9.5n SDC loop inoperability requiring establishment of containment closure.

a. In addition to the requirements in Section 5.3.C, the status of Containment penetrations shall be verified to be accurate by performing STPO-55A, Containment Closure Verification, within 7 days prior to electively entering Restricted Containment Closure Conditions. The Shift Manager shall determine the requirements to perform STPO-55A in unplanned situations leading to entry into Restricted Containment Closure conditions (for example: unplanned required SDC loop inoperability).

(1) Each time STPO-55A is completed, the person performing the. surveillance shall note all closure deviations directly on the STP and on the Containment Penetration Status Board. Subsequent changes to closure need only be captured on the status board. Changes should not be made to STPO-55A after the initial performance. (2) Each time STPO-55A is performed, the SRO reviewing the STP shall ensure a Deviation Sheet exists for each discrepancy noted on the STP by auditing the Shutdown Control Log. Should a deviation exist which is not current or is improperly entered into the Shutdown Control Log, the SRO shall correct the situation and bring the Log up to date. (3) For STPO-55As performed for T.S. SR 3.9.3.1, process the original of the STP per EN-4-104, Surveillance Testing. Place a copy of the original STP in the Shutdown Control Log. (4) For STPO-55As performed for restricted containment closure conditions other than T.S. SR 3.9.3.1, place the original STP in the Shutdown Control Log. (5) Send previous STPO-55As performed for restricted containment closure conditions (other than T.S. SR 3.9.3.1, which were processed per EN-4-104, Surveillance Testing) and all Containment Closure Deviation Sheets to the Operation's shift office for retention for 2 years.

CONTAINMENT CLOSURE NO-1 -114 Revision 01700 Page 19 of 39 5.3.D.1 .a (Continued) NOTE Reference to performing STPO-55A for the initial SG unavailability is included in STPO-55A, Attachment 5, Performance Flowchart for the sake of completeness. This is NOT considered a Restricted Containment Closure condition. (6) For all elective entries into Restricted Containment Closure Conditions, STPO-55A shall be initially and subsequently executed per the requirements of STPO-55A, Attachment 5, Performance Flowchart. Subsequent required performances of STPO-55A should be tracked on the Shift Turnover Information Sheet per CNG-OP-1.01-2002, Operations Shift Turnover and Relief.

b. All manually operated valves and handswitches (for remotely operated valves) used for Containment Closure shall be yellow caution tagged.

[B0609] (1) Implementation of yellow caution tags shall be controlled per CNG-OP-1.01-1007, Clearance and Safety Tagging. (2) Yellow caution tags for Containment Closure shall be annotated to indicate that equipment is being controlled for Containment Closure and may only be operated with SM/CRS permission. (3) If a penetration's Containment Closure is being maintained by process flow, then at least one Control Room component or indicator shall be yellow caution tagged (if available) to indicate to Control Room personnel the nature of the closure for that penetration. (a) If controls that could affect the flow are in various locations within the Control Room, it may be appropriate to yellow caution tag more than one component or indicator for that penetration. (b) If no appropriate Control Room components or indicators are available, yellow caution tags may be hung locally to provide equivalent information about the nature of Containment Closure for that penetration. (4) When Containment Closure boundaries are required to be changed, ensure that the new yellow caution tags are hung prior to removing the previous yellow caution tags.

c. If a penetration is controlled by a Safety Tagging Clearance per CNG-OP-1.01-1007, Clearance Safety Tagging, and is aligned differently than STPO-55A, Containment Closure Verification, then:

(1) Review the tagout to be sure it meets closure requirements, including valves within the boundary. (2) Place a circled comment number in the initials column of the STPO-55A alignment.

CONTAINMENT CLOSURE NO-1.-114 Revision 01700 Page 20 of 39 5.3D. 1.c (Continued) (3) List the comment number and specific tagout number in the STPO-55A cover sheet Remarks sections. (4) Ensure yellow caution tags are hung on the credited closure boundaries per the section above in addition to those tags which are a part of the clearance. a, (5) Identify these components and closure tags on the Containment Penetration Status Board.

2. Prior to entering and during the movement of irradiated fuel in containment and SDC Maintenance, comply with the following T.S. requirements for Containment Closure:

3.9.3 3.9.4 3.9.5

3. Deviations to Containment Closure during Reduced Inventory shall have their restoration plans approved by the GS-SO.

E. In addition to the current STPO-55A, Containment Closure Verification, a copy of NO-1 -114, Containment Closure, and active Deviation Sheets shall be kept in the Shutdown Control Log. F. Local Leak Rate Testing (LLRT) [B0610]

1. Prior to the start of the outage, Operations LLRT personnel shall review every LLRT to performed under the applicable STPO-1 08, Local Leak Rate Procedure against STPO-55A, Containment Closure Verification, for any change in Containment Closure requirements. This review will result in a document similar to Attachment 3, LLRT Matrix (Example).

a. LLRT personnel shall ensure LLRTs which deviate from Containment Closure ("N"s on the LLRT Matrix) are scheduled by Outage Scheduling for performance during Non-Restricted Containment Closure Conditions.

(The GS-SO may approve Deviation Sheets for these LLRTs in Reduced Inventory.)

b. All LLRTs that cannot be performed while maintaining closure ("N"s on the LLRT Matrix) or require draining evolutions prior to setting closure

("Drain-Aheads" on the LLRT Matrix) shall have Deviation Sheets.

CONTAINMENT CLOSURE NO-1 -114 Revision 01700 Page 21 of 39 5.3.F.1 (Continued)

c. LLRTs that can be performed and still maintained closure can be scheduled in any Mode 5 and 6 condition (including the set-up and post-test valve manipulations: venting, draining, filling, and connection of the Leak Rate Monitor (LRM)).

(1) As long as the LRM is connected to the piping and pressurized above Lower Mode Operations Containment Pressure, Containment Closure is satisfied. (2) If the LRM is connected to the piping and pressure is less than Lower Mode Operations Containment Pressure or vented, closure shall be maintained by other boundaries or a Deviation Sheet shall exist for the penetration.

2. In-progress LLRTs shall be tracked and status updated per Attachment 4, Containment Closure Status Sheet for LLRTs. There shall be direct communications between the LLRT team and the Operations Work Control Center or Control Room which will include presentation of Attachment 4 by the LLRT personnel.

3. Penetration valve manipulations for LLRTs should only be performed by LLRT, Operations and Instrument and Controls personnel.

4. Failure of the LLRT

a. In order for a degraded boundary, leakage greaterthan max allowed in accordance with the applicable STPO-108, Local Leak Rate Test Procedure, to serve as a Containment Closure boundary, the valve and test data must be evaluated by Engineering.

b. Ifthe piping will not pressurize or leakage is so significant that the test is obviously failing, DO NOT vent or break the LRM connection until an alternate closure boundary is established and the LRM test connection has been isolated.

5. Upon LLRT completion or while moving test boundaries, ensure Containment Closure is maintained or a Deviation Sheet exists.

G. Transmitter Calibrations

1. Calibration procedures for all transmitters associated with Containment penetrations shall be the controlling procedures and shall meet the closure requirements of this procedure.

2. Per the calibration procedures, transmitter local instrument stops are specifically used to isolate the transmitter from the process fluid during the calibration and shall be credited to maintain closure. Calibration procedures require independent verification of local instrument stops to place the transmitters back in service.

3. There shall be direct communications between the Instrument and Controls personnel and the Operations Work Control Center or Control Room.

CONTAINMENT CLOSURE NO-1 -114 Revision 01700 Page 22 of 39 5.3.G (Continued)

4. Penetration valve manipulations upstream of the local instrument shop shall be controlled by Operations. Manipulation of transmitter local instrument stops and other downstream valves shall be controlled by Instrument and Controls personnel.

5.4 Deviations A. As a general operating philosophy, containment breaches should not be allowed. However, when work activities require a deviation to a Containment Closure boundary and the deviation is allowed or an inadvertent breach has occurred, then:

1. The breach shall:

a. Be controlled and recorded according to Section 5.3 of this procedure.

b. Have restoration plans to facilitate closure of the breach at all times in Modes 5 and 6.

(1) Containment Closure restoration plans shall document provisions for the establishment of Containment Closure prior to Tech Spec mandated timelines and the time boiling would occur in the RCS based on existing water inventory and decay heat. This may require, but not be limited to: Pre-staging of personnel and material Pre-approved Special Work Permits Personnel safety equipment (2) The supervisor of the work group designated to restore closure shall ensure that: (a) Personnel designated to restore closure have the specific knowledge required for restoration actions. (b) A walk-through is conducted to ensure the designated personnel are aware of the closure's location, the necessary equipment, and actions required to establish closure. (c) Trained individuals necessary to establish closure are on station if the TTB is less than one hour (30 minutes for COD per 5.2.A.3). (d) Trained individuals necessary to establish closure are on-site if the TTB is greaterthan or equal to one hour. (e) Manifolds, quick-disconnect devices, or some other means of quickly restoring the penetration's capability to withstand Lower Mode Operations Containment Design Pressure are utilized when temporary hoses, cabling, or other equipment are running through the containment penetration. [B0138]

CONTAINMENT CLOSURE NO-1-114 Revision 01700 Page 23 of 39 5.4.A.1 (Continued)

c. Have Temporary Containment Closure Devices installed, if necessary, in such a way as to facilitate rapid separation and/or removal and shall be clearly labeled with tags hung on the isolation points identifying:

• Organization
• Contact number
• Purpose/job B. When a breach in containment will or does exist as a result of maintenance activity or any other unforeseen circumstance, then:

1. The responsible Work Group Designated Contact and Workleader shall complete Steps 1-7 of Attachment 1, Containment Closure Deviation Sheet, per Attachment 2.

2. If the job does not require a tagout, then the Work Group shall present the Deviation Sheet to the Operations Work Control (OWC) Senior Reactor Operator (SRO) or the CRS along with the Work Order when requesting authorization to start work. The SRO shall sign Step 9 of Attachment 1 for review per Attachment 2.

3. If the job requires a tagout, the work group shall forward the Deviation Sheet to Safety Tagging. Safety Tagging shall sign Step 9 of Attachment 1 for review per Attachment 2.

4. The Shift Manager shall sign Step 10 of Attachment 1 for approval per Attachment 2.

5. The GS-SO shall also sign Step 11 of Attachment 1 for approval if the deviation exists during Reduced Inventory.

6. The Deviation Sheet shall be filed in the Shutdown Control Log by the OWC SRO or the CRS, and a copy shall be included in the work package. Work Group Workleaders responsible for restoring closure should also retain a copy.

7. The Containment Penetration Status Board shall be updated with the new deviation by the OWC.

8. Once the activity requiring the deviation has been completed, the OWC SRO shall sign for close-out per Attachment 2. The OWC SRO shall then forward the completed sheet to the Shift Office for retention.

9. Information other than the method for restoration may be updated on Attachment 1, Containment Closure Deviation Sheet, in accordance with the guidelines of this procedure. The OWC SRO or the CRS shall initial and date all changes.

a. If the method of restoration changes, then the existing Attachment 1, Containment Closure Deviation Sheet, shall be closed out, and a new Attachment 1, initiated and approved.

CONTAINMENT CLOSURE NO-1 -114 Revision 01700 Page 24 of 39 5.4 (Continued) C. Testing activities, which could affect the ability to close containment, shall be reviewed for:

• Closure controls in place
• Potential loss of power supplies
• Management authorization
• Inadvertent draining
• Compensatory measures 5.5 Closure Restoration A. To initiate Containment Closure Restoration:

1. Notify personnel and evacuate Containment by initiating ERPIP-3.0, Immediate Actions. [B10138]

2. The CRS will perform a follow-up initial notification by communicating with appropriate personnel to ensure expected results:

• Radiation Protection Supervision
• Security
• Outage Management
• Maintenance
• Outage Control Center B. Operations shall:

1. Initially focus on Control Room manipulations and notification of responsible work groups per existing Deviation Sheets. [B0138]

2. If necessary, dispatch personnel for component manipulation, coordination of contingency plans, or restoration assistance and verification.

3. Follow-up initial efforts by confirmation of STPO-55A, Containment Closure Verification, requirements by:

a. Administrative reviews of STPO-55A.

OR

b. Actual performance of sections or all of STPO-55A as designated by the Shift Manager/CRS. Consider performing only outside alignments since a harsh Containment environment may exist. [B0138]

4. Ensure Containment Purge is secured or an automatic signal is OPERABLE to isolate Containment Purge (depending on Tech Spec requirements).

5. Ensure available Containment Air Coolers and Iodine Removal Units are operating as required.

6. Hang tags on closure boundaries at the Shift Manager's discretion depending upon Containment conditions and the necessity to maintain Containment Closure.

CONTAINMENT CLOSURE NO-1 -114 Revision 01700 Page 25 of 39 5.5 (Continued) C. Upon notification, the Containment Closure Team shall report to applicable locations to restore Containment Closure. D. The LLRT Team shall terminate and isolate all tests in progress and report the status to the Control Room. E. The Outage Management shall notify the CRS when closure is restored to all Containment hatches. F. The RCSS shall notify the Control Room that the Containment evacuation is complete (including Closure Team members). G. Restoration actions required to establish Containment Closure may be terminated when the SDC system, RCS, and fuel matrix have been restored to a controllable and stable condition. The Shift Manager/CRS shall use appropriate judgment when implementing and terminating actions. 5.6 Drills A. The Containment Closure program shall be periodically assessed by drills.

1. Minimize impact on the outage.

2. Conduct a drill at least once per refueling outage.

B. The Outage Manager shall coordinate Containment Closure Restoration drills as necessary to ensure: [B0138]

1. Lines of communication are clearly established for both initiation of closure and restoration feedback to the Control Room.

2. Personnel are aware of their assignments.

3. Tools and equipment are staged as required.

4. All closure deviations can be restored within the required time.

5.7 Abnormal Conditions A. During Restricted Containment Closure Conditions, if a loss of Containment Closure is experienced, enter AOP-4A, Loss of Containment Integrity/Closure, section titled Modes 5 and 6. [B0138] B. In the event of a fuel handling incident, enter AOP-6D, Fuel Handling Incident. C. In the event of an abnormal SDC condition, enter AOP-3B, Abnormal Shutdown Cooling Conditions. D. In all cases where Containment Closure restoration is required, Containment penetrations to the atmosphere shall be isolated or closed prior to the TTB and within the time requirements of T.S. 3.9.4/3.9.5. [B0606]

CONTAINMENT CLOSURE NO-1 -114 Revision 01700 Page 26 of 39 6.0 BASES [B30138] NUMARC 91-06 Guidelines for Industry Actions to Assess Shutdown Management, Sections 3.3.5.2, 4.1.1.3, 4.5.1, 4.5.2, and 4.5.3 and Shutdown Safety Task Force, AIT 1U930006, 1 U930011, 1U9300008 [B0482] Nuclear Engineering Unit Memo NEU 95-120, dated April 25, 1995 [B0483] NEU Memo 96-288, Time to Boil for Refueling Pool with UGS installed, dated July 16, 1996. [B0594] NRC Generic Letter 88/17, Section 2.2 Containment Closure [B0595] BGE Response to NRC Generic Letter 88-17, J.A. Tiernan Letter, dated January 3, 1989 [B0596] Licensing Memo, L95-131, dated August 24, 1995 [B0606] Nuclear Engineering Unit Memo NEU 93-028, dated January 27, 1993 [B0607] Design Engineering Section Commitment Resolution Document, AIT PD9400025 [B0608] Licensing Memo, L94-003, dated January 5, 1994 [B0609] NO-1 -112, Safety Tagging, Revision 3, dated November 29, 1995 [B0610] AIT 1 F1 99500548, Rise in IRs indicates a potentially inadequate process for administration of containment closure during periods of high maintenance activities [B0611] AIT 1F199500655, Refueling Action Plan, ES200001071 and memo dated 3/16/01, from M.A. Junge to J.K. Mills,

Subject:

Visual Inspection of Containment Purge Valves for Containment Closure [B0612] BGE Response to Notice of Violation, 89-11, George Creel letter dated August 10, 1989 [B0674] Technical Specification Interpretation # 96-001, ITS 3.9.3 Change Request, Refueling Operations, Containment Penetrations [60859] IR-015-307 and IR4-015-735, Maintaining Containment Emergency Air Lock temporary closure requirements during Restricted Containment Closure Conditions [B1222] Cat 1 RCAR, Tech Spec Requirement for Containment Closure not established: during Core Alts (IR200500070).

CONTAINMENT CLOSURE NO-1-114 Revision 01700 Page 27 of 39 7.0 RECORDS 7.1 The following records are generated by use of this procedure and shall be controlled according to CNG-PR-3.01-1000, Records Management.

• Containment Closure Deviation Sheets
• STPO-55A, Containment Closure Verification

    ,,      Containment Closure Status Sheet for LLRTs

CONTAINMENT CLOSURE NO-1-114 Revision 01700 Page 28 of 39 Page 1 of 3 Attachment 1, CONTAINMENT CLOSURE DEVIATON SHEET [B0138] [B13222]

1. Deviation:

a. Deviation Location: (Room Name and Elevation)

(PenetrationNalve Number)

b. Reason for Deviation:

(WO#, RCR#, etc.) NOTE The containment closure deviation sheet shall be closed out whenever the method for closure control is changed. A new containment closure deviation sheet shall be initiated and approved for the "new" method for closure control.

2. Method for Restoration or Closure (for example: Procedures such as: Door-01, Opening and Closing of Containment Outage Door.... ) (Detailed instructions):

3. Estimated Time Required to Physically Establish Closure and/or Exit Containment:

4. Time to Boil (TTB) (taken from CNG-OP-1.01-2002, Operations Shift Turnover Sheet):

Maximum Restoration Time is within the Time to Boil (TTB) if both S/Gs are not available and/or T.S. 3.9.4, 3.9.5 (4 hours), if applicable.

5. Personnel Protective Equipment necessary to support Restoration or Closure during a Sustained Loss of SDC (required at the penetration if time to boil is less than or equal to 1 hour):

E1 Respirator [-] SCBA LI Full Anti-C's 0 RP El Scaffolding El Plastic Suit [ Rubber Boots E] Dose Rate Meter 0 Safety Harness LI N/A (Restoration is from outside containment) MI Other Other equipment necessary to restore closure (required at the penetration when Time To Boil is less than 1 hour):

6. Work Group Designated to Restore Closure

CONTAINMENT CLOSURE NO-1 -114 Revision 01700 Page 29 of 39 Page 2 of 3 Attachment 1, CONTAINMENT CLOSURE DEVIAITON SHEET [B10138] [B13222] (Continued)

7. Work Group Contacts to Restore Closure shall be based on a 24-hour period.

a. Designated Contacts listed shall read, understand and be capable of taking the required actions necessary to restore closure.

b. Responsible Workleader signature certifies that the Workleader has notified and briefed the Designated Contact(s). (NUMARC 4.5.2 Shift Start Stop NamePrint Name Contact Time/Date Time/Date Work Group Number Designated

Contact:

Print Name: Work Group: Designated

Contact:

Print Name: Work Group: Designated

Contact:

Print Name: Work Group: Responsible Print Name: Signature: Workleader: Work Group:______ Designated

Contact:

Print Name: Work Group: Designated

Contact:

Print Name: Work Group: Designated

Contact:

Print Name: Work Group: Responsible Print Name: Signature: Workleader: Work Group: Designated

Contact:

Work Group: Designated

Contact:

Print Name: Work Group: ______ Designated

Contact:

Print Name: Work Group: Responsible Print Name: Signature: Workleader: Work Group:

CONTAINMENT CLOSURE N0-1 -114-Revision 01700 Page 30 of 39 Page 3.of 3 Attachment 1, CONTAINMENT CLOSURE DEVIAITON SHEET [B10138] [B13222] (Continued)

8. RWP # for Containment Entry during a Sustained Loss of SDC:

9. SST, OWC SRO, OR CRS Review: /

Date Signature

a. If Signature in Step 9 is the SST, then enter the Clearance # :

10. Shift Manager Approval: /

Signature Date

11. GS-SO Approval is required if Reduced Inventory Condition Exists: /

Signature Date

12. OWC SRO Deviation Sheet Close-Out:

[B13222] Signature Date Penetration # Valve/Component STP - O-055A Inside or Verify Position Required Outside Sign and Date Position Closure

CONTAINMENT CLOSURE NO-1-114 ' Revision 01700 . Page 31 of 39 Page 1 of 2 Attachment 2, INSTRUCTIONS FOR CONTAINMENT CLOSURE DEVIATION SHEET [B1222] NOTE Attachment 1 may be used for tracking purposes when applicable, for the Containment Outage Door (COD)(Section 5.2.A.3), Emergency Air Lock (EAL) (Section 5.2.B) and Personnel Air Lock (PAL) (Section 5.2.C).: Att. 1 Instruction Step l.a. As a minimum, list the penetration room name and elevation, penetration number and valve number, if applicable. l.b. Explanation of job scope. Include WO and/or FCR/MCR number or other document. [B0610]

2. Detailed description of actions required by the work group should the deviation need to be restored.

This should consider the unavailability of AC electrical power that could cause the loss of lighting or tools necessary to effect closure. Consideration should be given to having redundant power supplies available for these cases. [B0138] Use of plugging, flanging, or other means of restoring closure is acceptable if the Containment penetration can be restored to hold Lower Mode Operations Containment Design Pressure. If the method of restoration changes, then the existing Attachment 1, Containment Closure Deviation Sheet, shall be closed out, and a new Attachment 1 initiated and approved.

3. Total amount of time from Control Room contact with appropriate work group personnel, to deviation being physically restored.

• If possible, the maintenance on the containment penetrations shall be performed such that it is possible to close the penetrations from outside the containment.
• When it is not possible to take the required actions from outside the containment, additional time shall be added to the closure time to allow for personnel to safely exit the containment prior to the onset of boiling.

Due to the environmental conditions that may exist after the onset of boiling (elevated temperatures, containment pressurization, noise levels) it is important to ensure that personnel will be out of containment prior to the onset of boiling. [B01 38]

4. Enter Time to Boil (TTB) from the current CNG-OP-1.01-2002, Operations Shift Turnover Sheet. TTB must be greaterthan the estimated time required to physically establish closure and/or exit containment (Step 3).

Time To Boil (TTB) is the time for RCS/Refuel Pool mass to reach bulk boiling after loss of SDC as determined by Figures in OP-7, Shutdown Operations.

• T.S. 3.9.4/3.9.5 (Mode 6) has a required action to close all containment penetrations providing direct access from containment atmosphere to outside atmosphere within 4 hours.
• Consideration shall be given to ensure required containment closure can be attained within this timeframe.
• For the Containment Outage Door (COD), an additional 10 minutes must be applied to the actual COD closure time if personnel are not on station.

5. Mark or list other appropriate items which would be required to support work group personnel when restoring a deviation inside the Containment during a loss of Shutdown Cooling event. Personnel protective equipment, tools, ladders, flashlights, and materials necessary to support the required work to effect closure of containment openings are immediately available.

6. Proper name of work group responsible for ensuring the deviation is restored if needed.

7. During the movement of irradiated fuel assemblies in containment, designated individuals shall be available to close both the Personnel Air Lock (PAL) and the Containment Outage Door (COD). The designated individuals shall be stationed at the Auxiliary Building side of the outer air lock door and at the outside of the Containment equipment hatch.

These designated individuals shall be properly trained and knowledgeable of required actions to restore closure.

CONTAINMENT CLOSURE NO-1-114 Revision 01.700 Page 32 of 39 Page 2: of 2 Attachment 2, INSTRUCTIONS FOR CONTAINMENT CLOSURE DEVIATION SHEET [B13222] (Continued) Att. I Instruction Step

7. List all Work Group Designated Contacts which can be contacted immediately by the Control Room to cont. restore the deviation. The Shift, Start Time/Date, and Stop Time/Date shall be recorded. The Contact Name and the Work Group shall be printed legibly. The Contact Number may be a pager, shop or office telephone, etc., but not a home phone number. [BO138]

The Workleader is responsible for ensuring personnel are aware of the deviation location and the equipment involved for closure. The Responsible Workleaders signature on Attachment 1, certifies that they have notified and briefed the Designated Contact. A walk-through shall be conducted to ensure personnel are aware of the actions required to restore closure. Workleaders are also responsible for' ensuring that any changes to work group contacts include their review of the Containment Closure Deviation Sheet. They shall require new work group contacts to sign and date the Attachment 1 in the appropriate section, and inform the Shift Manager of the changes. [B10138]

8. Actual SWP or EWP number which will be used for entry.

9. Ifthe iob requires a taqout, Safety Tagging shall:

Ensure all entries on the Sheet are legible. Ensure Steps 1-7 of the Deviation Sheet provide detailed information to promptly and properly execute closure restoration. Sign for review in Step 9 of the Sheet, and enter the Clearance number in Step 9.a. Present the Deviation Sheet to the OWC SRO/CRS when the tagout is presented for approval. If the mob does not require a taqout, then the work group shall:

a. Present the Deviation Sheet to the OWC SRO or the CRS along with the Work Order when requesting authorization to start work.

The OWC SRO or the CRS shall:

1. Obtain the TTB and completion time requirements of T.S. 3.9.4/3.9.5 from the Shift Turnover Information Sheet, and compare to the "Estimated Time Required to Physically Establish Closure and Exit Containment", in Step 3 of the Deviation Sheet.

2. If Step 3 time is equal to or lonqer than TTB and the completion time requirements of T.S. 3.9.4/3.9.5, then the maintenance associated with the deviation shall not be approved until the Work Group provides alternate closure restoration plans to reduce the time associated with restoring closure.

3. Evaluate proposed containment breach against current or expected plant conditions(for example: will breach exist during Reduced Inventory) and inform the Shift Manager of concerns.

4. If a tagout is not required for the job:

a. Ensure all entries on the sheet are legible.

b. Ensure Steps 1-7 of the Deviation Sheet provide detailed information to promptly and properly execute closure restoration actions.

5. Sign for review in Step 9 of the Sheet.

10. The Deviation Sheet shall be approved by the Shift Manager authorizing the work.

a. The Deviation Sheet shall be filed in the Shutdown Control Log by the OWC SRO or the CRS and a copy shall be included in the work package.

b. The OWC SRO or the CRS shall ensure work group leaders responsible for restoring closure have a copy of the signed closure Deviation Sheet. [B0138]

11. If the deviation exists during Reduced Inventory, then the GS-SO shall also approve Attachment 1.

12. Upon activity requiring deviation completion, the OWC SRO shall close-out the deviation sheet by signing and ensuring that the valves/components affected by the deviation sheet are reconciled in the table. The OWC SRO shall then forward the completed sheet to the Shift Office for retention.

CONTAINMENT CLOSURE NO-1-114 Revision 01700 Page 33 of 39 Page 1 of 3 Attachment 3, LLRT MATRIX (EXAMPLE) STP0-55A To be Pen. Equip. page # worked with Tagging arrangement InnerlOuter Function Pen. _Equip. page_ # _ 55A set 1A-1 CV-5464 14 N RC and PZR sampling 1A-2 CV-5465 14 Y Tag outside Cont. Alignment (PS-5464 Shut) RC and PZR sampling 1A-3 CV-5466 14 Y Tag outside Cont. Alignment (PS-5464 Shut) RC and PZR sampling 1A-4 CV-5467 14 Y Tag outside Cont. Alignment (PS-5464 Shut) RC and PZR sampling 1B-1 CV-2181 16 Y Tag Inside Cont. Alignment (RCW-340 Shut) Cont. Vent Header 1B-2 CV-2180 16 Y Tag Inside Cont. Alignment (RCW-340 Shut) Cont. Vent Header 1C-1 CV-505 17 Y-Drain Tag Inside Cont. Alignment (CVC-506 Shut) RC Pump Seals Ahead 1C-2 CV-506 17 Y-Drain Tag Inside Cont. Alignment (CVC-506 Shut) RC Pump Seals Ahead 1D CV-6529 18 Y Tag Outside Alignment (PS-6529 US Key Oxygen Sampling Rem) 2A-1 CV-516 39 N :_Letdown to purif. demin 2A-2 CVC-103 39 N Letdown to purif. demin 2A-2 CVC-105 39 N Letdown to purif. demin 2A-3 CV-515 39 N Letdown to purif. demin 2B-1 CVC-184 41 N RC Charging 2B-2 CVC-435 41 N RC Charging 2B-3 CV-517 41 N RC Charging 2B-4 CV-519 41 N RC Charging 2B-5 CV-518 41 N RC Charging 7A ILRT-1 20 Y Tag Inside Cont. Alignment (B1 Flange ILRT Test Installed) 7B ILRT-2 21 Y Tag Inside Cont. Alignment (B1 Flange ILRT Test Installed) 8-1 MOV-5462 83 Y Tag Outside Cont. Alignment (EAD-5462 Cont. Sump Shut) 8-2 MOV-5463 82 Y Tag Outside Cont. Alignment (Option A) Cont. Sump 9-1 SI-340 37 Y-Drain Tag Inside Cont. Alignment (SI-340 Installed) Cont. Spray Ahead 9-2 SI-326 37 Y-Drain Tag Inside Cont. Alignment (SI-340 Installed) Cont. Spray Ahead 10-1 SI-330 53 Y Tag Inside Cont. Alignment (SI-330 Installed) Cont. Spray 10-2 SI-316 53 Y Tag Inside Cont. Alignment (SI-330 Installed) Cont. Spray 13 Blind Flange 81 N Cont. Purge 14 Blind Flange 54 N Cont. Purge 15-1 CV-5292 51 Y Tag Inside Cont. Alignment (CRM-5291 Shut) Purge Air Monitor 15-2 CV-5291 51 Y Tag Inside Cont. Alignment (CRM-5291 Shut) Purge Air Monitor 16 CV-3832 55 Y-Drain Tag Outside Cont. Alignment (CC-3832 Shut) Component Cooling Ahead 18 CV-3833 52 Y-Drain Tag Outside Cont. Alignment (CC-3833 Shut) Component Cooling Ahead 19A-1 IA-175 71 N Instrument Air 19A-2 MOV-2080 71 N Instrument Air 19B-1 PA-137 73 N Plant Air 19B-2 PA-1044 73 N Plant Air

CONTAINMENT CLOSURE NO-1 -114 Revision 01700 Page 34 of 39 Page 2 of 3 Attachment 3, LLRT MATRIX (EXAMPLE) (Continued) STP-0-55A To be Pen. Equip. page # page worked with 55A set Tagging arrangement InnerlOuter Function 20A-1 N2-347 68 N Nitrogen Supply 20A-1 CV-612 68 N Nitrogen Supply 20A-1 CV-622 68 N Nitrogen Supply 20A-1 CV-632 68 N Nitrogen Supply 20A-1 CV-642 68 N Nitrogen Supply 20A-2 CV-612 68 N Nitrogen Supply 20A-2 CV-622 68 N Nitrogen Supply 20A-2 CV-632 68 N Nitrogen Supply 20A-2 CV-642 68 N Nitrogen Supply 208-1 N2-395 69 Y Tag Inside Cont. Alignment (N2-395 Nitrogen Supply Installed)) 20B-2 N2-348 69 Y Tag Inside Cont. Alignment (N2-395 Installed) Nitrogen Supply 20C-1 N2-398 70 Y Tag Inside Cont. Alignment (N2-398 Installed) Nitrogen Supply 20C-2 N2-349 70 Y Tag Inside Cont. Alignment (N2-398 Installed) Nitrogen Supply 21-1 Flanges 102 Y SG Sec. Manway 21-2 Flanges 102 Y SG Sec. Manway 22-1 Flanges 102 Y SG Sec. Manway 22-2 Flanges 102 Y SG Sec. Manway 23 CV-4260 26 Y-Tank Tag Inside Cont. Alignment (RCW-303 Shut) RC Drain Tank Empty 24 SV-6531 19 Y Tag Outside Alignment (PS-6513 US Key Quench Tank Rem.) 37-1 PSW-1020 36 Y-Drain Tag Inside Alignment (PSW-1020 L/Shut) Plant Water Ahead 37-2 PSW-1009 36 Y-Drain Plant Water Ahead 38 CV-5460 65 N Demin. Water 39-1 SI-455 35 Y-Drain Tag Outside Alignment(SI-463 L/Shut) SI Test Line Ahead 39-2 SI-463 35 Y-Drain Tag Outside Alignment (SI-463 LJShut) SI Test Line Ahead 41 MOV-651 56 N Shutdown Cooling 41 MOV-652 56 N Shutdown Cooling 42 Xter tube 94 Y Before Flooding Fuel Trans. tube 44-1 FP-145B 66 Y Tag Inside Alignment (FP-145B Installed) Fire System 44-2 FP-145-A 66 Y Tag Inside Alignment (FP-145B Installed) Fire System 44-3 MOV-6200 66 Y Tag Inside Alignment (FP-145B Installed) Fire System 47A-1 SV-6507-A 31 N Hydrogen Sampling 47A-2 SV-6540A 31 Y Tag Inside Alignment (PS-6507 L/S Key Hydrogen Sampling Rem.) 478-1 SV-6507E 32 Y Tag Inside Alignment (PS-6540E US Key Hydrogen Sampling SI _ I__ Rem.) 47B-2 SV-6540E 32 N I Hydrogen Sampling

CONTAINMENT CLOSURE NO-1-114 Revision 01700 Paae 35 of 39 Page 3 of 3 Attachment 3, LLRT MATRIX (EXAMPLE) (Continued) STP-0.55A To be Pen. Equip. worked with Tagging arrangement InnerlOuter Function page # 55A set 47C-1 SV-6507F 33 N Hydrogen Sampling 47C-2 SV-6540F 33 Y Tag Inside Alignment (PS-6540 US Key Hydrogen Sampling Rem.) 47D-1 SV-6507G 34 N Hydrogen Sampling 47D-2 SV-6540G 34 Y Tag Inside Alignment (PS-6540G US Key Hydrogen Sampling Rem.) 48A-1 MOV-6901 58 N Hydrogen Sampling 48A-2 MOV-6900 58 N Hydrogen Purge 48B-1 MOV-6903 59 Y Tag Inside Alignment (HP-1 04 Installed) Hydrogen Purge 48B-2 HP-104 59 Y Tag Inside Alignment (HP-104 Installed) Hydrogen Purge 49A-1 SV-6507B 43 N Hydrogen Sampling 49A-2 SV-6540B 43 Y Tag Inside Alignment(PS-6540B USh Key Hydrogen Sampling Rem) 49B-1 SV-6507C 44 N _ _ _ _ _ _ Hydrogen Sampling 49B-2 SV-6540C 44 Y Tag Inside Alignment(PS-6540C USh Key Hydrogen Sampling Rem) 49C-1 SV-6507D 45 N ... Hydrogen Sampling 49C-2 SV-6540D 45 Y Tag Inside Alignment(PS-6540D+E70 USh Hydrogen Sampling Key Rem) 50 ILRT Pen 67 Y ILRT Pressurization 59 SFP-178 22 N Refuel Pool 59 SFP-179 22 N Refuel Pool 60 ES-142 23 Y Tag Inside Cont. Alignment (ES-144 L/Shut) Stm. to Rx HD C/U Area 60 ES-144 23 Y Tag Inside Cont. Alignment (ES-144 L/Shut) Stm. to Rx HD C/U Area 61 SFP-180 24 N Refuel Pool Cooling 61 SFP-181 24 N Refuel Pool Cooling 61 SFP-182 24 N Refuel Pool Cooling 61 SFP-186 24 N Refuel Pool Cooling 62 MOV-6579 79 Y Tag Outside Cont. Alignment (PH-6579- Contain. Heat MOV) 64 PH-387 80 Y-Drain Tag Inner Alignment (PH-734) Contain. Heat Ahead 67 Eq. Hatch 95 Y Equipment Hatch 68 PAL 96 Y Personnel Air Lock 69 EAL 100 Y Emergency Air Lock 84 ILRT Vent 93 Y Tag Inner Flange ILRT Vent (U-2 Only)

CONTAINMENT CLOSURE NO-1-1144 Revision 01700 Page 36 of 39 Page lofl1 Attachment 4, CONTAINMENT CLOSURE STATUS SHEET FOR LLRTS When an LLRT begins, enter the Penetration No. and Name of the responsible personnel. Indicate whether Containment Closure is established for the penetration or a deviation exists. Enter the Start Time and Date. When the LLRT is finished, enter the Finish Time and Date. INTERFACE DIRECTLY WITH THE CONTROL ROOM OR THE OPERATIONS WORK CONTROL CENTER. Penetration Cntmt. Finish N.Name Closure Start Time Date TieDate N.(Yes/Dev.) _____ Time__

CONTAINMENT CLOSURE NO-1 -114 Revision 01700 Page 37 of 39 Page 1 of 3 Attachment 5, STPO-55A PERFORMANCE FLOWCHART Tech Spec SIR 3.9.3.1 within 7 days prior to the start of refueling, core alterations or planned inoperability of required SDC loops, Restore Closure deviations per NO-I-114 prior to entering the Tech Spec restricted closure condition.

CONTAINMENT CLOSURE NO-1 -114 Revision 01700 Page 38 of 39 Page 2 of 3 Attachment 5, STPO-55A PERFORMANCE FLOWCHART (Continued) R49 Perform STPO-55A per NO- 1-114 within 7 days prior to

                 ! entering Reduced Inventory.

Restore Closure deviations per NO-1-1 14 prior to entering the non-Tech Spec resuicted closure condition. Schedule the subsequent performances of STPO-55A per NO-1-114.

CONTAINMENT CLOSURE NO-1 -114 Revision 01700 Page 39 of 39 Page 3 of 3 Attachment 5, STPO-55A PERFORMANCE FLOWCHART (Continued) YES EL~~u§EIiI Perform STPO-55A per NO-1-1 14 and ensure deviations can be restored po to wvthin the TTB13 making the SGs unavailable.

FORM 1, ECP COVER SHEET (Page 1 of 5) ECP Supp No.: ECP-10-000208 Rev. No.: 0000 A. INITIATION - ENGINEERING SERVICE REQUEST (ESR) ESR No.: ESR-09-003787 F1 N/A Originator/Ext/Date: Printed Name Site (check one): Z CCNPP ZNMP [] REG Z UN'IT I [UNIT 2 El COMMON F1 ISFSI Requested Due Date and Reason: System: 009 Priority: Routine Equip ID: 1LITI100,1LITII01A, 1LITII01B, ILITI201A, ILIT1201B, ILITI301B, 1LITI401B, ILIT1501B, ILITI601B, 2LIT2101B, 2LIT2201B, 2LIT2301B, 2LIT2401B, 2LIT2501A, 2LIT2501B, 2LIT2601A, 2LIT2601B, 2LIT2100, 1LII 100, 2L12100 ER Component Classification E] Critical 0 Significant E] Economic El RTF El N/A WO No.: CR No. CR Category: Is this a request for a Temporary Change? [ Yes LI No Is this a request for Generic Engineering? Ei Yes [ No Reasons for Request/Problem Statement/Proposed Changes: This change installs nine (9) radar probes per unit with local indication to monitor intake structure level. At each unit intake structure, six (6) probes are installed downstream of the traveling screens, one (i) is installed upstream of the trash rakes, and two (2) are installed between the traveling screens and the trash rakes. This change provides a temporary local indication of level to meet a plant commitment. A permanent change installed per ECP 000209 uses radar probes installed in this change to provide remote indication of water levels to the control room. LI Check if additional sheets are attached (mark sheets with ECP No., Supplement and Rev. No., as applicable) APPROVAL: Date: Originator's Supervisor / Workgroup Lead TRB APPROVAL (New MODS and some EQVs (Section 5.2.B) require TRB approval.) [I N/A TRB Approval Meeting Date: LI Standby 20/40 List Date: Z Active 20/40 List Date: 9/16/2009 Account No.: N02711 CNG-FES-015 Rev. 00002

FORM 1, ECP COVER SHEET (Page 2 of 5) ECP Supp No.: ECP-10-000208 Rev. No.: 0000 B. INITIAL ENGINEERING SCREEN AND ASSIGNMENT E] N/A PRELIMINARY SERVICE TYPE DETERMINATION [] Engineering Response f Administrative Document Change E . Engineering Evaluation .] Equivalent Change F] Commercial Change F] DC 0; Design Change Z Modification El EQV i El Setpoint El Document Change RESPONSIBLE ENGINEER: SUPERVISOR: SYSTEM ENGINEERING REVIEW/APPROVAL [: N/A System Engineer/Supervisor Brad Wright F] Approved [] Disapproved (Printed Name/Signature) 0l Check if additional sheets are attached (mark sheets with ECP No., Supplement and Rev. No., as applicable) C. FINAL SERVICE SERVICE CLASSIFICATION: El SR 0 ...NSR T - -----. .. . El Augmented Quality F] Generic Engineering 0 Temporary Change SERVICE PERFORMED (check one) F] ....

        ...Engineering E.g.ne  I. ...
                   ........          n..Response.. iu - ~ .....
                                                                                      .........................             i F]
                                                                                                         ..... .. ............ * .. .. .~Administrative
                                                                                                                        .........                           g -. . . . .. Change u- a - n C ia Document        . . .... . .. .. .... .. . ...

E] Engineering Evaluation ElF Equivalent Change E] Commercial Change F] DC 0 Design Change 0 Modification F] EQV F] Setpoint F] Document Change COMMENTS L- L r-- o%-, CNG-FES-015 Rev. 00002

FORM 1, ECP COVER SHEET (Page 3 of 5) ECP Supp No.: ECP-10-000208 Rev. No.: 0000 ECP RISK SCREENS Technical Task Risk Rigor Assessment (CNG-CM-1.01-2000): Assessment required: Z YES El No (If"No" proceed to QRT Risk Ranking) Consequence Risk Factors Identified: Z YES [No If "YES," complete Human Performance and Process Risk Evaluations and any additional actions required by CNG-CM-1.01-2000. Include summary of results in ECP. - Attachment 12 If"No," proceed to QRT Risk Ranking Independent Third Party Review Screen Results: E] 1 2 F1 3 0 4 Third Party Review Required: [E YES 0 No IF YES, TYPE: Third Party Review Completed: [] YES F1 No E NOT REQUIRED QRT Risk Ranking (CNG-CM-1.01-1000): 0 Red E] Yellow II Green Z N/A ECP SUPPLEMENT INVENTORY Inventory all Forms and attachments, issued with this ECP Supplement, which do not have unique document identification numbers. Ensure all products issued with unique document identification numbers are electronically linked to the ECP Supplement in FCMS. Form # refers to CNG-FES-0 15 form numbers u~nles otherwise snecified. Form # Title Number Comments of Pages [ Attach. 12 Design Inputs and Change Impact Screen 14 CNG-CM-1.01-1003, Att 12 El 6 EQV Technical Evaluation 7 Design Change Technical Evaluation 2 7A DC Technical Evaluation Continuation 6 7B DC Technical Evaluation Continuation 8 Operational Impact Statement 2 9 Installation and Testing Requirements 10 11 ECP Material List 1 LI 12 Engineering Evaluation z 13 Record of Walkdown 2 16 Fire Protection/Appendix R Review Electrical 2 Design Features Checklist z 17 Fire Protection/Appendix R Review Fire 2 Protection Design Features Checklist 18 Design Review For ALARA Good Practices lI 10 CFR 50.59/72.48 Screen CNG-NL-1.01-101 1, Aft 2 TO/CO Plan No.: 201000229 CNG-FES-015 Rev. 00002

FORM 1, ECP COVER SHEET (Page 4 of 5) ECP Supp No.: ECP-10-000208 Rev. No.: 0000 REVIEW AND APPROVAL - Sargent & Lundy LLC: Responsible DvdJ od . Engineer: David J. Goode (S&L) / (Printed Nen¶ and Signature) te: (If Required) Professional [ N/A Engineer: (Printed Name, Signature, and Requal Date) Date: Is Design Verification Required? E Yes [ No If yes, Design Verification Form is 0 Attached L Filed with: Independent Reviewer. Angelo A. Emanuele (S& " (Printed Name and Signature) Date: Additional Jeff J. Grajewski (S&L ) - Preparer Printed Name k-ignature Date Additional Carol D. Frantilla .3 .,T ,/ , Reviewer Printed Name and Signature Date Additional ] Reviewer A__nted Name and St ature Date Approved0 Printed Name and Sia Date ECP Cause Code (Section 5.1.1): 0 CNG-FES-015 Rev. 00002

FORM 1, ECP COVER SHEET (Page 5 of 5) ECP Supp No.: ECP-10-000208 Rev. No.: 0000 IMPLEMENTATION REVIEW/APPROVALS I/A (if not required) Engineering Manager: spwA~tj ý, T:1AL4 Date: c ~i (Printed Name and Signature) PORC/PLANT GENERAL MANAGER REVIEW/APPROVALS Z N/A (if not required) PORC Meeting No.: Date: (Printed Name and Signature) PORC Chairman: El Approved F- Disapproved (Printed Name and Signature) Plant General Manager: El Approved E] Disapproved (Printed Name and Signature) CNG-FES-015 Rev. 00002

ATTACHMENT 12, DESIGN INPUTS AND CHANGE IMPACT SCREEN [CNG-CM-i.01-1003, ATTACHMENT 12](Page 1 of 14) ECP Supp No.: ECP-10-000208 Rev. No.: 0000 I Applicable Action Sect Design Input or Change Impact Yes No Tracking CNG-FES-007, Preparation of Design Inputs and Change Impact Screen, shall be used in preparation of 2. CNG-FES-007 provides detailed screening questions for each section of this screen to assist in determining the correct overall screening result for each topic. The column titled "Sect" refers to the applicable section of CNG-FES-007. CNG-FES-007 also provides recommended actions for any "Yes" answers. Review and approval of attachment 12 is indicated by review and approval of the ECP. 5.4.1 Mechanical/Civil/Structural Design: Does the Engineering Change 0 El involve any Mechanical System characteristics where design limits are placed on the mechanical properties of a system or components? Does the Engineering Change involve any Civil/Structural requirements where limits are placed on the structural properties of an SSC such as equipment foundations and component supports? 1FB02411 A mechanical assembly is required for radar probe mounting in existing penetrations. In addition, since the man holes are located in the open, the electronics modules protrude above ground and are exposed to weather and other hazards from personnel working in the area. For this reason, a protective structure is also designed around the probe to prevent damage. See Form 7/7A for evaluation of this design. To install conduit for radar probes ILITI 100, ILITI 101B, ILIT120IA, 2LIT2501A, 2LIT260IA, and 2LIT2100, concrete must be cut in the intake structure. See Form 7/7A for an evaluation of the structural integrity of the intake structure per this change. 5.4.1.1 Containment Sump Recirculation Issue (CCNPP and Ginna, only): E 11 Does the Engineering Change affect inputs or assumptions made in containment sump testing and analysis? Does the Engineering Change affect or impact commitments in response to Generic Letter 2004-02? 5.4.1.2 Managing Gas Accumulation in Emergency Core Cooling, Decay Fl - [ Heat Removal, and Containment Spray Systems: Does the Engineering Change involve the potential introduction of gas into the Emergency Core Cooling System, the Decay Heat Removal System, or the Containment Spray System or involve the potential failure of managing gas accumulation in the subject systems? [FB05091

5.4.2 Valves

Does the Engineering Change involve or impact motor operated E] Z valves, air operated valves, relief valves or check valves? Does the Engineering Change involve or affect valve packing?

5.4.3 Flooding

Does the Engineering Change impact or affect internal or I] [] external flooding analysis? I CNG-CM-1.01-1003 Rev. 00200

ATTACHMENT 12, DESIGN INPUTS AND CHANGE IMPACT SCREEN [CNG-CM-1.01 - 003, ATTACHMENT 12](Page 2 of 14) ECP Supp No.: ECP-10-000208 Rev. No.: 0000 SApplicable Action Sect Design Input or Change Impact Yes No Tracking 5.4.4 HVAC: Does the Engineering Change impact or affect HVAC or HVAC E [ loading? 5.4.5 Thermal Fatigue: Does the Engineering Change affect SSCs or piping [] [ in the Thermal Fatigue Program? 5.4.6 Control Room Habitability: Does the Engineering Change impact I] z Control Room Habitability? IFB02431

5.4.7 Seismic

Does the Engineering Change add, relocate, or alter Seismic Category I mechanical and/or electrical components that impact the Seismic Qualification? This change installs non-safety related components in the intake structure. The radar probe mountings were evaluated for Seismic Category II over I criteria in Form 7/7A, Design Change Technical Evaluation. 5.4.8 Structural Barriers: Does the Engineering Change impact or change the E] [ functional performance of any plant structural barrier?

5.4.9 Coatings

Does the Engineering Change require the application or removal of a protective coating or change any coating specifications or procedures? 5.4.10 ElectricatlI&C Design: Does the Engineering Change involve any T El Electrical requirements where limits are placed on the electrical properties of a system or components? Does the Engineering Change involve any Instrument Control requirements, including digital technology requirements? IFB02421 IFB02551 This change installs a total of 18 radar level probes (9 per unit) at penetrations in the intake structure. See Form 7/7A for technical evaluation of these components. Power to all radar level probes is supplied via temporary 24Vdc power supplies installed centrally to probe locations. Junction boxes are installed to distribute power wiring. See Form 7/7A for power supply evaluation. Each radar probe comes with a local indicator that relies on firmware for setup. A Cyber Security Assessment shall be performed in accordance with 201000229 Form 10, Turnover Closeout Plan. Temporary conduit is installed per this change for power cable for radar probes that are installed upstream of the traveling screens. See Form 7/7A for further evaluation of conduit. CNG-CM-1.01-1003 Rev. 00200

ATTACHMENT 12, DESIGN INPUTS AND CHANGE IMPACT SCREEN [CNG-CM- 1.01- 1003, ATTACHMENT 12](Page 3 of 14) ECP Supp No.: ECP-10-000208 Rev. No.: 0000 Aplicable Action SeADesign Input or Change Impact Sect Yes No Tracking 5.4.10.1 Transmission System Impacts: Does the Engineering Change impact El Z the transmission system? 5.4.11 10CFR50.49 Environmental Qualification: Is the Environmental El Qualification (EQ) of equipment is affected? I 1 5.4.12 Human Factors: Are there any Human Factors requirements introduced 11 z by the Engineering Change? 5.4.13 Station Blackout: Does the Engineering Change impact any station E [ blackout analysis or procedures? 5.4.14 Reactivity, Nuclear Fuels: Is there any impact on nuclear fuel, core components, core design, reactivity management, criticality control and accountability of nuclear materials as well as transient and /or accident analysis? [FB02471 1FB0252] 5.4.15 jNMP Only] BWR Vessel Internals Program (BWR VIP): Does the Engineering Change impact the BWR Vessel Internal Program? LI 5.4.16 Fire Protection/Appendix R: Does the Engineering Change affect any E [] fire protection/suppression equipment, change combustible loading, or impact the Fire Protection Program? Does the Engineering Change impact the plant's ability to safely shutdown in the event of an Appendix R Fire? All components installed per this change are located outside the plat and do not have any fire protection requirements. However, cable installed should comply with IEEE 383 standards at the recommendation of the fire protection engineer. See forms 16 & 17 as required. 5.4.17 PRA: Does the Engineering Change affect the existing Probabilistic Risk El E Assessment (PRA), Mitigating System Performance Index (MSPI) Basis Document PRA content, and shutdown risk models? 5.4.18 NFPA 805: Does the Engineering Change impact the analysis or assumptions of the NFPA-805 Program? CNG-CM.1.01-1003 Rev. 00200

ATTACHMENT 12, DESIGN INPUTS AND CHANGE IMPACT SCREEN [CNG-CM- 1.01 - 1003, ATTACHMENT 12](Page 4 of 14) ECP Supp No.: ECP-10-000208 Rev. No.: 0000 Applicable Action Sect Design Input or Change Impact Yes No Tracking 5.4.19 Safety Classification: Does the Engineering Change require a change in z El safety classification or category for any SSC? This change adds new components as defined in Form 7/7A Design Change Technical Evaluation. 5.4.20 Equipment Database(s): Does the Engineering Change require changes 1 1 1 to the equipment technical database(s)? Radar probes installed are given ComplDs and added to the FCMS database per this change. See form 7/7A for a list of ComplDs and descriptions. Cables installed are temporary and not scheduled. Therefore, this change does not impact CRS. 5.4.21 Equipment Reliability: Does the engineering Change add, remove or z El modify equipment with critical functions or require classification of new equipment to determine equipment reliability classification? The radar level probe system was chosen based on successful demonstration at CCNPP. However, since these are new components, an equipment reliability classification shall be performed at project closeout per 201000229 Form 10, Turnover Closeout Plan. 5.4.22 SPV: Does the Engineering Change impact single point vulnerability El z (SPV) so as to add to the potential to cause an unplanned reactor SCRAM? 5.4.23 Maintenance Rule: Does the Engineering Change impact maintenance 1 1 I rule SSCs or impact the Maintenance Rule Program? 5.4.24 EPIX: Does the Engineering Change affect the existing Equipment ] 1 T Performance Information Exchange (EPIX) database? 5.4.25 License Renewal: Does the Engineering Change potentially impact the El z results or conclusions of a License Renewal Aging Management Review, Aging Management Program, or Time Limited Aging Analysis or affect any License Renewal Commitment? 5.4.26 IST/1SI Program: Does the Engineering Change result in changes in E]l plant configuration, calculations, or safety analyses that may create or eliminate safety functions which fall within the scope of the IST/ISI program, or require changing surveillance test/acceptance criteria? CNG.CM-1.01.1003 Rev. 00200

ATTACHMENT 12, DESIGN INPUTS AND CHANGE IMPACT SCREEN [CNG-CM- 1.01-1003, ATTACHMENT 12](Page 5 of 14) ECP Supp No.: ECP-10-000208 Rev. No.: 0000 Sect Design Input or Change Impact Applicable Action Yes No Tracking 5.4.27 FAC: Does the Engineering change have the potential to impact the Flow 11 z Accelerated Corrosion program? 5.4.28 Thermal Performance: Does the Engineering Change plant efficiency or electrical megawatt output or their measurement in a way that may impact thermal performance monitoring? 5.4.29 Appendix J: Does the Engineering Change modify any containment El [] penetration or containment leakage criteria in a manner that will impact the Appendix J Program? 5.4.30 Boric Acid Program Impact: Will any new component or system by El z added or installed near a boric acid system or a credible boric acid leak path? 5.4.31 Periodic and Surveillance Testing: Does the Engineering Change Z necessitate changes to periodic or surveillance testing? 5.4.32 System Engineering: Does the Engineering Change require active Z El involvement on the part of System Engineering? This change adds new components for level monitoring. The system engineer has been engaged in the design and operation of these components installed in the intake structure. 5.4.33 ALARA: Are Radiation Protection/ALARA programs impacted by the El z Engineering Change that affect any of the following during normal or post accident conditions: Radiation sources, changes affecting controlled radiation areas, primary coolant fluid systems (Cobalt Materials); contaminated systems; radiation monitoring systems; HVAC Systems which could transport airborne contaminants; change or alter shielding? This change is installs equipment located outside and not exposed to radiation. 5.4.34 Environmental Impacts: Are there environmental conditions and z impacts affected by the Engineering Change? CNG-CM-1.01-1003 Rev. 00200

ATTACHMENT 12, DESIGN INPUTS AND CHANGE IMPACT SCREEN [CNG-CM-1.01-1003, ATTACHMENT 12](Page 6 of 14) ECP Supp No.: ECP-10-000208 Rev. No.: 0000 Applicable Action Sect Design Input or Change Impact Yes No Tracking 5.4.35 Emergency Preparedness: Does the Engineering Change potentially El Z impact the existing Emergency Plan or environmental or discharge monitoring that are used to prevent undue risk to public health and safety? 5.4.36 FSAR/Tech Spec/TSB/Regulatory Commitments: Does the change E] 0 alter any statement or commitment in the UFSAR (A thorough review of the UFSAR is required)? Does the change result in non-compliance with the Technical Specifications or the Technical Specifications' Bases? Does the change modify or delete any regulatory commitment? 5.4.37 Security: Does the Engineering Change involve any Security procedures El [ or requirements such as site monitoring, alarm systems, vehicle barrier systems, security and security lighting? 5.4.38 NEIL: Does the Engineering Change have any impact on the El 0 requirements of any applicable Nuclear Electric Insurance Limited (NEIL) Insurance Standard, or other appropriate insurance standards? 1FB02441 1FB02451 5.4.39 Information Technology: Does the Engineering change affect plant systems computer hardware, firmware, software, or data or analytical I] Dl software used in the design or analysis of plant systems, structures, or components? Does it modify or add a digital device in a plant system? Cyber Security Assessment shall be performed for firmware on each probe per 201000229 Form 10, Turnover Closeout Plan. 5.4.40 Industrial Safety: Are there any Industrial Safety requirements such as El restricting the use of dangerous materials, hazardous chemicals, escape provisions from enclosures, pertinent OSHA requirements, and grounding of electrical systems? Radar probes are installed in penetrations that are in traffic areas on the intake structure. The probes protrude up from the cement structure and create a walking hazard. A protective cover is designed to protect the radar probes, but shall also be externally marked to bring attention to personnel in the area to avoid a tripping hazard. In addition, installation requires opening of metal grating upstream of the traveling screens. Fall protection requirements shall be implemented during this installation. CNG-CM-1.01-1003 Rev. 00200

ATTACHMENT 12, DESIGN INPUTS AND CHANGE IMPACT SCREEN [CNG-CM-1.01-1003, ATTACHMENT 12](Page 7 of 14) ECP Supp No.: ECP-10-000208 Rev. No.: 0000 Sect Design Input or Change Impact Applicable Action Yes No Tracking 5.4.41 Margin: Does Engineering Change reduce design or operating margin or address an existing margin issue identified on the station Low Margin List? 5.4.42 Operating Experience (OE): Are there any applicable Operating T E ] Experience listed on the INPO internet site or equivalent sources that are applicable to this Engineering Change? 1FB0242] IFB02461 1FB0247] An OE search on the INPO website resulted in several hits relating to intake structure level. However, all of these events were associated with the circulation pump control and SCRAM aspect due to decreased level. This change only provides local indication of intake structure level and does not include any control or reactor SCRAM functions. Operating Experience OE27386 is for spurious alarms caused by Ohmart-Vega VEGAPULS 65 radar transmitter installed to measure Caustic Storage Tank Level. The cause of this event was splashing the radar probe with sodium hydroxide during filling. A solution from the vendor was to adjust the signal-to-noise ratio for the transmitter so it remains stable during splashing or unstable tank event. For this change, the vendor has demonstrated the performance on-site for this application dealing with foaming and it has been found to be acceptable by CCNPP personnel. An additional result of the OE is the vendor discovered multiple echoes due to the fact that the measurement is in an enclosed tank. Since this change is not an enclosed tank, this is not a concern with relation to the transmitter location and mounting. 5.4.43 Training: Are there any changes to or additional training requirements FzT required by the Engineering Change? IFB02521 _ Ohmart/Vega radar probes are new components to CCNPP. Personnel shall be trained for the operation and setup of these components per TRR CCNPP-2010-351 as required in 201000229 Form 10, Turnover Closeout Plan. 5.4.44 Simulator: Does the Engineering Change necessitate any changes to E 11 simulator hardware, programming, labels, programming, or training requirements? 5.4.45 Procedures: Are there any procedure changes caused by the Engineering [ [2 Change? This change installs new components for monitoring intake structure level. Impacts to existing plant procedures are to be determined by CCNPP per 201000229 Form 10, Turnover Closeout 5.4.46 Operational Impact: Does the Engineering Change potentially change El z] any Operational Requirements? I 5.4.47 Load Handling: Does the Engineering Change impact any load handling El Z procedures or load path analysis; are there any specific load handling requirements for installation, implementation, or removal associated with the Change? CNG-CM-1.01-1003 Rev. 00200

ATTACHMENT 12, DESIGN INPUTS AND CHANGE IMPACT SCREEN [CNG-CM- 1.01-1003, ATTACHMENT 12](Page 8 of 14) ECP Supp No.: ECP-10-000208 Rev. No.: 0000 DApplicable Action Sect Setj Design Input or Change Impact Yes No Tracking 5.4.48 Personnel: Are there any Personnel Requirements and Limitations El Z associate with the Engineering Change, such as the need for trade specialists and engineering experts as well as support personnel, such as Radiation Chemistry technicians, welding technicians with special expertise, use of specific contractor or station procedures for installation or the need for mock-ups for training, installation, or operation? 5.4.49 Special Procedures & Specifications: Are there any special procedures and installation specifications that apply, but are not part of the normal T] z installation procedural direction? CNG-CM-1.01-1003 Rev. 00200

ATTACHMENT 12, DESIGN INPUTS AND CHANGE IMPACT SCREEN [CNG-CM-1.01-1003, ATTACHMENT 12](Page 9 of 14) ECP Supp No.: ECP-10-000208 Rev. No.: 0000 Applicable Action Sect Design Input or Change Impact Yes No Tracking 5.4.50 Impacted Organizations: Does the Engineering Change impact any Z El interfacing departments such as Operations, System Engineering, Training (including Plant Simulator), Maintenance, Reactor Engineering, Radiation Protection and others? Indicate the organizations that may be impacted by the proposed activity by checking the appropriate boxes. Use blanks for unlisted organizations or individuals. Engineering Z Mechanical/Civil Design Engineering Z Systems Engineering " Electrical/I&C Design Engineering El Engineering Programs " Nuclear Fuel Services El Fire Protection Engineer " Engineering Equipment Reliability El Appendix R Engineer " Procurement Engineering El El _ __ __ _ Other Organizations Z Operations Z Maintenance - E&C E Chemistry El Planning - Mechanical E Licensing Z Planning - E&C E Rad Protection Z PDU Z Maintenance - Mechanical Z Nuclear Training E Maintenance Support El El Outage Management El El El_ _ 5.4.51 Walkdown Requirements: Determine the need for walkdowns to look I El at accessibility to the work area(s) and any special installation considerations that need to be addressed during design development Z 10%(pre-design) El Turnover E] 50% E] Other (Specify)_ Z 90% (post-design; prior to ECP approval) Z Other (Specify) Designer Walkdown for Layout 5.4.52 1 Design Progress Meetings: Determine the need for design progress T]T [] meetings during design development Z 10% (pre-design) E] Other (Specify)_ El 50% E] Other (Specify)_ Z 90% (post-design; prior to ECP approval) El Other (Specify) CNG-CM-1.01-1003 Rev. 00200

ATTACHMENT 12, DESIGN INPUTS AND CHANGE IMPACT SCREEN [CNG-CM- 1.01-1003, ATTACHMENT 12](Page 10 of 14) ECP Supp No.: ECP-10-000208 Rev. No.: 0000

                                                                                        ý A plicable     Action Sect                             Design Input or Change Impact                           Yes      No  Tracking Waiver of Required Walkdowns or Design Progress Meetings: Step 5.3F.5.f allows for waiver of any Walkdown or Design Progress Meeting required by Step 5.3F. Rationale for and approval of such waivers shall be documented in this space:

Approval: Printed Name & Signature Date The space below may be used for documenting any additional results of the Responsible Engineer/Engineering Supervisor Initial Meeting (Record notes, decisions, and actions) Technical Task/Risk-Rigor Assessment Page 1 of I Attachment 1, Determination of Consequence Factors HIGH CONSEQUENCE - If the change is not correctly evaluated and addressed, can it result in: YES NO Personal injury, safety issue Z " Hot environment / heat stress " Diving activities " Hazardous materials " Radiological Hazards >1 Rem for job, Dose rate > 1 Rem/hr. " Any unmonitored release Reactivity Management Event El Scram El [ Operability issue involving multiple trains of a safety related system operability El E Unplanned Safety System Actuation/Loss El E MEDIUM CONSEQUENCE - If the change is not correctly evaluated and addressed, can it result in: YES NO Regulatory non-compliance (environmental, NRC, State) El E Lost/limited Generation (2:5%)/6 Adverse impact on outage (>-2 hours) or project critical path El [ Operator Workaround or Challenge created or not addressed El E Introduction of foreign material E] Z Reactor coolant or steam generator' chemistry transient outside of acceptable band. El Z Operability Issue involving one train of safety related equipment El E Tech Spec violation Sl [ Reportable environmental consequence or violation El D LOW CONSEQUENCE - If the change is not correctly evaluated and addressed, can it result in: YES NO Unplanned Component Unavailability El[ Unbudgeted financial consequences (?$50K) El Z CNG-CM-1.01-1003 Rev. 00200

ATTACHMENT 12, DESIGN INPUTS AND CHANGE IMPACT SCREEN [CNG-CM-1.01-1003, ATTACHMENT 12](Page 11 of 14) ECP Supp No.: ECP-10-000208 Rev. No.: 0000 I Applicable Yes No Action Tracking Sect Design Input or Change Impact Unplanned entry into a Tech Spec shutdown LCO EU Z Unplanned Security vulnerability El] 0 Aggregate review: Are there any activities, conditions, or situations that, when combined with this activity, could El 0 cause undesirable consequences? Repeat functional failure of Maintenance Rule systems, structures or components with potential to create new (a) (1) system. Unplanned Fire Protection Vulnerability " Emergency Plan affected EU Z

• High sensitivity issue with public or Regulator Other unacceptable consequence not listed

" Security compensatory actions " Fire protection compensatory actions "Emergency plan affected "NPDES permit affected " High sensitivity issue with public or regulator. "Potential adverse reduction in safety or production margins "Other Attachment 2, Determination of Risk Factors HUMAN PERFORMANCE RISK FACTORS- Is the likelihood of a technical errorincreased by: YES NO Overconfidence/complacency, "can-do" attitude El E Mental state (such as stress, illness, fatigue) E] 0 Conflicts (personality) U1 0 Knowledge/experience, low proficiency lack of skills/training/qualification. El 0 First time or non-routine evolution D 0 Method changed or new process/procedure El 0 Infrequently performed EU Z Frequently performed (habit intrusion), repetitive actions or monotony LI 0 High Complexity El E Inadequate information available/problem not clearly understood E]U Availability/complexity of tools U OZ Group think, lack of independence 111 High workload/schedule pressure z 11 Distraction/interruptions EU 0 Availability of resources (people) E] 0 Unclear goals, roles, responsibilities Ul 0 Lack of or unclear standards 11 E Omission/failure to revise required document EU 0 Other issues: E] 0 PROCESS RISK FACTORS YES NO Is the exact scope of the task NOT completely understood? El Z Are there parts of the task process/procedure that cannot be followed? Are we Out-Of-Process (OOPS)? Are there parts of the task the current process does not address? El E Are parts of the process or task not understood, unclear, or controversial E] ED Is task on a fast track? 0 Ul CNG-CM-1.01-1003 Rev. 00200

ATTACHMENT 12, DESIGN INPUTS AND CHANGE IMPACT SCREEN [CNG-CM- 1.0 1- 1003, ATTACHMENT 12](Page 12 of 14) ECP Supp No.: ECP-10-000208 Rev. No.: 0000 Applicable Action Sect Design Input or Change Impact Yes No Tracking Is an outside organization, including external design organizations and equipment vendors, providing significant inputs? Are the critical parameters NOT known? E [ Are all the tools, programs, and procedures necessary for the task NOT available and useable? E [ Is design basis NOT known? Are multiple parties or disciplines involved such that errors may be introduced via communication channels or E 0 coordination? I Is this a Station first-time action, configuration change or process: El Z Is this a First of a Kind task? Will the product or process result in operation outside of industry Operating Experience? Is it the first application of this technology or methodology in the nuclear industry? Other factors not listed: El [ TOTAL number of applicable Risk Factors 3 ( Medium Consequence ) and ( <=3 Risk Ranking Factors ) = Requires normal review by station. Page 1 of3 Attachment 4, Technical Task Pre-Job Brief Form Supervisor Performing Brief: Brad Wright Date of Brief: 4/8/2010

Participants:

David Dvorak - CCNPP Document/Task ID: David Goode - S&L ECP-10-000208 Task

Description:

Intake Structure Level Radar Probe Installation - Temporary Installation Resources and Estimated Time to Complete: Task Due Date/Time: 4/30/2010 Minimum Briefing Expectations Key Briefing Points Define Scope: Install 18 radar level probes (9 per unit) at the intake Clearly define the task and what the task entails (scope). structure for level monitoring. Each unit will have 6 Discuss how the scope of the task was validated, installed downstream of the traveling screens and 1 upstream of the trash rakes. Additionally, a probe is installed on the bay side of traveling screens 1 B and 12A (Unit 1) and 25B and 26A (Unit 2). All radar probes will provide local level indication, except those installed upstream of the trash rakes. These probes will have a remote indicator mounted near the transmitter. Roles and Responsibilities: Design to be prepared by S&L Clearly define roles and Responsibilities (such as In-house RE is Dave Dvorak performer, preparer, checker, independence of verifier, project coordinator, corporate, Non Station Personnel). Critical Parameters: None Assumptions, inputs, or requirements that if allowed to be untrue or not met, would adversely affect the task outcome. Procedure/Standards: CNG-CM- 1.01-1003 Rev 02 (Design and Config.) Discuss and ensure proper understanding of the CNG-CM- 1.01-1004 Rev 00 (Temp Change Process) procedures and standards applicable to the task (such as CNG-CM-1.01-1003 Rev. 00200

ATTACHMENT 12, DESIGN INPUTS AND CHANGE IMPACT SCREEN [CNG-CM- 1.01-1003, ATTACHMENT 12](Page 13 of 14) ECP Supp No.: ECP-10-000208 Rev. No.: 0000 Design Input or Change Impact A iYesNo Tracking Sect Equipment Reliability, Configuration Control, Standards, CNG-CM-1.01-2003, Rev 00 (Owner Acceptance) and Industry Codes & Standards) Bring copy (copies) of governing process procedure for the task to the brief. List all output products (ECN, etc) RE to develop Forms Training and Qualification: None Review personnel qualifications. Establish appropriate mentoring and oversight of appropriate. Lessons Learned: Clearly identify mounting details and ensure hardware Discuss previous lessons learned and experience specified on BOM is consistent with mounting. (Operating Experience, Corrective Action Program & individual) that may be applicable to this task, particularly those involving human performance errors. Fundamentals: Discuss applicable fundamentals. Page 2 of 3 Attachment 4, Technical Task Pre-Job Brief Form (Continued) Additional Briefing Topics validate the risk factors chosen with the briefing members. Consequence Mitigation: For each consequence factor identified in Attachment 1, list the factor and the actions to be employed. Consequence Factors Compensating Action Owner Due Date NONE Human Performance Risk Mitigation: For each human performance risk factor identified in Attachment 2, list the factor and the actions to be employed to mitigate that risk. Risk Factors Compensating Action Owner Due Date High workload/schedule 1. S&L to use resources in 1. Goode 1. 4/30/2010 pressure (late design Chicago start - required for 6/1 commitment) 2. Coordinate CCNPP project 2. Wright 2. 4/30/2010 team for design inputs and review. Process Risk Mitigation: For each process risk factor identified in Attachment 2, list the factor and the actions to be employed to mitigate that risk. Risk Factors Compensating Action Owner Due Date CNG-CM-1.01 -1003 Rev. 00200

ATTACHMENT 12, DESIGN INPUTS AND CHANGE IMPACT SCREEN [CNG-CM- 1.01-1003, ATTACHMENT 12](Page 14 of 14) ECP Supp No.: ECP-10-000208 Rev. No.: 0000 Design Input or Change Impact Applicable Action Sect es I No Tracking Project on a fast track 1. Parallel reviews by S&L 1. Goode 1. 4/30/2010 and CENG Supplemental reviewers

2. Owner Acceptance 2. Wright 2. 4/30/2010 Review process Outside Design Communicate with vendor to Goode 4/30/2010 Organization confirm operation and setup of radar probes Page 3 of 3 Attachment 4, Technical Task Pre-Job Brief Form (Continued)

Tracking Required? Follow-up Action Owner Date Mechanism Yes Progress update S&L Weekly Project Schedule Yes 10%/ 50% 90% S&L As scheduled Project Schedule reviews No ITPR or CRB Additional Pre-job Brief No Other (specify) CNG-CM-1.01-1003 Rev. 00200

FORM 7, DESIGN CHANGE TECHNICAL EVALUATION (Page 1 of 2) ECP Supp No.: ECP-10-000208 Rev. No.: 0000

1.0 PURPOSE

(CNG-FES-007, SECTION 5.3.1)

• Provide an overview of the proposed activity and its interfaces.

This change installs eighteen radar level probes (9 per unit) in the intake structure to monitor level. Twelve radar level probes (6 per unit) are installed downstream of the traveling screens in existing penetrations located on the intake structure. Four radar probes (2 per unit) are installed between the trash rakes and the traveling screens. These components each contain local indication for monitoring. An additional two radar probes (I per unit) are located upstream of the trash rakes. These components are located under the intake structure grating and are not easily accessible for local monitoring due to safety requirements in proximity to the bay. As a result, remote indication modules are connected to these radar probes and installed on power racks located between traveling screens for monitoring. All radar probes are powered from 24Vdc power supplies (one per unit), distributed to each probe from local junction boxes also installed per this change. Installation of this change is a temporary configuration for the radar probes. The permanent installation will provide remote indication back to the control room per ECP-10-000209.

2.0 FUNCTIONS

(CNG-FES-007, SECTION 5.3.2)

• Basicfunctions of each structure, system, and component. (NQA-l, Question 1)

The basic function of the radar probes is to provide local indication to monitor intake structure level. All components installed per this change are expected to operate during all plant modes. However, instrumentation is for monitoring purposes only and is not credited for any function during off-normal, abnormal, or emergency operation.

• Interface requirements includingdefinition of the functional andphysicalinterfaces involving structures,systems, and components: (NQA-J, Question 7)

     " The effect on existing plant equipment capability,such as DC battery loads, AC bus capacity, availablestored water inventory, service instrument aircapacity,water systems capability (intake, service and component cooling water), and HVAC capability; Instrumentation installed per this ECP is powered through temporary 24Vdc power supplies that receive 120Vac power from local welding carts located in closed, ventilated rooms near screens 14B (Unit 1) and 25A (Unit 2). Welding carts are to be supplied by CCNPP prior to implementation of this change. See Form 7A for evaluation of the power supply.
     "    The effect of cumulative tolerances in the design; The changes associated with this ECP do not impact cumulative design tolerances.
     "    The effect on design and safety analyses to ensure the analyticalbases remain valid, Changes associated with this ECP do not impact the design of safety analyses.

• The compatibility with unimplemented design changes to specify any requiredsequence for implementation; Changes associated with this ECP are not impacted by unimplemented design changes.

     "    Compatibilit, with Technical Specification requirements.

Changes associated with this ECP do not have any Technical Specification requirements. 3.0 FAILURE EFFECTS: (CNG-FES-007, SECTION 5.3.3)

• Failureeffects requirementsof SSCs includinga definition of those events and accidents which they must be designed to withstand (NQA-l, Questionl9)

Instrumentation installed per this change is not credited for monitoring in any design basis event or accident. A failure of a radar probe would only result in the loss of local intake structure level indication. Separate instrumentation is relied upon for control CNG-FES-015 Rev. 00002

FORM 7, DESIGN CHANGE TECHNICAL EVALUATION (Page 2 of 2) ECP Supp No.: ECP-10-000208 Rev. No.: 0000 room indication of intake structure level and circulation pump control. Therefore, no failure effects requirements are associated with this change. Reliability requirements ofstructures,systems, and components including their interactions,which may impairfiunctions important to safety (NQA-I, Question 30) Instrumentation installed per this change is relied on for non-safety related local monitoring and does not interface with any systems or components providing control related to safety. Therefore, no equipment reliability requirements are associated with this change. 4.0 CODES, STANDARDS, REGULATORY REQUIREMENTS AND CLASSIFICATION: (CNG-FES-007, SECTION 5.3.4)

• Codes and standards, regulatory requirementsand commitments or responses to Federal.State, and Local Regulations (NQA-l, Question 3).

1. IEEE STD. 383 - Qualifying Class I E Electric Cables and Field Splices for nuclear Generating Stations, Rev, 2008

2. NFPA 70: NEC Handbook 2008

3. AWS D1.1, Structural Design and Welding

4. AISC Manual of Steel Construction, 7 th Edition or later

5. ACI 318-63 Building Code Requirements for Reinforced Concrete

5.0 REFERENCES

1. VTM 12335-030 - Ohmart-Vega Vendor Manual

a. Tab I - VEGAPULS 65 Operating Instructions

b. Tab 2 - PLISCOM Operating Instructions

c. Tab 3 - VEGADIS61 Operating Instructions

2. Phoenix Contact Data Sheet 102050_01_en- Power Supply Unit, Primary Switch Mode CONTINUATION Design Change Technical Evaluation must include FORM 7A or FORM 7B or both.

Z FORM 7A is attached [] FORM 7B is attached [] Additional Pages attached CNG-FES-015 Rev. 00002

FORM 7A, DESIGN CHANGE TECHNICAL EVALUATION CONTINUATION (Page 1 of 6) ECP Supp No.: ECP-10-000208 Rev. No.: 0000 6.0 DESIGN OPERATION AND PERFORMANCE REQUIREMENTS: " Performancerequirements such as capacity, rating,system output (NQA-J, Question 2). The maximum measurable range of the radar probes installed per this change is approximately 99 ft (Ref I). Each radar probe is mounted around the 10' elevation and required to measure intake structure level which reaches a maximum depth at the (-) 26' (below sea level) elevation corresponding to the bottom of the intake structure at the traveling screens. Therefore, the maximum range needs to encompass at least 40' to allow for some margin in the measurement. Therefore, the range of the probes is acceptable with respect to the process. To satisfy a plant commitment, the probes must provide local indication of intake structure level. All radar probes are equipped with an integral display mounted on the top of each module. The exception is the two probes installed under the front of the intake structure upstream of the trash rakes. Due to safety requirements required to access these components for monitoring, each has an indicator routed back to power racks between the nearest set of traveling screens. This location does not have any special safety requirements and is easier for personnel to view. As a result, this change satisfies the plant commitment to install local level indication at the intake structure. No existing accuracy requirements are placed on intake structure level monitoring. However, resolution is 0.039 in. with a deviation of+ 0.394 in. per (Ref. 1). This shall be used for operations to determine impact of local indicators on procedures.

• Design conditions such as pressure, temperature,fluid chemistry, and voltage. (NQA-I, Question 4)

Radar probes are 2-wire (loop powered) components powered by an external 24Vdc power supply. Each probe provides a 4-20mA output signal to its local indicator.

• Loads such as seismic, wind, thermal, and dynamic; the cumulative effect of design changes on the analyticaldesign basis.

(NQA-J, Question 5) See the structural requirements section below for an evaluation of the effects on loading due to this change. " Materialrequirements includingsuch items as compatibility,electrical insulationproperties,protective coatings, and corrosionresistance. (NQA-J, Question 8) All components installed per this change, including mounting assemblies, junction boxes and cables are located outdoors on the intake structure and exposed to the elements. Stainless steel shall be used to fabricate mounting assemblies to prevent rusting. Junction boxes shall have a rating of NEMA 4 or better, and cables shall be outdoor type to withstand exposure to weather.

• Mechanical requirementssuch as vibration, stress, shock, and reactionforces. (NQA-1, Question 9)

Each radar probe located downstream of the traveling screens is installed in an existing penetration using a mounting assembly designed per this change. The mounting assembly is made up of three sub-assemblies that are bolted together. The design of the assembly secures the radar probe to the intake structure, allows easy cable terminations and view of indication, and protects the radar probes from damage. Detailed drawings of the assembly and sub-assemblies can be found in Form 9, Installation and Testing Instructions.

• Structuralrequirements covering such items as equipment foundationsand pipe supports. (NQA-1, Question 10)

Water level monitoring instrumentation is to be mounted to the intake structure. Since the intake structure concrete is safety-related, these mountings will be analyzed per Seismic Category II over I criteria. The SSE loading condition will be conservatively considered with normal operating allowable loads. Unless noted otherwise, the peak acceleration is conservatively used to qualify the instrumentation supports, with 1% damping considered for SSE. The SSE accelerations are 1.875 x (6.20g) = I1.625g (use 11.7) horizontally and 1.875 x (0.5 Ig) = 0.956g (use 1.0) vertically. Accelerations are taken from the response spectrum curves in Calculation No. CA04085 Attachment F, for the intake structure. Form 9 Installation sketches 001 and 002 depict the mounting of the VEGAPULS 65 radar sensor and PLICSCOM adjustment module through penetrations in the concrete. The combined weight of the radar sensor and the module is about 7 lbs. The critical element of the support is the 1"x 1" x 1/8" angle in the penetration. The total weight of the support is approximately 50 lb, and the actual natural frequency of the support is about 39 Hz, which is in the rigid zone of the response spectra curves. The corresponding ZPA for all the curves is below unity, which is much less than the conservatively assumed peak accelerations. Therefore, all components of the support are considered acceptable by Engineering Judgement based on the small magnitude of the seismic loads. CNG-FES-015 Rev. 00002

FORM 7A, DESIGN CHANGE TECHNICAL EVALUATION CONTINUATION (Page 2 of 6) ECP Supp No.: ECP-10-000208 Rev. No.: 0000 Form 9 Installation sketch 003 depicts the mounting of the VEGAPULS 65 radar sensor and PLICSCOM adjustment module to the wall of the intake structure. The total weight of the equipment and mounting is approximately 17 lbs. Dead load plus peak SSE seismic load results in applied bending moments of Mx = 1000 in-lbs and My = 1000 in-lbs in the plane of the wall, and Mz = 826 in-lbs as a torsional moment perpendicular to the plane of the wall. These moments result in a maximum plate bending stress of 7.9 ksi, which is much less than the 22.5 ksi bending stress allowed for a stainless steel plate under normal operating loads. Thus, the plates are adequate for supporting the equipment. The 3/16" all-around fillet weld has a capacity of 2.98 kips/in, which is much greater than the applied dead plus SSE seismic weld stress of 0.73 kips/in. Therefore, the all-around fillet weld is acceptable. The dead plus SSE seismic tension in a single anchor is computed to be 427 Ibs, while the dead plus SSE seismic shear in a single anchor is computed to be 140 lbs. Given the allowable tension load of 683 lbs and an allowable shear load of 1261 lbs, the linear interaction ratio for the anchors is 0.73 which is less than 1.0 and is therefore acceptable. Form 9 Installation sketch 004 depicts the mounting of the VEGADIS 61 level indicator. The total weight of the equipment and mounting is approximately 30 lbs. The equipment is mounted to a 1/4" thick backing plate. Applying dead load and peak SSE seismic loads and considering the backing plate acting in one-way bending results in a plate bending stress of 14.4 ksi, which is less than the 22.5 ksi allowed for a stainless steel plate under normal operating loads, and therefore the plate is adequate. The anchors used are the same as in Installation Sketch 003 while the anchor forces here are less than those in Form 9 Installation Sketch 003. Thus the anchors are acceptable by comparison. Form 9 Installation sketch 008 depicts the mounting of the VEGAPULS 65 radar sensor and PLICSCOM adjustment module underneath grating. The total weight of the equipment and mounting is approximately 15 lbs. The actual natural frequency of the support is approximately 50 Hz, which is in the rigid zone of the response spectra curves. The corresponding ZPA for all the curves is below unity, which is much less than the conservatively assumed peak accelerations. Therefore, all components of the support are considered acceptable by Engineering Judgement based on the small magnitude of the seismic loads. In addition to the installation of instrument supports, a 3" deep trench will be excavated in the EL 10'-0" floor slab of the intake structure to accommodate buried conduit. The top I V2" of the concrete is concrete topping, and has no structural purpose. Thus, only I V2" of the concrete excavated is structural concrete. With the removal of the I V" of structural concrete, the moment capacity of the beam is reduced by approximately 15%, and this trenched portion of the slab will not see its design live load during this time. When the trenches are filled with concrete, after 28 days, the slab will be at full design capacity. Therefore, the removal of this concrete has an insignificant impact on the structural integrity of the EL 10'- 0" slab.

• Hydraulic requirements such as pump Net Positive Suction Head (NPSH), allowable pressuredrops, and allowablefluid velocities. (NQA-l, Question 11)

The changes associated with this ECP have no hydraulic requirements. " Chemistry requirements includingprovisionsfor system flushing, batch sampling and in-line sampling. Powerplant water chemistry treatmentfor primarysystems, steam generator,andplant limitationson water chemistry. (NQA-I, Question 12) The changes associated with this ECP have no chemistry requirements.

• Electricalrequirements such as source ofpower, load profile voltage, electricalinsulation, motor requirements,physical and electricalseparationof circuits and equipment; the effect of cable routingor reroutingon the cable tray system (loading,seismic capability,and capacityI imitations) (NQA-I, Question 13)

The radar probes are two-wire devices that are loop powered from two temporary 24 Vdc power supplies (one per unit, 9 probes each). Each radar probe has a maximum current of 22 mA. Therefore, each power supply must be able to supply the maximum current draw from each radar probe all at once or 248 mA (125% max). The Phoenix Contact power supply specified on Form I1, Bill of Materials has a maximum output current output of 1.5A (Ref 2). In addition, the power supply complies with DIN VDE 0106 for protection against electric shock (Ref. 2) as required by the radar probe (Ref. 1). Power is supplied via 2/C shielded 20 AWG cable for all radar probes. Power cable is distributed at junction boxes located inside each equipment where the power supplies are installed. Junction boxes are also installed at the far north end and far south end of the traveling screens to distribute power to radar probes upstream of the traveling screens. See Form 9, Installation and Testing Instructions for a detailed junction box layout. Wiring for the two remote indicators for ILITI 100 and 2LIT2100 is via a 4/C shielded 20 AWG cable routed in conduit along with its power cable. CNG-FES-015 Rev. 00002

FORM 7A, DESIGN CHANGE TECHNICAL EVALUATION CONTINUATION (Page 3 of 6) ECP Supp No.: ECP-10-000208 Rev. No.: 0000 Embedded conduit is installed to support the power cable for radar probes mounted upstream of the traveling screens and below the 10' elevation surface of the intake structure. Conduit below grade shall be encased in concrete per Form 9, Installation and Testing Instructions, and shall be Polystyrene Type I conduit per E-406 Section 105.3; all other conduit shall be rigid steel. The route for the conduit starts between traveling screens I IB/12A for ILITI 100, ILITI 101B and I LITI120 1A and between 25B/26A for 2LIT2100, 2LIT2501 A and 2LIT2601 A. Conduit is not scheduled per this change. See Form 9, Installation and Testing Instructions for detailed conduit routing. All other power cable installed per this change is unscheduled and field routed open air between junction boxes and radar probes. All cable shall be procured as non-safety related cable and takes exceptions to specification SP-317 as this change is to a non-safety related system. Cable selected contains PVC insulation and jacket; however, it meets the specifications for Class IE cable per IEEE 383. Therefore, it meets the recommendations from Fire Protection in Form 17, Fire Protection/Appendix R Review Fire Protection Design Features Checklist for flame retardant cable and is qualified to be installed in nuclear power plants. In addition, the cable is only rated to 300V rather than 600V. This is acceptable however, since this is a low voltage application (24 Vdc) that will never challenge the voltage rating of the cable. Since the permanent modification will route cable through conduit rather than free-air, all conduits are dedicated conduit and will not contain any other cables. Therefore, it is acceptable to procure cable as non-safety related cable as it will not be routed with any safety related cable upon permanent installation. " Operationalrequirements under various conditions,such as startup, normaloperation,shutdown, maintenance, abnormal or emergency operation, special or infrequent operationincluding installationof design changes, and the effect ofsystem interaction.(NQA-l, Question 15) The changes associated with this ECP are temporary and provide local indication of intake structure level during normal operation. They are not required to operate during any other plant condition.

• Instrumentationand control requirements including indicatinginstruments, controls, and alarms requiredfor operation.

testing, and maintenance. Other requirementssuch as the type of instrument, installedspares, range of measurement, and location of indicationare included (NQ,4-1, Question 16) This change installs radar level probes at the Unit I and Unit 2 Intake structure. Each radar probe is assigned a CompID per this change as follows: CompID Description ILITI 100 Unit I Trash Rake Upstream Radar Level ILITI 101A Traveling Screen I I Upstream Radar Level ILITI 101B Traveling Screen 11 Downstream Radar Level ILIT1201A Traveling Screen 12 Upstream Radar Level ILIT1201B Traveling Screen 12 Downstream Radar Level ILIT1301B Traveling Screen 13 Downstream Radar Level ILIT1401B Traveling Screen 14 Downstream Radar Level ILIT1501B Traveling Screen 15 Downstream Radar Level ILIT1601B Traveling Screen 16 Downstream Radar Level 2LIT2100 Unit 2 Trash Rake Upstream Radar Level 2LIT2601A Traveling Screen 26 Upstream Radar Level 2LIT2601B Traveling Screen 26 Downstream Radar Level 2LIT2501A Traveling Screen 25 Upstream Radar Level 2LIT2501B Traveling Screen 25 Downstream Radar Level 2LIT2401B Traveling Screen 24 Downstream Radar Level 2LIT2301B Traveling Screen 23 Downstream Radar Level 2LIT2201B Traveling Screen 22 Downstream Radar Level 2LIT2101B Traveling Screen 21 Downstream Radar Level CNG-FES-015 Rev. 00002

FORM 7A, DESIGN CHANGE TECHNICAL EVALUATION CONTINUATION (Page 4 of 6) ECP Supp No.: ECP-10-000208 Rev. No.: 0000 An integral indicator is mounted on top of the electronics module for each radar probe. Components ILITI 100 and 2LIT2100 are located inside a safety area that requires personal floatation gear for entry. Therefore, these probes are connected to indicators that are mounted on existing power racks between traveling screens that have no safety requirements to view. The level indicators are assigned the following ComplDs: CompiD Description ILII 100 Unit I Trash Rake Upstream Radar Level Indicator 2L12100 Unit 2 Trash Rake Upstream Radar Level Indicator The integral indicator also serves as the configuration/adjustment module. The initial setup and configuration of the radar probes is to be performed by the vendor with oversight from CCNPP. This setup shall be documented and maintained to support documentation required for the permanent installation of these transmitters per ECP-10-000209. Also see Form 10, Turnover Closeout Plan for this requirement. Redundancy, diversity, and separationrequirements of structures,systems, and components. (NQA-1, Question 18) Since the power supply and current signal are carried on the same two-wire cable, reliable separation shall exist between the supply circuit and the mains circuit per DIN VDE 0106 part 101. Fire protectionor resistancerequirements: Safe shutdown analyses, the introductionof safe shutdown equipment into fire areas; Routing of pipingand electrical cables and the necessityfor cable fireproofing and/orfire stops; Fire detection and fire suppressioncapability; Fire barriercapability includingfire door installation;Fire dampers; Access to fire fighting and emergency equipment; Use of non-combustible materials; Introducingcombustible materials into safe shutdown areas by design or during installationor operation; Smoke and toxic gas generation.(NQA- 1, Question24) The changes associated with this ECP do not have and Fire protection or resistance impacts. Cable installed at radar probes is approved per IEEE 383 to be flame retardant as recommended by CCNPP Fire Protection. See Forms 16 and 17 for Fire Protection and Appendix R screenings.

• Requirementsfor criticalitycontrol and accountabilityof nuclear materials (NQA-I, Question 32)

The changes associated with this ECP do not have any control or accountability of nuclear materials requirements. 7.0 APPLICATION ENVIRONMENT: (CNG-FES-007, SECTION 5.3.3) " Environmentalconditions anticipatedduring storage,construction, operation,and accident conditions, such as pressure, temperature,humidity, corrosiveness, site elevation, wind direction,exposure to weather,flooding, nuclear radiation, electromagneticradiation,and duration of exposure; qualification test requirements; shelfor service life limitations. (NQA-1, Question 6) All components installed per this change are located outside at the intake structure. It can be conservatively assumed that the outdoor temperature at the intake structure has a maximum range of 07F to I 10°F. All components installed per this change, except the power supply, are required to withstand exposure to rain, sleet and snow. In addition to the ambient (outside) temperature, the radar probes measure water level from the Chesapeake Bay that is conservatively assumed to have a temperature range of 32°F to 90'F. The radar level probes have an ambient rating of-40'F to 176°F (Ref. I) for their electronics unit, which is acceptable for the expected operating and storage range. In addition, each probe can measure a medium with a process temperature between -407F and 266°F (Ref. I), which is acceptable for the expected process temperature. In addition, each probe comes with an integral or remote indicating module with an ambient temperature rating of 5°F to 1587 (Ref. 3 and 4), which is just outside the lower end of the expected operating range. However, due to the nature of this change (non-safety related), the fact that the modules only provide local indication, and the unlikely probability that local indication would be desired during these extreme temperatures; the difference in rated and expected temperatures is acceptable. The power supply has an ambient temperature of 5'F to 158°F (Ref. 2), which is also just outside the lower end of the expected operating range. This is acceptable for the same reasons as the indicators. In addition, the power supply is mounted inside a structure, which is likely to be warmer than the outside temperature. CNG-FES-015 Rev. 00002

FORM 7A, DESIGN CHANGE TECHNICAL EVALUATION CONTINUATION (Page 5 of 6) ECP Supp No.: ECP-10-000208 Rev. No.: 0000 8.0 FIELD INTERFACE: (CNG-FES-007, SECTION 5.3.3)

• Layout and arrangementrequirements. (NQA-I, Question 14)

The changes associated with this ECP do not have layout or arrangement requirements.

• Test requirements includingpre-operationaland subsequent periodic tests and the conditions under which they will be performed. (NQA-l, Question 20)

Preliminary and Post-installation testing shall be performed as required per Form 9, Installation and Testing Instructions. No periodic testing is required per this change.

• Accessibility, maintenance, repairsandpre-service and in-service inspection requirementsfor the plant including the conditions under which these will be performed (NQA-1, Question 21).

The changes associated with this ECP do not have accessibility, maintenance, repairs or pre-service and in-service inspection requirements. Per VTM 12335-030, radar probes do not require periodic maintenance; however, it is suggested that a check of the instrument measurement against a field measurement be performed at intervals in accordance with the Equipment Reliability Classification established per 201000229 Form 10, Turnover Closeout Plan. " Personnelrequirements and limitations includingthe qualificationand number ofpersonnelavailablefor operation, maintenance, testing and inspection, and radiationexposures to the public andfacilitypersonnel. (NQA-1, Question 22) The changes associated with this ECP do not have personnel requirements or limitations.

• Safety requirementsfor preventingpersonnel injury including such items as radiationsafety, minimizing radiation exposure to personnel,criticalitysafety, restricting the use of dangerousmaterials, escape provisionsfrom enclosures, andgrounding of electrical systems (NQA-1, Question 28).

Installation of ILITI 100 and 2LIT2 100 require entry into a safety area that requires personal floatation gear. This should be worn when applicable in accordance with Form 9 Installation and Testing Instructions.

• Materials,processes,parts, and equipment suitablefor application.(NQA-I, Question 27)

Material used for this application shall be per Form 11, ECP Materials List.

• Quality and quality assurance requirements (NQA- I, Question 29)

The components installed per this change are non-safety related. Therefore, NQA-I requirements are not specifically invoked. " Interface requirements between equipment and operation and maintenance personnel (NQA-I, Question 31) Local indication at each radar probe and ILII 100 and 2L12100 may be incorporated into procedures as necessary. This is to be determined by operations per 201000229 Form 10, Turnover Closeout Plan.

• Loadpath requirementsfor installation,removal, and repairof equipment and replacement ofmajor components (NQA- 1, Question 33)

The changes associated with this ECP have no load path requirements. 9.0 OTHER (NQA-1 REQUIREMENTS): (CNG-FES-007, SECTION 5.3.3) " Security requirements to include access and administrativecontrol requirementsand system design requirements including redundancy,power supplies, supportsystem requirements, emergency operationalmodes, andpersonnel accountability(NQA-l, Question 17) Each radar probe indicating and adjustment module has the option to require a PIN number to change the settings. If the PIN option is enabled, only read functions are permitted without entering the PIN. This option is a permanent setting on the module. " Transportabilityrequirementssuch assize and shipping weight, limitations,ICCregulations.(NQA-I, Question 23) The changes associated with this ECP do not have transportability requirements.

• Other requirements to prevent undue risk to the health and safety of the public. (NQA- 1, Question 26)

CNG-FES-015 Rev. 00002

FORM 7A, DESIGN CHANGE TECHNICAL EVALUATION CONTINUATION (Page 6 of 6) ECP Supp No.: ECP-10-000208 Rev. No.: 0000 The changes associated with this ECP do not have other requirements related to public health and safety. Handling, storage,cleaning,and shipping requirements.(NQA-1, Question 25) The radar probes installed per this change shall be shipped in accordance with instruction notes included on packaging. Storage shall be in un-opened original packaging until time of use. Storage shall be under the following conditions:

• Not in the open
• Dry and dust free
• Not exposed to corrosive media
• Protected against solar radiation
• Avoiding mechanical shock and vibration CNG-FES-015 Rov. 00002

FORM 8, OPERATIONAL IMPACT OF DESIGN CHANGE Page 1 of 2 ECP Supp:No.: :ECP-10-000208 Rev. No.: 0000 A. INSTRUCTIONS: .. Describe in Section B the operational impact of the change, if any. Include the following, as applicable,

• How the system operates differently from what it did.
• Changes to the functional and operational characteristics of the system or component.
• Impact of this change on the simulator software, e.g., flow coefficients on valves, and hardware
• Electrical, interlocks, power supply, control schemes, alarm and indication changes, etc.
• Mechanical, capacity changes, effect on system parameters, setpoint changes, equipment additions or deletions, cross-connects, etc.
• Valves, changes in failure mode, capacity drive mechanism, actuation signal alarm and control function or location, etc.
• Technical Specification, "How must operation change?
• Are new or changes to current operator movements required?
• Potential for this modification to inadvertently cause a reactor trip, including:
• Is any affected equipment trip sensitive or located in trip sensitive areas?
• Will construction activities impact trip sensitive equipment or occur in trip sensitive areas?
• Will post modification testing impact trip sensitive equipment?
• Potential for this modification to impact the control or monitoring of reactivity
• Potential for this modification to affect changes in operating limits and changes in operating margins and strategies.
• For core reloads, evaluate and determine if there will be significant changes in core physics or reactivity coefficients.
• Recommendations for special post-modification testing, e.g., testing for potential side effects due to changes in system operation, if any
• Recommendations for special Operator or Maintenance training, if any
• Recommendations for unique configuration documentation or logistic support, if any.
• Other recommended compensatory measures, if any, e.g., mock-ups, simulation
• Discuss potential for MOD to impact control of core monitoring, operating limits, core physics, and reactivity B., DESCRIPTION OFIMPACT: .

This change installs radar level probes at the Intake Structure to provide local level indication only. Each probe provides local level indication from an electronic display module on the top of the component. The exception is the indication for I LITI 100 and 2LIT2100, which is located on the east intake structure wall at new remote indicators ILII 100 and 212 100 respectively. The radar probes do not provide control room indication or alarms and have no input to control related functions. Refer to the following ECNs for location of instrumentation for level monitoring. ComplD Description ECN ILITI201B Traveling Screen 12 Downstream Radar Level ECP-10-000208 61348-0039 ILIT1301B Traveling Screen 13 Downstream Radar Level ECP- 10-000208 61349-0042 ILITI401B Traveling Screen 14 Downstream Radar Level ECP-10-000208 61349-0042 ILITI501B Traveling Screen 15 Downstream Radar Level ECP-10-000208 61349-0042 ILIT1601B Traveling Screen 16 Downstream Radar Level ECP-10-000208 61349-0042 2LIT2501B Traveling Screen 25 Downstream Radar Level ECP-10-000208 63351SH001-0031 2LIT2401B Traveling Screen 24 Downstream Radar Level ECP-10-000208 63350-0040 2LIT2301B Traveling Screen 23 Downstream Radar Level ECP-10-000208 63350-0040 2LIT2201B Traveling Screen 22 Downstream Radar Level ECP-10-000208 63350-0040 2LIT2101B Traveling Screen 21 Downstream Radar Level ECP-10-000208 63350-0040 CNG-FES.015 Rev. 00002

FORM 8, OPERATIONAL IMPACT OF DESIGN CHANGE Page 2 of 2 ECP Supp.Nd.::,,.:., EýCF40-000208 Rev. No.: 0000 ComplD Description ECN I LIT 101B Traveling Screen I I Downstream Radar Level ECP-10-000208 61348-0039 2LIT2601B Traveling Screen 26 Downstream Radar Level ECP-10-000208 63351 SH0O1-0031 ILIT1101A Traveling Screen 11 Upstream Radar Level ECP-10-000208 61348-0039 ILIT120iA Traveling Screen 12 Upstream Radar Level ECP- 10-000208 61348-0039 2LIT2601A Traveling Screen 26 Upstream Radar Level ECP- 10-000208 63351 SHOO 1-0031 2LIT2501A Traveling Screen 25 Upstream Radar Level ECP-10-000208 63351SH001-0031 ILIT! 100 Unit I Trash Rake Upstream Radar Level ECP-10-000208 61348-0039 2LIT2100 Unit 2 Trash Rake Upstream Radar Level ECP-10-000208 63351SHOO1-0031 ILl1 100 Unit I Trash Rake Upstream Radar Level Indicator ECP-10-000208 61348-0039 2L12100 Unit 2 Trash Rake Upstream Radar Level Indicator ECP- 10-000208 63351 SHOO 1-0031 CNG-FES-015 Rev. 00002

FORM 9, INSTALLATION AND TESTING INSTRUCTIONS (Sheet 1 of 10) ECP Supp No.: ~ ECPA-10000208 Rev~. No.. 0000 A. INSTALLATION INSTRUCTIONS: .... This installation section addresses the changes associated with the installation of new radar level probes at the Units I & 2 intake structure. All work associated with this ECP is classified as non-safety related and shall be planned and controlled in accordance with the applicable procedures and specifications. General Notes: Installation steps may be performed in any order as determined by the field. Radar probes are being installed in temporary configuration by this modification. The level indicator numbers have been assigned in FCMS but the junction box numbers, cable numbers and conduit numbers will not be assigned due to this temporary configuration. Conduits will be installed in the concrete and will remain in place but will not be numbered until the next modification ECP-10-000209 is installed. Precautions: When working on the waterfront, ensure site procedures for fall protection, Personnel Floatation Devices and other safety procedures are followed. Pre-Installation Instructions NOTE: Additional assemblies shall be fabricated at the direction of the System Engineer

1. Fabricate 6"/8" penetration mounting sub-assemblies (10 each) per Installation Sketch #1

2. Fabricate 10" penetration mounting sub-assemblies (2 each) per Installation Sketch #2

3. Fabricate anchor mounting brackets (4 each) per Installation Sketch #3

4. Fabricate bay level mounting brackets (2 each) per Installation Sketch #8

5. Fabricate Level Indicator Brackets (2 each) per Installation Sketch #4

6. Build junction boxes per Installation Sketch #6

7. At penetration locations, top of penetration shall be ground flush with concrete to provide flush mounting surface.

8. Replace rail mount attachment with wall mount attachment on ILII 100 and 2L12100 Installation Instructions NOTE: Sub-section installations can be performed in any order.

Junction Box Installation

1. Install junction boxes with supports for transmitters located upstream of the traveling screens to intake structure deck per E-406 Section 104.3 Sht 65 (Behind 11B/12A for ILIT1 100, ILITI 101A and ILIT1201A and behind 25B/26A for 2LIT2100, 2LIT2501A, and 2LIT2601A per Installation Sketch #5).

Mount per Installation Sketch #6. Verify box locations with Project Manager (PM) prior to installation.

2. Install junction boxes with supports for power distribution inside equipment rooms behind screens 14B and 25A per E-406 Section 104.3 Sht 61 (Reference Installation Sketch #5). Mount per Installation Sketch #6.

Verify box locations with PM prior to installation. CNG-FES-015 Rev. 00002

FORM 9, INSTALLATION AND TESTING INSTRUCTIONS (Sheet 2 of 10)

ECP SEppNo.: ECP-10-000208 Rev. No.: 0000 Embedded Conduit Installation

3. Scan area where conduit is to be installed between screens I IB/12A and 25B/26A, extending out to trash rakes, to identify any existing conduits or rebar (Ref. ECP-10-000208 61348-0039, ECP-10-000208 63351 SHOO 1-0031 and Installation Sketch #5).

NOTE: The following step requires cutting of concrete.

4. Lay out conduit route using Installation Sketches #5 and #9 as a guide to cut concrete from junction boxes to instrument locations for ILITI 100, ILITI OlA and ILITI201A on the north side of the intake structure and 2LIT2100, 2LIT2501A, and 2LIT2601A on the south side. Remove upper 3" of concrete along conduit route. CAUTION: DO NOT cut any rebar or remove concrete more than 3" deep.

5. Install PVC conduit below grade for radar probes upstream of the traveling screens per E-406 and Installation Sketch #9. Conduit length shall be adequate to stub out of concrete once poured.

6. Field route rigid steel conduit from junction boxes to PVC conduits and connect using CG fittings to prevent water intrusion (Reference Installation Sketch #5).

7. Inspect and check conduit to assure continuity and correct position in accordance with E-406 Section 105.3.

8. Encase conduit in concrete per E-406 Section 105.3 and C-00 10. Roughen the sides and the bottom of the trench before pouring to ensure adequate bond. Fill trench with structural concrete that conforms to Bechtel Specification 6750-C-9 and shall be class C-I concrete (4000 psi min at 28 days).

Remote Indicators

9. Field locate remote indicator ILI11100 either on east intake structure wall or racks located between traveling screen sets. Verify location with PM prior to installation.

10. Install remote indicator mounting brackets for ILI 1100 per Installation Sketch #4 and VTM 12335-030 Tab 3.

11. Field locate remote indicator 2LI2100 either on east intake structure wall or racks located between traveling screen sets. Verify location with PM prior to installation.

12. Install remote indicator mounting brackets for 2LI2100 per Installation Sketch #4 and VTM 12335-030 Tab 3.

Power Supply Installation NOTE: The following steps assume welding carts are located inside structure intake equipment rooms.

13. Inside intake structure room located behind traveling screen 14B, attach temporary DIN rail to welding cart. Use DIN rail as template to drill holes in cart and attach using machine screws.

14. Attach 24Vdc power supply to DIN rail.

15. Wire electrical pigtail cord to 120VAC input terminals L(+) & N(-).

16. Inside intake structure room located behind traveling screen 25A, attach temporary DIN rail to welding cart. Use DIN rail as template to drill holes in cart and attach using machine screws.

CNG-FES-015 Rev. 00002

FORM 9, INSTALLATION AND TESTING INSTRUCTIONS (Sheet 3 of 10) ECP Suppi No.: *ECP-10 000208 .. . Re.No.: Re'** '0000

17. Attach 24Vdc power supply to DIN rail.

18. Wire electrical pigtail cord to 120VAC input terminals L(+) & N(-).

Cable Install NOTE: Cables shall be routed along the existing fiberglass pipes for support and protection. Cables to be attached using tie-wraps or other approved means. Ensure all cables are properly supported and attached.

19. Field route cable between power supplies and corresponding junction boxes inside equipment rooms using E-406 Section 102 as guidance per Installation Sketches #5, #6, and #7. At power supplies, 24Vdc power is connected across terminals 24V and OV.

20. Field route cables from equipment room junction boxes to radar probe locations for the following components using Installation Sketch #5 and E-406 Section 102 for guidance. Cables shall be routed through existing penetrations in equipment rooms.

CompID Description Power Supply Location ILIT1201B Traveling Screen 12 Downstream Radar Level 14B Equipment Room ILITI301B Traveling Screen 13 Downstream Radar Level 14B Equipment Room 1LITI401B Traveling Screen 14 Downstream Radar Level 14B Equipment Room ILITI501B Traveling Screen 15 Downstream Radar Level 14B Equipment Room ILITI601B Traveling Screen 16 Downstream Radar Level 14B Equipment Room 2LIT2501B Traveling Screen 25 Downstream Radar Level 25A Equipment Room 2LIT2401B Traveling Screen 24 Downstream Radar Level 25A Equipment Room 2LIT2301B Traveling Screen 23 Downstream Radar Level 25A Equipment Room 2LIT2201B Traveling Screen 22 Downstream Radar Level 25A Equipment Room 2LIT2101B Traveling Screen 21 Downstream Radar Level 25A Equipment Room

21. Field route power cable from junction box in equipment room behind traveling screen 14B to junction box located at the north end of the intake structure per Installation Sketch #6.

22. Field route power cable from junction box in equipment room behind traveling screen 25A to junction box located at the south end of the intake structure per Installation Sketch #6.

23. Field route cables from junction boxes to radar probe locations for the following components using Installation Sketch #5 and E-406 Section 102 for guidance.

CompID Description Junction Box Location ILIT110IB Traveling Screen 11 Downstream Radar Level Intake Structure North End 2LIT2601B Traveling Screen 26 Downstream Radar Level Intake Structure South End

24. Wire at junction boxes per Installation Sketches #6 and #7.

24.1 Cable may have single communication wire, this wire is not used and can be left floating at both ends. Ensure wire does not contact any terminals. CNG-FES-015 Rev. 00002

FORM 9, INSTALLATION AND TESTING INSTRUCTIONS (Sheet 4 of 10) TECP-10000208" ECPSupp No.: Rev. No.: ,0000,

25. Route cable through conduit previously installed between junction boxes and radar probes upstream of the traveling screens as follows:

25.1 Route 20 AWG T.S.P. through 3/4'" conduit for ILITI 101A and ILITI201A on the north side of the intake structure and 2LIT2501A and 2LIT2601A on the south side. 25.2 Route 20 AWG T.S.P and 4/C 20 AWG cable through 3/4" conduit to ILITI 100 on the north side of the intake structure and 2LIT2100 on the south side. 25.3 Terminate cable injunction box per Installation Sketch #7

26. Route 4/C 20 AWG cable from junction box to ILI1 100 and 2LI2100 respectively per Installation Sketch

       #5. Terminate cable at junction box per Installation sketch #7 and at indicator per VTM 12335-030 Tab 3.

Radar Probe Installation NOTE: Radar Probe Installation can be performed in any order

27. Perform the following steps for each radar probe listed below:

ComplD Description ECN 1LIT1201B Traveling Screen 12 Downstream Radar Level ECP-10-000208 61348-0039 ILITI301B Traveling Screen 13 Downstream Radar Level ECP-10-000208 61349-0042 ILIT1401B Traveling Screen 14 Downstream Radar Level ECP- 10-000208 61349-0042 ILITi501B Traveling Screen 15 Downstream Radar Level ECP- 10-000208 61349-0042 ILITI601B Traveling Screen 16 Downstream Radar Level ECP-10-000208 61349-0042 2LIT2501B Traveling Screen 25 Downstream Radar Level ECP-10-000208 63351SHOO1-0031 2LIT2401B Traveling Screen 24 Downstream Radar Level ECP-10-000208 63350-0040 2LIT2301B Traveling Screen 23 Downstream Radar Level ECP-10-000208 63350-0040 2LIT2201B Traveling Screen 22 Downstream Radar Level ECP-10-000208 63350-0040 2LIT2101B Traveling Screen 21 Downstream Radar Level ECP-10-000208 63350-0040 27.1 Locate radar probe per the applicable ECN in the table above. 27.2 Install 6"/8" lower mounting assembly in penetration per Installation Sketch #1. 27.2.1 Rotate the lower assembly to the desired position (based on detector head orientation). 27.2.2 Thread a nut on the 3/8" bolt and run close to the bolt head, thread the bolt into the welded nut on the angle leg and tighten the jacking bolts firmly against the penetration side wall. Once tight, lock the bolt in place using the jam nut on the bolt. 27.2.3 Perform above step for all jacking bolts. 27.3 Install 6"/8" upper mounting assembly per Installation Sketch #1. Position the upper plate assembly on top of the lower assembly plate and secure using (4) / 4-20 x 3/4" bolts. Note that the radar probe may be installed in the upper plate prior to installing upper plate to insure correct orientation. CNG-FES-015 Rov. 00002

FORM 9, INSTALLATION AND TESTING INSTRUCTIONS (Sheet 5 of 10) ECP:Supp No.: ECPI0-000208 .Rev. No.: 0600 27.4 Install radar probe in threaded coupling of upper mounting assembly and attach electronics module. Verify that the probe orientation is correct, if not rotate the probe or the lower assembly to obtain desired orientation. 27.5 Label radar probe. 27.6 Wire transmitter per installation Sketches #6 and #7 and VTM 12335-030 Tab 1. 27.6.1 Prior to cable entry into gland seal, a drip loop shall be installed to drain moisture away from radar probe electronics and junction box. 27.6.2 Cable has single communication wire, this wire is not used and can be left floating at both ends. Ensure wire does not contact any terminals. 27.7 Install protective cage assembly per Installation Sketch #1. Verify the probe orientation is correct and cables are installed. Attach the guard assembly to the upper plate using (4) 1/4-20 SS bolts and nuts. If interference is encountered contact System Engineer and Engineering for resolution.

28. Perform the following steps for each radar probe listed below:

CompID Description ECN ILITI 101B Traveling Screen I Downstream Radar Level ECP-10-000208 61348-0039 2LIT2601B 2LIT2601B Traveling Screen 26 Downstream Radar Level I ECP-10-000208635SOI03 NOTE: To minimize interference with the penetration, 3" long angle may be trimmed as necessary. NOTE: Welded nuts on lower assemblies may be lowered up to 2" if needed based on penetration conditions. 28.1 Locate radar probe per the applicable ECN in the table above. 28.2 Install 10" lower mounting assembly in penetration per Installation Sketch #2. 28.2.1 Rotate the lower assembly to the desired position (based on detector head orientation). 28.2.2 Thread a nut on the 3/8" bolt and run close to the bolt head, thread the bolt into the welded nut on the angle leg and tighten the jacking bolts firmly against the penetration side wall. Once tight, lock the bolt in place using the jam nut on the bolt. 28.2.3 Perform above step for all jacking bolts. 28.3 Install 10" upper mounting assembly per Installation Sketch #2. Position the upper plate assembly on top of the lower assembly plate and secure using (4) /4-20 x 3/4" bolts. Note that the radar probe may be installed in the upper plate prior to installing upper plate to insure correct orientation. 28.4 Install radar probe in threaded coupling of upper mounting assembly and attach electronics module. Verify that the probe orientation is correct, if not rotate the probe or the lower assembly to obtain desired orientation. CNG-FES-015 Rev. 00002

FORM 9, INSTALLATION AND TESTING INSTRUCTIONS (Sheet 6 of 10) iECP;Supp No.: ECP-10-000208 , . Rev. No. 0000 28.5 Label radar probe. 28.6 Wire transmitter per installation Sketches #6 and #7 and VTM 12335-030 Tab I. 28.6.1 Prior to cable entry into gland seal, a drip loop shall be installed to drain moisture away from radar probe electronics and junction box. 28.6.2 Cable has single communication wire, this wire is not used and can be left floating at both ends. Ensure wire does not contact any terminals. 28.7 Install protective cage assembly per Installation Sketch #2. Verify the probe orientation is correct and cables are installed. Attach the guard assembly to the upper plate using (4) 1/4-20 SS bolts and nuts. If interference is encountered contact System Engineer and Engineering for resolution.

29. Perform the following steps for each radar probe listed below:

ComplD Description ECN ILIT] 101A Traveling Screen II Upstream Radar Level ECP-10-000208 61348-0039 1LIT1201A Traveling Screen 12 Upstream Radar Level ECP- 10-000208 61348-0039 2LIT2601A Traveling Screen 26 Upstream Radar Level ECP- 10-000208 63351 SHOO 1-0031 2LIT2501A Traveling Screen 25 Upstream Radar Level ECP-10-000208 63351SHOO1-0031 29.1 Locate radar probe per the applicable ECN in the table above. 29.2 Install anchor mounting bracket per Installation Sketch #3. The components shall be installed below grating in front of the traveling screens. Centerline of mounting bracket shall be at the 9'-0" elevation. Verify location and elevation for each bracket prior to drilling anchors. Install mounting bracket using Hilti Kwik Bolt anchors per site procedure and Hilti installation procedure. 29.3 Install radar probe in threaded coupling on mounting bracket and attach electronics module. 29.4 Label radar probe. 29.5 Wire transmitter per installation Sketches #6 and #7 and VTM 12335-030 Tab 1. 29.5.1 Prior to cable entry into gland seal, a drip loop shall be installed to drain moisture away from radar probe electronics and junction box. 29.5.2 Cable has single communication wire, this wire is not used and can be left floating at both ends. Ensure wire does not contact any terminals.

30. Perform the following steps for each radar probe listed below ComplD Description ECN ILITI 100 Unit I Trash Rake Upstream Radar Level ECP-10-000208 61348-0039 2LIT2100 Unit 2 Trash Rake Upstream Radar Level ECP- 10-000208 63351 SHOO 1-0031 CNG-FES-015 Rev. 00002

FORM 9, INSTALLATION AND TESTING INSTRUCTIONS (Sheet 7 of 10) ECPSupp No.: ECP-..000208 . . Rev. No.: 0000 NOTE: Prior to removing grating or accessing location for Bay Level detectors ILITI 100 and 2LIT2100, ensure all requirements for fall protection and personal floatation are met. 30.1 Locate radar probe per the applicable ECN in the table above. 30.2 Use conduit route as guide to locate radar probe in grating, cut 8" (+/-I")square hole in grating and mesh per Installation Sketch #8 (Reference Dwg 61843). CAUTION: Ensure that cutting does not create instability in grating. Grating shall be banded prior to cutting to ensure stability is maintained during cutting. 30.3 Prior to installation, wire transmitter per installation Sketches #6 and #7, and VTM 12335-030 Tab 1. Ensure adequate cable exists to provide a drip loop when probe position is finalized. 30.4 Install radar probe per Installation Sketch #8. Verify probe and lower assembly are level and plumb. 30.5 Ensure a drip loop exists prior to cable entry in the transmitter gland seal to drain moisture away from radar probe electronics and junction box. 30.6 Cable has a single communication wire, this wire is not used and can be left floating at both ends. Ensure wire does not contact any terminals. 30.7 Tighten bolts and secure instrument in lower mounting assembly and tighten lower assembly to upper assembly. 30.8 Attach upper mounting assembly to grating using grating clips and stainless steel hardware as required. 30.9 Label radar probe. Radar Probe Confliuration

31. Configure Radar probes per vendor instruction and VTM 12335-030 Tab 2.

32. Document As-Left configuration for individual probes as necessary and submit to Lead Design Engineer (LDE). NOTE: A configuration document can be shared between probes with identical configuration, but the applicable components shall be listed on the document.

Power Up System

33. At equipment room located behind traveling screen 14B, plug power supply into 120 Vac welder utility receptacle.

34. At equipment room located behind traveling screen 25A, plug power supply into 120 Vac welder utility receptacle.

Removal Instructions NOTE: This change does not remove radar probes, level indicators, or junction boxes in support of implementation of ECP-10-000209 for permanent installation. CNG-FES-015 Rev. 00002

FORM 9, INSTALLATION AND TESTING INSTRUCTIONS (Sheet 8 of 10) ECP Supp No.: ECP-10-000208 Rev. No.:,. :0000:.. I. Inside intake structure rooms located behind traveling screen 14B and 25A, unplug power supply from welder outlet.

2. On power supply, de-terminate 120Vac wiring at terminals L & N and 24Vdc wiring at terminals 24V and 0v.

3. Determinate all cable between power supply and radar probes.

4. Remove cable and place in stock if desired. Cable may be re-used for permanent installation under ECP-10-000209.

5. Inside intake structure rooms located behind traveling screens 14B and 25A, detach power supply from DIN rail mounted on welding cart. These components should be placed back in stock.

6. Remove DIN rail from welding cart. DIN rail and mounting screws can be placed in stock if desired.

B. TESTING REQUIREMENTS AND ACCEPTANCE CRITERIA: Post-Installation Testing

1. Power supply testing Acceptance Criteria: 24Vdc +/- 1%

2. Radar probe configuration Acceptance Criteria: Shall be tested with vendor upon installation.

3. New cables shall be continuity tested in accordance with E-406 Acceptance Criteria: Test values shall be per E-406

4. Concrete Acceptance Criteria: Concrete shall be tested in accordance with Specification C-001 1B

5. Radar probe functional test Radar probes do not fall out of calibration and either function as designed, or do not function at all.

Therefore, ensuring that the radar probe is measuring level is enough to verify functionality. Acceptance Criteria: Radar probe measurement compares to field measurement CNG-FES-015 Rev. 00002

FORM 9, INSTALLATION AND TESTING INSTRUCTIONS (Sheet 9 of 10) ECP.SuppNo...:. ECP-I06000208. Rev. No.,: 0000 . &. C. TURNOVER/CLOSEOUT REQUIREMENTS - The following steps shall be included in the implementing work order(s) to ensure turnover and/or closeout requirements are satisfied. TO/CO Plan No: 201000229 Final Turnover: [] Partial Turnover: [] Description of components/system (work scope) to be turned over to Operations: Work Orders being turned over: Does this work complete this modification? El YES E] NO If"NO," does the 10 CFR 50.59/72.48 review cover the interim plant configuration E] YES [E NO created by these work orders? If this is a partial turnover, list the Work Orders required to complete modification.

                            .isf                                                            ibie PRIOR TO TESTING:

["- All work Orders associated with this ECP that are required to be Resp Engv completed prior to turnover are complete Z -* Final Walkdown Complete with Operations and Maintenance Resp Engv Document "Open Items" on FORM 13 and attach to work order

**      Engineering for all At-Risk Activities has been approved                    Resp Engv

[* Final Walkdown "Open Items List" has been reviewed. They will Resp Engv neither prevent safe testing nor reduce the safety of plant operations AFTER TESTING: El* Test Results have been reviewed and are satisfactory Resp Engv El with anomalies listed below: E] without anomalies System Eng ED* Final Walkdown "Open Items List" has been reviewed and does not Resp EngV adversely impact safe operation or the design intent

-]*     All Labels are Installed (Valve, Component, Alarm)                          Ops Shift Mngr

-j* Any CRs impacting operability have been dispositioned Resp Engv CNG-FES-015 Rev. 00002

FORM 9, INSTALLATION AND TESTING INSTRUCTIONS (Sheet 10 of 10) ECP SuppNo ECP*-0,000208,<  :::.*. ., Rev. No.: 0000 "  : Z Engineering for all At-Risk Activities has been approved Resp Engv E1 All Critical CDs and associated ECNs are Statused as Resp Engv APPROVED/DESIGN BASIS M All Required Changes to Operations Procedures are Complete Ops Shift Mngr El All TO/CO actions required prior to Turnover are complete Resp Engv El Training has been notified of turnover Resp Engv []* Training to Support Turnover Complete El 9 Operations Ops Shift Mngr El 9 All others Resp Engv Z* Applicable Technical Specification Changes are Completed and UFSAR or Resp Engv USAR Changes are Submitted? E1* Plant Change Description provided to the Shift Manager Resp Engv NOTE: Description is generally a copy of the ECP coversheet and the Operational Impact Statement, if required) E]* Acceptance of Change: Manager - Operations (or Designee) Printed Name/ Signature Date

• These requirements are generally not applicable for EQVs V Responsible Engineer may be the responsible engineer or project manager assigned to the ECP or an alternate assigned by their organization.

CNG-FES-015 Rev. 00002

TEMPORARY PLANT CONFIGURATION CHANGE PROCESS CNG-CM-1.01-1004 Revision 00000 Page 41 of 47 Attachment 4, TC Installation and Testing Instructions Addenda ECPSupp. 000o ECP-1 0-000208-000 Rv o: oo A. PRE-INSTALLATION REQUIREMENTS, The followingsteps shall be inciudedln the Implementing work order(s) to ensure pre-instaliation requirements are'satisfied.: WARNINGI - Do Not Install After Date is 30 days after TCP approval date. Return to the Responsible Engineer if installation is delayed beyond this date. Applicable Modes: [] 1 [9 2 21 3 [] 4 [] 5 91 6 El Defueled ,N/A: Action Responsible. Individual'* INITIALS, IK Engineering for all At-Risk Activities has been approved Resp Eng' [] Pre-Installation Training Complete Resp Eng' [] Pre-installation Procedure Changes Complete Resp Eng' El Installation Approval Date: Shift Manager B. TEMPORARY CHANGE INSTALLATION AND VERIFICATiON:. -The foiowingisteps.shall be included-,.

in the implementing wok orderý(s* to ensure TC tags are hung aniinsta*llation is verified.l: '

Installer: Name (Print) Initials: Ext. Verifier: Name (Print) Initials: Ext.

• INSTALLATION.:': RESTORATION..

Installer Verifier Restorer Verifier Tag Config: EquipIDDescriptionlLocation. InitiallDate. Initial/Date Initial/Date Initial/Date Seq# _____________ Note any TC Tag placement restrictions, for example, TO tag not hung on SSC in containment:

'Responsible Engineer may be the Responsible Engineer, System Engineer, or Engineering Services designee.

TEMPORARY PLANT CONFIGURATION CHANGE PROCESS CNG-CM-1.01-1004 Revision 00000 Page 42 of 47 Attachment 4, TC Installation and Testing Instructions Addenda ECP Supp ECP-O0-00208 Rev...,.No.:

                                                                       ., ..,* 0000 No.:            ECP-10-000208 C. POST-INSTALLATION TURNOVER REQUIREMENTS - The following steps shall be included in the implementing work order(s) to ensure post-installation turnover requirements are satisfied.

N/A Action Responsible Individual INITIALS BEFORE POST-INSTALLATION TESTING: El Installation Steps of Work Order(s) that are required to be Resp Eng 1 completed prior to post-installation testing are complete AFTER POST-INSTALLATION TESTING: EZ Test Results have been reviewed and are satisfactory Resp Eng 1 El All TC Tags or Labels are Installed Ops Shift Mngr [] All ECNs are Statused as TC INSTALLED Resp Eng 1 IZ TCP status changed to TC INSTALLED Resp Eng 1 LI All TO/CO actions required prior to Turnover are complete Resp Eng' El Training has been notified of TCP Installation Resp Eng1 LI Post-Installation Training Complete Resp Eng' E] Post-Installation Procedure Changes Complete Resp Eng' Acceptance of Temporary Change: Manager - Operations (or Designee) Printed Name/ Signature Date D. TEMPORARY CHANGE RESTORATION - The following steps shall be included In the implementing work order(s) to ensure pre-restoration -requirements are satisfied and TC removal is verified.. Restoration Approval Date: Shift Manager The Restorer and Verifier shall initial in the table of Tags (Section B) to indicate restoration and verification. Restorer: Name (Print) Initials: Ext. Verifier: Name (Print) Initials: Ext. Other Restoration Requirements and Post Restoration Actions, including Testing, Training, Procedure Revisions, and Operations Turnover are addressed on the ECP Installation and Testing Instructions, CNG-FES-015, Form 10.

ECP-1O-000208 INSTALLATION SKETCH 001 SHEET 1 OF 4 6"& 8" PENETRATION MOUNTING ASSEMBLY ELEVATION VIEW NOTESI I. ALL MATERIAL TO HE TYPE 316 OR 304 Ss OREQUAL 2 ALL.CORNERS AND EDGESTO BE GROUND SMOOTH

3. ANGLELEGS MAY BETR ,IMMOAS NECESSARY

4. CHINO TOP OP RISER PIPE I'LUSHIWITH CONCRETE S. TIGHTEN ALL BOLTS TO A SNUG-TIGHTCONOITION WELD R E L BE E316-mX OR E304-XX ASRE1.

DIANETEnHOLE IN ANGLEPRIOR 10 WTDIING NUT. 6' & 8' ASSEMBOLY BILL OF MATERIALS ET -- DESCRIPTION 4 ANGLE*.TYPE 316 SSH'.'l I .% 8II

                                                                .f LONG 2     ANIGLE-TYPE 316 ,SS." 1"* tI-        3" LONG PLATE. TYPE 3155.'...      Ito DIAMETER     WITH 314" DIAMETERHOLE PLATE. TYPE3tI SS.'... t0" DIAMETERWITH2        OIANEIER HOLE PLATE. TYPE 316 SS.1"4". Vq3      DIAMETER  WITH 3",l  DIAIMETER HOLE 4     SAR. TYPE   16 SS.la* x 1',t" I     HALFCOUPLING.SS.      1"H2NPT 2     HEX NUT. TYPE 316 SS, 3/B-16 B     HEX NUT. TYPE 316 SS,    I/4-2O BOLT. HEG HEAD. TYPE 316 S.,       3/H-16. LENGTHAS REG.

B BOLT. HEX HEAT, TYPE 316 SS. 1/4-20. LENGTHAS REO. WASHER,FLAT. TYPE IINSS, t, 4 NASHEHELOOK. TYPE 316 SS. I

                ,m,

ECP-1 0-000208 INSTALLATION SKETCH 001 SHEET 2 OF 4 71 6"& 8" PENETRATION LOWER MOUNTING ASSEMBLY SECTION VIEW 6"& 8" PENETRATION LOWER MOUNTING ASSEMBLY A-A PLAN VIEW

ECP-10-000208 INSTALLATION SKETCH 001 SHEET 3 OF 4 e," SS PLATE 10' DIAMETERWITH 2' ODIAETERHOLE

                                      %W DIAMEERHROLEORILLED AT 5- OIAAETER PLATE To' DIAMETER  WITH 2" DIAMETERHOLE
                                                                                                            .- I',; NPT SS HAL.FC".LING A5 SHOWN BAR       ".1" Tlji NPT SS HALFCOUPLING 6"& 8" PENETRATION UPPER MOUNTING ASSEMBLY SECTION VIEW B-B 6"& 8"  PENETRATION UPPER MOUNTING ASSEMBLY PLAN VIEW

ECP-1 0-000208 INSTALLATION SKETCH 001 SHEET 4 OF 4 4/

                                                                               '0
                             - KATE Vt St SW olaEtC* sOn AY.~cL~TKs .~A (2                 1. TAr 9,-.8~ LC TYPEPLEA                                                 0
                                                                                             .1211-I!

PROTECTIVE CAGE ASSEMBLY PROTECTIVE CAGE ASSEMBLY PLAN VIEW SECTION VIEW C-C

ECP-!0-000208 INSTALLATION SKETCH 002 SHEET 1 OF 4 10" PENETRATION MOUNTING ASSEMBLY ELEVATION VIEW N*OTES. I ALL MATERIALTO BE TYPE 316 OR 304 SS OR EORAL

z. ALLCORENRSAND EOGES TO BE GRODUN SMOOTH

3. ANGLELEGS MAYBE TRI4&"0 AS NECESSARY

4. GRINO TOP OF RISER PIPE FLUSH WITHCONCRETE S. TIlHTEN ALL BOLTS TO A SNSG-'TIGH1 CONDITION

6. WELDELECTRODE

1. SHALLBE E316-XXOR E304-XX AS RET.

7. DRILL .e' DIAEIETR HOLE ZN ANGLE PRIOR TO RELING NUIT.

10" ASSEMBLY BILL OF MATERIALS OTY I0ESCR IPTI1ON

                  '"4"  ANGLE.TYPE 3!     SESS.',. 1". I. e*,* LONG 1

2 ANGLE. TYPE 316 SS. 'ýRI" 1'. 3' LONG P1.AT. TYPE 316 SSl.'". 12' DIAMETERWITH 631.7 DIAMETERROLE PLATE. TYPE 316 S.', 12' DIAMETERWITH 2' DIAMETERHOLE PLATE. TYPE316 OIAMETER 6S1.'.", D'"* WITH 31,"1DIAMETERHOLE 4 BAR. 316 SS.1,Rx 1'.1l I HALF COUPLING. SS. 5 1,5.NPT A HEX NUT. TYPE 316 SS. 3/8-1I 0 HEX NUT. TYPE 316 SS. 1/4-20 2 BOLT. RHEHEAD. TYPE 316 SS. 3/8-16.LENGTHAS REY. 8 BOLT. HEX HEAD, TYPE 316 .SS. 1/0-20. L4" LENGTHAS RED. RASHER.PLAY. TYPE 316 SY. '." 4 RASHER.LDCK. TYPE 316 G5. 'S.

ECP-1 0-000208 INSTALLATION SKETCH 002 SHEET 2 OF 4 l'l, SS PL&TE?Z" DIAMETR WITH L, DIMT(R HOLE 6 DIAMETER*.L DRILLED AT 81,j' DIAMETER T, 1/4-20 SS HEX NUT TYP 4 PLCS 2 PLCS. 10" PENETRATION LOWER MOUNTING ASSEMBLY SECTION VIEW 10" PENETRATION LOWER MOUNTING ASSEMBLY B-B PLAN VIEW

ECP-10-000208 INSTALLATION SKETCH 002 SHEET 3 OF 4

                         '-4" 5$ PLATE 12' DIAACTER*JTH 2'  DIAACTERHOLE "I                                      %,I DAMlETERHOLEDRILLED AT 8"0j DIAWTE.

PLATE IAA $~

                                                             - BAR SS.'-.~

DRIILLEO AS SHOII T',1 NPT SS HAL.FCOUPLING 10" PENETRATION UPPER MOUNTING ASSEMBLY SECTION VIEW B-B 10" PENETRATION UPPER MOUNTING ASSEMBLY PLAN VIEW

ECP-10-000208 INSTALLATION SKETCH 002 SHEET 4 OF 4 4 pLcS. r- -7 1

                                                            '0, V4' DIAJýTý0
                                                                                              . -R&MIUED a llICYlll,
                              -O.r . W~.-L YC 0

i4.1 PROTECTIVE CAGE ASSEMBLY PROTECTIVE CAGE ASSEMBLY PLAN VIEW SECTION VIEW C-C

ECP-10-000208 INSTALLATION SKETCH 003 SHEET 1 OF 2 SECTION VIEW D-D ANCHOR BRACKET MOUNTING ASSEMBLY ELEVATION VIEW ANCHOR BRACKETASS*MBLYBILL OF MATERIALS NOTES: OY ODESCRIPTION

1. ALL MATERIAL TO BE 7SP 304 OR 316 SS OR EOUM.

I PLATE. 1TPE 316 SS.,,"A4,1"'-0

2. ALL CORNERSAND0 EDGESTO BE CRO120 SMOOTH 1 PLATE. TYPE 316 SSo.g'j 4". 0'-6'

3. BRACKETTO BE MOUJNTED USING Y"DIAMETERSS HILTi K661 001.1III

       .HALF COUPLING.SS. 1'-I  AFPT                          ANCHORS. MIN!EMSED TO BE 15,

4. N0 REBARSMALLBE CUT FOR INSTALLAIOGN OF CEA'S.

ANCHOR BLT. HILT] All Ill. A SS.Iy DIAMETER 3 LONG RELOCATEBRACKETAS NIECESSARY TO AVOIDRAEAR.

5. WELDELECTRODE SMALLBE E316-XX OR E3S4-XX AS RE.0.

ECP-10-000208 INSTALLATION SKETCH 003 SHEET 2 OF 2 HALFrCOUPLING1-' P PLAE SS. 1,x 4'o-I_ PL4ATEN S Q) 2" DI-INETERHOLE

                -Pr V"

PLATE. SS. lf. 4' . 1*-D"-/14 SECTION VIEW D-D ANCHOR BRACKET MOUNTING ASSEMBLY ELEVATION VIEW

ECP-10-000208 INSTALLATION SKETCH 004 SHEET 1 OF 2 MOTES:I I. AUOPTPLATE TO USISNTRUT CHANNELUSING IV' OS BOLTS ANDUNISTRUT SPRING NUTS 2. I MOU1JNT UNIST.UT P1. CHANIE N IK BOLT IIl ANCHORS LS USIN4GtILTI Le DIAMETERSS NIN E.IBED IW"

3. ALL MATERIALTO 8R TYPE 304 0B,31T SS UNLESS'NITED.

4 DINT INSTRUMENT TO *ACK PLATE USIN0Gli4-20 SS BOLTS

                                                                 "          1                                  RHOLES  TO BE ORILLED LAO TAPPED IA BACAPLATE PER VENDORTEMPLATE I  I I                                           S. UNISTRU7 CHANNELS   HAT BE RUN A   VERTICALON HORIZONTAL EXACTORIENTATIONTO BE DETERINED 8N IlELO A. TIGCSTEN ALL BILTS TO A SlA , G' CNC     ITI,ON
                                                                                                                                                        ,O I I  I                                  T. AI45     BOLTS ANDROLES'NOT SOV* F'ORCLARITY I        PLATE. TYPE S1I SS.'...T4 B T-2    8. NO RERANSNJ1L NE COT TN TAT INSTALLITION OF THE CEAS.

I9. NELD ELECTRODE SHALL BE ASIA-NX OR E304-XX AS REO. PLATE AND INOICATOR LEVEL INDICATOR MOUNTING ASSEMBLY ELEVATION VIEW

ECP-10-000208 INSTALLATION SKETCH 004 SHEET 2 OF 2 PLATE. TYPE 316 SS..', 6' 0 -2O LEVEL INDICAT(OB NOT SHROB6 FOR CLARITY LEVEL.INDICATOR ROURTIRODETAILBILL OF MATERIA.LS OTT OESRBIPTICIO 4' P1OO0 UNISTAUT A BOLT. HE% ADAO. TYPE 31f, ST. 3/8-16. 1

• LONG 4 ASOER. FLAT. TYPE 316 SS. A'i 6

4 SPRIRG*UT. ," UNISTRUT I PLATE. TYPE 316 S$.'.4" 14'

                                                                                                                               ?    PLATE.TYPE 3it  SS.,Zx    6'.      0'.10-2 2    PLAT. TYPE 316 SS."',r ,         O--TODl-.

A RILTI KIRIRBT Ill. SS,,'S IAll1ER 2~' LODO PLATE. TYPE 316 SS.',ýx, 6" x 0'-0D' HILTI ARIK BOLT Ill. SS..." OIAIETEARI%, MIN EAED TYP. 4 PLCS PLATE. TYPE 316 S*.'.,x W4 x 1-2" SECTION VIEW D-D

ECP-1 0-000208 INSTALLATION SKETCH 005 SHEET 1 OF 2 "II -IT flMA 1201A LI E~1 FIIEI~ZLKIE~Z 14 I[=12 Z. l] 2

                               .1            JNCTION I          Room OtUIPMCNT

ECP-1 0-000208 INSTALLATION SKETCH 005 SHEET 2 OF 2 2LIT 2*00 2LIT 2L11 2501A 2WI1A W W 2~Z1L2UI L~IZ LI~ E~lLZ~iE~l El] =2r,.L~I IEOuIPmEN' T ROOM

ECP-1 0-000208 INSTALLATION SKETCH 006 SHEET 1 OF 1 P1000 WAISTRuTFIELD CUT TOSTIlT TYP NOTES I. JUNCTION BOXS TO SE LOCATED ST FIELD.

2. JU.NCTIONaXES TO BE MOUNTEDPEA SKETCRH AN E.-4

3. A5 TO SE NITT*EE USING SS */4-20 ELCTS.WASHERS AND SPRIN NUTS HOFFA4NENCLOSUREA-1210WSS SACIMP1ATC A-IZPIOSS -

JUNCTIION BOX MIUNTINGDETAIL BILL O WATERIAMS OTY DESCRIPTIO1N 6° DIN RAIL 199-DRI. ALLENBRADLEY OR £OUAL 1I TERMINA.L ELOCTS. ALLENBRADLEY1492-43 2 TERMINALBLOCK END BLOCKS.ALLEN RADOLE* 1492-{'BJ3 I NCF*rATN ENCLOSURE A-12106T*SS I "OFFMJNFNCLUSUE-. BSAC-PLATE A-12PIOSS

                                                                   .. PIO00 UNISTRUT FIELD CUT TO SUIT 4     L. NEWHEAD. 316 SS. 1/4-20. 3"Z LONG 4   WASHER.FLAT. 316 SS. ',r 4  SPRING WAT. 1/4-20 LINISTRUT PIOOG-1420 2  TERMINAL  ELOCKENIl RETAINER. ALLENBRADLEY    1492-EAJTS JUNCTION BOX (COVER REMOVED)

ECP-10-000208 INSTALLATION SKETCH 007 SHEET 1 OF 1 Tat 24V Dc IN -p OK I Iv00 14I IZt4?24004 24V0OC IN -P I&4 1415108 ITZ4OIB)_ P UlN-4 P v NW .4 41713019 IZL1T22018) 6 SMtE p OR ILITt4OID__42LIT2SOIA, I2 7 P SK.I a , am ILITISOIS _I2LI123OIB4 WIN ILI40* 4L46

                                               ;NL                                                         .90 P
                                                       .4   ILI~lOIN     2L1210018                                 SIR      ILIT16010 , 2LIT2S401N it SmtE f 21. 1T210     )111100      A   a 13
                                         '4                                                                'S  Pw SP                                                                               JUNCh~4TION M
                                         '5
                                        -;7                                                                -'a PHL CONNECTION DETAIL                                                     CONNECTION DETAIL JUNCTION BOX TYPE B                                                    JUNCTION BOX TYPE A NOTESt I. JLNCTIONBOX TO 13 LOCATED by FIE4LD

2. INSTALLDIN RAIL TO ALLOW FOR MOR &LOCKS IN THE rUTIUE

ECP-10-000208 INSTALLATION SKETCH 008 SHEET I OF 4 IT. 0 M[E H*O UPPER MOUINTING 8RACKET 3/8-16 BOLT BOLTINCHARDWARE U/- H" SS HALr

                                                                       -   LOWERWEUNTNG BRACWE iPLATE A.. INDICATOR ELEVATION         VIEW BAY LEVEL MOUNTING BRACKET ASSEMBLY

ECP-10-000208 INSTALLATION SKETCH 008 SHEET 2 OF 4 Typ.

• SS PLATE 61,w DIAWTER WITH 2w DIAiNTER HOLE SS PLATE6W0 DIAMETERWITH2' TIAbCTER HOLE PLATE AND 1N01CATDA T0'y"MPTSS HALFCOL'IKIAL BAR SS.'YxI'w WITH 0 AIAATER 1 HOL 1OP 2 PLCS R ILL'EDAS SHOWN a2 0TP. I SS HALFCOUPLING t PLATEA.~ INDICATOR PLAN VIEW BAY LEVEL SECTION VIEW LOWER MOUNTING BRACKET A-A

ECP-1 0-000208 INSTALLATION SKETCH 008 SHEET 3 OF 4 WITR6".ý DIAMETERHOL.E DIAMETERHOLE DRILLED AT T-12 DIAMETER 7yT 4 PI.CS PLAN VIEW PLAN VIEW BOTTOM SIDE BAY LEVEL BAY LEVEL UPPER MOUNTING BRACKET UPPER MOUNTING BRACKET (INSTRUMENT COVER NOT SHOWN)

ECP-1 0-000208 INSTALLATION SKETCH 008 SHEET A OF 4 PLATE. TYPE 316 S$.-,. o DVIA.WITH 3m DIAMETERHOLE P0.10UPER-ASTE SI I I,

                                                                                                                                                           -    3' DIAMETER HOLE TO VIEWLEVAL I.

• II I I I. -LONG 30I%

I I /- ANGL SS.IIB.P, Y', II

• II
• II II
• II II I.
• II I I DIAMETERHOLE DRILLEDAS SRO"R 7',z- DIAMETER HOLEPAT7ERN I I
• II I.

II I. I I I I

• II I I
• II
• II II
• II I I I I
• II I I
• II BAY LEVEL INSTRUMENT I.

II INSTRUMENT COVER PLATE I I .s- ' ROLE l.RIAM4ETER I, BAY LEVEL BRACKETASSEMBLY BILL OF MATERIALS 0,r DESCRIPTION tOTES: I PLATE. TYPE 316 SS.'.42"x 10'-" WITH6 3-4" DIAABTEAROLE B-B PLATE. TYPE 316 SS.,. 6 l DIAMETERWITH 2m DIAIMTERHOLE 1. 2. ALL MATERIALTO BE TYPE 304 OR 316 SS OR E.UAL ALL CORNERS ATD EDGESTO BE GROUND SL0OTIT BAR. TYPE 316 SS.'xT " 3. UPPER MOIUNTIN1G BRACKET PLATE TO.BE ATTACHED TO GRATINGUSING GRATINGCLIPS 6 HEX HEADBOLTS. SS. 1/4-20 LENGTHAS RED. AND SS BOLTS ANDHIARDWARE AS REQUIRED. BAY LEVEL INSTRUMENT HEX NUT. SS. 114-2O

4. VERIFY THE LEVELPRO1E IS PLUTB ANDLEVELPRIOR TO TIGCATEN*IC BOLTS SWING ARM DETAIL ANGLE.SS~l-xT.T. 10'1l LONG

5. SECUREINSTRUVENT CABLETO ENSUREIT DOESNOT AFFECT POSITION or INSTRUMENT MAOIS PROPERLYSUPPORTED 2 ANGLE. SS.',.x 0,ri'l '-2. Vl,7" LOWG 6. ENSURETHE CRATING1 CUTOUTDOESNOT EXCEEO9B SOUIE DICIES 2 REQ. 2 HALF COULI.ING.SS.

5 11,2" NPT MINIMIZESIZE OF OPENING. SMALLBE B* 8" .- r GRATING STALLBE BANOEDAS REOUIREBPER SITE PROCEDURES. GRATINGCLIPS ANDISS BOLTINGHARDWARE 7. INSTRUNCHT SMTALL BE PLACED TO ENASUIREIT DOES NOT IMPACT RITIOEDORATINGCOVERS, ROB NUI. SS. 3/B-T6 S.BOLT COVERPLATE TO UPPER MOUNTING PLATE AS 5HOW1NUSIRO 1/4-20 BOLTS HEX HEADBOLTS. SS. 3S18-16 x A RIGHTEN T. ALL BOLTSTO A SMUGTIGHT CONDITION PLATE. TYPE 316 SS.*:. 9* DIAMETERWITH 3- DIAMETERHOLE I0. WELDELECTR1ODE SMALLRE ESIS-XX OR E304-XX AS RED.

ECP-1O-000208 INSTALLATION SKETCH 009 SHEET 1 OF 2 SECURITYCOVERS TRASHRACKCOVERS CUT FOR CONDUITROUTIIC CABLE ILI 71101 FREE AIR 24VDC SUIPPY CUT FOR CONDUITROUTING

ECP-1O-000208 INSTALLATION SKETCH 009 SHEET 2 OF 2 ScCuRI y Can(R$ TRASW0- *COvft COIMTfl CUT FRi CONUIIT AIR CABLE

                                                 -      Wu2100

ECP-10-000208 FORM 11, ECP MATERIALS LIST PO/SRI NO.! MAKE/ REQ NO. PRINT/ ON MODEL or QUANTITY/ or STOCK Q-LIST CODE or ORDER COMPONENT/PART TYPE UNITS SRI NO. ID NO. CLASS STAND. (Y/N) REMARKS Radar Level Probe Ohmart- 18 NSR Y Vega/PS65. UXMNDH KNAX Remote Display w/ Wall Mount Adapter Ohmart- 2 NSR Y Vega/DIS61

                                            .UFKNB 24VDC Power Supply 1.5A               Phoenix         2                                  NSR                                  Or Equivalent Contact/Ml NI-SYS-PS-100-240AC/24D C/1.5 2/C 20 AWG T.S.P                Belden/1033    2000 ft                               NSR                                  Or Equivalent A

4/C 20 AWG w/ shield Beldenr3016 100 ft NSR Or Equivalent A Pigtail power cord - 4ft FarmTek/W 2 NSR Or Equivalent F4629 Refer to Installation Sketches for additional BOM items. SHEET I of I State as appropriate that when a Purchase Order (P.O.) is specified on the Bill of Materials, the item purchased shall be from that P.O. and no substitution is allowed without the concurrence of the Responsible Engineer. CNG-FES-015 Rev. 00002 . ý .....

FORM 13, RECORD OF WALKDOWN (Page 1 of 2) ":ECPSupp No.:. ..ECP-10-000208 Rev. No.: ,0000

.ECP . .. . .. . ~~~~~~~~~~... " ........

Type of Walkdown Completed: Walkdown Lead: Brad Wright Date Completed: 3/17/2010 Z CONCEPTUAL or PRE-DESIGN System/structure/component/location: E- POST DESIGN/PRE-INSTALLATION Unit 1 & 2 Intake Structure El POST CONSTRUCTION/INSTALLATION F- TURNOVER/CLOSEOUT Objective: El OTHER: Walkdown 2eneral layout for radar probe locations and identify any issues REQUIRED Waikdown. Participants - Check Boi*fo Allthat Apply . .. :  : Identify the.. nyo Personnel by Name; In icataAg.reement .ed withb WalkdownConclusions El Change Requester: El Design Engineer: [] System Engineer: E] Project Manager: Z Designer (Mech/Civil): E] Designer (E&C) E] Planner (Mech.): Z Planner (E&C): Dave Earp Donald Debuhr EL Maintenance (Mech.): E] Maintenance (E&C): El Procurement Engineer: E] Health Physics: El Design Engr (Elec): E] Design Engr (I&C): Z Design Engr (Mech): E] Design Engr (Civil): Charlie LaRue (S&L) El Operations: El ISI: E] Fire& Safety: E] Test Coordinator: 1- Simulator or Training: E] Nuclear Training: E] As-needed participant: El As-needed participant: OPEN ISSUES AND EXCEPTIONS LISTING: Description of Open Item or Issues Identified Resolution Resp Actions Org ECD/AI & Actions 10" penetrations have interference issues with piping Install probes S&L in 6" penetrations USE: ADDITIONAL

           . i*. :..'   . .::i:*::* !:,.. . :!REQUIRED SHEETS:AS                       '. .: . * . .:.
                                               *!: .*.:**              . .   . .             .:.:i::,:. , :** . , !.. Check
                                                                                                                       . if::additioiialsheets               used
                                                                                                                                 .. ,. :: :* ' *': .: *:..,* ..:.1/4    E CNG.FES-015 Rev. 00002

FORM 13, RECORD OF WALKDOWN (Page 2 of 2) ECP Supp No.: ECP-10-000208 ý Rev. No.:' .0000< Type of Walkdown Completed: Walkdown Lead: Brad Wright Date Completed: 3/24/2010 Z CONCEPTUAL or PRE-DESIGN System/structure/component/location: Ml POST DESIGN/PRE-INSTALLATION Unit 1 & 2 Intake Structure El POST CONSTRUCTION/INSTALLATION El TURNOVER/CLOSEOUT Objective: [] OTHER: Locate radar probe power supply location, locate bay level locaions, and identify conduit routing "REQUTIRED Walkdown Participants - Check.Box for All: that Apply Identifythe Involved Personnel by Name; Indicate Agreement with Walkdown Conclusions. El Change Requester: El Design Engineer: E] System Engineer: El Project Manager: E] Designer (Mech/Civil): El Designer (E&C) E] Planner (Mech.): [I Planner (E&C): El Maintenance (Mech.): [] Maintenance (E&C): El Procurement Engineer: El Health Physics: El Design Engr (Elec): E- Design Engr (I&C): [ Design Engr (Mech): E] Design Engr (Civil): Charlie LaRue (S&L) El Operations: Dl ISI: E] Fire & Safety: El Test Coordinator: Dl Simulator or Training: E Nuclear Training: El As-needed participant: E1 As-needed participant: OPEN ISSUES..AND EXCEPTIONS LISTING: Description of Open Item or Issues Identified Resolution Resp Actions Org ECD/AI & Actions None .USE ADDITIONAL i.:.. *::*:.:AL

                   ' *"*    SHEETS

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                                                                                                                             ",i.? :: used

.= Ell CNG-FES-015 Rev. 00002

FORM 16, FIRE PROTECTION/APPENDIX R REVIEW ELECTRICAL DESIGN FEATURES CHECKLIST (Page I of 2) EC SunP No.: ECP-10-000208 Rev.,No.: 0000 Does the proposed engineering in its final form, as well as during interim installation procedures: A. Does the ECP directly or indirectly involve Appendix R equipment? [3 YES 0 NO E] N/A B. Does the ECP add, relocate or change equipment whose operation would be E] YES Z NO E N/A required to achieve the safe shutdown functions identified in the Interactive Cable Analysis (ICA)? (Include equipment that provides additional safe shutdown systems boundary isolation, electrical distribution equipment changes (such as addition or deletion of loads, changes to relay settings) and electrically powered instruments.) C. Is Appendix R equipment being deleted? EYES [D NO E] N/A D. Does the ECP change the characteristics of Appendix R equipment? E YES [K NO E] N/A E. Does the ECP involve existing or adding new power, control, or E YES Z NO E] N/A instrumentation cables for Items A through D above? F. Does the ECP create a new potential associated circuit of concern? E YES Z NO E] N/A G. Does the ECP involve or add cables associated with Auxiliary Shutdown Panel YES Z NO [] N/A isolation from the control room? H. Does the ECP affect compliance with requirements of, or affect drawings, E] YES [D NO E] N/A statements, or analysis in the site Fire Protection Program, such as changes to fire rated compartmentation as shown on the drawings? Does the ECP involve changes to the automatic suppression system or E YES NO [] N/A standpipe and hose systems for safety-related structures? I. Does the ECP affect plant Technical Specifications, Technical Requirements E YES [D NO E] N/A Manuals, or FSAR positions related to Fire Protection? J. Does the ECP involve emergency lighting required for operation of safe E] YES 0 NO E N/A shutdown equipment and access and egress routes thereto or require additional emergency lighting? K. Does the ECP affect communication systems that are being credited for use in E YES NO E] N/A shutting the plant down during a fire? Or does the modification introduce a new manual action that will require communication from an area of the plant E YES [ NO E N/A for which the communication system has not been previously analyzed? L. Does the ECP require a revision to the ICA Database? E YES [ NO E] N/A M. Does the ECP require a change to the ASSARF packages? E] YES Z NO [] N/A N. Does the ECP affect criteria for which a NRC-approved technical exemption E] YES 2] NO E] N/A request has been granted according to the site Fire Protection Program?

0. Does the ECP affect cable trays with marinate tray covers required for E YES Z NO E] N/A Appendix R?

For CCNPP, this refers specifically to trays ZDICF07, ZEICFI9, ZFICLI7, and ZGICLI0 inUnit I containment and ZF2CLO7, ZD2CF08, and ZE2CFI8 in Unit 2 containment. P. Does the ECP affect calculations or AOPs associated with the ICA? (If, E YES Z NO E N/A "YES," review required by Nuclear Engineering and Nuclear Operations.) I_ _ __ CNG-FES-015 Rev. 00002

FORM 16, FIRE PROTECTION/APPENDIX R REVIEW ELECTRICAL DESIGN FEATURES CHECKLIST (Page 2 of 2) ECP Supp No.: *ECP 10m#00208 :X Rev. No.:. 0000 Discuss "YES" responses below. Indicate if the change is justified. Identify information in the site Fire Protection Program that will require update and for which changes are unacceptable. When comments are resolved, the resolution, along with appropriate justification, should be included. NONE The change [-] does/! ] does not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire. Fire Protection Electrical Engineer: (Printed Name and Signature) Date CNG-FES-015 Rev. 00002

FORM 17, FIRE PROTECTION/APPENDIX R REVIEW FIRE PROTECTION DESIGN FEATURES CHECKLIST (Page 1 of 2) , PSupp No. ECP-10000208:."

                            *. .....' .'*.*/L
                                               */ Y
                                                                  .::*k  *:*,:

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Rev. No.:. 0006::.. Does the proposed engineering in its final form, as well as during interim installation procedures: A. Add, delete or relocate combustible materials within the plant (any quantity of F] YES E] NO E] N/A flammable/combustible liquid or combustible solid)? B. Affect Appendix R or controlled fire rated barriers (walls, floors, doors, El YES 0 NO E] N/A dampers, penetrations). Add new barriers, remove or relocate existing barriers, or modify the design of existing barriers in ways not previously approved? Use penetration seal designs which have not been previously approved? Affect the integrity of structural steel? Affect fire propagation requirements, including areas free of intervening combustible and radiant energy shields? C. Affect installed fire protection SSCs (sprinkler, halon, hose stations, smoke El YES E NO El N/A detection, heat detection, flame detection, etc.). Install new components within 36 inches of sprinklers/detectors/etc. or that block sprinkler spray patterns, or isolate portions of a room from normal circulation? D. Affect fire fighting equipment, fire suppression efforts, or post fire operations [E YES Z NO E] N/A in any area of the plant? E. Add or relocate Safety Related equipment (specifically equipment which might El YES Z NO E] N/A be adversely affected by water spray) in an area of the plant protected by a sprinkler system? F. Add/modify fire hazards within the plant in any way? El YES 0 NO [] N/A G. Alter the physical arrangement or configuration of an area that affects fire El YES Z NO El N/A protection equipment/systems, access and egress routes, emergency lighting, etc? H. Utilize construction/modification techniques that may result in an inadvertent El YES [ NO El N/A operation of fire protection equipment or systems. I. Alter the location, function, design or material requirements of fire protection El YES [ NO El N/A equipment and/or systems? J. Affect the Reactor Coolant Pump/Motor Lube Oil Collection System? El YES 0 NO E] N/A K. Affect compliance with requirements of source documents as applicable such El YES Z NO El N/A as the SER, UFSAR, TRM, etc.? L. Affect compliance with guidelines provided in applicable National Fire E] YES E NO E] N/A Protection Association Codes and Standards? M. Affect compliance with guidelines provided in applicable Nuclear Electric El YES 0 NO E] N/A Insurance Limited Loss Control Standards? N. Alter or affect what has previously been stated in the site Fire Protection El YES [ NO El N/A Program such as drawings, statements, or analysis (combustible loading or fire hazards)?

0. Affect criteria for which an NRC-approved technical exemption request has El YES [ NO El N/A been granted?

CNG-FES-015 Rev. 00002

FORM 17, FIRE PROTECTION/APPENDIX R REVIEW FIRE PROTECTION DESIGN FEATURES CHECKLIST (Page 2 of 2) i:ECP Supp No.: ECP-10-000208 ,, Rev. No.: 0000 "YES" responses shall be discussed and appropriately evaluated below. Identify information in the Fire Protection Program that will require update and/or for which the activity is considered unacceptable. This change installs approximately 600ft of cable routed free-air on the intake structure deck. This installation is outside the intake structure and does not have any fire protection requirements. It has been recommended that cable used be flame retardant in accordance with IEEE 383. Cable specified on Form 11, ECP Material List, meets the specifications of IEEE 383 for Class lE flame retardant cable. The change E] does/! does not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire. Fire Protection Engineer: N/A per Chris Dobry (Printed Name and Signature) Date CNG-FES-015 Rev. 00002

I I ACTION VALUE BASIS DOCUMENT

ACTION VALUE BASIS DOCUMENT ESP No.: 1925-01326 Supp, No.: - Rev. No.: __ Page __of D)oo)D: EOP-33.02 Rev. No.: 0 Page 2 of 3 I Basis Reference(s): I. BGE Emergency Operating Procedures: EQ2 4 RevisioniLL.bang. Unit 2 Change # 4 2 12 9 5 2 16 15 8 2 21 25

2. IRO-033-206, Revision 1.

Attachment:

1. Excerpt from NFPA 325M, pg. 59, "Fire Hazard Properties of Flammable Liquids, Gases, and Volatile Solids", 1991 Edition.

2. IRO-033-206, Revision 1.

Documentation Level: 3 Function of Equipment and Use: The control room indication for hydrogen concentration is used by the operators to Indicate degrading conditions exist in containment. This indication is precautionary and ensures that the Containment Combustible Gas Control Safety Function Acceptance Criteria are satisfied, Action Value Basis: Following an Excess Steam Demand Event (ESDE) inside, containment, LOAF or LOCA, containment hydrogen concentration is expected to increase as a result of the metal-water reactions involving zircaloy or stainless steel at high RCS temperatures, the radiolysis of water by fission product decay, or the corrosion of aluminum and zinc by containment spray. The purpose of this action value is to warn the operators that the possibility of hydrogen ignition exists if containment hydrogen concentration reaches 4.0% by volume. In addition, caution statements in the BOPs advise against the use of any equipment in containment if the hydrogen concentration is greater than 4.0% by volume to reduce the possibility of hydrogen ignition.

ACTION VALUE BASIS DOCUMENT ESP No.: 299i_-QI2)6 Supp. No.: __ Rev. No.: __ Page__of DocID: EOP-13.02 Rev.No.: 0 Page 3 of 3 Two control room recorders (AR-651 9 and AR.6527) indicate the hydrogen concentration in containment, and follow-on grab samples provide redundant indication. Corroborative indications of degrading containment conditions are provided by containment temperature indication, containment pressure indication, and containment radiation monitors. The current action value of 4.0% by volume hydrogen concentration, defined as the Lower Explosive Limit of hydrogen mixed in air (Attahment 1), is conservative because the moisture content in containment following a LOCA, LOAF, or ESDE would inert the hydrogen-air mixture (Reference 2). When the hydrogen concentration exceeds 0.5%, all available Hydrogen Recombiners will be operating to maIntain/reduce the hydrogen concentration to a non-explosive level, If the Containment Environment continues to deteriorate, the BOPs direct the operator to ERPIPs. Subsequent Hydrogen Purge System operation is directed by the Plant Technical Support Center based on grab sample results. For the following reasons, this application is a Level 3 application and consideration of instrument uncertainty is not required:

• The action value is very conservative considering hydrogen-air mixture inerting by moisture.

0 No equipment manipulations are made by operators as a result of this indication.

• The action value is only precautionary to remind operators of the possibility of ignition following a LOCA, LOAF, or ESDE.
• Corroborative indications of containment environmental conditions are available.

              # Redundant indication of hydrogen concentration via grab samples is available.

Remaining Actions: Chemistry will verify that uncertainty is applied to grab samples as needed, This will be from an EOP perspective and will be tracked by BOE AIT # ES199501326, Milesone 8.

ACTION VALUE BASIS DOCUMENT ESP No.: TES1 99801680 1Supp. No.: 100 1 1Rev. No.: 10000 1Page of INITIATION DOC. ID: EOP-23.02 Rev: I Page I of_3 Responsible Group: Bechtel I&C ' 1,i Responsible Engineer: S. Kapur BASIS DOCUMENT Use Summary: This action value is used to verify that plant parameters are in the normal or expected post-trip range, to ensure that Inventory Control and RCS/Heat Removal Safety Function Acceptance Criteria are satisfied, to provide indirect support of a safety function, and to consider parameters in the decision making process. Parameter: Subcooling Margin (SCM) Value: 25* F Subcooled Comments: None REVIEW AND APPROVAL: Responsible Engineer: & '_',,-&4 0 ftate: , .603 Independent Reviewer: * "* & BcAAr) Date: 3/cs /O a Approval: Cflq* lc, -- ) Date: 3 e4l0 OR (for Vendor Documents) Owner Acceptance Reviewer(s): J. P. M*c*uhan * ' i/Y 403 NEU: Date: PD&MAU: Date: ICU: Date:

ACTION VALUE BASIS DOCUMENT ESPNo.: ES199801680 Supp. No.: 00_1 Rev. No.: 0000 Page _ of I L DoclD: EOP-23.02 Rev. No.: L Page 2 of 3 Basis Reference(s):

1. BGE Emergency Operating Procedures:

EOP #4 Revision Unit I Chanpe # Unit 2 Change # 6 2 13 12 8 2 21 25

2. CE-NPSD-928-NP, Section 4, "Possible Solutions to Margin Loss",

Revision 1.

3. Deleted

4. BGE Action Value Basis Document AVB # EOP-23.01, "Subcooling Margin", Revision 1.

5. Deleted

6. BGE Emergency Operating Procedures:

Attachment # Revision Unit I Change # Unit 2 Change # 1 2 10 8

7. Westinghouse Calculation 8067-ICE-36372, Rev. 01, "Uncertainty Calculation for the Subcooled Margin Monitor System for the BG&E PAMS Upgrade".

Documentation Level: 2 Function of Equipment and Use: Subcooling Margin (SCM) is used to verify that plant parameters are in the normal or expected post-trip range, to ensure that Inventory Control Safety Function Acceptance Criteria are satisfied, to provide indirect support of a safety function, and to consider parameters in the decision making process.

ACTION VALUE BASIS DOCUMENT ESP No.: ES 199801680 Supp. No.: 001 Rev. No.: 0000 Page of DoclD: EOP-23.02 Rev. No.: I Page 3 of 3 Action Value Basis: This action value is used to provide a minimum control limit of SCM for a Steam Generator Tube Rupture (SGTR) and for the Functional Recovery Procedure (FRP), since it can include an SGTR. This value was chosen lower than 30 degrees in order to reduce the primary-to-secondary pressure difference which will reduce flow out of the break. This action value is classified as a level 2 application, which requires that instrument uncertainties be addressed, either in a formal calculation or by engineering judgment. The control room indication for subcooling margin is obtained from PAMS displays ICRTIC05A/B and 2CRT2CO5A/B. PAM displays on C04 and C06 are part of an integrated system and can provide identical data. These indicators are classified as Category I PAM instruments. The 25 degrees Subcooled action value is intended to ensure that subcooling of the RCS remains above zero when instrument uncertainties are addressed (this is set lower than the 30 degrees subcooled action value to allow RCS and S/G pressures to be more closely equalized to minimize flow out the break). During non-harsh containment conditions (which apply to a SGTR), the 25 degrees subcooling will accommodate instrument uncertainties when PAMS displays are used (Reference 7) at RCS pressure greater than or equal to 250 psia. In addition to this action value, several corroborative indications of adequate SCM are available to the operators, including pressurizer level, pressurizer pressure, and RVLMS. This action value is also used as one of the many Reactor Coolant Pump (RCP) starting criterion in EOP 6. The purpose of this is to ensure a single phase, subcooled RCS fluid, thereby limiting the expected decrease in Pressurizer level once the pumps are started. This function is classified as a level 2 application, which requires that instrument uncertainties be addressed, either in a formal calculation or by engineering judgment. Based on the uncertainty discussions in Reference 4, the 25 degree value is sufficient during normal containment conditions. This is acceptable since RCP restart is prohibited by CIS closing component cooling containment Isolation Valves during harsh containment conditions. In addition, the RCP starting criteria also requires that RCS pressure be within the RCP operating curves (Reference 6), which is more limiting than the SCM requirement. Remaining Actions: None

ATTACHMENT 17, ACTION VALUE BASES DOCUMENT (AVBASES) ES199801680, Supp. No. 001, Rev. 0000 EOP-24.34 Page 1 of 2 INITIATION (Control Doc Type - AVBASIS) DOCID: EOP-24.34 Rev.No.: 0001 (DEVICE# - CHANGE#) LETTER, IF APPUCABLE RESPONSBLE GROUP: Bechtel I&C (0 O)) RESPONSIBLE ENGINEER: S. Kapur BASIS DOCUMENT Use Summary: This action value is used to establish the Core and RCS Heat Removal Safety Function Status check Criteria for EOP-3, 4, 6, and 7. The value is based on assessing the effectiveness of heat removal via the steam generators. PARAMETER: CET Temperature VALUE: < 600 degrees F COMMENTS: REVIEW AND APPROVAL: RESPONSIBLE ENGINEER:. j,* Ž DATE: 3/ "/6* INDEPENDENT REVIEWER: ._. DATE: _ ____._____ APPROVAL: '7 p eC,.~~ DATE' ________ OR (for Vendor Documents) OWNER ACCEPTANCE P. Mc~uighan C q/A" REVIEWER(S): M g NEU: DATE: PD&MAU: DATE: ICU: DATE:

ATTACHMENT 17, ACTION VALUE BASES DOCUMENT (AVBASES) ES199801680, Supp. No. 001, Rev. 0000 EOP-24.34 Page 2 of 2 BASIS Reference(s):

1. CEN-152 Rev 4, "Emergency Procedure Guidelines"

2. CA02090, "Uncertainty Calculation for Pressurizer Pressure"

3. System 058 Setpoint File

4. HCI Record of Conversation (attached)

5. System 083 Setpoint File

6. DCALC CA0131 1, "Instrument Uncertainty Calculation for CET Indication"

7. Westinghouse Calculation 8067-ICE-36370, Rev. 01. "Uncertainty Calculation for the Core Exit Thermocouple System for the BG&E PAMS Upgrade" (,C A IP 00t-OP1 S1381-0ec. Oda Documentation Level. 2 Function of Equipment and Use:

The Control Room CET indications are used by the operators for Safety Function Status Checks for EOP-3, 4, 6, and 7 to ensure that Steam Generator heat removal is adequate. Action Value Basis: The purpose of this action value is to demonstrate adequate heat removal via the Steam Generators. The Main Steam Safety Valves (MSSVs) will lift as necessary to limit S/G pressure and will remove energy from the primary as a result. If S/G pressure increases above the MSSV lift setpoints, then it can be assumed that S/Gs are not effective in removing heat from the RCS and therefore the core. The engineering limit is based on the saturation temperature corresponding to the lift setpoint of the PORVs. Although no specific plant manipulations are required by this engineering limit, uncertainty will be considered to ensure that a proper diagnosis of plant status can be made by operators. Therefore, the AVBD is a category 2. The nominal setpoint for the PORVs is 2385 psia per Reference (3). The total loop uncertainty associated with the PORV setpoint is + 77.69 psi -67.78 psi per reference (2). Therefore the lowest actual pressure that could lift a PORV is 2385 - 67.78 = 2317.22 psia. The saturation temperature corresponding to this pressure is 657 degrees F. Therefore as long as RCS temperature remains below 657 degrees, then the S/G's are adequately removing heat from the core. CET indication uncertainty should be considered. For temperatures less than 700 degrees F. an indication bias of -4.1 degrees F exists per references (6 and 7). Other uncertainties associated with CET indication are random and will not specifically be accounted for since eight (8) CET indications are available to the operator. Per reference (4), operators are expected to use the highest reading valid CET indication for EOP applications. With eight indicators, the probability that one of the indicators will read high is approximately 96%. Therefore, as long as the highest indicated CET temperature remains below approximately 653 degrees F (657 - 4 degrees bias), then the S/G's are adequately removing heat from the core. In order to provide additional margin, an engineering limit of 600 degrees F is recommended. This value is sufficiently above the saturation temperature (approx. 548 degrees F) corresponding to the highest MSSV relief pressure (1030 psia per reference 5) to avoid prematurely failing the Safety Function Status Check. (The worst case positive uncertainty of the CETs is 45.70 degrees F per reference 7). Remaining Actions: None

Action Value Basis Document EOP-24.18, Attachment I HCl RECORD OF CONVERSATION Parties Involved: Jim Willis (HCI), Bob Bleacher (BGE Operations) Subject CET Temperature Indications Date: 20 February 1996 Discussion: I spoke with Bob Bleacher of BG&E Operations regarding the CET temperature indications which are used during Emergency Operating Procedures. Specifically, I asked Bob which of the eight CET temperature Indications are used to determine the CET temperature. Bob stated that the operators are Instructed to use the most conservative of the valid CET temperature readings. If a temperature reading is not valid, the operator will switch to a valid Indication. So it is probable that the operator will have available eight valid CET temperature readings to choose the most conservative value from. Signature of HCI Representative: cc. Kirk Melson Bob Hunter Bob Bleacher Frank Barich BGEAVB File Page I of I

Calvert Cliffs Units I and 2 TECH SPEC ACTION VALUE BASIS DOCUMENT MODULE 1 - SPENT FUEL POOL LEVEL ESP No.: ES199800829 Supp. No.: 000 -Rev. No.: 0000 TS-05.01 Rev. 0 INITIATION: Responsible Group: DES ICU Responsible Engineer: Stephen Keefe BASIS DOCUMENT: SFUEL STORAGE Component. SPENT FUEL POOL Parameter, LEVEL T.S. Valuefs); > or = 21.5 FT above top of irradiated fuel in the fuel racks Mode(s): All Comment: Margin is satisfactory. REVIEW AND APPROVAL: ABB: Verification Status: Complete The information contained in this docummnhas been verified to be correct by means of design review. Cognizant Engineer: J.R1LCongdonat:-l eop Independent Reviewer: H. F. Sha I~JCgJI4" 4 *)]/ Date: Management Approver: _C._J. Gimbron ate: _ iZf _- IF BGE: Owner Acceptance Reviewer(s): NEU: A&k ,A;Date: iIý;o ICU: S.E. KEEFE Date ABB Doc ID. ST-98-410-07 R,ev. No.: 0 1 Pa e1 of 4

Calvert Cliffs Units I and 2 TECH SPEC ACTION VALUE BASIS DOCUMENT MODULE 1 - SPENT FUEL POOL LEVEL [ESP No.:] ES 199800829 ISupp. No.: I000 IRev. No.: I0000 TS-05.01 Rev. 0 Part I - Action Value Bases References Unit Document

1. 1, 2 Calvert Cliffs Nuclear Power Plant Improved Technical Specifications. Unit I Amendment No. 230, Unit 2 Amendment No. 206

2. 1,2 Calvert Cliffs UFSAR, Revision 23

3. 1,2 BG&E Calculation Number C-91-224, Rev. 0, Spent Fuel Pool Water Level Evaluation Per NCR 8936/9960, 8/26/91

4. 1, 2 Calvert Cliffs Master Calibration Data Sheet for Spent Fuel Pool Level, 0-LIA-2001 and 0-LIA-2002

5. 1, 2 BGE DCALC CA 04048, Rev. 0, "Fuel Handling Accident During Reconstitution,"

3/10/98

6. CE-NPSD-925, revision 00, "Guidelines for Addressing Instrument Uncertainties in Emergency Operating Procedures and Technical Specifications" January 1994

7. 1,2 CCNPP Unit One and Two Control Room Logsheet Mode I and 2

8. 1,2 CCNPP Surveillance Test Procedure, STP 0-87-1(2), Rev. 12, Borated Water Source 7 Day Operability Verification, 4/29/98 T.S. Value Use and Application Summary:

LCO 3.7.13 - Limiting condition for operation for spent fuel pool water level. SR 3.7.13.1 - OPERABILITY surveillance requirement for spent fuel pool water level. Technical Specification Value: Engineering Limit: Documentation Level Category:

       > or = 21.5 ft above top of irradiated         23 ft above the top of the fuel                  2 fuel in the fuel racks                         pins of a ruptured fuel assembly standing on the floor of the SF Pool Action Value Basis:

The engineering limit for minimum spent fuel pool level is 23 feet of water covering a ruptured fuel assembly. If a fuel handling incident were to occur while handling fuel in the spent fuel pool area, the following assumptions apply: ABB Doc ID. ST-98-410-07 Rev. No.: 0 Page 2 of 4 I III IIIIMI II

Calvert Cliffs Units 1 and 2 TECH SPEC ACTION VALUE BASIS DOCUMENT MODULE 1 - SPENT FUEL POOL LEVEL ESP No.: I ES199800829 Supp. No.: 1000 I Rev. No.: I 0000 TS-05.01 Rev. 0 L[

• The activity release to the spent fuel pool water is identical to that assumed in the case of a fuel handling incident in containment.
• The overall spent fuel pool decontamination factor for iodine is 100. This is based upon a water level of at least 23 ft covering a ruptured fuel assembly.
• Because a fuel handling accident is shown only to occur by the droUpine of a fuel assembly onto the floor of the spent fuel vool, the Technical Specification requirements that 21.5 ft of water cover the spent fuel racks preserves at least 23 ft above a damaged fuel assembly.
• The release of activity to the air above the spent fuel pool is identical to that released to the containment air in the event of a fuel handling incident in containment.

The analytical limit is 23 ft above the top of a fuel pin. The "top of a fuel pin" is inferred from the treatment of a fuel assembly on. top of a spacer in the SF fuel rack (Ref. 5, pg. 13) where the height of 7.266" from the top of the fuel assembly to the top of a fuel rod is credited. The basis for the analytical limit is to have 23 ft of water available for scrubbing in the event of the rupture of a fuel assembly sitting upright on the floor of the Spent Fuel Pool (SFP). Technical Specifications (TS) allows meeting the 23 ft criterion by requiring 21.5 ft above fuel in the SFP racks, as this is stated to ensure 23 ft over a bundle resting on the bottom of the SFP. The surveillance procedure criterion is 65' 8.5" (Ref. 8, pg. 14). This is most likely the result of the walkdown performed for C-4477.0 (Ref. 3, pg. 13) which states that the top of the fuel assembly in the storage rack is at 44'2 1/2". Adding 21' 6" gives 65' 8 1/2". Therefore, the analytical limit based on SFF level is: Elevation of the bottom of the SFP + 30' 0" (Ref. 3, SH 20) Height of a fuel bundle = + 13' 1.241" (Ref. 3, SH 20) Height of water column assumed in analysis + 23' 0" (Ref. 5, pg. 13) Distance from top of the fuel ass'y to top of fuel pin = - 7. 266" (Ref. 5. pD. 13) Analytical limit based on SFP level = +65' 5.98" = 65' 6" or 65.5 ft Potential effects of indication error If spent fuel pool level is less than 23 ft of water covering a ruptured fuel assembly, then, the safety analysis is not valid and more iodine may be released following a fuel handling accident (dropped fuel assembly) than calculated in the safety analysis. Supporting Reference Excerpts: Ref 2 - 14.18.3.2 -- Fuel Handling Incident in the Spent Fuel Pool Area If a fuel handling incident were to occur while handling fuel in the spent fuel pool area, the following assumptions would apply:

a. The activity release to the spent fuel pool water is identical to that assumed in the case of a fuel handling incident in containment. The overall spent fuel pool decontamination factor for iodine is 100. This is based upon a water level of at least 23 ft covering a ruptured fuel assembly on the floor of the SF Pool.

Because a fuel handling accident is shown only to occur by the dropping of a fuel assembly onto the floor of the spent fuel pool, the Technical Specification requirements that 21.5 ft of water cover the spent fuel in the racks preserves at least 23 ft above a damaged fuel assembly. The release of activity to the air above the spent fuel pool is identical to that released to the containment air in the event of a fuel handling incident in containment-ABB Doe 1D. ST-98-410-07 I Rev. No.: 0 1 Page 3 of 4

Calvert Cliffs Units 1 and 2 TECH SPEC ACTION VALUE BASIS DOCUMENT MODULE 1 - SPENT FUEL POOL LEVEL ESP No.: ES.199800829 Supp. No.: 000 Rev. No.: I 0000 TS-05.01 Rev. 0 Part II - Instrument Uncertainties Asessment Spent Fuel Pool Level 0-LIA-2001 0-LIA-2002 Instrument 1l): (64 FT 8 IN- 67 Fr 8 IN) (64 FT 8 1N- 67 FT,8 N) TLU Calc Complete?: No No Calibration data: Yes Yes (Of. 4) (Ref. 4) TLU, % Span: - Accuracy: + 1.0% + 1.0% TLU, Rug. Units: Setting Tolerance: t 1.4%/ +/- 0.5 IN + 1.4%/ + 0.5 IN Instrument Uncertainties Assessment: This application of Spent Fuel Pool level indication is Category 2 per CE-NPSD-925 (reference 9, pg. 21). This category is reserved for instrument uses that possess a moderate to low degree of nuclear safety significance, or are corroborative in nature. Engineering judgement may be used when determining and applying instrument uncertainties. The engineering limit for minimum spent fuel pool (SFP) level of 23 feet of water covering a ruptured fuel assembly is 65' 6". The minimum TS limit is > 21.5 ft above fuel in the SFP racks is 65' 8.5". The surveillance (Ref. 8, pg. 14) acceptance criterion is also 65' 8.5". Therefore, there is 2.5" of margin between the analytical limit and the TS limit / surveillance procedure criterion-The Control Room operator is required to log the lowest level of LIA-2001 or LIA-2002 every 12 hours (66.5 - 67.25 ft) (Ref. 7, pg. 5). Spent Fuel Pool Level is also checked locally once a day using a tape measurement attached to the side of the Spent Fuel Pool. The remote Control Room SF Pool level instrument is the primary means of monitoring SF Pool level. The local indication is a back-up. TS compliance is achieved by performance of STP 0-87-1/2 every seven days. The surveillance acceptance criterion is 65' 8.5" (Ref. 8, pg. 14). There is no TLU calculation for SFP level indication, LIA-2001 or LIA-2002. However, these instruments are calibrated periodically to a tolerance of + 1.4% ( + 0.5") (Ref.4) and the error allowance for readability is less than 1%. The 2.5" analytical margin will accommodate this instrument inaccuracy. Use of calibration data is judged to be acceptable instead of requiring calculating the TLU because if it were calculated, the TLU value would likely still be less than the available margin. In other words, in order to exceed the 65' 6" analytical minimum level with an indicated minimum level of 65' 8.5", the total loop inaccuracy would have to be greater than t 2.5" or + 8.9%. Loop inaccuracy of this magnitude is not likely. The 2.5" available margin between the analytical limit and the TS limit / surveillance procedure criteria can accommodate the + 0.5" instrument inaccuracy. Evaluation: The margin is satisfactory. ABB Doe ID. ST-98-410-07 Rev. No.: 0 Page 4 of 4

Calvert Cliffs Units 1 and 2 TECH SPEC ACTION VALUE BASIS DOCUMENT MODULE 1 - REFUELING CANAL WATER LEVEL INITIATION: Responsible Group: DES ICU Responsible Engineer: Stenhen Keefe BASIS DOCUMENT: Svstenu REFUELING C28niamt WATER Parameter LEVEL T.S. Value~s): > or = 23 ft over top of fuel seated in reactor vessel

                 < 23 ft over top of fuel seated in reactor vessel Modeffl:          6 Comment:          Margin is satisfactory.

1. During the course of this evaluation, it was determined that LI-4140 was currently referenced for use in OP-07. It should not be, since L14138 and LI-4139 replaced it. BG&E has initiated an Issue Report (IR3-000-608) to revise OP-7 to remove all reference to LI-4140.

REVIEW AND APPROVAL: ABB: Verifa.tion Status: Complete The information contained in this documnnt has been verified to be correct by means of design review. Cognizant Enginmredo .. 7 Date: Z ZP0 Independent Rvee  ;-1 ae Management Ap~prover~ C. I. Gimbrne (2</ BGE: Owner AcceptanceRevlewer(s): NEU: , ..... Date: D __ ICU: S,.Ef  ::.Date: ABB Doe ID. ST-98.410-09 I Rev. No.: 0 - Page 1 of 4

Calvert Cliffs Units I and 2 TECH SPEC ACTION VALUE BASIS DOCUMENT MODULE 1 - REFUELING CANAL WATER LEVEL [ESP No.:T.60 Fe.S199800829 ]Supp, No.: 000* ' Rev. No.:0 0000, [ TS-06.Ol_ Rev.-0 Part I - Action Valge Bases Ref,erences

1. 1,2 Calvert Cliffs Nuclear Power Plant Improved Technical Specifications.

Unit I Amendment No. 230. Unit 2 Amendment No. 206

2. 1,2 Calvert Cliffs UFSAR, Revision 25

3. 2 BGE Procedure "Calvert Cliffs Nuclear Power Plant Unit Two OP-7 Shutdown Operations," 5/12/99

4. 1,2 CE-NPSD-925, revision 00, "Guidelines for Addressing Instrument Uncertainties in Emergency Operating Procedures and Technical Specifications" January 1994

5. 1,2 CCNPP Unit One and Two Control Room Logsbeet Mode 6

6. 1,2 BG&E Calculation No. 1-92-39, Rev. 0, Instrnment Loop Uncertainty Estimate, RCS Mid-Loop Wide Range Level Monitor Loop T.S. Value Use and Application Summary:

APP, 3.9.4 -Applicability condition for Shutdown cooling and Coolant Circulafion-High Water Level APP, 3.9.5 - Applicability condition for Shutdown cooling and Coolant Circulation-Low Water Level LCO, 3.9.6 - Limiting condition for operation for Refueling Pool Water Level SR, 3.9.6.1 - Surveillance requirement for Refueling Pool Water Level Technical Specification Value: Engineering Limit Documentation Level __________________ ______________Category:

> or =23FT, over top of fuel seated in

• 23 ft over top of fuel 2 reactor vessel during CORE seated in reactor vessel if ALTERATION or movement of only one shutdown irradiated fuel or when only one cooling loop OPERABLE shutdown cooling loop is OPERABLE and in operation and in operation. < 23 ft over top of fuel is

 < 23 Fr, over top of fuel seated in              allowed if two shutdown reactor vessel is permitted if no CORE           cooling loops are ALTERATION or fuel movement is                   OPERABLE with one taking place and two SDC loops are               loop in operation OPERABLE ABB Doc ID. ST-98-410-08                                    Rev. No.: 0         7   Pae 2 of 4

Calvert Cliffs Units 1 and 2 TECH SPEC ACTION VALUE BASIS DOCUMENT MODULE 1 - REFUELING CANAL WATER LEVEL SESP No.: 1ES 199800829 ISuPP. No.: I1000 I ev..No.: 0000[ TS-06.01 Rev. 0 Action Value Basis: The engineering limit for minimum refuel pool level is 23 ft of water covering'a fuel assembly seated in the reactor vessel. The top of the core (and assembly) is 32.9 ftL Therefore, the analytical limit is 55.9 ft (32.9 + 23). TheTSRefuelingPool Level is 56.70 ft(ReL 3. Table 1). The height of water above the top of a fuel assembly at the TS limit is (56.7' - 32.9') = 23.8'. Refueling level is surveilled to (56.7 - 67,25) in Mode 6 using the Control Room Logs (Ref 5, pg. 2). Per ref 1 - The engineering limits for refueling canel water level is a function of the number of shutdown cooling loops OPERABLE and in operation, thus: Ref. 1, Bases 3.9.4, Applicable Safety Analysis summary: If only one, shutdown cooling loop is OPERABLE (and in operation), then refuel pool level must be > or = 23 feet of water above the top of fuel seated in the reactor vessel. Although no specific analysis has been located, it is believed that high water level and the resulting higher heat capacity would permit sufficient time to take compensatory actions in case the operating SDC loop were to fail. Re1f 1,Bases 3.9.5, Applicable Safety Analysis summary: If two shutdown cooling loops are OPERABLE, with at least one loop in operation, then, refuel pool level may be <23 feet of water above the top of fuel seated in the reactor vessel A minimum refueling pool water level of 23 Rabove the irnadiated fuel assemblies seated in the reactor vessel is requited during fuel movement to ensure that the radiological consequences of a postulated fuel handling accident inside containment are within the acceptable limits given in the UFSAR (Rcf. 2). Potential effects of indication error: If refueling pool level is less than 23 feet of water covering a ruptured fuel assembly, then, the safety analysis is not valid and more iodine may be released following a fuel handling accident (dropped fuel assembly) than calculated in the safety analysis Sunnortlnd Reference Excernts: Ref. 2 - 14.18.3.1 - Fuel Handling Incident in Containment Because iodine is readily absorbed by water and the fuel being handled is under water, much of the iodine released fiom the damaged rods would be retained in the refueling pool water. To account for this preferential retention of iodine by the pool water, a decontamination factor of 10a is assumed, which corresponds to the value suggested in Regulatory Guide 1.25. No additional credit is taken for plate-out of iodine on surfcs within the containment. Ref. 2 - 14.18.3.2 - Fuel Handling Incident in the Spent Fuel Pool Area The release of activity to the air above the spent fuel pool is identical to that released to the containment air in the event of a fuel handling incident in containment ABB Doc ID, ST-98-410-08 I Rev. No.: 0 Page 3 of 4

Calvert Cliffs Units I and 2 TECH SPEC ACTION VALUE BASIS DOCUMENT MODULE 1 - REFUELING CANAL WATER LEVEL ESP No.:ZES199800829 Supp. No.: I000 i Rev. No.: [0000 TS-06.01 Rev. 0 partu I- Insttyment 'Uncertalnties Assessment RCS Water Refueling Level Refueling Level Refueling Level Local Local Level Cart Cart Cart Refueling Tygon Instrument Indicator Recorder Alarm Level (WR) ID: (Wide Range) (Wide Range) (Wide Range) Indicator 1(2) LI.4139 1(2) LR-4138 1K184 (Wide Range) 1(2) LG-4139 Is TLU Cale yes Yes Yes No N/A Complete?: Reference 6 Reference 6 Reference 6 Calibration data: TLU, % NIA N/A N/A N/A W/A Span: TLU, Eng, -7.48 in. a.21n. +/-1 1.57 in. N/A N/A Units: Instrument Uncertainties Assessment: This application of Refueling Pool level indication is Category 2 per CE-NPSD-925 (reference 4, pg. 21). This category is reserved for instrument uses that possess a moderate to low degree of nuclear safety significance, or are corroborative in nature. Engineering judgement may be used when determining and applying instrument uncertainties. LT-4138(NR) and 4139(WR) are temporary instruments located on the refueling instrumentation cart, which is placed in service during refuelin& They are read remotely in the Control Room. If these instruments are not available, LG-4139 or a tygon are available for wide range RCS/Refiueing Pool level determination in containment. The analytical limit is 55.9 ft (32.9 + 23). The TS Refueling Pool Level in 56.70 ft (Ref. 3, Table 1). Refueling level is surveilled to (56.7 - 67.25) in Mode 6 using the Control Room Logs (Retf 5, pg. 2). The height of water above the top of a fuel assembly is at the TS limit is (56.7'- 32.9') = 23.8'. There exists a (23.8' -23.0') - 0.8' - 9.6" of margin. The above table list TLUs for wide RCS range level instrumentation. The TLU for 1(2) LI-4139 is + 7.48 inches and the TLU for 1(2) LI-4138 is +/- 8.21 inches. Since these values are less than the 9.6" of available margin, the margins are satisfactory. Evaluation: Margin evaluation is satisfactory. The above discussion demonstrates that LI-4139 and 4138 provide sufficient margin to the analytical value. ABBDocID. ST-98-410-08 Rev. No.: 0 .Page4of 4

Calvert Cliffs Units I and 2 TECH SPEC ACTION VALUE BASIS DOCUMENT MODULE 12 - RMS ALARM, CONTAINMENT HIGH RANGE I ESP No.: I Supp. No. 000oES199800829 1 Rev. No.: 10000 1 ITS-76.01 Revision I INITIATION: Responsible Group: DES ICU Responsible Engineer: Stephen Keefe BASIS DOCUMENT: System. RMS Component: AREA Parameter: RADIATION T.S. Value(s): Operable (CONTAINMENT HIGH RANGE) Mode(s): 1, 2 and 3

 -Comment:          Margin evaluation is not applicable.

RECORD OF REVISIONS REVISION PAGE NO. DESCRIPTION OF CHANGE

       .0                All           Initial Issue I               All           Miscellaneous clarifications and edits REVIEW AND APPROVAL:

CE Nuclear Power:. Verification Status. Complete The information contained in this document has been verified t be correct by means of design review. Cognizant Engineer: L. WLd Date: Independent Reviewer: J. R. Co nan ate: Management Approver: R. 0. Don Date: BGE: Owner Acce tan Reviewer(s)- NEUl: S.KEEDate: ICU: SEKEEDate: I ABB CENP Doc ID. B-PENG-99-016-060 I Rev. No.: I I Page I of 3

Calvert Cliffs Units I and 2 TECH SPEC ACTION VALUE BASIS DOCUMENT MODULE 12 - RMS ALARM, CONTAINMENT HIGH RANGE ESP No.: ES199800829 ISupp. No.: 1000 1Rev. No.: 10000 1 TS-76.01 Revision I Part I - Action Value Bases References U09 Do

1. 1,2 Calvert Cliffs Nuclear Power Plant Technical Specifications: Unit 1 Amendment No. 233, Unit 2 Amendment No. 209

2. 1,2 Cakvert Cliffs UFSAR, Revision 26

3. CE-NPSD-925, Revision 00, "Guidelines for Addressing Instrument Uncertainties in Emergency Operating Procedures and Technical Specifications', January 1994

4. 1 STP 0-98-1, Containment High Range Monitors Monthly Functional Test, Revision 4, January 4, 1997

5. 2 ST? 0-98-2, Containment High Range Monitors Monthly Functional Test, Revision 4, January 4, 1997

6. 1 STP-M-562-1, Containment High Range Radiation Monitor Alignment Check, Revision 4, May 28, 1992

7. 1,2 Calvert Cliffs Unit 0, 1, and 2 Setpoint File, NEQR440, 12/16/99, for Systems 077 Use and Application Summary:

SR 3.3.10.1- Operability Channel Check for PAM Instrumentation SR 3.3.10.3- Operability Channel Calibration for PAM Instrumentation Technical Specification Value: Eneineerin Limit: Documentation Level / Cateoriv Operable - PAMI None 6 Attion Value Basis: Reference 1, Technical Specificaton Bases B 3.3.10 (pg. B .3.3.10-2, B &3 "0-7) APPLICABLE SAFETY ANALYSES - The PAM insrumentation ensures the OPERABILITY of Regulatory Guide 1.97 Type A variables, so that the control room operating staff can:

• Perform the diagnosis specified in the emergency operating procedures. These variables are restricted to preplanned actions for the primary success path of DBAs; and 0 Take the specified, preplanned, manually controlled actions, for which no automatic control is provided, that are.required for safety systems to accomplish their safety functions.

The PAM instrumentation also ensures OPERABILITY of Category I, non-Type A variables. This ensures the control room operating staff can:

 " Determine whether systems important to safety are performing their intended functions;

• Determine the potential for causing a gross breach of the barriers to radioactivity release;

 " Determine if a gross breach of a barrier has occurred- and
 " Initiate action necessary to protect the public as well as to obtain an estimate of the magnitude of any impending threat I ABB CENP Doc ID. B-PENG-99-016-060                     I Rev. No.: I               I Page 2of`3

Calvert Cliffs Units 1 and 2 TECH SPEC ACTION VALUE BASIS DOCUMENT MODULE 12 - RMS ALARM, CONTAINMENT HIGH RANGE IESP No.: ES199800829 Su . No.: 000 Rev. No.: 0000 TS-76.01 Revision 1 I I0I I Containment area radiation detectors are provided to monitor for the potential of significant radiation releases and to provide release assessment for use by operations in determining the need to invoke site emergency plans. I Containment area radiation instrumentation consists of two radiation detectors with displays and alarm in the Control Room. The radiation detectors have a measurement range of I to 108 R/hr. I Reference 2, UFSAR, Section 7.5.8 (pg. 7.5-17) Variables and systems can be monitored under accident conditions. Included is the instrumentation required for the operators to take the plant to hot shutdown from outside the Control Room and to monitor for radiation released following a postulated accident. Certain instrumentation in the Control Room and on the Auxiliary Safe Shutdown Panels used for normal plant operations is designated for post-accident monitoring (PAM) use. Potential effects of indication error: None Supporting Reference Excerpts: None Part U - Instrument Uncertainties Assessment Containment High Range Radiation Monitor Instrument ID: 1(2)-RI-5317A, 1(2)-RI-5317B (I to 10" R/hr) TLU Cak Complete: No Calibration Data: Yes (Ref. 6)

                                    % Span:

I Alarm Tolerance: +/- 4 RIHr (Ref. 7, Pg. 8 and 13) Eng. Units: (R/Hr) High Alarm Setpoint- 6 R/Hr High High Alarm Setpoint: 20 R/Hr (Ref. 7, Pg. 8 and 13) Instrument Uncertainties Assessment: Per CE-NPSD-925 (Reference 3, page 23), this parameter application is Category 6 (not applicable) because it is a Technical Specification OPERABILITY requirement only. No specific value is given in the referenced section of TS; therefore instrument uncertainties can not be evaluated. These instrument applications are covered elsewhere when the instruments are actually used. Evaluation: Margin evaluation is not applicable. I ABB CENP Doc ID. B-PENG-99-016-060 I Rev. No.: I I Page 3 of 3

Calvert Cliffs Nuclear Power Plant TECHNICAL REQUIREMENTS MANUAL (TRM) (NORMS DOC ID: NO-TRM) Revision 01502 Effective Date 4/27/10 Sponsor: General Supervisor - Shift Operations Approval Authority: Manager - Operations

Technical Requirements Manual Rev. 15 Page 2 of 88 RECORD OF REVISIONS AND CHANGES Revision Change Summary of Revision or Change 015 02 Section 15.3.6 Applicability Deleted (Unit-2 only). PCR-10-02030. ECP-09-000147 Now also applicable to Unit-1. Section 15.3.6.B Changed from 4-hour TO 16-minute. Deleted Note explaining that the Nonconformance can be exited when either the 2-minute or 16-minute are restored. PCR- 10-02030. ECP-09-000147 The system gives bad quality when the 2-minute goes bad. The Nonconformance can be exited when restored. No explanation is needed.

Technical Requirements Manual Rev. 15 Page 3 of 88 TABLE OF CONTENTS SECTION TITLE PAGE L IS T O F F IG U RE S ...................................................................................................................................... 7 L IST O F A C R O NY M S ................................................................................................................................ 8 B A S ES .......................................................................................................................................................... 9 15.0 TECHNICAL REQUIREMENTS MANUAL ........................................................................... 10 15.0.1 B A C K G R O U N D ..................................................................................................................... 10 15 .0 .2 U S E ......................................................................................................................................... 10 15.0.3 FAILURE TO MEET A TNC OR TVR ............................................................................. 11 15.1 REACTIVITY CONTROL SYSTEMS ...................................................................................... 12 15.1.1 B O R ON D ILU T ION ........................................................................................................... 12 15.1.2 BORATION FLOW PATHS - OPERATING .................................................................... 13 15.1.3 BORATION FLOW PATHS - SHUTDOWN ................................................................... 16 15.1.4 CONTROL ELEMENT ASSEMBLY (CEA) POSITION INDICATION ......................... 18 15 .2 N O T U S E D ..................................................................................................................................... 22 15.3 IN STR UM EN TA T ION .................................................................................................................. 23 15.3.1 RADIATION MONITORING INSTRUMENTATION ................................................... 23 15.3.2 METEOROLOGICAL INSTRUMENTATION ................................................................. 24 15.3.3 INCORE DETECTOR SYSTEM ....................................................................................... 25 15.3.4 SEISMIC MONITORING INSTRUMENTATION ......................................................... 28 15.3.5 FIRE DETECTION INSTRUMENTATION ...................................................................... 30 15.3.6 FEEDWATER FLOW MEASUREMENT INSTRUMENTATION .................................. 38 15.4 .1 C H E M IST R Y .......................................................................................................................... 40 15.4.2 PRESSURIZER PRESSURE/TEMPERATURE LIMITS ................................................. 42 15.4.3 AMERICAN SOCIETY OF MECHANICAL ENGINEERS (ASME) CODE CLASS 1, 2, AND 3 COMPONENTS .................................................................................................... 43

Technical Requirements Manual Rev. IS Page 4 of 88 15.4.4 DELETED ............................................................................................................................... 45 15.4.5 LETDOW N LINE EXCESS FLOW .................................................................................. 46 15.4.6 RCS VENTS ............................................................................................................................ 47 15.5 NOT USED ..................................................................................................................................... 49 15.6 CONTAINM ENT SYSTEM S .................................................................................................. 50 15.6.1 CONTAINM ENT STRUCTURA L INTEGRITY ............................................................ 50 15.6.2 CONTAINM ENT CLOSEOUT ......................................................................................... 51 15.7 PLANT SYSTEM S ......................................................................................................................... 52 15.7.1 STEAM GENERATOR PRESSURE/TEMPERATURE LIMITATION ........................... 52 15.7.2 SNUBBERS ............................................................................................................................ 53 15.7.3 SEALED SOURCE CONTAM INATION ........................................................................ 59 15.7.4 DELETED ............................................................................................................................... 61 15.7.5 FIRE SUPPRESSION WATER SYSTEM ........................................................................ 62 15.7.6 SPRA Y AND SPRINKLER SYSTEM ............................................................................. 66 15.7.7 HALON SYSTEM .................................................................................................................. 70 15.7.8 FIRE HOSE STATIONS ................................................................................................... 72 15.7.9 YARD FIRE HYDRANTS AND HYDRANT HOSE HOUSES ...................................... 77 15.7.10 FIRE BARRIER PENETRA TIONS ................................................................................. 79 15.8 NOT USED ..................................................................................................................................... 81 15.9 REFUELING OPERATIONS ................................................................................................... 82 15.9.1 DECAY TIM E ........................................................................................................................ 82 15.9.2 COM M UNICATIONS ....................................................................................................... 83 15.9.3 REFUELING M ACHINE .................................................................................................. 84 15.9.4 CRANE TRAVEL - SPENT FUEL POOL ......................................................................... 85 15.9.4 CRANE TRAVEL - SPENT FUEL POOL ......................................................................... 85

Technical Requirements Manual Rev. 15 Page 5 of 88 15.10 NOT USED ..................................................................................................................................... 86 15.11 RADIOACTIVE EFFLUENTS .................................................................................................. 87 15.11.1 EXPLOSIVE GAS M IXTURE ........................................................................................... 87 15.11.2 GAS STORA GE TANKS .................................................................................................. 88

Technical Requirements Manual Rev. 15 Page 6 of 88 LIST OF TABLES TABLE TITLE PAGE 15.1.4-1 CEA POSITION INDICATION APPLICABILITY 20 15.3.4-1 SEISMIC MONITORING INSTRUMENTATION 28 15.3.5-1 FIRE DETECTION INSTRUMENTS - UNIT 1 32 15.3.5-1 FIRE DETECTION INSTRUMENTS - UNIT 2 35 15.7.2-1 SNUBBER VISUAL INSPECTION INTERVAL 54 15.7.6-1 SPRINKLER LOCATIONS - UNIT 1 65 15.7.6-2 SPRINKLER LOCATIONS - UNIT 2 66 15.7.8-1 FIRE HOSE STATIONS - UNIT 1 71 15.7.8-2 FIRE HOSE STATIONS - UNIT 2 72 15.7.8-3 FIRE HOSE STATION ISOLATION VALVES - UNIT I & 73 UNIT 2

Technical Requirements Manual Rev. 15 Page 7 of 88 LIST OF FIGURES FIGURE TITLE PAGE 15.1.2-1 MINIMUM BAST VOLUME AND TEMPERATURE AS A 14 FUNCTION OF STORED BORIC ACID CONCENTRATION

Technical Requirements Manual Rev. 15 Page 8 of 88 LIST OF ACRONYMS APD Amplitude Probability Distribution ASME American Society of Mechanical Engineers BAST Boric Acid Storage Tank CEA Control Element Assembly COLR Core Operating Limits Report ECCS Emergency Core Cooling System LEFM Leading Edge Flow Measurement NRC Nuclear Regulatory Commission RCS Reactor Coolant System RWT Refueling Water Tank TNC Technical Normal Conditions TVR Technical Verification Requirement SA Spectral Analysis SFP Spent Fuel Pool

Technical Requirements Manual Rev. 15 Page 9 of 88 BASES [B0627] Licensing Renewal Aging Management Basis Document: Snubber Visual Inspection Program (AMBD-0028, Rev. 0000) [B0650] UCROO191, Letter from Atomic Energy Commission (AEC), dtd 1/31/74. CCNPP agreed to changes in this letter, but was not put into Tech Spec revision 4/1/74 as requested: Add verification requirements for inventory of sealed sources. [B0653] Memo dtd 11/20/00 from A. J. O'Donnell to Steve McCord regarding basis for Calvert Cliffs Meteorological Parameter - Delta T (ERPIP 825). [B0703] ASME, Section XI, Subsection IWL, Requirements for Class CC Concrete Components of Light-Water Cooled Plants, 1992 Edition with 1992 Addenda as modified and amended by 10 CFR 50.55a. [B0772] Steam Generator Project - Design Engineering, Memo SGP-EN-01-297, Basis for change to TRM 15.4.1, Reactor Coolant System Chemistry, dtd 12/14/01 to S. C. McCord from T. W. Reed. [B0783] Memo dtd 3/28/94 from J. Alvey to M. Navin; Subj. Watertight Door Tickets. [B0800] Memo dtd 4/27/02 from J. Calle to S. McCord: Subj. Unit-I Steam Generator Replacement Project TRM 15.7.1 Steam Generator Pressure/Temperature Limitation. [B0889] ES200400058/IR4-016-662 (1E200300078, MS #2): Technical Evaluation of the Licensing Basis and Design Basis for the RCP Pump Bay Heat Detectors. [B0898] Memo dtd 12/4/03 from Jack DeSando, Stephen Keefe and Jay Robinson to C. Jones: Subj: Operability of New Intake Building Fire Detection System. [B0909] ES200400030, Modify the Restoration Times of the Boric Acid Flow Paths contained in Section 15.1.2 [132369] EPRI PWR Primary Water Chemistry Guidelines

Technical Requirements Manual Rev. 15 Page 10 of 88 15.0 TECHNICAL REQUIREMENTS MANUAL 15.

0.1 BACKGROUND

This manual contains requirements that were removed from the Technical Specifications during the conversion from the standard format Technical Specifications to the improved standard Technical Specifications. This conversion was approved by the Nuclear Regulatory Commission (NRC) on May 4, 1998 (Amendment Nos. 227/201), and placed in Revision 22 of the UFSAR. UCR No. 00110, approved on November 9, 1999, permitted removal of the TRM from the UFSAR and replaced it with a summary. This change endorsed in NEI 98-03, Guidelines for Updating Final Safety Analysis Reports, Revision 1, and a NEI letter dated June 30, 1999. The NEI letter answers questions about NEI 98-03. The letter was reviewed and concurred with by the NRC. NEI and the NRC has said the TRM can and should be a document separate from the UFSAR and controlled by the 10 CFR 50.59 process. The 10 CFR 50.59 revision process will be controlled by NO-I- 118, Control of the Technical Requirements Manual (TRM). To minimize the impact of associated procedures that reference the Technical Requirements Manual (TRM), the manual will continue to retain the same chapter numbering and title that was used when it was maintained within the UFSAR, Revision 24. 15.0.2 USE The following terms are used in this manual and have the same definition as the equivalent term in the Technical Specifications.

      - channel calibration
      - channel check
      - channel functional test
      - core operating limits report (COLR)
      -  mode
      -  operable/operability
      -  rated thermal power
      -  shutdown margin
      -  staggered test basis
      -  thermal power The use of logical connectors (AND, OR) is the same as their use in the Technical Specifications.

Technical Normal Conditions (TNCs) are intended to be met during the times they are applicable. If a TNC is not met, the contingency measures must be taken within the specified time, unless otherwise noted. If a Restoration Time requires periodic performance on a "once per..." basis, a frequency extension (1.25 times allowance) applies to each performance after the initial performance. If a TNC is no longer applicable, the contingency measures do not have to be completed. Technical Verification Requirements (TVRs) are included as a means to determine equipment operability. They must be performed within the frequency (with a 1.25 times allowance) noted for equipment to meet the TNC. The measuring of the frequency is from the time of the previous performance or from the time a specified condition of frequency is met.

Technical Requirements Manual Rev. 15 Page II of 88 15.0.3 FAILURE TO MEET A TNC OR TVR When it is discovered that a TNC has not been met and the associated contingency measures are not satisfied (or an associated contingency measure is not provided), the equipment subject to the TNC is in a nonconforming condition, subject to the requirements of CNG-OP-1.01-1002, Conduct of Operability Determinations/Functionality Assessments (e.g., Attachment 6, Functionality Assessments), 10 CFR Part 50, Appendix B, Criteria XV and XVI, Generic Letter 91-18 and Generic Letter 91-18, Revision 1. In this situation, appropriate actions shall be taken as necessary to provide assurance of continued safe plant operations. In addition, an issue report shall be written and assessment of reasonable assurance of safety shall be conducted. Items to be considered for this assessment include the following:

• Availability of redundant or backup equipment;
• Compensatory measures, including limited administrative controls;
• Safety function and events protected against;
• Probability of needing the safety function;
• Conservatism and margins; and
• Probabilistic Risk Assessment or Individual Plant Evaluation results that determine how operating the plant in the manner proposed will impact core damage frequency.

If this assessment concludes that safety is sufficiently assured, the facility may continue to operate while prompt corrective action is taken. Entry into a Mode or other specified condition in the Applicability, where a TNC is not met, may be made after completing the above assessment and it concludes safety is is sufficiently assured; exceptions to this Requirement are stated in the individual Requirement.

• This Requirement shall not prevent changes in Modes or other specified conditions in the Applicability that are required to comply with the Contingency Measures or that are part of a shutdown of the unit.

When it is discovered that a TVR frequency (including the 1.25 times extension) has not been met, the equipment subject to the TVR is in a nonconforming condition. In this situation, an issue report shall be written and, if indicated, determination to evaluate the impact on plant safety shall be performed in a timely fashion and in accordance with plant procedures. Actions should be taken to restore conformance with the TNCs/TVRs in a timely fashion. If equipment has been removed from service or declared inoperable, it may be returned to service under administrative control to perform testing required to demonstrate its operability.

Technical Requirements Manual Rev. 15 Page 12 of 88 15.1 REACTIVITY CONTROL SYSTEMS 15.1.1 BORON DILUTION NORMAL TNC 15.1.1 Reactor Coolant System (RCS) flow rate shall be > 3,000 gpm. CONDITION APPLICABILITY Modes 1, 2, 3, 4, 5, and 6, whenever a reduction in RCS boron concentration is being made from a source whose boron concentration is less than the present Shutdown Margin requirements (Refueling Boron for Mode 6) per COLR. CONTINGENCY MEASURES Nonconformance Contingency Measures Restoration Time A. The RCS flow rate is not A.1 All operations involving a reduction Immediately within limits, in RCS boron concentration must be suspended. VERIFICATION REQUIREMENTS TVR Verification Frequency 15.1.1.1 Verify RCS flow rate is > 3,000 gpm. Within 1 hour prior to the start of a NOTE: This technical verification reduction in RCS boron concentration requirement is not required to be AND performed in Modes I and 2 (i.e., RCP's operating). Every hour during a reduction in RCS boron concentration This includes verifying at least one reactor coolant pump is in operation or verifying that at least one low pressure safety injection pump is in operation and supplying the required amount of flow through the RCS.

Technical Requirements Manual Rev. 15 Page 13 of 88 15.1.2 BORATION FLOW PATHS - OPERATING NORMAL TNC 15.1.2 Two boron injection flow paths shall be operable. CONDITION Each boration flow path consists of a boric acid storage tank (BAST) connected to the RCS via a boric acid pump or gravity feed connection, and a charging pump; or a refueling water tank (RWT) connected to the RCS via a charging pump. Charging pumps are required to be powered from separate emergency buses. Each boric acid pump is required to be powered from an emergency bus. Each BAST must have its associated heat tracing systems. Each operable boron injection flow path must have at least one heat tracing circuit operable. No actuation signals are required for operability. APPLICABILITY Modes 1, 2, 3, and 4. CONTINGENCY MEASURES [B0909] Nonconformance Contingency Measures Restoration Time A. One required boron A. I Restore the required boron injection 72 hours injection flow path is flow path to operable status inoperable due to Charging Pump inoperability. B. One required boron B.I Restore the required boron injection 7 days injection flow path is flow path to operable status. inoperable for reasons other than Condition A. C. Contingency measure C. 1 See Section 15.0.3. and associated restoration time of Nonconformance A or B are not met. VERIFICATION REQUIREMENTS TVR Verification Frequency 15.1.2.1 Verify the temperature of the heat traced 7 days portion of the flow path from the concentrated BASTs is above the temperature limit line shown on Figure 15.1.2-1. 15.1.2.2 Verify the BAST boron concentration is as 7 days specified in Figure 15.1.2-1, but limited to

                 *_8%.

15.1.2.3 Verify the BAST borated water volume is 7 days as specified in Figure 15.1.2-1.

Technical Requirements Manual Rev. 15 Page 14 of 88 15.1.2 BORATION FLOW PATHS - OPERATING - Continued VERIFICATION REQUIREMENTS - Continued TVR Verification Frequency 15.1.2.4 Verify the BAST borated water solution 7 days temperature is as specified in Figure 15.1.2-1. 15.1.2.5 Verify that each manual, power-operated, 31 days or automatic valve in the flow path that is not locked, sealed, or otherwise secured in position, is in its correct position.

Technical Requirements Manual Rev. 15 Page 15 of 88 170

                                                                                          ý-
                                                                                          ýý-_=

I

                                                                                           *4130 ISO 1.9U 130 o

1-1 110 110 100 i. 90 ~MDS1, 2. 3. & 4

                      . _ ."J'_*      "z':

m 0 90 70 0* 80

                                                    -I
                                                    =t 50 20 F-=

10 7-*. *7.

                                     --          MODES 5 &                    -

_____ .~--. 0 6 7 8 9 10 11 12 STORED BORIC ACID CONCENTRATION (WT%) FIGURE 15.1.2-1 MINIMUM BAST VOLUME AND TEMPERATURE AS A FUNCTION OF STORED BORIC ACID CONCENTRATION

Technical Requirements Manual Rev. 15 Page 16 of 88 15.1.3 BORATION FLOW PATHS - SHUTDOWN NORMAL TNC 15.1.3 One boron injection flow path shall be operable. CONDITION The boration flow path must consist of a BAST connected to the RCS via a boric acid pump or gravity feed connection, and a charging pump; or an RWT connected to the RCS via a charging pump or high pressure safety injection pump. Each flow path is also required to contain associated heat tracing systems. The operable boric acid pump, charging pump, or high pressure safety injection pump shall be capable of being powered from an operable emergency bus. APPLICABILITY Modes 5 and 6. CONTINGENCY MEASURES Nonconformance Contingency Measures Restoration Time A. The required boron A.1 Suspend positive reactivity additions. Immediately injection flow path is inoperable. VERIFICATION REQUIREMENTS TVR Verification Frequency 15.1.3.1 Verify temperature of the heat traced 7 days, if a flow path from the BAST is portion of the flow path is above the used temperature limit line shown on Figure 15.1.2-1. 15.1.3.2 Verify RWT borated water temperature 24 hours, if the RWT is used as a borated

                 >_350 F.                                        water source and the outside air temperature is < 35°F 15.1.3.3          Verify the BAST borated water volume is         7 days, if the BAST is the borated water as specified in Figure 15.1.2-1.                source 15.1.3.4          Verify the RWT borated water volume is          7 days, if the RWT is the borated water
                 > 9,844 gallons.                                source 15.1.3.5          Verify the BAST borated water solution          7 days, if the BAST is the borated water temperature is as specified in                  source Figure 15.1.2-1.

15.1.3.6 Verify the RWT borated water solution 7 days, if the RWT is the borated water temperature is _> 357F. source 15.1.3.7 Verify the BAST boron concentration is as 7 days, if the BAST is the borated water specified in Figure 15.1.2-1. source 15.1.3.8 Verify the RWT boron concentration is 7 days, if in Mode 5 and the RWT is the

                 > 2,300 ppm.                                    borated water source

Technical Requirements Manual Rev. 15 Page 17 of 88 15.1.3 BORATION FLOW PATHS - SHUTDOWN - Continued VERIFICATION REQUIREMENTS - Continued TVR Verification Frequency 15.1.3.9 Verify the RWT boron concentration in 7 days, if in Mode 6 and the RWT is the Mode 6 exceeds the larger of 2300 ppm or borated water source the Refueling boron concentration limit specified in the COLR. 15.1.3.10 Verify that each manual, power-operated, 31 days or automatic valve in the flow path that is not locked, sealed, or otherwise secured in position, is in its correct position.

Technical Requirements Manual Rev. 15 Page 18 of 88 15.1.4 CONTROL ELEMENT ASSEMBLY (CEA) POSITION INDICATION NORMAL TNC 15.1.4 Two CEA position indicator channels shall be operable for each CONDITION shutdown and regulating CEA. Any two of the following three CEA position indication channels are allowed to be operable to satisfy this TNC:

a. Control element assembly voltage divider reed switch position indicator channel;

b. Control element assembly "Full Out" or "Full In" reed switch position indicator channel as verified by actuation of the applicable position indicator;

c. Control element assembly pulse counting position indicator channel.

The only time the CEA "Full In" or "Full Out" reed switch position indicator channels can be considered operable for one of the three CEA Position Indicator Channels is when the CEAs are either fully withdrawn or fully inserted. APPLICABILITY Modes I and 2. CONTINGENCY MEASURES Nonconformance Contingency Measures Restoration Time A. One or more CEA(s) per A.1 Restore the position indicator 6 hours group having its voltage channel(s) to operable status. divider reed switch OR position indicator channel inoperable and A.2.1 Reduce thermal power to < 70% 6 hours either the "Full out" OR rated thermal power. If negative "Full in" reed switch reactivity insertion is required to position indicator reduce thermal power, boration channel inoperable, shall be used. AND after power is reduced _<70% rated thermal power. A. continued A.2.2.1 Fully withdraw CEA group(s) with 10 hours inoperable position indicator(s) and verify the CEA(s) to be fully withdrawn via a "Full Out" indicator. OR

Technical Requirements Manual Rev. 15 Page 19 of 88 15.1.4 CONTROL ELEMENT ASSEMBLY (CEA) POSITION INDICATION - Continued CONTINGENCY MEASURES - Continued Nonconformance Contingency Measures Restoration Time A. continued A.2.2.2 Fully insert CEA group(s) with 10 hours inoperable position indicator(s) and verify the CEA(s) to be fully inserted via a "Full In" indicator. OR A.3 If the failure existed before entry into Within 10 hours of Mode 2 or occurs prior to an "all CEAs entry into Mode 2 out" configuration, the CEA group(s) with an inoperable position indicator AND channel(s) must be moved to the "Full Out" position and verified to be fully Prior to exceeding withdrawn via a "Full Out" indicator. 70% of rated thermal power. B. One or more CEA(s) per B.I Verify that either the CEA voltage 1 hour group having its CEA divider reed switch position indicator pulse counting position channel or the "Full Out" or "Full In" indicator channel reed switch position indicator channel inoperable and either the for the affected CEAs is operable.

     "Full Out" or "Full In"          AND reed switch position indicator or the voltage  B.2    Restore the position indicator            24 hours divider reed switch              channel(s) to operable status position indicator channel inoperable.

C. Contingency measures C.I See Section 15.0.3. and associated restoration times of Nonconformance A or B are not met.

Technical Requirements Manual Rev. 15 Page 20 of 88 15.1.4 CONTROL ELEMENT ASSEMBLY (CEA) POSITION INDICATION - Continued VERIFICATION REQUIREMENTS TVR Verification Frequency 15.1.4.1 Verify CEA position indicator channels Every 12 hours agree within 4.5 inches. AND Every 4 hours when deviation circuit is inoperable This shall be accomplished by the following: (1) Verifying the CEA pulse counting position indicator channels and the CEA voltage divider reed switch position indicator channels agree within 4.5 inches; or (2) Verifying the CEA pulse counting position indicator channels and the CEA "Full Out" or "Full In" reed switch position indicator channels agree within 4.5 inches; or (3) Verifying the CEA voltage divider reed switch position indicator channels and the CEA "Full Out" or "Full In" reed switch position indicator channels agree within 4.5 inches.

Technical Requirements Manual Rev. 15 Page 21 of 88 TABLE 15.1.4-1 CEA POSITION INDICATION APPLICABILITY One or more Affected Affected Voltage Pulse "Full out"/ Applicable rod(s) per rod(s) rod(s) fully divider counting "Full in" Non-group partially withdrawn position position position conformance affected inserted (or fully indicator indicator indicator inserted) channel channel X X I I* A X X I I1* C (See Section 15.0.3) X X I I* B X X I I B X X I I A X X I I B I = Inoperable I* = Inoperable due to rods partially inserted

Technical Requirements Manual Rev. 15 Page 22 of 88 15.2 NOT USED

Technical Requirements Manual Rev. 15 Page 23 of 88 15.3 INSTRUMENTATION 15.3.1 RADIATION MONITORING INSTRUMENTATION NORMAL TNC 15.3.1 One Main Vent Wide Range Noble Gas Effluent Radiation Monitor CONDITION Channel and two Main Steam Header Noble Gas Effluent Radiation Monitor Channels shall be operable with their alarm setpoints as specified in the setpoint control manual. The measurement range of the main vent wide range noble gas effluent monitors is 10-7 to 101 gCi/cc. The measurement range of the main steam header noble gas effluent is 10.2 to 105 R/hr. APPLICABILITY Modes 1, 2, 3, and 4. CONTINGENCY MEASURES Nonconformance Contingency Measures Restoration Time A. A radiation monitoring A.I Restore the setpoint to within limits. 4 hours channel alarm setpoint is not within limits. A.2 Declare the affected radiation 4 hours monitoring channel inoperable. B. Contingency measure B. 1 Initiate the preplanned alternate method 72 hours and associated of monitoring the appropriate restoration time of parameter. Nonconformance A are AND not met. OR B.2.1 Restore the inoperable channel to 7 days One or more required operable status. radiation monitoring OR channels are inoperable. B.2.2 See Section 15.0.3. VERIFICATION REQUIREMENTS TVR Verification Frequency 15.3.1.1 Perform a channel check. 12 hours 15.3.1.2 Perform a channel functional test. 31 days 15.3.1.3 Perform a channel calibration. 18 months

Technical Requirements Manual Rev. 15 Page 24 of 88 15.3.2 METEOROLOGICAL INSTRUMENTATION NORMAL TNC 15.3.2 The following meteorological monitoring instrumentation channels CONDITION shall be operable.

a. wind speed - 10 meter nominal elevation,

b. wind speed - 60 meter nominal elevation,

c. wind direction - 10 meter nominal elevation,

d. wind direction - 60 meter nominal elevation, and

e. air temperature - delta T (60 m - 10 in). [B06531 APPLICABILITY At all times.

CONTINGENCY MEASURES Nonconformance Contingency Measures Restoration Time A. One or more required A. 1 Restore required channels to operable 7 days meteorological status. monitoring channels are inoperable. B. Contingency measure B. I See Section 15.0.3. and associated restoration time of Nonconformance A are not met. VERIFICATION REQUIREMENTS TVR Verification Frequency 15.3.2.1 Perform a channel check. 24 hours 15.3.2.2 Perform a channel calibration. 6 months

Technical Requirements Manual Rev. 15 Page 25 of 88 15.3.3 INCORE DETECTOR SYSTEM The instruments covered by the verification requirements are discussed in the UFSAR Section 7.5.4.3. NORMAL TNC 15.3.3 The Incore Detection System must be operable as follows: CONDITION A. For base functionality of the Incore Detection System, I. At least one detector segment in each core quadrant at each of the four axial elevations must be operable. B. For monitoring the azimuthal power tilt with the Incore Detection System, I. At least two quadrant symmetric detector segments groups must be operable at each of the four axial elevations in the outer 184 fuel assemblies. C. For recalibration of the Excore Neutron Flux Detection System,

1. At least 75% of all incore detector segments must be operable.

2. A minimum of nine incore detector segments must be operable at each of the four axial elevations.

3. A minimum of two detector segments in the inner 109 fuel assemblies must be operable at each of the four axial elevations.

4. A minimum of two detector segments in the outer 108 fuel assemblies must be operable at each of the four axial elevations.

D. For monitoring total planar radial peaking factor, total integrated radial peaking factor, or linear heat rate,

1. At least 75% of all incore detector string locations must be operable (i.e., at least three of four segments are considered operable).

2. A minimum of nine incore detector segments must be operable at each of the fouraxial elevations.

3. A minimum of two detector segments in the inner 109 fuel assemblies must be operable at each of the four axial elevations.

4. A minimum of two detector segments in the outer 108 fuel assemblies must be operable at each of the four axial elevations.

5. All 5 x 5 arrays of fuel assemblies that contain 25 fuel assemblies must contain at least one operable detector segment on any axial level.

Technical Requirements Manual Rev. 15 Page 26 of 88 15.3.3 INCORE DETECTOR SYSTEM - Continued NORMAL CONDITIONS - Continued NORMAL E. For post-refueling startup testing and power ascension, CONDITION

1. Meet the requirements of (B) and (D. I through D.4) above for azimuthal power tilt monitoring and for monitoring total planar radial peaking factor, total integrated radial peaking factor, or linear heat rate, AND

2. either Criteria I, II, III, OR IV

a. Criterion I

1. All incore detector string locations must have at least one operable detector segment in any of the four axial elevations.

b. Criterion 11 I. At least 75% of all incore detector string locations in a quadrant have at least one operable detector segment.

2. All 5x5 arrays of fuel assemblies that contain 25 fuel assemblies must contain at least one operable detector segment on any axial level.

c. Criterion III

1. Symmetry checks must be performed on all CEA groups

d. Criterion IV

1. Perform an evaluation of the ability of the incore detector system to detect core power symmetry with the actual operable incore detector pattern prior to exceeding 30%

power.

2. Implement symmetry checks as identified in the evaluation.

3. Implement penalties on the total planar radial peaking factor, total integrated radial peaking factor, and linear heat rate as identified in the evaluation.

APPLICABILITY When the Incore Detection System is used as described above in items A through E.

Technical Requirements Manual Rev. 15 Page 27 of 88 15.3.3 INCORE DETECTOR SYSTEM - Continued CONTINGENCY MEASURES Nonconformance Contingency Measures Restoration Time A. TNC 15.3.3.A, B, C, D.1 A.1 Stop using the Incore Detection System Immediately on through D.4, or E not for that associated function. discovery satisfied. B. TNC 15.3.3.D.5 not B.1 Stop using the Incore Detection System Within 14 EFPDs, satisfied for monitoring total planar radial either: peaking factor, total integrated radial Perform an peaking factor, or linear heat rate. evaluation and Perform an evaluation of the ability of implement any the incore detector system to detect required penalties, average power asymmetry of at least 10% between quadrant 4x4 groups of assemblies with the actual operable reduce power to less incore detector distribution, and if not, than or equal to 50%. implement penalties as identified in the evaluation to allow use of the Incore Detection System for monitoring total planar radial peaking factor, total integrated radial peaking factor, and linear heat rate. VERIFICATION REQUIREMENTS TVR Verification Frequency 15.3.3.1 Perform a channel check. Once within 24 hours prior to use AND 7 days thereafter 15.3.3.2 Perform a channel calibration. Neutron 24 months detectors are excluded from the channel calibration, but all electronic components are included. 15.3.3.3 Perform a calibration of the neutron Prior to installation detectors in the reactor core.

Technical Requirements Manual Rev. 15 Page 28 of 88 15.3.4 SEISMIC MONITORING INSTRUMENTATION NORMAL TNC 15.3.4 Each instrument listed in Table 15.3.4-1 must be operable. CONDITION APPLICABILITY At all times. CONTINGENCY MEASURES Nonconformance Contingency Measures Restoration Time A. One or more instruments A.1 Restore the instrument(s) to operable 30 days are inoperable status B. Contingency measure B.I See Section 15.0.3 and associated restoration time of Nonconformance A not met C. The system is activated C.I Restore to an operable status. 24 hours during a seismic event AND C.2 Retrieve and analyze data from the Following the event activated instruments to determine the magnitude of the vibratory ground motion. VERIFICATION REQUIREMENTS TVR Verification Frequency 15.3.4.1 Perform channel check. 31 days This channel check includes verifying the seismic monitoring instruments are energized except for the seismic triggers for the Triaxial Time-History Strong Motion Accelographs. 15.3.4.2 Perform channel functional test. 6 months 15.3.4.3 Perform channel calibration. Within 5 days following a seismic event AND 24 months

Technical Requirements Manual Rev. 15 Page 29 of 88 TABLE 15.3.4-1 SEISMIC MONITORING INSTRUMENTATION INSTRUMENTS AND SENSOR LOCATIONS MEASUREMENT RANGE

1. Triaxial Time-History Strong Motion Accelographs

a. 0-YE-00 1 Unit I Containment Base 0-1g

b. 0-YE-002 Unit 1 Containment 69' 0-1g

c. 0-YE-003 Auxiliary Building Base 0-1g

d. 0-YE-004 Intake Structure 0-1g

e. 0-YE-005 Free Field 0-lg

2. Triaxial Seismic Switches

a. 0-YS-001 Unit 1 Containment Base NA

b. 0-YS-002 Unit I Containment 69' NA

3. Seismic Acceleration Recorder

a. 0-YRC-001 Control Room NA

b. 0-YR-001 Control Room NA

Technical Requirements Manual Rev. 15 Page 30 of 88 15.3.5 FIRE DETECTION INSTRUMENTATION NORMAL TNC 15.3.5 The Fire Detection Instrumentation for each fire detection zone CONDITION shall be operable. APPLICABILITY Whenever equipment in the fire detection zone is required to be operable. CONTINGENCY MEASURES Nonconformance Contingency Measures Restoration Time A. One or more fire A.1 Establish an hourly fire watch to Within 1 hour and detection instruments inspect the zone(s) with the inoperable once per hour outside Containment are instrument(s), thereafter inoperable. AND AND A.2 Restore the instrument to operable 14 days Instrument(s) is located status. in a fire detection zone(s) not equipped with an automatic wet pipe sprinkler system alarmed and supervised to the Control Room. B. One or more fire B.1.1 Inspect in the Containment. Once per 8 hours detection instruments OR located inside Containment are B. 1.2 Monitor containment air temperature Within 1 hour inoperable, at the containment dome and containment reactor cavity locations. AND Once per 1 hour thereafter B.2 Restore instrumentation to operable 14 days status.

Technical Requirements Manual Rev. 15 Page 31 of 88 15.3.5 FIRE DETECTION INSTRUMENTATION - Continued CONTINGENCY MEASURES - Continued Nonconformance Contingency Measures Restoration Time C. One or more fire C. 1.1 Establish an hourly fire watch. Within I hour detection instruments OR outside Containment are C. 1.2.1 Inspect the zone(s) with Within I hour inoperable, inoperable instruments. AND AND Once per 24 hours AND thereafter The instrument(s) is located in fire detection zone(s) C. 1.2.2 Perform a channel functional test Within 1 hour equipped with an on the automatic sprinkler system, AND automatic wet pipe including the water flow alarm and sprinkler system alarmed supervisory system, in the zone Once per 24 hours and supervised to the with the inoperable instrument, thereafter Control Room. AND C.2 Restore instrumentation to operable 14 days status. D. Contingency measure D.I See Section 15.0.3. and associated restoration time of Nonconformance A, B, or C are not met. E. Fire detection instrument E. 1 For each detector found inoperable, Within frequency found inoperable during perform TVR 15.3.5.3 on an additional associated with TVR Technical Verification 10% of all fire detection instruments 15.3.5.3 that Requirement accessible during plant operation. Note identified inoperable (TVR) 15.3.5.3. that TVR 15.3.5.3 is only required to be instruments performed on either 10% of or 10 fire detection instruments accessible during plant operation, whichever is less

Technical Requirements Manual Rev. 15 Page 32 of 88 15.3.5 FIRE DETECTION INSTRUMENTATION - Continued VERIFICATION REQUIREMENTS TVR Verification Frequency 15.3.5.1 Verify each non-supervised circuit 31 days associated with detection alarms between the instrument and Control Room is operable. 15.3.5.2 Verify each National Fire Protection 6 months Association Code 72D Class B supervised circuit's supervision associated with the detector alarms is operable. 15.3.5.3 Perform a channel functional test on the 6 months fire detection instruments accessible during plant operation. This is only required on 25% of the fire detection instruments selected on a rotating basis such that all fire detection instruments accessible during plant operation will be tested over a 24 month period. If in any detection zone there are less than four detectors, at least one different detector in that zone shall be tested every 6 months. 15.3.5.4 Perform a channel functional test on the Each Mode 5 entry exceeding 24 hours fire detection instruments inaccessible during plant operation. This is not required if performed in the previous 6 months.

Technical Requirements Manual Rev. 15 Page 33 of 88 TABLE 15.3.5-1 FIRE DETECTION INSTRUMENTS -- UNIT 1 MINIMUM INSTRUMENTS OPERABLE ROOM/AREA AUX BLDG. INSTRUMENT LOCATION HEAT FLAME SMOKE 100/103/ 104/116 Corridors - Elevation (-)10'0" 5 110 Coolant Waste Receiving & Monitoring Tank 2 Pump Room 111 Waste Processing Control Room 112/114 Coolant Waste Receiving Tank 4 113 Miscellaneous Waste Receiver Tank Room 115 Charging Pump Room 3 118/122 Emergency Core Cooling System (ECCS) Pump 7 Room 119/122 ECCS Pump Room 7 200/202 Corridors, & 209/210 Corridors & 212/219 N/S Corridor & Personnel Elevator Access 13 Vestibule 207/208 Waste Gas Equipment Room 3 216 Reactor Coolant Make-up Pumps 1 217 BAST & Pump Room 2 218 Volume Control Tank Room 220 Degasifier Pump Room 221/326 West Piping Penetration Room 2 3 222 Hot Instrument Shop 2 223 Hot Machine Shop 4 224 East Piping Area 10 225 Radiation Exhaust Vent Equipment Room 4 226 Service Water Pump Room 3 6 227/316 East Piping Penetration Room 3 5 228 Component Cooling Pump Room 8 301/304/300 Battery Room & Corridor 3 306/1C Cable Spreading Room & Cable Chase(a) 2 10 308 N/S Corridor 6 315 Main Steam Piping Area 6 317 Switchgear Room, Elevation 2 7 '-0'(a) 6 318 Purge Air Supply Room 2

Technical Requirements Manual Rev. 15 Page 34 of 88 TABLE 15.3.5-1 (Continued) FIRE DETECTION INSTRUMENTS -- UNIT 1 MINIMUM INSTRUMENTS OPERABLE ROOM/AREA AUX BLDG. INSTRUMENT LOCATION HEAT FLAME SMOKE 319/325 West Passage and Vestibule 6 320 Spent Fuel Heat Exchanger Room 3 323 Passage 27' Valve Alley & Filter Room 3 324 Letdown Heat Exchanger Room Elevation 27-0" Switchgear Vent Duct IA Cable Chase 1A IB Cable Chase lB 405 Control Room 6 410 N/S Corridor 4 417/418 Solid Waste Processing 2 3 413/419/420 Cask and Equip Loading Area & 424/425/426 Cask and Equip Loading Area 3 22 421 Diesel Generator No. (1B) (a) 2 423 West Electrical Penetration Room 3 428 East Piping Area 7 429 East Electrical Pen Room 3 430 Switchgear Room Elevation 45 _O0,(a) 8 439 RWT Pump Room 2 441 Spent Resin Metering Tank Room 1 Elevation 45'-0" Switchgear Vent Duct I Elevation 69'-0" Control Room Vent Duct "A" Elevation 69'-0" Cable Spreading Room Vent Duct 512 Control Room Heating, Ventilation, and Air 4 Conditioning Equipment 586/588/589/590 Radiation Chemistry Area, 592/593 Radiation Chemistry Area, 595/596/597 Radiation Chemistry Area, 587 Frisker Area, 591 Clothing Disposal, and 523/594 N/S Corridor & Dressout/Frisker Area 20 520 Spent Fuel Pool (SFP) Area Vent Equipment 2 Room 524 Main Plant Exhaust Equipment Room 8 525 Containment Access Area 3

Technical Requirements Manual Rev. 15 Page 35 of 88 TABLE 15.3.5-1 (Continued) FIRE DETECTION INSTRUMENTS -- UNIT 1 MINIMUM INSTRUMENTS OPERABLE ROOM/AREA AUX BLDG. INSTRUMENT LOCATION HEAT FLAME SMOKE 529 Electrical Equipment Room 3 530/531/533 SFP Area 5 17 536/537 Miscellaneous Waste Evaporator & Equipment 3 Room Elevation 83'-0" Cable Tunnel 4 603 Auxiliary Feedwater Pump Room 2 Containment Bldg. U-1 Reactor Coolant Pump Bay East(b)(d) 16 U-I Reactor Coolant Pump Bay West(b)(d) 16 U-1 East Electric Penetration Area(b) (c) West Electric Penetration Area(b) (c) U-I Intake Structure Elevation 3'-0" Unit I Side [B08981 I IA DG Bldg. Zone 1 (a) Diesel Generator Room, Oil Separator Room, IA 33 Diesel Generator Building Trench, Fan Room, Maintenance Shop, and Hallway Zone 2 (a) Battery Room, Non-IE Electric Panel Room, I 11 Control Room, I -E Switchgear Room, Future Expansion Room Zone 3 (a) Fuel Oil Storage Tank Room 8 Zone 4 General Area, Third Room 17 Zone 5 Heating, Ventilation, and Air Conditioning Duct, 2 Second and Third Floor (a) Detectors that automatically actuate Fire Suppression Systems. (b) Detection Instruments located within the Containment are not required to be operable during the performance of Type A Containment Leakage Rate Tests. (c) Monitored by four protecto wires. (d) RCP bay heat detectors are not required to be operable in Modes 5 and 6 if all of the following conditions are met: [B08891 I. The RCP motors in the associated bay are de-energized, and

2. The RCS temperature is 200'F or less

Technical Requirements Manual Rev. 15 Page 36 of 88 TABLE 15.3.5-1 (Continued) FIRE DETECTION INSTRUMENTS -- UNIT 2 MINIMUM INSTRUMENTS OPERABLE(b) ROOM/AREA AUX BLDG. INSTRUMENT LOCATION HEAT FLAME SMOKE 101/120 ECCS Pump Room 7 102/120 ECCS Pump Room 7 105 Charging Pump Room 3 106 Miscellaneous Waste Monitor Tank 107/109 Coolant Waste Monitor Tank 4 108 Pump Room-Elevation (-)10'-0" 1 201 Component Cooling Pump Room 9 203 East Piping Area 10 204 Radiation Exhaust Vent, Equipment Room 4 205 Service Water Pump Room 3 6 206/310 East Piping Penetration Room 3 5 21 1/321 West Piping Penetration Room 2 3 213 Degasfier Pump Room 1 214 Volume Control Tank Room 1 215 BAST & Pump Room 2 216A Reactor Coolant Make-up Pumps 2 302/2C Unit 2 Cable Spreading Room & Cable Chase(a) 2 10 305/307/303 Unit 2 Battery Room & Corridor 3 309 Main Steam Piping Area 6 311 Switchgear Room, Elevation 27'-0" 6 312 Purge Air Supply Room 2 322 Letdown Heat Exchanger Room 1 Elev. 27'-0" Switchgear Vent Duct I 2A Cable Chase 2A 2B Cable Chase 2B 407 Switchgear Room, Elev. 4 5 '-,0 a 8 408 East Piping Area 7 409 East Electrical Penetration Room 3 414 West Electrical Penetration Room 3 416 Diesel Generator No. (2B) (a) 2 422 Diesel Generator No. (2A) (a) 2 440 RWT Pump Room 2 Elev. 45'-0" Switchgear Vent Duct I

Technical Requirements Manual Rev. 15 Page 37 of 88 TABLE 15.3.5-1 (Continued) FIRE DETECTION INSTRUMENTS -- UNIT 2 MINIMUM INSTRUMENTS OPERABLE(b) ROOM/AREA AUX BLDG. INSTRUMENT LOCATION HEAT FLAME SMOKE 526 Main Plant Exhaust Equipment Room 8 527 Containment Access 3 532 Electrical Equipment Room 3 Elev. 69'-0" Cable Spreading Room Vent Duct 1 Elev. 83'-0" Cable Tunnel 4 605 Auxiliary Feedwater Pump Room 2 Containment Bldg. Unit 2 Reactor Coolant Pump Bay East(b)(d) 16 Unit 2 Reactor Coolant Pump Bay West(b)(d) 16 Wc) Unit 2 East Electric Penetration Area(b) Unit 2 West Electric Penetration Area(b) (c) Intake Structure Elevation 3'-0" Unit 2 Side [B08981 I (a) Detectors that automatically actuate Fire Suppression Systems. (b) Detection instruments located within the Containment are not required to be operable during the performance of Type A Containment Leakage Rate Tests. (c) Monitored by four protecto wires. (d) RCP bay heat detectors are not required to be operable in Modes 5 and 6 if all of the following conditions are met: [B08891

1. The RCP motors in the associated bay are de-energized, and

2. The RCS temperature is 2007F or less

Technical Requirements Manual Rev. 15 Page 38 of 88 15.3.6 FEEDWATER FLOW MEASUREMENT INSTRUMENTATION NORMAL TNC 15.3.6 The LEFM CheckPlus system shall be operable, with the Plant CONDITION Computer available to perform the secondary calorimetric calculation. APPLICABILITY Mode I > 2700 MWt. I CONTINGENCY MEASURES

---

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

15.0.3 is not applicable to the LEFM CheckPlus system to raise Reactor Power >2700 MWt within the Restoration Time of the Contingency Measures. Nonconformance Contingency Measures J Restoration Time A. The LEFM CheckPlus A. 1.1 Maintain Reactor Power within Immediately system is inoperable. 10% Rated Thermal Power (RTP) of the initial power level when the system was declared inoperable. OR A. 1.2 Ensure Reactor Power is < 2700 Immediately MWt (98.6% RTP). AND A.2.1 Shift to the compensated venturi 1 hour feedwater flow measurement input to the secondary calorimetric. OR A.2.2 Ensure Reactor Power is _<2700 1 hour MWt (98.6% RTP). AND A.3.1 Restore the LEFM CheckPlus 72 hours system to operable status. OR A.3.2 Ensure Reactor Power is _S2700 72 hours MWt (98.6% RTP).

Technical Requirements Manual Rev. 15 Page 39 of 88 15.3.6 FEEDWATER FLOW MEASUREMENT INSTRUMENTATION - Continued CONTINGENCY MEASURES - Continued Nonconformance Contingency Measures Restoration Time B. The Plant Computer is B. I Restore the Plant Computer and all Prior to the next I unavailable, inputs to the secondary calorimetric required performance calculation. of Tech. Spec. SR OR 3.3.1.2 OR 24 hours, whichever is less An input from other than OR the LEFM CheckPlus system to the secondary B.2 Ensure Reactor Power is < 2700 MWt Prior to the next calorimetric calculation (98.6% RTP). required performance has failed, AND of Tech. Spec. SR resulted in bad quality of 3.3.1.2 OR 24 hours, the 16-minute average whichever is less calculation. C. Contingency measure C. 1 See Section 15.0.3. and associated restoration time of Nonconformance A or B are not met. VERIFICATION REQUIREMENTS TVR Verification Frequency 15.3.6.1 Perform applicable maintenance checks 24 months contained in VTD 15799-004-1002:

                 " General examination of the LEFM cabinet
                 " Power supply inspection

• Central processing unit inspection
• Acoustic processing unit checks

                 " Analog input checks

• Ethernet communication test

                 " Transducer checks

• Spool piece metering section checks Analog output checks, relay output checks, watchdog timer checks and the serial communication test contained in VTD 15799-004-1002 are not applicable to Calvert Cliffs.

Technical Requirements Manual Rev. 15 Page 40 of 88 15.4 REACTOR COOLANT SYSTEM 15.4.1 CHEMISTRY NORMAL CONDITION TNC 15.4.1 The RCS chemistry shall be maintained within limits. [B23691 Parameter Action Level 2 Action Level 3 Dissolved Oxygen >0.100 ppm > 1 ppm Chloride > 0.15 ppm > 1.50 ppm Fluoride > 0.15 ppm > 1.50 ppm Sulfate

• 0. 15 ppm > 1.50 ppm Hydrogen < 15 cc/kg < 5 cc/kg H 2 limits only apply when RX is critical.

The dissolved oxygen limits are not applicable with Tag < 250'F. APPLICABILITY At all times. CONTINGENCY MEASURES Nonconformance Contingency Measures Restoration Time A. One or more chemistry A. I Initiate unit shutdown and cooldown to Immediately parameter values in excess Tavg <250 0 F. of Action Level 3 with Tavg >250°F. If a shutdown is initiated due to RCS parameter(s) exceeding Action Level 3, and RCS chemistry improves to within Action Level 3, the shutdown and cooldown per this Contingency Measure may be terminated. B. One or more chemistry B. I Restore the parameter(s) to below 24 hours parameter values in excess Action Level 2 limits. of Action Level 2. C. The contingency measure C.1 Initiate unit shutdown and cooldown to Immediately and associated restoration Tavg <250 0 F. time of Nonconformance B are not met. If a shutdown is initiated due to RCS parameter(s) exceeding Action Level 2, and RCS chemistry improves to within Action Level 2, the shutdown and cooldown per this Contingency Measure may be terminated.

Technical Requirements Manual Rev. 15 Page 41 of 88 15.4.1 CHEMISTRY - Continued CONTINGENCY MEASURES - Continued Nonconformance Contingency Measures Restoration Time D. The contingency measure D.I See Section 15.0.3. and associated restoration time of Nonconformance A or C are not met. OR One or more chemistry parameter values exceed Action Level 3 with Tavg

      <2500 F.

VERIFICATION REQUIREMENTS TVR Verification Frequency NOTE 15.4.1.1 TVR is not required to be performed when all of the following requirements are met: 1B07721

• RCS chemistry sampling is not possible due to low RCS level.

                " The applicable Unit (I or 2) is defueled.
                "    RCS temperature is less than 145°F.

• RCS chemistry is verified to be within TRM 15.4.1 limits prior to reducing RCS level.

Verify RCS chemistry to be within the 72 hours TNC limits. OR 8 hours prior to exceeding 250°F in the RCS

Technical Requirements Manual Rev. 15 Page 42 of 88 15.4.2 PRESSURIZER PRESSURE/TEMPERATURE LIMITS NORMAL TNC 15.4.2 The pressurizer temperature shall be limited to: CONDITION

a. A maximum heatup of 100'F in any one hour period,

b. A maximum cooldown of 200'F in any one hour period, and

c. A maximum spray water temperature differential of 400'F.

APPLICABILITY At all times. CONTINGENCY MEASURES Nonconformance Contingency Measures Restoration Time A. Pressurizer temperature A. 1 Restore temperature to within limits. 30 minutes in excess of any of the AND above limits. A.2 Perform an engineering evaluation to None determine the effects of the out-of-limit condition on the fracture toughness properties of the pressurizer and to determine that the pressurizer is acceptable for continued operation. B. Contingency measure B. 1 See Section 15.0.3. and associated restoration time of Nonconformance A are not met. VERIFICATION REQUIREMENTS TVR Verification Frequency 15.4.2.1 Verify the pressurizer temperature is At least once per 30 minutes within the limits during system heatup or cooldown. 15.4.2.2 Verify the spray water temperature At least once per 12 hours differential is within the limits during auxiliary spray operation.

Technical Requirements Manual Rev. 15 Page 43 of 88 15.4.3 AMERICAN SOCIETY OF MECHANICAL ENGINEERS (ASME) CODE CLASS 1, 2, AND 3 COMPONENTS NORMAL TNC 15.4.3 The structural integrity of ASME Code Class 1, 2, and 3 CONDITION components shall be within the limits of the Inservice Inspection Program. APPLICABILITY Modes 1, 2, 3, 4, 5, and 6. CONTINGENCY MEASURES Nonconformance Contingency Measures Restoration Time A. Structural integrity of A.1 Restore structural integrity of the Prior to increasing ASME Class 1 affected component(s) to within the the RCS temperature component(s) is not limit, more than 50'F within the limit. above the minimum temperature required by nil-ductility OR temperature considerations A.2 Isolate the affected component(s). Prior to increasing the RCS temperature more than 50'F above the minimum temperature required by nil-ductility temperature considerations B. Structural integrity of B.1 Restore the structural integrity of the Prior to increasing ASME Class 2 affected component(s) to within the the RCS temperature component(s) is not limit, above 2007F within the limit. OR B.2 Isolate the affected component(s). Prior to increasing the RCS temperature above 2007F C. Contingency Measures C. 1 See Section 15.0.3. and associated restoration times of Nonconformances A or B not met. D. Structural integrity of D.1 Restore the structural integrity of the None any ASME Class 3 affected component(s) to within the component(s) is not limit. within the limit. OR

Technical Requirements Manual Rev. 15 Page 44 of 88 15.4.3 AMERICAN SOCIETY OF MECHANICAL ENGINEERS (ASME) CODE CLASS 1, 2, AND 3 COMPONENTS - Continued CONTINGENCY MEASURES - Continued Nonconformance Contingency Measures Restoration Time D.2 Isolate the affected component(s) from None service. VERIFICATION REQUIREMENTS TVR Verification Frequency. 15.4.3.1 Verify structural integrity of ASME In accordance with the Inservice Class 1, 2, and 3 components are within Inspection Program limits specified in the Inservice Inspection Program. 15.4.3.2 Verify structural integrity of main steam In accordance with the augmented and main feedwater piping is within limits Inservice Inspection Program. specified in the augmented Inservice Inspection Program. Augmented lnservice Inspection Program for Main Steam and Main Feedwater Piping The unencapsulated welds greater than four inches in nominal diameter in the main steam and main feedwater piping runs located outside the Containment and traversing safety-related areas or located in compartments adjoining safety-related areas shall be inspected per the following augmented inservice inspection program using the applicable rules, acceptance criteria and repair procedures of the ASME Boiler and Pressure Vessel Code, Section XI, Endorsed in the Inservice Inspection Program, for Class 2 components. Each weld must be examined in accordance with the above ASME Code requirements, except that 100% of the welds must be examined, cumulatively, during each ten year inspection interval. The welds to be examined during each inspection period shall be selected to provide a representative sample of the conditions of the welds. If these examinations reveal unacceptable structural defects in one or more welds, an additional 1/3 of the welds shall be examined and the inspection schedule for the repaired welds shall revert back as if a new interval had begun. If additional unacceptable defects are detected in the second sampling, the remainder of the welds shall also be inspected. Alternatively, a Risk-informed process for piping outlined in EPRI Topical Report 1006937 revision 0-A may be used for the weld selections and the determination of required additional examinations when defects are discovered.

Technical Requirements Manual Rev. 15 15.4.4 DELETED Page 45 of 88

Technical Requirements Manual Rev. 15 Page 46 of 88 15.4.5 LETDOWN LINE EXCESS FLOW NORMAL TNC 15.4.5 The bypass valve for the excess flow check valve in the letdown CONDITION line shall be closed. APPLICABILITY Modes 1, 2, 3, and 4. CONTINGENCY MEASURES Nonconformance Contingency Measures Restoration Time A. Bypass valve open. A.I Close bypass valve. 4 hours B. Contingency measure B. I See Section 15.0.3. and associated restoration time of Nonconformance A are not met. VERIFICATION REQUIREMENTS TVR Verification Frequency 15.4.5.1 Verify bypass valve for the excess flow 4 hours prior to entry into Mode 4 from check valve in the letdown line is closed. Mode 5

Technical Requirements Manual Rev. 15 Page 47 of 88 15.4.6 RCS VENTS NORMAL TNC 15.4.6 Two RCS vent paths shall be operable. CONDITION The two RCS vent paths consist of two closed solenoid valves in series at the reactor vessel head and the pressurizer vapor space. APPLICABILITY Modes 1 and 2. CONTINGENCY MEASURES Nonconformance Contingency Measures Restoration Time A. Reactor vessel head vent A.I Maintain the inoperable vent path Immediately path is inoperable, closed with power removed from the actuator of the solenoid valves. AND A.2 Restore the Inoperable reactor vessel 30 days head vent path to operable status. B. Pressurizer vapor space B. 1 Maintain the inoperable vent path Immediately vent path is inoperable, closed with power removed from the actuator of the solenoid valves. AND B.2.1 Verify one power-operated relief 72 hours valve and its associated flow path is operable. AND B.2.2 Restore the inoperable pressurizer Prior to entering vapor space vent path to operable Mode 2 following the status. next Mode 3 of OR sufficient duration B.3 Restore inoperable pressurizer 30 days vapor space vent path to operable status. C. Reactor vessel head vent C. I Restore both inoperable vent paths to 72 hours path is inoperable, operable status. AND Pressurizer vapor space vent path is inoperable. D. Contingency measure D.I See Section 15.0.3. and associated restoration time of Nonconformances A, B, or C are not met.

Technical Requirements Manual Rev. 15 Page 48 of 88 15.4.6 RCS VENTS - Continued VERIFICATION REQUIREMENTS TVR Verification Frequency 15.4.6.1 Verify manual isolation valves in each 24 months vent path are locked in the open position. 15.4.6.2 Verify flow through the RCS vent path 24 months with the vent valves open.

Technical Requirements Manual Rev. 15 15.5 NOT USED Page 49 of 88

Technical Requirements Manual Rev. 15 Page 50 of 88 15.6 CONTAINMENT SYSTEMS 15.6.1 CONTAINMENT STRUCTURAL INTEGRITY NORMAL TNC 15.6.1 The structural integrity of the Containment shall be maintained at CONDITION a level consistent with the acceptance criteria of the ASME Boiler and Pressure Vessel Code Section XI, Subsection IWL, Requirements for Class CC Concrete Components of Light-Water Cooled Plants, 1992 Edition with 1992 Addenda, as modified and amended by 10 CFR 50.55a. [B07031 APPLICABILITY Modes 1, 2, 3 and 4. CONTINGENCY MEASURES Nonconformance Contingency Measures Restoration Time A. The Acceptance A.I Perform actions as required by IWL-3310. Immediately Standards of IWL-3000 are not met. B.1 See Section 15.0.3. B. Contingency measure and associated restoration time of Nonconformance A are not met OR Containment structure exhibits possible evidence of abnormal degradation. C. Containment Structural C. I Restore structural integrity. Prior to increasing Integrity not conforming OR RCS temperature to acceptance criteria of - above 200'F. TVR 15.6.1.2. C.2 Complete an engineering evaluation that assures structural integrity. VERIFICATION REQUIREMENTS TVR Verification Frequency 15.6.1.1 Perform the examinations required by In accordance with the Concrete IWL-2000. Containment Tendon Surveillance Program. 15.6.1.2 Conduct an inspection of the pre-selected In accordance with the Containment concrete crack patterns adjacent to containment Leakage Rate Testing Program. tendon end anchorage's during the Type A Containment Leakage Rate Tests with Containment at maximum test pressure.

Technical Requirements Manual Rev. 15 Page 51 of 88 15.6.2 CONTAINMENT CLOSEOUT NORMAL TNC 15.6.2 The Containment shall remain free of loose debris (rags, trash, CONDITION clothing, etc.) which could be transported to the containment sump and cause restriction of the pump suctions during LOCA conditions. APPLICABILITY Modes 1, 2, 3, and 4. CONTINGENCY MEASURES Nonconformance Contingency Measures Restoration Time A. NONE A.I NONE NONE VERIFICATION REQUIREMENTS TVR Verification Frequency 15.6.2.1 A visual inspection shall be performed for Prior to establishing Containment all accessible areas of the Containment. integrity. 15.6.2.2 A visual inspection shall be performed of Upon completion of the containment entry the areas affected within Containment. when Containment integrity has been established.

Technical Requirements Manual Rev. 15 Page 52 of 88 15.7 PLANT SYSTEMS 15.7.1 STEAM GENERATOR PRESSURE/TEMPERATURE LIMITATION NORMAL TNC 15.7.1 The temperatures of both the primary and secondary coolant in CONDITION the steam generators shall be > 807F when the pressure of either the primary or secondary coolant in the steam generator is > 200 psig. APPLICABILITY At all times. CONTINGENCY MEASURES Nonconformance Contingency Measures Restoration Time A. Steam generator A.1 Reduce the steam generator pressure on 30 minutes pressure/ temperature the applicable side to < 200 psig. not within limits. AND A.2 Perform an engineering evaluation. Prior to increasing The engineering evaluation shall steam generator determine that the steam generator temperatures above remains acceptable for continued 200°F operation. VERIFICATION REQUIREMENTS TVR Verification Frequency 15.7.1.1 Verify each steam generator primary and 1 hour, if the following conditions apply: secondary coolant pressure is < 200 psig. [B08001 This is only required to be performed Both manways are installed on both the when steam generator primary or primary and secondary side of the secondary coolant temperature is < 800 F. steam generator, OR Both manways are installed on the primary side (hot leg/cold leg) of the steam generator AND either one or both manways are removed from the secondary side. In this case, the surveillance need only be performed on the primary side, OR Both manways are installed on the secondary side of the steam generator AND either one or both manways are removed from the primary side (hot leg/cold leg). In this case, the surveillance need only be performed on the secondary side.

Technical Requirements Manual Rev. 15 Page 53 of 88 15.7.2 SNUBBERS NORMAL TNC 15.7.2 The safety-related snubbers shall be operable. CONDITION Safety-related snubbers include those snubbers installed on safety-related systems and snubbers on non-safety related systems if their failure or the failure of the system on which they are installed would have an adverse effect on any safety-related system. APPLICABILITY Modes 1, 2, 3, 4, 5, and 6. In Modes 5 and 6 the only snubbers required to be operable are those snubbers located on systems required to be operable. CONTINGENCY MEASURES Nonconformance Contingency Measures Restoration Time A. One or more snubbers A. I See Technical Specification LCO 3.0.8. inoperable. VERIFICATION REQUIREMENTS TVR I Verification Frequency 15.7.2.1 Verify snubbers are operable per the In accordance with the snubber inspection snubber inspection program. As used here, program type of snubber shall mean snubbers of the same design and manufacturer, irrespective of capacity.

Technical Requirements Manual Rev. 15 Page 54 of 88 15.7.2 SNUBBERS - Continued VERIFICATION REQUIREMENTS - Continued TVR I Verification Frequency Snubber Inspection Program

a. Visual Inspections Visual inspections shall be performed in accordance with the schedule determined by Table 15.7.2.1. Snubbers are categorized as inaccessible or accessible during reactor operation. Each of these categories (inaccessible and accessible) may be inspected independently or jointly according to the schedule determined by Table 15.7.2.1. The visual inspection interval for each population or category of snubbers shall be determined based upon the criteria provided in Table 15.7.2.1. [B0627]

b. Visual Inspection Acceptance Criteria Visual inspections shall verify (1) that there are no visible indications of damage or impaired operability, and (2) that the snubber installation exhibits no visual indications of detachment from foundations or supporting structures. 1B06271 Snubbers that appear inoperable as a result of visual inspections may be determined operable for the purpose of establishing the next visual inspection interval, provided that: (1) the cause of the rejection is clearly established, remedied and functionally tested for that particular snubber and for other snubbers that may be generically susceptible; or (2) the affected snubber is functionally tested in the as found condition and determined operable per the Hydraulic Snubbers Functional Test Acceptance Criteria, as applicable. When the fluid port of a hydraulic snubber is found to be uncovered, the snubber shall be determined inoperable unless it can be determined operable via functional testing for the purpose of establishing the next visual inspection interval.

For the snubber(s) found inoperable, an engineering evaluation shall be performed on the component(s) that are supported by the snubber(s). The scope of this engineering evaluation shall be consistent with the licensee's engineering judgment and may be limited to a visual inspection of the supported component(s). The purpose of this engineering evaluation shall be to determine if the component(s) supported by the snubber(s) were adversely affected by the inoperability of the snubber(s) in order to ensure that the supported component remains capable of meeting the designed service.

c. Functional Tests At least once per 24 months, a representative sample of 10% of each type of snubbers in use in the plant shall be functionally tested either in-place or in a bench test. For each snubber that does not meet the functional test acceptance criteria of the Hydraulic Snubbers Functional Test Acceptance Criteria, an additional 5% of that type snubber shall be functionally tested until no more failures are found or until all snubbers of that type have been functionally tested.

Snubber Inspection Program - Continued

Technical Requirements Manual Rev. 15 Page 55 of 88 Snubber Inspection Program - Continued

c. Functional Tests Snubbers identified as "Especially Difficult to Remove" or in "High Exposure Zones" shall also be included in the representative sample (permanent or other exemptions from functional testing for individual snubbers in these categories may be granted by the NRC only if a justifiable basis for exemption is presented and/or snubber life destructive testing was performed to qualify snubber operability for all design conditions at either the completion of their fabrication or at a subsequent date).

In addition to the regular sample, snubbers that failed the previous functional test shall be retested during the next test period. If a spare snubber has been installed in place of a failed snubber, then both the failed snubber (if it is repaired and installed in another position) and the spare snubber shall be retested during the next test period. Failure of these snubbers shall not entail functional testing of additional snubbers. If any snubber selected for functional testing either fails to lock up or fails to move, i.e., frozen in place, the cause will be evaluated and if caused by manufacturer or design deficiency all generically susceptible snubbers of the same design subject to the same defect shall be functionally tested. This testing requirement shall be independent of the requirements stated above for snubbers not meeting the functional test acceptance criteria. For the snubber(s) found inoperable, an engineering evaluation shall be performed on the component(s) that are supported by the snubber(s). The scope of this engineering evaluation shall be consistent with the licensee's engineering judgment and may be limited to a visual inspection of the supported component(s). The purpose of this engineering evaluation shall be to determine if the component(s) supported by the snubber(s) were adversely affected by the inoperability of the snubber(s) in order to ensure that the supported component remains capable of meeting the designed service.

d. Hydraulic Snubbers FunctionalTest Acceptance Criteria The hydraulic snubber functional test shall verify that:

1. Activation (restraining action) is achieved within the specified range of velocity or acceleration in both tension and compression.

2. Snubber bleed, or release rate, where required, is within the specified range in compression or tension. For snubbers specifically required to not displace under continuous load, the ability of the snubber to withstand load without displacement shall be verified.

Snubber Inspection Program - Continued

Technical Requirements Manual Rev. 15 Page 56 of 88 Snubber Inspection Program - Continued

e. Snubber Service Life Monitoring A record of the service life of each snubber, the date at which the designated service life commences and the installation and maintenance records on which the designated service life is based shall be maintained.

At least once per 24 months, the installation and maintenance records for each safety-related snubber shall be reviewed to verify that the indicated service life has not been exceeded or will not be exceeded prior to the next scheduled snubber service life review (including the 1.25 times extension). If the indicated service life will be exceeded prior to the next scheduled snubber service life review, the snubber service life shall be reevaluated or the snubber shall be replaced or reconditioned so as to extend its service life beyond the date of the next scheduled service life review. This reevaluation, replacement or reconditioning shall be indicated in the records.

Technical Requirements Manual Rev. 15 Page 57 of 88 TABLE 15.7.2-1 SNUBBER VISUAL INSPECTION INTERVAL NUMBER OF INOPERABLE SNUBBERS Population Column A Column B Column C or Category Extend Interval Repeat Interval Reduce Interval (Notes I and 2) (Notes 3 and 6) (Notes 4 and 6) (Notes 5 and 6) 1 0 0 1 80 0 0 2 100 0 1 4 150 0 3 8 200 2 5 13 300 5 12 25 400 8 18 36 500 12 24 48 750 20 40 78 1000 or greater 29 56 109 Note 1: The next visual inspection interval for a snubber population or category size shall be determined based upon the previous inspection interval and the number of inoperable snubbers found during that interval. Snubbers may be categorized, based upon their accessibility during power operation, as accessible or inaccessible. These categories may be examined separately or jointly. However, the licensee must make and document that decision before any inspection and shall use that decision as the basis upon which to determine the next inspection interval for that category. Note 2: Interpolation between population or category sizes and the number of inoperable snubbers is permissible. Use next lower integer for the value of the limit for Columns A, B, or C if that integer includes a fractional value of inoperable snubbers as determined by interpolation. Note 3: If the number of inoperable snubbers is equal to or less than the number in Column A, the next inspection interval may be twice the previous interval but not greater than 48 months. Note 4: If the number of inoperable snubbers is equal to or less than the number in Column B but greater than the number in Column A, the next inspection interval shall be the same as the previous interval.

Technical Requirements Manual Rev. 15 Page 58 of 88 TABLE 15.7.2-1 (Continued) SNUBBER VISUAL INSPECTION INTERVAL Note 5: If the number of inoperable snubbers is equal to or greater than the number in Column C, the next inspection interval shall be two-thirds of the previous interval. However, if the number of inoperable snubbers is less than the number in Column C but greater than the number in Column B, the next interval shall be reduced proportionally by interpolation, that is, the previous interval shall be reduced by a factor that is one-third of the ratio of the difference between the number of inoperable snubbers found during the previous interval and the number in Column B to the difference in the numbers in Columns B and C. Note 6: An extension of 1.25 times the inspection interval is applicable for all inspection intervals up to and including 48 months.

Technical Requirements Manual Rev. 15 Page 59 of 88 15.7.3 SEALED SOURCE CONTAMINATION NORMAL TNC 15.7.3 Each sealed source containing radioactive material either in excess CONDITION of 100 microcuries of beta and/or gamma emitting material or 5 microcuries of alpha emitting material shall be free of> 0.005 microcuries of removable contamination. APPLICABILITY At all times. CONTINGENCY MEASURES Nonconformance Contingency Measures Restoration Time A. Sealed source removable A. I Withdraw the sealed source from use. Immediately contamination is not within the limit. Whenever a sealed source is withdrawn from use, the sealed source must either be decontaminated and repaired, or disposed of in accordance with the regulations. VERIFICATION REQUIREMENTS Startup sources and fission detectors previously subjected to core flux do not require verification tests. TVR Verification Frequency 15.7.3.1 Verify leakage and/or contamination levels 6 months for sealed sources in use. This is only required to be performed on sealed source containing radioactive material with a half-life greater than 30 days (excluding Hydrogen-3), and in any form other than gas. The leakage and contamination test may be performed by licensee, or other persons specifically authorized by the NRC or an agreement state. The test method shall have a detection sensitivity of at least 0.005 microcuries per test sample.

Technical Requirements Manual Rev. 15 Page 60 of 88 15.7.3 SEALED SOURCE CONTAMINATION - Continued VERIFICATION REQUIREMENTS - Continued TVR Verification Frequency 15.7.3.2 Verify leakage and/or contamination levels Prior to use or transfer to another licensee. for sealed sources not in use. This is only required to be performed if not tested in the previous 6 months. Sealed sources transferred without a certificate indicating the last test date shall be tested prior to being placed into use. 15.7.3.3 Verify leakage and/or contamination levels Within 31 days prior to being subjected to for startup sources and fission detectors. core flux or installed in the core AND Following repair or maintenance to the source or detector. 15.7.3.4 Perform inventory of Sealed sources. Annual [B06501

Technical Requirements Manual Rev. 15 Page 61 of 88 15.7.4 DELETED

Technical Requirements Manual Rev. 15 Page 62 of 88 15.7.5 FIRE SUPPRESSION WATER SYSTEM NORMAL TNC 15.7.5 The Fire Suppression Water System shall be operable. CONDITION The Fire Suppression Water System shall consist of:

a. Two high pressure pumps, each with a capacity of 2500 gpm, with their discharge aligned to the fire suppression header,

b. Two water supplies, each with a minimum contained volume of 300,000 gallons, and

c. An operable flow path capable of taking suction from the Pretreated Water Storage Tank Nos. II and 12 and transferring the water through distribution piping with operable sectionalizing control or isolation valves to the yard hydrant curb valves required to be in operation in Section 15.7.9 and the first valve ahead of the water flow alarm device on each sprinkler, hose standpipe, or spray system riser required to be operable per TNCs 15.7.6, 15.7.8, and 15.7.9.

Opening the cross-connect valves to the owner-controlled loop of the fire fighting system does not affect the operability of the plant fire suppression system. However, the owner-controlled loop of the fire fighting system cannot be used to make the plant fire suppression system operable. Shutting fire suppression water system isolation valve 0-FP-137(PIV) for the purpose of performing surveillance testing (e.g., TVR 15.7.5.10) does not make the fire suppression water system inoperable provided:

                   "     An operator is dedicated to immediately open the valve and return it to its normal position (e.g., locked open) and is in direct communication with the Control Room.
                   "     An inspection of the affected sprinkler area(s) has been conducted to verify no ignition source activities are in progress (e.g., welding, cutting, grinding, stress relieving of pipe welds, heat treatment of metals, and open flames).

APPLICABILITY At all times.

Technical Requirements Manual Rev. 15 Page 63 of 88 15.7.5 FIRE SUPPRESSION WATER SYSTEM - Continued CONTINGENCY MEASURES Nonconformance Contingency Measures Restoration Time A. One pump inoperable. A. I Restore pump or water supply to 7 days OR operable status. One water supply inoperable. B. Fire Suppression Water B. 1 Establish a backup Fire Suppression 24 hours System inoperable for Water System. reasons other than Nonconformance A. See Section 15.0.3. C. Contingency measure C. 1 See Section 15.0.3. and associated restoration time of Nonconformance A is not met. VERIFICATION REQUIREMENTS TVR Verification Frequency 15.7.5.1 Verify that each required contained water 7 days supply volume contains > 300,000 gallons. 15.7.5.2 Verify diesel fire pump starting battery 7 days bank electrolyte level is above the plates. 15.7.5.3 Verify diesel fire pump starting battery 7 days bank overall voltage is > 24 Volt. 15.7.5.4 Verify electric motor driven fire pump 31 days on a staggered test basis operates for > 15 minutes. AND Verify diesel fire pump starts from ambient condition and operates for _ 30 minutes. 15.7.5.5 Verify each manual, power-operated, and 31 days automatic valve in the flow path that is not locked, sealed, or otherwise secured in position is in the correct position.

Technical Requirements Manual Rev. 15 Page 64 of 88 15.7.5 FIRE SUPPRESSION WATER SYSTEM - Continued VERIFICATION REQUIREMENTS - Continued TVR Verification Frequency 15.7.5.6 Verify the diesel fire pump fuel oil day 31 days storage tank contains > 174 gallons. 15.7.5.7 Verify diesel fire pump fuel oil storage 92 days tank sample is within limits. The sample is required to be obtained in accordance with American Society for Testing and Materials D270-65 and results of sampling is required to be within the limits specified in Table I of the American Society for Testing and Materials D975-81 when checked for viscosity, water, and sediment. 15.7.5.8 Verify diesel fire pump starting battery 92 days bank specific gravity is appropriate for continued service of the battery. 15.7.5.9 Perform a system flush of the filled 12 months portions of fire suppression water system. 15.7.5.10 Verify each testable valve in the flow path 12 months can be cycled, by cycling it through at least one complete cycle of full travel. 15.7.5.11 Perform a system functional test on the fire 18 months suppression water system. The verification will consist of:

a. simulating automatic actuation of the system throughout its operating sequence,

b. verifying each automatic valve in the flow path actuates to its correct position,

c. verifying each pump develops at least 2500 gpm at a discharge pressure of 125 psig, and

d. verifying each high pressure pump starts (sequentially) to maintain the fire suppression water system pressure _> 80 psig.

15.7.5.12 Verify the diesel fire pump starts from 18 months ambient conditions on the auto-start signal and operates for > 20 minutes, while loaded with the fire pump.

Technical Requirements Manual Rev. IS Page 65 of 88 15.7.5 FIRE SUPPRESSION WATER SYSTEM - Continued VERIFICATION REQUIREMENTS - Continued TVR Verification Frequency 15.7.5.13 Perform an inspection of the fire pump 18 months diesel. This inspection is required to be performed in accordance with procedures prepared in conjunction with its manufacturer's recommendations for the class of service. 15.7.5.14 Verify fire pump diesel starting batteries, 18 months cell plates, and battery racks show no visual indication of physical damage or abnormal deterioration. 15.7.5.15 Verify fire pump diesel starting battery-to- 18 months battery and terminal connections are clean, tight, free of corrosion, and coated with anti-corrosion material. 15.7.5.16 Perform a system flow test on the fire 24 months suppression water system. The test must be performed in accordance with the Fire Protection Handbook. [Fire Protection Handbook, 14th Edition, Section 11, Chapter 5 (published by The National Fire Protection Association)] 15.7.5.17 Perform a system functional test on the fire 24 months suppression water system. The verification will consist of:

a. simulating automatic actuation of the system throughout its operating sequence, and

b. cycling each valve in the flow path that is not testable during plant operation through at least one complete cycle of full travel.

Technical Requirements Manual Rev. 15 Page 66 of 88 15.7.6 SPRAY AND SPRINKLER SYSTEM NORMAL TNC 15.7.6 The fire suppression spray and/or sprinkler system shall be CONDITION operable. The spray and/or sprinkler systems identified in Tables 15.7.6-1 and 15.7.6-2 are required to be operable. Shutting spray and sprinkler system isolation valve(s) for the purpose of performing surveillance testing (e.g., TVR 15.7.6.2, 15.7.5.10) does not make the spray and sprinkler system inoperable provided:

• An operator is dedicated to immediately open the valve and return it to its normal position (e.g., locked open) and is in direct communication with the Control Room.
• An inspection of the affected sprinkler area has been conducted to verify no ignition source activities are in progress (e.g., welding, cutting, grinding, stress relieving of pipe welds, heat treatment of metals, and open flames).

APPLICABILITY Whenever equipment in the spray/sprinkler protected areas are required to be operable. CONTINGENCY MEASURES Nonconformance Contingency Measures Restoration Time A. One or more spray or A. I Establish a continuous fire watch with 1 hour sprinkler systems backup fire suppression equipment. inoperable in areas where redundant safe shutdown systems or A.2 Restore system(s) to operable status. 14 days components could be damaged. B. One or more spray or B.1 Establish an hourly fire watch patrol. 1 hour sprinkler systems AND inoperable in areas other A than in Nonconformance B.2 Restore system(s) to operable status. 14 days A. C. Contingency measures C.1 See Section 15.0.3. A.2 and/or B.2 and associated restoration time cannot be met.

Technical Requirements Manual Rev. 15 Page 67 of 88 15.7.6 SPRAY AND SPRINKLER SYSTEM - Continued VERIFICATION REQUIREMENTS TVR Verification Frequency 15.7.6.1 Verify each manual, power-operated, and 31 days automatic valve in the flow path that is not locked, sealed, or otherwise secured in position is in its correct position. 15.7.6.2 Cycle each valve in the flow path through 12 months at least one complete cycle of full travel. 15.7.6.3 Perform a system functional test on the fire 18 months suppression spray and sprinkler system. The verification will include:

a. simulating automatic actuation of the system, and

b. verifying that the automatic valves in the flow path actuate to their correct positions on a simulated test signal.

15.7.6.4 Verify by visual inspection of the area in 18 months the vicinity of each nozzle that the nozzle spray pattern is unobstructed.

Technical Requirements Manual Rev. 15 Page 68 of 88 TABLE 15.7.6-1 SPRINKLER LOCATIONS -- UNIT 1 CONTROL VALVE SPRINKLER LOCATION ELEVATION I B Diesel Generator 45'-0" Unit I East Pipe Penetration Room 227/316(a) 5'-0" Unit I Auxiliary Feedwater Pump Room 603(a) 12'-0" Unit I East Piping Area Room 428(a) 45'-0" Unit I East Electrical Penetration Room 429(a) 45'-0" Unit 1 West Electrical Penetration Room 423(a) 45'-0" Unit 1 Main Steam Piping Room 315(a) 45'-0" Unit I Component Cooling Pump Room 228(a) 59-0" Unit 1 East Piping Area 224(a) 5'-0" Unit I Radiation Exhaust Vent Equipment Room 225(a) 5'-0" Unit I Service Water Pump Room 226(a) 59-0" Unit I BAST and Pump Room 217()a) 5'-0" Unit 1 Reactor Coolant Makeup Pump Room 216(a) 5'-0" Unit 1 Charging Pump Room 115(a) (-)10'-0" Unit I Miscellaneous Waste Monitoring Room 113(a) (-)10'-0" Cask and Equipment Loading Area Rooms 419, 420, 425, and 426(a) 459-0" Solid Waste Processing(a) 45'-0" Corridors 200, 202, 212, and 219(a) 5'-0" Corridors 100, 103, and 116(a) (-)10'-0" Cable Chase 1A(a) 45'-0" Cable Chase 1Ba(a) 45'-0" Unit I ECCS Pump Room 119(a) (-)15'-0" Hot Instrument Shop Room 222(a) 59-0" Hot Machine Shop Room 223(a) 55-0" 1A Diesel Generator Building - Preaction Systems 1, 2, and 3 45'-6" (a) Sprinklers required to ensure the operability of redundant safe shutdown equipment.

Technical Requirements Manual Rev. 15 Page 69 of 88 TABLE 15.7.6-2 SPRINKLER LOCATIONS -- UNIT 2 CONTROL VALVE SPRINKLER LOCATION ELEVATION Unit 2 Auxiliary Feedwater Pump Room 605(a) 12'-0" Unit 2 East Piping Area Room 408(a) 45'-0" Unit 2 East Electrical Penetration Room 409(a) 45'-0" Unit 2 West Electrical Penetration Room 414(a) 45'0" Cable Chase 2A(a) 45'-0" Cable Chase 2B(a) 45'-0" Unit 2 Main Steam Piping Room 309(a) 45'-0" Unit 2 Component Cooling Pump Room 201(a) 51-0" Unit 2 East Piping Area 203(a) 5'-0" Unit 2 Radiation Exhaust Vent Equipment Room 204(a) 5'-0" Unit 2 Service Water Pump Room 205(a) 5-0" Unit 2 BAST and Pump Room 215(a) 51-0" Unit 2 Reactor Coolant Makeup Pump Room 216A(a) 5'-0" Unit 2 Charging Pump Room 105(a) (-)10'-0" Unit 2 Miscellaneous Waste Monitoring Room 106(a) (-)10'-0" Unit 2 ECCS Pump Room 101(a) (-)15'-0" 2A Diesel Generator 45'-0" 2B Diesel Generator 45'-0" Unit 2 East Pipe Penetration Room 206/310(a) 5'-0" (a) Sprinklers required to ensure the operability of redundant safe shutdown equipment.

Technical Requirements Manual Rev. 15 Page 70 of 88 15.7.7 HALON SYSTEM NORMAL TNC 15.7.7 The Halon Systems located in the following locations, shall be CONDITION operable:

a. Cable spreading room total flood system, and associated vertical cable chase IC, and

b. 4160 volt switchgear room 27 foot and 45 foot elevation.

The Halon System storage tanks must have at least 95% of full charge weight (or level) and 90% of full charge pressure. APPLICABILITY Whenever equipment protected by the Halon System is required to be operable. CONTINGENCY MEASURES Nonconformance Contingency Measures Restoration Time A. Both primary and A.I Establish an hourly fire watch with 1 hour backup Halon Systems backup fire suppression equipment. protecting the area are inoperable. A.2 Restore system to operable status. 14 days B. Contingency measure B.I See Section 15.0.3. A.2 and associated restoration time is not met. VERIFICATION REQUIREMENTS TVR Verification Frequency 15.7.7.1 Verify each manual, power-operated, and 31 days automatic valve in the flow path is in its correct position. 15.7.7.2 Verify halon storage tank weight (level) is 6 months

                >_95% of full charge weight.

15.7.7.3 Verify halon storage tank pressure is 6 months

                 Ž!90% of full charge pressure.

15.7.7.4 Verify by visual inspection the nozzle(s) 12 months and visible flow paths are clear of obstructions.

Technical Requirements Manual Rev. 15 Page 71 of 88 15.7.7 HALON SYSTEM - Continued VERIFICATION REQUIREMENTS - Continued TVR Verification Frequency I 15.7.7.5 Verify the system actuates manually and 18 months automatically upon receipt of a simulated actuation signal. This includes associated ventilation dampers and fire door release mechanisms. Perform a system flow test on the Halon Within 72 hours following completion of System. major maintenance or modifications The test will require flow through the headers and nozzles to assure no blockage.

Technical Requirements Manual Rev. 15 Page 72 of 88 15.7.8 FIRE HOSE STATIONS NORMAL TNC 15.7.8 The required fire hose stations identified in Tables 15.7.8-1 and CONDITION 15.7.8-2 shall be operable. Shutting fire hose station containment isolation valves for the purpose of performing an ILRT does not make the fire hose station inoperable. Shutting fire hose system isolation valve(s), listed per Table 15.7.8-3, for the purpose of performing surveillance testing (e.g., TVR 15.7.5.10) does not make the fire hose station inoperable provided an operator is dedicated to immediately open the valve and return it to its normal position (e.g., locked open) and is in direct communication with the Control Room. APPLICABILITY Whenever equipment in the areas protected by the fire hose stations is required to be operable. CONTINGENCY MEASURES Nonconformance Contingency Measures Restoration Time A. One or more required A. I Route a fire hose from any operable I hour fire hose stations plant fire hose station or fire hydrant to inoperable, the unprotected area(s) with the inoperable fire hose station. AND A.2 Restore fire hose stations to operable 14 days status. B. Contingency measure B.1 See Section 15.0.3. A.2 and associated restoration time are not met. VERIFICATION REQUIREMENTS TVR Verification Frequency 15.7.8.1 Verify by visual inspection that the 31 days required equipment is at each fire hose station located outside Containment. 15.7.8.2 Verify by visual inspection that the During each scheduled reactor shutdown, required equipment is at each fire hose but not required more frequently than station located inside Containment. every 31 days 15.7.8.3 Deleted. 15.7.8.4 Deleted.

Technical Requirements Manual Rev. 15 Page 73 of 88 15.7.8 FIRE HOSE STATIONS - Continued VERIFICATION REQUIREMENTS - Continued TVR Verification Frequency 15.7.8.5 Verify valve operability and no flow 24 months blockage for hose station valves inside Containment by partially opening each hose station valve. 15.7.8.6 Deleted. 15.7.8.7 Verify valve operability and no flow 36 months blockage for hose station valves outside Containment by partially opening each hose station valve. 15.7.8.8 Deleted.

Technical Requirements Manual Rev. 15 Page 74 of 88 TABLE 15.7.8-1 FIRE HOSE STATIONS -- UNIT 1 NUMBER OF LOCATION ELEVATION HOSE STATIONS I. Containment 10' 2 45' 2 69' 2

2. Auxiliary Building -15'(a) I (b)

_10,(a) (b) 2 5, 6 27' 3 45' 5 691(a) 4

3. Turbine Building, Heater Bay Outside Service Water Pump Rooms and Auxiliary Feedwater Pump Rooms 12' 3 Outside Switchgear Room 27' 2 Outside Switchgear Room 45' 3

4. Intake Structure 1O,(a) 1

5. Diesel Generator Building 35' 45' 1~

66' 80' (a) Fire Hose Stations required for primary protection to ensure the operability of safety-related equipment. (b) Hose Stations that serve both Units 1 and 2.

Technical Requirements Manual Rev. 15 Page 75 of 88 TABLE 15.7.8-2 FIRE HOSE STATIONS -- UNIT 2 NUMBER OF LOCATION ELEVATION HOSE STATIONS

1. Containment 10' 2 45' 2 69' 2

2. Auxiliary building _15,(a) 1 (b)

                                                                    - 10'(8)                       (b) 2 5,                      3 27'                       2 45'                       4 69'(a)                     3

3. Turbine Building, Heater Bay Outside Service Water Pump Rooms and Auxiliary Feedwater Pump Rooms 12' 2 Outside Switchgear Room 27' 1 Outside Switchgear Room 45' 2

4. Intake Structure I01(a) I (a) Fire Hose Stations required for primary protection to ensure the operability of safety-related equipment.

(b) Hose Stations that serve both Units I and 2.

Technical Requirements Manual Rev. 15 Page 76 of 88 TABLE 15.7.8-3 FIRE HOSE STATION ISOLATION VALVES -- UNIT 1 AND UNIT 2 AUX BUILDING VALVE HOSE STATION 0-FP-419 69-6 0-FP-420 45-28 0-FP-421 45-29 0-FP-422 45-30 0-FP-423 45-21 0-FP-450 27-15 0-FP-496 5-20 0-FP-497 5-21 0-FP-521 2 0-FP-653 69-6 & 69-9 IA DG BUILDING VALVE HOSE STATION 0-FP-835 DG-IA-1 DG-1A-2 DG-1A-3 DG-IA-4

Technical Requirements Manual Rev. 15 Page 77 of 88 15.7.9 YARD FIRE HYDRANTS AND HYDRANT HOSE HOUSES NORMAL TNC 15.7.9 The following yard fire hydrants and associated hydrant hose CONDITION houses shall be operable.

a. No. 6 yard hydrant and associated hydrant hose house, which provides primary protection for Unit 2 RWT blockhouse, and

b. No. 7 yard hydrant and associated hydrant hose house, which provides primary protection for Unit I RWT blockhouse.

APPLICABILITY Whenever equipment in the areas protected by the yard fire hydrants is required to be operable. CONTINGENCY MEASURES Nonconformance Contingency Measures Restoration Time A. One or more yard fire A. I Have sufficient additional lengths of 1 hour hydrants or associated 2.5 inch diameter hose located in an hydrant hose houses adjacent operable hydrant hose house to inoperable, provide service to the unprotected area(s) if the inoperable fire hydrant or associated hydrant hose house is the primary means of fire suppression. AND A.2 Restore yard fire hydrant(s) or hydrant 14 days hose house(s) to operable status. B. Contingency Measure B. I See Section 15.0.3. A.2 and associated restoration time are not met. VERIFICATION REQUIREMENTS TVR Verification Frequency 15.7.9.1 Verify by visual inspection of the hydrant 31 days hose house that the required equipment is at hydrant hose house. 15.7.9.2 Verify that the hydrant barrel is dry and 6 months that the hydrant is not damaged. The verification is required to be performed every 6 months (once during March, April, or May; and once during September, October, or November) by visually inspecting each yard fire hydrant.

Technical Requirements Manual Rev. 15 Page 78 of 88 15.7.9 YARD FIRE HYDRANTS AND HYDRANT HOSE HOUSES - Continued VERIFICATION REQUIREMENTS - Continued TVR Verification Frequency 15.7.9.3 Perform a hose hydrostatic test at a 12 months pressure at least 50 psig above the maximum pressure available at any yard fire hydrant. 15.7.9.4 Perform an inspection of gaskets. 12 months This requires the replacement of any degraded gaskets in the couplings. 15.7.9.5 Perform a flow check of each hydrant. 12 months

Technical Requirements Manual Rev. 15 Page 79 of 88 15.7.10 FIRE BARRIER PENETRATIONS NORMAL TNC 15.7.10 Fire barrier penetrations (i.e., cable penetration barriers, fire CONDITION doors, and fire dampers), in the fire zone boundaries, protecting safe shutdown areas, shall be operable. APPLICABILITY At all times. CONTINGENCY MEASURES Nonconformance Contingency Measures Restoration Time A. One or more fire barrier A. I Establish a continuous fire watch on at 1 hour penetrations inoperable, least one side of the affected penetration. OR A. 1.2.1 Verify operability of fire detectors 1 hour on at least one side of the inoperable fire barrier. AND A.1.2.2 Establish an hourly fire watch 1 hour patrol. OR A.1.3 Verify operability of automatic I hour sprinkler systems on both sides of the inoperable fire barrier (including the water flow alarm and supervisory system). AND A.2 Restore penetration fire barrier(s) to 7 days operable status. B. Contingency measure B. I See Section 15.0.3. A.2 and associated restoration time are not met.

Technical Requirements Manual Rev. 15 Page 80 of 88 15.7.10 FIRE BARRIER PENETRATIONS - Continued VERIFICATION REQUIREMENTS TVR Verification Frequency 15.7.10.1 Perform a visual inspection of fire barrier 18 months penetrations. AND Prior to returning a fire barrier penetration to functional status following repairs or maintenance

Technical Requirements Manual Rev. 15 Page 81 of 88 15.8 NOT USED

Technical Requirements Manual Rev. 15 Page 82 of 88 15.9 REFUELING OPERATIONS 15.9.1 DECAY TIME NORMAL TNC 15.9.1 Reactor shall be subcritical for at least 100 hours. CONDITION APPLICABILITY During movement of irradiated fuel in the reactor vessel. CONTINGENCY MEASURES Nonconformance Contingency Measures Restoration Time A. Reactor subcritical A. I Suspend operations involving Immediately

       < 100 hours.                       movement of irradiated fuel in the reactor vessel.

VERIFICATION REQUIREMENTS TVR Verification Frequency 15.9.1.1 Verify reactor has been subcritical for at Prior to movement of irradiated fuel in the least 100 hours. reactor vessel This verification shall consist of verifying the date and time of the subcriticality prior to movement of irradiated fuel in the reactor vessel.

Technical Requirements Manual Rev. 15 Page 83 of 88 15.9.2 COMMUNICATIONS NORMAL TNC 15.9.2 Direct communications shall be maintained between the Control CONDITION Room and personnel at the refueling station. APPLICABILITY During the movement of irradiated fuel in Containment CONTINGENCY MEASURES Nonconformance Contingency Measures Restoration Time A. Direct communications A.1 Suspend the movement of irradiated Immediately between the Control fuel in Containment. Room and personnel at the refueling station cannot be maintained. VERIFICATION REQUIREMENTS TVR I Verification Frequency 115.9.2.1 Demonstrate direct communications Within 1 hour prior to movement of between the Control Room and personnel irradiated fuel in Containment at the refueling station. AND Once per 12 hours thereafter

Technical Requirements Manual Rev. 15 Page 84 of 88 15.9.3 REFUELING MACHINE NORMAL TNC 15.9.3 The refueling machine shall be operable. CONDITION a. The main hoist shall be used for the movement of fuel assemblies and shall be operable with:

1. A minimum capacity of at least 1610 pounds with the refueling pool dry and at least 1437 pounds with the refueling pool flooded.

2. An overload cutoff limits of* 3500 pounds.

b. Auxiliary hoists shall be used for the movement of CEAs that are being removed from or inserted into fuel assemblies in the core and shall be operable with:

1. A minimum capacity of 1000 pounds, and

2. A load indicator that shall be used to prevent lifting loads in excess of 1000 pounds.

APPLICABILITY During movement of CEAs or fuel assemblies within the reactor pressure vessel. CONTINGENCY MEASURES Nonconformance Contingency Measures Restoration Time A. Refueling machine main A.1 Suspend movement of fuel assemblies Immediately hoist inoperable, within the reactor pressure vessel. B. All refueling machine B.I Suspend movement of CEAs within the Immediately auxiliary hoists reactor pressure vessel. inoperable. I VERIFICATION REQUIREMENTS TVR Verification Frequency 15.9.3.1 Perform a load test on the refueling Within 72 hours prior to the initial start of machine main hoist. movement of fuel assemblies within the reactor pressure vessel for a refueling operation which consists of either a fuel offload and onload OR a fuel shuffle. A load test of at least 1610 pounds with the refueling pool dry or at least 1437 pounds with the refueling pool flooded will be performed. The load cutoff must also be tested by demonstrating an automatic load cut off when the crane load exceeds < 3500 pounds. 15.9.3.2 Perform a load test on all the refueling Within 72 hours prior to the initial start of machine auxiliary hoists and associated movement of CEAs within the reactor load indicators to be used. pressure vessel for a refueling operation which consists of either a fuel offload and onload OR a fuel shuffle. The load test requires a load of at least 1000 pounds.

Technical Requirements Manual Rev. 15 Page 85 of 88 15.9.4 CRANE TRAVEL - SPENT FUEL POOL NORMAL TNC 15.9.4 Loads in excess of 1,600 pounds shall be prohibited from travel CONDITION over fuel assemblies in the SFP. This TNC does not apply to loads handled by the single-failure-proof Spent Fuel Cask Handling Crane. APPLICABILITY Whenever fuel assemblies are stored in the SFP. CONTINGENCY MEASURES Nonconformance Contingency Measures Restoration Time A. Loads in excess of A.1 Place the crane load in a safe condition. Immediately 1,600 pounds over the fuel assemblies in the SFP. VERIFICATION REQUIREMENTS TVR Verification Frequency 15.9.4.1 Verify the weight of each load over fuel Prior to movement over the fuel assemblies in the SFP is < 1,600 pounds. assemblies in the SFP This is not required to be performed when moving fuel assemblies and CEAs over fuel assemblies in the SFP. This is not required to be performed if the single-failure-proof Spent Fuel Cask Handling Crane is used. 15.9.4.2 Visually inspect slings and special lifting 7 days prior to use of the Spent Fuel Cask devices and verify they are operable. This Handling Crane is only required to be performed during AND Spent Fuel Cask Handling Crane operation over the SFP. every 7 days thereafter 15.9.4.3 In addition to the requirements of Per plant procedures TVR 15.9.4.2, pre-operational and periodic tests and preventive maintenance shall be performed.

Technical Requirements Manual Rev. 15 Page 86 of 88 15.10 NOT USED

Technical Requirements Manual Rev. 15 Page 87 of 88 15.11 RADIOACTIVE EFFLUENTS 15.11.1 EXPLOSIVE GAS MIXTURE NORMAL TNC 15.11.1 The concentration of oxygen in the Waste Gas Holdup System CONDITION shall be limited to less than or equal to 4% by volume. APPLICABILITY At all times. CONTINGENCY MEASURES Nonconformance Contingency Measures Restoration Time A. The concentration of A. I Suspend all additions of waste gases to Immediately oxygen in a waste gas the waste gas decay tank. decay tank is greater AND than 4% by volume. A.2 Reduce the concentration of oxygen in Immediately the waste gas decay tank holdup system to within limits. VERIFICATION REQUIREMENTS TVR Verification Frequency 15.11.1.1 Collect and analyze a sample from the Following waste gas decay tank isolation waste gas decay tanks to determine if the AND concentration of oxygen is _ 4% by volume. 7 days This frequency is only required for the inservice tank. 15.11.1.2 Collect and analyze a sample from the 7 days waste gas surge tank. AND 24 hours during power escalation from Mode 6 through Mode 3

Technical Requirements Manual Rev. 15 Page 88 of 88 15.11.2 GAS STORAGE TANKS NORMAL TNC 15.11.2 The quantity of radioactivity contained in each gas storage tank CONDITION shall be limited to less than or equal to 58,500 curies noble gasses (considered as Xe-133). APPLICABILITY At all times. CONTINGENCY MEASURES Nonconformance Contingency Measures Restoration Time A. The quantity of A. I Suspend all additions of radioactive Immediately radioactive material in a material to affected tank. gas storage tank greater AND than 58,500 curies noble gas. A.2 Reduce the quantity of radioactive 48 hours material in the affected tank to within the limits. VERIFICATION REQUIREMENTS TVR Verification Frequency 15.11.2.1 Determine quantity of radioactive material 24 hours in the in-service gas storage tank is within limits. This is not required if the RCS specific activity of Xe-133 is less than or equal to 150 tCi/ml.

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vosY1P--. i~sc4etja~ l ouet Name Project Class Modified 0. Modified By Approval BGE Fuel Degradation EALs Calculation Worksheet JSB Associates February 18 A,B,C 1/4/2011 1:50 PM *Jones, 1993 Michele Letter dated March 6 1997 from Charles H Cruise to USNRC Revision to EALs A,B,C 1/4/2011 1:53 PM *Jones, Technical Basis Document Michele Letter LB Russell (BGE) to James H Joyner EAL Review Meeting June 6 1991 A,B,C 1/4/2011 1:53 PM *Jones, Michele Radioactivity Release Emergency Action Levels September 1990 JSB Associates A,B,C 1/4/2011 1:53 PM *Jones, Michele http://moss.constellation.comlcgg/home/ero/ccnpp/99-01 %2ORev%205%20EALL%2OUpgrade/Project%20D... 2/22/2011

ATTACHMENT (3) EAL COMPARISON MATRIX Calvert Cliffs Nuclear Power Plant, LLC February 1, 2011

BALTMORE.

 *GAS AND.I ELCTIC.

MEMORANDUM Chemistry Section February 24, 1993 TO: E.H. Roach FROM: R.L Conatser

SUBJECT:

FUELDEGRADATION EAL The attached document calculates the fuel degradation EAL corresponding to 5% failed fuel. Page 6 of this report contains the dose rates at one foot for the shielded sample bomb. Please note that these values have changed from the values we discussed previously, because some of the assumptions In the calculation have changed. If you have any questions, please contact me by calling extension 2086. Attachments: Calculation Worksheet For BG&E Fuel Degradation EAL RLC:rlc c: J.M. Bills. Chemistry File: RLC194 EU W Recvd4L&4Z3- - ( roaowup PUZ 4O.- 14

JSB ASSOCIATES Page 1 of. 7 CALCULAT1ON WORKSHEET Project: BG&E Fuel Degradation EAL

Purpose:

Determine the.RCS sample dose rate to use as an Emergency Action Level representative of "significant fuel degradation." Inputs: ALERT EALs from NUREG-0654, Rev. 1: 1.b. Very high coolant activity sample (e.g., 300 pCi/cc equivalent of 1-131) 1.c. Failed fuel monitor (PWR) indicates increase greater than 1% fuel failures within 30 minutes or 5%.total fuel failures. Fuel Clad Barrier Example EAL 2. Primary Coolant Activity Level, from Basic Information for Table 4 of NUMARC/NESP-007 indicates that 300 pCi/cc I-131 equivalent corresponds to about 5% to 10% fuel clad damage. 'This amount of clad damage indicates ... the Fuel Clad Barrier is considered lost." Sample container geometry from BG&E Calc. 200-DA-9201, page 16: 8 in. long, of 3/8 in. iron tube, containing 12.5 ml of coolant, shielded by 1/2 in., Pb cylindrical shield. DCFs for: 1-131 1-132 1-133 1-134 1-135 are: 1.48E6 5.35E4 4E5 2.5E4 1.24E5 in Rem per Curie inhaled. (From TID 14844) Assumptions:

1. The source term is based on a 24 month fuel cycle as contained In BG&E calculation 200-DA-9201 for the core inventory.

2. The gas gap inventory as a fraction of the core Inventory is taken from CE Core Damage Assessment guidance and ANSI/ANS-5.4-1982, both of which provide similar values.

BG&EEAL.RPT 02/18M*

JSB ASSOCIATES Page 2 of 7 CALCULATION WORKSHEET

3. The concentrations used assume a gas gap release diluted into the RCS volume, without additional dilution by safety Injection. Concentrations and therefore'dose rates will be reduced by additional dilution. RCS Vol. = 2.7 E08 ml

4. Assume 1 hour elapses between fuel damage and ACS sampling.

Approach: A. Compute the source term resulting from a 5% gap release Into the RCS volume, both pressurized and degassed. B. Compute the dose rate per ml of sample at 30 cm (1 ft.) for the source terms developed in A. above. Assume both the normal sample container and th& Pb shielded sample container. C. Present results in simple to use format. Analyses: A. Source Term The source term applicable for determining fuel clad failure is a gap release. That is, the fission products which have migrated from the fuel matrix Into the fuel/clad gap will be released first, and these should be used as the appropriate source term. A fuel gap source term does not appear to be available from BG&E. NUREG-1465, Accident Source Terms for Ught-Water Nuclear Power Plants, Draft Report for Comment, states the assumption that 5% of the core Inventory of iodine fission products are available in the gap. This assumption may be conservative as a source term for calculation of off-site dose Impacts of potential accidents, but it Is non -conservative for the calculation of estimated fuel damage as a function of RCS sample dose rate. The bases for the: previous statement follow. Shorter-lived 1-132,1-134, and 1-135 have much higher gamma emissions energies and intensities than the longer-lived 1-131 and 1-133. Therefore they contribute significantly more to sample dose rate per unit concentration, but signifibantly less to off-site dose rate, since off-site dose conversion factors are based on the BG&E-EALRPT 02/18/93

JSB ASSOCIATES Page 3 of 7 CALCULATION WORKSHEET Inhaled thyroid dose which Is also a function of hafl-life. The fuel/clad gap concentration of. radioiodines is also a function of half-life. This is clearly shown In the equations in ANSI/ANS-5.4-1982, Method for Calculating the Fractional Release of Volatile Fission Products from Oxide Fuel. Logically, the time required for a fission product to migrate from the fuel matrix to the gap will cause longer-lived fission products to exist in the gap in higher concentrations than shorter-lived isotopes of the same element. It follows that assuming a constant 5% of core Inventory In the gap for all iodine fission products significantly over-estimates the shorter lived 1-132, 1-134, and 1-135 compared to the longer-lived 1-131 and 1-133. This would cause one to calculate

     .a much higher sample dose rate for a given level of fuel clad damage than should actually be expected. Subsequently, using measured dose'rates and comparing them to the higher calculated dose rate to estimate the amount of fuel clad damage could lead to under-estimating the fuel damage. (Note that this is but one of several indicators of fuel clad damage. It is not likely that the best assessment of the amount of damage will be based on an RCS sample dose rate measurement.)

Estimates of the fraction of core Inventory available in the gap may be obtained from the CE Owners Group Core Damage Assessment guidance. Also, a distribution of the Iodine isotopes in the fuel/clad gap may -be obtained using Equation 5 of ANSI/ANS-5.4-1982 to calculate the fractional release F., Note that the fractional release F computed using the equations in ANSI/ANS-5.4-1982 are functions of burnup and temperature and half-life of the isotope being considered. Neither the burnup nor the temperature can be known before the fact, but they do not vary for analysis of the relative iodine fission products distribution. Burnup over a range of 0,000.to 60,000 MWd/t were computed for a temperatures of 1°K 11350 K = 15830 F and 1265" K = 18170 F. These temperatures were selected to obtain agreement between the CE Owners Group core damage assessment values and the results calculated using ANS-5.4-1982. The C-E Owners Group core damage assessment guidance does not include either cesiums or a particulate contribution, for the gap release. BG&E-EAL.RPT 02/18/93 0/89

JSB ASSOCIATES Page 4 of 7 CALCULATION WORKSHEET Core inventory from BG&E calculation 200Q-DA-9201: CCNPP CE Damage ANS-5.4-'82 Gap Core Assessment Computed Fraction Nuclid- Half-liffe Inventory(Ci) Gag Fraction Gap Fraction Assumed Kr-85m 4.48 h 1.97E7 0.005 0.005 Kr-87 76.3 m 3.87E7 2E-7 0,003 0.003 Kr-88 2.84 h 5.54E7 0.004 0.004 Xe-133 5.245 d 1139E8 9.3E-2 0.03 0.09 Xe-135 9.09 h 2.81 E7 0.01 0.01 1-131 8.04 d 6.90E7 9.2E-2

• 0.093 0.09 1-132 2.3 h 9.78E7 7E-5 0.0103 0.01 1-133 20.8 h 1.39E8 4.5E-2 0.031 0.04 1-134 52.6 m 1.55E8 0.006 0.006 1-135 6.8,h 1.22E8 7.9E-3 0.018 0.02 The CE Computed Gap Fractions are from CE Owners Group Core Damage Assessment guidance, by dividing Table 3-5 data by Table 3-4 data for a 2700 MWT Plant Class.

See Appendix A for computation of ANSI/ANS-5.4-1982 Gap Fractions. CCNPP Core Inventory

• Release Fraction = Estimated Gap Activity Estimated Gap Activity
• 5% release
• 10/JCi/Ci /2.7E8 ml = Sample Conc.

BG&E-EALRPT 0/89 02/18/93

                                       *JSB ASSOCIATES                           Page 5 of 7 CALCULATION WORKSHEET Assumed            5% Gap Release        Dose Core              Release            RCS Conc.(pCi/cc)     Equivalent Isotoge            Inventory(Ci)     Fraction          :(I hour decay4 Kr-85m             1.97E7            0.005              I .6E+01 Kr-87               3.87E7            0.003              1.2E+01 Kr-88'              5.54E7            0.004             3.2E+01 Xe-1 33             IM3ES             0.09              2.3E+03 Xe-135              2.81 E7           0.01              4.8E+01 1-131.             6.90E7            0.09               1.1 E+03              1.1E+03 1-132              9.78E7            0.01               1.3E+02               4.8E+00 1-133              1.39E8            0.04              .1.0E+03.              2.7E+02 1-134              1.55E8            0.006             7.8E+01                1.3E+00 1-135               1.22E8            0.02              4.1 E+02               3.4E+01 Total =                1.5E+03 Note that this calculated source term Is a factor of 5 hi-aher than the 300 uCi/ml dose equivalent 1-131 guidance from the NRC. The primary reason for this difference is the higher fraction of 1-131 assumed in the gap.

For comparison, a 5% gap release assuming a constant 5% of the core inventory of iodines is available in the gap results in the following Iodine concentrations (pCi/cc) after 1 hour: 1-131 1-132 1-133 1-134 1-135 640 670 1200 650 1000 This equals 1100 pCi/cc dose equivalent 1-131. B. Dose Rate at 1 foot from 12.5 ml sample The dose rate at I foot from the center of the 12.5 ml sample bomb was calculated for the radioiodines and the noble gases, each separately. Data for the sample bomb was obtained from BG&E Calculation 200-DA-9201 Rev. A, Case B4X.04, after correcting for the sample bomb wall thickness. The following dimensions for the Reactor Coolant sample bomb were used: BG&E EAL.RPT 02/18/93

JSB ASSOCIATES Page 6 of 7 CALCULATION WORKSHEET Length = 20.32 cm Shield = 1.27 cm Pb, 11.3 g/cc Source radius = 0.443 cm H2 0, 1 g/cc Source volume = 12.528 cm 3 Tube wall = 0.234 cm Fe, 7.84 g/cc PC-SHIELD was used to calculate the dose rate at 1 foot fromý the sample bomb. The output of the PC-SHIELD calculations are contained in Appendix B. The results are: Shielded Sample Bomb 42 mrem/hr at 1 ft. due to radiolodines (Depressurized sample in shielded sample. bomb) .2.2 mrem/hr at 1 ft. due to noble gases in pressurized sample 44 mrem/hr at 1 ft. for pressurized sample in shielded sample bomb Normal Samole Bomb . 160 mrem/hr at 1 ft. due to radioiodines (Depressurized, unshielded sample bomb) 8.2 mrem/hr at I ft. due.to noble gases in pressurized sample 168 mrem/hr at 1 ft. for pressurized sample in unshielded sample bomb The calculated dose rates are a direct multiple of the assumed level of cladding failure. Thus, if an EAL equivalent to 2% clad failure rather than 5% clad failure is desired, the above results may be multiplied by 2/5. C. Present Results in simple to use format A 12.5 ml RCS sample in the shielded sample bomb with. a dose rate greater than 40 mrem per hour at 1 foot is an indication of significant fuel damage, that is, a release on the order of 5% of the gap activity.. Whether the. sample is pressurized or not makes little difference, as the largest contribution to the dose rate after 1 hour decay is from the radioiodines expected following a gap release. Similarly, a dose rate of 160 mrem/hour at 1 foot from an unshielded RCS sample bomb indicates. a gap release on the order of 5%. Again, noble: gases contribute relatively little to the total dose rate in these circumstances, so whether the sample is pressurized or not makes little difference. BG&E-EAL.RPT 02VI1/93 0/89

JSB ASSOCIATES Page 7 of 7 CALCULATION WORKSHEET References Development of the Comprehensive Procedure Guideline for Core Damage Assessment, C-E Owners Group Task 467, May 1983 from BG&E CCNPP Chemistry Department files. ANSI/ANS-5.4-1982, American National Standard Method for Calculating the Fractional Release of Volatile Fission Products from Oxide Fuel, Approved November 10, 1982. NUREG-1228, Source Term Estimation During Incident Response to Severe Nuclear Power Plant Accidents, October 1988. NUMARC/NESP-007, Methodology for Development of Emergency Action Levels, April 1990. TID 14844, Calculation of Distance Factors for Power and Test Reactor Sites, AEC, March 1962. NUREG-0654, Rev. 1, Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants, USNRC/FEMA, November 1980. NUREG-1465, Accident Source Terms for Ught-Water Nuclear Power Plants, Draft Report for Comment, USNRC, June 1992.

• BG&E Calculation 200-DA-9201, Re-evaluation of Radiation Doses from Post-Accident Sampling, October 1992.

BG&EEAL.RPT 02/18/93

APPENDIX A SOURCE TERM CALCULATIONS

Dose t Hi Temp 5% Gap Release Dose Equivalent Lambda Inventory Conversion Release RCS Conc. 1-131 Isotope Half-Life (1/sec) (Ci) Factor Fraction (1 hr. decayed) Kr-85m 4.48h 4.30E-05 1.97E+07 0.005 1IE+01 Kr-87 76-3mi 1.512-04 3.87E+07 0.003 1.2E+01 Kr-88 7-94h 6.78E-05 5.54E+01 0.004 3.22+01 Xe-133 5.245d 1.53E-06 1.39E+08 0.09 2.3E+03 Xe-135 9.09h 2.12E-05 2.81E+07 0.01 4.8R+01 1-131 &04d 9.981-07 6.90E+07 1.48E+06 0.09 1.11+03 1.11+03 1-132 2-3h &37E-05 9.78E+07. 5.35E+04 0.01 1.31+02 4.8E+00 1-133 20.8h 9.25E-06 1.39E+08" 4.00E+05 0.04 LOE+03 217E+02 1-134 52.6m 2.20E-04 1.55E+08 2.50E+04 0.006 7.8E+01 1.3E+00 1-135 6.8h 2.83E-05 1.22E+08 1.24E+05 0.02 4.1E+02 3.411+01 1.5E+03

 % Gap Release =    5 Kr-85m     4.48h       4.302-05   1.97E+07                   0.05 1.6E+02 Kr-87      76.3m        1.51E-04  3.87E+07                   0.05 2.11+02 Kr-88      2-94h       .6.78E-05  5.54E+07                   0.05 4.0E+02 Xe-133     5.245d       1-53E-06  1.39E+08'                  0.05 13E+03 Xe-135     9.0911      2.1211-05. 2.81E+07                   0.05 2.4E+02 1-131      &04d        9.98E-07   6.90E+07   1.48E+06        0.05 6.4E+02         6.4E+02 1-132      2-3h        837E-05    9.78E+07   5.35E+04        0.05 6.7E+02,        2.4E+01 1-133      20.8h       9.2511-06  1.39E+08   4.00E+05        0.05 1.21+03         3.41+02 1-134      52.6m       2.20E-04   1.55E+08   2.50E+04        0.05 6.5E+02         1.11+01 1-135      6.8h        7-83E-05   1.22E+08   1.24E+05        0.05 1.0E+03         8.5E+01 1.11+03 4jaz.kJ4        4-ITmi~          4

PROBLEM: Develop estimates of the gap radioiodine activities available for release following fuel cladding failure; APPROACH: Fractional (gap)radioiodine releases from the fuel to the gap are determined using the equilibrium equation (equation

5) from ANSI/ANS-5.4-1982, which is attached for reference.

From the referenced standard; "For these conditions (varying temperature and power operations) the release fraction may be conservatively calculated using the equilibrium equation (Equation 5) using the peak temperature reached durina the last two halflives of operation." The temperatures used were selected to obtain results close to those presented in the C-E Owners Group core damage assessment guidance. These temperatures are consistent with those which would be expected for cladding failure, as indicated in NUREG-1228, Table 4.1. CALCULATIONS: (Using MathCad) Bu = 20000 ,30000.. 60000 T ' 1265 Kelvin equivalent of 1817 F. D(Bu,T) = .61*exp[ -[ (1.987T) ]J100(280001. See ANS-5.4 for explanation of terms. The factor of 7 at the end of the equation comes from section 4.1 HighTemperature Release Calculations of the standard. For 1-131 1 9.98 10-7 Decay constant in 1/seconds. D (Bu , T) D (Bu ,T) 3.689 101 3DI D 1.911 10'1 2.705 104 F[rn]: 3 1~ coth1 V/MI- M 1 9.897 l10( 5.223 10S 5.126 .0-9 1.008 10 194.68 F(1008) 0.093 2.655 10-81 37.588 Evaluated at 40K MWd/t

For 1-132: I :- 8.37 10-' Decay constant in 1/seconds. rrID1 2.269 10' 4.38 109 8.457 104 F[ S. 457" 10' ]) 0.0103 Evaluated at 4OK MWd/t 1.633 10 3.152 103 For 1-133: I

• 9.25 10-6 Decay constant in I/seconds.

2.507 i0' 4.841 104 9.346 103 F(9346) = 0.031 Evaluated at 40K MWd/t

1. 804 10

  -348.381 For 1-134:         :. 2.20  10'4          Decay constant in 1/seconds.

5.963 106 1.151 106 F[2.223-10'] = 0.006 Evaluated at 40K MWd/t 2.223 10' 4.292 10 8.286 10" For I-'135: I := 2.83 10-' Decay constant in 1/seconds. 7.671 10! 1.481 - 10! 2.859.104 F[ 2.859' 101 = .0.018Evaluated at 40K MWd/t 5.521 102 1.066-102 Summary of Results at 1265K, 40K MWd/t: Iodine isotope 1131 1132 1133 1134 1135 Release fraction 0.093 0.0103 0.031 0.006 0.018 C-B Guidance 0.092 0.007 0.045 0.0079

T -- 1135 For 1-131 9.98 io1"7 Decay constant in 1/seconds. {., T) (B I

1. 368 10"1 D (DBu.,

T) 7.086 10"1 mI*D 3.67 101j 7.295 10 1.901 10o" 1.408- 10 1(1014) 0.093 9.846 10"¶ 2.719 ' 10 5.25 10 Evaluated at 60K MWd/t 1.014- 101 For 1-132: ] 8.37-10"s Decay constant in i/seconds. 1 J' D 1 6.118 *107 1.181 10, F[8. 501 104i 0.0103 Evaluated at 60K MWd/t 2.28 - 10' 4.403 10' 8.501' 10i For 1-133: I 9.25"10-6 Dec;ay constant in I/seconds. mD 6.761 106 1.305. 1 0E F(9394) = 0.031 E 'aluated at 60K MWd/t 2.52.106 4.866 10 19.394 - 10. For 1-134: ] :- 2.20 103"4 De :ay constant in 1/seconds. 1.608 10 3.105 10' F[ 2.234 10'] = 0.006 Evaluated at 60K MWd/t 5.994 109

1. 157 ICý 2.234 10'

For I-'135: I = .2.83 16-' Decay constant in I/seconds. 2.069 10 3.994-101 F[ 2.874 10'] = 0.018 Evaluated at 60K MWd/t 7.711 101 11.489 10 2.874 101 Summary of Results at 1135 K, 60K MWd/t: Iodine Isotope 1131 1132 1133 1134 1135 Release Fraction 0.093 0.0103 0.031 0.006 0.018

== Conclusion:==

As is evident from both the C-E Owners Group core damage assessment guidance and the above calculations using the methods of ASNI/ANS-5.4-1982, the distribution of the release fractions of the radioiodines to the gap is not constant.

PROBLEM: Develop estimates of the gap noble gases activities available for release following fuel cladding failure. APPROACH: Fractional (Gap) noble gases released from the fuel to the gap are determined using equation 5 from ANSI/ANS-5.4-1982, which is attached for reference. From the referenced standard: "For those conditions (varying temperature and power operation), the release fraction may be conservatively calculated using the equilibrium equation (equation 5 in the standard), using the peak temperature reached during the last two halflives of operation." These calculations are consistent with the previous ones for iodines, and are performed to obtain release fractions for a wider range of noble gases than is provided in the C-E Owners Group guidance on core damage assessment. CALCULATIONS: (Using MathCad) Bu *= 20000 ,30000 .. 60000 T = 1135 Kelvin equivalent of 1583 F. D(Bu , 0.61aexp-0T) 72300 100 l00 00u 1(1.987 T) j See ANS-5.4 for explanation of terms For Kr-85m: I :- 4.30 10-5 Decay constant in I/seconds D (Bu T) ] 1.954 10"1 D (Bu ,T) 1.012 101' 2.2 108 5.243 101 4.248 107 2.716 101 1.407 10"1 8.201lO1 [MJ: .3. - -coth(4 ]F. 1.5583 1 0 '

3. oa57. l0 Equation 5 from ANS-5.4 F[ 3. 06"-1]0 0.005 Evaluated at 60K MWd/t

For Kr-87: I = 1. 51

• 10-4 Decay constant in 1/seconds I"1,D)1 7.726 10i F[ 3..07 -o10]= 0.003 Evaluated at 60K MWd/t 1.492 10' 2.88 10o 5.56 10, 1.074 10 For Kr-883: 3 6.78-106- D,ecay constant in 1/seconds mIID 1 3.469 10!

F[ 4.82 10'] = 0.004 Evaluated at 60K MWd/t 6.698 .10 1.293 10' 2.497 10' 4.82 10 For Xe-133: z 1.53"10'6 Decay constant in 1/seconds r1 0 11 7.828 10o 1.511 1o0 Fl 1.09 1o']- 0.029 Evaluated at 60K MWd/t 2.918 10"

,5.634 10 1.088 104 For Xe-135:      1:: 2.12 10"'               Decay constant in 1/seconds
 *[ I ,D]1 1.085     10
.2.094     10i  F[ 1.51" 10]     =  0.008         Evaluated at 60K MWd/t 4.043      10 7.806      10 1.507    10:

Summary of Results at 1135K, 60K MWd/t: Noble gas Kr-85m Kr-87 Kr-88 Xe-133 Xe-135 Release Fraction 0.005 0,003 0.004 0.03 0.008 C-E Guidance <IE-6 0.0867

T = 1265 For Kr-85m: I := 4.30 10-5. Decay constant in 1/seconds (Bu, T) [ ),D ]"- D(BU ,T) 5.27 1012 "[nD 2.73 10-11 8.159 10 1.414 10-'1 1. 575 - 10' I0s FEl3. 04a10'0 0/005 7.323 107N 3. 041

• 3.793 10-9 5.872 10 Evaluated At 40K MWd/t 1.134 - 10+ 75 For Kr-87: I 'a 1.51 10-4 Decay constant in I/seconds B] 1,0, ,

2.865 10, 5.532 .O1 10* F[ 1.07 106= 0.o003

                                                      .Evaluated at 40K MWd/t 1.068 2.062 10' 3.981 10J For Kr-88:         ]      6.78 10-'          Dec Jay constant in I/seconds ID 1.286   10 2.484   10 4.795 10 F[ 4.8 1o0         = 0.004             Evaluated at 40K MWd/t 9.258 10 11.788 101 For Xe-133:          I :X  1.53 10-6            Decay constant in    1/seconds gp 1,D 1 2.903    105 5.605 10' F[ 1.082        104] = 0.029        Evaluated at 40K MWd/t 1.082 101 2.089 103 403.37 For Xe-135:          I :a 2.12 30"-                Decay constant in I/seconds 4.023    10  '

7.766 10! 1.499 10! F1 1.499 10 ] = 0.008 Evaluated at 40K MWd/t 2.895 10& 5.589 10O

Summary of Results for 1265K at 40K MWd/t: Noble Gas Kr-85m Kr-87 Kr-88 Xe-133 Xe-135 Release Fraction 0.005 0.003 0.004 0.029 0.008

== Conclusions:==

Noble gases are not contained in the gap at a constant fraction of the core inventory. 3%, rather than 5%, is a more realistic assumption regarding the fraction of long-lived noble gases in the gap.

     .APPENDIX B DOSE RATE CALCULATIONS"

J. Stewart BLand Consultants, Inc. PC - SHIELD REPORT for BG&E EAL for RCS saple dose rate, iodine contribution Using only the photon contribution to dose Prepared on 2/17/93 Press RETURN 3.05flci01 Cm X-RadiaL distance to the dose point 1.0'. 1 Cm Y-Verticat distance from the end of the source to the dose point 2.032E+01 Cm SL-Source Length 4.430E-01 Cm SR-Source radius and first shield 1.253E+01 cc CaLculated source volume 5.OOOE+O0 NT-Number of horizontal angle intervals for numerical integratlo 1.100E+01 HP-Number of vertical angle intervals for numerical integration 5.O00E+00 DR-Length of radial intervals for nunerical Integration A total of 4 cylindricat shields are used Shield 1 thickness Is 4.430E-01 Cm Shield 2 thickness t8 2.34DE-01 Cm Shield 3 thickness is 1.270E400 Cm Shield 4 thickness is 2.855E*01 Cm (the last shield is an air shield.added by PC-SHIELD Press RETURN

2 2/17/93 J. Stewart Wtand ConsuLtants, Inc. PAGE 3 PC - SHIELD REPORT for BG&E EAL for RCS ,awpte dose rate

                             .SHIELD SPECIFICATIONS A total of 4 shields are used Shield 3 isused for catculating buitdup Density in Shield WVcc Shield Kateriat   Shield I Shield 2 Shield 3 Shield 4 H20               1.00E+O0      .OOE+0O    .OOE+00                           .-

Iron .OOE+OO 7.8*E+O0 .OOE400 Load .OOE+0o .0OE+00 1.13E+01 AIR 0.001293 Press RETURN SOURCE SPECIFICATIONS VaLues shown are in curies. The source voLume is 1.253E+01 cc. Name Amount 1 131 1.3781E-02 1 132 1.6286E-03 1 133 1.2528E-02 I 134 9.7718E-04 1 135 5.1365E-03 Press RETURN

i117/93 J. Stewart BLand ConsuLtants, Inc. PAGE 4 PC - SHIELD REPORT for-SG&E EAL for RCS sample dose rate DOSE RESULTS GROUP GROUP GROUP ENERGY FLUX DOSE RATE PRODUCTION RATE AVERAGE ENERGY AT DOSE POINT AT DOSE POINT PHOTONS/SEC NEV MEV/CN,2!SEC REM /HR 0021 .000E400 1.500E-02 .O0OE+OO .OOO0O0

          .O00E+O0         2.500E-02            .O00E+O0     .O000E00 obi      .O0OE+00         3.500E-02             .O00E+00    .OOE00 0063      .OOOE+OO         4.500E-02            .O00E+O0     .O000E00
          .O000E.0         5.500E-02            .O00E+00     .0001E00 tDiy      .000E+O0         6.500E-O0             .O00E+00    .O00E+00 006       .OO0E+O0         7.500E-02             .000E+00    .O00E+00 666' 1.326E+07          8.SOOE-02             .OOOE+O0    .O00E+00 009      .O00E+O0         9.500E-02            .0OOE+O0     .000E.00 010       .OOOE+0O         1.500E-01            .O00E+00     .O000E.0 Press RETURN GROUP          GROUP            GROUP          ENERGY FLUX      DOSE RATE PRODUCTION RATE   AVERAGE ENERGY     AT DOSE POINT AT DOSE POINT PHOTONS/SEC               XEV          KEV/CK2/SEC        REM    /HR 011     3.110.E07          2.500E-01          6.398E-02     1.612E-07 012     4.171E+08          3.500E-01           1.307E+02    3.280E-04 1.352E+03    3.2171-03
.013    4.404E+08          4.750E-01 014. 1.441E+08         6.500E-01           1.516E103    3.366E-03 015      1.706E+08         8.250E-01          3.938E+03     8.269E-03 016     4.292E+07           I.0000E+0          1.521E+03    3.011E-03 017      1.578E+08          1.225E+00         7.562E+03     1.407E-02 018    2.B47E+07           1.475E+00          1.785E+03    3.141E-03 019    4.728E+07           1.700E÷00         3.556E+03     6.046E-03 020    2.892E+06           1.900E+00         2.496E+02     4.043E-04 021       .OOE+00         2.1001E00              .O00E+00    .000E100 022        .O000E10        2.300E+00             .000E÷00     .001E+00 023        .000E100        2.500E+00              .O00E+OO    .O00E+00 024        .O000E10        2.700E+00             .000E+0      .O00E+00 025        .O000E00       3.000E÷00              .O000E÷0    .O00E+00 TOTAL     1.496E+09                            2.161E+04     4.185E-02 Press RETURN

J. Stewart Bltand Consultants, Inc. PC - SHIELD REPORT for BG&E EAL for RCS sample dose rate, noble gases contribution Using only the photon contribution to dose Prepared on 2/17/93 Press RETURN 3.050E+01 Cm X-Radial distance to the dose point 1.01 Cm Y-VerticaL distance from the end of the source to the dose point

.2.032E+01 Cm SL-Source length 4.430E-01 Cm SR-Source radius and first shield 1.253E+01 cc Calculated source volume 5.000E+O0       NT-Niumber of horizontal angle intervals for numerical integratfo 1.100E+01      NP-Number of vertical angle intervals for numericaL integration 5.000E+O0       DR-Length of radial Intervals for runericel integration A total of 4 cylindrical shields arelused Shield 1 thickness Is 4.430E-01 Cm Shield 2 thickness Is 2.340E-01 Cm Shield 3 thickness is 1.270E*00 Cm Shield 4 thickness is 2.855E+01 Cm (the Last shield is an air shield added by PC-SHIELD Press RETURN

. 2/17/93 J. Stewart Bland Cormultants, Inc. PAGE 3 PC - SHIELD REPORT for MG&E EAL for RCS sampte dose rate, noble gases contribution SHIELD SPECIFICATIONS A total of 4 shields are used Shield 3 is used for calculating buildup. Density in Shield gm/cc Shield Material Shield I Shield 2 ShieLd 3 Shield 4 f20 1.OOE+O0 .OOEO.O O O0E÷O0 Iron .OOE÷00 7.84E+O0 .OE+O0 Lead .OOE+O0 .OOE÷00 1.13E*01 AIR 0.001293 Press RETURN SOURCE SPECIFICATIONS Values shown are In curies. The source volume is 1.253E+01 cc. Name Amount KRM85 2.0045E-04 KR 87 1.5034E-04 KR 88 4.0090E-04 XE 133 2.8814E-02 XE 135 6.0134E-04 Press RETURN

                                                                                      .1..

2/17/93 J. StewartPC BLand ConsuLtants, Inc. PAGE 4

                                     -. SHIELD REPORT for BG&E EAL for RCS swple dose rate, nobte gases contribution DOSE RESULTS GROUP         GROUP            GROUP           ENERGY FLUX      DOSE RATE PRODUCTION RATE   AVERAGE ENERGY AT DOSE POINT AT DOSE POINT PHOTONS/SEC               NEV          NEV/CM2/SEC         REX   /NR 001      .000E+OO          1.500E-02           .00E2+00      .000E+0O 002                        2.500E-02           .OOE+O0        .002E+OO
          .002E+0           2.SOOE-02 003        O002E+O0        3.5002E-02          .000m+0        .000E+0 004        OOOE+0O         4.500E-02           .000E+0        .O00E+O0
                                                               .00E+00 005      .OO0E+O0          5.500E-02           .0002+O0 00o6     .000E+00          6.500E-02           .OOOE+D0      .O000E+0 007      .OOOE+O0          7.500E-02           .002E+O0       .002E+0 008     6.024E+08          8.500E-02           .0E000         .OOOE+O0 009      .000E2OO          9.500E-02           .OOOE+00       .O00E+O0 D1O     7.799E+06          1.500E-01          9.787E-12     2.476E-17 Press RETURN GROUP         GROUP            GROUP           ENERGY FLUX      DOSE RATE PRODUCTION RATE   AVERAGE ENERGY AT DOSE POINT AT DOSE POINT PHOTONS/SEC              IHEV          MEV/CH2/SEC         REM   /HR 01i     2.014E+07          2.500E-01          4.142E-02     1.044E-07 012     1.083E+06          3.500E-01          3.393E-01     8.515E-07 013     3.226E+06          4.750E-01          9.902E+00     2.357E-05 014    6.452E+05          6.500E-01          6.789E+00     1.507E-05 015     2.857E+06          8.250E-01          6.597E+01     1.385E-04 016       .O00E*O0         1.0000E+0            .O00O020      .000E+00 017       .O000E+0         1.225E+00            .O000EO0      .OOOE+O0

'018 1.988E+06 1.475E+00 1.246E÷02 2.193E-04 019 1.335E.05 1.7002E00 1.004E÷01 1.707E-05 "020 .OOOE200 1.900E200 .002E+00 .O00E+O0 021 3.402E+06 2.1OOE20 3.038E+02 4.830E-04 022 6.942E*06 2.300E+00 7.453E+02 1.140E-03 023 8.34,E÷05 2.500E+00 9.542E+01 1.431E-04 024 .002E+0 2.700E+00 .000E+00 .000E+0 025 .000E+0 3LOO0EO00 .002E+00 .002E+00 TOTAL 6.514E208 1.362E+03 2,1812-03 Press RETURN J.

J. Stewart Bland Consultants, Inc. PC - SHIELD REPORT for BG&E EAL for RCS sample dose rate, iodine contribution, unshielded A., - Using only the photon contribution to dose Prepared on 2/17/93 Priess RETURN 3 050E+01 Cm X-Radiat distance to the dose point 1.01 1 Cm Y-Vertical distance from the end of the source to the dose point 2.032E+01 Cm SL-Source length 4.430E-01 Cm SR-Source radius and first shield 1.253E+01 cc CalcuLated source volume 5.000E+00 NT-Nunmer of horizontaL angle intervals for numerical integratio S1A00E+01 NP-Number of vertical angle intervals for numerical integration Sý.000E+00 DR-Length of radial intervals for numerical integration A total of 3 cylindrical shields are used ShieLd I thickness is 4.430E-01 Cm Shield 2 thickness is 2.340E-01 Cm Shield 3 thickness is 2.982E+01 Cm. (the Last shield is an air shield added by PC-SHIELD Press RETURN

2/17/93 J. Stewart Stand Consultants, Inc. PAGE 3 PC - SHIELD REPORT for AE EAL for RCS sample dose rate, iodine contribution, unshlelded SHIELD. SPECIFICATIONS A total of 3 shietds.mre used Shield 2 is used for calculating buildup Density in Shield gm/cc Shield Material Shield I Shield 2 Shield 3 H20 1.OOE+0O .OOE+00 Iron .OOE+00 7.84E+00 AIR 0.001293 Press RETURN SOURCE SPECIFICATIONS Values shown are in curies. The source volume is 1.253E÷01 cc. Name Amount

1. 131 1.3781E-02 1 132 i.6286E-03 I 133 I .2528E-02 1 134 9.7718E-04 1 135 5.1365E-03 Press RETURN

7",. L*, *,*

* !+::

2/17./93 J. Stewart Bland Consultants, Inc. FAGE 4 PC - SHIELD REPORT for-- KG&E EAL for RCS sample dose rate, iodine contribution, unshletded DOSE RESULTS GROUP GROUP GROUP ENERGY FLUX DOSE .RATE PRODUCTION RATE AVERAGE ENERGY AT DOSE POINT AT DOSE POINT PHOTONS/SEC NEV MEV/CM2/SEC REM /NR 001 .000E+O0 1.500E-02 .000E+00 .O00E+O0 002 .OOOE+00 2.500E-02 .O00E+00 .OOOE00 603 *O00E+O0 3.500E-02 .000E+00 .O00O600 064 .O0OE+O0 4.500E-02 .O00E+O0 . 000E6O0 005 . O00E÷O0 5.500E-02 .O00E+00 .OOOE+00 66 6006 cO0e+O0 OOOE+OO 6.500E-02 .000E+00 .O00E+O0 007 O00E+0O 7.SOOE-02 .O00E00 .000E+00 6008 1.326E÷07 8.500E-02 1.937E÷01 6.10.1E-05 6009 .DOOEOO 9.500E-02 .000÷00 .000E+00 dio ,O0OE+OO I.SOOE-01 .,OOE+00 .000E+00 Press RETURN GROU- GROUP GROUP ENERGY FLUX DOSE RATE PRODUCTION RATE AVERAGE ENERGY AT DOSE POINT AT DOSE POINT PHOTONS/SEC NEV NEV/CM2/SEC REM /HR 011 3.110E+07 2.500E-01 6.033E+02 1.520E-03 012 4.171E+08 3.500E-0I i.146E+04 2.877E-02 013 4.404E+08 4.750E-01 1 .642E+04 3.90E6-02 014 1.441E+08 6.500E-01 7.327E+03 1.627E-02 015 1.706E+08 8.250E-01 1.102E+04 2.314E-02 016 4.292E+07 1.000E+00 3355E+03 6.642E-03 017 1.578E+08 1.225E+00 1.499*+04 2.7886-02 018 2.847E+07 1.475E+00 3.252E+03 5.724E-03 019 4.728E+07 ¶.?OOE+D0 6.210E603 I.056E-02 020 2.892f+06 I .900E+00 4.235E+02 6.860E-04

.021               .O00OEO0        2.1006400            .0OOE+00    .O0OE+00 022              .O00E+00        2.300E+00            .000E+00    .006E+O0
                                                                    .O00E+O 0 023              .OOOE+00        2.500E+00            .O00E+00 0006E+00 "024               .OOE+00         2.700E+00            .O00E+00    .000E+00
                                                                     .O00E6+00

-025 .O00E+00 3.000E+00 .OOOE+00 TOTAL 1.496E+09 7.508E+04 1.603E-01 Press RETURN

                      .J. Stewart Bland Consuttants, Inc.

PC - SHIELD REPORT for BG&E EAL for RCS sanple dose rate, noble gases contribution, unshleLded Using only the pioton contribution to dose Prepared on 2/17/93 Press RETURN 3.050F+01 CM X-RadiaL distance to the dose point 1.0! 1 Cm *Y-Vertical distance from the end of the source to the dose point 2.032E+01 Cm SL-Source Length 4.430E-01 Cm SR-Source radius and first shield 1.253E*01 cc CalcuLated source volume 5.000E+00 NT-Number of horizontal angle intervals for numerical integratlo 1.100E+01 NP-Niumber of vertical angLe intervals for numerical integration 5.OO0E+DO DR-Length of radial intervals for rvnerical integration A total of 3 cylindrical shields are used ShieLd I thickness is 4.430E-01 Cm ShieLd 2 thickness is 2.340E-O1 Cm Shield 3 thickness is 2.982E+01 Cm (the Last shield is an air shield added by PC-SHIELD Press RETURN

. 2/17/93 J. Stewart Bland Consultants, Inc. PAGE 3 PC - SHIELD REPORT for BG&E EAL for RCS sampte dose rate, nobLe gases contribution SHIELD SPECIFICATIONS A total of 3 shields are used Shield 2 is used for calculating buildup. Density in Shield 7/Vcc Shield Material Shield I Shield 2 ShieLd 3 1120 .OOE÷O0 Iron .OOE+OO 7.84E*00 AIR 0.001293 P R Press RETURN SOURCE SPECIFICATIONS Values shown are in curies. The source volume is 1.253E+01 cc. Maine Amounxt KRm85 2.0045E-04. KR 87 1.5034E-04 KR 88 4.0090E-04 XE 133 2.8814E-02 XE 135 6.0134E-04 Press RETURN

2/17/93 J. Stewart Btend Coresultants, Inc. PAGE 4, PC - SHIELD REPOR T for BC&E EAL for RCS ample cdose rate, noble gases contribution DOSE RESULTS GROUP GROUP GROUP ENERGY FLUX DOSE RATE PRODUCTION RATE AVERAGE ENERGY AT DOSE POINT AT DOSE POINT PHOTONS/SEC KEV MEV/CM2/SEC REM /HR 001 .000E+00 i.500E-02 .OOOE+OO .O00E+00 002. .000+00 2.500E-02

                                                 .o00E+00    .0002E+0 003       .0O0E+O0         3.500E-02          .O00E.OQ     .000E+00 004        .000E+00        4.500E.02           .000E+00    .OOE+00 005         D000E+00       5.500E-02          .000E+00     .000E+00 006        .OD0E+O0        6.500E-02          .0000+00     .OOOE+00 007         .00OE+00        7.500E-02          .000+00      .000+E00 008      6.024E+08          8.500E-02         8,600E+02    2.772E-03 009        . O00E+O0        9.500E-;02          .000E.00    .000E+00 010      7.799E+06          1.500E-01         8.890E201    2.249E-04 Press RETURN GROUP           GROUP            GROUP         ENERGY FLUX     DOSE RATE PRODUCTION RATE   AVERAGE ENERGY     AT DOSE POINT AT DOSE POINT PHOTONS/SEC               MEV         MEV/CM2/SEC        REM   /MR 01i     2.014E+07          2.500E-01         3.906E+02    9.842E-04 012       1.083E+06         3.500E-01         2.975E401    7.468E-05 013     3.226E+06          4.750E-01         1.203E+02    2.863E-04 014     6.452E+05          6.500E-01         3.280E+01    7.283E-05 015     2.857E+06          8.250E-01         1.646E+02    3.876E-04 016        .000E+00         1.000E+00           .000E+00    .000E+00 017        .000E+00         1.225E+00          .000E+00     .000.E00 1:1018      1.988E+06          1.475E200        2.271E+02    3.996E-04 01 9     1.335E+05          1.700E+00        1.753E+01    2.981E-05 020        .000E+00         1.900E+00          .000E+00     .002E+O0 02 1    3.402E+06          2.1OOE+0          5.499E+02    8.743E-04 022     6.942E+06          2.300E÷00         1.226E+03    1.876E-03 023     8.344E+05          2.500E+00         1.600E+02    2.400E-04
.024         .000E+00         2.7O0E+00           .00E2+00    .000E.00 025        .OOOE+00        3.0000E+0           .000E*00     .000E÷O0 TOTAL     6.514E+48                            3.908E+03    8.222E-03 Press RETURN

Amnerican Nationan Standard ANSIIANS-5.4-1982

3. Noble Gas Release Calculations The following definitions applyr 3.1 High-Temperature Release Calculations. B iis the fission product production rate (birth For calculating high-temperature release of rate) during the it" step, noble gases from fuel pellets, the column of fuel Atj is the length of the ith time step (sec),

pellets is divided into radial and axial nodes, and the model is applied to each node for the appro- .k 010 priate local values of temperature and burnup. Z D~ t. kX= i f-i 7 1l=2 : . Six or more radial nodes of equal volume or equal radial increment, and ten or more axial zi - g('rT) =3I - 4V,.,W -t 8'ri2 for-r<.1,.I nodes of equal length shall be used, unless other. wise justified. The irradiation period shall be I__I sl ep(_n 2 AO~j divided Into a series of burnup (time) increments gj = gj'rj= 1571 Ti n=1 n4V4 such that the temperature and power in each increment can be assumed constant. These in- for r> 0.1, crements shall not exceed 2.000 MWd~t pro-vided that the burnup values used in the D1 (Doa2)exp( &T4] X100 analysis correspond to the midpoint of the burn-up increments. Otherwise, the burnup in- D orag -0.61 sec,1. where the notation D&/a2 crements shall not exceed 1,000 MWd/t" Is retained for consistency with published references, In the following equations, approximations Q - 72,300 cal/mol, have been made so that only finite number of R = 1.987 cal/mol K. terms remains. The error introduced by making these approximations is about one part In 100, Ti Is the temperature (K) during the i.k time In-which is considered insignificant in gas release crement, calculations. and 3.1.1 Long-Uved Nuclides (halfilfe greater than one year). For nuclides with halflife greater Bul is the accumulated burnup (MWdct) at the than one year (e.g., Xr85), equations for stable midpoint of the ith time Increment. nuclides are assumed to apply. The fractional release F at the end of a single burnup (time) 8.1.2 Short-LUved Nuclides (halflife less than increment is: one year). The release fraction F for an irradia-tion ]*riod at constant temperature and power, F - g(Tr), (Eq.1) for T < 0.1, is: where =u D't, t is time (sec), and the other F i'*-'-4p)-- [er definitions can be obtained by omitting the Fm eP(-PJT) 1- (Eq. 8) subscripts from the appropriate expressions. following Equation 2. 2V5 exp(-.}] U--(1+ I)eX-P}) The cumulative fractional release Fk at the end of k burnup (time) increments (k Y 2) Is: and, for T> 0.1, the release fraction is: Fk -I (Bil(Tjg- Ti+1gj+)I/DjI + Au F 3a[ oth(V -A ]- exp(M)-Z (Eq. 2) (Eq. 4) I-eXp(-n 2 N~t X I i=11 A= 1 l2 )AnYlt + Yi) 2

American Nat~onal Stamndard ANSIJANS-5.4-2982 322 Short-Lived Nuclides (halflife less than The following definitions apply-one year). The release fraction F is: T A/D't F - (11A) [10-7 V'T + 1.6 X 10- 1 2 P], (Eq. 7) where P is the specific power (megawatts per A is the decay constant (se' 1 ), metric ton of heavy metal) and A is the decay constant (sec' 1 ). For conservatism, the specific t is the time (sec) during the constant-temperature and constant-power Irradiation power P should correspond to the maximum period, power level during the last two halflives of operation. D = [Do/a2 ) exp(-QIRT)] X 10011W29,M

3. Precursor Effects. The effect of precursors T is the temperature (K), is believed to be negligibly small except for Xe-133 and Xe-135. When calculating the total Bu is the total accumulated burnup (MWd/t) in- release fraction Ftotwj for these nuclides of cluding all prior operating periods,. -xenon, the fractional release of these nuclides, and calculatýd in 3.1 and 8.2,.should be corrected for the effect of precursors (FIF 1 33 and F1 '13 5,respec.

DOja 2 , Q, and R are defined in 3.1.1. tively) as follows: These equations are valid when, no concentra-tion of the nuclides of interest exists from prior FXO13 = l-1BS + FX.I-233 operating periods. For most practical applica. (Eq. 8) tions, a shutdown period of four halflives satisfies this criterion. Formulations for release fractions during vary. FXO-1 5 = FI-335 + pXe-136-ing temperature and power operation cannot be tow x~~ (Eq. 9) easily obtained in closed form. For those conditions, the release fraction may be conservatively calculated using the equilibrium 4. Iodine, Cesium, and Tellurium Release equation: Calculations. 4.1 High-Temperature Release Calculations. [F = 3 cothiv') , (Eq.) The noble gas model described in 3.1 is used ex-cept that the diffusion parameters are altered as follows: using the peak temperature reached during the last two halflives of operation.

                                                       "D         obtl
                                                                           = 7, 3.2 Low-Temperature Release Calculations.

3.2.1 Long-IUved Nuclides (halflife greater than one year). The cumulative fractional release F is independent of temperature and given by. VDjrWfD~wb~e 80-F =7 X 10 5 BU, (Eq. 6) 4.2 Low-Temperature Release Calculations. where Bu is the rod-average accumulated burn- Release fractions are assumed to be the same as up (MWdit). those for the noble gases as described in 3.2. 3

J.STEVYjAPT ES.ý'1 7 JED 45S=SZC.ATES. Ir'~ RADIOACTIVITY RELEASE EMERGENCY ACTION LEVELS SEPTEMBER 1990 by Jim B. McIlvaine, P. E. JSB Associates, Inc. 133 Defense Highway, Suite 208 Annapolis, MD 21401 aPu F'ec ý'-!-v - 1/ý/-?!ý - rý t mLU~ U~ 1~3'3 CE.Tý:NS3 HIGIHWAYý - SLUITE 208 0 ANNAPOLIS. M0 ^? 'C~ 2::~ ~

FINAL September 1990 RADIOACTIVITY RELEASE EMERGENCY ACTION LEVELS EXECUTIVE

SUMMARY

A revised set of Radioactivity Release Emergency Action Levels (EALs) is proposed based on the most recent evaluation of source term distributions for various accidents and the Dose Rate Conversion Factors (DCFs) which are used consistently for emergency preparedness off-site dose assessment. Use of EP methods and values, rather than ODCM methods and values, assures consistency within the Emergency Plan. Proposed Radioactivity Release EALs follow: Monitor Unusual Event ALERT WRNGM (UI+U2)-RI-5415 1.8 E 5 pCi/sec 1.8 E 6 ACi/sec MAIN VENT (Ul+U2)-RE-5415 5.8 E 4 cpm 5.8 E 5 cpm WASTE PROC (Ul+U2)-RE-5410 2.0 E 5 cpm Off Scale, High FUEL HANDLING 0-RE-5420 1.7 E 5 cpm Off Scale, High ACCESS CONTROL 0-RE-5425 Off-Scale, High NA ECCS Pp. Rm. 1/2-RE-5406 Off-Scale, High NA These Radioactivity Release EALs are based on:

   - A conservative assessment of the expected source term radionuclide distribution for accidents as presented in BG&E-EP9 and considering release pathways;
   - The dose rate conversion factors published by Kocher and used consistently in the ERPIPs, but which differ from the DCFs used in the ODCM; and,
   - Guidance in Appendix 1 of NUREG-0654.

The Radioactivity Release EALs developed herein differ from the current values primarily because of differences in the assumed source term radionuclide distribution. Differences between ERPIP and ODCM DCFs also contribute to the difference in EALs. EPIU Rcei'eved 7/79 F LLCM tP1N - iFVF.ENO. __._. _

FINAL September 1990 INTRODUCTION AND BACKGROUND The purpose of this document is to explain the bases and reasoning leading to the proposed Calvert Cliffs Radioactivity Release Emergency Action Levels (EALs) for Unusual Event and Alert classifications. NUREG-0654 (Ref. 1) Appendix 1 guidelines call for Notification of Unusual Event if radiological effluent technical specifications are exceeded, and further recommend that an ALERT be declared for radiological effluents greater than 10 times technical specification limits. The Calvert Cliffs Technical Specifications (T.S. 3.11.2) related to gaseous effluents restrict both the offsite dose rate and the total offsite air dose. The offsite dose rate is logically the limiting Technical Specification for Emergency Planning purposes. Offsite dose rate limits exist for the total body, skin, and the "maximum organ", which for CCNPP is the child thyroid, inhalation pathway. Different nuclides have different dose rate conversion factors for each of the three different dose rate limits considered. The value selected for the Radioactivity Release EAL for each monitor should therefore be established for the most restrictive Technical Specification dose rate limit applicable for the radionuclide distribution existent at the monitor. Each accident scenario applicable to the monitored pathway should be evaluated. The radionuclide distribution impacts both the effective Dose Conversion Factor which is used to assess offsite dose rates and the effluent monitor response which is used to determine when the EAL is reached. Considerable efforts have already been devoted to assessing potential source terms. The accident source terms in use for accident dose assessment are presented in BG&E-EP9, Calvert Cliffs Nuclear Power Plant Accident Source Terms, Rev. 2, April 1990. (Ref. 2) A comparison with other source terms used at Calvert Cliffs is presented in this report. The values of the Dose Conversion Factors used in the ERPIPs come from an article by Kocher in the September 1983 Health Physics. 2 t D_

FINAL September 1990 (Ref. 3) These values differ from the dose conversion factors used in the Offsite Dose Calculation Manual (ODCM), the Kocher values for noble gases being generally lower. The ODCM is used to evaluate the environmental impacts of normal releases over long time periods. The Kocher values are newer dose rate conversion factors for immersion in contaminated air, and are used consistently throughout the Calvert Cliffs Emergency Response Plan Implementing Procedures (ERPIPs) and in the RADDOSE dose assessment model. The Kocher values are therefore used in this study. This study resulted from discovery of an inconsistency in the Radioactivity Release EALs which was identified during the development of responses to NRC comments regarding the EALs. The NRC did not comment specifically regarding the value of the Radioactivity Release EAL for the Main Vent monitors. However, it was determined that the EAL was established using ODCM methods and values. When the EAL was reached, calculations of off-site dose rates using ERPIP methods and values result in values. greater than the Technical Specification limit, which is the basis for the EAL. It is this inconsistency which is being addressed and corrected. APPROACH Once the appropriate limit has been established, determination of an appropriate EAL for radioactivity releases is straightforward, although several variable factors must be considered. Two variables, meteorology and the Dose Conversion Factors (DCFs), impact the calculation of offsite dose rate, but choosing the most conservative values for each variable can lead to an EAL value which is too low. Unnecessarily low EAL values could lead to declaration of unwarranted UNUSUAL EVENTs or ALERTs. Other factors to consider are the Technical Specifications limits on Whole Body, Skin, and Maximum Organ dose rates. Which dose rate is most restrictive will depend on the radionuclide distribution assumed, which in turn will vary as a function of accident type. 3 IS B77..

FINAL September 1990 The approach used to establish appropriate Radioactivity Release EALs follows:

     - BG&E-EP9 was used as the source term reference for all accident types;
     - DCFs were calculated for the expected radionuclide distribution for each accident type;
     - The DCFs were evaluated with respect to all accident types and the Technical Specifications and an appropriate DCF was selected;
     - The annual average X/Q (2.2E-6 sec/rn)  was assumed as appropriate meteorology; and,
     - In accordance with NUREG-0654 guidance, EALs were set for expected monitor response at Technical Specification limits for Notification of Unusual Event and at 10 times Technical Specification limits for an Alert.

The Whole Body dose-rate limit was determined to be the controlling Technical Specification limit for the Waste Gas Decay Tank Rupture (WGDTR) and the Loss of Coolant Accident with release of Reactor Coolant (LOCAR). The Whole Body dose-rate limit also controls for the Steam Generator Tube Rupture (SGTR) accidents as long as the release exits through the condenser to the Main Vent. (This pathway achieves additional iodine and particulate washout in the condenser.) For the Fuel Handling Incident (FHI), determination of the most limiting dose rate depends upon which values are used to compute the dose rate. The ODCM dose rate conversion values result in the Whole Body dose rate being more limiting; the Kocher values and the values used in RADDOSE for the Child Thyroid dose rate result in the Maximum Organ dose rate being more limiting for this accident. The comparison of Whole Body limits with Skin and Maximum Organ dose rate limits is discussed in the CALCULATIONS AND RESULTS section under Dose Rate Conversion Factors. The specific dose rate limit used to calculate each EAL value is stated in the EAL Computation Use of BG&E-EP9 as the source term basis document was determined to be appropriate for several reasons. It is the most recent and current study; it is comprehensive, and thoroughly researched and reviewed; and in one very important aspect - the noble gases distribution calculated for the Calvert Cliffs core - it is 4

FINAL September 1990 consistent with other bases documents which were used previously in establishing the emergency procedures. That is, the noble gases distribution found in BG&E-EP9 is identical, to 2 significant figures, to that derived from NUREG-0771, which was previously used to develop source terms for the ERPIPs. CALCULATIONS AND RESULTS Source Terms For purposes of establishing the Radioactivity Release EALs, the distribution of radionuclides is as important as the absolute magnitude of the release. The dose rate varies as a function of the individual isotopes; i.e., 1 curie per cubic meter of Xe 135 produces a greater dose rate than 1 curie per cubic meter of Xe 133. Therefore, the distribution of radionuclides has as much bearing on the dose rate as does the release rate. The original ERPIPs were developed using NUREG-0771, Table 3.2 source term values normalized to 2700 MWt as the basis. (Ref.4) BG&E-EP9 is based on the later NUREG-1228. Comparison of the distribution of the noble gases between these two base documents, shown in Table 1, shows agreement to two significant digits in the relative contributions of the noble gases. Therefore, the difference in base document - NUREG-0771 or NUREG-1228 - makes no appreciable difference for these purposes. 5

FINAL September 1990 TABLE 1 ACCIDENT SOURCE TERM COMPARISON Derived Core Inventories in MegaCuries Isotope Kr-85 Kr-85m Kr-87 Kr-88 Xe-133 Xe-135 t, (hrs.) 93910 4.48 1 .27 2.84 125.9 9.09 BG&E-EP9 0.645 27.7 54.2 78.4 196 39.2 % Total 0.16% 6.99% 13.68% 19.79% 49.48% 9.90% NUREG07710.445 19.7 38.7 55.4 139 28.1 % Total 0.16% 7.00% 13.76% 19.69% 49.41% 9.99% ORIGEN 1.49 13.7 24.8 34..6 149 32.2 % Total 0.58% 5.36% 9.70% 13.50% 58.3% 12.6% A comparison was also made to the Calvert Cliffs Nuclear Power Plant specific source term analysis done by Combustion Engineering using the ORIGEN computer code and assuming a 24 month fuel cycle. (Ref. 5) Agreement between BG&E-EP9 and the ORIGEN results is good, although not as good as the agreement between results based on NUREG-0771 and NUREG-1228. (See Table 1.) The ORIGEN results, when the same six significant noble gas radionuclides are considered, indicate more relative Xenon isotopes and Krypton 85 and relatively less of the other Krypton radionuclides. This results in a lower calculated effective dose-rate conversion factor when using the ORIGEN results. This further demonstrates the conservatism in use of BG&E-EP9 as the basis for accident source terms. The noble gas radionuclide distribution for both gap and core releases are nearly identical, so only the RCS and gap release need be considered with respect to noble gases distribution. See Table 2. 6 B - c~c~ -

FINAL September 1990 TABLE 2 NOBLE GASES DISTRIBUTION RCS, Gap, and Core (Curies) Isotope Kr-85 Kr-85m Kr-87 Kr-88 Xe-133 Xe-135 RCS Inventory 91.7 34.1 32.0 59.7 554 181 % of Total 9.63% 3.58% 3.36% 6.27% 58.2% 19.0% Gap Inventory 1.94E4 8.30E5 1.62E6 2.35E6 5.88E6 1.18E6 % of Total 0.16% 6.99% 13.6% 19.8% 49.5% 9.93% Core Inventory 6.45E5 2.77E7 5.42E7 7.84E7 1.96E8 3.92E7 % of Total 0.16% 6.99% 13.7% 19.8% 49.5% 9.90% Above values are from BG&E-EP9, Table 1, page T2. Dose Rate Conversion Factors The effective Dose-Rate Conversion Factor for a specific mix of airborne radioactive material may be determined using the method presented in the CCNPP ODCM, Section 3.4.5. The method is defined by the equation: DCFEFF = Zi DCFt x f, where: DCF.,, = the effective whole body dose-rate conversion factor from all radionuclides released; DCFI = the whole body dose-rate conversion factor for radionuclide i from Kocher; and, fj = the fractional abundance of radionuclide i relative to the total noble gas activity. 7 I GtI~

FINAL September 1990 Use of this equation with the radionuclide distributions presented in BG&E-EP9, Table 11, and the Kocher dose-rate conversion factors yields the following effective Whole Body DCFs, in mrem/hour per pCi/m 3 : Waste Gas Decay Tank rupture: DCFre~ = 0.0455; Fuel Handling Incident: DCF., = 0.0208; Steam Line Break: DCF.fo = 0.465; Steam Generator Tube Rupture, without fuel damage: DCFe,, = 0.148; Steam Generator Tube Rupture, with gap release: DCFo*r = 1.08; LOCA, with RCS release: DCFo,, = 0.0962; LOCA, with Gap release: DCF.,, = 0.243; LOCA, with core melt: DCF.o, = 0.243; RCS distribution of noble gases: DCFofr = 0.144. The spreadsheet used in the calculation of these values is presented in Appendix A. For all the accident types except the Loss of Coolant Accidents (LOCAs), the duration of the release is assumed to be one hour or less. For these cases the change in the radionuclide mix due to decay during the release is not too great and a time variable DCF was not calculated. Rather, the DCF is based on the total curies released during the postulated accident. For the LOCA scenarios, with 6 hour release periods, decay during the release does materially effect the DCF calculation. The DCFs used herein for a 6 hour LOCA release are also based on the total activity estimated to be released. (BG&E-EP9, Table 9 or 11) An evaluation was done to compare this value for the DCF with the DCF as a function of time after reactor shutdown. (The evaluation and results are contained in Appendix B.) The DCFs decrease 8

FINAL September 1990 rather quickly as a function of time. The mid-range value of the DCF over 6 hours is always greater than the average, and is also greater than the value at 3 hours. The DCF based on the total activity released during a LOCA is always between the mid-range value and the average value of the DCF as a function of time. The Kocher dose rate conversion factors result from calculations which assume a semi-infinite cloud of uniformly distributed radioactive material. Therefore the above numbers do not include a finite cloud correction factor. For the purpose of this determination of appropriate Emergency Action Levels, the Kocher values are judged to be adequate, without a finite cloud correction factor. The Whole Body dose rate is the more limiting Technical Specification compared to the Skin dose rate limit. This was determined by evaluating the effective whole body and skin dose rate conversion factors from the noble gases for each accident type. Values from the ODCM were used in this evaluation for consistency and simplicity. The results, presented in Table 3, show that the effective skin DCF is less than 6 times the effective whole body DCF. Since the Technical Specification skin dose rate limit is 6 times the whole body dose rate limit, the whole body dose rate limit will control for each of the evaluated accidents. (See.Appendix C for supporting data.) TABLE 3 COMPARISON OF WHOLE BODY AND SKIN DOSE-RATE CONVERSION FACTORS (mrem/hour per gcurie/m3 ) ACCIDENT TYPE WHOLE BODY DCF SKIN DCF WGDTR 6.57E-2 0.132 FHI 3.37E-2 8.02E-2 LOCAR 0.131 0.256 Likewise, an evaluation was also done to determine for which accidents the maximum organ dose-rate limit of Technical Specification 3.11.2.1 b. was more limiting than the Total Body dose-rate limit. (Evaluation and results are shown in Appendix 9 G III 7-, rSxc ti:3

FINAL September 1990 D.) The RADDOSE values of the dose conversion factors were used with the source terms in BG&E-EP9 to calculate both Total Body and Maximum Organ DCFs for each accident. The ratio of the DCFs were compared to the fraction of the release comprised of radioiodines to determine if the maximum organ dose-rate was most limiting. When all iodine reduction factors are considered, the Total Body dose-rate limit is limiting for each accident except the Steam Line Break (SLB) and possibly the Fuel Handling Incident (FHI). The Steam Line Break (SLB) has a larger effective Dose-Rate Conversion Factor than any other potential accident analyzed except for the Steam Generator Tube Rupture with a Gap release (SGTRG). However, this accident is not used to establish any Radioactivity Release EAL, for two reasons. First, although the DCFo,, is high, the total curies available within the secondary system is small. Noble gases are continuously removed in the Condenser, and iodines and particulates are continuously removed by the Condensate Cleanup System. Also, a Technical Specification limits the allowable level of dose equivalent I-131. Even with a high DCFt,, with a very small source quantity the off-site doses will be small. Second, the Steam Line Break accident outside of containment results in a unmonitored release from the Turbine Building. The escaping steam is not released via a normal, monitored vent pathway, so no monitor exists to provide a Radioactivity Release EAL for the SLB. EAL Computation Determination of the appropriate Emergency Action Level for radioactivity releases is simply the calculation of the release rate which equates to the Technical Specification limit and determining the expected monitor response at that release rate. Computations for each monitor(s) used for EALs follow. 110

FINAL September 1990 Main Vent Release Pathway For this EAL computation only those accidents where releases via the main vent are probable are considered. These accidents include: Waste Gas Decay Tank Rupture (WGDTR); Fuel Handling Incident (FHI); Steam Generator Tube Rupture without fuel damage (SGTRR); Steam Generator Tube Rupture with Fuel damage (SGTRG); and all the Loss of Coolant Accidents (LOCAR, LOCAG, and LOCAM). Steam Generator Tube Rupture releases will be via the main vent only until the Main Steam Isolation Valves close. And as long as the releases are via the Main Vent, radioiodine releases should be lower than projected in BG&E-EP9 due to additional iodine washout in the condenser, leaving only the noble gases as a significant source. Likewise for the LOCA scenarios, Containment leakage that exits via the Main Vent has probably leaked into Penetration Room(s) and ventilation exhaust from these rooms is filtered in charcoal filters to remove radioiodines. Therefore, the RCS distribution of noble gases is used to establish DCFoE. There is a significant difference between the effective DCF for RCS releases vis-a-vis fuel rod gap releases. The less conservative RCS noble gas distribution is used to determine the allowable release rate instead of the more conservative fuel gap distribution. This assures that the EAL is above the Main Vent Monitor's alarm setpoint, which is only reasonable since the alarm setpoint has a safety margin in it. Use of this less conservative distribution is justified by the observation that it is highly unlikey that a noble gas distribution equivalent to a gap release could exist at the Main Vent monitors without some other indicator which would have already caused an appropriate emergency notification. It is also most likely that - during progression of an accident - an RCS distribution will exist in a release pathway prior to fuel damage. The Wide Range Noble Gas Monitor has a more predictable response to a range of noble gas distributions. Consequently, if there is significant disagreement between the WRNGM and the MVGM, the WRNGM should be used for EAL classification. 11

FINAL September 1990 Wide Range Noble Gas Monitor (Ul+U2)-RI-5415 The basis for the WRNGM EAL should be consistent with the basis for the MVGM EAL, as both monitors are in the same release path. Therefore, the EAL should be set based on the RCS noble gas distribution. NOUE at Tech. Spec. 3.11.2.1 limit: Tech Spec Whole Body limit = 500 mrem/yr = 0.057 mrem/hr 0.057 mrem/hr / 0.144 mrem/hr per pCi/m 3 = 0.40 pCi/m 3 at site boundary 0.40 pCi/mr / 2.2 E-6 sec/m3 = 1.8 E+5 MCi/sec release from site NOUE EAL: (U1+U2)-RI-5415 at 1.8 E 5 ACi/sec ALERT EAL: (Ul+U2)-RI-5415 at 1.8 E 6 pCi/sec 12 3 7, r TGD-,.~c~-'

FINAL September 1990 Main Vent Gaseous Monitors (U1+U2)-RE-5415 The basis for the MVGM EAL should be consistent with the basis for the WRNGM EAL, as both monitors are in the same release path. Therefore, the EAL should be set based on the RCS noble gas distribution. NOUE at Tech. Spec. 3.11.2.1 limit: 0.40 ACi/m 3 / 2.2 E-6 sec/m3 = 1.8 E+5 pCi/sec release from site Total main vent flow rate = 63.7 + 57.5 = 121.2 m3/sec 1.8 E+5 ACi/sec / 121.2 m'/sec = 1.5 E-3 pCi/cc in both vents The minimum Notification of Unusual Event concentration is 1.5 E-3 ACi/cc in both main vents simultaneously. Table 4 presents the development of the expected monitor response for the Main Vent Gaseous Monitor. TABLE 4 MAIN VENT MONITOR RESPONSE AT RADIOACTIVITY RELEASE EAL

RESPONSE

ISOTOPE RCS CONC.  % TOTAL EAL CONC. cpm/10"6 EAL cpm Kr-85 0.43 9.62 1.4 E-4 35 4.9 E3 Kr-85m 0.16 3.58 5.4 E-5 55 3.0 E3 Kr-87 0.15 3.36 5.0 E-5 218 1.1 E4 Kr-88 0.28 6.26 9.4 E-5 189 1.8 E4 Xe-133 2.6 58.17 8.7 E-4 1.87 1.6 E3 Xe-135 0.85 19.01 2.9 E-4 70 2.0 E4 Totals 4.47 100% 1.5 E-3 5.8 E4 The computed EAL value of a total of 5.8 E4 cpm from both Main Vent Gaseous Monitors is comfortably higher than the current ALARM setpoint of 1200 cpm on each monitor. The ALERT EAL should be 10 times the Unusual Event EAL, or 5.8 E 5 cpm for (Ul+U2)-RE-5415. 13 E L3 ~

FINAL September 1990 Waste Processing Monitor (U1+U2)-RE-5410 For the Waste Processing Monitor the noble gas distribution associated with a Waste Gas Decay Tank Rupture is the most likely source for an accident sufficient to cause implementation of the Emergency Plan. NOUE at Tech Spec 3.11.2.1 limit: 0.057 mrem/hr / 0.0455 mrem/hr per ACi/m3 = 1.3 j4Ci/m 3 1.3 pCi/m 3 / 2.2 E-6 sec/mr = 5.7 E 5 pCi/sec release from site Waste Processing Ventilation Flow = 49,500 cfm = 23.4 m3/sec 5.7 E 5 gCi/sec / 23.4 m3/sec = 2.4 E-2 pCi/cc Monitor Response at EAL Concentration Response EAL Isotope  % Total E cpm/lO-6 Response Kr-85 0.5 1.3 E-4 35 4.2 E 3 Kr-85m 0.8 1.9 E-4 55 1.1 E 4 Kr-87 0.4 9.6 E-5 218 2.1 E 4 Kr-88 1.3 3.1 E-4 189 5.9 E 4 Xe-133 93.1 2.2 E-2 1.87 4.2 E 4 Xe-135 3.9 9.4 E-4 70 6.6 E 4 Total cpm at EAL Conc.= 2.0 E 5 ALERT EAL at ten times NOUE EAL = 2.0 E 6 cpm for (Ul+U2)-RE-5410 or either monitor off-scale, high. 14

FINAL September 1990 Fuel Handling Monitor O-RE-5420 For the Fuel Handling Monitor the EAL should be established based on a Fuel Handling Incident (FHI). However, whether to set the EAL based on the Total Body dose-rate limit or the Child Thyroid (Maximum Organ) dose-rate limit is not easily determined. Starting with BG&E-EP9 FHI source terms and using ODCM values for dose conversion factors results in the Total Body dose-rate limit being the limiting Technical Specification. Using Kocher and RADDOSE values results in the Maximum Organ (Child Thyroid) dose-rate limit being more restrictive. This anomaly is due solely to different values for dose-rate conversion factors, but it does suggest that either limit is justifiable. The Maximum Organ (Child Thyroid) dose rate is related to the amount of radioiodines released, which in turn is dependent upon iodine washout in the Spent Fuel Pool. Washout may result in a reduction factor of from 100 to 10,000. At the low end, the Maximum Organ dose-rate limit could be limiting; at the high end the Total Body dose-rate limit is most restrictive. Analysis indicates that if iodine washout in the Spent Fuel Pool results in a DF > 252, then the Total Body dose-rate limit controls. Since this DF is towards the low end of the expected range, this EAL will be established based on a Total Body dose-rate limit. Only noble gases will be considered in determining the monitor response at the EAL. This will result in a conservative EAL. The monitor is located upstream of the charcoal filters. It will respond to both noble gases and radioiodines released from the Spent Fuel Pool, after iodine washout in the pool but before reduction through the charcoal filters. The Fuel Handling Monitor does not distinguish between noble gases and radioiodines, so radioiodines which are released and sensed at the monitor will cause earlier attainment of the EAL. NOUE at Tech Spec 3.11.2.1 limit: 3 3 0.057 mrem/hr / 0.0208 mrem/hr per pCi/m = 2.7 MCi/m 15

FINAL September 1990 2.7 .Ci/mn

           / 2.2 E-6 sec/mW = 1.2 E 6 MCi/sec release from site Fuel Handling Area Ventilation Flow = 32.,000 cfm = 15.1 m3/sec 1.2 E 6 MCi/sec / 15.1 m/sec = 8.0 E-2 pCi/cc Monitor Response at EAL Concentration Response       EAL Isotope         % Total       EAL Conc. cRm!10-6       Response Kr-85           0.5           4.0 E-4       35             1.4 E 4 Kr-85m          0             0             55             0 Kr-87           0             0             218            0 Kr-88           0             0             189            0 Xe-133          99.4          8.0 E-2       1.87           1.5 E 5 Xe-135          0.1           8.0 E-5       70             5.6 E 3 Total cpm at EAL Conc.  =  1.7 E 5 cpm ALERT EAL at ten times NOUE EAL = Off-scale,    High. Use 9 E5 cpm.

16 3 B... -~

FINAL September 1990 Access Control Monitor O-RE-5425 Although significant airborne releases via the Access Control Point are unlikely, the monitor is placed in a potential release pathway. Therefore determination of an EAL is prudent. This determination must assume an airborne radionuclide distribution, and the distribution should reflect a feasible accident so that the EAL may be realistic. With complete failure of the Auxiliary Building ventilation systems and a reactor coolant leak into the Aux. Building, a RCS noble gas distribution could be present. Such a distribution would be conservative vis-a-vis other potential accident distributions such as the WGDTR or FHI. Therefore, a RCS noble gases distribution will be assumed to determine the Access Control Point EAL. NOUE at Tech. Spec. 3.11.2.1 limit: Tech Spec Whole Body limit = 500 mrem/yr = 0.057 mrem/hr 0.057 mrem/hr / 0.144 mrem/hr per mCi/ml = 0.40 ACi/m 3 at site boundary 0.40 gCi/m 3 / 2.2 E-6 sec/m3 = 1.8 E+5 MCi/sec release from site Access Control Point vent flow rate = 13,900 cfm = 6.56 m3 /sec 1.8 E+5 pCi/sec / 6.56 m3 /sec = 2.7 E-2 pCi/cc Access Control Point Monitor Response at EAL Concentration Response EAL Isotope  %-Total EAL Conc. cpm!0l7L Responge Kr-85 9.62 2.6 E-3 35 9.1 E 4 Kr-85m 3.58 9.8 E-4 55 5.4 E 4 Kr-87 3.36 9.2 E-4 218 2.0 E 5 Kr-88 6.26 1.7 E-3 189 3.2 E 5 Xe-133 58.17 1.6 E-2 1.87 3.0 E 4 Xe-135 19.01 5.2 E-3 70 3.6 E 5 Total cpm at EAL Conc. = Off-scale, High 17

                                                                              'A FINAL                                                     September 1990 ECCS Pump Room U1/U2-RE-5406 Following a Loss of Coolant Accident, equipment leakage into the ECCS Pump Room could release the RCS distribution of noble gases
                                                                             ;*.]

- into the ECCS Pump Room. Initially flow is from the Refueling ".I Water Storage Tank, but recirculation can begin in about 30 minutes, therefore the RCS distribution without decay may be assumed without significant additional conservatism. NOUE at Tech. Spec. 3.11.2.1 limit: Tech Spec Whole Body limit = 500 mrem/yr 0.057 mrem/hr 0.057 mrem/hr / 0.144 mrem/hr per pCi/m' = 0.40 pCi/m 3 at site boundary

• 0.40 pCi/m 3 / 2.2 E-6 sec/m3 = 1.8 E+5 pCi/sec release from site ECCS Pump Room vent flow rate = 3,000 cfm = 1.42 m3 /sec 1.8 E+5 pCi/sec / 1.42 m3 /sec = 0.13 pCi/cc ECCS Pump Room Monitor Response at EAL Concentration Response EAL cpm/lo-" Response Isotope Total EAL Conc.

Kr-85 9.62 1.2 E-2 35 4.2 E 5 Kr-85m 3.58 4.6 E-3 55 2.5 E 5 Kr-87 3.36 4.3 E-3 218 9.4 E 5 Kr-88 6.26 8.0 E-3 189 1.5 E 6 Xe-133 58.17 7.4 E-2 1.87 1.4 E 5 Xe-135 19.01 2.4 E-2 70 1.7 E 6 Total cpm at EAL Conc. = Off-scale, High 18

FINAL September 1990 CONCLUSIONS Revisions to ERPIP 3.0 Emergency Action Levels are suggested to reflect the accident source term assumptions of BG&E-EP9. Default dose-rate conversion factors presented in the ERPIPs should be revised to be consistent with those used in the emergency dose assessment code RADDOSE and with the expected sources for the different types of accidents as presented in BG&E-EP9. Other portions of the ERPIPs, such as graphs of monitor response, will likewise need revision to maintain consistency. A comprehensive ERPIP review is recommended upon acceptance of RADDOSE and BG&E-EP9. REFERENCES

1. NUREG-0654 / FEMA-REP-l, Rev. 1, Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants, Nov. 1980

2. BG&E-EP9, Calvert Cliffs Nuclear Power Plant Accident Source Terms, Rev. 2, April 1990

3. D.C. Kocher, "Dose-Rate Conversion Factors for External Exposure to Photons and Electrons", p. 665-686, in Health Physics, Vol. 45, No. 3, September 1983

4. E.T. Reimer memorandum to G.C. Rudigier, Oct. 6,1987,

Subject:

CCNPP Accident Source Terms, BG&E-EP9

5. Combustion Engineering (J.E. Baum) letter to BG&E (J.A.

Mihalcik), 9/15/87,

Subject:

BG&E Fuel Fission Products Isotopic Inventories from ORIGEN

6. Westinghouse (C.H. Griesacker) letter to BG&E (Boyd Wylie),

6/26/81,

Subject:

Request by Pete Crinigan for various isotope response sensitivity for the monitors at Calvert Cliffs Nuclear Power Plant 19

FINAL September 1990 APPENDIX A EFFECTIVE TOTAL BODY DOSE CON4VERSION FACTORS GD ~ -

• AIR IM)SION FISIOff DCF WGDTR FRI SLB SGTRR SG7 WCAR LOCKG LOCAM PIWT VGDTR DC PHll DC SIB DC! S DC SGT0; DC! WeCAR DC!F WAG DC! LOCM DC!'

Kr-85 3.03 2.62e2 1.382e-2 1.lel 1.472.-2 2.32e-1 1.4300-2 2.7501 2.902e-1 5.8e0 4.7990-3 2.299-1 3.287e-1 4.83e0 6.518e-3 1.61e2 6.496e-3 Kr-85M 96.3 4.41e2 7.3930-1 5.490-3 2.335e-4 8.64e-2 1.692e-1 1.02el 3.421000 2.49e2 6.5481e0 5.510-2 2.5134e0 1.34e2 5.7469.0 4.46e3 5.7192.0 Nr-87 527.99 2.402 2.2060e0 7.33.-15 1.71e-15 8.1e-2 8,699e-1 9.59e0 1.7635el 4.8792 7.0218ei 2.34e-2 5.8522e0 1.1-92 2.7982el 3.9703 2.7912e1 Kr-88 1313.63 7.69a2 1.7586el 2.560-5 1.4850-5 1.51.-1 4.0349e0 1.79el 8.1893el 7.0492 2.525402. 7.79e-2 4.8472el 3.06e2 1.7902e2 1.02e4 1.7842e2 X0-133 20.7 5,35e4 1.9279.1 2.25e3 2.0571el 1.4eO 5.895e-1 1,66e2 1.1%7e1 1.7603 9.948990 1.36e0 1.3335el 1.4403 1.3275.1 4.8104 1.325801 X0-135 146.99 2.2303 5.7064e0 2.97e0 1.928e-1 4.59e-1 1.3724e0 ý.44el 2.784991 3.52e2 1.4129el 3.65e-1 2.5413el 2.36e2 1.5449el 7.87e3 1.5404el 5.7442e4 100.00% 2.264003 99.87% 2.4094.0 1.52t 2.8559e2 96.39% 3.5578e3 32.61% 2.11040 99.71% 2.239803 99.26% 7.4761e4 98.88% 1-131 222.18 8.6e-2 8.439.-3 5.150 2.3275el 5.76e-2 4.457e-2 1.17el 7.0998-1 4.759-5 4.9990-3 9.68.1- 9.5780-2 4.84el 1.432e-1 1-132 1381.22 5.91.-11 3.61e-11 2.44e0 6.8554.1 2.69e-1 1.2940e0 1.6601 6.261300 1.03e-4 6.7390-2 6.380-1 3.925e-1 3.19e1 5.867e-1 1-133 358.61 2.07e-2 3;279e-3 8.5560 6.2369el 1.79e-1 2.236e-1 2.35el 2.301400 1.350-4 2.293e-2 1.77e0 2.827e-1 8.87el 4.2368-1 1-134 1600.86 5.330-26 3.770-26 1.55e0 5.0474el 4.35e-1 2.4253e0 2.62el 1.14540l 7.590-5 5.7550-2 4.58e-1 3.265e-1 2.29el 4.8820-1 1-135 967.27 1.170-4 4.998W-5 7.4960 1.4737e2 3.,33e-1 1.121800 2.07el 5.467810 2.070-4 9.484e-2 1.2990 5.557e-I 6.43el 8.282e-1 0 1.068.-I .06% 2.518el 75.70% 1.2736e0 .3.44% 9.87el 2.42%5.684e-4 .26% 5.124e0 .681 2.562o2 A.01% Cs-134 929.26 2.45e-2 1.0060-2 1.030O .l9470el 9.080-3 2.939e-2 2.59e0 4,4507e2 7.57e-6 3.332e-3 2.16e-I 8.939e-2 4.31e0 5.3330-2 Cs-136 1305.19 8.37e-3 4,825e-3 1.180-1 3.1328e0. 1.1l0-3 5M046e-3 1.04LO2.5101e2 9.21.-7 5.694e-4 8.570-2 4.9820.2 1.71eO 2.972e-2 Cs-137 .95 1.54e-2 6.462e-6 1.3860 2.6670-2 1.20-2 3.970e-5 1.62e0 2.8460-1 le-5 4.500e-6 1.350-1 5.7120-5 2.7e0 3.4160-5 1R-86 62.94 7.62.-5 2.1180-6 8.97e-3 1.044e-1 7.440-4 2.085e-5 1.49e-2 1.249.-5 T0-127 4.22 1.90-7 3.54.-10 4.07e-3 3.176e-3 2.74e-4 5.150e-7 8.23e-1 4.625.-5 T0-127m 1.87 7.070-6 5.839e-9 7.590-4 2.625e-4 6.32.-5 5.263e-8 1.9.-i 4.731e-6 T0-129 35.82 3.14e-23 4.970-25 1.49e-1 1.0869-1 3.070-2 3.8300-3 2.14e-2 1.4180-1 6.90-6 1.1710-4 4.810-4 7.673e-6 1.44e0 6.868e-4 To-129M 21.84 3.2605 3.145e-7 2.399-2 1.0620-2 2.439-4 1.848e-5 3.660-3 1.478e-2 2.02e-7 2.090e-6 3.040-4 2.957e-6 9.120-1 2.652e-4 To-131m 861.68 1.61e-5 6.1270-6 1.09e-1 1.9105.0 .1.92e-3 5.762e-3 .8.97e-3 1.4293e0 1.49e-6 6.081e-4 6.98e-4 2.6790-4 2.eoO 2.410e-2 To-132 126.72 4.14e-4 2.317e-5 1.68e-I 4.330.-I 2.17e-3 9.5770.4 8.28e-2 1.9403M 0 1.760-6 1.0560-4 6.720-3 3.7920-4 2.02e1 3.409e-2 Sb-127 .393.67 2.34e-5 4.0699-6 4.21e-3 3.0650-1 3.43e-4 6.014e-5 1.03L0 5.3990-3 Sb-129 870.12 1.95e-9 7.49e-10 2.28e-2 3.6687e0 1.22e-3 4.728.-4 3.65e0 4.2290-2 Sr-89 5.03 1.76e-2 1.8010-3 1.790-4 3.136e-6 1.490-7 3.5500-7 3.78e0 2.;5323-4 Sr-90 1.22 1.540-3 3,8220-5 1.53e-5 6.501e-8 1.280-8 7.3970-9 1.498-1 2.421e-6 Sr-91 420.28 3.689-2 3.146.-1 .1.23eo3 1.8000-3 8.320-7 1.6560-4 3.6e0 2.0156-2 Ba-140 110.67 1.540 3.4668e0 1.660-2 6.398e-3 1.38e-5 7.234e-4 1.83el 2.697e-2 Co-58 582.9 5.890-1 6.9838.0 5.880-3 1.194e-2 4.9e-6 1.353e-3 4.48e-2.3.4770-4 CO-60 1499.48 6.89e-2 2.10160 6.780-4 3.541e-3 5.65e-7 4.013e-4 1.67e-2 3.334e-4 4o-99 95.46 6.18e-1 1.20000e 8.190-3 2.7230-3 6.62e-6 2.993e-4 8.93e0 1.135e-2 Tc-99M 76.87 1.190-1 1.8610-1 6.01e-3 1.609e-3 3.61e-6 1.3140-4 5.8100 5.947e-3 1u-103 280.47 9.53e-1 5.437000 9.59e-3 9.368e-3 7.98e-6 1.060e-3 4.420-1 1.6510-3 Bu-105 468.85 1.88e-1 1.174e-3 Ru-106 1.16el 1.15.-1 9.59e-5 1.01.-i 0 Rh-105 46.04 1.86.-I 1.140e-4 Y-90 8.36 2.17e-4 2.4160-8 1-91 7.31 6.49e-, 9.650e-5 6.65e-6 1.6930-7 5.530-9 1.915e-8 6.890-3 6.707e-7

  -%95      443.51                                           4.95*-2 4.466.1- 4.99.-4 7.708.-4                             4.150-7 8.718.-5.             .         ..        35.0gb-S Zr-97        114.89                                                                                                                                                     7.66e-3 1.172e-5 Nb-95        460.41                                           3.37e-2  3.156e-1    3.58e-4 5.7410-4                         2.98a-7  6.499e-5                           8.61e-3 5.2790-5 La-140     1427.68                                             2.0400  5.9244el. 3.2e-2 1.5910-1                         2.53e-5  1.7110-2                           8.74e-3 1.662e-4 Ce-141         45.2                                           1.870-2  1.7199-2    1.92e-4 3.022e-5                         1.59e-7  3.4040-6                           8.61e-3 5.182e-6 Ce-143       155.44                                           2.07e-1  6.545e-1    3.580-3 1.938e-3                          2.80W6  2.062e-4                           7.03e-3 1.4550-5 Ce-144        10.77                                               5e-1 1.095.-I    5.12e-3 1.920e-4                         4.26-6   2.173e-5                           4.890-3 7.013e-7 Pr-143         2.31                                                                                                                                                     7.430-3 2.285o-7 Rd-147        78.56                                                                                                                                                     3.42e-3 3.5780-6 Kp-239        97.99                                               2e-1 3.9870.1 2.81.-3 9.5900-4                            2.260-6 1.049e-4                             9.10-2 1.187e-4 Pi-238            .05                                                                                                                                                   3.280-6 2.18e-12 Pu-239            .05                                                                                                                                                  1.21e-6 8.060-13 Pu-240            .05                                                                                                                                                  1.210.6 8.06e.13 Pu-241                                                                                                                                                                 1.96W-4            0 Am-241        11.02                                                                                                                                                    9.78e-8 1.44e-11 Ca-242            .06                                                                                                                                                  2.87e-5 Z.29e-ll Cm-244            .05                                                                                                                                                  1.32e-6 8.79e-13 0          4.8840-2        .07% 2.1571el 22.79% 2.652e-1            .17% 5.4076e0 64.97% 1.987e-4            .03% 4.475o-1       .06% 8.0791el           .11%

5.7442e4 4.5531el 2.2641e3 2.0805.l 4.9161el 4.6506e2 2.8713e2 1.4841e2.3.6619e3 1.083603 2.1112e0 9.6188al 2.2454e3 2.4327e2 7.5098e4 2.4345e2

FINAL September 1990 APPENDIX B TINE DEPENDENCY OF TOTAL BODY DOSE-RATE CONVERSION FACTORS Time After Dose-Rate Conversion Factor 3 Shutdown in mrem/hr per pCi/m (hours) LOCAR .LOCAG LOCAM 0 0.144 0.365 0.366 1 0.122 0.313 0.314 2 0.105 0.266 0.267 3 0.090 0.225 0.225 4 0.079 0.190 0.190 5 0.070 0.160 0.161 6 0.062 0.136 0.136 Mid-Range Value 0.103 0.251 0.251 Average Value 0.096 0.236 0.237 DCF Based on Total Curies 0.096 0.243 0.243 Released in 6 Hours E ~

LOCAR.I. AIR PRIMARY IMMERSIONHALF-LIFE SYSTEM t 0 t = 1hr t = 1hr t = 2 hr t = 2 hr t =3 hr t = 3 br t= 4hr t= 4 hr t = 5hr t = 5 hr t=6hrt=6hr DCF (days) INVENTORY DCF INVENTORY DCF INVENTORY DCF INVENTORY DCF INVENTORY DCF INVENffORY DCF INVENTORY DCF (Ci) (Ci) (Ci) Kr-85 3.03eO 3.95e3 9.17e2 2.916e-1 9.1699e2 3.069e-1 9.1699e2 3.202e-1 9.1698e2 3.318e-1 9.1697e2 3.422e-1 9.1697e2 3.516e-I 9.1696e2 3.602e-I IKr-85mn 96.3 .183 3.41e2 3.4458e0 2.9122e2 3.0981e0 2.4872e2 2.7602e0 2.1241e2 2.4429e0 1.8141e2 2.1516e0 1.5493e2 1.8880e0 1.3231e2 1.6519e0 iKr-87 527.99 .0528 3. 2e2. 1.7729e1 1.8520e2 1.0802el 1.0719e2 6.5219e0 6.2035e1 3.9117e0 3.5903ei 2.3348e0 2.0779el 1.3884e0 1.202661 8.232e-1 Kr-SB 1313.63 .117 5.97e2 8.2292e1 4.6644e2 6.7687ei 3.6443e2 5.5169el 2.8473e2 4.4670el 2.2246e2 3.5992e1 1.7381e2 2.8893e1 1.3580e2 2.3127e1 Xe-133 20.7 5.28 5.54e3 1.2033el 5.5098e3 1.2599e1 5.4797e3 1.3072el 5.4499e3 1.3473el 5.4201e3 1.3819el 5.3906e3 1.4121el 5.3612e3 1.4388el Xe-135 146.99 .384 1.81e3 2.7918el 1.6789e3 2.7262e1 1.5573e3 2.6379el 1.4445e3 2.5357e1 1.339803 2.4257el 1.2428e3 2.3117ei 1.1528e3 2.1968el 1-131 222.18 8.05 1.92e-1 4.476e63 1.913e-I 4.696e-3 1.906e-1 4.881e-3 1.899e-i 5.040e-3 1.893e-1 5.179e-3 1.886e-1 5.302e-3 1.879e-1 5.413e-3 1-132 1381.22 .0958 8.95e-1 1.297e-I 6.621e-1 1.010e-1 4.898e-I 7.796e-2 3.623e-I 5.977e-2 2.681e-l 4.560e-2 1.983e-I 3.466e-2 1.467e-1 2.627e-2 1-133 358.61 .875 5.97e-1 2.247e-2 5.776e-1 2.288e-2 5.589e-1 2,310e-2 5.407e-1 2.316e-2 5.232e-1 2.311e-2 5.062e-I 2.297e-2 4.898c-1 2.277e-2 1-134 1600.86 .0366 1.45eo 2.436e-1 6.588e-1 1.165e-1 2.993e-1 5.522e-2 1.360e-1 2.600e-2 6.178e-2 1.218e-2 2.807e-2 5.686e-3 1.275e-2 2.647e-3 1-135 967.27 .28 1.lleO 1.127e-1 1.0012e0 1.070e-1 9.031e-1 1.007e-1 8.146e-1 9.411e-2 7.348e-1 8.754e-2 6.628e-1 8.113e-2 5.979e-1 7.498e-2 Cs-134 929.26 750 3.03e-2 2.955e-3 3.030e-2 3.110e-3 3.030e-2 3.245e-3 3.030e-2 3.362e-3 3.030e-2 3.467e-3 3.029e-2 3.563e-3 3.029e-2 3.650e-3 Cs-136 1305.19 13 3.7le-3 .5.081e-4 3.702e-.3 5.337e-4 3.694e-3 5.556e-4 3.685e-3 5.745e-4 3,677e-3 5;911e-4 3.669e-3 6.060e-4 3.661e-3 6.195e-4 Cs-137 .95 11000 4.01e-2 3.997e-6 4.010e-2 4.208e-6 4.010e-2 4.390e-6 4.010e-2 4.550e-6 4.010e-2 4.692e-6 4.610e-2 4.821e-6 4.010e-2 4.939e-6 Te- 132 126.72 3.25 7.25e-3 9.640e-5 7.186e-3 1.006e-4 7.122e-3 1.040e-4 7.059e-3 1.068e-4 6,997e-3 1.092e-4 6.935e-3 1.112e-4 6.874e-3 1.129e-4 Sr-89 5.03 50.5 5.97e-4 3.151e-7 5.967e-4 3.315e-7 5.963e-4 3.457e-7 5.960e-4 3.580e-7 5.956e-4 3.690e-7 5.953e-4 3.789e-7 5.950W-4 3.880e-7 Sr-90 1.22 11000 5.12e-5 6.555e-9 5.120e-5 6.900e-9 5.120e-5 7.198e-9 5.120e-5 7.460e-9 5.120e-5 7.693e-9 5.120e-5 7.905e-9 5.120e-5 8.098e-9 Ba-140 110.67 12.8 5.54e-2 6.434e-4 5.528e-2 6.758e-4 5.515e-2 7.034e-4 5.503e-2 7.2736-4 5.490e-2 7.484e-4 5.478e-2 7.672e-4 5.466e-2 7.842e-4 MO-99 95.46 2.8 2.73e-2 2.735e-4 2.702e-2 2.849e-4 2.674e-2 2.942e-4 2.647e-2 3.018e-4 2.620e-2 3.080e-4 2.593e-2 3.132e-4 2.566e-2 3.176e-4 Ru-103 280.47 39.5 3.84e-1 1.130e-2 3.837e-1 1.189e-2 3.834e-I 1.239e-2 3.832e-1 1.283e-2 3.829e-i 1.323e-2 3.826e-I 1.358e-2 3.823e-i 1.390e-2 La-140 1427.68 4.67 1.07e-I 1.603e-2 1.052e-I 1.659e-2 1.034e-I 1.701e-2 1.016e-1 1.732e-2 9.985e-2 1.756e-2 9.814e-2 1.713e-2 9.646e-2 1.785e-2 Ce-144 10.77 284 1.71e-2 1.933e-5 1.710e-2 2.034e-5 1.710e-2 2.122e-5 1.709e-2 2.199e-5 1.709e-2 2.267e-5 1.709e-2 2.329e-5 1.709e-2 2.386e-5 NP-239 97.99 2.35 9.386-3 9.645e-5 9.265e-3 1.003e-4 9.152e-3 1.034e-4 9.041e-3 1.058e-4 8.930e-3 1.078e-4 8.821e-3 1.094e-4 8.713e-3 1.107e-4 9.5299e3 1.442562 9.0523e3 1.2214e2 8.6774e3 1.0452e2 8.3732e3 9.0430e1 8.1192e3 7.9106ei 7.9021e3 6.9946ei 7.7131e3 6.2488e1 .. LorA, p.,. rTrl. , -, h-/Y /P-- co I,-- o e, 44ed

LOoCA6 AIR RELEASED IMMERiSIONHALF-LIFEACTIVITY t =0 t = 1hr t = Ihr t = 2 hr t = 2 hr t z 3 hr t = 3 hr t = 4 hr t = 4 hr t 5 hr t 5 hr t 6 hr t = 6 hr DCF (days) INVENTORY DCF INVENTORY DCF INVENTORY DCF INVENTORY DCF INVENTORY DC? INVENTORY DCF INVENTORY DCF (Ci) (Ci) (Ci) Kr-85 3.03 3950 1.94e4 4.934e-3 1.9400e4 5.613e-3 1.9400e4 6.216e-3 1.9400e4 6.742e-3 1.9399e4 7.200e-3 1.9399e4 7.5998-3 1.9399e4 7.948e-3 Kr-85m 96.3 .183 8.3e5 6.7088o0 7.0885e5 6.5186e0 6.0538e5 6.1647e0 5.1701e5 5.710980 4.4154e5 5.2085e0 3.7709e5 4.6946e0 3.2205e5 4, 1936e0 Xr-87 527.99 .0528 1.62e6 7.1792ei 9.3758e5 4.7273ei 5.4263e5 3.0297el 3.1405e5 1.9020el 1.8176e5 1.1755e1 1.0519e5 7.1803e0 6. 0882e4 4.3466e0 Xr-88 1313.63 .117 2.35e6 2.5911e2. 1.8361e6 2.3032e2 1.4345e6 1.9927e2 1.1208e6 1.6888e2 8.7567e5 1.4090e2 6.8416e5 1.161992 5.3454e5 9.4950el Xe-133 20.7 5.28 5.88e6 1.0216e1 5.8479e6 1.1560ei 5.8160e6 1.2731el 5.7843e6 1.3734el 5.7528e6 1.4587el 5.7214e6 1.5311ei 5.6902e6 1.5927el Xe-135 146.99 .384 1.18e6 1.4558e1 1.0945e6 1.5363el 1.0152e6 1.5780el 9.4170e5 1.5877ei 8.7348e5 1.5721el 8.1021e5 1.5396el 7.5152e5 1.4937ei 1-131 222.18 8.05 3.92e3 7.310e-2 3.9060e3 8.287e-2 3.8920e3 9.144e-2 3.8780e3 9.883e-2 3.8642e3 1.052e-1 3.8503e3 1.106e-1 3. 836.. 1.153e-1 .1-132 1381.22 .0958 5. 53e3 6.411e-1 4.0910e3 5.396e-1 3.0264e3 4.420e-1 2.2388e3 3.547e-1 1.6562e3 2.802e-1 1.2252e3 .2.188e-1I 9.0641W2 1.693e-I 1-133 358.61 .875 7.84e3 2.360e-1 7.5855e3 2.598e-1 7.3393e3 2.783e-I 7.1010e3 2.921e-1 6.8705e3 3.018e-1 6.6475e3 3.082e-1 6&4317e3 3.119e-1 1-134 1600.86 .0366 8. 7e3 1.1770e0 3.9799e3 6.084e-i 1.8082e3 3.061e-1 8.2151e2 1.508e-1 3.7324e2 7.319e-2 1.6957e2 3.509e-2 7.7042el 1.668e-2 1-135 967.27 .28 6.91e3 5.610e-1 6.2329e3 5.757e-1 5.6222e3 5.751e-1 5.0713e3 5.627e-1 4.5744e3 5.420e-1 4.1261e3 5.160e-I 3.7218e3 4.868e-1 Cs-134 929.26 750 8. 64e2 6.739e-2 8.6397e2 7.667e -28.6393e2 8.489e-2 8.6390e2 9., 8.6387e2 9.833e-2 8.6383e2 1.038e-1 8.6380e2 1.085%-I Cs-136 1305.19 13 3.46e2 3.790e-2 3.4523e2 4.303e -2 3.4447e2 4.754e-2 3.4370e2 5.: 3.4294e2 5.483e-2 3.4218e2 5.774e-2. 3.4142e2 6.026e-2 Cs-137 .95 11000 5.42e2 4.322e-5 5.4200e2 4.917e -5 5.4200e2 5.445e-5 5.4200e2 5.! 5.4199e2 6.307e-5 5.4199e2 6.656e-5 5.4199e2 6.962e-5 Te-132 126.72 3.25 2.77ei 2.946e-4 2,7455e1 3.322e--4 2.7212el 3.646e-4 2.6971ei 3.! 2.6733e1 4.150e-4 2.6496el 4.341e-4 2.6262e1 4.500e-4 Sr-89 5;03 50.5 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Sr-90 1.22 11000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Ba-140 110.67 12.8 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Ho-99 95.46 2.8 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Ru-103 280.47 39.5 0 0 0 0 0 0 0 0 0 0 0 0 0 0 La-140 1427.68 1.67 0 0 0 0 0 0 0 0 0 0 0 0 .0 0 Ce-144 10.77 284 0. 0 0 0 0 0 0 0 0 0 0 0 0 0 Np-239 97.99 2.35 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1.191407 3.6518e2 1.0472e7 3.1323e2 9.4567e6 2.6607e2 8.7182e6 2.2483e2 8.1637e6 1.8965e2 7.7352e6 1.6013e2 7.395366 1.3563e2 Loc-A6 k4ELE--1E, ACr Vj~IrY /iJVEA1700 ~~ g ~ ~~ /~~ 7 i Lec A 6 & (&4~ XeIe&~4 /Vc43/4~/7 t( (C'j. (CLI

LOCAI4 AIR RELEASED I1MEISIONHALF-LIFEACT1VITY t =0 t= hr t =1 hr t = 2 hr t =2 hr t = 3 hr t =3 hr t =4 hr t = 4 hr t = 5 hr t =5hr t=6hrt=6hr DuF (days) INVENTOJRY DCF INfVENTORY DCF INVENTO~RY DCF IffEiTNORY DCF INVENTORY DCF INVENTORY DCF INVENTORY DCF CZ-/iý, (Ci) (Ci) (Ci) Kr-85 3.03 3950 6.45e5 4.910e-3 6.4500e5 5.588e-3 6.4499e5 6.189e-3 6.4499e5 6.714e-.33 6.4498e5 7.170e-3 6.4498e5 7.568e-3 6.4497e5 7.916e-3 Mr-85m 96.3 .183 2.77e7 6.7016e0 2.3657e7 6.5136e0 2.0204e7 6.1612e0 1.725407 5.7082eo 0 1.4736e7 5.2064e0 1.2585e7 4.6929e0 1.0748e7 4.1923e0 Kr-87 527.99 .0528 5.42e7 7.1895el 3.1369e7 4.7354ei 1.8155e7 3.0355e1 1.0507e7 1.9058el 6.0811e6 1.1780el 3.5195e6 7.1957e0 2.0369e6 4.3561e0 Kr-88 1313.63 .117 7.84e7 2.5874e2 6.1254e7 2.3006e2 4.7858e7 1.990802 3.739107 1.68702 2.9214e7 1.4080e2 2.2825e7 1.1610e2 1.7833e7 9.4885el Xe-133 20.7 5.28 1.96e8 1.0193el 1.9493e8 1.1537e1 1.9387e8 1.2708e1 1.9281e8 1.3711e1 1.9176e8 1.4563ei 1.9071e8 1.5287e1 1.8967e8 1.5903el Xe-135 146.99 .384 3.92e7 1.4476el 3.6360e7 1.5281el 3.3727e7 1.5699e1 3.1294e7 1.5797e) 2.9017e7 1.5649ei 2.6915e7 1.5320e1 2.4966e7 1.4864ei 1-131 222.18 8.05 1.96e5 1.094e-1 1.9530e5 1.241e-1 1.9460e5 1.369e-I 1.9390e5 1.480e-1 1.9321e5 1.575e-1 1.9252e5 1.656e-1 1.9183e5 1.726e-1 1-132 1381.22 .0958 2.77e5 9.612e-I 2.0492e5 8.092e-i 1.5159e5 6.631e-i 1.1214e5 5.321e-1 8.2%2e4 4.204e-1 6.1373e4 3.283e-1 4.5402e4 2.540e-1 1-133 358.61 .875 3.92e5 3.532e-1 3.7928e5 3.889e-1 3.6696e5 4.167e-1 3.5505e5 4.374e-1 3.4353e5 4.520e-1 3.3237e5 4.616e-1 3.2158e5 4.671e-1 1-134 1600.86 .0366 4.38e5 1.7616e0 1.9900e5 9.108e-1 9.0410e4 4.583e-1 4.1076e4 2.259e-1 1.8662e4 1.096e-1 8.4786e3 5.256e-2 3.8521e3 2.498e-2 1-135 967.27 .28 3.46e5 8.408e-1 3.1210e5 8.631e-1 2.8152e5 8.623e-1 2.5393e5 8.438e-1 2.2905e5 8.129e-1 2.0661e5 7.739e-1 1.8636e5 7.301e-1 Cs-134 929.26 750 1.73e4 4.039e-2 1.7299e4 4.596e-2 1.7299e4 5.090e-2 1.7298e4 5.522e-2 1.7297e4 5.897e-2 1.7297e4 6.224e-2 1.7296e4 6.510e-2 Cs-136 1305.19 13 6.91e3 2.266e-2 6.8947e3 2.573e-2 6.8794e3 2.a43e-2 6.8641e3 3.078e-2 6.8489e3 3.280e-2 6.8337e3 3.454e-2 6.818&5e3 3.605e-2 Cs-137 .95 11000 1.08e4 2.578e-5 1.0800e4 2.934e-5 1.0800e4 3.249e-5 1.0800e4 3.525e-5 1.0800e4 3.764e-5 1.0800e4 3.973e-5 1.0MOMe4.156e-5 Te-132 126.72 3.25 8.3e4 2.642e-2 8.2266e4 2.981e-2 8.1538e4 3.272e-2 8.0817e4 3.518e-2 8.0102e4 3.724e-2 7.9394e4 3.896L-2 7..8691e4 4.039e-2 Sr-89 5.03 50.5 1.52e4 1.921e-4 1.5191e4 2.185e-4 1.5183e4 2.418e-4 1.5174e4 2.622e-4 1.5165e4 2.799e-4 1.5157e4 2.952e-4 1.5l48e4 3.086e-4 Sr-90 1.22 11000 5.97e2 1.830e-6 5.9700e2 2.082e-6 5.9700e2 2.306e-6 5.9700e2 2.502e-6 5.9699e2 2.672e-6 5.%99e2 2.820e-6 5.9699e2 2.950e-6 Ba-140 110.67 12.8 7.37e4 2.049e-2 7.3534e4 2.327e-2 7.3368e4 2.571e-2 7.3203e4 2.783e-2 7.3038e4 2.966e-2 7.2873e4 3.123e-ý2 7.2709e4 3.259e-2 NO-99 95.46 2.8 3.69e4 8.850e-3 3.6521e4 9.968e-3 3.6147e4 1.093e-2 3.5776e4 1.173e-2 3.5409e4 1.240e-2 3.5046e4 1.295e-2 3.4686e4 1.341e-2 RU-103 280.47 39.5 1.77e3 1.247e-3 1.7687e3 1.418e-3 1.7674e3 1.570e-3 1.7661e3 1.702e-3 1.7648e3 1.816e-3 1.7635e3 1.915e-3 1.7623e3 2.002e-3 La-14J3 1427.68 1.67 3.69el 1.324e-4 3.6267el 1.480e-4 3.5646e1 1.612e-4 3.5035e1 1.718e-4 3.4434e1 1.804e-4 3.3844el 1.8710-4 3.3264e1 1.924e-4 Ce-144 10.77 284 1.96el 5.303e-7 1.9598el 6.035e-7 1.9596ei 6.683e-7 1.9594ei 7.250e-7 1.9592ei 7.742e-7 1.9590el 8.170e-7 1.9588e1 8.545e-7 Np-239 97.99 2.35 3.69e2 9.084e-5 3.6449e2 1.021e-4 3.6004e2 1.117e-4 3.5565e2 1.197e-4 3.5130e2 1.263e-4 3.4701e2 1.317e-4 3.4277e2 1.360e-4 3.9804e8 3.6616e2 3.4975e8 3.1399e2 3.1578e8 2.6670e2 2.9109e8 2.2537e2 2.7256e8 1.9013e2 2.5824e8 1.6057e2 2.4689e8 1.3605e2 Lor-Am \cll /i 5= ký~~'~ ,IK"77v 7-ý/'jl- o '<! 4-0"~ 66,ýE-L19, L~oC,/cl mo~4~/1 AeJL (ce)

FINAL September 1990 APPENDIX C EVALUATION OF LIMITING DOSE-RATE TOTAL BODY VERSUS SKIN To establish appropriate Radioactivity Release EALs, one must determine which dose-rate limit of Technical Specification 3.11.2.1.a. is more restrictive, the Total Body or Skin dose-rate limit. To do this, it is sufficient to compute the Total Body DCF and the Skin DCF for each accident type and to compare the ratio of these values to the ratio of the Total Body and Skin dose-rate Technical Specification limits. For simplicity, and to assure consistency of inputs, these calculations are made using the ODCM values for dose-rate conversion factors. The ODCM contains all the required data in consistent units and in a convenient format. Skin dose factors are not readily available in the ERPIPs or RADDOSE. Since the intent is to determine the limiting dose rate, it is preferrable to use one document which contains all the required inputs. The following Attachment 1 from the ODCM presents values related to the Total Body and Skin dose factors for the noble gases. The ODCM does not contain skin dose factors for iodines or particulates via either airborne or liquid pathways. Page 24 of the ODCM also presents formulae for determining the effective total body dose factor due to gamma emissions and the effective skin dose factor due to beta and gamma emissions. Using these values and equations, effective Total Body and Skin DCFs may be computed for each noble gas and for the noble gas distributions of each postulated accident. Table C-I presents the Total Body and Skin DCFs and the Skin to Total Body DCF ratio for all the noble gases. By inspection of Table C-I it is apparent that the noble gases will not cause a Skin dose rate that is 6 times the Total Body dose rate except when Kr-85 is dominant. Because of its long half-life, Kr-85 is most significant in those accidents which include some decay of the source term prior to release, e.g., the WGDTR and the FHI. Table C-2 shows the calculated effective Total Body and Skin DCFs 8T_9 B_-7,,,~fC

FINAL September 1990 for the source terms associated with WGDTR, FHI, and LOCAR. It is clear from this Table that the Skin DCF is not 6 times the Total Body DCF for any of these accidents. It is therefore concluded that the Total Body dose-rate limit is more restrictive than the Skin dose-rate limit of Technical Specification 3.11.2.1. TABLE C-I NOBLE GAS DOSE-RATE CONVERSION FACTORS mrem/hr per MCi/m3 Total Body Skin DFLSkin Isotope DCF DCF DCF(TB) Kr-85 1.84E-3 1.55E-1 84.24 Kr-85m 1. 34E-1 3.21E-1 2.40 Kr-87 6.76E-1 1.89E 0 2.80 Kr-88 1.68E 0 2.18E 0 1.30 Xe-133 3.36E-2 7.93E-2 2.36 Xe-135 2.07E-1 4.53E-1 2.19 TABLE C-2 EFFECTIVE TOTAL BODY AND SKIN DCFs FOR SPECIFIC ACCIDENTS TB SKIN Isotope DCF DCF WGDTR FHI LOCAR me/rper MCiZm3 (Ci-.- (_Ci) (Ci) Kr-85 .00184 .155 262 11 .229 Kr-85m .134 .321 441 5.49E-3 .0551 Kr-87 .676 1.89 240 7.33E-15 .0234 Kr-88 1.68 2.18 769 2.56E-5 .0779 Xe-133 .0336 .0793 53500 2250 1.36 Xe-135 .207 .453 2230 2.97 .365 Total 57442 2264 2.1104 Effective DCF (Skin) .132 .080 .256 Effective DCF (Total Body) .0657 .0337 .131 DCF(Skin) / DCF(TB) 2.01 2.38 1.96 G D1T

FINAL September 1990 APPENDIX D EVALUATION OF MAXIMUM ORGAN DOSE RATES Technical Specification 3.11.2.1.b. limits the dose rate to any organ, from 1-131 and all radionuclides in particulate form with half-life longer than 8 days, to not more than 1500 mrem per year (0.17 mrem/hour). The following evaluation was done to determine whether any Radioactivity Release EAL should be established with respect to this Technical Specification limit. Based on this evaluation and arguments presented herein, all the Radioactivity Release EALs are set based on the Total Body dose-rate limit. For the Calvert Cliffs Nuclear Power Plant, the Child Thyroid, Inhalation pathway, is the limiting maximum organ dose. (Ref: ODCM, p.16) Radioiodines are the predominant contributors to the Child Thyroid, Inhalation dose rate, and only the radioiodines are considered herein. (Te-132 may be neglected with no loss of accuracy.) However, all the radioiodines - not just 1-131 - are included in the evaluation. This is considered appropriate for accident evaluations, whereas the Technical Specification is meant to limit normal releases. A way to evaluate whether the maximum organ dose rate is limiting is to compare Maximum Organ DCF / Total Body DCF ratio to the fraction of the release which contributes to the maximum organ dose rate. For example, if the Maximum Organ DCF is 4 times the Total Body DCF, and the nuclides contributing to the Maximum Organ dose rate comprise 1/4 of the total release, then the Maximum Organ dose rate and the Total Body dose rate would be identical. (A radionuclide may contribute to both the Total Body and the Maximum Organ dose rates simultaneously.) The Maximum Organ dose-rate limit is three times the Total Body dose-rate limit. Therefore, nuclides contributing to the Maximum Organ dose rate would have to exceed 3/4 of the release before the Maximum Organ dose-rate limit would be more restrictive than the Total Body dose-rate limit. Stated another way, the Maximum Organ dose-rate limit will not control unless the fraction of the release which contributes to the Maximum Organ dose exceeds 3 times the Total Body DCF / Maximum Organ DCF ratio. J s_,D

FINAL September 1990 Table D-1 presents the data used to calculate effective Child Thyroid DCFs for each accident type contained in BG&E-EP9, along with the calculated result. Table D-2 presents the comparison of the parameters used to determine when the Child Thyroid, Inhalation dose-rate limit is more restrictive than the Total Body dose-rate limit. Some explanation is required for proper interpretation of the data. The Fuel Handling Incident results indicate that the Child Thyroid should be limiting. Due to the uncertainty in iodine washout in the Spent Fuel Pool, the EAL for this incident is based on the-Total Body dose-rate limit. This is discussed in detail in the section presenting the calculation of the Fuel Handling Monitor EAL. The Steam Line Break (SLB) consists predominantly of an iodine release, since noble gases are continuously removed from the steam cycle through the condenser off-gas system. However, the Technical Specification limiting dose equivalent 1-131 in the steam system effectively limits the consequences of a SLB. Also, a SLB in the Turbine Building results in essentially an unmonitored release. Therefore, no Radioactivity Release EAL exists for this event. The Steam Generator Tube Rupture (SGTRR or SGTRG) source terms presented in BG&E-EP9 shows that the Child Thyroid dose-rate limit controls in each accident. However, Radioactivity Release EAL for these accidents must consider both system design and reduction phenomena. Until such time as the Main Steam Isolation Valves close, releases from a SGTR will be via the Condenser air removal system, which exhausts to the Main Vent. There will be very effective iodine removal in the condenser. In fact, NUREG-1228 assumes complete iodine and particulate removal in the Condenser. Reduction of the radioiodines will leave only the noble gases in the release, so the Total Body dose-rate limit should control for these accidents also. The Total Body dose-rate limit is most restrictive for the LOCAR. For the LOCAG release the Child Thyroid is indicated as the controlling dose-rate limit, but consideration should be given to

FINAL September 1990 the most likely leakage pathways. For this accident, the most likely leakage is through containment penetrations into the Penetration Rooms. In an accident situation, the ventilation of these rooms draws air out of the rooms and through charcoal filters before discharging the exhaust to the Main Vent. This additional iodine reduction would result in the Total Body dose-rate limit being most restrictive. The LOCAM is purposely analyzed to be the worst case scenario. It is presumed that this accident leads to failure of the containment, so leakage from the containment would not necessaril y be filtered. In such circumstance, the Child Thyroid dose-rate limit would be controlling. However, there is no monitor which can be used for a Radioactivity Release EAL in this situation. Such an EAL would be superfluous in any case, as a General Emergency will have been indicated for other reasons already. 3D

Table D-l EFFECTIVE CHILD THYROID DOSE-RATE CONVERSION FACTORS (Rem/hour per Curie/cu.meter) Child Curies released from BG&E-EP9 Thyroid Isotope DCF FHI SLB SGTRR SGTRG LOCAR LOCAG LOCAM 1-131 1.96e6 8.61e-2 5.15e0 5.76e-2 1.18el 4.75e-5 9.69e-1 4.84ei 1-132 1.15e4 5.9e-11 2.44e0 2.69e-1 1.66ei 1.03e-4 6.39e-I 3.2ei 1-133 3.31e5 2.07e-2 8.55e0 1.79e-1 2.35ei 1.35e-4 1.78e0 8.89ei 1-134 3.11e3 5.3e-26 1.55e0 4.35e-1 2.63ei 7.59e-5 4.58e-1 2.29ei 1-135 5.74e4 1.17e-4 7.49e0 3.33e-1 2.07ei 2.07e-4 1.29e0 6.44ei Total 1.069e-1 2.518ei 1.2736e0 9.89ei 5.684e-4 5.136e0 2.566e2 Child Thyroid DCF 1.6425e6 5.3165e5 1.5366e5 3.2727e5 2.6581e5 5.0063e5 5.0049e5

TABLE D-2 EVALUATION OF LIMITING DOSE-RATE Accident Type PARAMETER WGDTR FHI SLB SGTRR SGTRG LOCj LOCAG LOCAM Total Body DCF 4.55ei 2.08ei 4.65e2 1.48e2 1.08e3 9.6:2el 2.43e2 2.43e2 Child Thyroid DCF 0 1. 64e6 5.32e5 1.54e5 3.27e5 2.646e5 5. 01e5 5e5 3*(TB DCF/CT DCF) Indeter 3.805e-5 2.622e-3 2.883e-3 9.908e-3 1.08!5e-3 1.455e-3 1.458e-3 Total Release 5.74e4 2. 27e3 4.77ei 2.87e2 3.67e3 2.1:1eO 2. 25e3 7. 52e4 Total Iodines 0 1. 07e-1 2.52ei 1.27e0 9.89ei 5.694ý- 4 5.13e0 2.57e2 Fraction lodines 0 4. 714e-5 5.283e-i 4.425e-3 2.695e-2 2.69 7e-4 2.28e-3 3.418e-3 Limiting Dose Rate TB CT CT CT CT TB CT CT

ATTACHMENT 1 NON-OPERATING COPY FOR. INFORMATION ONLY DOSE FACTORS FOR NOBLE GASES Dose to People + Dose to Air # Gamma-Body Beta-Skin Gamma Beta Nuclide K(i) L(U) M(U) N(i) AR-41 8. 840E+03 2.690E+03 9.300E+03 3.280E+03 KR-83M 8. OOOE-02 0.000E+00 1.930E+01 2. 880E+02 KR-85 1.610E+01 1. 340E+03 1. 720E+01 1.950E+03 KR-85M 1. 170E+03 1.460E+03 1.230E+03 1. 970E+03 KR-87 5.920E+03 9.730E+03 6 170E+03 1. 030E+04 KR-88 1.470E+04 2.370E+03 2.520E+04 2.930E+03 KR-89 1. 660E+04 1. 010E+04 1.730E+04 1. 060E+04 KR-90 1.560E+04 7.290E+03 1.630E+04 7.830E+03 XE-131M 9.150E+01 4.760E+02 1. 560E+02 1..110E+03 XE- 133 2.940E+02 3.060E+02 3.530E+02 1.050E+03 XE-133M 2. 510E+02 9.940E+02 3. 270E+02 1.480E+03 XE-135 1. 810E+03 1.860E+03 1. 920E+03 2.460E+03 XE-135M 3. 120E+03 7. 110E+02 3.360E+03 7.390E+02 XE-137 1. 420E+03 1. 220E+04 1.510E+03 1.270E+04 XE-138 8.830E+03 4.130E+03 9.210E+03 4.750E+03

                      +  --   mrem/yr per uCi/cu~m
                      #  --   mradlyr per uCi/cu.m Rev. I

6 October 1987 To: G. C. Rudigier From: E. T. Reimer Subj: Calvert Cliffs Nuclear Power Plant Accident Source Terms, BGE-EP9 A comparison was performed between subject core inventories of radionuclides and those determined by use of NUREG-0771 Table 3.2 values normalized to 2700 MWt full power. Table 1 illustrates this comparison and the percent error that the subject values vary from the NUREG-0771 values. It is also obvious that the subject study did not include all the radiologically important isotopes and the inventory for reactors that NRC, etc., expect to be potentially released to the atmosphere during an reactor accident. If the subject core inventories are to be accepted for use in emergency response assessment for offsite releases, the invento-ries sod contain all the radiologically important isotope inventories mentioned in NUREG-0771, and these latter inventories placed in ERPIP Appendix C.1 for potentia use in offsitd~se assessmen. Should you have any questions or comments concerning this matter, please contact me. AEugene Reimeir Plant Health Physicist Attachment Copy to RSS staff routing FILENO. AN3.A&7. gvrý

TABLE 1. COMPARISON BETWEEN NUREG-0771 AND NUREG-1226 DERIVED CORE INVENTORIES (MCi) Group/Radionuclide IFull Power Core Inventory NUREG-1226 NUREG-0771 I NUREG-1226 I % ERROR NOBLE GASES Krypton-85 0.455 0.645 41.76 Krypton-85m 19.719 27.700 40.47 Krypton-97 38.680 54.20.0 40.12 Krypton-88 55.365 78.400 41.61 Xenon-133 138.792 196.000 41.22 Xenon-135 28.062 39.200 39.69 Iodine-131 69.017 97.900 41.85 Iodine-132 97.837 138.000 41.05 Iodine-133 138.792 196.000 41.22 Iodine-134 154.719 219.000 41.55 Iodine-135 122.107 173.000 41.68 ALKALI METALS Rubidium-86 0.021 Cesium-134 6.143 8.640 40.65 Cesium-136 2.427 3.460 42.56 Cesium-137 3.868 5.420 40.12 TELLURIUM-ANTIMONY Telluriuma-127 4.778 Tellurium-127m 0.910 Tellurium-129 25.028 Tellurium-129m 4.323 Tellurium-13 Im 10.618 Tellurium-132 97.837 138.0.00 41.05 Antimony-127 5.006 Antimony-129 26.545 ALKALINE EARTHS Strontium-89 76.6.01 108.000 40.99 Strontium-90 3.034 4.260 40.41 Strontium-91 89.494 Barium-140 130.449 184.000 41.05 NOBLE METALS & COBAL Cobalt-58 0.637 Cobalt-60 0.235 Molybdenum-99 130.449 184.000 41.05 Technetium-99m 114.522 Ruthenium-103 89.494 127.000 41.91 Ruthenium-105 58.399 Ruthenium-106 20.478 28.800 40.64 Rhodium-105 40.197 RARE EARTHS, REFACTORY OXIDES & TRANSURANICS Yttrium-90 3.185 I

Yttrium-91 97.837 Zirconiun-95 122. 107 Zirconium-97 122.107 Niobium-95 122. 107 Lanthanum-140 130.449 184.000 41.05 Cerium-141 122.107 Cerium-143 106.180 Cerium-144 69.017 97.900 41.85 Praseodymium- 143 106.180 Neodymium-147 49.298 Neptunium-2 39 1365.169 1840.000 34.78 Plutonium-238 0.046 Plutonium-239 0.017 Plutonium-240 0 . 017 Plutonium-241 (Feeds 2.806 Americium-241 0.001 Curium-242 0.410 Curium-244 0.019

                               - ----   ~===    _______

a

 /

Wesi!nghouse Hucigl Instlnumenation and Electric Corporation Conriol Department liiSchilling Road Hunt Valley Maryland 21031 (301,667 1000 June 26, 1981 Baltimore Gas & Electric Co. Gas & Electric Building Baltimore, Maryland 21203 ATTN: Mr. Boyd Wylie -. Engineering Dept.

Subject:

Request by Pete Crinigan for various isotope response' sensitivity for the monitors at Calvert Cliffs Nuclear Plant.

Dear Boyd:

As requested by Mr. Pete Crinigan of your office several weeks ago, we have accumulated various reference documents which should give you the information you need. We have included several detailed sensitivity curves similar to the originals in your RMS manual, and in addition, we have included three tables giving the sensitivities of the process monitors to various isotopes. The tables include: 1., Noble Gas Monitors using 912NB3 G-M tubes and 6 inches of lead shielding.

2. Liquid Monitors using 6 S4 / 2 Scintillation tubes and 5.5 or 7.5 inches of lead shielding. According to our records, your liquid has 7.5 inches of shielding. Thus, you should use information under "Note 1".

3. Airborne Monitors using 6S4/2 Scintillation tubes and 4.5 inches of lead shielding.

We regret the delay in forwarding this information but will be glad to assist you in the future if possible. Sinerr ly,9 C. H. Griesacker RMS Proj. Engr. 301-667-5115 ` 05 o car CC: P. Crinigan

RrSPC:.SE OF Til- Vj'STCIIxCjOUE -,ICD'S CAS I0.:T. I 5 TO VARIOUS ZSO7O.pS CPH/10" 6 iu: Ci/Cc CPljs/10 -u C4/Cce 84 Br 236 *441 88 Rb 242 453 89 Rb * .. 150 279, - .. 89"

                                                            " .              "--*-..      129                                                           241

• Sr rZ 17.3 32 90 * - -

                                                              'C *      ..~ ,* . 5" . .. .. '

170 -316  : Zr95 S-249.--

                                                                 .... ** '*'""    " 213                "                 ' "

y 99 399 Z*. 8.5

  ,-          . h-95
   --         * *99              .
          -'*   *131 ."                                                                   106                                                           198 26                                                            4*.
                 -132 167                                                          309
                   *133                  .

112 '209*

• 134 180 335
• 125 233 TeI32
• 1. ~'"1

                ,re1 34 Cs1 3 4                                                                   .34.                                                            62 S.

13 6 V Cs 6 8.6 Cs 137 20 36 CsI3 o07 386 BaY 440 83 J 154 " 131 243 _ cet144

    -                 *~144           *'

365

      .-. ~.      Pr                                                                       195 i

4 4

                .      *t* %fl

• A SW. AQt."W.~.S.&.fl. jA'~W* .. '.fl.* fl..,m **. . --...-..--..-..-- ..---.. -

                                                              -.      ~ ClC  ~            ~          ~          P

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                                                                                                           . 8000
                  '35 Yr        -                                 ..      218                                       23000-          7*
               ~88.                         .     *8 K7                                                  18.9 13333)
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                                                                                                            . 0   .
                                                                         '::       .70

• -. ~~~1 .5M.- '-
• J . .*. . --

OI"OIL 60-.

                   ;'.sedon:       Note 1. 1- Z 17S5
                                          -                             ZRB-1752, 1-RE.S406zý'2RBTS406
                                          *~ ~              ~         ~ --~RE   ' 4-R-S2, r.-I-R    ~ 0- ~B-r-S SD0
                                                                                    ~ 2-RBS42            ~       -~S1,-
                                                                                                                  ~ -54.~ Z:

Note 2 0RE: Z219 1 0-

• Tbeoretical response calcul.ated f-.=n the knowrn responses Of the calibratic-.

Is+/-.otopes K=~ 8 and'X 39

THOEIA REP WF TMI)SHME 0F-LIME LIQUID WNITORS To YM~OUS ISOTOPES* Br-843.03 Rb-894.46 Sr-89 o Sr-90 0 Sr-91 2.06 Sr-92 2.50 Y-90 48 Y-91.0 Y-92 1 Z?-95 2.53

                                        .52 1-132                                 10.2 2.32 1-134                                 5.74 1-1 35                                3.5ii 4Te-l 32                               2.32 Te-1 34                                1.03 cs.1324                                5.83 Cs-136                                7.04.

Csr-i37 2.20 C¶-1l8 4.02 Sa-1 40 1.16 LA .140 4.56

                                         .06 Pr14                      I        .0

     .. e.

TABLE I CCoatimed) *tt

                                                 ,\
                                 . Resporw Isot~ae             106 cPmuCf/cc Isotme Kr-87                     3.48 Kr-88                    '387 Xe-I 33                   0 Xe-I 33                     .36 3.30 Xa-13S                    2.04 2.S8 MR-56                     3.09 Co-58                     3.38 p

5.16 Fe-59 2.65 0 Cr. 5l , 23 12

CP-604-A Page 1 of 1 ATTACH4ENT 9.2.2 RNS RESPONSE FACTORS (cpm/pCi/cc) COLUMN 1 COLUMN 2 COLUMN 3 MV NOBLE GAS MV GASEOUS WASTE GAS DISCHARGE ISOTOPE (RIC-5415) (RI-5415) (RI-2191) Ba-140 1.8 8.3E+07 1.5E+08 Ce-144 .95 1.OE+06 1.OE+06 Co-58 1.6 1.0E+06 1.0 Co-60 2.2 2.OE+08 1.0 Cs-134 1.3 3.4E+07 6.2E+07 Cs-137 1.4 2.OE+07 3.6E+07 Cs-138 2.2 2.1E+08 3.9E+08 1-131 1.5 2.6E+07 4.8E+07 1-132 2.1 1.7E+08 3.1E+08 1-133 2.0 1.1E+08 2.1E+08 1-135 2.0 1.3E+08 2.3E+08 Kr-85 1.7 3.5E+07 8.OE+03 Kr-85m 2.4E-8 5.5E+07 1.0 Kr-87 2.2 2.2E+08 2.3E+04 Kr-88 2.0 1.9E+08 1.5E+04 La-140 2.1 1.3E+08 2.4E+08 Rb-88 2.2 2.4E+08 4.5E+08 Xe-133 1.0 1.9E+06 3.2E+02 Xe-133m 2.4E-8 1.0E+06 1.0 Xe-135 1.9 7.OE+07 5.0E+03 Xe-135m 2.4E-8 1.0E+06 1.0 NOTE: Responses for isotopes not listed above may be obtained from the GSC.

T' CHARLES H. CRUSE Baltimore Gas and Electric Company Vice President Calvert Cliffs Nuclear Power Plant Nuclear Energy 1650 Calvert Cliffs Parkway Lusby, Maryland 20657 410 495-4455 AP March 6, 1997 U. S. Nuclear Regulatory Commission Washington, DC 20555 ATTENTION: Document Control Desk

SUBJECT:

Calvert Cliffs Nuclear Power Plant Unit Nos. I & 2; Docket Nos. 50-317 & 50-318 Independent Spent Fuel Storage Facility Docket No. 72-8 Revision to Emergency Action Levels Technical Basis Document

REFERENCE:

(a) Letter from Mr. D. G. McDonald, Jr. (NRC) to Mr. R. E. Denton (BGE), dated April 12, 1994, Emergency Action Levels, Calvert Cliffs Nuclear Power Plant Units 1 and 2 (TAC Nos. M87080 and M87081) Enclosed for your information is Revision 5 to the Calvert Cliffs Nuclear Power Plant Emergency Action Levels Technical Basis Document. The Technical Basis Document meets Regulatory Guide 1.101 criteria (i.e., NUMARC/NESP-007, Methodology for Development of Emergency Action Levels), and has been approved by the NRC (Reference a). The Emergency Action Level changes that will be effected by Revision 5 of the Technical Basis Document will be incorporated in Revision 18, Change 9, of Calvert Cliffs Emergency Response Plan Implementation Procedure 3.0, "Immediate Actions." Emergency Response Plan Implementation Procedure 3.0, Revision 18, Change 9, will be implemented approximately 90 days from the date of this letter, but not earlier than 45 days. This implementation date allows for staff training and for other internal document processing requirements. The Emergency Action Level Technical Basis Document, Revision 5, changes have been reviewed with appropriate State and local agencies. CN600001

.1' 17

    ~

Document Control Desk March 6, 1997 Page 2 Should you have questions regarding this matter, please contact Mr. T. E. Forgette, Director-Emergency Planning, at (410) 495-4996. Very truly yours, CIIC/GT/dlm

Enclosure:

Revision 5 to the Calvert Cliffs Nuclear Power Plant Emergency Action Levels Technical Basis Document cc: (Without Enclosure) D. A. Brune, Esquire H. 3. Miller, NRC J. E. Silberg, Esquire Resident Inspector, NRC Director, Project Directorate I-1, NRC R. I. McLean, DNR A. W. Dromerick, NRC J. H. Walter, PSC IIIIIIl IIiNIill0 0 iIIIIIl

I, Document Control Desk March 6, 1997 Page 3 bcc: (Without Enclosure) G. C. Creel R. E. Denton P. E. Katz P. G. Chabot J. R Lemons R. P. Heibel T. J. 0-amilleri K. R. Eser S. B. Haggerty L. A. Larragoite K. R. Neddenien OSSRC Secretary M. G. Polak Correspondence Evaluator (With Enclosure) G. Tesfaye T. E. Forgette File 35.03 Electronic Docket File CHC/GT/gt/dlm NRC 97-014 CN600003

ENCLOSURE CALVERT CLIFFS NUCLEAR POWER PLANT EMERGENCY ACTION LEVELS TECHNICAL BASIS DOCUMENT REVISION 5 CN600004 Baltimore Gas & Electric Company Docket Nos. 50-317 and 50-318 Independent Spent Fuel Storage Facility Docket No. 72-8 March 6,1997

1 ENCLOISURE CALVERT CLIFFS NUCLEAR POWER PLANT EMERGENCY ACTION LEVELS TECHNICAL BASIS DOCUMENT REVISION 5 Only the revised pages of the Technical Basis Document are included in this transmittal. - New words/information are identified by bold letters and revision bars. Deleted words/information are identified by line-out and revision bars. Typographical and reference corrections are identified by revision bars only. SPECIFIC REVISION ITEMS PAGE ITEM Updated procedure reference from CCI-.154 to RM-.I - 100. 0a Adde qusinadase liing the use of an alarm rather than a value. Renoverted mifssingop enuber. Updated prorecedure refeenc fromw C-14toR-lO 4 Al...dA apytolekgewthnth apctyehofea chargingwpum. Adde Areed au to apd to leakagiing the uaactof a charratherhng p p Aed Addd aswe eplinig qestonan heus ofanalrm aterthn6a0valu reference to cooldown.

                                                                       " ...                                                           ++"V' . . ".A
            *x           ?  W ...SJ.... *    ".   .'

Updated discussion of AOP-6A vis-ea-vis Chemistry Action Level. Added a reference to Improved Technical Specifications.

                                                                                                    .......         Ii.i                 l l l ll II.. . .

P ENCLOSURE CALVERT CLIFFS NUCLEAR POWER PLANT EMERGENCY ACTION LEVELS TECHNICAL BASIS DOCUMENT REVISION 5 PAGE ITEM Added a reference to Improved Technical Sp~eciflcations. Revised EAL to refer to Improved Technical Specifications. Added a reference to Improved Technical Specifications. Page overflow

  .... 6.XtCI~4                                      ...........                                  :..~               4..............
                                                                                                                           . 4' . 4...                           . . .                         ........                          .Y.r                                   4
                                      ........... R Added a reference to EOP-6.

Added a new EAL for EOP-6 implementation. Subdivided EAL for EOP-5 and EOP-8 implementation. Added a reference to EOP-6.

          "  " *i".
         "4'*    "                .. *..   ..          "'     ....          ..   .  ,4
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                  *..*..*.*.              :: Loss    ...               **

Added a Nuclear Management and Resources Council (NUMARC) question and answer explaining guidance on cross-tied units. Corrected AOP-3F Mode reference to shutdown. Deleted discussion on EOP-2 as an entry condition of the EAL. Added a reference to credit taken for ability of Calvert Cliffs to cross-tie units.

 **     .,4.,...
                        ,*.   ... q4.
                                       **     ...... *     *:      :**.>.      *r", ..  .-         M+..
                                                                                                    *.....+*     * *        ,,*.+ ... .***      **:*..      ..    .   .    ..,.   *.   .    .    , ,. *    ..  ....:.94.:.-. ..1/2:*.,.x.:.  ,*..:.".'.4.'. ..   . ..  ,,..*
              ............                                                                                     4..m4tA Revised EAL. Combined two EALs into one. Eliminated EOP-2 as an entry condition.

Added reference to applicability of IA DG Bus 14 to EAL entry condition. Added question and answer explaining why reference is included.

                                                  ..     .......                 .           .     .             .     ....                                         M..         .      .             .               .               .             .           .

AdLm~tinitrativ chne4Vst~SiWittaetandardeltedstike Cagdodt ous

                   ... . .....  .               .               .          .            .              .      444    .        .                  .

i ~~iiii!:: :*..*;* :*Administrative s ** ~ ~

• change. * **!Changed
• bold ** *to standard,

                                                                                                                                                           .*.*                      deleted  : '4* 4 striket*:" outs..                       44 .::* 44.
                                                                                                                                                                                                                                                           '".4'$.".4*(?.?,.'

4... ~ ~ ~~ ... .... ... 4.. *4:.'44.4.4...4...4...f4"..4...Y.4

                                                                               .............                                                                                             -. - - l l I II IIl.I.l                                                                .

Administrative change. Changed bold to standard, deleted strike outs. CN600006 2

I1 ENICLOSURE CALVERT CLIFFS NUCLEAR POWER PLANT EMERGENCY ACTION LEVELS TECHNICAL BASIS DOCUMENT REVISION 5 PAGE ITEM XAdded reference explaining acceptabijity of back up power sources. i**oY*

         **. .. *.-*z*. ............      . *tan.*                z              * ............ ....................................................
                                                =. i............ ...................                                                                . . . .....................

Revised reference to Calvedt Cliffs status as a one-hour station blackout coping category plant. Added reference explaining the basis of station blackout core uncovery time of four hours. Page overflow. Added a reference to explain that Security defines intrusion and sabotage. Deleted reference to "hostile manner."

                          ~    2..    .0                                                                 .
                                                                                                ........................ .. ..... .. . ...CC k2     . .
                                                                                                                                            . .4.C.C     ...... ....:C:

Added a referehce to explain that Security defines intrusion and sabotage. Deleted reference to "hostile manner." Added a reference to explain that Security defines intrusion and sabotage. Deleted reference to "hostile manner." Revised EAL to refer to "Areas of Concern for Safe Shutdown." Rearranged two EALs into one integrated statement. Deleted EAL to incorporate it into a single integrated statement. Added a reference to NRC Information Notice 96-71. Added a new EAL for AOP-9 implementation. Renumbered EAL. Renumbered EALs. CN600007 3

ENCLOSURE CALVERT CLIFFS NUCLEAR POWER PLANT EMERGENCY ACTION LEVELS TECHNICAL BASIS DOCUMENT REVISION 5 PAGE ITEM Revised EAL to refer to "observable damage" and "Area of Concern for Safe Shutdown." Typographical errors corrected: flammable. Renumbered EAL Added new EAiL for EOP-4 implementation and its basis. Revised EAL to refer to "observable daage" rather than securit report. Revised EAL to refer to "observable" rather than "visible," and adds plant protected area. Corrected EAL to refer to "protected area" rather than "safe shutdown." Added a reference to "potential damageY. Removed reference to "maintaining safe shutdown." Added clarification explaining that effect of "safe shutdown" is escalation to Alert. Removed reference to table of "Areas of Concern for Safe Shutdown." Revised BAL to refer to "observable damage" rather than safe shutdown.".

                                                                                                       .                                                .... . .           ..            4::: 44:5:

4:44:::::::

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Revised EAiL:*::::::*

                                                                 ... .:..:                      : 4.

to refer to "Areas . of Concern for Safe ..Shutdown."

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                                                                                                                                                                          .f#:Q44:p Revised EAL to refer to "Areas of Concern for Safe Shutdown" and "observable
                                          ~ damage."

4:.::4fr4t4*444 0 .... .44:. s. . 0'0 .2.......... 4-.:s.:.:.:.x.>s..55 . 4 Revised EALs to refer to "Areas of Concern for Safe Shutdown" and "observable damage." g "n .... >II:I.II*lIIII:II

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                                                                                                .. 44 45.

CN600008

CALVERT CLIFFS NUCLEAR POWER PLANT UNITS I & 2 EMERGENCY ACTION LEVELS TECHNICAL BASIS DOCUMENT REVISION 5 PREPARED: DATM: e/s..97 Emergency Planning - GI. Rudigier REVIEWED: al y DATE: 2- -- /9_ P"r perations - J.V. Grooms REVIEWED: DATE: pe1ratio sTr - LT. Huber REVIEWED: emsty&rrms:iZe DATE: REVIEWED: I a DATE: ________ Radiation ety - E. H. Roach REVIEWED: 4; DATE: _______ REVIEED: e~ign En~gi ring-Mech *al-C.3. Ludlow DATE: 3A2fz-REVIEWED: DATE: rEgine REVWED . - Security - D. M. Dean REVIEWED: ( /- Icensin .. sorne APPROVED:Pn DATE: /__ DATE: 5-- 1 . . DATE: Plant General Vanager Effective Date: with ERPIP 3.0, Revision ...__._, Change CN600009 Rev. 5 Calvert Cliffs Basis Document EAL Basis Cliffs EAL Document Rev. 5

LIST OF EFFECTIVE PAGES PAGE REVISION i 3 ii 1 iii 5 A:l 1 A:2 5 A:3 I G:1 0 G:2 0 G:3 0 G:4 0 G:5 0 G:6 0 G:7 0 G:8 3 G:9 0 G:IO 0 R:A 0 R:2 0 R:3 I R:4 0 R:5 1 R:6 0 R:7 0 R:8 0 R:9 0 R:10 0 R:I1 5 R:12 5 R:13 0 R:14 5 R:15 0 R:16 5 R:17 0 R:18 0 R: 19 0 R:20 0 R:21 0 R:22 0 R:23 0 R:24 0 B:A 0 B:2 0 B:3 5 B:4 5 B:5 5 B:6 0 B:7 0 CN600010 H -

9 tp LIST OF EFFECTIVE PAGES PAGE REVISION B:8 0 B:9 0 B:10 0 B:ll 0 B:12 0 B:13 0 B:14 0 B:15 0 B:16 0 B:17 0 B:18 0 B:19 0 B:20 0 B:21 0 B:22 0 B:23 0 B:24 1 B:25 5' B:26 5 B:27 0 B:28 0 B:29 0 B:30 0 B:31 0 B:32 0 B:33 0 B:34 1 B:35 I B:36 0 B:37 0 B:38 0 Q:I 0 Q:2 0 Q:3 0 Q:4 0 Q:5 0 Q:6 0 Q:? 0 Q:8 " Q:9 0 Q:10 0 Q:II 0 Q: 12 0 Q:13 0 Q:14 3 Q:15 3 Q:16 3 Q:17 3 Q:18 5 Q:19 3 Q:20 3 Q:21 3 S.......... 1 #1111111 i IIiCN600011 M.. I1i

                                                -i      ev. 5 R

LIST OF EFFECTIVE PAGES PAGE REVISION E:1 5 E:2 5 E:3 4 E:4 5 E:5 5 E:6 5 E:7 3 E:8 5 E:9 I E:10 0 E:l1 1 E:12 0 E:13 0 E:14 0 E:15 5 E:16 5 T:1 5 T:2 5 T:3 5 T:4 4 I:1 3 1:2 3 1:3 5 1:4 5 1:5 3 N:A 0 N:2 0 N:3 0 N:4 5 0:1 5 0:2 5 0:3 0 0:4 0 0:5 5 0:6 0 0:7 0 0:8 5 0:9 0 0:10 5 0:11 5 0:12 0 0:13 0 0:14 0 0:15 0 0:16 0

            "-- iJJIJ1Ji  !AllIiJfIIIIIlll 1i101         Rev. 5 CN60001 2

TABLE OF CONTENTS TABLES Table G-1: Comparison of NUMARC Guidelines to BGE ICs NUMARC Abnormal Radiation Levels/Radiological Effluent Category ........................................ G:6 Table G-2: Comparison of NUMARC Guidelines to BGE ICs NUMARC Hazards and Other Conditions Affecting Plant Safety Category .................................. G:7 Table G-3 Comparison of NUMARC Guidelines to BGE ICs NUMARC System Malfunction Category ............................................................................... G:8 Table G-4: Comparison of NUMARC Guidelines to BGE ICs NUMARC Fission Product Barrier Degradation Category ....................................................... G:10 Table G:5 Comparison of NUMARC Guidelines to BGE EALs NUMARC Fission Product Barrier Degradation Category ....................................................... G:11 Table B-i: SAE Barrier Loss/Potential Loss Combinations for CCNPP Logic .............................. B:8 Table B-2: SAE Barrier Loss/Potential Loss Combinations for NUMARC Logic ...................... B:9 Table E-1: Effects of Lost 125 Volt DC Buses 11, 21, 12 and 22 ............................................. E:5

                                                                                                             *CICN600013   10IIiiI011i3ii IIIi Calvert Cliffs EAL Basis Document                            °.,

Rev, 5

ADMINISTRATIVE CONTROL OF THE EAL TECHNICAL BASIS Administrative revisions shall not change the intent of the Basis AND shall not cause a wording difference with ERPIP 3.0, Attachment 1. IV.B.1.b. Administrative revisions shall be approved by the Director-Emergency Planning. C. Administrative revisions approved by the Director-Emergency Planning will be distributed in accordance with PR-2-100, Document and Drawing Control.

2. Technical revision.

a. Technical revisions shall be reviewed by:

(1) Emergency Planning (2) Nuclear Operations (3) Operations Training (4) Chemistry Programs (5) Radiation Safety (6) Nuclear Engineering (7) Design Engineering (8) Nuclear Security (9) Licensing

b. The Emergency Planning reviewer will collect and reconcile review comments. Reviews will be documented on the Basis review/approval sheet.

c. Technical revisions shall be approved by the Director-Emergency Planning. The Director will consider review comments and their reconciliation.

d. Technical revisions shall be submitted to POSRC and the Plant General Manager in accordance with NS-2-101, Conduct of the Plant Operations and Safety Review Committee/Procedure Review Committee/Qualified Reviewer.

e. Technical revisions approved by the Plant General Manager shall be submitted to the NRC for information in accordance with GG-t544 RM-1-100, Preparation of NRC Correspondence. This submittal shall specify that a revision to ERPIP 3.0, Attachment 1, Emergency Action Levels, to implement the Basis document change, will be processed in forty-five (45) days.

f. After action IV.B.2.e. is complete (i.e., the correspondence is mailed) then a revision to ERPIP 3.0, Immediate Actions, Attachment 1, Emergency Action Levels may be initiated in accordance with ERPIP 900, Preparation of Emergency Response Plan and Emergency Response Plan Implementation Procedures. The effective date

                                                                         .. 1111111N1 CN600014 ill 00i H 4ill 11111111 Hil0l       ill Calvert Cliffs EAL Basis Document                  A:2                                                 Rev. 5

RADIOACTIVITY RELEASE RAI Threshold for RI-5421, RI-5422 Release Rate = 3.2 E+7 giCi/sec (see above) 3 Release Coefficient (for SG Tube Rupture) = 6.1 E+2 uCi/cm rem/h Atmospheric Dump Valve Flow Rate = 1.4 E+6 cm 3 /sec Safety Valve Flow Rate = 2.4 E+6 cm 3 /sec Main Steam Monitor Reading (rem/h) = Release Rate Release Coefficient x Flow Rate For safety valve rem/h = 3.2 E+7 6.1 E+2 x 2.4 E+6

                                                = .022 rem/h (read as .02) (0.2 mSv/h)

For atmospheric dump valve rem/h = 3.2 E+7 6.1 E+2 x 1.4 E+6

                                                = .038 rem/h (read as .04) (0.4 mSv/h)

The minimum reading for RI-5421/5422 is 10 mrem/h due to the "keep alive" source. Twenty mrem/h would be difficult to read accurately. The high alarm setpoint for these monitors is set at 47 nurem/h

• 5 mreml/h. Therefore, for human factors reasons, the existence of the high alarm setpoint is used as the threshold for this EAL.

Thus, EAL 2 uses the lower value and is written as: Valid Main Steam Effluent Monitor (RI-542 1 RI-5422) High Alarm for GREATER THAN 15 Minutes CCNPP Ouestions and Answers (Radioactivity Release)

• Why isn't a value given for the EAL 2 monitor reading?

It is difficult to readthis monitor at the response level that is requiredL it is more appropriateto use the alarm set point in considerationof humanfactors. Valid means that the indication is from instrumentation determined to be operable in accordance with the Technical Specifications or has been verified by other independent methods such as indications displayed on the control panels, reports from plant personnel, or radiological survey results. Based on the March 14, 1993 SG tube rupture event at Palo Verde Unit 2, the main steam effluent monitors (RI-5421, RI-5422) _may read N 16 immediately following SG tube rupture and prior to reactor trip. However, given the short half-life of N16 , this should clear within the first minute following reactor trip. Although Calvert Cliffs does not have a perimeter monitoring system, field monitoring could reliably detect radioactive releases. Thus EAL 3 is written as: Field Survey Dose Rate Reading of 10 mrem/h or greater at Site Boundary Calvert Cliffs EAL Basis Document R: 11 Rev. 5 CN600015

RADIOACTIVITY RELEASE Sourc Documents/References/Calculations:

1. System Descriptions a No. 15, Radiation Monitoring System

2. Off-Site Dose Calculation Manual (ODCM) for the Baltimore Gas & Electric Company Calvert Cliffs Nuclear Power Plant

3. Radioactivity Release Emergency Action Levels, J.B. McIlvaine, JSB Associates, Inc., September 1990

4. Emergency Response Plan Implementation Procedures a ERPIP 821, Accidental Radioactivity Release Monitoring and Sampling Methods

5. BG&E Internal Memorandum, L. R. Hill (Nuclear Plant Operations) to R. L. Wenderlich, CE Operations Subcommittee Meeting - Trip Report, April 16, 1993

6. 10 CFR Part 20, Standards for Protection Against Radiation; Final Rule, 56 FR 23360, May 21, 1991

7. Calvert Cliffs Instructions

       *CCI-302, Calvert Cliffs Alarm Manual, Main Steam Effl Rad Monitor 2C24B CN600016 Calvert Cliffs EAL Basis Document                        R:12                                              Rev. 5

RADIOACTIVITY RELEASE Thus, EAL 1 is written as: AOP-6E, Loss of Refueling Pool Level, is Implemented AND Valid Containment Radiation Alarm (RI-15316A/B/C/D) CCNPP Questions and Answers (Radioactivity Release) ,. Why isn't a value given for tie EAL 1 monitor reading? Since the alarmset point and the action level are the same, humanfactor considerationIs to reference the alarm to eliminate the need to visuallyfollow a monitor output duringa containmentevent Thus, EAL 2 is written as: AOP-6D, Fuel Handling Incident, is Implemented AND ANY of the Following:

    - Valid Containment Radiation Alarm (RI-5316A/B/C/D)
    - Valid Fuel Handling Area Ventilation Exhaust Radiation Monitor (RI-5420) Reading of AT LEAST 2E+4 CPM
    - Valid Spent Fuel Service Platform Monitor PR-7025) Reading of AT LEAST 100 mrem/h Valid means that the indication is from instrumentation determined to be operable in accordance with the Technical Specifications or has been verified by other independent methods such as indications displayed on the control panels, reports from plant personnel, or radiological survey results.

The containment radiation alarm corresponds to a dose rate of 200 mrem/h. The value for RI-5420 was determined based on a fuel handling accident damaging one fuel rod in an average (tupeaked) fuel assembly. The results of the calculation, showing RI-5420 response versus age of the assembly (time after shutdown), is shown as Figure RI. The value of 2E4 CPM corresponds to the minimum expected response and is significantly higher than the alarm setpoint of 600 CPM. One hundred mrem/h is used for the Service Platform Monitor (RI-7025) because it corresponds to the administrative limit for a high radiation area and is significantly higher than the dose rates expected for fuel handling activities. Expected increases in monitor readings due to controlled evolutions (such as lifting the reactor vessel head during refueling) should not result in emergency declaration. Nor should momentary increases due to events such as resin transfers or controlled movement of radioactive sources result in emergency declaration. In-plant radiation level increases that would result in emergency declaration are also unplanned,e.g., outside the limits established by an existing radioactive discharge permit. Source Documents/References/Calculations:

1. System Descriptions

• No. 15, Radiation Monitoring System

2. Abnormal Operating Procedures

• AOP-6D>, Fuel Handling Incident

    " AOP-6E, Loss of Refueling Pool Level

3. Ogden Calculation #RA-1, 0-RI-5420 Detector Response to Fuel Handling Accident CN600017 Calvert Cliffs EAL Basis Document R:14 Rev. 5

RADIOACTIVITY RELEASE For areas requiring infrequent access, the (Site-Specific) value(s) should be based on radiation levels which result in exposure control measures intended to maintain doses within normal occupational exposure guidelines and limits (I.e., 10 CFR 20), and in doing so, will impede necessary access. For many areas, it may be possible to establish a single <Generic> EAL that represents a multiple of the normal radiation levels (e.g., 1000 times normal). However, areas that have normally high dose rates may require a lower multiple (e.g., 10 times normal). Plant-Specific Information The control room is required to be continuously occupied following design basis accidents. All actions required to achieve and maintain cold shutdown can be accomplished from the control room. Post-accident doses have been evaluated and shown to be less than limits based on GDC 19. On a control room high radiation signal, the control room emergency ventilation system automatically switches into a recirculation mode of operation with flow through the HEPA filters and charcoal absorber banks. EAL 1 is based on the GDC 19 limit recommended by NUMARC. Thus, EAL I is written as: Valid Control Room Radiation Monitor a.-5350) Reading GREATER THAN 15 mrem/h This corresponds to a dose rate of 0.15 mSv/h. Valid means that the indication is from instrumentation determined to be operable in accordance with the Technical Specifications or has been verified by other independent methods such as indications displayed on the control panels, reports from plant personnel, or radiological survey results. EAL 2 addresses event sequences outside the plant design basis. Entry into any area with exposure rates of at least 10 Rem/h (100 m Sv/h) could result in an individual exceeding 10 CFR 20 limits (5 REM/yr) with approximately 30 minutes., Thus, EAL 2 is written as: Exposure Rate of 10 rem/h or greater in Areas Required to Ac.*i'e ofr intW-in Sgo Shutdowirn an Area of

 ..Concern for Safe Shutdown R.eq.ied means that ent*,; int" the or.a is not options! and is imp..a.iv" based cn wd.itng eendifte"*.

Areas of concern for Safe Shutdown are listed below. Areas of Concern for Safe Shutdown

   " Control Room                                        *Electrical Penetration Rooms
   " Control Room HVAC Room

• Auxiliary Feedwater Pump Room

   " Cable Spreading Room                                - Charging Pump Rooms

• Cable Chases
• Diesel Generator Rooms "Switchgear Room
• Diesel Generator Building (0C/1A)

   "ECCS Pump Room                                       - Refueling Water Tank (RWT) 11(2 1)

• Service Water Pump Room - Condensate Storage Tank (CST) 12
• Component Cooling Pump Room
• Pretreated Water Storage Tank (PWST) 11(21)

  " Main Steam Penetration Room

• Fuel Oil Storage Tank (FOST) 12 This list of Safe Shutdown areas is displayed on the EAL Tables to assure that all areas related to Safe Shutdown are considered by the SEC.

Expected increases in monitor readings due to controlled evolutions (such as lifting the reactor vessel head during refueling) do not result in emergency declaration. Nor should momentary increases due to events such as resin transfers or controlled movement of radioactive sources result in emergency declaration. In-plant radiation level increases that would result in emergency declaration are also unplanned,e.g., outside the limits established by an existing radioactive discharge permit. The containment radiation monitor readings should only apply to this IC when personnel are in containment for normal maintenance, inspection, surveillance, testing, or refueling activities. Source Documents/References/Calculations: T IIIi iiUHll 11lliIl H i

1. System Descriptions CN600018 Calvert Cliffs EAL Basis Document R: 16 Rev. 5

FISSION PRODUCT BARRIER DEGRADATION Calvert Cliffs Units 1 and 2 are Combustion Engineering designed reactors. These reactors use a programmed pressurizer water level that varies as a function of T ava and load. The Chemical Volume Control System includes three fixed flow positive displacement charging pumps and a variable letdown system. Each charging pump has a capacity of 44 GPM. The letdown system valves regulate letdown flow from 28 GPM to 128 GPM. The nominal configuration is one charging pump with -40 GPM letdown flow. The letdown flow is varied as necessary to maintain programmed pressurizer level. Additional charging pumps are automatically started when necessary to maintain pressurizer level. AOP-2A, Excessive Reactor Coolant Leakage, is implemented if any entry conditions are met; this includes the results of STP-0-27-1/2, Reactor Coolant Leakage Evaluation. STP-0-27-1/2 wil indicate leakage in excess of Technical Specification 3.4.6.2 allowable limits. Control room personnel require approximately 5 to 15 minutes to implement AOP-2A if RCS. leakage exceeds the capacity of one charging pump. In general, Calvert Cliffs does not distinguish between identified or unidentified leakage when AOP-2A is implemented. Per AOP-2A, if leakage exceeding the capacity of one charging pump (11 GPM leakage with minimum letdown flow or greater than 39 GPM with letdown isolated) could not be isolated, then the reactor must be shutdown (tripped) and cooled down. IfRCS leakage-is less than the capacity of one charging pump, STP-0-27-1/2 would be performed to determine the leak rate and the reactor would be maintained at power. It requires approximately 3 to 6 hours to perform STP-0-27-1/2 to determine the amount of unidentified leakage. Calvert Cliffs EALs have been written to be consistent with procedural requirements. These leakage rates are very similar to the NUMARC generic leakage. AOP-2A specifies certain flow paths that can be isolated to terminate RCS leakage. If isolation of the leakage path is successful (e.g., isolating a leaking pressurizer power operated relief valve), reactor operation can continue and this EAL does not apply. However, if RCS leakage could not be isolated, then under these conditions.the reactor would have to be shut down in accordance with technical specifications. The EAL language was picked to assure that: (1) leakage is greater than net RCS make-up flow threshold of 11 GPM, and (2) Such leakage could not be isolated in accordance with procedural requirements. Thus, the Calvert Cliffs EAL is written as: AOP-2A, Excessive Reactor Coolant Leakage, Is Implemented For RCS Leakage Exeeeding within the l Capacity of One Charging Pump AND Reactor Shutdown OR Cooldown is Required NUREG 1449 raises concerns regarding events involving leakage through RCS temporary boundaries. RCS leakage EALs apply to all operational modes at Calvert Cliffs. This will assure that leakage is appropriately addressed for cold shutdown and refueling modes and address NRC concerns about leakage through temporary RCS boundaries as they apply to EALs. Source Documents/References/Calculations:

1. Technical Specifications

         - TS 3.4.6.2, Reactor Coolant System Leakage

2. Abnormal Operating Procedures

         - AOP-2A, Excessive Reactor Coolant Leakage

3. Surveillance Test Procedure (STP) 0-27-1/2, RCS Leakage Evaluation

4. NUREG 1449, Shutdown and Low-Power Operation at Commercial Nuclear Power Plants in the United States, Draft for Comment, February 1992 1111141 hl hI!I CN600019 111ff 1Diii11!111fII ff Calvert Cliffs EAL Basis Document B:3 Rev. 5

FISSION PRODUCT BARRIER DEGRADATION Emeraency Classification Level: UNUSUAL EVENT Applicable Operational.Modes: ALL Calvert Cliffs Initiating Condition: BU3 Fuel Clad Degradation NVUMARC Recognition Category: System Malfunction NUMARC Initiating Condition: SU4 Fuel Clad Degradation Barrier: Fuel Clad NUMARC Generic Basis: This IC is included as an Unusual Event because it is considered to be a potential degradation in the level of safety of the plant and a potential precursor of more serious problems. <Generic> EAL 1 addresses (Site-Specific) radiation monitor readings such as failed fuel monitors, etc., that provide indication of fuel clad integrity. <Generic> EAL 2 addresses coolant samples exceeding coolant technical specifications for iodine spike. Escalation of this IC to the Alert level is via the <Fission Product Barrier Degradation EALs>. Plant-Specific Information: A significant rise in the count rate on the Activity Monitor or valid actuation of the "RADIATION MONITOR LEVEL HI" alarm can be due to either fuel clad failure or to crud burst. In accordance with AOP-6A, the response to high RCS activity level is to notify Plant Chemistry to perform a sample analysis to determine what radionuclides caused the radiation alarm. This means that the monitor indications are not sufficient alone to determine whether fuel clad damage has occurred at Calvert Cliffs. Thus, <Generic> EAL 1 is not appropriate for use at Calvert Cliffs. Clad damage is determined from specific activity levels contained in reactor coolant samples. Per AOP-6A, when RCS activity is less than Chemistry Fuel R"liabiliP- Plan Action Level 1 values, the operator may return to the appropriate operating procedure. Per CP-204, Chemistry Action Level 1 is for specific activity levels greater than 0.5 pjCi/gram 1131 DEQ or greater than 50/Ebar ;PCi/gram of gross radioactivity. 4 is defined as D es Equ-vhe'al PR 4 -RDE* -of at-least th Technical Specification Section 3.4.8. (Improved Technical Specifications Section 3.4.15) requires the specific activity of the reactor coolant to be within limits..'- are:

a. NTet f-fge .ehan1 gCi/gram 1131 DEQ.

b. Ntem 100/Ebar tiCi/gram of gross radioactivity.

The specific activity of the reactor coolant may be as high as the limits defined by Technical Specification Figure 3.4.8-1 (Improved Technical Specification Section 3.4.15-1) for up to 48 hours. The lowest limit for this figure corresponds to 60 pCi/gram 1131 DEQ. Scaling down from the value shown for FCB3, Radiation, corresponding 1500 liCi/gram 1131 DEQ an RCS sample dose rate at one foot is computed as shown in the equation below. CN600020 Rev. 5 B:4 Calvert Cliffs Cliffs EAL Basis Document EAL Basis Document 13:4 Rev- 5

FISSION PRODUCT BARRIER DEGRADATION RCS Sample Reading For 60 pCi/gramin 1131 DEQ Refer to EAL FCB3 , Radiation BU3 Value = 60 uCi/gram x 168 mrem/h = 6.7 mrem/h 1500 ICi/gram Read as 6 mremnh (.06 mSv/h) Thus, the EAL 1 is written as: Dose Rate at One Foot from RCS Sample of AT LEAST 6 mremn/h This corresponds to a dose rate of 0.06 mSv/h. Technical Specification 3.4.8 (Improved Technical Specification Section 3.4.15) Reactor Coolant System - Specific Activity is addressed by EAL 2: Thus EAL 2 is written: FuelCladDegradationIndicated by RCS Sample Activity GREATER TILAr Tech Spec 3.4.8 (Improved Technical SSpecification Section 3.4.15) Allowable Limits Source Documents/References/Calculations: I. Technical Specifications 0 TS 3.4.8, Reactor Coolant System - Specific Activity Improved Technical Specification

• TS 3.4.15, RCS Specific Activity

2. Abnormal Operating Procedures 0 AOP-6A, Response to High RCS Activity

3. BG&E Fuel Degradation EALs Calculation Worksheet, JSB Associates, February 18, 1993 CN600021 Calvert Cliffs EAL Basis DMcament B:5 Rev. 5

FISSION PRODUCT BARRIER DEGRADATION Calvert Cliffs Emergency Action Level: RCB4 Coolant Leakage NTUMARC Emergency Action Level: RCS 2 RCS Leak Rate PotentialLoss - Unisolable Leak Exceeding the Capacity of One Charging Pump in the Normal Charging Mode RCS 3 SG Tube Rupture

• PotentialLoss - (Site-Specific) Indication that a SG is Ruptured aid Has a Non-Isolable Secondary Line Break OR (Site-Specific) Indication that a SG is Ruptured and a Prolonged Release of Secondary Coolant is Occurring From the Affected SG to the Environment RCS 5 Other (Site-Specific) Indications NUMARC Generic Basis:

[RCS 2, RCS 3) <Loss EALs are addressedunder IC RCB2, Temperature.>< The Potential Loss EAL is based on the inability to maintain normal liquid inventory within the Reactor Coolant System (RCS) by normal operation of the Chemical and Volume Control System which is considered as one centrifugal charging pump discharging to the charging header. <This indication, applying to any RCS leakage including primary-to-secondary leakage> assures that any event that results in significant RCS inventory shrinkage or loss (e.g., events leading to reactor scram and ECCS actuation) will result in no lower than an "Alert" emergency classification. [RCS 51 This EAL is to cover other (site-specific) indications that may indicate loss or potential loss of the RCS barrier, including indications from containment air monitors or any other (site-specific) instrumentation. Plant-Specific Information: The Calvert Cliffs Chemical and Volume Control System (CVCS) uses three positive displacement horizontal pumps with a capacity of 44 GPM each. The pressurizer level control program regulates letdown purification subsystem flow by adjusting the letdown flow control valve so that the reactor coolant pump (RCP) controlled leak-off plus the letdown flow matches the input from the operating charging pump. Equilibrium pressurizer level conditions may be disturbed due to RCS temperature changes, power changes, or RCS inventory loss due to leakage. A decrease in pressurizer water level below the programmed level will result in a control signal to start one or both standby charging pumps to restore water level. An increase in pressurizer water level above the programmed level will result in a control signal to increase letdown purification flow rate and initiate a backup signal to stop the two standby charging pumps. A start signal is sent to all three charging pumps on a Safety Injection Actuation Signal (SIAS), aligning the charging pumps suction to the Boric Acid Storage Tanks (BASTs) via the boric acid pumps. All three charging pumps will then inject highly concentrated boric acid into the RCS to ensure that the reactor is shutdown. Potential Loss of the RCS corresponds to conditions where the CVCS can not maintain pressurizer water level within normal limits requiring transition into the EOPs when the reactor is initially critical. Thus, Potential Loss EAL 1 is written as: RCS Leakage Exceeds Available CVCS Ca acit. IIIvertlliffs El Bosis6ocument0 I2l2Rev 5 Calvert Cliffs EAL Basis Document B:25 Rev. 5

FISSION PRODUCT BARRIER DEGRADATION However, review showed that an appropriate site-specific Potential Loss EAL could be developed based on entry into EOP-5, Loss of Coolant Accident, EOP-6, Steam Generator Tube Rupture, or EOP-8, Functional Recovery Procedure, for an RCS leak. I Thus, Potential Loss EAL 2 is 2 3 and 4 are written as: EOP-5, Loss of Coolant Accident, Or EOP 8, Functional Rcc.;'cry PFrcedurM, is Implemented for RCS Leakage EOP-6, Steam Generator Tube Rupture, is implemented for RCS leakage. EOP-8, Functional Recovery Procedure, is implemented for RCS leakage. Source Documents/References/Calculations:

1. Abnormal Operating Procedures AOP-2A, Excessive Reactor Coolant Leakage

2. Emergency Operating Procedures

• EOP-5, Loss of Coolant Accident
• EOP-6, Steam Generator Tube Rupture
• EOP-8, Functional Recovery Procedure I

3. Surveillance Test Procedure (STP) 0-27-1/2, RCS Leakage Evaluation

4. Updated Final Safety Analysis Report a Section 9.1, Chemical and Volume Control System CN600023 Calvert Cliffs EAL Basis Document B:26 Rev. 5

EQUIPMENT FAILURE Emergency Classification Level: SITE EMERGENCY Applicable Operational Modes: 5, 6 Calvert Cliffs Initiating.Condition: QS3 Loss of Water Level That Can Uncover Fuel in the Reactor Vessel NUMARC Initiating Condition: SSSLoss of Water Level in the Reactor Vessel That Has or Will Uncover Fuel in the Reactor Vessel Barrier: FUEL CLAD NUMARC Generic Basis: Under the conditions specified by this IC, severe core damage can occur and reactor coolant system pressure boundary integrity may not be assured. <> For PWRs, this IC covers sequences such as prolonged boiling following loss of decay' heat' removal. Thus, declaration of a Site <F,>niergency is warranted under the conditions specified by the IC. Escalation to a General Emergency is via <Radioactivity Release IC RG1, Off-Site Dose of AT LEAST 1 REM (EDE+CEDE) Whole Body or 5' REM (CDE) Thyroid>. Plant-Specific Information: Sequences that can result in uncovery of fuel in the reactor vessel (indirectly by prolonged boiling) include leakage through SG nozzle dams, pipe breaks in the Shutdown Cooling (SDC) System or Chemical & Volume Control System (CVCS), or. loss of the SDC function. These leakage sources are outside the reactor vessel and at most could only result in water level decreases to the bottom of the hot leg elevation. This water level decrease would cause loss of SDC suction. In-core instrumentation (ICI) penetrations for Calvert Cliffs are through the vessel head. Thus, these do not have to be considered for this IC. A review of attachments to AOP-3B, Abnormal Shutdown Cooling Conditions, shows that depending on previous power history and assuming an initial RCS temperature of 1407F, boiling in the core can begin in as little as 7 minutes following loss of SDC during mid-loop operation. AOP-3B also shows that under these conditions, without any operator action, core uncovery can begin within about 80 minutes after loss of SDC. Available methods to restore RCS inventory and to remove core heat include restoring the SDCS, injecting into the RCS from the Refueling Water Tank (RWT) using the HPSI, LPSI, CS or charging pumps, using the steam generators as a heat sink, using the Refueling Pool as a heat sink, aligning a LPSI pump to take suction from the RWT, or even injecting into the RCS using Safety Injection Tanks (SITs). Given the number of methods to restore inventory, and the amount of time available, it is highly unlikely that this IC will be entered. Thus, the EAL is written as: AOP-3B, Abnormal Shutdown Cooling Conditions, Is Implemented AND ANY of the Following Conditions Exist:

• Alternate Methods for Restoring RCS Inventory Are NOT Effective Valid RVLMS Reading Indicating 0.% Level water level above core is ten inches or less.

      . Valid CET Reading Indicating Superheat Conditions CN600024 Calvert Cliffs EAL Basis Document                              Q: 18                                                  Rev. 5

ELECTRICAL Emergency Classification Level: UNUSUAL EVENT Applicable Operational Modes: ALL Calvert Cliffs Initiating Condition: EU1 Loss of Off-Site Power NUMARC Recomnition Catemory: System Malfunction NUMARC Initiating Condition: SUl Loss of All Off-Site Power to Essential Busses for Greater Than 15 Minutes Barrier: Not Applicable NUMARC Generic Basis: Prolonged loss of AC power reduces required redundancy and potentially degrades the level of safety of the plant by rendering the plant more vulnerable to a complete Loss of AC Power (Station Blackout). Fifteen minutes was selected as a threshold to exclude transient or momentary power losses. NUMARC Questions and Answers. June 30. 1993 (System Malfunction)

1. Does the EAL of SU1 apply to one unit whose essential busses can be energized from another (unaffected) unit at a multi-unit site?

SUl does apply to this situation. Plants that have the capability to cross-tiepowerfrom a companion unit may take creditfor the redunantpower source in the associatedEAL for this IC. Inability to effect that cross-tie within IS minutes is groundsfor declaringthe UnusualEvent. Multi-unit stations with shared safety functions should further consider how this IC may affect more than one unit and how this may be a factor in escalating the emergency class. Plant-Specific Information: Procedure EOP-2, Loss of Off-Site Power, would be implemented under the conditions of concern. AOP-3F applies to the other operational modes when the plant is e4itieal shutdown. Per EOP-2, the following are symptoms of a loss of off-site power:

         " Momentary loss of Control Room lighting on both Units.

• 500KV Red Bus and Black Bus power available lights are de-energized.
• Diesel Generators automatically start.

        " 13KV Service Buses 12 and 22 power available lights are de-energized.

• No RCPs are running on either Unit.

         " Reactor Trip occurs due to RCS low flow.

Fer-eensistefncy with perocedural requirements and te r-eflect potential severity, separatc EALs have been developed for-hot and Gold conditions. With the plant initially operating in Mode 1 Or 2, EOP 2 would be cntcrcd on a less of off- site pov.'or Under: thesc condifiens, rcestzr-ing off site poBes ~cted to Wceso~n less then 15 minutes based en preedur implementatien ThcFr-efr, E.AL 1dARM not --- us

                                               . e e eei 15 minute threshold. HOP 2 may also be implemented if singl phase natural cir-eulation is to be used for RCS heat removal although at least one 13KV Scr~ee Bus is energized. Unusua Ev.en.t de-lar-atin is nct approp.-ate for-this use of.the pr.edur. Being a two unit site with the ability to cross-tie power from the other (unaffected) unit, credit Istaken for the redundant power source.

Calvert Cliffs EAL Basis Document E:1 111 IH1111111111111 111111111111HE CN600025 111N11 Rev. 5

ELECTRICAL Thus, #the EAic is written as: HOP 2 Loss of All Off-site 500 kV Power to both 4 kV Safety Related Buses on, kn.. . ne . her Unit for loss of off-site power. Greater than 15 minutes. HAL 2 addrfesses. less of off site power- when EOP 2 does net apply. EA ThstLi A itten as: Le sae&Off S*ite Power-for G1_ATER TH- N* 15 A-4-i Source Documents/References/Calculations:

1. Technical Specifications

• TS 3.8.1, A.C. Sources

2. Emergency Operating Procedures

• EOP-2, Loss of Off-Site Power

3. Abnormal Operating Procedures

• AOP-3F, Loss of Off-Site Power While in Modes 3, 4, 5, or 6 Iilil 111111 l giirl i 11111 CN600026 111ili .. .'

Calvrt Ciff EALBass Doumet....Re. 5 . Calvert Cliffs EAL Basis Document E:2 Rev. 5

ELECTRICAL There is one battery charger fed from Unit I and another battery charger fed from Unit 2 connected to each 125 volt dc bus. The ac power for both battery chargers per bus is obtained from the same load group. The reserve battery is connected to its own charger when it is not connected to a safety related 125 volt dc bus. Each of the four 125 volt dc power sources is equipped with the following instrumentation in the control room to enable continual operator assessment of 125 volt dc power source condition:

         -  DC bus undervoltage alarm
         -  Battery current indication
         -  Charger current indication
         -  Charger malfunction alarm (including input ac undervoltage, output dc undervoltage, and output dc overvoltage)
         -  DC bus voltage indication, and
         -  DC ground indication Components affected by the loss of 125 volt dc buses 11, 12, 21, or 22 are listed in table EU2-1. Loss of the new Diesel Generator 1A 125 volt DC bus 14 does not constitute an entry condition for this EAL.

CCNPP Ouestions and Answers (Electrical)

• Why does the 125 volt DC bus 14 need to be addressed in the basis if it has no impact on the EAL?

Site Emergency Coordinatorsaskedfor documentation In the basis, that the new 125 volt DC bus 14 was considered for the electricalEAL I& AOP-71lUsts the equipment that Is lost if bus 14 is lost. Thus, the EAL is written as: AOP-71, Loss of 120 Volt Vital AC or 125 Volt Vital DC Power, is Implemented AND 125 Volt DC Power

 ' Lost for GREATER THAN 15 Minutes           .

Source Documents/References/Calculations:

1. Abnormal Operating Procedures 0 AOP-7J, Loss of 120 Volt Vital AC or 125 Volt Vital DC Power

2. Updated Final Safety Analysis Report

3. BG&E Drawing 61-030-E, Single Line Diagram, Vital 120V AC & 125VDC - Emergency 250V DC

4. BG&E Drawing 61-057-E, Block Diagram - Auxiliary System Load Groups - Units 1 & 2 CN600027 E:4 Rev. 5 Calvert Cliffs EAL Calvert Cliffs Basis Document EAL Basis Document E:4 Rev. 5

ELECTRICAL Table E-1: Effects of Lost 125 Volt DC Buses 11, 21, 12, and 22 Loss of Loss of Loss of Loss of 11 125 volt do Bus 21 125 volt do Bus 12 125 volt dc Bus 22 125 volt de Bus Channel ZD ESFAS and Channel ZE ESFAS and AFAS Channel ZF ESFAS and AFAS Channel ZO ESFAS and AFAS. AFAS Sensor Cabinets de- Sensor Cabinets do-energized Sensor Cabinets de-energized Sensor Cabinets do-energized energized CNTMT Area Rad Monitor CNTMT. Area Rad Monitor out CNTMT Area Rid Monitor out CNTMT Area Rad Monitor out out of service ofservice of service ofservice Channel A RPS Cabinet do- Channel B RPS Cabinet do- Channel C RPS Cabinet do- Channel D RPS Cabinet de-energzed energized energized energized Loss of 2A EDO field flash Loss of 2B EDO field flash and Loss of IB EDO field flash and and control power; the start control power,the start solenoids control power, the start bolenoids solenoids fail shut (Unit 2 fall shut (Unit 2 only) fail shut (Unit I only) only) Loss of breaker position Loss of breaker position indication: indication:

 -Nornal power supply to the    -Normal power supply to the 11AJ2 IA and 12A/22A           1IB/2 IB and 12B/22B RCPs RCPs                       -13/23 and 14/24 4 KV buses
 -11/21, 12/22, 15/25, and      -13A/23A, 13B/23B, 14A/24A, 16/26 4 KV buses              and 14B/24B 480 Volt Buses
 -IIA/21A, IIB/21B, 12A/22A, and 12B/22B 480 Volt Buses 11 and 12 13 KV buses (Unit I only)

Loss of Unit 2 Annunciation All Unit I Annunciator lights de-energized (Status Panels remain energized) CC CNTMT SUPPLY fails CC CNTMT RETURN fails shut shut 12 SO AFW STM SUPP & II SO AFW STM SUPP & BYPASS valves fail shut BYPASS valves fail shut Loss of SRW to the Turbine Loss of SRW to the Turbine Building Building . IA and PA may be lost due IA and PA may be lost due to loss to loss of SRW to the of SRW to the Turbine Building Turbine Building _ Channel A ESFAS and Channel B ESFAS and AFAS AFAS Actuation Cabinets Actuation Cabinets de-energized de-energized 11/21 SRW, 11/21 CC, and 12/22 SRW, 12/22 CC, and 11/21 ECCS Pump Room 12/22 ECCS Pump Room HX HX SW outlet valves fail SW outlet valves fail open open 11/21 Main Steam Effluent 12/22 Main Steam Effluent Rad Rad Monitor out of service Monitor out of service 11 and 12 SFP Heat 11 and 12 SFP Heat Exchangers Exchangers lose oooling flow lose cooling flow due to SRW due to SRW outlet CVs outlet CVs failing shut (Unit I failing shut (Unit I only) only) 11/21 MSIV loses position 12/22 MSIV loses position indication, but can still be indication, but can still be closed closed from IC03/2CO3 from IC03/2CO3 CNTMT High Range CNTMT High Range Monitor Monitor Channel A out of Channel B out of service service 1iii i1li iiiiIi lll .... C C BD tCN600028 Calvert Cliffs EAL Basis Document E:5 Rev. 5

ELECTRICAL Table E-1: Effects of Lost 125 Volt DC Buses 11, 21, 12, and 22 (Continued) Loss of Loss of Loss of Loss of 11 125 volt do Bus 21 125 volt do Bus 12 125 volt dc Bus 22 125 volt dc Bus Loss of open signal to the Turbine Bypass Valves and loss of quick open signal to the ADVs (Unit I only) Aux Spray Valve fails shut IA downstream ofthe CNTMT IA Control Valve is isolated C'CNTMT IA ISOLATED IA-2085-CV CLOSED" alarm does NOT actuate) CNTMT Gaseous Monitor out ofservice Gaseous and Liquid Waste release control valves fail shut (Unit I only) IIB/21B and 12B122B RCPs are untrippable from IC06/2CO6 Loss of letdown due to 1/2-CVC-516-CV failing shut AFW Turbine Driven Train Flow Control Valves II SO and 12 SO fail open (Unit 1 only) PORV-404 inoperable in MPT ENABLE (Unit I only) TCBs I and 5 trip TCBs 2, 6, and 9 trip TCBs 3 and 7 trip TCBs 4 and 8 trip Loss of plant oscillograph (Unit 1 only) CN600029 Calvert Cliffs EAL Basis'Document E:6 Rev. 5

ELECTRICAL Emergencv Classification Level: ALERT Applicable .perational Modes: 1, 2, 3, 4 Calvert Cliffs Initiating Condition: EA2 Only One AC Power Source Available to Supply 4 kV Emergency Busses NUMARC Recognition Category: System Malfunction NUMARC Initiating Condition: SA5 AC Power Capability to Essential Busses Reduced to a Single Power Source for Greater Than 15 Minutes Such That Any Additional Single Failure Would Result in Station Blackout Barrier: Not Applicable NUMARC Generic Basis: This IC and its associated <Generic> EAL are intended to provide an escalation from IC <EUI, Loss of Off-Site Power>. The condition indicated by this IC is the degradation of the off-site and on-site power systems such that any additional single failure would result in a station blackout. This condition could occur due to a loss of off-site power with a concurrent failure of one diesel generator to supply power to its emergency busses. Another related condition could be the loss of all off-site power and loss of on-site emergency diesels with only one train of emergency busses being backfed from the unit main generator, or the loss of on-site emergency diesels with only one train of emergency busses being backfed from off-site power. The subsequent loss of this single power source would escalate the event to a Site <E>mergency in accordance with IC <ES 1, Station Blackout>.

 <Generic> EAL lb should be expanded to identify the control room indications of the status of Site-specific power sources and distribution busses that, if unavailable, establish single failure vulnerability.

At multi-unit stations, the EALs should allow credit for operation of installed design features, such as cross-ties or swing diesels, provided that abnormal or emergency operating procedures address their use. However, these stations must also consider the impact of this condition on other shared safety functions in developing the site specific EAL. Plant-Specific Information: The EAL addresses conditions while operating in Modes 1, 2, 3, or 4 under which only one method is available to supply the emergency buses and loss of that method will result in a Station Blackout. Acceptable back up power sources with respect to this EAL include the non-safety related OC diesel generator and the 13 kV SMECO tie line. The 13 kV SMECO tie line can back up both units. When one or more of these sources are available to back up the Unit experiencing a loss of offsite power or loss of a safety related diesel generator the entry condition for the EAL is not being met and the EAL does not apply. Thus, the EAL is written as:

• Only One Power Source (Off-site or Diesel) is Available to Supply Unit 1 (Unit 2) Safety Related 4 kV

(( busses for GREATER THAN 15 Minutes AND the Unit is Not on Shutdown Cooling (this is a condition IIwhere any additional single failure will result in Station Blackout). Source Documents/References/Calculations:

1. Updated Final Safety Analysis Report Section 8, Electric Power Systems iiiIlI111iiiTll1 ilI]l~l I!Ilf i 'I

_____ CN600030 Calvert Cliffs EAL Basis Documrnt E:8 Rev. 5

ELECTRICAL Under conditionswhere a diesel generatoris supplyingpower to one Unit, it should not be consideredavailable as a power supply for the other Unit. The first part of this EAL corresponds to the threshold conditions for IC ESI, Station Blackout for GREATER THAN 15 Minutes. The second part of the EAL addresses the conditions that will escalate the SBO to General Emergency. Occurrence of any one of these conditions following SBO is sufficient for escalation to General Emergency. These conditions are: (1) SBO coping capability, or (2) indications of inadequate core cooling. Each of these conditions is discussed below:

1. SBO Coping Capability Calvert Cliffs falls -i*hi* the is licensed both for a four hour SBO coping category AND a one hour SBO coping category. The ability of each unit to cope with a four hour SBO duration was based on an assessment of condensate inventory required for decay heat removal, Class lE battery capacity, compressed air availability or manual operation of certain valves, effects of loss of ventilation, containment isolation valve operability, and reactor coolant inventory loss. A plant-specific analysis indicates that the expected rates of reactor coolant inventory loss under SBO conditions do not result in core uncovery in a SBO of four hours. Therefore, makeup systems in addition to those currently available under SBO conditions are not required to maintain core cooling under natural circulation (including reflux boiling). Thus, conditions in which restorationofA C power within 4 hours is NOT likely are included in the EAL.

Installation of a SBO diesel also allows Calvert Cliffs to operate as a plant having a one hour coping capability. This allowance is in recognition that sufficient diesel generator back-up reduces the likelihood of station black-out. The analysis for the four hour coping category however, provides the source of an appropriate estimate of the time to core uncovery following a station black out from which the plant can not recover. This time (four hours) is used as the basis for determining when to declare a general emergency subsequent to a prolonged station black out.

2. Indications of Inadeguate Core Cooling Calvert Cliffs does not use Critical Safety Function Status Trees. Calvert Cliffs uses Safety Function Status Checks developed by the Combustion Engineering Owners' Group (C-E OG) which are based on logic similar to that used for CSFSTs developed for Westinghouse PWRs. The applicable acceptance criteria for Core and RCS Heat Removal are shown on the Safety Function Status Checks. They are:

Steam Generators Available for RCS Heat Removal

1. Adequate secondary side liquid inventory in at least one steam generator as indicated by level between -170 and +30 inches, and

2. Adequate source of feedwater available to assure continued liquid inventory available as indicated by Condensate Storage Tank level greater than 5 feet, and

3. Steam Generators acting as effective heat sink as indicated by Cold Leg Temperatures (TCOLD) constant or lowering.

Primary Side Conditions for Core and RCS Heat Removal

1. Adequate core heat removal as indicated by Core Exit Thermocouple readings less than superheated, and

2. Either of the following:

    " Natural circulation established as indicated by the temperature difference between Hot Leg Temperature (THOT) and TCOLD of between 10 OF and 50 OF, or
    " Forced circulation effective as indicated by THOT - TCOLD less than 10 "F.

IIIIII IIIII III1I 111 CNII6 CN600031 I l li i Calvrt lifs EL Bsis ocuentE:1 Re.. - Calvert Cliffs EAL Basis Document E:15 Rev. 5

ELECTRICAL Per CEN-152, superheated conditions indicate core uncovery and inadequate core cooling. Thus, the EAL is written as: EOP-7, Station Blackout, is Implemented AND ANY of the Following:' Restoration of Power to ANY Vital 4kV Bus Is NOT Likely Within 4 Hours I Valid CET Readings Indicate Superheat Temperatures I Core and RCS Heat Removal Using Steam Generators Can NOT Meet Acceptance Criteria Valid means that the indication is from instrumentation determined to be operable in accordance with the Technical Specifications or has been verified by other indications displayed on the control panels. Can NOT is used because the ability to meet the final acceptance criteria is the appropriate concern, not whether intermediate acceptance criteria are not being achieved at any given moment. Source Documents/References/Calculations:

1. Emergency Operating Procedures EOP-7, Station Blackout EOP-8, Functional Recovery Procedure

2. CEN-152, Emergency Procedure Guidelines

3. Letter, Daniel G. MacDonald (US Nuclear Regulatory Commission) to G.C. Creel (BG&E), Response to Station Blackout Rule - Calvert Cliffs Nuclear Power Plant, Units 1 and 2, TAC Numbers 68525 (Unit 1) and 68256 (Unit 2),

October 10, 1990 1 r11 011 [1-ii i11ii i 1"1ii

                                                                                          -111 CN600032 Calvert Cliffs EAL Basis Document                            E: 16                                                      Rev. 5

SECURITY Emergeny, Classification Level: UNUSUAL EVENT Avplicable Ouerational Modes: ALL Calvert Cliffs InitiatLng Condition: TUI Confirmed Security Event With Potential Degradation in the Level of Safety of the Plant MUMARC Recognition Cateaov: Hazards and Other Conditions Affecting Plant Safety NUMARC Initiatina Condition: HU4 Confirmed Security Event Which Indicates a Potential Degradation in the Level of Safety of the Plant Barrier: Not Applicable NUMARC Generic Basis: This EAL is based on (Site-specific) Site Security Plan. Security events which do not represent at least a potential degradation in the level of safety of the plant are reported under 10 CFR 73.71 or in some cases under 10 CFR 50.72. The plant Protected Area Boundary is typically that part within the security isolation zone and is defined in the (Site-specific) security plan. Bomb devices discovered within the plant Vital Area would result in <> escalation <to a higher emergency classification level via other Security Event ICs>. Plant-Specific Information: The Calvert Cliffs EALs address the generic areas of concern and include the ISFSI. Nuclear Security will determine whether or not intrusion or sabotage exists in accordance with the Safeguards Contingency Plan. Attempted intrusion means that intruders are not successful in getting past the innermost fence of the double fence that surrounds the plant protected area. Sabotage within the ISFSI includes discovery of a bomb device, Intruders are armed or unarmed personnel that are attempting to or have gained unauthorized access in a h.c..lc hoste r. Sabotage (including discovery of a bomb device) inside the Plant Protected Area warrants escalation to an Alert level emergency. A Site Emergency is warranted if sabotage occurs in an area of concern for safe shutdown of either reactor. Thus, EAL 1 is written as:

  "Scuri yEmergeny"or "Security Alert" Declared for Attempted Intrusion into the Plant Protected Area EAL 2 is written as:
  "Security Event" Declared for:
            . Sabotage Within or to ISFSI Protected Area

• Intrusion Into ISFSI Protected Area Source Documents/References/Calculations:

None

• lN 6i0ii0ili CN600033 U3l ii Calvert Cliffs EAL Basts Dc -:.*,nt . T:1 Riv. 55

SECURITY Emergency Classification Level: ALERT Applicable Ouerational Modes: ALL Calvert Cliffs Initiating Condition: TA1 Security Event in the Plant Protected Area N-UMARC RecomMtion Category: Hazards and Other Conditions Affecting Plant Safety NUMARC Initiating Condition: HA4 Security Event in a Plant Protected Area Barrier: Not Applicable NUMARC Generic Basis: This class of security events represents an escalated threat to plant safety above that contained in the Unusual Event. For the purposes of this IC, a civil disturbance which penetrates the protected area boundary can be considered a hostile force. Intrusion into a vital area by a hostile force will escalate this event to a Site <Emergency>. Plant-Specific Information: The Calvert Cliffs EALs address the generic areas of concern. Nuclear Security will determine whether or not intrusion or sabotage exists in accordance with the Safeguards Contingency Plan. Sabotage includes discovery of a bomb device. Intruders are armed or unarmed personnel that have gained unauthorized access in a hostile m.n-'r. Thus, EAL 1 is written as:

  "Security Emergency" or "Security Alert" Declared For:

IIntrusion , Sabotage into insidethethe Plant Protected Plant ProtectedArea Area . ...... , [ Source Documents/References/Calculations: None 11111IIIIIIII 11II CNI !IIIIIl4liii CN600034 iilil l.... Calvert Cliffs EAL Basis Document T:2 Rev. 5

SECURITY Emeraencv Classification Level: SITE EMERGENCY Applicable Operational Modes: ALL Calvert Cliffs Initiating Condition: TSL Security Event in a Plant Vital Area NUMARC Recognition Categorv: Hazards and Other Conditions Affecting Plant Safety N*UMARC Initiating Condition: HS1 Security Event in Plant Vital Area Barrier: Not Applicable NUMARC Generic Basis: This class of security events represents an escalated threat to plant safety above that contained in the Alert IC in that a hostile force has progressed from the Protected Area to the Vital Area. < > Plant-Specific Information: The Calvert Cliffs EALs address the generic areas of concern. Nuclear Security will determine whether or not intrusion or sabotage exists in accordance with the Safeguards Contingency Plan. Sabotage includes discovery of a bomb device. Intruders are armed or unarmed personnel that have gained unauthorized access in a hostilev! .-n:. Thus the EAL 4-is written as: I "Security Emergency "or "Security Alert" Declared For: Intrusion into an Aarea of the plant t.ut is a enc*nm for- safe shutdwn of either mcuter Concern for Safe Shutdown. I Sabotage within an Aarea of the plant that is a cancom for safe shutde% efceither. raetcr Concern for Safe Shutdown. . The list of areas of concern for Safe Shutdown are shown below and are prominently displayed on the EAL Table. Areas of Concern for Safe Shutdown

                - Control Room

• Electrical Penetration Rooms

                - Control Room HVAC Room

• Auxiliary Feedwater Pump Room
• Cable Spreading Room
• Charging Pump Rooms

                - Cable Chases

• Diesel Generator Rooms

                - Switchgear Room

• Diesel Generator Building (0C/IA)

                - ECCS Pump Room                                         ' Refueling Water Tank (RWT) 11(21)
                - Service Water Pump Room

• Condensate Storage Tank (CST) 12

                - Component Cooling Pump Room

• Pretreated Water Storage Tank (PWST) 11(21)

                - Main Steam Penetration Room

• Fuel Oil Storage Tank (FOST) 12
• This list of Safe Shutdown areas is displayed on the EAL Tables to assure that all areas related to Safe Shutdown are considered by the SEC.

EAL 2 is written as: FSAbOtngwihin am rea f the pflant that is a concarfn for-safe shudown of either-reaetor-. Source Documents/References/Calculations:

1. NRC Information Notice No. 96-71: Licensee Response to Indications of Tampering, Vandalism, or Malicious Mischief.

Calvert Cliffs EAL Basis Document Rev. 5 CN111lII1160003

FIRE Emergency Classification Level: ALERT Applicable Operational Modes: ALL Calvert Cliffs Initiating Condition: IAI Fire or Explosion Affecting Safe Shutdown NUMARC Recognition Categorv: Hazards and Other Conditions Affecting Plant Safety NUMARC Initiating Condition: HA2 Fire or Explosion Affecting the Operability of Plant Safety Systems Required to Establish or Maintain Safe Shutdown Barrier: Not Applicable NUMARC Generic Basis: (Site-specific) Areas containing functions and systems required for the safe shutdown of the plant should be specified. (Site-Specific) Safe Shutdown Analysis should be consulted for equipment and plant areas required for the applicable mode. This will make it easier to determine if the fire or explosion is potentially affecting one or more trains of safety systems. Escalation to a higher emergency class, if appropriate, will be based on <Equipment Failure, Electrical, Fission Product Barrier Degradation, Radioactivity Release, or SEC Judgement ICs>. <> With regard to explosions, only those explosions of sufficient force to damage permanent structures or equipment required for safe operation within the identified plant area should be considered. As used here, an explosion is a rapid, violent, unconfined combustion, or a catastrophic failure of pressurized equipment, that potentially imparts significant energy td near-by structures and materials. The inclusion of a "report of visible damage" should not be interpreted as mandating a lengthy damage assessment before classification. No attempt is made in this <Generic> EAL to assess the actual magnitude of the damage. The occurrence of the explosion with reports of evidence of damage (e.g., deformation, scorching) is sufficient for the declaration. The declaration of an Alert and the activation of the TSC will provide the <SEC> with the resources needed to perform these damage assessments. The <SEC> also needs to consider any security aspects of the explosions, if applicable. Plant-Specific Information: Each Calvert Cliffs unit uses the Abnormal Operating Procedures (AOP) 9A through 9S to address fires within the plant protected and vital areas that are of particular concern because they contain equipment required for safe shutdown. Thus, EAL 1 is written as: AOP-9 series Impleemented for Fire.. There are two independent clocks for determining the magnitude of a fire based on time. One clock starts when a fire is detected. For practical purposes a fire is detected when the report of the fire is received in the Control Room. Report of a fire may be by Control Room fire alarm or by voice message. A fire alarm refers to I C24B, Fire System Control Panel, for fire detection and fire suppression system actuation. Fire pump running and trouble alarms by themselves do not constitute a report ofa fire. This clock includes: the time it takes to confirm or verify the fire report, plus the response team assembly time, plus the time it takes the responders to establish a fire fighting strategy, plus the time it takes to actually extinguish the fire. Thus, EAL 4-2 is written as: 11Fire in an Area of Concern for Safe Shutdown that is not extinguished within 30 minutes of its detection. II Calvert Cliffs EAL Basis Document 1:3 "........ Rev. 5 CN600036 ._____

FIRE Visible smoke is sufficient to conclude that a fire exists. Flames do not have to exist. Odor by itself does not constitute a fire. A fire is extinguished when the Fire Brigade Leader determines that active combustion has ceased and there is no immediate danger of the fire spreading. The other clock for determining the magnitude of a fire is the time it takes to extinguish the fire. This clock begins when the first extinguishing agent is applied to the fire. Thus, EALT 3 is written as: I Fire in an Area of Concern for Safe Shutdown that is not extinguished within 15 minutes of the first extinguishing agent being applied. p This EAL accounts for situations where the time to validate and respond to the fire is short. EAL -14is written as: 1Eplosion in an Area of Concern for Safe Shutdow*n. 1. An explosion is a rapid, violent, unconfined combustion, a catastrophic failure of pressurized equipment, or a violent electric arc, of sufficient force to potentially damage equipment, structures or components. Fire and/or explosion in the Control Room HVAC Room may lead to power being lost to the alternate shutdown panels. Thus, the Control Room HVAC Room (Room 512) has been added to the areas of concern for safe shutdown. The list of areas of concern for Safe Shutdown are shown below and are prominently displayed on the EAL Table. Areas of Concern for Safe Shutdown

• Control Room ' Electrical Penetration Rooms
• Control Room HVAC Room
• Auxiliary Feedwater Pump Room
• Cable Spreading Room
• Charging Pump Rooms
• Cable Chases
• Diesel Generator Rooms
• Switchgear Room - Diesel Generator Buildings (OC/IA)

          "ECCS Pump Room

• Refueling Water Tank (RWT) 11(21)

          " Service Water Pump Room

• Condensate Storage Tank (CST) 12
• Component Cooling Pump Room
• Pretreated Water Storage Tank (PWST) 11(21)
• Main Steam Penetration Room
• Fuel Oil Storage Tank (FOST) 21 This list of Safe Shutdown areas is displayed on the EAL Tables to assure that all areas related to Safe Shutdown are considered by the SEC.

The significance of these EALs is not that safety systems have been degraded. What is significant is that a fire of such magnitude that it can not be extinguished in the times specified exists in an area of concern for safe shutdown. Likewise, an explosion is significant because it occurred in an area of concern for safe shutdown, not because it degraded safety systems. Calvert Cliffs EAL Basis Document IAa ..ert C UIIrififEll I BII Dce Rev. Rev. 5 CN600037

NATURAL HAZARDS EAL 2 is written as: Han Verified Report to Control Room of Visible Damage to Safe Shutdc:n Equipment Observable Damage in Area of Concern for Safe Shutdown. Verification of damage can be by physical observation, or by indications of degraded equipment performance in the Control Room or at local control stations. EAL 3 uses a sustained wind speed of 90 MPH to address high winds striking the Plant Vital Area as recommended by NUMARC. This speed is chosen to assure that the wind speed is within the design capability of the meteorological tower. Thus, EAL 3 is written as: Sustained Wind Speed GREATER THAN 90 MPH L40 meters/second for AT LEAST 15 Minutes The duration of 15 minutes is selected to indicate sustained winds and to preclude wind gusts. Wind speeds are also provided here in meters/second for dose assessment input. The conversion equation is as follows: 90 miles/hour x 5280 feet/mile x (1 hour/3600 seconds) x 1 meter/3.2808 feet) = 40 meters/second Per UFSAR Section 2.8.3.6, the still water level used for Intake Structure analysis is 17.6 feet MSL. This is above the top of the range of the Tide Level Recorder (0-LR-5195). The top of the Traveling Screen cover housings is about 18 feet MSL. EAL 4 indicates achieving the design water level. Thus, EAL 4 is written as: 11Bay Water Level At Or Above the Top of the Traveling Screen Cover Housing Per UFSAR Section 2.8.3.7, the predicted extreme low tide is -3.6 feet MSL and the plant is designed to safely operate at an extreme low water level of -6.0 feet MSL. EAL 5 is based on the lower elevation. Thus, EAL 5 is written as: rBay Water Level Is AT LEAST 6 Feet Below Mean Sea Level Surveillance Test Procedures provide a way to determine Bay level. Source Documents/References/Calculations:

1. Updated Final Safety Analysis Repori

2. Operating Instruction (01) 46, Seismic Measurement Equipment

3. BG&E Drawing 60-220-E (M-3 1), Equipment Location Service Building, Water Treatment Area & Intake Structure Section "J-Y'

4. BG&E Internal Memorandum, J.E. Thorp to R.E. Denton, Emergency Action Level Review Criteria, June 1, 1990 Calvert Cliffs EAL Basis Document N:4 IIIIII I 1111 IIII Rev.l5 CN600038

OTHER HAZARDS Emerency Classification Level: UNUSUAL EVENT Applicable Operational Modes: ALL Calvert Cliffs Initiating Condition: OU1 SEC Judgement NUMARC Recognition Category: Hazards and Other Conditions Affecting Plant Safety NUMARC Initiating Condition: HU5 Other Conditions Existing Which in the Judgement of the Emergency Director Warrant Declaration of an Unusual Event Barrier: Not Applicable NUMARC Generic Basis: This <Generic> EAL is intended to address unanticipated conditions not addressed explicitly elsewhere but that warrant declaration of an emergency because conditions exist which are believed by the <SEC> to fall under the Unusual Event emergency class. From a broad perspective, one area that may warrant <SEC> judgement is related to likely or actual breakdown of site specific event mitigating actions. Examples to consider include inadequate emergency response procedures, transient response either unexpected or not understood, failure or unavailability of emergency systems during an accident in excess of that assumed in accident analysis, or insufficient availability of equipment and/or support personnel. Specific examples of actual events that may require <SEC> judgement for Unusual Event declaration are listed here for consideration. However, this list is by no means'all inclusive and is not intended to limit the discretion of the site to provide further examples.

         - Aircraft crash on-site
         - Train derailment on-site
         - Near-site explosion which may adversely affect normal site activities.

• Near-site release of toxic or flo...agle flammable gas which may adversely affect normal site activities  !
• Uncontrolled RCS cooldown due to Secondary Depressurization It is also intended that the <SEC's> judgement not be limited by any list of events as defined here or as augmented by the site. This list is provided solely as examples for consideration and it is recognized that actual events may not always follow a pre-conceived description.

Plant-Specific Information: Site Emergency Coordinator (SEC) is the title for the emergency director function at Calvert Cliffs. Thus, the EAL 1 is written as: An"y Condition Which in the SEC's Judgement Indicates Potential Degradation in the Level of Safety of the [ I Plant I In this manner, the EAL addresses conditions that fall under the Notification of Unusual Event emergency classification description contained in NUREG-0654, Appendix I that is retained under the NUMARC methodology. Calvert Cliffs EAL Basis Document 0:1 *- l M lll 01i110i FiILD111 III U1l Rev. 5 CN600039

OTHER RAZARDS Uncontrolled RCS cooldown due to secondary depressurization is given as an example under this initiating condition. In order to reduce the need for judgment in recognizing this condition, a separate EAL is written for EOP-4 implementation. EOP-4 is implemented for this condition at Calvert Cliffs. Other examples given in the generic basis are addressed as specific EAL's and under OU2 and OU3. Thus EAL 2 is written as: I EOP-4. Excess Steam Demand Event. is Imnlemented. II Source Documents/References/Calculations:

1. Emergency Response Plan

2. NUREG-0654/FEMA-REP-1, Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants, Revision 1, October 1980, Appendix 1 I.

Calvert Cliffs EAL Basis Document Cl*:2 Cliffs EA Ifrt Rev. Basis Document Rev. 5 CN600040

OTHER HAZARDS EAL I is written as:

    *dlear- Security Report of an Explosion Causing Observable Damage to Permanent Equipment orI Structures Within the Plant Protected Area Or Within the ISFSI Protected Area                                              I.

EAL 2 is written as: I Nisible Observable Damage to Safe Shutdo.n Equipment Or to Permanent Equipment or Structures LIWithin the Plant Protected Area Or Within the ISFSI Protected Area EAL 3 is written as: I Turbine Failure Causing Observable Casing Damage Ui Observable is used to indicate that such damage can be readily seen and does not require special equipment or techniques to see or measure. EAL 4 is written as: Vessel or Vehicle Collision Causing Observable Damage to Safe Shutdovn Permanent Equipment or Structures Within the Plant Protected Area. . I. EAL 5 is written as: LVessel or Vehicle Collision Causing Observable Damage to Structures Containing Dry Stored Spent Fuel EALs 4 and 5 address airplane, helicopter, barge, boat, train, car, or truck collisions inte that may potentially damage equipment required to achieve or maintain safe shutdown or with the Horizontal Storage Modules and their associated structural supports. These EALs do not include vehicle crashes with each other, damage to office structures, damage to equipment nt rcmquirzed t aehiv2 or nmisnnt *sfc hutd..'n%that does not affect plant safety, or damage to structures that are not required to maintain the integrity of the dry spent fuel stored in the ISFSI. SAfeShutdone . . .,. and equipment conceFn ar-c identfied beleim. Actual damage in areas of Concern for Safe Shutdown are escalated to Alert whereas damage in the plant protected area is recognized as only having the potential for affected safe shutdown. Areas3 of Conern for Saf- Shutdown

                -  Cenifol Room                                          Eleetial       .e     n Raoms
     *          - Ccntrol Roomn HVAC Reem                                A~uxiliay Feedwater Pump Room l*      in   G - able Sprcading Reem                                   gCha         Pump Rooe r blg
                 -uGable r           hasesWhDiesel                                       GcnroatcrtRoo..s_
                                 -e ~iegef                               Diesel Gonorater Builin(CIA
                - EGGS Pump Room                                         Refl~feling Water Tnk(        T)1()
                -  Servic Water-Pamp Room                             -  Cndensatc Storage TwAn (CST-) 12
                -cmpenent d            Ceoling Pump R oom         r            Prietreated Watevr Strmage Toan (PWSth) 11(
                -   iwit n SteamnPenetrpioen R ge o-                e Fuelio Stoage Tank (hOST) 12 t heq list cf Safe Shutdown area istdisplayed an thoEAL Table teoassure       that all a     Pmeplatd to    af ShutmeRn arce hnuideroed    by the SEC.

EAL 6 is written as: I~ooding; of-Reems Containing Safe Shutdown Equipment Causing Observable Damage to Permanent M Euipment or Structures Within the Plant Protected Area Flooding indicates that the net water flow into the room results in elevated water levels, may be more than available drain capacity, and if continued, can prevent operation of equipment in the room. Thus, minor water level increases that may result in wet floors and do not pose a challenge to equipment operation are not included in this EAL. Areas containing equipment required for Safe Shutdown are listed above. The rooms located below MSL include the ECCS Pump Rooms and the Charging Pump Rooms. The Shutdown Cooling Heat Exchangers are also located in the ECCS Pump Roams. Such flooding can result in a potential degradation in the level of safety of the Calvert Cliffs plant and is therefore included in this EAL. Calvert Cliffs EAL Basis Document 0:5 Rev. 5 CN600041

OTHER HAZARDS Emergency Classification Level: ALERT A1olicable Operational Modes: ALL Calvert Cliffs Initiating Condition: 0,A2 Toxic or Flammable Gases Affecting Safe Shutdown NUMARC Recognition Category: Hazards and Other Conditions Affecting Plant Safety NUMARC Initiating Condition: HA3 Release of Toxic or Flammable Gases Within a Facility Structure Which Jeopardizes Operation of Systems Required to Maintain Safe Operations or to Establish or Maintain Cold Shutdown Barrier: Not Applicable N'UMARC Generic Basis: This IC is based on gases that have entered a plant structure affecting the safe operation of the plant. This IC applies to buildings and areas contiguous to plant Vital Areas or other significant buildings or areas (i.e., Service Water Pumphouse). The intent of this IC is not to include buildings (i.e., warehouses) or other areas that are not contiguous or immediately adjacent to plant Vital Areas. It is appropriate that increased monitoring be done to ascertain whether consequential damage has occurred. Escalation to a higher emergency class, if appropriate, will be based on <Electrical, Equipment Failure, Radioactivity Release, Fission Product Barrier Degradation, or SEC Judgement ICs.> <> Plant-Specific Information: For the purposes of this IC, Halon (such as is discharged by the fire suppression system) is not toxic. Fire suppressant discharge can be lethal if it reduces oxygen to low concentrations that are immediately dangerous to life and health (IDLH). Fire suppressant discharge into an area is not basisfor emergency classificationunder this IC unless: (1) Access to the affected area is required,and (2) Fire suppressantconcentrationresults in conditions that make the area Inaccessible (i.e., JDLH). Thus, the EAL is written as: Toxic or Flammable Gas Making Safe Shutde-, A.rc' naIeen'sibl an Area of Concern for Safe ' IIShutdown Inaccessible.

• This EAL also addresses releases that could originate from the Cove Point Liquid Natural Gas Plant.

The areas of concern for safe shutdown are identified below. Areas of Concern for Safe Shutdown

                  - Control Room                                        - Electrical Penetration Rooms
                  - Control Room HVAC Room                              - Auxiliary Feedwater Pump Room
                  - Cable Spreading Room

• Charging Pump Rooms

                  - Cable Chases

• Diesel Generator Rooms
• Switchgear Room - Diesel Generator Building (OC/IA)

                 - ECCS Pump Room

• Refueling Water Tank (RWT) 11(21)

                  - Service Water Pump Room                             e Condensate Storage Tank (CST) 12
                 - Component Cooling Pump Room

• Pretreated Water Storage Tank (PWST) 11(21)

                 - Main Steam Penetration Room

• Fuel Oil Storage Tank (FOST) 12 This list of Safe Shutdown areas is displayed on the EAL Tables to assure that all areas related to Safe Shutdown are considered by the SEC.

Calvert Cliffs EAL Basis Document Rev. 5. CN600042

OTHER HAZARDS Emergency Classification Level: ALERT Applicable Operational Modes: ALL Calvert Cliffs Initiating Condition: OA3 Destructive Phenomena Affecting Safe Shutdown NUMARC Recognition Categorv: Hazards and Other Conditions Affecting Plant Safety NUMARC Initiating Condition: HAI Natural and Destructive Phenomena Affecting the Plant Vital Area Barrier: Not Applicable NUMARC Generic Basis: GenericEA4Ls 1, 2, and 3 are addressedunderIC NA 1, NaturalPhenomenaAffecting Safe Shutdown. <Generic> EAL 4 should specify the types of instrumentation or indications including judgement which are to be used to assess occurrence. <Generic> EAL 5 is intended to address such items as plane or helicopter crash, or on some sites, train crash, or barge crash into a plant vital area. <Generic> EAL 6 is intended to address the threat to safety-related equipment imposed by missiles generated by main turbine rotating component failures. This (site-specific) list of areas should include all safety-related equipment, their controls, and their power supplies. This )EAL is, therefore, consistent with the definition of an ALERT in that if missiles have damaged or penetrated areas containing safety-related equipment the potential exists for substantial degradation of the level of safety of the plant. <Generic> EAL 7 covers other (Site-Specific) phenomena such as flood. Each of these <generic> EALs is intended to address events that may have resulted in a plant vital area being subjected to forces beyond design limits, and thus damage may be assumed to have occurred to plant safety systems. The initial "report" should not be interpreted as mandating a lengthy damage assessment prior to classification. No attempt is made in th<ese> EAL to assess the actual magnitude of the damage. Escalation to a higher emergency class, if appropriate, will be based on <Equipment Failure, Electrical, Fission Product Barrier Degradation, Radioactivity Release, or SEC> Judgement ICs. Plant-Specific Information: The Calvert Cliffs EALs are based on report to the control room of damage affecting safe shutdown functions. EAL 1 addresses airplane, helicopter, barge, boat, train, car, or truck collisions. This EAL does not include vehicle crashes with each other, damage to office structures, or damage to structures that are not safety-related. Thus, EAL 1 is written as: Vessel or Vehicle Collision Affcctlng the Ability to Achie'v': O*r .intain Safe Shutdown Causing Observable Damage in an Area of Concern for Safe Shutdown Calvert Cliffs EAL Basis Document Rev. 5 CN600043

1OTHER HAZARDS EAL 2 is written as: Mssiles A efing the Ability to Aehf-i-. Or Maintain Safe S,-.do,... Causing Observable Damage in an Area of Concern for Safe Shutdown EAL 3 is written as: Flooding A ',tingthe Ability to A^hie,: . Or

                                                   .. M.int ain 83-Sc*

f Shutd,..A. Causing Observable Damage In an Area of Concern for Safe Shutdown Determination of whether the collision, missiles, or flooding are affecting ability to achieve or maintain safe shutdown is determined by physical observation, or by Control Room/local control station indications. Observation of damage to systems should be used to discriminate between major flooding and minor flooding or flooding in areas having a low probability of affecting safe shutdown. Operability determinations are not expected prior to declaration of this event-based EAL. The list of areas of concern for Safe Shutdown are shown below and are prominently displayed on the EAL Table. Areas of Concern for Safe Shutdown

• Control Room
• Electrical Penetration Rooms
• Control Room HVAC Room
• Auxiliary Feedwater Pump Room
• Cable Spreading Room
• Charging Pump Rooms

         " Cable Chases

• Diesel Generator Rooms

         " Switchgear Room

• Diesel Generator Building (0C/1A)

         "ECCS Pump Room

• Refueling Water Tank (RWT) 11(21)

         " Service Water Pump Room                                 - Condensate Storage Tank (CST) 12
         " Component Cooling Pump Room

• Pretreated Water Storage Tank (PWST) 11(21)

         "Main Steam Penetration Room

• Fuel Oil Storage Tank (FOST) 12 This list of Safe Shutdown areas is displayed on the EAL Tables to assure that all areas related to Safe Shutdown are considered by the SEC.

Source Documents/References/Calculations:

1. Updated Final Safety Analysis Report Calvert Cliffs EAL Basis Document 0:11 i 44...

                                                                               *. ... ...... i ..CN.6000.9 i .. ----..

Rev. 5

IGAS AND CHARLES CENTER

• P.O. BOX 1475 9 BALTIMORE, MARYLAND 21203-1475 LEON 1. RUSSELL MAKAW ftAFN4U 0iPAN'T~iNT June 6, 1991 Mr. James H. Joyner, Chief Facilities Radiological Safety and Safeguards Branch Division of Radiation Safety and Safeguards U.S. Nuclear Regulatory Commission Region I 475 Allendale Road King of Prussia, PA 19406

SUBJECT:

Calvert Cliffs Nuclear Power Plant Unit Nos. 1 & 2; Docket Nos. 50-317 & 50-318 Emergency Action Level Review Meeting

REFERENCES:

(a) Letter from Mr. J. H. Joyner (NRC) to Mr. G. C. Creel (BG&E), dated February 12, 1991 (b) Letter from Mr. G. C. Creel (BG&E) to Mr. J. H. Joyner (NRC), dated March 29, 1991

Dear Mr. Joyner:

This is to confirm arrangements for Baltimore Gas and Electric Company (BG&E) to meet with your staff on Thursday, June 20,1991, 10:.00 a.m., in the Nuclear Regulatory Commission (NRC) Region I Offices, King of Prussia, Pennsylvania. The purpose of this meeting is to present a proposed draft revision to Emergency Action Levels (EAIs). As you are aware, Reference (a) discusses the results of NRC staff review of Revision 14, Change 3 to the Emergency Classification and Action Level Scheme for Calvert Cliffs Nuclear Power Plant. This review concluded that the EAL scheme has been improved, but that additional changes are needed to meet the guidance of NUREG-0654. Reference (b) provides BG&E comment on the Staff's review and a schedule for implementing changes to the EAL scheme. In keeping with Rcfcrence (b), BG&E will present an EAL proposed revision in draft on June 20, 1991. The specifics on the revision will be discussed during this meeting. I want to thank you for making your staff available for this meeting. It is our endeavor to resolve NRC staff concerns in a timely manner. Getting togcther to review this proposal in draft should facilitate an understanding of the issues and expedite NRC's formal review (Region and NRR). E 1 T . . _ _ _ _ _ _

                                                                        --   "r "     j-J*,fr~Im'~

BA LTI MORE IGAS AND CHARLES CENTER

• P.O. BOX 1475
• BALTIMORE, MARYLAND 21203-1475 LEON 9. RUSSELL PLAI"IA OIPArTWM June 6, 1991 Mr. James HL Joyner, Chief Facilities Radiological Safety and Safeguards Branch Division of Radiation Safety and Safeguards U.S. Nuclear Regulatory Commission Region I 475 Allendale Road King of Prussia, PA 19406

SUBJECT:

Calvert Cliffs Nuclear Power Plant Unit Nos. 1 & 2; Docket Nos. 50-317 & 50-318 Emergency Action Level Review Meeting

REFERENCES:

(a) Letter from Mr. J. H. Joyner (NRC) to Mr. G. C. Creel (BG&E), dated February 12, 1991 (b) Letter from Mr. G. C. Creel (BGSE) to Mr. J. H. Joyner (NRC), dated March 29,1991

Dear Mr. Joyner:

This is to confirm arrangements for Baltimore Gas and Electric Company (BG&E) to meet with your staff on Thursday, June 20, 1991, 10:00 a.m., in the Nuclear Regulatory Commission (NRC) Region I Offices, King of Prussia, Pennsylvania. The purpose of this meeting is to present a proposed draft revision to Emergency Action Levels (EALs). As you are aware, Reference (a) discusses the results of NRC staff review of Revision 14, Change 3 to the Emergency Classification and Action Level Scheme for Calvert Cliffs Nuclear Power Plant. This review concluded that the EAL scheme has been improved, but that additional changes are needed to meet the guidance of NUREG-0654. Reference (b) provides BG&E comment on the Staff's review and a schedule for implementing changes to the EAL scheme. In keeping with Reference (b), BG&E will present an EAL proposed revision in draft on June 20, 1991. The specifics on the revision will be discussed during this meeting. I want to thank you for making your staff available for this meeting. It is our endeavor to resolve NRC staff concerns in a timely manner. Getting together to review this proposal in draft should facilitate an understanding of the issues and expedite NRC's formal review (Region and NRR). Er,

                                                                                   .  ... --   ,S.,7   ,
                                                                       . -* i' __    __      __      __  "' _

Mr. James H. Joyner June 6, 1991 Page 2 I envision this to be a working meeting of one to two hour duration. An agenda in. attached. Please don't hesitate to contact me at (301) 260-6680 if questions arise. Sincerely, Manager Nuclear Safety & Planning Department LBR/PEF/GLD/bjd Attachment cc: D. A. Brune, Esquire J. E. Silberg, Esquire R. A. Capra, NRC D. G. McDonald, Jr., NRC T. T. Martin, NRC L. F. Nicholson, NRC R. I. McLean, DNR J. H. Walter, PSC

t ATTACHMENT (1) BG&E / NRC MEETING Proposed EAL Revision Thursday, June 20, 1991 King of Prussia, Pennsylvania 10:00 a.m. Personnel introduction and introductory L B. Russell remarks. 10:10 a.m. Overview. T. E. Forgette

Background

Meeting process 10.20 a.m. EAL proposed revision presentation/ All discussion Unusual Event Alert Site Emergency General Emergency 11:20 am. (+) Meeting recount and adjournment T. E. Forgette

CALVERT CLIFFS NUCLEAR POWER PLANT PROBABILISTIC RISK ASSESSMENT Individual Plant Examination of External Events Summary Report August 1997

                                    ~4-.
                                         '2

CALVERT CLIFFS NUCLEAR POWER PLANT PROBABILISTIC RISK ASSESSMENT I PROJECT TEAM PROJECT MANAGER Bruce B. Mrowca BGE TEAM MEMBERS Gayle A. Blizzard Robert F. Cavedo Alex S. F. Deng Don W. Findlay Mark S. Graham Paul A. Jameson John G. Koelbel Ed R. Kreahling Timothy A. Rogers Eric A. Schade Jeff L. Stone DOCUMENT PREPARATION SUPPORT Helen C. Buck, Dawn M. Cox

Calvert Cliffs Nuclear Power Plant Individual Plant Examination External Events LIST OF EFFECTIVE PAGES Section Total Pages Introduction 14 1 2 2 2 3 40 4 95 5 44 6 18 7 4 8 4 Attachments Total Pages 4-A 5 4-B 13 4-C 2 4-D I 4-E 42 4-El 2 4-F 20 4-G 2 4-H 3 4-1 13 4-J 10 4-K 8 4-L 5 4-M 10 4-N 6 4-0 2 4-P 5 4-Q 3 4-R 6 4-S 5 4-T 4 4-U 14 BGE ii RAN 97-031

Caivert Cliffs Nuclear Power Plant Individual Plant Examination External Events Table of Contents 1.1 Background and Objectives.. ... .................. . .... . ..... ......... . ........ . .............. . .... . ........ . ........ 1.2 Plant Familiarization ...... _. ...................... . ........ .. ........ . .... . ............... . .... ........ 1.3 Overall Methodology ....... ....................... . ..... ................. . .......... . ..... . ........ . .... . ............. 1.4 Summary of Major Findings................... . .... .... ... ....................... . ..... . .... ........ 1-2 1.5 flCIC[Ir WIE3.................... ..- . 4 ..............

                                                                                                             ................                                 .....              ......      ................            .............         .1-2 2.1          JL1Z&rVUU%;UUU ....               ........
                                                         .     ...     .............  . ....        ...........        . .........      . .....   . ..... .....    .    ...       .......   . ......       . ........   . .... .....        - &-   a 2.2         Conformance with Generic Letter and Supporting Material .                                                                                     .................-....                            ............ 2-1 2.3         General Methodology..........                                     .... ..............................                                             ...-.............                .. ......-.                        4.2-1 2.4         Information Assembly ......                                   ........................ r.                         ..................    .........................-..                                                        2-3 3.0          Methodology Selection                     ................                          .            ...
                                                                                                                ..-                  ................................................ 3-1 3.0.1        Coordination with US! A-46 ....................... ....... . ................ ..... .. 3-1 3.1         Seismic PRAt                . ..................                               .444 .            ... ................ 4.               4.4           .......         .-.....3-1   ............         .. ......

3.1.1 Seismic Hazard Evaluation ..... .... ........ ..... ....................................

                                                                                                                                                        .        ...                                                              ......       3-1 3.1.2       Review of Plant Information and Walkdowns.................................................                                                                                                                     .......-..      3-3 3.1.3       Analysis of Plant System and Structure Response ......................................................                                                                                                                         3-4.

3.1.4 Evaluation of Component Fragilities and Failure modes ................................................... 3-7 3.1.5 Analysis of Plant Systems and Sequences .... .......... ........ ............................ ........... 3-9 3.1.6 Analysis of Containment Performance ................ .....-.......................................

                                                                                                                                                  ....                                                                                       3-21 3.2          US! A-45 and Other Seismic Safety Issues ..........-...............................................3-23 3.2.1        US! A-45 Background ...................-............................................................ 3-23 3.3          References                 .......................................................................................                                                                                                             253 3...2 4.0          Methodology Selection...........                                            ............................................................... . 4-1 4.1          Fire Hazard Analysis...........................................                                                                  ........................................... 4-1 4.1.1        Key Assumptions .....44 ....................................                                   . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . .. . . . . 4 -3 4.2          Review of Plant Information and Walkdown .......................................................                                                                                                                    ..... _4-3 4.2.1        Plant Fire Protection Program Description ..............................................................                                                                                                                      4-4 4.2.2        Plant Familiarization........................................................................................ 4-4 4.2.3        Plant W akd alkdow..................................................

w ... ........................... 8-Zn 4.3 Fire Growth and Propagation ............................................................................ 4-9 4.3.1 Identification of Fire Areas to he Analyzed ....... 4......... .................................. ....4-9 4.3.2 Quantification of Fire Ignition Frequencies ............................................................ 4-22 4.3.3 Treatment of Cross-Zone Fire Spread ................. ............ ................ .......... . .4-25 4.3.4 Detailed Fire Modeling .................................-................................................ 4-30 4.4 Evaluation of Component Fragilitles and Failure Modes ............................................. 4-39 4.4.1 Cable Analysis.......................................... .............................................. .4-39 4.5 Fire Detection and Suppression.................................................................. 4-40 4.6 Analysis of Plant Systems%Sequences and Plant Response........................................4-41 4.6.1 Fire Top Events................................................................................. 4-42 4.6.2 Fire Spilt Fractions........................................................................ ..... 4-44 4.6.3 Evaluation of Human Recovery Actions........................................................ .. ...4-46 4.6.4 Initiating Events................................................ ts. ......... .................. .:15

                                                                                                                                                                                                                                          .4...

4.6.5 Compaurtmesnt Avualuck ..................... . ........ . .... . ........... . .................... . .............................................. CAA 4.6.6 Cross-Zone Analysis ... ...................... .. . .......... . ....... . .......... . ............. 6... ....................... . .... 4-56 4.6.7 Unit 1 Fire Risk Assessment Results .......... .. . .............................. . ................. . ............... . ... 6... .... 4-57 4.6.8 Unit 2 Fire Assessment ... ..................... .. ............................ 66.. ............... . ................ ............ 4-60 4.7 Analysis of Containment Performance.._. .................................. . ................ . ............................. 4-63 4.8 Treatment of Fire Risk Seoping Study Issues .. . ................................... 4- 6........................... . ......... 4-63 4.8.1 Qc;.m-1.jra.~ I #~. *nla Lt......................

                                                                 .~44
                                                                   . ..................                              4...........4.......4....4
                                                                                                                      .~b...                                                            ...........                                            4-64 Table of Contents (cont'd)

RAN 97-031 iii BGE iii RAN 97-031

Calvedt Cliffs Nuclear Power Plant Individual Plant Examination External Events 4.8.2 Fire Barrier Qualification . .............. ................................-......................... 65 4.8.3 Manual Firefighting Effectiveness ..........-................. ...... .................................. 4-65 4.144 Total Environment Equipment Survival ..................... ............ ............ .... ....... 4-66 4.8.5 Control Systems Interactions.-.. ...... ............ ........................ ........ ............ _ 4-67 4.8.6 Improved Analytical Codes ..........

                                                                               ...               ...................                         ..............-       .. .. ...                            ....-...... 8 4.9          USI A-4S and other Safety Issues ...............................                                                                   .......................-                       ............ 4-68 4.9.1         USI -45 Background ......                  .4....            ...........................................                                            .................
                                                                                                                                                                          ...                                    -. 4-68 4.9.2        Generic Issue 57, "Effects of Fire Protection System Actuation"...-........                                                                                               ........
                                                                                                                                                                                  -....-                   ...... 46 4.10          References ..................                   ..................................-................................ 4-71 5.0           Introduction ..............................................                                                    ....                         .........                  ..... .........       ....  ..... &-I 5.1          Generic Plant Description.................-.                                  .....................-................                                                ....................5-1 5.1.1         Site Description ..                 .
                                              .....         ........... .......... .......                     .............                      . .... 9.. ... ...         . .... ............... _._            5-1 5.1.2         Identification of Structures, Systems and Components Susceptible to External Events .....-...5-2 5.2           Screening of External Hazards.                                 -.........       ...............-
                                                                                                     .........                    ....................                                           ........           ...5-3 5.2.1         Description of Approach            ......................-......                    .....................-..............                                                   ..................              5-3 5.2.2         Results of Screening Analysis-........ ......-....                  .                        9................................                                ................-...............             5-4 5.3           Hih    Winds....................................................................................

iHigh.. ... -5 5.3.1 Design of Plant Structures for High Winds ........ ............................

                                                                                                                                -                                            . ............                         ...5-4 5.3.2        Identification of Structures and Components Susceptible to Wind Damage....                                                                                                     ............
                                                                                                                                                                                                  .....                  5-5 5.3.3         Impact of High Winds on the Plant ........-...-...... ............................                                                      .....                                      .............. 5-9 5.3.4        Analysis of Risk from Tornadoes and Missiles ..................-...................................... 5-9 5.3.5        Analysis of Risk from Hurricanes                          .............                               ...........-..........       ....................                                   ......... 5-12 5.3.6.       Plant Model Quantification of High Winds Impact........                                                              .      ...                       -...-.........................              ....5-12 5.3.7        Summary of High Winds.......................................................................... 5-15 5.4           External Floods................................................................................... 5-15 5.4.1        Comparison of Plant Design Against 1975 SlIP.....................................................5-16 5.4.2        Effects of Local Intense Precipitation .......-...............                                                             ........................................ 5-18 5.5          Transportation and Nearby Facilities Accidents ........-............                                                            .............. ............... 5-19 5.5.1        Aircraft Hazard .................                                   .-...................................................................                                                                5-19 5.5.2        Transportation Hazards........                        .......-..........                              ...................................................... 5-23 5.5.3        Nearby Facility Hazards . ............                                                        ............................................................ 5-27 5.5.4        Onsite Chemical Storage ....                       ................................                            ....                  ...                   .................. . .. 5,27

• 5.6 Turbine Missiles................................................................... ............ .... 5-28 5.6.1 Turbine Description ...................-....................... .. ........................ ......... ...5-28 5.6.2 Mechanism of Turbine Failures and Missile....................-.....................................5-29 5.626. U itI.....Unit.......................................................... .................................. 5-29.'2 5.6.3 Safety-related Equipment Susceptible to Damage from Low Trajectory .............................. 5-29 5.6.4 Analysis of Risk from Turbine Missile Generation...............................................5-30 5.6.5 Summary of Turbine Missiles ..... ......................................................

                                                                                ..........                                                                                                                             5-32 5.7           Overall Conclusions ........................                                   ......................................                                       .................-                           53 5.8R                         .

fe eneReferences ............................................. .. .... .............-...... ........... 343 6.1 IPEER Program Organization ..-..................... ................... .......-............. 6(-1 6.2 Composition of Independent Review Teams ................ 4.....- .............................. 6-1 6.2.1 Seismic............................. eimi .. .......................................... ............. ...... 6..62 6.2.2 Other External Events ................... ......

                                                                                                 ...........-                                  ............-..................................                           6-2 6.232ir....Fire           ...........................................                                          ..........-
                                                                                                                                                                                                         -......          6   6.3           Areas of Review and Major Comments..................................                                                                   . ......................                                     _      6-2 Table of Contents (cont'd)

BGE iv UGE 97-031 ivRAN

Calvert Cliffs Nuclear Power Plant Individual Plant Examination External Events 6.4 Resolution of Comments .................................................................................................... 6-2 7.1 Helicopter Flights ...................................................................................................................... 7-1 7.2 Switchgear Room Ventilation Recovery During A Hurricane ......... .71 . ...... 7.3 Smoke Infiltration Into the Control Room via Ventilation Intake ................................................. 7-2 7.4 Inadvertent Isolation of Switchgear Room and Cable Spreading Room Ventilation ................. 7-5 7.5 Barrier Inspections .........-........................................ ............................ .............. 7-6 8.1 Seismic Analysis ............................................................................................. . . 8-1 8.2 Fire Analysis ............. .. .............................................................. .......................... 8-2 8.3 Other Events Analysis .................................................... ............... ...... 8-3 8.4 Proposed Resolution of Unresolved Safety Issues and Generic Issues . ............. .................... 8-4 RAN 97-031 V BGE V RAN 97-031

Calvert Cliffs Nuclear Power Plant Individual Plant Examination External Events List of Attachments Attachment Tab Description A A225 Unit Radiation Exhaust Equipment Room (Fan Room) B A226 Unit I Service Water Pump Room C A227/A316 East Piping Penetration Rooms D A228 Unit I Component Cooling Water Pump Room E CSR Unit I & 2 Cable Spreading Room El CSR Passageway F SWGR Switchgear Rooms G A315 Unit I Main Steam Isolation Valve Room H A318 Unit 1 Purge Air Supply Fan Room I MCR Main Control Room J A419 Adjoining areas of the 45' Elevation of the Auxiliary Building K A423 Unit I West Electrical Penetration Room L A429 Unit I East Electrical Penetration Room M A5 12 Control Room H-IVAC Room, Spent Fuel Vent Room, Unit I Main Vent Fan Room, Unit 1 Containment Access Area N A529 Unit 1 69' West Electrical Room 0 AB Auxiliary Building Stairtowers P CC-AB Cable Chases IA, I B, 2A, 2B, AS 18, and A517 Q CC-C Cable Chases IC & 2C R INTAKE Intake Structure S T603 Unit I AFW Pump Room T TB Unit I and 2 Turbine Building U YARD Yard Areas BGE Ai RAN 97-031

Calvert Cliffs Nuclear Power Plant Individual Plant Examination External Events List of Figures Figure Title Page Number Number 3-1 Failure Probability vsISeismic g (Short Term Actions) 3-30 3-2 Failure Probability vs. Seismic g (Long Term Actions) 3-34 3-3 Seismic Core Damage Frequency Contribution vs. Peak Ground 3-35 Acceleration 4.3 - I Auxiliary Building -10' and -15' Level 4-18 4.3 - 2 Auxiliary Building 5' Level 4-19 4.3 - 3 Auxiliary Building 27' Level 4-20 4.3 - 4 Auxiliary Building 45' Level 4-21 4.3 - 5 Auxiliary Building 69' Level 4-22 5.3 - 1 Plant Layout (Tornado Nodes Assignment) 5-35 8.2 - 1 Fire Contributors by Area 8-2 4-I-1 Main Control Room 4-1-6 4-U- I Plant Layout (Transformer Locations) 4-U- 13 RAN 97-03 1 vii BGE BGE vii RAN 97-031

Calvert Cliffs Nuclear Power Plant Individual Plant Examination External Events List of Tables Table Title Page Number Number 3-1 CCNPP Seismic Hazard Curve Values 3-30 3-2 Seismic Initiating Events 3-31 3-3 Fragilities of Selected Equipment for CCNPP 3-32 3-4 Seismic Split Fraction Values 3-33 3-5 Median Capacities and HCLPF Values for Buildings & Structures 3-34 3-6 Seismic Contribution to Frequencies of Major Containment Failure 3-35 Categories From The Key Plant Damage States 3-7 Top 100 Seismic Core Damage Sequences 3-36 3-8 Partial List of Split Fraction Descriptions and Values 3-39 4.3.1 Appendix R Fire Area to CCFPRA Compartment 4-11 4.3.1.1 Subdivided Fire Areas 4-13 4.3.1.2 Screened Rooms - No PRA Compartments or Cables 4-14 4.3.1.3 Screened-Low Functional Impact 4-15 4.3.1.4 Screened Rooms-Low Fire Ignition Frequency 4-16 4.3.2.a Fire Ignition Room Weighting Factors 4-23 4.3.2.b Fire Ignition Sources 4-25 4.3.3.a Barriers in an Inspection Program 4-27 4.3.3.b Barriers in a Control Program 4-28 4.3.3.c Rooms Fire Modeled for Barrier Effectiveness 4-31 4.6.3. I a Human Action Fire Models 4-50 4.6.3. l b Human Action Fire Model 5 Performance Shaping Factors 4-51 Impacted 4.6.5a Single Compartment Fire Initiators 4-56 4.6.5b Group Compartment Fire Initiators 4-56 4.6.5c Fire Modeled Compartments 4-57 4.6.6a Cross-Zone Fire Initiators Analysis 4-58 4.6.7 CCFPRA Results Summary 4-60 4.6a Unaccounted Frequencies & Sequence Count 4-75 4.6b Top Events 4-80 4.6c Top 100 Sequences 4-86 4.6.d Split Fraction Descriptions 4-89 4.7 Frequencies of Major Containment Failure Categories 4-96 5.3.4.2 Affected Components Group 5-11 5.2.2 External Events Considered 5-36 5.3.6.1 Split Fraction Definition and Values 5-39 5.3.6.2 High Wind Sequences 5-43 6.3 IPEEE Peer Review Comments and Resolutions 6-3. 4-A-1 A225 Fire Scenarios Summary 4-A-I 4-A-2 A225 Fire Analysis Results 4-A-2 RAN 97-031 viii BGE viii RAN 97-031

Calvert Cliffs Nuclear Power Plant Individual Plant Examination External Events List of Tables (cont'd) Table Title Page Number Number 4-B-I A226 Fire Scenario Summary 4-B-2 4-B-2 A226 Fire Analysis Results 4-B-3 4-C-I A227/A316 Fire Analysis Results 4-C-1 4-E-1 A306 Fixed Ignition Fire Scenarios Summary 4-E-2 4-E-2 A306 Transient Fire Scenarios Summary 4-E-5 4-E-3 Cable Spreading Room Fire Analysis Results 4-E-7 4-E-4 A306 Transient Fire Scenarios and Frequency Summary 4-E-15 4-E-5 A302 Fixed Ignition Fire Scenarios Summary 4-E-26 4-E-6 A302 Transient Fire Scenarios Summary 4-E-30 4-E-7 Cable Spreading Room Fire Analysis Results 4-E-31 4-E-8 A302 Transient Fire Scenarios and Frequency Summary 4-E-35 4-F-I Unit 2 27' Switchgear Room (A3 11) Fire Scenario Summary 4-F-2 4-F-2 Unit 2 27' Switchgear Room (A31 1) Fire Analysis Results 4-F-3 4-F-3 Unit 1 27' Switchgear Room (A317) Fire Scenarios 4-F-4 4-F-4 Unit 1 27' Switchgear Room (A317) Fire Analysis Results 4-F-6 4-F-5 Unit 2 45' Switchgear Room (A407) Fire Scenario Summary 4-F-8 4-F-6 Unit 2 27' Switchgear Room (A407) Fire Analysis Results 4-F-9 4-F-7 Unit I 45'Switchgear Room (A430) Fire Scenarios 4-F-10 4-F-8 Unit 1 45' Switchgear Room (A430) Fire Analysis Results 4-F-12 4-I- I Control Room Panels 4-I-1 4-1-3 Treatment of Potential Control Room Panel Fire Propagation 4-1-12 4-J-1 A419 Fire Analysis Results 4-J-2 4-K-I A423 Fixed Ignition Fire Scenario Summary 4-K-I 4-K-2 A423 Transient Fire Scenario Summary 4-K-2 4-K-3 A423 Fire Analysis Results 4-K-2 4-L-3 A429 Fire Analysis Results 4-L-2 4-M-1 A512 Fire Scenario Summary 4-M-2 4-M-2 A524 Fire Scenario Summary 4-M-4 4-M-3 A5 12/A524 Fire Analysis Results 4-M-5 4-N-I A529 Fixed Ignition Fire Scenario Summary 4-N-I 4-N-2 A529 Transient Fire Scenario Summary 4-N-I 4-N-3 A529 Fire Analysis Results 4-N-2 4-P-I Cable Chase Fire Scenario Summary 4-P-2 4-P-2 Cable Chase Fire Analysis Results 4-P-3 4-R-I INTAKE Fire Scenarios Summary 4-R-I 4-R-2 INTAKE Fire Analysis Results 4-R-2 4-S-1 Fixed Ignition Fire Scenarios Summary 4-S-1 4-S-2 T603 Transient Fire Scenarios Summary 4-S-1 4-S-3 T603 Fire Analysis Results 4-S-2 4-T- 1 Turbine Building Fire Analysis Results 4-T- 1 RAN 97-03 1 ix BGE ix RAN 97-031

Calvert Cliffs Nuclear Power Plant Individual Plant Examination External Events List of Tables (cont'd) Table Title Page Number Number 4-U-I Yard Fire Scenario Summary 4-U-2 4-U-2 Yard Fire Analysis Results 4-U-4 4-U-3 Transformer/Intake Distance Determination 4-U-8 4-U-4 Historical Wind Speed and Direction 4-U-9 4-U-5 Probability of Smoke Impact Due to Wind 4-U-10 BGE X RAN 97-031

Calvert Cliffs Nuclear Power Plant Individual Plant Examination External Events List of Acronyms AC Air Conditioning ACA Access Control Area ADV Atmospheric Dump Valve AFAS Auxiliary Feedwater Actuation System AFW Auxiliary Feedwater AIB Auxiliary Improvement Bulletins AOPs Abnormal Operating Procedures APCSB Auxiliary and Power Conversion System Branch ASA All Support Available ASCE American Society of Civil Engineers ATWS Automated Transient Without Scram BAST Boric Acid Storage Tank BGE Baltimore Gas & Electric BTP Branch Technical Position CAC Containment Air Coolers CCDP Conditional Core Damage Probability CCFPRA Calvert Cliffs Fire Probabilistic Risk Assessment CCNPP Calvert Cliffs Nuclear Power Plant CCPRA Calvert Cliffs Probabilistic Risk Assessment CCSPRA Calvert Cliffs Seismic Probabilistic Risk Assessment CCW Component Cooling Water CDF Core Damage Frequency CEA-MG Controlled Element Assemblies - Motor Generator CEDM Control Element Drive Mechanism CEDS Control Element Drive System CH Channel CKV Check Valve CNTMT Containment CR Control Room CRS Circuit & Raceway System CSAS Containment Spray Actuation System CSR Cable Spreading Room CST Condensate Storage Tank CV Control Valve DAS Data Acquisition System DBE Design Basis Earthquake DHR Decay Heat Removal DWT Demineralized Water Storage Tank ECCS Emergency Core Cooling System EDGs Emergency Diesel Generators EHC Electro-Hydraulic Control EMD Emergency Management Division EOPs Emergency Operating Procedures EPRI Electrical Power Research Institute ERPIP Emergency Response Plan Implementation Procedures ESFAS Emergency Safety Feature Actuation System FAA Federal Aviation Agency BGE xi RAN 97-031

Calvert Cliffs Nuclear Power Plant Individual Plant Examination External Events List of Acronyms (cont'd) FCIA Fire Compartment Interaction FCR Facility Change Request FEDB Fire Events Database FEMA Federal Emergency Management Agency FIVE Fire-Induced Vulnerability Evaluation FOST Fuel Oil Storage Tank FPRA Fire Probabilistic Risk Analysis FRSS Fire Risk Scoping Study HCLPF High Confidence of Low Probability of Failure HCR Human Cognitive Reliability HDR Header HELB High Energy Line Break HEPA High Efficiency Particulate Air HGL Hot Gas Layer HMR Human Action Methodology Report HPSI High Pressure Safety Injection HRA Human Reliability Analysis HRR Heat Release Rate HVAC Heating Ventilation Air Conditioning HX Heat Exchanger IA/PA Instrument Air/Plant Air IE Initiating Event IEEE Institute of Electrical and Electronic Engineers ILRT Individual Leak Rate Test IPE Individual Plant Examination IPEEE Individual Plant Examination of External Events ISFSI Independent Spent Fuel Storage Installation ISFSI Independent Spent Fuel Storage Installation LLNL Lawrence Livermore National Laboratory LLOCA Large LOCA LNG Liquified Natural Gas LNG Liquified Natural gas LOCA Loss of Coolant Accident LOOP Loss Of Offsite Power LPSI Low Pressure Safety Injection LTM Low Trajectory Missile MCCs Motor Control Center MCR Main Control Room MFW Main Feedwater MOV Motor Operated Valve MSDS Material Safety Data Sheet MSIV Main Steam Isolation Valve MSL Mean Sea Level MTC Moderate Temperature Coefficient MU Make Up NAS Naval Air Station NFPA National Fire Protection Association RAN 97-031 xii BGE xii RAN 97-031

Calvert Cliffs Nuclear Power Plant Individual Plant Examination External Events List of Acronyms (cont'd) NM Nautical Mile NRC Nuclear Regulatory Commission NSAC Nuclear Safety Analysis Center NSR Non-Safety Related NSSS Nuclear Steam Supply System OBE Operational Basis Earthquake OBE Operational Basis Earthquake 01 Operating Instructions OL Operating License OP Operator ORE Operator Reliability Experiments OTCC Once Through Core Cooling PCB Polychlorinated Biphenyl PDS Plant Damage State PE Performance Evaluation PEG Plant Engineering Guideline PGA Peak Ground Acceleration PMH Probable Maximum Hurricane PMP Probable Maximum Precipitation PNS Probability of Non-Suppression PORV Power Operated Relief Valve POSRC Plant Operations Safety Review Committee PP Pump PRA Probabilistic Risk Assessment PSF Pounds Per Square Foot PSF Performance Shaping Factors PTS Pressure Thermal Shock PWST Pre-Treated Water Storage Tank QA Quality Assurance RAS Recirculation Actuation System RC Reactor Coolant RCP Reactor Coolant Pump RCS Reactor Coolant System RCW Reactor Coolant Waste RLE Review Level Earthquake RMIEP Risk Methods Integration and Evaluation Program Methods Development RMS Radiation Monitoring System RPS Reactor Protection System RRS Reactor Regulating System RWT Refueling Water Storage Tank S&A Stevenson & Associates S/D Shutdown S/G Steam generator SBO Station Blackout SCBA Self-Contained Breathing Apparatus SF Split Fraction SFP Spent Fuel Pool RAN 97-031 xiii BGE xiii RAN 97-031

Calvert Cliffs Nuclear Power Plant Individual Plant Examination External Events List of Acronyms (cont'd) SGos Steam Generator Isolation Signal SIAS Safety Injection Actuation System SLB Steam Line Break SLI Success Likelihood Index SLIM-MAUD Success Likelihood Index Methodology - Multi-Attribute Utility Decomposition SNL Sandia National Laboratory SPT Standard Penetration Test SQUG GIP Seismic Qualification Utility Group Generic Implementation Procedure SR Safety Related SRP Standard Review Plan SRT Seismic Review Team SRV Safety Relief Valve SRW Service Water SSE Safety Shutdown Earthquake SSI Soil Structural Interaction SSSA Spurious Safety System Actuation STP Surveillance Test Procedure SW Saltwater SWAC Salt Water Air Compressor SWGR Switchgear TIG Turbine Generator TBV Turbine Bypass Valve TNT Trinitrotoluene TSC Technical Support Center TURB Turbine UFSAR Updated Final Safety Analysis Report USDOT United States Department of Transportation USI Unresolved Safety Issue USNRC United States Nuclear Regulatory Commission UV Undervoltage VCT Volume Control Tank VMT Vessel Melt Through WANO World Association of Nuclear Operators XFMER Transformer ZPA Zero Period Acceleration BGE xiv, RAN 97-031

Calvert Cliffs Nuclear Power Plant Examination Description Individual Plant Examination External Events SECTION 2 EXAMINATION DESCRIPTION 2.1 Introduction The requirements for CCNPP's IPEEE are satisfied with this submittal. CCNPP's IPEEE was started shortly after the completion of the IPE. As in the IPE, one of CCNPP's objectives was to utilize the in-house staff to the maximum extent possible to retain the knowledge within the utility. The IPEEE process was initiated consistent with the requirements of Generic Letter 88-20, Supplement 4 and using NUREG-1407 as guidance. The examination process, methodology and information assembly are described in the following sections. 2.2 Conformance with Generic Letter and Supporting Material The major objectives of CCNPP's IPEEE are to meet the purposes of the IPEEE stated in the Generic Letter 88-20 (i.e., to develop an overall appreciation of severe accident behavior due to external events, to understand the most likely severe accident sequences that could occur under full-power operating conditions for these events, to gain a qualitative understanding of the overall likelihood of core damage and radioactive material release, and if necessary, to reduce the overall probability of core damage and radioactive material release by appropriate modifications to plant operating procedures and hardware that would help prevent or mitigate severe accidents). As evidenced by the results documented in the various sections of this report, the active and direct involvement in the development and performance of the various IPEEE tasks has provided the means for BGE: (I) to understand severe accidents at the broad and detailed levels, (2) to understand the most likely severe accident sequences, dominant contributors to these sequences, and the resulting consequences, (3) to have an overview of the significance and magnitude of the most probable core damage sequences and release states, (4) to identify the vulnerabilities and recommend corrective actions in terms of design modification and/or procedure changes in order to reduce the overall core damage frequency. 2.3 General Methodology The IPEEE for CCNPP is performed using the approaches identified in NUREG-1407. The general methodology being used specifically for each task is summarized below: The report is written from a Unit I perspective. Key differences between the Units are assessed. A seismic PRA is performed for CCNPP using the approaches described in NUREG-1407 and EPRI NP-6041-SL. Section 3 of this report provides a detailed description of the methods used. A very comprehensive component walkdown list is first developed followed by a screening process using the DGE 2-1 RAN 97-031

Calvert Cliffs Nuclear Power Plant Examination Description Individual Plant Examination External Events results from extensive plant walkdowns. The results from the A-46 project are also utilized for screening. HCLPF (high-confidence-of-low-probability of failure) calculations are performed for the second screening followed by detailed fragility calculations for all the non-screened components. A HCLPF of 0.3g is used for screening. Soil liquefaction, soil-structural interaction and structural fragility analyses are also performed and the results are used as input for the component HCLPF and fragility calculations. The seismic initiating events are developed using the results from the fragility calculations. The annual probability of exceedance for peak ground acceleration from the Revised Livermore Seismic Hazard Estimate (NUREG -1488) for CCNPP is used for the initiating events binning. All the non-screened components are grouped as a surrogate component which is assumed to lead directly to core damage when failed. The seismic impact in terms of core damage frequency and containment performance are quantified using a modified version of CCNPP's IPE submittal model. Contractors with specific seismic expertise were utilized, for example, EQE International performed the component walkdown, HCLPF screening and fragility calculations. Stevenson & Associates performed all the soil structural related analyses. Fire A fire PRA is performed for CCNPP using the approaches described in NUREG-1407 and the EPRI Fire PRA Implementation Guide. Section 4 of this report provides a detailed description of the methods used. The Fire Induced Vulnerability Evaluation (FIVE) methodology is used as guidance for the evaluation of specific scenarios within a compartment when the failure of the entire compartment is proven to be significant. The quantification of the fire induced core damage frequency is performed using a modified version of CCNPP's IPE submittal model. A containment performance review is also performed to identify any sequences that would lead to containment failure. Other External Events For the risk assessment of the other external events, the approaches provided in NUREG 1407 are followed, i.e., an initial screening analysis is performed followed by bounding or detailed analyses as necessary. Thus, the analysis process basically follows the steps outlined in Figure 5.1 of NUREG-1407. Section 5 of this report provides the detailed description of the methods used. 2.4 Information Assembly The IPEEE process includes a considerable effort to assemble information relevant to all of the external events analyzed. A variety of internal and external information sources are utilized to support the IPEEE. Examples of internal documents are: UFSAR, Ols, AOPs, EOPs, ERPIP, various design calculations, etc. Examples of external documents are: NUREGs, Regulatory Guides, vendor's design calculations including Bechtel and turbine vendors, federal and local governments' reports on related subjects, etc. The reference sections provided in Sections 3, 4 and 5 of this report provides more details on the information obtained for the seismic, fire and other events analyses. BGE 2-2 RAN 97-031

Calvert Cliffs Nular Power Pleat Seismc Analysis Individual Plat Examination External Events SECTION 3 SEISMIC ANALYSIS 3.0 Methodology Selection CCNPP's PRA was performed to satisfy the IPE requirements for internal initiating events on CCNPP. To assess the risk contribution and significance of seismic initiated events to the total plant risk, Baltimore Gas and Electric Company selected the PRA method for the seismic analysis to meet the requirements of the IPEEE. The PRA method is selected over the seismic margins method because it allows component risk ranking and provides the ability to relate the seismic risk to the risk from internal events and other external events providing insight to the total risk profile. The Seismic PRA is performed using the methodology outlined in NUREG-1407 (Ref. 3-13). The general transient linked event tree model is used to quantify seismic induced core damage frequency. A seismic event tree is added in front of the model to assess the probability of system failures directly due to the seismic event. The impact of the seismic event tree top event failures are then cascaded into the general transient event trees using split fraction assignment rules to reflect the dependencies of the seismic failures on the downstream top events. Thirty seismic initiating events are used to generate accident sequences. These sequences are then analyzed to identify any potential vulnerabilities. 3.0.1 Coordination with USI A-46 Since the USI A-46 and Seismic IPEEE programs are similar in many respects, the programs where possible were coordinated to gain efficiency. EQE International, Inc. was contracted to perform equipment walkdowns and evaluations for both the USI-A46 and Seismic IPEEE programs. The primary area of overlap between the two programs occurred in the component walkdown evaluation. The USI A-46 walkdowns followed the guidelines in the Seismic Qualification Utility Group (SQUG) Generic Implementation Procedure (GIP). These walkdowns are documented with detailed seismic evaluation worksheets, calculations and photographs. The seismic PRA takes into account the results of the A-46 walkdowns and anchorage calculations for equipment that appears in both programs. 3.1 Seismic PRA 3.1.1 Seismic Hazard Evaluation 3.1.1.1 Seismic Hazard Curves Seismic hazard curves were developed for the CCNPP site by EPRI and LLNL. NUREG-1407 states that if only one set of curves are used for the analysis, the higher of the two should be used. For the CCNPP site, the LLNL curves are higher. The updated LLNL curves, provided in NUREG-1488 (Ref. 3-5), are used for the CCNPP Seismic PRA (CCSPRA). These curves are used as the basis for the seismic initiating BGE 3-1 RAN 97-031

CdVrt Clif NOeCtr Power PAMt Seismic Analysis Individual Pint Examinaton Encrst Evctu event frequencies used for quantification and for the sod-structure interaction analysis and structure fragility calculations performed by S&A (Ref. 3-1). Table 3-1 shows the Updated LLNL Seismic Hazard Curve Values for CCNPP. This table gives estimates for the annual probability of exceeding ten peak ground acceleration levels ranging from 50 to 1000 cm/sec/sec. The CCSPRA uses these values to generate thirty bins ranging firm 12.5 to 1500 cm/sec/sec. These bins are shown in Table 3-2. A relatively high number of bins is used to attempt to minimize the conservatism in the calculation of the core damage frequency. Acceleration levels below the given range are logarithmically extrapolated and those above the given range are exponentially extrapolated to obtain the corresponding frequencies. 3.1.1.2 Liquefaction Analysis The liquefaction analysis was performed, along with the soil-structure interaction analysis and structure fragility calculations, by S&A. The results of the analysis are contained in Ref. 3-1 and are summarized here. CCNPP is located on a deep-soil site. The stratigraphy consists of a sequence of Quaternary, Tertiary, and Cretaceous sand, silt, clay, and gravel deposits which are about 2,500 feet thick at the site. Existing available soil boring data includes that obtained from borings made in the 1967 & 1968 time frame prior to the initial excavation work as well as more recent borings made for the new Diesel Generator Project. The new Diesel Generator Project added two new diesel generators, one self-cooling safety-related diesel in a concrete building and one augmented quality diesel enclosed in a steel frame building. The safety-related Diesel Generator Building was evaluated for liquefaction analysis. This building is referred to here and in Ref. 3-L as the New Diesel Generator Building. The results of the liquefaction evaluation conducted for the Containments, Auxiliary Building, Turbine Building, and the Intake Structure, indicate that the supporting soils are not subject to liquefaction for the Review Level Earthquake (RLE) with a peak ground acceleration of 0.4g. For the new Diesel Generator Building, initial liquefaction is expected to occur at a median peak ground acceleration of 0.27g with a range of 0.2g to 0.36g. The stratum considered in determining the Zero Period Acceleration (ZPA) levels at which liquefaction could be imminent below the New Diesel Generator Building is located 16 feet below the foundation of the building and is (on average) nine feet thick. Due to this, plus the fact that the differential contact pressure is small compared to the existing overburden pressure prior to excavation (an increase of 1.2ksO, stability failure is not considered a realistic hazard. Hence, the only remaining issue for the new Diesel Generator Building is liquefaction-induced settlement, which is addressed below. 3.1.1.3 Seismically Induced Settlements of Structures Seismic-induced settlements are estimated using empirical correlations. For the Containments, Auxiliary Building, and Intake Structure, essentially no seismic-induced settlements are indicated. Total seismic-induced settlement for the ground without any structures (i.e., considering the full soil column and blow counts from test borings made in areas not directly below any structure) is estimated to be 0.25 inches. Total seismic-induced settlements for the Turbine Building are estimated to be 0.5 inches and a total TPANM01.fM I BGE 1-7

Calver CU& Nudler Power Sic Anlys Individual Plant Examiation External Events settlement ranging from 0.3 inche to 0.75 inches for the new Diesel Generator Building again due to the range in Standard Penetration Test (SPi) blow counts for the six test borings. This amount of s is not considered significatL A conservative review of the differential displacements between buildings (performed for the Containments and Auxiliary Buildings) indicates a probability of 0.1 that the buildings will impact if subjected to the RLE and assuming out-of-phase displacement. The effects of this interaction are not modeled. 3.1.2 Review of Plant Information and Walkdowns The walkdowns were conducted by a Seismic Review Team (SRT) consisting of personnel from EQE and CCNPP. The purposes of the walkdown were to: 1) visually inspect and screen-out inherently rugged components from further review, 2) define the failure modes (such as anchorage failure) and elements which are not screened, and 3) add to the analysis any seismic interaction items judged to be a potentially serious problem. The scope of the walkdowns and screening covered only equipment and components. Structure and soil analyses were performed separately by S&A and is discussed in Sections 3.1.1.2 and 3.1.3.1. The component walkdown list is compiled from the components in the PRA database and the Q-list (Ref. 3-22). Initial screening is performed on these components as described in IPEEE Seismic Component Walkdown List, Ref. 3-3. For example, check valves are inherently rugged and are screened from the walkdown list. In addition, systems such as Main Feedwater, Condensate, and Circulating Water are not walked down because of their low importance in the PRA. Components that passed this initial screening comprise the walkdown list and were walked down. The Seismic IPEEE is closely coordinated with USI A-46. Most of the components included in the Seismic IPEEE walkdown are also on the USI A-46 Safe Shutdown Equipment List. The scope of the Seismic IPEEE walkdown includes the additional work necessary to supplement the work done during the USI A-46 walkdown. The scope of the walkdown also includes the identification of higher capacity equipment and components which may be screened out from explicit consideration in the CCSPRA. NUREG-1407 directs that the walkdown follow the guidelines of EPRI NP-6041-SL, Rev. I (Ref. 3-4). The guidelines contained therein are used for both the walkdown and the screening out of higher capacity Components. 3.1.2.1 Component Screening For screening, the guidelines of Table 2-4 of EPRI NP-6041 are used. The guidelines are set to screen earthquakes of about 0.3g and 0.5g peak ground acceleration (0.Sg and 1.2g peak spectral acceleration). For USI A-46, the equipment is evaluated for the plant's safe shutdown during an earthquake with a peak ground acceleration of 0.15g. Therefore, equipment and components are screened as follows: e At 0.3g peak ground acceleration, if caveats of column I of EPRI NP-6041 are met and the A-46 anchorage calculation showed a factor of safety greater than two. V AK? O'7 All LA BGE BGE V A'I 017 Al I

Calvart Cfs5 Nhwir Power Plnt Seismic Analysis Individual P6l Exunation Exteal Events

• At 0.Sg peak ground acceleration, if caveats of column 2 of EPRI NP-6041 are met and the A-46 anchorage calculation showed a factor of safety greater than four.

One exception to the above has to do with seismic interactions, particularly block walls. For seismic interactions, he walkdown must note potential seismic interactions for earthquake levels above the Safe Shutdown Eatqake (SSE). These are not documented in the A-46 walkdowns. For block walls, nemaby equipment and components could be screened at 0.3g if the wall is qualified by elastic analysis for IEB 80-11 (Ref. 3-9). It is assumed that all walls are reinforced and anchored in accordance with BGO Drawing 62-128-E, "Masony Details." Equipment near walls qualified by inelastic analysis could be screened at 0.3g if the SRT judged that ther is sufficiest margin based on the wall height and thickness. Inno case is equipment near masony walls screoed at the 0.5g level. For seismic-fire and seismic-flood interaction, potential fire and flood sources are identified by BGE and then evaluated per the EPRI NP-6041 guidelines at a review level of 0.3g. Those sources not screened out are identified for further review and possible fragility analysis. The walkdown lists and screening results are contained in Attachment A to Ref. 3-3. Attachment A is a complete walkdown and screening report prepared by EQE. It contains sections on methodology, the seismic review team, screening, seismic-fire interaction and seismic-flood interaction. 3.1.3 Analysis of Plant System and Structure Response 3.1.3.1 Structure Fragility Analysis The Soil-Structure Interaction (SSI) Analysis and structurefragility analysis were performed by S&A and are documented in Rat 3-1. The information presented here is from that report. To estimate realistic fragility values for structures and components, it is necessary to consider an earthquake level where a number of components would be expected to fail or near their failure limit. The RLE was defined by the median shape Uniform Hazard Spectrum for CCNPP from NUREG-1488 for a 10,000-year return period at a peak ground acceleration (pga) of 0.4g set at 50 Hz. The pga is four times the associated median pga of 0.1g from NUREG-1488 and 2.67 times the Design Basis Earthquake of 0.15g. Probabilistic seisnmic SSI analysis for five of the CCNPP major site buildings were performed. The buildings considered for probabilistic seismic SSI analysis were:

    "   Containment
    "   Auxiliary Building

• Intake Structure

    "   Turbine Building
    "   New Emergency Diesel Generator Building Additionally, seismic response analyses are performed for the Fire Pump House and the Condensate Storage Tank and Fuel Oil Storage Tank enclosures for the purpose of calculating fragilities for these structures.

The results of the SSI analyses includes development of probabilistic in-structure response spectra for use in calculating equipment fragilities, and probabilistic nodal forces and moments in the structure models for DGE 3-4 R AW 97-03.'1

Calvert aifsNuclas Power Plant Seismic Analysis Iniul Plat Exuatinon External Evemn use in calculating structure fiagilities. The structure floor response spectra are contained in Ref. 3-1. Table 3-5 shows the fragility values for the structures. 3.1.3.2 Seismic Relay Chatter Analysis An extensive relay evaluation (Ref 3-12) was performed at CCNPP for the US[ A-46 program. The evaluation found no 'bad actor' relays and therefore, for focused scope plants such as CCNPP, completion of the USI A-46 review satisfies the IPEEE intent for review of relays. 3.1.3.3 Seismic-Fire Interaction Analysis NUREG-1407 and NUREG/CR-5088 explain that the IPEEE seismic walkdown and screening should address the following for seismic-fire interaction: Seismically-induced fires, seismic actuation of fire suppression systems and seismic degradation of fire suppression systems. Seismic-Induced Fires Seismic-induced fires are addressed by examining sources of flammable liquids or combustible gases which, in the presence of an ignition source, could damage equipment on the IPEEE component list. Materials may be screened from fire source consideration if they meet one of the following criteria:

a. The fire source materials are not explosive nor combustible and they have a high flash point.

b. The system containing the fire source material is not pressurized and operates in a low temperature environment.

c. The fire source material is not near vital equipment.

Based on the fire screening criteria above, the screened and not screened fire sources are listed in Ref. 3-2. The non-screened fire sources are then walked down. Generally, the non-screened fire sources includes the storage tanks and piping that contain flammable liquids or combustible gases. These sources include components such as the Volume Control Tanks, EDG Fuel Oil Day Tanks, hydrogen seal oil skid, hydrogen piping to the main generators, lube-oil piping to the main turbine, etc. In addition to evaluating components specifically identified as potential fire sources, the Component Table (walkdown list) (Attachment A, Ref. 3-3) includes a column indicating whether or not the Seismic Review Team identified a seismic-induced fire concern for each component listed. In the safety-related buildings, most of the tanks and piping are screened at either 0.3 or 0.5g. The non-safety-related buildings with flammables are the Fire Pump House, Turbine Building and the North Service Building. CCNPP has two Fuel Oil Storage Tanks (FOST) which have fragilities of 0.22g; This is less than the 0.3g screening criteria. However, in the case of tank failure, the contents and possible resulting fire should be confined to the area immediately around the tank. The No. 21 FOST sits inside a tornado proof concrete building. Inside the building, but surrounding the lower portion of the tank, are concrete walls designed to contain the contents of the tank if it ruptures. The concrete structure, which has a HCLPF of 3.70g, is quite rugged and is not expected to fail in the earthquake range of interest. BGE 3-5 RAN 97-011I

Cavt CiR Nucear Powr Plant Sismic Analysis Individual Plant Euminiog Extern Evet The No. 11 FOST is surrounded by an earthen berm designed to contain the fuel oil if the tank fads. A fire here would probably affect 500 KV Unit 1 output to the Switchyard by burning the overhead power lines leading to the Switchyard. However, this impact is bounded by switchyard failure, with its much lower HCLPF of 0.09S. Therefore, fires resulting from FOST failure arenot expected to have a significant direct impact on other equipment. The only remaining issue for a FOST fire is the smoke geterated by the fire. Smoke generated by a large outside fire could potentially be drawn into the Control Room and Cable Spreading Room Ventilation system and adversely affect the Control Room Operators. The likelihood of smoke from fires in various outside areas is addressed in this report in Section 4, Fire Analysis. Protection fiom smoke being drawn into the Cntrol Room and Cable Spreading Room is addressed in this report in Section 7.0, Plant Improvemnt and Unique Safety Features. There are various outside transformers located around the main plant buildings. Most of these are included in the generic fragility used for 500KV Switchyard and loss of off-site power. Assuming that the transformers have a similar capacity, their HCLPF, which corresponds to about a 1% failure probability, is 0.09g. The probability of exceeding 0.09g is approximately 3.7E-04 (based on the LLNL seismic hazard curves for CCNPP). The base frequencies for transformer fires analyzed in Section 4 are on the order of E-02. Therefore, the impact of a seismic-induced trarisformer fire is bounded by the fire initiating event frequencies. Section 4, Fire Analysis, also includes the impact of smoke from each transformer on the Control Room Ventilation System. The only other outside fire source is the hydrogen storage area located in the tank farm. This fire source is evaluated in Section 4, Fire Analysis. The area consists of nine hydrogen cylinders in an area surrounded by a fence and concrete barriers. The tanks are far enough away from any vital equipment so that a fire here is not expected to have any adverse impact. All fire sources are either screened at a HCLPF of 0.3g or are not near any vital equipment, and therefore, are not a significant risk. Seismic Actuation of Fire Suppression Systems This is discussed below in Seismic-Flood Interaction. Seismic Degradation of Fire Suppression Systems During the walkdown, the smoke detectors, halon bottles and piping were found to be well secured and screened at 0.5g. The fire system pumps, motors, and piping were walked down and are screened at a HCLPF of at least 0.3 g. Therefore, there appears to be no significant risk associated with Seismic-Fire interaction. More details concerning particular components and screening criteria may be found in Ref 3-3. 3.1.3.4 Seismic-Flood Interaction Analysis Flood analysis includes equipment damage from spray as well as high water level. These risks may be created by failure of fluid system piping, water storage tanks inside safety-related buildings and by spurious actuation of fire suppression system. DA~J 07..fl21 "1RAV* 0-_w'Ii BGE

Caiwit CII& NUelm Power Plot Seduinic Analysis Individual PMat Examninatiou External Events Based on the plant walkdowns, all the safety-related piping systems and water storage tanks inside the Containment and the Auxiliary Building are considered seismically rugged and screened at a minimum HCLPF of 0.3g. The non-safety-related piping particularly the Fire Protection system in the safety-reated buildings, is well supported and is also screened at a HCLPF of at least 0.3g. In the Turbine Building, piping in the proximity of electrical components and the Fire Protection system are screened at 0.3g. Part of the Service Water (SRW) piping did not meet the HCLPF screening due to spatial interaction. Thus, SRW could be a potential flood source if the piping breaks during a seismic event. However, the results of the WPE Internal Flooding analysis indicate that the flooding from SRW source in the Turbine Building presents no significant risk to plant safety. Equipment damage fron spray could also be caused by seismic actuation of the Fire Protection system or from failure of Fire Protection piping. All the Fire Protection piping in the safety and non-safety-related buildings is screened at a minimum HCLPF of 0.3g, as a result of the equipment walkdowns. Actuation due to relay chatter is not considered a credible risk for CCNPP, based on the relay evaluation performed for USI-A46. Based on the above, it is concluded that seismic-induced flooding is unlikely except for SRW in the Turbine Building. However, this seismic flooding event presents no significant risk to plant safety. 3.1.4 Evaluation of Component Fragilities and Failure modes The methodology used to screen components and calculate component fragilities is described in Ref. 3-2. The information in this section is taken from that report. Relatively strong components may be identified and screened out by verifying during the plant walkdown that these rugged elements comply with the caveats in Tables 2-3 and 2-4 of Ref. 3-6. Use of the first column of these tables coupled with'anchorage calculations based on a peak ground acceleration of 0.3g implies a minimum HCLPF of 0.3g. If the plant component screening is performed at a HCLPF level of 0.3g, then the plant HCLPF capacity cannot exceed this level even if all components exceed the screening criteria. This is because a component is screened out based on its strength being greater than the screening level, but it is not known how much greater. Ref. 3-5 gives a simple approach to obtain a generally conservative estimate of the mean CDF if the plant HCLPF is known. Assuming a plant HCLPF of 0.3g and using the median seismic hazard curve for CCNPP from Ref. 3-4, this procedure estimates a core damage frequency of 3E-6. It is concluded on this basis that a HCLPF screening level of 0.3g peak ground acceleration was appropriate. The screening tables in Ref. 3-6 require anchorage calculations for certain types of equipment. For a 0.3g HCLPF screening, the anchorage calculations would be based on a peak ground acceleration of 0.3g. It was noted that the USI A-46 Equipment Review performed anchorage calculations based on a peak ground acceleration of 0.15g. Thus, if equipment reviewed under A-46 had a factor of safety (capacity to demand ratio) of 2.0 or greater, and also satisfied the caveats of the screening tables in Ref. 3-6, it would have a HCLPF capacity above 0.3g. (It should be noted that the SSE ground response spectrum used for A-46 has less amplification than the NUREG-0098 spectrum assumed in Ref. 3-6, however, it is judged that conservatism's in the A-46 criteria compensated for this difference.) Ref. 3-3 tabulates the results of the walkdown and screening for CCSPRA. For items that are in the scope of the A-46 review, those which had a safety factor of 2.0 or greater are screened out from further BGE R AN 97.1111

C*Iveil Cliffs Nudar Pow rUt Seimk APlyan lndividual Plant Exuikado Extemal Evets consideration. A-46 items with a safety factor less than 2.0, as well as items which are CCSPRA only or A-46 outliers, remained for consideration in developing fraglities for IPEEE. Probabilistic floor response spectra have been provided in Ref. 3-1 for use in development of the equipment fiagilities. 3.14AA HCLPF Calculation for Screening A-46 Equipment The initial activity is to determine the most vulnerable items for fragility development. For A-46 equipmet, this is accomplished by estimating an approximate HCLPF using the results of the A-46 calculations and the probabilistic floor spectra. Components with an estimated HCLPF greater than 0.3g may be screened from further fragility analysis. From Ref. 3-4, a HCLPF may be conservatively estimated as: C HCLPF = - x PGA D where: C = component capacity D = 84th percentile seismic demand on component from Ref. 3-1 ground response spectrum PGA = Peak acceleration of reference ground response spectrum The reference ground response spectrum of Ref, 3-I is the IE-4 median uniform hazard spectrum (UHS) shape for CCNPP from Ref 3-5 with a PGA of 0.4g. Therefore: C HCLPFul5 =- xO.4g The capacity may be conservatively determined from the A-46 review as: C = FS x DA-4 6 where: FS = Ratio of capacity to demand in the A-46 analysis From Ref. 3-6, the demand from the Ref. 3-1 earthquake may be estimated from the A-46 analysis as: DUHS = DA-45 x Sa 4 SaA-4e where: SaA4g = Spectral acceleration used in the A-46 analysis Sam = 84th percentile spectral acceleration at the component frequency due to the Ref 3-1 earthquake (Ref. 3-1). Combining the above yields: BOE 3-8 R8AM07.-*lI

Calvet Cliffs Nndwr Power Plant Seismic Analysis Individual Plant Examinos Extrnal Events SaM- 8 HCLPF = FS x g.- 4 x 0.4g S84 If the HCLPF is 0.3g or greater, the component is screened out from development of fragilities. Results of the comparison are shown in Table 1 of Re. 3-2. A-46 components not screened out arc listed in Table 2 of Ref. 3-2. These components are then further screened. For example, several distribution panels had their anchorage modified for A-46 and are screened out. Several Unit 2 125VDC distribution panels had anchorage modifications for A-46 and are screened out. Similar anchorage modifications will be made for several Unit I 12SVDC panels in the Spring 1998 Refueling Outage and these am also screened out. The inverters have been replaced using new rugged anchorage so they also are of no further concern. Fragility calculations are performed on the remaining components. The results of these calculations are shown in Reference 3-2 and Table 3-3 of this report. 3.1.5 Analysis of Plant Systems and Sequences 3.1,5.1 Seismic Event Trees The Seismic PRA model consists of six event trees from the internal events model with a seismic event tree linked to the front of the model. The six internal event model event trees are modified for the seismic model. The event trees are listed below:

• Seismic Event Tree Modified Internal Event trees
• Support I

        " Support 2

• General Transient I
• General Transient 2
• Long Term
• Plant Damage State The seismic event tree contains eight seismic top events. Each seismic top event models an important system function that may be failed by a seismic event. Each top event in the seismic event tree is linked to the corresponding top event in one of the internal event trees. For example, Seismic Top Event LE models the OC Emergency Diesel Generator (EDG). EDO OC is modeled by Top Event GJ in the Support 1 Event Tree of the internal events model. If EDG OC fails due to a seismic event, it is automatically failed in the Support I event tree because the 'rules' for Top Event OJ require Top Event LE success. In this way, each seismic top event is linked to the corresponding top event in the support or front-line event tree from the internal events model.

3.1.5.2 Seismic Top Events Fragilities are calculated for components as shown in Table 3-3. A Seismic Top Event is created for each system that had component fragilities with HCLPF values less than 0.3g. In addition, two surrogate top events are created, as explained below. BGE 3-9 RAN 97-031

Calvn Cih NvUh Power Plant Seismic Analyis lndkdual Plant Enminalion Extets Events Several components in Table 3-3 do not have top events. They were dispositioned as follows: Line 1 lists a fragilit for control cabinets for EDG3 IB, 2A and 2B. However, these EDGs are all SRW dependent. Since SRW has a significantly lower fragility, the function of these EDGs is bounded by the SRW Top Event LG. The components listed in Line 3 of Table 3-3 are relief valves associated with Steam Generator Blowdown and Reactor Coolant System Waste Process Sample Systems. These components are screened becuse by themselves, they do not cause a LOCA. The relief valve failure must occur concurrently with another component failure or event and the combined probability was very small. Line 4 of Table 3-3 is a block wall which could impact certain components. However, further analysis showed that its impact was bounded by other fragilities already considered. The remaining components have top events developed for them. Top Event LA Surrogate Systems sustain a seismic event During the component walkdowns, most of the plant components reviewed are found to be rugged and are screened at either the 0.3g or 0.5g screening level. Although these components are screened out from further evaluation, that does not mean they will not fail, They still have some contribution to seismic risk, particularly at the higher g levels. Top Event LA was created to model this risk contribution. Of the systems whose components were walked down but screened out because they are rugged, six are important enough that their failure (of any one of the six) has a high probability of causing core damage. These systems are 125VDC Distribution, 4KV Buses, 480V Buses & MCCs, Auxiliary Feedwater, Reactor Protection System and Condensate Storage Tanks. Top Event LA consists of these six systems under an 'or' gate. The failure of any one system will fail the top event. In the seismic model, Top Event LA failure leads directly to core damage. Each system under the 'or' gate is assigned a fragility. The first five systems named above are assigned a fragility based on the screening level and the guidance for assigning surrogate fragilities given in Ref. 3-2. Although these systems have capacities that exceed the screening criteria, we do not know by how much they exceed it. Therefore, we conservatively set the fragilities at the screening level. This resulted in a HCLPF of 0.3g and a median acceleration capacity of 1.2 g for the first five systems. The sixth system listed above, Condensate Storage Tanks, had a fragility analysis performed by S&A (Ref, 3-10). This analysis determined the median and HCLPF capacities to be 0.96 and 0.43 g respectively and these values are used for the CST fragility. The failure probabilities for Top Event LA are determined as follows. For a given g level earthquake, the conditional failure probability of a single surrogate system is the failure fraction of its frilty, associated with that g level. These failure fractions are calculated as described in Section 3.1.5.3 below and whose values are shown in Table 3-4. Let the failure fraction of one of the 0.3g systems equal 'x' and the failure fraction of the CST system equal 'y'. The success likelihood of a single system is (l-x) or (l-y). The likelihood of all six systems succeeding (Top Event LA success) is (1-x) * (1-x) * (l-x) * (l-x) * (i-x) * (- y) which may be.re-written as (l-x)5 * (l-y). The failure probability (Top Event LA fails) is simply I - this value or I - [(l-x4 * (l-y)]. This calculation is performed for each of the 30 initiating event g levels. The values are shown in Table 3-4. BGE 3-10 RAN 97-031

Caht CfS Nuckw Pow PFlat Seismic Anajysis Individual Plant Examinatiom Extcrna Events The seismic model is quantified both with and without Top Event LA. This is discussed more in Section 3.1.5.5. Top Event LB Refueling Water Storage Tanks sustain a seismic event This top event models the availability of a borated water supply to the suction of the HPSI, LPSI and Containment Spray pumps. This top event is linked to Top Event RT (RWT supplies flow during LOCAs) in the SMCGT2 internal events model event tree. Top Event LE OC EDG sustains a seismic event This top event models the OC Esergency Diesel Generator. This EDG, the 'Station Blackout' EDO, may be aligned to any one of the four safety-related 4KV Buses. The limiting components are three air conditioning components whose fragilities are calculated and are shown on lines 13, 14, and 15 of Table 3-

3. These three fragilities ae combined to form one fragility. Top Event LE is linked to Top Event GJ (EDG OC starts and runs) in the Support I (SMCSUPI) event tree of the internal events model.

Top Event LG SRW Headers 11, 12, 21 and 22 sustain a seismic event This top event models the function of the SRW system to provide cooling to various components, including EDGs IB, 2A and 2B. The components which limit the seismic capacity of this system are several SRW coolers and SRW piping located in the Turbine Building. These components are listed on lines 6 through 12 of Table 3-3. These fragilities are combined to a single fragility representing the SRW system. Top Event LG is linked to the following top events of the SMCSUP2 event tree.

     "    53       SRW Header 11 provides sufficient flow
     "   S4        SRW Header 12 provides sufficient flow
     "   GW        SW Header 22 & SRW Header 22 operate
     "   GZ        SW SRW r2&SWHeader 21 operate Top Event LH               CR HVAC sustains a seismic event This top event models the Control Room and Cable Spreading Room HVAC system. The seismically limiting component is a control cabinet whose fragility is shown on line two of Table 3-3. Top Event LH is linked to Top Event HH (Control Room/Cable Spreading Room HVAC provides adequate ventilation) of the SMCSUP I event tree.

Top Event LJ 500KV Switchyard sustains a seismic event This top event models the function of the 500KV switchyard to supply off-site power. The fragility is based on a generic value from Rsf. 3-7. Top Event LJ is linked to Top Event OP (grid fails to remain energized following a plant trip) in the SMCSUPI event tree. RAN 97-031 3-11 BGE BGE 3-11 RAN 97-031

Calvet Cliff Nuclear Power Plnt Seismic Analysis lndhidua Plant Examinmmu Eierul Event. Top Event LK Secondary Systems sustain a seismic event This top event modhls some systems (mostly secondary) that were not walked down because of their low importanee in the PRA and to reduce the scope of the walkdowns. These are assumed faiW for all seismic initiating events except for those at or below the Operational Basis Earthquake (OBE = 0.08G) and where Top Event LK is successU. Top Event LK is a surrogate top event representing these systems. It has practically no impact on CDF but was created to speed the model. It is assigned a fragility based on the most limiting fragility (500KV Switchyard). We assumed it had median acceleration capacity of one-half and twice the logarithmic standard deviations for uncertainty (Pj) and randomness (P,). The below-DBE initiating event are SMCP03, SMCP05, and SMCP08. The top events that are set to failure for all IFs, except where LK is successful are listed in the table below. Top Event Event Tree Descrigtion BS SMCGTI TBVs modulate BV SMCGTI TBVs quick open MC SMCGTI Condensate is available MN SMCGTI MFW is adequate after Trip MP SMCGTI MFW ramps back after Reactor Trip VC SMCGTI Condenser vacuum is available CV SMCGT2 2 of 3 Charging Pumps Borate as required NR SMCSUP2 Non Safety-related Instrument Air/Plant Air is available Top Event LK is only questioned if all of the preceding Seismic Top Events are successful. If any one of the preceding Seismic Top Events fail, Top Event LK is set to guaranteed failure. Although the fragility assigned to Top Event LK is probably realistic, some of the systems modeled by LK could possibly have lower seismic capacities than assumed. Although this would make LK non-conservative, the impact of this possibility is not very significant. Most of the functions LK represents are already modeled in the internal events model by initiating events such as Loss of Main Feedwater, Loss of Condenser Vacuum, or Loss of Instrument Air. These initiating events have comparable or greater frequencies than the three lowest-g seismic initiating events used with LK. Top Event LL Containment Isolation sustains a seismic event This top event models the function of the Containment Isolation sytern and penetrations to contain a LOCA. All of the electrical penetations, piping penetrations and containment isolation valves whose failure would lead to containment release that were walked down are screened at a 0.5g. Therefore, a surrogate fragility of 0.Sg is assigned to the Containment Isolation Top Event. Top Event LG is linked to Top Event Sl (Penetrations greater than 4 inches function) in the SMCLT event tree. Top Event LG failure leads to a large release. 3.1.5.3 Seismic Split Fraction Values Each seismic top event modeled represents some system function. The probability of fimctional failure increases with increasing seismic level, measured in ground acceleration g. The conditional probability that BGE D A XT 01/ A I!

Calve*t Chlff Nuler Power Plant Seismnic Analysis Individual Plant Examination Enxnal Eveats the fanction fails is the seismic fragility. The fragility is assumed to be lognormally distributed. The fragility curve has failure fraction values between zero and one on the ordinate and peak ground acceleration values on the abscissa. The fragility curve may be completely defined by two parameters, such as the median acceleration capacity Am, and the composite logarithmic standard deviation of the underlying normal distribution, B.. The seismic split fiaction values are calculated for each top event using the spreadsheet, shown in Table 3-

4. The spreadsheet calculates a failure fraction for each top event at each of 30 g levels (there is one g level for each of the 30 initiating events).

The fragih'ty curves are truncated at the low and high ends. This reduces the number of split fractions and speeds up the quantification. The fragility curves are truncated at the low end at a failure fraction of 5.OE-05. Below this failure fraction, the function is assumed to survive the seismic event. This truncation is reasonable because the lognormal distribution tends to overstate the failure likelihood at the low probability end of the distribution. This is because most components, particularly ductile components, have some cut-off limit below which, there is essentially zero probability of failure. The fragility curves are truncated at the high end at-a failure fraction of 0.95, except for Top Event LB, which is ncatedat .50 and Top Event LE, which was truncated at 0.90. Top events are set to guaranteed failure above the high-end truncation. LB and LE are truncated at a lower limit because the model runs more efficiently without a significant increase in core damage frequency. 3.1.5.4 Seismic Human Action Analysis Since we expect a seismic event to adversely affect operator performance, the human action failure rates used in the Internal Events CCPRA are adjusted for seismic scenarios. The non-seismic human action failure rates are calculated using performance shaping factors (PSFs). Those PSFs that were judged to be affected by a seismic event are multiplied by influence factors to account for the lower success rate following a seismic event. Different influence factors are used for human actions depending on whether it is a short term or long term action. Short term actions are those that must be completed within 15 minutes. All other human actions beyond the 15 minute time frame are considered long term. A seismic event is assumed to have a greater impact on short term actions because of the initial shock imposed by a seismic event and the more limited amount of time to complete the action. The impact on human actions is also affected by the magnitude of the seismic event. Three influence factors are used for the short term actions and three different influence factors are used for the long term actions, depending on the magnitude of the seismic event. The seismic initiating events are grouped into three bins: seismic events from 0.01 to 0.281 g (bin 1), seismic events between .282 and 0.663 g (Bin 2), and seismic events between 0.664 and 0.918g (bin 3). For seismic events above 1.02g, all human actions are set to guaranteed failure (see assumptions below). Values for the PSF influence factors are obtained from a straight line graph of PSF influence factor vs. seismic g level, shown below. There are two lines plotted, one line for the short-term actions and one line for the long-term actions. The endpoints for the long-term action line are established by assuming no impact (PSF influence factor = 1) at zero g and guaranteed failure (PSF influence factor= 0) at 2.0 g (see BOE 3-13 IRAM Q7-A*I I

Calve" Cho~ NdWce POWe lnutt Seismic Arionysi Individual Picat Exmmtionaz External Events assumptions below). The short-term action line was anchored assuming no impact (PSF influence = 1) at zero g and at guaranteed failure at one-half the seismic value of the long-term action line, or 1.0 g. This makes a more severe impact on the short-term actions for any given seismic event. Graph 1: PSF INFLUENCE FACTOR PSF Influence Factorvs. Seismic g Classification X-AXIS Short Term Actions Long Term Actions 0.510.0 0. 0 0.6~ fX) =-(0sx) +I1 R 0.1 0.3i+1 gC ai 0.2 t* 0.10 0.0 0.5 1.0 1.5 2,0 2.5 3.0 Seismic B Classification

                                       ---4--Short Term Actions                  *-  - Long Term Actions   I

• short term actions are those actions that must be completed in 15 minutes or less; all other human actions beyond the 15 minute timeframe will be considered long term actions.

where: f is the influence factor of PSF due to a seismic condition x is the seismic loading frame in g units Assumption: while x = 0 (no earthquake) the PSFs are unchanged

                                                                                /

while x = 2g (long term actions) or x = Ig (short term actions), PSFs drop to 0 (for direct PSFs) or 10 (for indirect PSFs). In other words, the specific action is set to guaranteed failure. In analyzing the graph, the impact on the actual human action failure probability is established through the PSF influence factor. At the guaranteed failure point (X g for long term actions, and Y g for short term actions) the appropriate direct acting PSFs (those PSFs whose survey rankings are better for higher ranked numbers) are multiplied by an influence factor of zero while all indirect acting PSFs (those PSFs whose survey rankings are worse for higher ranked numbers) are set to a value of ten. For all other actions, a seismic g classification corresponds to a specific PSF influence factor that is applied to all relevant PSFs. The specific seismic bins are as follows:

                                                               ,~1 A BGE                                                           1-ld                                       D A NT Wr A21 I

Calet CliWff Nudewr Power Plant Seismic Analysis Individual Plant Examinatio Extaena Evens RANGE OF VALUES PSF INFLUENCE FACTOR I 0.013g-0.28ig LT = 0.8595 ST = 0.719 2 0.282g - 0.663S LT = 0.6685 ST = 0.337 3 (see note below) 0.664g - 1.02g LT = 0.4900 ST = failure 1.02g or greater LT = failure ST = failure

                     =STShort Term Actions LT = Long Term Actions Note:      Since the Human Action Analysis was performed, the upper bound of Bin 3 was lowered to 0.918g. The frequencies of seismic levels above 0.918g are conservatively grouped with the l.5g initiating event, which goes directly to core damage. This reduced the number of initiating events with no significant impact on core damage.

The PSF influence factor for each bin is obtained by finding the influence value associated with the highest seismic level in that bin. This results in all short-term actions being set to guaranteed failure for all Bin 3 initiating events. There is one initiating event that fails above Bin 3. Initiating Event SMCIPS, which has a 1.5g seismic level, falls in the category where all human actions are set to guaranteed failure. This initiating event goes directly to core damage. As mentioned earlier, the human action failure rates for the internal events PRA are determined using PSFs. The methodology used to calculate the Internal Events CCPRA Human Action failure probabilities is a hybrid which incorporates the best features of several well-known Human Reliability Analysis (HRA) methodologies and uses concepts from more advanced HRA approaches and available empirical data. The SLIM-MAUD approach and the HCR (Human Cognitive Reliability) models form the basis of the CCPRA HRA methodology. Calvert Cliffs' human action methodology is documented in the Human Error Probability Methodology Report, Ref 3-15. The basic rationale underlying SLIM-MAUD is that the likelihood of an error occurring in a particular situation depends on the combined effects of a set of performance shaping factors. These PSFs include both human traits (e.g., operator competence, morale, motivation, etc.) and conditions of the work setting (e.g., time available to complete a task, procedures, indications, etc.) that are likely to influence an individual's performance. Not every PSF is likely to be degraded by a seismic event. The areas that will most likely be degraded for a seismic situation are: time to complete a specific action, concurrent actions in progress, communication, training and experience, Control Room indication, and the ability to access certain areas of the plant. Assumptions The following assumptions are used to analyze the impact of a seismic event on various human actions.

• We assume that the impact on human actions will vary with the strength of the seismic event. We assume that operators will be unable to perform required actions at seismic levels high enough to fail the building structure, because they may be physically blocked by fallen debris. If some part of the BGE rl A %T Y%-1 A-0 I

CdlVft Cliffs Nuder Power Plant Seismie Analysis Individual Plant Examination External Events building collapses, then the operators will probably be unable to perform actions, at least in that area. Most of the human actions take place in the Auxiliary Building (median capacities for the various buildings are shown in Table 3-5). The average median capacity is 2.0 g. This level is used to establish the guaranteed failure point for human actions.

• At a seismic g classification of zero there will be no degradation of the human action failure probability. The impact on the various PSFs from a seismic g classification of zero to the guaranteed failure point is assumed to be a linear relationship.
• The weighting factor associated with a specific PSF is assumed to remain the same for a seismic scenario. The weighting factor accounts for how important a PSF is in a transient. The PSF is assumed to have the same importance in a seismic situation although the ability associated with a specific PSF may be degraded. The way to account fbr this degradation is by adjusting the survey response for the specific PSF rather than adjusting the weighting factor linked to the PSF.

eThe conversion constant ('a' constant) used to convert the Success Likelihood Index (SLI) to a failure probability is assumed to remain constant in a seismic scenario. The human action methodology for CCPRA currently uses seven 'a' constants to calculate failure probabilities for different cognitive binning of the specific action in question. These same 'a' constants will be utilized to calculate the seismic human action failure probabilities since the 'a' constant is just a conversion constant The specific impact of the seismic event will be seen in the degradation of the specific PSFs as stated earlier. Specific Adjustments made to the Performance Shaping factors Specific adjustments made to the various types of performance shaping factors: Time-dependent PSFs: V.TI Operator Stress Level This PSF is an indicator of the operator's time, stress level, and mental load. Just several minutes after the earthquake, the operators may not have recovered from the initial shock of an earthquake. But after the. initial shock, the effect slowly diminishes. Therefore, VTI is judged as a time- ndent factor. VD3 Number of Concurrent Actions in Progress Certainly, in the early stages of a seismic event, a variety of different activities can be commencing, therefore, producing some chaos in the Control Room. The plant begiis to stabilize farther into the event, thus reducing the amount of concurrent actions in progress. VA4. 5.6 Communication In the first several minutes, communication may be more difficult due to the initial shock of the seismic event as compared to later in the event when the plant starts to stabilize. 0 AKI ei-r nit BGE BGE 0 A M WT 10'l 1*$

Calvedt Cliffs Nuclear Power Plant Seismic Analysis Individual Plant Examination Extemal Events VAI. 3 AdM Uacy of Personnel VAI and VA3 refer to the adequacy of personnel inside/outside the Control Room to perform a desired task. In the first several minutes, some operators may not be mentally or physically available because they may not have recovered from the initial shock of the earthquake or they might be busy in some non-task-related jobs. rune Independent PSFs: VII. V12 Initial and Seconda Indications A signal transmission line may be damaged by the earthquake, but the damage is assumed not recovered in the duty period. Therefore, the related PSFs will be degraded but not considered as time-dependent. VLI. VL2 Eauipment Location and Accessibility It is assumed that an earthquake will degrade the ability of an operator to get to certain locations (if required) but will not be related to time. This PSF models the impact of fallen structures blocking access to equipment. We expect this at the higher g levels. This PSF, by itself, will severely degrade the human action failure probability at the highest g level. Unchanged PSFs: VPI. VP3 Procedure Ouality and Adequacy These PSFs rank the quality and adequacy of any procedure that the operators may utilize to mitigate a transient. Since the operators will still enter the same procedures during a seismic event combined with a plant trip, these PSFs are assumed to be unaffected by an earthquake. VYCI. VC2. VC3. and VC4 ConsMeouences of Performing/Not Performing Action These factors arm only related to the accident scenario and will be unaffected by an earthquake. VD I. VD2 Impact of Previous Related Successful/Unsuccessful Actions We assume these PSFs will not be affected by an earthquake. g-level Independent PSFs: VEL. VE2. VE3 Ocerator Training and Experience in Identifyins. Dia*nosing, and Performing a Specific Action Regardless of the earthquake's g-level, most of the operators have not experienced a seismic event. Therefore, a generic influence factor of 0.5 is applied. The human action failure rates are multiplied by the adjusted performance shaping factors. The human action failure rates are incorporated into the appropriate split fraction failure probabilities in the master frequency file. A portion of the master frequency file is shown in Table 3-8. PAM 07Jfl1 3-17 BGE 3-17 !RAM 0'/o-ni I

Calved UStNu**ear Power Plant Seismic Analysis ladividual PFl Examminaon External Eveat Figure 3-1 shows the general trend of increasing human action failure probability versus peak ground acceleration (PGA) level for short-term actions. Note that all short-term human actions are set to guarante failure at a pga of 1.0g. Figure 3-2 shows the general trend of the long term human action failure probabilitys. Note that these are set to guaranteed failure at a pga of 2.0g. 3.1.5.5 Seismic Quantification The event trees are quantified to determine point estimate frequencies for core damage sequences and plant damage states that result fronm each of the 30 ranges in peak ground acceleration. The ranges, shown in Table 3-2, are divided up into three large bins. The initiato in each bin are quantified as a separate group because of the impact of seismic level on human actions. The three levels of impact dictated that tur would be three different failure probabilities for each split fiaction whose value is afibced by a human action. Approximately 200 of the roughly 1,400 split fraction failure probabilities used in the seismic quantification are affected. Having multiple values for the same split fraction (depending on the PGA level) is managed by making three different master frequeacy files in RISKMAN. The initiators are run in three separate batches, each batch using a separate 4FF. The linked seismic event tree, support trees and front-line trees are quantified at each of the 30 PGA ranges using the mean hazard curve and mean seismic fragility curves. There is a seismic initiating event for each of the 30 seismic bins. An initiating event is an earthquake causing a peak ground acceleration at CCNPP corresponding to a PGA level within a bin. The PGA level of the initiating event determines the failure fraction to be used for each top event fragility. Table 3-4 shows the failure fraction (conditional failure probability) of each seismic top event for each of the 30 PGA ranges. For each seismic top event, the split fraction values are equal to the failure fraction calculated from the corresponding fragility curve at the PGA of the initiating event. The very high (above 0.95) and very low (below 0.0005) failure fraction values correspond to the tails of the lognornal distribution representing the fragility curve. Split fractions were not assigned for these failure fractions. Rather, the fragility curve is truncated, and the failure probability is set to guaranteed failure for the high end or guaranteed success for the low end. This reduces the number of split frations and sequences generated. Fragility curve truncation is explained in detail in Section 3.1.5.3. Table 3-4 shows that the conditional failure probabilities for the seismic top events vary considerably over the acceleration range. At each g level, successes and failures in the seismic event tree determine which top events are failed seismically in the support and front-line trees, according to the way the trees are linked. If a top event in a support or front-line tree is not affected by seismic failure, its conditional failure probability is based on the updated WE (except for those failure probabilities affected by the seismic impact on human actions). In this manner, the hik event trees account for the combined contributions from all possible seismic and non-seismic failures at each acceleration.. The seismic event trees are quantified both with and without the contribution of surrogate Top Event LA. When Top Event LA is included, it is the single largest contributor to CDF. The most useful information gained by including LA is a more accurate estimate of total seismic CDF. However, this estimate is somewhat conservative because of the way the surrogate is calculated. As explained in Section 3.1.5.2, the surrogate systems are assigned fragilities at the screening level, when in reality, these systems likely have some higher capacity. However, the results which include the surrogate are probably closer to the actual CDF, so these are presented as the CCNPP Seismic CDF. BGE 3-18 RAN 97-031

Calvert CMEs Nudeat Power Plant Seismic Analysis Individual Plant Examination External Events The total seismic CDF for Unit 1, quantified with surrogne top event LA is 1.29E-05. Unit 1 CDF quantified without LA is 1.07E-05. 3.1.5.6 Seismic Sequence Analysis For performing component importance calculations and identifying potential vulnerabilities, results quantified without Top Event LA are considered more meaningful. The top 100 sequences quantified without Top Event LA are shown in Table 3-7. Most of these sequences fall into one of two main categories. The first type is a Spurious Safety System Actuation (SSSA) with a loss of Auxiliary Feedwater (AFW). The second category is a seismin-induced Station Blackout (SBO) and loss of Auxilary Feedwater. An SSSA is the spurious actuation of the Engineered Safety Features Actuation System, Auxiliary Feed Actuation System (AFAS) and Reactor Protection System (RPS). SSSA occurs in the Internal Events PRA and is explained in detail in the Calvert Cliffs IPE Summary Report (Ref. 3-14). It occurs when two of four Vital 120VAC buses de-energize. In most of the seismic sequences involving the SSSA, it is caused by a seismic-induced Loss of Offsite Power (U) and loss of all but one EDO. The three SRW-dependent EDGs fail whenever SRW fails (LG). Note that SRW and Off-site power are guaranteed to fail for all Bin 3 and most of the Bin 2 initiating events. If either of the two remaining self-cooled EDGs fail, an SSSA could occur (if both of the self-cooled EDGs failed at this point, a Station Blackout would result). Of the two self-cooled EDGs, EDG 0C (LE) and EDG IA (GE), EDG OC has a lower seismic capacity and is the more likely to fail. LE is guaranteed to fail for all Bin 3 initiating events. In either case, failure of one of the self-cooled EDGs leaves only one EDG operating. Each EDG is normally aligned to supply two of four Vital 120VAC buses. Each of the other two Vital 120VAC buses are supplied by a 125VDC battery through a vital inverter. The 125VDC batteries will last four hours with no SIAS (SIAS does not occur until the SSSA occurs at about the four-hour point). After about four hours, these two 125VDC batteries will deplete, resulting in a loss of their downstream buses, panels and loads. Prior to battery depletion, the operators must align the battery-supplied Vital 120VAC buses to their back-up buses. Failure of this action (Top Event XW) results in de-energizing two of four Vital 120VAC buses. This results in failing two of four sensor channels and actuating the two out of four trip logic in virtually all protective actions of our Engineered Safety Features Actuation System, Reactor Protection System, and Auxiliary Feed Actuation System. This event is referred to a spurious systems actuation (SSSA). An SSSA causes these significant events to occur.

• UV Channels A and B activate and lock in. This opens the feeder breakers to safety-related 4KV buses and sheds all major 4KV loads, including SRW and Safety Injection and the motor-driven AFW pump. Lock-in of the UV signal prevents the 4KV loads from re-starting. The three SRW-dependent EDGs (IB, 2A8 2B) will fail in 10 to 20 minutes because they have no SRW cooling (in most of the seismic sequences SRW is lost anyway due to failure of one of the various SRW coolers/piping in the Turbine Building).

BGE lrb A% d% ^ f t nkT

Calvert Ciffs Nudce Power Plant Scaimic Analysis Indidual Plant Examination Extemal Events

    "    Steam Generator Isolation Signal (SlS)Channels A and B activate: This shuts both Main Steam Isolation Valves (MSJVs), which fails MFW.
    " Reactor Protection System (RPS) activates: This sends an open signal to both Power Operate Relief Valves (PORVs). However, when the SSSA is caused by a loss of all power except EDO IA - as in many of the seismic sequences - the PORVs (on both units) lose 125VDC power and remain closed. The HPSI pumps cannot provide nmke-up to the RCS due to the locked in UV signal.
    "     AFAS Block Channels A & B activate: This, isolates AFW flow to both steam generators.

At this point, operator action is required to recover from the spurious AFAS by opening the AFW block valves (Top Event QZ) and locally control AFW flow (Top Event HX). If the operator fails to locally control flow, the steam generators eventually over-fill and the resulting water in the steam supply line is assumed to fail the operating AFW pump turbine. This leaves only the standby AFW turbine, and failure of this turbine (Top Event FIR) will result in AFW failure. Once-through Core Cooling is not an option because the High Pressure Safety Injection (HPSI) Pumps are locked out by the UV signal. Also, if the running EDG is EDG IA, the PORVs are failed shut due to the loss of 125VDC power after 125VDC Battery 21 runs down. When the 125VDC Bus 11 or 21 runs down, one of the AFW steam admission valves will shut on loss of power. This may require operator action to re-open the steam admission valve (Top Event MW). Long term AFW cooling also requires operator action to shift the suction from Condensate Storage Tank (CST )12 to either CST II or the Demineralized Water Storage Tank. Failure of this action (Top Event FI) will result in a loss of core cooling. Typically, automatic AFW flow control is lost and the operators must control AFW locally. If they underfeed the steam generators (Top Event UQ), the heat sink will be lost and core damage will result. The second most common type of seismic sequence is a seismic-induced SBO and an associated AFW flow control failure, Top Event FIR. Top Event FIR models the short term availability of AFW flow paths, including the supports for AFW pumps. This top event includes human action BHEFIQ, which is required in the following scenario: A seismic-induced SBO and failure of all EDGs results in a loss of main feedwater on both units. The station batteries deplete after about four hours and steam generator (S/G) water level indication is lost. The operators are assumed to overfill the S/Gs. Consequently, the 11 AFW Turbine-Driven Pump fails due to the return of excess water carryover from the S/G. Operator action is required to drain the AFW steam supply header and start 12 AFW Turbine-Driven Pump within three hours of the overfill condition in accordance'with the Emergency Operating Procedure. 3.1.5.7 CCNPP Unit 2 Assessment A Unit 2 assessment performed for the internal events PRA determined that the differences between the two units are minor and do not warrant the completion of a Unit 2 PRA. For the seismic analysis, both units were walked down and the difference between the units are noted on the walkdown list (Ref. 3-3). Various components had different anchorage configurations and these differences are explained in the notes section of Ref. 3-3. None are judged to be significant. BGE 3 -20 RN97-031

Calvert Cliffs Nuclear Power Plant Seismic Analysis Individual Plant Examination External Events The most significant difference between Unit I and Unit 2 is the lack of a SRW dependency on Emergency Diesel Generator IA. EDO IA is a newly-installed safety-related self-cooled diesel generator and backs up Unit l's safety-rclated 4KV Bus 11. The Unit 2 equivalent bus is 4KV Bus 24. It is backed up by SRW-dependet EDO 2B. Since SRW has a relatively low fragility, the diesels dedicated to Unit 2 are more susceptible to failure from a seismic event. The EDGs tie into the 4KV buses which in turn power the 480V, 125VDC, and vital inverters which power the 120VAC vital buses. At the 125VDC and 120VAC levels, multiple trains and cross ties between the units electrical buses eliminates the impact of the SRW dependency. That is, at the lower voltage levels, Unit 2 has half of ift trains ultimately powered from the non-SRW-dependent EDO IA, just as Unit I has. However, at lemls above these (4KV and 480V), there are no Unit 2 buses backed by EDO IA and the SRW dependency exists. The SBO diesel, EDO OC, is a newly-installed self-cooled diesel which may be aligned to a safety-related 4KV bus on either Unit. However, this diesel is not built to Seismic Class I specifications and it has a lower seismic capacity, due to the mounting of its Control Room air conditioning units and Switchgear Room air-handling unit. Since this diesel is intended to be aligned to either unit, it does not cause a difference between units for the seismic analysis. EDO OC is modeled by Top Event LE in the Seismic Event Tree. The most significant impact of the increased SRW dependency of Unit 2 is on the motor driven AFW pump. Unit 2's motor driven AFW pump (AFW Pump 23) is normally aligned to 4KV Bus 24, which is backed up by SRW dependent EDO 2B. Unit l's motor driven pump is normally aligned to EDO IA-backed 4KV Bus 11, and does not have the SRW dependency. However, this does not mean that Unit 2 AFW is entirely SRW dependent Unit I AFW may be cross-connected to Unit 2, but this requires a human action. However, Unit I AFW would only be needed for Unit 2 if AFW Pump 13 is not available because of a LOOP and the Unit 2 turbine-driven AFW pumps failed or are not available. The Unit 2 Seismic CDF is evaluated by quantifying a modified version of the Unit I Seismic Model. For the Unit 2 model, the diesel generators are 'rewired' so that the SRW-dependent diesels supply the 4KV buses on the Unit I side. This is accomplished by adding a SRW dependency to EDO IA and removing it from EDO 2B in the seismic model. The Unit 2 model quantification (with surrogate Top Event LA) shows that the Unit 2 seismic CDF is 1.52E-05. This is about 23% higher than the Unit I Seismic CDF (with Top Event LA). Even with this increase, the Unit 2 CDF is considered acceptable. The sequences for Unit 1 and Unit 2 are very similar. As expected, Unit 2 has an increased dependency on SRW and on the EDG OC. There are no other significant differences. 3.1.6 Analysis of Containment Performance Containment penetrations and containment isolation valves are screened at 0.5g. Seismic-induced failure of containment penetrations or containment isolation valves result in a failure of the containment isolation fiunction. This function is modeled by surrogate Top Event LL in the Seismic Event Tree. For CCNPP, a large release is defined as a break greater than a 4-inches diameter hole. Top Event LL is conservatively mapped to large release for all failures by making Top Event SI (containment penetrations greater than four-inch function) dependent on top event LL success. BGE 3-21 RAN 97-031

Camrt aifh Nuclear Power Plant Seidsic Analysis Individual Plant Examinaon Exteual Events The fragility assigned to the containment isolation function is based on the screening level used by the Seismic Review Team during the component walkdowns and the guidance provided by EQE in the filit report (Ref 3-2). This guidance states that for the purposes of defining surrogate element fragilities, components mounted in structures should conservatively have a median/HCLPF ratio of about four. Containment electrical penetrations and piping penetrations are screened at HCLPF of 0.5 g. Containment isolation valves arm also walked down and all those whose failure could lead to nontainment bypass or release are also screened at 0.5g Therefore, Top Event LL is assigned a fragility with a HCLPF of 0.5g. Using the recommended median/HCLPF ratio of four yields a median acceleration capacity of 2g. The randomness, PR, and uncertainty, Pu, are assigned as 0.40 and 0.44, respectively, based on the guidance given for establishing surrogate fragilities in Ref 3-2. Top Event LL split fration values are generated using a spreadsheet The values are shown in Table 3-4. The seismic structure fragility analysis (Ref. 3-1) determined a median acceleration capacity and HCLPF value for the containment shell, and the reinforced-concrete base slab. These values are shown in Table 3-

5. The base slab is the most limiting and has a median acceleration capacity of 2.3 lg and HCLPF of 0.70g. This is bounded by the surrogate Top Event LA, which leads directly to core damage and the Containment Isolation Top Event LL, which is mapped to a large (greater than four-inch diameter) leak in containment. Therefore, containment structural failures are not modeled in this evaluation.

3.1.6.1 Plant Damage States The Seismic Event Tree quantification binned the seismically induced core damage sequences into various plant damage states (PDS). The PDS define the entry condition into the Level 2 analysis, and define the thermodynamic conditions of the RCS at the time of core damage, the status of containment, and availability of both passive and active safety features that can terminate the accident or mitigate the release of radioactive materials to the environment. Table 3-6 contains the PDS with the three highest frequencies. The fractional contribution of each PDS to the different failure categories was obtained from Table 4.7.2.b of the IPE Summary Report, Reference 3-14. The dominant seismic PDS, HRIF, contains 85% of the total seismic core damage (quantified without surrogate Top Event LA). HRIF is the second ranked PDS in the internal events model. HRIF represents a high pressure in the reactor coolant system at the time of vessel melt through (VMT), only the RCS volume of coolant is inside containment because safety injection failed, the containment is isolated, and containment cooling has failed. HRIF results from a seismic-induced SBO or spurious safety system actuation (SSSA) with a total loss of main and auxiliary feedwater. The containment is isolated but HPSI and Containment Spray are not available. Most of the remaining seismic core damage (10% of total) is binned to PDS HRWF. HRWF results from a seismic-induced SBO with a total loss of foedwater, safety injection failure and failure of the containment isolation function. PDS HRWF represents a condition of high RCS pressure at vessel melt through, safety injection failure results in only the RCS volume of coolant on the containment floor, containment has a large (greater than four-inch diameter) leak area, and containment heat removal and fission product scrubbing are failed. PDS HRWF is a relatively severe PDS and did not appear in the Internal Events model and could not be 're-binned' to a higher-frequency, higher-consequence PDS from the Internal Events PRA because none existed. PDS HRWF results partially due to linking Containment Isolation Top Event LL to the large-break-size containment failure. This modeling is conservative but was done because the actual response of BGE 3-22 RAN 97-031

Calvt CliffM Nucle Powe Plant Seismic Analysis Individual Plant Examination Exftnal Events contaiment isolation is not well understood and internal events PRA MAAP runs do not exist for PDS HRWF. After the seismic quantification was performed we realized that assuming all containment failures to be large may have been overly conservative. Therefore, HRWF is binned to the most likely containment failure categories. Since HRWF is a relatively severe PDS it will likely result in the more severe categories of early-small and early-large containment failures. The results shown in Table 3-6 show a range of values for PDS HRWF's contribution to these two containment failure categories. The values reflect the two extreme cases of HRWF resulting entirely in early-large release (conservative) to HRWF resulting entirely in early-small release (less conservative). The true value lies somewhere in this range, but it is not known where. In the worst case, the seismic contribution to early-large containment failure is 1.4 IE-06 per year. About 5% of seismic core damage is binned to HGIP, which includes HHIP. HGIP represents a condition of high RCS pressure at VMT, HPS[ and containment-spray pumps inject before VMT, the containment is isolated and not bypassed, and containment heat removal and fission product scrubbing are available. 3.2 USI A-45 and Other Seismic Safety Issues The purpose of this section is to describe how the CCNPP IPEEE evaluates the Decay Heat Removal Safety Function based on results from the seismic analyses. The evaluation was performed to identify potential decay heat removal vulnerabilities for seismic events initiated from power operation, and to kdermine if the risk associated with the loss of decay heat removal can be reduced in a cost-effective manner. The results of this evaluation support closure of USI A-45. 3.2.1 USI A-45 Background The objective of the NRC's Shutdown Decay Heat Removal (DHR) Requirements Program (A-45) is:

           "to evaluate the adequacy of currentlicensing requirementsfor ensuringthat nuclear powerplants do not pose an unacceptable risk to the public as a result offailure to remove decay heat" (Ref 16).

This issue was designated USI A-45 on December 24, 1980. At the time the A-45 program was started, the NRC's desire was to determine the possible advantages and disadvantages of backfitted, independent, bunkered DHR systems such as those being installed at plants in a few European countries. In 1984, the A45 program characterized the DHR systems and functional capabilities of U.S. plants and grouped them into eight groups (Ref. 17). A Shutdown DHR analysis of a Combustion Engineering two-loop pressurized water reactor was performed in August 1987 (Ref. 18). The results of this and other NRC sponsored DHR case studies were summarized in a Shutdown Decay Heat Removal Analysis report (Ref. 19). The results of these studies prompted a policy statement concerning Shutdown Decay Heat Removal Requirements to be issued (Ref. 20). This SECY document informed utilities that the resolution of USI A-45 will be accomplished through plant-specific analyses under the IPE process. Due to the plant-specific nature of DHR vulnerabilities and corrective actions, the WPE and 1PEEE were determined to be the most effective means for resolving this issue. RAN 97-031 3-23 BGE 3 -23 RAN 97-031

CWlOt COB Nudea Pow Plant Sem0ic Anayti Individua Mlat Ewamination Exftmal Events In November of 1988 the NRC issued Generic Leter 88-20 which requires the IPE process to resolve USI A-45 (Re. 21). Resolution of USI A-45 requires:

         "adeterminationof whether the DHRfiunction is adequateand If cost-beneficial Improvemenft could be Identified" Appendix 5 of Generic Lett 88-20 identifies potential improvements to DHR systems.

3.2,2 Evaluatiom The CCNPP EPE submttal addressed the issue of DHRI With the exception of =ternal evmts, the CCNPP IPE concluded that USI A-45 was resolved. This section provides an evaluation of the CCNPP DHR fimtions with repect to the seismic analysis. Individual sequence namination was performed to dktrmine if any differences appeared in the seismic analysis that were not already identified in the internal events analysis. The major sequences from all seismic initiating evens were evaluated and compared with all sequences from CCPRA internal events. Most of the seismic sequences appear in the internal events CCPRA. All additional sequences unique to seismic were the result of increased human action failure probabilities. In seismic, certain performance shaping factors for all human actions were increased proportional to the "g" level of the earthquake. This, in turn, increased the failure probabilities for these human actions (See section 3.1.5.4 for detailed discussion on seismic human actions). CCNPP currently has effective operator training for these human actions, and it is not expected that additional training would benefit the failure probability of these human actions in the event of a seismic event. Based on these results, the CCPRA has effectively evaluated the DHR function with respect to seismic events at CCNPP and USI A-45 is resolved. 3.2.3 Charleston Earthquake Issue In accordance with NUREG 1407 and EPRI Report NP-6395-D, the Charleston issue has been closed for all but eight outlier plants identified through the Eastern U.S. Seismicity program. CCNPP is not one of those outlier plants. The Charleston issue is therefore considered closed. RAN 91-031 3-24 BGE 3-24 RN97-031L

Calvin Cliffs Nuiow r PMat Seismic Analysis Individual Plant Exainatmia Extmal Events 3.3 References 3-1 Probabilistic Soil-Structure Interaction Analysis and Fragility Calculations for Selected Structures and Buildings at CCNPP, Stevenson & Associates 3-2 Seismic Fragilities for IPEEE Equipment, CCNPP, Report No. 4211 I-R-002, EQE International, Inc. 3-3 IPEEE Seismic PRA Component Walkdown List, RAN 94-018 3-4 A Methodology for assessment of Nuclear Power Plant Seismic Margin (Revision 1), EPRI NP 6041-SL 3-5 NUREG-1448, "Revised Livermore Seismic Hazard Estimates for 69 Nuclear Power Plant Sites East of the Rocky Mountains", Draft, October 1993 3-6 EPRI-TR-103959, "Methodology for Developing Seismic Fragilities," June 1994 3-7 Kennedy, R. P., et al, "Dominant Contributors to Seismic Risk", Proceedinus: EPRJ/NRC Workshon on Nuclear Power Plants 3-8 Kennedy, R. P., et al, "Probabilistic Seismic Safety Study of an Existing Nuclear Power Plant", Expanded version of Invited Paper K2/1, presented at the 5th International Conference on Structural Mechanics in Reactor Technology, Berlin (West), 13-17 August 1979 3-9 BGE, IEB 80-11 Response, 1985 3-10 "Evaluation of Seismic Capacity of Condensate Storage Tanks at CCNPP Using a Local Nonlinear Finite Element Model for Bolt-Chair-Tank Shell Interaction", Stevenson & Associates, February 8, 1996 3-11 "CCNPP Units I and 2 Identification of Safe Shutdown Equipment for Unresolved Safety Issue A-46", MPR-l 187, Revision 3, November 1995 3-12 CCNPP Units I and 2 USI A-46 Relay Evaluation, MPR-1371, Revision 1, November 1995 3-13 NUREG-1407, "Procedural and Submittal Guidance for the Individual Plant Examination of External Event (IPEEE) for Severe Accident Vulnerabilities", Final Report, June 1991 3-14 Calvert Cliffs Nuclear Power Plant Individual Plant Examination Summary Report, December 1993 3-15 Human Error Methodology Report, RAN 96-002, Revision 0 3-16 A. Marchese, "Shutdown Decay Heat Removal Requirements" Task Action Plan, NRC Unresolved Safety Issue A-4, Rev 3, USNRC, Washington DC, March, 1984 3-17 Brookhaven National Laboratory, Brookhaven, MA, Grouping of Light Water Reactors for Evaluation of Decay Heat Removal Capability, NUREG/CR-3713, June 1984 BGE 3-23 RAN 97-031

Cavei Cliffs Nudelr Pow Plant Seismic Analysis Individual Phat Emimi ExtenW Events 3-18 Sandia National Laboratories, Albuquerque, NM, Shutdown Decay Heat Removal Analysis of a Combustion Engineering Two-Loop Pressurized Water Reactor, NUREG/CR-4710, August 1987 3-19 Sandia National Laboratories, Albuquerque, NM, Shutdown Decay Heat Removal Analysis: Plant Case Studies and Special Issues, NUREC(CR-5230, August, 1989 3-20 USNRC, Shutdown Decay Heat Removal Requirements (USI A-45), SECY-88-260, September 1993 3,21 Nuclear Power Reactor Facilities, Individual Plant Examination for Severe Accident Vulnerabilities, Generic Letter No. 88-20, 10CFR§59.54(f), Code of Federal Regulations, November 23, 1988 3-22 Calvert Cliffs Engineering Standard No. ES-O 1, System Structure, and Component (SSC) Evaluation 3-23 Calvert Cliffs Nuclear Power Plant, Units I and 2 Updated Final Safety Analysis Report (UFSAR), Volume H,Revision 20, February 5. 1997. BGE 3-26 RAN 97-031

Calvert Clifif Nuclea Power plant Seismic Analysis Individual Plant Examination External Events FIGURE 3-1 Failure Probability vs. Seismic g (Short Term Actions) 10o0.0o

 -5 0             4 CD 2 0

M 10-1.o00 C 0 4 3 2

  .0                                                                                                                                                                                                    -e--BHEF11
 .0                                                                                                                                                                                                     - -                BHEF12
                                                                                                                                                                                                        ----               B HERH2 5                                                                                                                                                                                                      B HERS1 4
                                                                                                                                                                                                 -f---                     B HERS2 2

10 -3.O

                    .. . . . . . . .I . . . .. . . . . I . . . . . . . . . I . . . . . . . . . I . . . .. . . . . I . . . . . . . . .I . . . . . . . . . I . . . . .. . .. I . . . . . . . . . I . . . . . I . . . I . . .. . . . . . I . . . . . . . .

0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 Seismic g Classification BGE 3 -27 RAN 97-031

Calvert Cliffs Nuclear Power Plant Seismic Analysis Individual Plant Examination External Events FIGURE 3-2 Failure Probability vs. Seismic g (LongTerm Actions) 100.0000 7 5 4 3 2 10"1.0000 8 6 4 3 2 6 4 3 2 F 1 10-4.000@

                                 *          ,                    I....       II           I                        i            I 0.0        0.2      0.4          0.6        0.8           1.0          1.2       1.4            1.6        .1.8   2.0 Seismic g Classification RAN 97-031 3-2&.,.

BGE BCE 3-2k.. e... RAN 97-031

Calvert Cliffs Nudlar Power Plant Sebt Analysis lndividual Plant xaminmation Euxeal Evits FIGURE 3-3 SEISMIC CORE DAMAGE FREQUENCY CONTRIBUTIONS vs. PEAK GROUND ACCELERATION 1.00E-05 I II. 1.00E-06 E U

      .! 1.00E-07 2W E

0 1.00E-08 "2 E a *. 1 IN 1.0-8CmfmmF 4M co ( 4)0 m' WD ' CD v o s -- - Ni (4 M IV !S W 0 S 6 ai 6 S CS 6  ; 0 C; Peak Ground Acceleration RAN 97-031 3-29 BGE BGE 3-29 RAN 97-031

Calvert Cffs Nuclear Power Plant ScismicAnaiysia Individual Plant Eamination External Events TABLE 3-1 CCNPP SEISMIC HAZARD CURVE VALUES Updated LLNL curves from NUREG 1488 Acceleratiom (cm/sec/sed Mean 15th Percentiles 50th (median) 85th I 50 .7674E-03 .6850E-04 .3090E-03 .1300E-02 75 .4321E-03 .3100E-04 .1620E-03 .7160E-03 150 .1459E-03 .6460E-05 .4310E-04 .2340E-03 250 .5891E-04 .1470E-05 .1350E-04 .8490E-04 300 .4141E-04 .8270E-06 .8380E-05 .5590E-04 400 .2292E-04 .2720E-06 .3780E-05 .2830E-04 500 .1402E-04 .1040E-06 .1900E,05 .1570E-04 650 .7565E-05 .2860E-07 .77i0E-06 .7510E-05 800 .4498E.05 .9010E-08 .3370E-06 .4000E-05 1000 .2490E-05 .2220E-08 .1290E-06 1900E-05 BGE 3-30 RAN 97-031

Calvert CliW Nuclear Power Plant Seismic Analysis Individal Plant Examination External Events TABLE 3-2 SEISMIC INITIATING EVENTS Frequency Batch Name Initiators Description PGA (per year) SEISMIC1 SMCP03 SEISMIC EVENT O.IG - 0.026G 6.7870E-03 SMCPO0 SEISMIC EVENT 0.027G - 0.051G 1.5350E-03. SMCPO8 SEISMIC EVENT 0.052G - 0.077G 3.3530E-04 SMCP12 SEISMIC EVENT 0.078G - 0.115G 1.4310E-04 SMCP13 SEISMIC EVENT 0.116G- 0.134G 7.1550E-05 SMCP15 SEISMIC EVENT 0.135G - 0.153G 7.1550E-05 SMCPI8 SEISMIC EVENT 0.154G - 0.179G 2.1750E-05 SMCP20 SEISMIC EVENT 0.180G - 0.204G 2.17501E-05 SMCP23 SEISMIC EVENT 0.205G - 0.230G 2.1750E-05 SMCP24 SEISMIC EVENT 0.23 1G - 0.242G 1.0870E-05 SMCP26 SEISMIC EVENT 0.243G - 0.255G 1.0870E-05 SMCP28 SEISMIC EVENT 0.256G - 0.281G 8.7500E-06 SEISMIC2 SMCP31 SEISMIC EVENT 0.282G - 0.306G 8.7500E-06 SMCP33 SEISMIC EVENT 0.307G - 0.332G 4.6230E-06 SMCP36 SEISMIC EVENT 0.333G - 0.357G 4.6230E-06 SMCP38 SEISMIC EVENT 0.358G - 0.383G 4.6230E-06 SMCP41 SEISMIC EVENT 0.384G - 0.408G 4.6230E-06 SMCP43 SEISMIC EVENT 0.409G - 0.4340 2.2250E-06 SMCP46 SEISMIC EVENT 0.435G - 0.459G 2.2250E-06 SMCP49 SEISMIC EVENT 0.460G - 0.485G 2.2250E-06 SMCP51 SEISMIC EVENT 0.486G - 0.510G 2.2250E-06 SMCP55 SEISMIC EVENT 0.511G - 0.548G 1.5140E-06 SMCP59 SEISMIC EVENT 0.549G - 0.587G 1.6140E-06 SMCP63 SEISMIC EVENT 0.588G - 0.625G 1.6140E-06 SMCP66 SEISMIC EVENT 0.626G - 0.6630 1.6140E-06 SEISMIC3 SMCP74 SEISMIC EVENT 0.664G . 0.740G 1.5330E-06 SMCP78 SEISMIC EVENT 0.741G - 0.778G 7.6670E-07 SMCP82 SEISMIC EVENT 0.779G - 0.8160 7.6670E-07 SMCP92 SEISMIC EVENT 0.817G - 0.918G 1.0040E.06 SMCIP5 SEISMIC EVENT 0.919G- 1.531G 3.4940E-06 RAN 97-031 3-31 BOB BGE 3-31 RAN 97-031

C~amt Cliffs Nuclear Power Plant Seismic Analysis Indivkidu Plant Exmininstion Extarnal Events TABLE 3-3 FRAGILrrlES OF SELECTED EQUIPMENT FOR CCNPP 1 Emnwrgef Diel Geerator Conliol 1.01 .39 .56 .21 bounded by Panels IC61ABC, 2C61AB,C SRW impact 2 ConW Rom HVAC Contrl Panels .66 .40 .52 .14 CRHVAC INBi08, 2NB408 3 80 Blowdown and Wast Sampling Hoods d-temined, to U! BD Waste .46 .38 .56 .10 be negligsle U2 B/D Waste* .22 .38 .56 .05 impact on U1 R/C Samples .80 .38 .56 .17 CDF U2 R/C Sample* .38 .38 .56 .08 4 Bounding Case Block Wall in Auxiliaty Bldg. (A at 1.06 .38 .44 .27 impact of this Elev. 2T and C at Elev. 69') wall bounded by othe components 5 Refueling Water Storage Tank .48 .22 .44 .16 RWST 6 U2 Turbine Lube Oil Cooler .54 .36 .40 .15 SRW 7 Generator Bus Duct Cooler .61 .39 .41 .17 SRW 8 U2 EHC Cooler .67 .31 .43 .20 SRW 9 Ul Turbine Lube Oil Cooler .97 .31 .31 .35 SRW 10 Block Wall Ne Waste Process Area Degassifier .88 .34 .41 .26 SRW 11 TDAFP Room A/C Unit .50 .33 .50 .13 SRW 12 Turbine Building SRW Piping .44 .41 .30 .14 SRW 13 OCAHUI DG Conrol Room A/C Unit .67 .41 .37 .18 OC-EDG 14 OCAHU ICDG Control Room A/C Condenser Unit .80 .29 .42 .25 OC-EDO 15 OCAHU2 DO Rm. Air Handler '.67 .41 .37 .18 0C-EDG Expansion anchors are only 1/4", thus very low capacity. BGE 3-32 RAN 97-031

Calved Cliffs Nuclear Power Plant Seaimnc Anayais lndividual Plant Examination Exteral Events TABLE 3.4 SEISMIC SPLIT FRACTION VALUES 2 .Am 1.0 0.0-% 0.00 0.48 0.43 0.20 % 0.2 0.1 2 Fmagilty 0. 0.00%4 0.2 0.18 0022 P0 0.4 040 PSMCRP1 5 u04 0.44 0.3 0.44 0.52 0.25 0.5 044 M0.5I 0341 0.35 0.41 0036 0.66 0.32 0.34 0.0 ToR Event LA La LE La LH UJ _-LK LL IENo. SUFFIX _ZL* I 2-m p 5Smolrfs CS S sur4CST RWTf CCEDO SM CR I.NAC LOOP flecodAer, C,4c I*d SMCP03 1 0.021 0.00% 0.34% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% CLOD% SMCP05 2 0.051 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0. O MODS SMCP23 3 0.077 0.27% 1.36% 0.00% 0.00% .... "S O' SMCP12 4 0.115 0.30% 0.02% 0.00% 0&.64% 0.00 SMCP13 5 0.135 048% 0.06% 0.00% 67.02% 0.00% SMCP15 6 0.10.00% 74.67% 0.00% SMCP18 7 0.179 0.07% 0.34% 0.00% 81.84% 0.00% SMCP20 8 0.204 0.14% 0.72% 0.00% 86.72% SMCP23 9 0.238 0.27% 1.36% 0.43% 90.33% SMCP24 A 0.242 0.35% 1.76% 0.00% 91A2% SMCP28 B 0.255 0.46% 2.28% 0.01% 92.81% SMCP28 C 0.281 0.73% 3.61% 1,02% 94 SMCP31 L 0.306 1.38% 5.28% 0.05% 95.W% SMCP33 E 0.332 1.54% 7.44% 0.12% 9&95% SMCP36 G 0.357 Z.07% 9.95% 0.23% 97.W% SMCP38 H 0.383 1.74% 12.97% 0.43% 07.88% 9&2% SMCP41 P 0.408 3.48% 16.24% 0072% 70 4L70% 98 98.67% SMCP43 J 0.434 4.36% 19.9B% 1.16% 99.22% 98.91% SMCP46 K a.459 5.3D% 23.85% 1.75% .  ; ' 99.53% 99.13% SMCP49 L 0.485 6.38% 28.09% 2255% 81.24% 99.72% 99.32% SMCP51 M 0.510 7.51% 3.731% 3.53% 34.9D% 964%.3% 9.46% SMCP55 N 0.581 9.37% 38.87% 5.45% 60.697 99.92% 99.61% SMCP59 0 0.587 11.46% 46.58% 7.99% 65.88% 98.8% 9.6% 9. SMCP63 P 0.625 13.63% 51.94% 11.6 76%9942% 9 1.10% 99.98% 91.79%

          ,SMCP66       0     0-663      15.92%     57.98%   14,50%D*              7.3          . 94%               99.99%   9.4 SMCP78        T     0.778      23.31%     73.47%   27.40%              ,83.69%            99.86%             10D.00%  99.93%

SMCP82 U 0.816 25.83% 77.56% 3Z.11% " ** 85.96% 99M9% 100.00% 99.95% SMCP92 V 0.918 32-2 86.11% 44.91 9063% 96.-78 99.97% 100.00% 99.97% 8;MCIP5 z 1.5M0 1 64.96% 99.47% 90.16% 99.95% 99.(XDk 99.E) 100.00%

• 10. 100.00%

RAN 97-031 3-33 BGE 3-33 RAN 97-031

Calvert Cliffs Nuclear Power Plant Seismic Analysis Individual Plant Examination External Events TABLE 3-5 MEDIAN CAPACITIES mad HCLPF VALUES FOR BUILDINGS and STRUCTURES Buimin/S Median Canacitv CP Containments Shell-With Prestress 7.78g 2.85g Shell-Without Prestress 2.68g 0.98g Reinforced Concrete Base Slab 2.31g 0. 7 0g Auxiliamy Building-Main Reinforced Concrete Shear Wall 2.54g 0.95g Steel Column 2.50g 0.9Og Auxiliary Building Penetration Area Reinforced Concrete Shear Wall 2.76g 1.05g Reinforced Concrete Shear Wall 1.19g 0.45g Intake Structue Reinforced Concrete Shear Wall 2.30g 0.93 Reinforced Concrete Shear Wall 1.40g 0.55g New EDG Building Reinforced Concrete Shear Wall 2.12g 0,80g Reinforced Concrete Slab 1.24g 0.49g Turbine Building Steel Columns 2.88g 1.02g Fire Pump House Steel Beam 23.22g 8.51g Condensate Storage Tank Tornado Enclosure--Reinforced Concrete Shear Wall 4.05g 1.84g Fuel Oil Storage Tank Tornado Enclosure Reinforced Concrfte Shear Wall 8.70g 3.70g values are referenced to peak ground acceleration in g's RAN 97.031 3-34 BGE 3-34 RAN 97-031

Cahlvet cliffs Nuclear Power Plant Smcic Anabys Individual Plant Examinton External Events TABLE 3-6 SEISMIC CONTRIBUTION TO FREQUENCIES OF MAJOR CONTAINMENT FAILURE CATEGORIES FROM THE KEY PLANT DAMAGE STATES Associated Percent of ontainment Failure Category Seismic Seismic COF HRWP HRIF HGIP C DP 1.10E-06 I 9.07E.-0 1 6.1211104 I. intact Containment 4.62E-07 4.33% 4.62E-07 II. Late Containment Failure 8.63E-06 80.9% 8.614E-06 2.05E-08 III. Early Small Containment Failure 1.70E-07 to 1.27E-06 1.3% to 11.9% 0 to 1.10E-06 1.632E-07 6.65E-09 IV. Early Large Containment Failure 3.13E-07 to 1.41E-06 2.9% to 13.2% 0 to 1.10E-06 2.902E-07 2.25E-08 V. SmaU Containment Bypass O.OOE+00 0.00% VI. Large Containment Bypass O.OOE+00 0.00% Total of all groups 1.07E-05 100% 100% 100% 100% 4 Note; The Seismic contribution to Containment failure categories IV and V Is shown as a range of values. A range Is shown because the contribution of PDS HRWF will be apportioned between the small and large early containment failures, but the ratio Is unknown. Therefore, we show a range of values which reflect the contribution of PDS HRWF from being attributed entirely to early-large containment failures (conservative) to early-small containment failures. See section 3.1.6.1 for a m ore detailed explanation. These results reflect quantification without the surrogate Top Event LA. RAN 97-03 1 3-35 BGE 3-35 RAN 97-031

Calvert Cliffs Nuclar Power Plant Seismic Analysis Individual Ptam EuanmiMtion Fxernal Events TABLE 3-7 TOP 100 SEISMIC CORE DAMAGE SEQUENCES (quantified Wiut Swutopmt Top Event LA) Initiating Bin Frequency PDI euence Cumulative Event m I I I - 9 - ni I CDF SMCIP5 3 2.37E-06 HRIF (1-(LLZ+S14+SRA+SG4+SHH+RSL)) 22.23% SMCIP5 3 1.11E-O HRWF LLZ 32.60% SMCP74 3 1.31E-07 HRIF LER*XW2FCH 33.83% SMCP74 3 1.16E-07 HRIF LER*F31 34.92% SMCP92 3 9.47E-06 HRIF XW2*FCH 35.81% SMCP74 3 9.21E-08 HRIF LER*H32*HSU*FIR 38.67% SMCP92 3 8.40E.06 HRIF F31 37.46% SMCP74 3 7.94E-08 HRIF LER*GE5"FIR 38.20% SMCP74 3 7.39E-08 HRIF LER*XV2HXSFIR 38.89% SMCP82 3 6.81E-08 HRIF LEU'XW2*FCH 39.53% SMCP74 3 6.71 E-08 HRIF GJSXW2*FCH 40.16% SMCP78 3 6.70E-08 HRIF LET'XW2*FCH 40.79% SMCP92 3 6.65E-08 HRIF H32"HSU*FIR 41.41% SMCP41 2 6.45E-08 HRIF LEI*LGI*GES*HX3*F1R 42.01% SMCP82 3 6.04E-08 HRIF LEU*F31 42.58% SMCP74 3 5.95E-08 HRIF GJ5*F31 43.13% SMCP78 3 5.94E-08 HRIF LET*F31 43.69% SMCP92 3 5.74E-08 HRIF GES*FIR 44.23% SMCP31 2 5.68E-08 HRIF LGD*LJD*GE5*GJA*HX3*F 1R 44.76% SMCP38 2 5.34E-08 HRIF LEH*LGH*GE5*HX3*FIR 45.26% SMCP92 3 5.34E-08 HRIF XW2*HX5*F1R 45.76% SMCP74 3 5.21 E-08 HRIF LER*HX5*UQ5 46.25% SMCP51 2 5.17E-08 HRIF LEM*GE5*HX3*F1R 46.73% SMCP66 2 4.85E-08 HRIF LEQ*GE5*HX3*F1R 47.19% SMCP49 2 4.81E-08 HRIF LEL*GES*HX3F1R 47.64% SMCP82 3 4.78E-08 HRIF LEU*H32*HSU*FIR 48.08% SMCP74 3 4.71E-08 HRIF GJSH32"HSU*F R 48.52% SMCP78 3 4.70E-08 HRIF LET*H32*HSUUFIR 48.96% SMCP63 2 4.65E-08 HRIF LEP*GES*HX3*F1R 49.40% SMCP74 3 4.65E-08 HRIF LER*XW2*Q11*QZ4 49.83% SMCP74 3 4.50E-08 HRIF LER*H32*HSU*MH5 50.26% SMCP41 2 4.48E-08 HRIF LGI*GE5*GJA*HX3*F1 R 50.68% SMCP59 2 4.41E-08 HRIF LEO*GES*HX3*F1R 51.09% SMCP38 2 4.28E-08 HRIF LGH*GE5*GJA*HX3*F R 51.49% SMCP36 2 4.19E-08 HRIF LEG*LGG*GE5*HX3*F1R 51.88% SMCP74 3 4.19E-08 HRIF LER*XW2*HX5*MH2 52.27% SMCP74 3 4.15E-08 HRIF GE5*GJA*F1R 52.66% SMCP82 3 4.12E-08 HRIF LEU*GES*FIR 53.05% SMCP46 2 4.12E-08 HRIF LEK*LGK*GE5*HX3*FIR 53.43% SMCP78 3 4.06E-08 HRIF LET'GE5*F1R 53.81% SMCP36 2 4.02E-08 HRIF LGG*GE5GJA*HX3*FIR 54.19% a a a RAN 97-03 1 3-36 BGE 3-36 RAN 97-031

Cahw laiffs Nwlosr Power Plans Seimc Analysi la&vxidua Plant Examuniatbon Externaf Events TABLE 3-7 TOP 100 SEISMIC CORE DAMAGE SEQUENCES (Continued) Initiating Bin Frequency equence Cumulative Event I I I .... r I CDF IMCP74 3 3.69E-08 HRIF LER*GES*MH5 54.55% SMCPSS 2 3.85E-08 HRIF LEZ*GES*HX3*FIR 54.91% SMCP82 3 3.84E-08 HRIF LEU6XW2HXS*FI R 55.27% SMCP74 3 3.79E-08 HRIF LER*FCH'F33 55.63% SMCP74 3 3.78E-08 HRIF GJ52XMHXS*F1R 55.98% SMCP78 .3 3.77E-08 HRIF LETwXM2HX5'F1 R 56.34% SMCP92 3 3.78E-08 HRIF HX6"UQ5 56.69% SMCP31 2 3.69E-08 HRIF LEDtLGDLJD*GE5*HX3*F1 R 57.03% SMCP43 2 3.64E-08 HRIF LEJ*tGJ*GE5*HX3*FIR 57.37% SMCP33 2 3.50E-08 HRIF LGEULE*GES*GJA*HX3*F1 R 57.70% SMCP82 3 3.36E-08 KRIF GJ5*XW2*FCH 58.02% SMCP78 3 3.36E-08 HRIF GJ5*XW2*FCH 58.33% SMCP92 3 3.38E-08 HRIF XW2*QI11*QZ4 58.64% SMCP74 3 3.26E-08 HRIF H32*HSU*FCH 58.95% SMCP92 3 3.25E-08 HRIF H32*HSU*MH5 59.25% SMCP74 3 3.08E-06 HRIF F3C 59.54% SMCP92 3 3.02E-08 HRIF ,XW2'HXS5MH2 59.83% SMCP78 3 2.98E-08 HRIF GJ5*F31 60.10% SMCP33 2 2.96E-08 HRIF LEE*LGE.8LJE*GE5*HX3*F1 R 60.38% SMCP92 3 2.81 E-08 HRIF GE5*MH5 60.64% a8 SMCP92 3 2.74E-08 HRIF FCH.8F33 60.90% SMCP82 3 2.70E-08 HRIF LEU*H~XS5UQ5 61.15% SMCP74 3 2.67E-08 HRIF GJS'KX5*UQ5 61.40% SMCP78 3 2.66E-08 HRIF LET*HX5*UQS 61.65% SMCP23 1 2.60E-08 HRIF LGg*LJ9*GE5*GJA*HX3*FI R 61.90% SMCP41 2 2.59E-08 HRIF LEI*LGI*H32*HSU*HX3*FI R 62.14% SMCP74 3 2.55E-08 HRIF LER*GE5*FCH 62.38% SMCP5I 2 2.44E-08 HRIF GES*GJA*-IX3*F1R 62.61% SMCP49 2 2.44E-08 HRIF GE5*GJA*HX3*FI R 62.84% SMCP82 3 2.41 E-08 HRIF LEU*XW2*Q1 1QZ4 63.06% SMCP74 3 2.38E-08 HRIF GJS*XW2*Q1 1QZ4 63.28% SMCP78 3 2.37E-08 HRIF LET*XW2*Q1I QZ4 63.51% SMCP74 3 2.36E-08 HRIF LER*HSJ*HZ3*FI R 63.73% SMCP82 3 2.36E-08 HRIF GJ5*H32*HSLD*FI R 63.95% SMCP78 3 2.36E-08 HRIF GJ5'H32*HSU*F1 R 64.17% SMCP82 3 2.34E-08 HRIF LEU*H32*HSLI*MHS 64.39% SMCP74 3 2.30E-08 HRIF GJS*H32*HSU*MHS 64.60% SMCP78 3 2.30E-08 HRIF LET*H32*HSU*MHS 64.82% SMCP46 2 2.28E-08 HRIF LGK*GE5.8GJA*HX3*F1 R 65.03% SMCP43 2 2.23E-08 HRIF LGJ*GE5*GJA*HX3*FI R 65.24% SMCP41 2 2.20E-08 HHIP LEItLGt*F31 65.45%

                      - ~.                         4 -          U RAN 97-031 3-37 BCE BGE                                                      3-37                          RAN 97-031

Cabvt Clfs NuWM Powr Plant SaisirnoAnamis ladivkdual Plant E,.rnmitioa Extrnal Evnts TABLE 3-7 TOP 100 SEISMIC CORE DAMAGE SEQUENCES (Continued) Initiating Bin Frequency PDS Sequence Cumulative Event CDF SMCP31 2 2.19E-08 HRIF LGDLJD*GJS*H321HSU*HX3"FIR 65.65% SMCP28 1 2.19E-O8 HRIF LGC*LJC*GESGJA*HX3"FIR*(1-(SRA)) 65.86% SMCP82 3 2.17E-08 HRIF LUEXW2"HXSMH2 68.08% SMCP38 2 2.15E-08 HRIF LEH*LGH*H32"HSU1X3*FIR 66.20% SMCP74 3 2.14E-08 HRIF GJSXW2*HX5"MH2 66.46% SMCP78 3 2.14E-08 HRIF LET*XW2*HXS*MH2 66.68% SMCP92 3 2.14E-08 HRIF H32HSUFCH 66.86% SMCP51 2 2.08E-08 HRIF LEM*H32*HSU*HX3"F1R 67.06% SMCP74 3 2.08E-08 HRIF LER*XW2*TF4 67.25% SMCP74 3 2.03E-08 HRIF GE5*GJA*MH5 67.44% SMCP82 3 2.02E-08 HRIF LEU*GESMHS 87.63% SMCP41 2 2.01E-08 HRIF LEI*LGI'GE5'HX3*MH5 67.82% SMCP26 1 1.99E-08 HRIF LGB*5JB*GES*GJA'HX3*FIR-(1-(SRA)) 68.00% SMCP78 3 1.98E-08 HRIF LET*GES*MH5 68.19% SMCP82 3 1.97E-08 HRIF LEU*FCH*F33 68.37% SMCP66 2 1.95E-08 HRIF LEQ.H32*HSU'HX3*F1R 68.56% SMCP82 3 1.94E-08 HRIF LHU*GJ5"F31 68.74% SMCP74 3 1.94E-08 HRIF GJSFCH*F33 68,92% RAN 97.031 3-38 BGE 3-38 RAN 97-031

Caivet Cliffs uctewa Power Plant Individua Plant Examination Extera Evena Seismic -uvi TABLE 3-9 PARTIAL LIST OF SPLIT FRACTION DESCRIPTIONS AND VALUES SP..V . ..- .........

              ..        ....               .,~u          ..          ..       ~t 4*                             CE FIR        AW delivers Wegaeiabo w, give 880 wit 810 weail                             4.9S.0     6601            7.38E-01 FM1        APYJ bea adoquaba ivediny (acindadeOP Utica fbe Wtaawitova), an CHNM        1 .22E-03  1.20E.02        8.37E-02 P33        AFW has wqade imvawq (iChica op actio6w tank swiSdavo) givea so             7.25E-03   3.20E-02        1.15E-01 PCH        APW PP RhI -ohma       op-esa,    sworn a 880 condition, EMP                7.83E-03   4.66E-02        2.37E-01 FF         OPMoro lisas AFW Tueouia Pomp Room Eramcopacy Coolift Nan, WO?4             9.82E-02   3.34E-01        9.40E-01 P114       Operabor aliens N2 or datam SWACs t AFW CVa, give a &daskn SDO HOP-S        6.6E-02    2.07E-01        6.801-01 095        EDO IA duals& pmvid- powerio4KV Bus 11, Loop > I I boun, ASA                7.74E-02   7.74E-02        7,74E.02 (ISA       EDO 0C dpra&vidaPower to a4KVBus, LOOP > IlIhoun, EDO IA                    2.34E-01   3.12E-01        4.74E-01 fails, ASA1 1132       OP satall d61-111Y Swichgcar HYAC trairn within 2 hours, LOOP               1.87E-02   0.1 8E02         1.78E.01 HSUJ       SWC3R HVAC IIDR OPERATES gives HYAC train 12 fails due to Ion ot            5 .04E-01  5.04E-01        6.04E-01 sippout; HVAC train I I bas sappoMl 4KV XUNIER 11 failure or LOOP causesa moamcabm Ioaa of 4KV Bus 11; Operato fua to dam antab tons bndrumeat M0(      Operator ooniola AMW flow, locally due to CR AFW Flow comvrl wuppoot        1 .98E-02  6.08BE-02        1.81 E-01 HZ3        OP locally ventilates bothi Swgr R~ma using teapormy fans, LOOP, 4KV Bus 14 1.66E-01    3.01E-01       4.96E-01 LED        OC EDO paauaas awsmicevent up to0.306 g.                                    2.03E-01    2.03E-01        2.03E-01 LEG        OC EDO msWWaiaasciauuic event upto 0.357 S.                                 3.25E-01    3.25E-01       3.25E-01 LEH        OC EDO Nmdainsama     simic eved ato 0.393 1.                               3.89E-01    3.89E-01       3.89E-01 LMt        OC EDO mdsasa sesmi event uptoO0.409 S.                                     4.49E-01   4.49E-01        4.49E-01 LWJ        OC EDO mstains aacismic vent upto 0.434gS.                                  5.09E-01   5.09E-01        5.09E-01 LPK        OCED        .a    a sciaaamac vetup t. .459 S.                              6.83E-01    6.a3E-O1       5.03E-01 LEL        OC EDO nasain.. a seismia ovent up to 0.485gS.                              GASEE0l     6.15E-01        0.15E-01 LEM        OC EDO nosaisa saeismic e potup to 0.31S.                                   6.61E-01    0.0 1E-OI       68.1E-01 LEO        OC EDO widaisaaaseismiccevent up to0.587 S.                                 7.7GE-O1    7.78E-01        7.76E-01 LUP        OCEDo         ;w    0 Sdiaeimimc vent up100.6m S.                           8.19E-01    *.1BE-O1       8.1$E-01 LHQ        OC ED       walaina a acunsmi meat up to 0.663 S.                           8.55E-01    8.55E-01        8.55E-01 LEZ        OC EDO mdisasaoa    asismic even.up to -W 1.                                7.23E-01    7.23E-01        72EO Log        81W Headers 11, 12, 21 and 22 sustain a seismic event up to 0.23 g.         3.43E-01    3.43E-01        3.43E-01 LGD        SRW Heders 11, 12, 21 aid 22 wudaiaa seismicevea p to 0.3o6 S.              8.51E-01    0.51E-01        0.51E-01 WGE       SRW Healers 11. 12,21 waid22 sudaa iaaemicevent upto o.332 g.               7.31E-01    7.31 E-01I      7.31E-01 LOG        SRW Ieeidrs 11, 12,21 and 22 =uAd& aseismticevent upto 0.357 S.             7.93E-01    7.93E-01        7.838-01 LOH       ISRW Heiden 11, 12,21 aid22 sudstisa seismic event upto 0.393 g.             8.44E-01 I    .44E-01       8.44E-01 RAN 97-031 3-39 BGE BWE                                                                    3-39                                          RAN 97-031

Calvsed C~hi Nuclear Power Plant Seismic Anahsi IndhOWua Plant Examinaboo Exhinmi Evcots TABLE 34 PARTIAL LIST OF SPLIT FRACTION DESCRIPTIONS AND VALUES (Continued) LW S ][Eous 11, 12,21 sd*22 maiaa wisasmovew ap 0.40t g. .631E-01 8,63E-01 0.83E-01 L(A .WHReina 11, 12,21 and22 mia*aasamio evenaupto0.434g. S.13E-01 9.13E-01 9.13E-O1 LOK SOW Ieesd It, 12,21 &aW22smaaisaso event upwt04AS9 9. 6.35E-01 9.35E-01 9.35E-01 LHR C- r- 11oom IVAC miais a suic' ev - up to 0.74 g. 5.97E101 5.97E-01 5.97E-01 LUT Coeidl Rom JVAC mmin a mscinc arve up t 0.778 g. 6.26-01 0.26E-01 6.26101 LHU CoQtil Room HVAC maim a seimsmc even up lo 0.816 S. 0.653E01 6.53E-01 0.53E-01 LV ComMd Room IrVAC maniasma seismi ee up to 0.9188. 7.17E-01 7.17E-01 7.17E-01 L19 SO0KV Swiakyase maiajsa sciamce vent up to 0.23 t. 6.691-01 6.69E-01 8.09E-01 IWD S00KV Swishbyard stais a seasmic ove to 0.255 g. 7.76E.01 7.70E-01 7.76E4-1 LIC S00KV Swilthyarud untais a saismtc event up to 0.281 g. ,656E-01 8.56E-01 8.66E-01 LID) W0KV Swischyaoi maiami a @dew@ even o uto 0.306 S. S .0BE-O1 9.06E-01 9.08E-01 LIB 50KV Swilcytard u sais 8icioner ,voL- up 19 0.332 X. 9.43E-01 0,43-01 9.43E101 LLB Coai*mat aIlioiftMiau a sismi rvent up to 0.332 X. 1.21-03 1.26E-03 1.20E-03 LLR Caoana hohlio mauss a sasmic even up to 0.74 g. 4.73E-02 4,73E-02 4.73E-02 LLT Conaiae Iol maua a scia even up to 0.779 . 5.62E-02 5.62E-02 5.62E-02 LLU Codssmailatuio maia*asasmu even up to 0.8165 . 6.58E-02 0.58E42 8.50E-02 LLV Coaiamn neto a amis a ascmlic ventup to 0.918 g. 9.62E102 9,52E-02 9.52E-02 Oparir

                    .MH recovm failed dam admission lUse toA W tuadi deives pumps,       2.15E-02   1,03E-01      4.18E-01 QII       OP scovers AFW at o0w (w/ia 10 minutes) of. spurious AFAS blok (Cowboy)  2.55E.01   3.75E-01      5.28E.01 QZ4       OP suove     AFW fuollowuig a "uous AFAS Mork, g,*en PORV opes an SSSA    1.45E-02  5.26E-02      1.59E-01
      . SL      Resebo Trip acumsac, pivo a LOOP (4KV Dums 12 & 13 d-cuMrgize)           3.2610E6   3.20E-0       3.20E-40 SA         Cow Nonna Sump Drais Lia imnacawas       ca LOCA. so aipo avaubl        2.01 E-03  2.01E-03      2.01E-03 T'i       AFW TURB PP II provides adequae flow gives PP 13 mscesaMf or oo.?ed, boh 3.76E-02   3.75E-02      3.75E-02 GDL sad Tunb Rae fails T04       AFW Pamp 12 woft, AFW PP II msucfl & 13 fails, EOPS                      2.02E-01   5.03E.01     1.00E + 00 UQ5        OP do mst underlil S/Gs whoa AFW flow ogrol aslost, givm SIG Level Ind  5.69E-02   1.16E-01      2.07E-01 w*l nautsfowontrwol 6WW, EO-41 X%2        OP supplies 120VAC Vital Panel from 208/120 VAC Irmhinat Bu, given       1.08E-01  2.17E-01      3.98E-01 I     104R is available RAN 97-031 3-40 BGE                                                                   3-40                                   RAN 97-031

Calvert CliffA Nuclear Power Plant Iniernal Fire Analysis Individual Plant Examination External Events SECTION 4 INTERNAL FIRES ANALYSIS 4.0 Methodology Selection The Nuclear Regulatory Commission (NRC) in Generic Letter (GL) No. 88-20 Supplement 4 (Ref. 4-1),

'Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities" requested all utilities to perform an individual plant examination of external events to identify any severe accident vulnerabilities that may exist at their nuclear power plants and to submit the results of the examination to the NRC.

The Baltimore Gas and Electric Company selected the fire PRA method to assess the total core damage frequency due to fire events at CCNPP. This selection is based primarily on the expected future usefulness of a plant specific fire PRA. 4.1 Fire Hazard Analysis A Level I PRA is used to evaluate the fire risk for CCNPP Unit 1. Unit 2 was reviewed and significant differences are evaluated. This summary report is written from the Unit 1 perspective. The Unit 2 assessment is contained in Section 4.6.7. The general guidelines described in NUREG-1407 (Ref. 4-2) and the EPRI Fire PRA Implementation Guide (Ref. 4-3) are followed. The EPRI Fire Events Database (Ref. 4-4) is used for the quantification of fire ignition frequencies. The Fire-induced Vulnerability Evaluation (FIVE) methodology (Ref. 4-5) is used as guidance for the evaluation of specific fire scenarios within a compartment when the failure of the entire compartment proved to be significant. The quantification of fire-induced core damage frequency (CDF) is obtained by propagating fire-induced failures through a modified version of CCPRA. This modified version is constructed from the General Transient module of CCNPP's updated internal events Level I PRA. This is referred to as the "base CCPRA." A screening process is used to identify the compartments and compartment groups of concern. Compartments are grouped when barriers between them are not credited. See Section 4.3.1. A fire initiating event is assigned to each compartment, compartment group or for fire scenarios within a compartment. In addition, fire initiating events are developed for compartments which are grouped as a result from cross-zone fire spread (fire propagation across credited fire barriers). A CDF point estimate for each of these initiating events is calculated as follows: Fcnr= F1

• P.
• Ph
• CCDP FCDF = fire-induced core damage initiating event frequency F1 = fire ignition frequency P. = probability of induced equipment damage Pa = probability of fire suppression failure CCDP = Conditional Core Damage Probability given the fire damage WGE 4-1 RAN 97-031

w Calvet Clifi Nuclear Power Plant Intenal Fire Analyuis Individual Plat Examination External Events The overall fire CDF is determined by summing all the compartment CDFs and scenario CDFs including the contribution due to cross-zone fire spread. These results are summarized in Section 4.6.6. Cross-zoneProtagaion The assessment of the likelihood of cross-zone propagation includes the determination of the fire frequency at which each barrier is challenged, the likelihood of suppression effectively stopping the fire growth and the likelihood that the barrier is effective in preventing the fire from spreading to an adjacent compartment. See Section 4.3.3 for details on the approach used in the Calvert Cliffs Fire PRA (CCFPRA). Compartment FireModeling Those compartments which exhibited unacceptable conditional CDFs when modeled as fully burned or those which have a large system functional loss potential are evaluated to determine compartment specific fire scenarios. See Section 4.3.4 for the detailed fire modeling process. Fire scenarios are developed for over twenty compartments. These fire scenarios are then grouped, assigned an initiating event designator and then propagated through the PRA. See Attachments 4-A through 4-U for details on the development of fire scenarios for each compartment. Cable Analysis Cable analysis is perhaps the most important element of CCNPP's fire risk analysis. The cable routing used in CCFPRA addresses all functions considered in the base CCPRA. Therefore, assuming failure of those non Appendix R components where cable routing information is typically not available was not required. This approach required the routing and analysis of approximately 5,500 cables. It should be noted that cables for the containment mitigation and isolation functions, and those fire-induced initiating events that are in addition to a standard reactor trip are explicitly evaluated. See Section 4.4.1 for more details on the cable routing analysis. Quantificadonof Fire-Risk The method used to propagate the impact of fire induced fires through the PRA model is described in Section 4.6. Included in this discussion is a description of BGE's comprehensive treatment of human actions. In addition, the reactivity control functions which support the likelihood that the reactor trips on demand are explicitly modeled by the evaluation of impact of fires on the loss of the Reactor Protection System and the Diverse Scram System. A containment performance review is also done to identify any sequences leading to containment failure that are different from those identified in the individual examination of internal events. See Section 4.7. Fire Risk Sco.ing Study Fire Risk Scoping Study Issues are addressed through specifically tailored walkdowns as defined in the FIVE methodology, including seismic fire interactions, effects of fire suppressant on safety repeated equipment, fire barrier effectiveness and control systems interactions. See Section 4.8. RAN 97-031 4-2 BGE 4-2 RAN 97-031

Calvert Cliffs Nuclear Power Plat Internal Fire Anaysis individual Plant Examinafion External Evens 4.1.1 Key Assumptions The Calvert Cliffs Fire PRA (CCFPRA) uses an updated version of the IPE logic models. Consequently, fundamental assumptions associated with the Level 1 analysis are applicable. The following key assumptions are used in this analysis. Specific assumptions for each compartment are included in the analysis for those compartments.

1. The reactivity control fimctions which support the likelihood that the reactor trips on demand are explicitly modeled by the evaluation of impact of fires on the loss of the Reactor Protection System and the Diverse Scram System.

2. Internal events operator actions are assumed to be applicable. However, they are failed if a fire blocks the performance of the action in question and are degraded to reflect the impact of fire and smoke. See Section 4.6.1.

3. Fire induced spuriously opening PORVs and RCP Seal LOCAs due to the loss of the Component Cooling Water System are explicitly modeled.

4. For fires which impact off-site power, a 24 hour LOOP duration is assumed if off-site power is lost and the Control Room is abandoned, a four hour duration is assumed if a 4KV service transformer is lost with the Control Room manned and two hours is assumed for all other scenarios. Note that a fire in the switchyard has a similar impact as that of a standard loss of off-site power event and therefore its impact is considered to be included in the internal events loss of offsite power initiating event.

5. A 24 hour period is assumed as the base mission time for this analysis. This time is consistent with the internal events analysis and NUREG-1335 (Ref. 4-12).

6. Cross-zone propagation between Appendix R areas and between sub-divided areas within Appendix R areas with credited barriers is considered possible and is explicitly evaluated. Barriers which are not in an inspection and/or control program are assumed to be ineffective. See Section 4.3.3.

7. It is assumed that all automatic fire suppression systems are properly sized to effectively mitigate the growth and spread of fire within their zones of coverage.

8. It is assumed that the Halon 1301 extinguishing agent has no short term effects on equipment operation based on an evaluation of chemical characteristics, industry studies and operational experience.

4.2 Review of Plant Information and Walkdown This section provides a description of the plant, particularly as it relates to the fire protection program and other aspects of the plant that bear on the Fire PRA for CCNPP. The IPE Summary Report (Ref. 4-6) for CCNPP provides descriptions and simplified diagrams of the plant systems that were modeled for that study, and therefore, they are not included here. This section also includes a discussion of the plant familiarization work and walkdowns that were done as part of the fire study. BGE 4-3 RAN 97-031

Calv Cliffs Nuclear Power Piant I Fi Analysis Individual PlaIn E£raminadon Exiernal Evens 4.2.1 Plant Fire Protection Program Description The CCNPP Fire Protection Program (Ref. 4-11) is an integrated effort involving components, procedures and personnel used to carry out all activities of fire protection and prevention. The program provides the necessary controls to protect the health and safety of CCNPP workers and the general public, satisfy NRC and insurer requirements and safeguard Company assets with the goal to prevent fires and to minimize the consequences of any fire that does occur. To achieve this goal the program established a defense-in-depth approach by providing:

1. Design of systems and facilities that minimize the probability and consequences of fire; and that provide for the detection, annunciation, confinement and suppression of fire.

2. Controls to verify the operability and availability of equipment and systems through inspection and test programs.

3. Controls that prevent fires from starting and minimize potential fire hazards.

4. Controls that establish planned strategies in response to fires including trained fire fighting brigades.

5. Training programs that provide fire prevention and response training consistent with assigned duties and responsibilities.

6. Monitoring and continuous assessment of Fire Protection Program performance.

7. Periodic audits of the Fire Protection Program.

4.2.2 Plant Familiarization This section describes the plant familiarization work performed to complete the CCFPRA. The CCFPRA is developed in a large part by BGE personnel who have familiarity with the plant and its systems. Their work is supported by the site's fire protection engineers. Key information used in support of the CCFPRA is described below. Information contained in the IPE (Ref. 4-6) and its update is also used, but is not included below. 4.2.2.1 Fire Hazards Analysis The Calvert Cliffs Fire Hazards Analysis Summary Document (Ref. 4-7) provides a compartment by compartment summary of the fire protection features in plant compartments which contain safe shutdown components. This document identifies for each compartment:

                  " the major Appendix R safe shutdown equipment
                  " the Appendix R Abnormal Operating Procedure number
                  " the type of fire detection and suppression

• the Appendix R exemptions, if any

                  "    a summary of the primary fixed combustibles
                  "    the equivalent fire severity of the combustible loading BOE                                                         4-4                                   RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events 4.2.2.2 Interactive Cable Analysis The Interactive Cable Analysis for Calvert Cliffs Nuclear Power Plant Unit 1 (Ref. 4-8) analyzes the consequences of a fire in any area associated with the safe shutdown of Unit 1. A similar document exist for Unit 2 (Ref. 4-9). This document includes listing of equipment and cables in specific fire areas, previously defined in the Calvert Cliffs Nuclear Power Plant Fire Protection Evaluation Program (Ref. 4-10), required to reach hot standby and cold shutdown. It provides an analysis of the impact of losing each area as a result of a fire and identifies the available recovery actions. 4.2.2.3 Combustible Loading Analysis Report The Combustible Loading Analysis identifies the assumptions, methodology and results of the July 1993, combustible loading re-analysis for Calvert Cliffs Nuclear Power Plant Units I and 2 (Ref. 4-14). This calculation:

                 "     defined the specific plant area which required calculation

• calculated floor area for each specific plant area
• identified heat content (Btu) attributed to cable insulation
• identified heat content (Btu) attributed to fixed and transient combustibles
• summed the total heat content found in each area then calculated the heat load (Btul/t 2 ) and fire severity (min.) for the plant area This information was used as a prime input into the calculation for the fire ignition frequency for each area.

See Section 4.3.2. 4.2.2.4 Abnormal Operating Procedures (AOPs) These procedures are used by operators when responding to a particular abnormal situation in the plant, such as a fire. The AOPs which address mitigating a fire are listed below: AOP-9A Control Room Evacuation and Safe Shutdown due to a Severe Control Room Fire AOP-9B Safe Shutdown due to a Severe Cable Spreading Room Fire AOP 9C Safe Shutdown due to a Severe Fire in Room 100, 103, 104, 110 or 116 Auxiliary Building (-)I0' and (-)15' Corridors AOP-9D Safe Shutdown due to a Severe Fire in Room 119 - Unit I No. I I ECCS Pump Room AOP-9E Safe Shutdown due to a Severe Fire in Room 225 - Unit 1 5' Exhaust Fan Equipment Room AOP-9F Safe Shutdown due to a Severe Fire in Room 226 - Unit l Service Water Pump Room AOP-9G Safe Shutdown due to a Severe Fire in Room 227/316 - Unit 1 5' and 27' East Piping Penetration Rooms AOP-9H Safe Shutdown due to a Severe Fire in Room 228 - Unit 1 Component Cooling Pump Room AOP-91 Safe Shutdown due to a Severe Fire in Room 315 - Unit 1 Main Steam Penetration Room AOP-9J Safe Shutdown due to a Severe Fire in Room 317 - Unit 1 Switchgear Room 27' RAN 97-031 4-5 BGE 4-5 RAN 97-031

Calvert Cliffs Nuclear Power Plan IcnW Fire Analysis Individual Plan Examination Externas Events AOP-9L Safe Shutdown due to a Severe Fire in Cable Chase IA - Unit 1 West Vertical Cable Chase AOP-9M Safe Shutdown due to a Severe Fire in Cable Chase IB - Unit 1 East Vertical Cable Chase AOP-9N Safe Shutdown due to a Severe Fire in Room 408, 410, 413, 419, 424, 425, 426 or 428 Auxiliary Building - 45' Corridors and Sample Rooms AOP-9P Safe Shutdown due to a Severe Fire in Room 429 - Unit I Auxiliary Building 45' East Electrical Penetration Room AOP-9Q Safe Shutdown due to a Severe Fire in Room 430 - Unit 1 Switchgear Room 45' AOP-9R Safe Shutdown due to a Severe Fire in Room 603 - Unit 1 Auxiliary Feed Pump Room AOP-9S Safe Shutdown due to a Severe Fire in Room 423 - Unit 1 Auxiliary Building 45' West Electrical Penetration Room 4.2.2.5 Fire Fighting Strategies Manual The Calvert Cliffs Fire Fighting Strategies Manual provides the operator and fire fighter with pertinent information in the case of a fire in vital areas, particularly for those areas containing safe shutdown equipment. For each area there is an elevation floor plan with the appropriate compartment highlighted and access/egress routes clearly marked. Locations of fire extinguishers, hose stations and electrical outlets found on that elevation are also indicated. Individual floor plans show a detailed area layout and indicate the location of fire fighting apparatus, important plant equipment, various hazards (fire, toxic, radiological, electrical, etc.) access/egress routes, smoke ejection routes and electrical power supply breaker numbers. 4.2.2.6 Fire Prevention Administrative Procedure CCNPP Fire Prevention Administrative Procedure, SA-I-100, establishes administrative controls and requirements to prevent fires and to ensure activities are conducted in a manner that promotes fire prevention. It promulgates the plant processes for controlling transient combustibles, ignition sources, fire barrier penetrations and the use of fire suppression water systems for non-emergency, non-fire fighting purposes. 4.2.2.6.1 Controlling Transient Combustible SA-I-l10 requires minimizing the amount of transient fire loading introduced inside or adjacent to safbty-related area or systems and in the Turbine Building during maintenance, modifications, or operations activities. It also requires that the amount of transient material introduced into an area will not exceed allowable combustible limits specified in the Combustible Loading Analysis. The Combustible Loading Analysis includes an allowance equal to the following total quantities of transients to be introduced into plant areas:

• 100 pounds of ordinary combustibles
• 5 gallons of flammable liquids
• 55 gallons of combustible liquids BGE 4-6 RAN 97-031

Calvert Cliffs Nuclea Power Plant Internal Fire Analysis Individial Plant Examination External Events It also requires that debris, scrap, rags, oil spills or other waste combustibles resulting from the work activity are removed either after completion of the activity or at the end of the shift, whichever occurs first. 4.2.2.6.2 Controlling Ignition Sources SA-1-100 requires Hot Work Permits for work using flame, heat or spark producing equipment with the exception of permanent welding areas, shop areas and laboratories for work normally performed within those areas. The Hot Work Permit process requires the following precautions:

• The work area will be personally examined ensuring that the floors and surroundings have been swept clean and that combustibles, floors and construction form work (if any) have been wetted down.

                " If the work requires cutting, welding or other spark-producing equipment, all combustibles will be located at least 30 feet to 40 feet from the activity or protected with metal guards, flameproof curtains or covers (not ordinary tarpaulins).

All floor and wall openings within 40 feet of the activity shall be covered tightly or a fire watch will be established for lower elevations. Floor drains shall not be covered. A responsible person shall be assigned to watch for sparks in the area, as well as on floors below. The area shall be roped off or posted. 0 A fire watch shall remain for at least one-half hour after work has stopped. Additional restrictions are identified below for the Control Room, Cable Spreading Rooms, Switchgear Rooms and Data Acquisition System (DAS) Computer Rooms:

• No welding or burning shall be performed above the lowest cable tray in the Cable Spreading Rooms unless the work-controlling documents are reviewed by POSRC and authorized by the Superintendent - Nuclear Operations.
• Alternatives to welding and burning should be explored in all other areas of the Cable Spreading Rooms, Switchgear Rooms and Control Room.

                 " The duration of welding or burning in the Cable Spreading Rooms, Switchgear Rooms and Data Acquisition System (DAS) Computer Rooms should be minimized because the Halon 1301 system will have to be impaired to prevent unwanted discharge. Welding in these areas shall be pre-approved by the Supervisor - Safety and Fire Protection Unit.

SA-1-100 also prohibits the use of open flame or combustion smoke for leak testing of cable penetrations and fire barriers or for the determination of air flow. RAN 97-031 4-7 8GB BGE 4-7 RAN 97-031

Calvert Cliffs Nuclear Power Plant l Fire Anys Individual Plat Examination ExWWnal Events 4.2.2.6.3 Controlling Fire Barrier Penetrations SA- I- 100 requires a Fire System/Fire Barrier Impairment Permit for the impairment of an Appendix R fire area boundaries. It also requires an evaluation of compensatory actions such as continuous or periodic fire watches, testing of fire detection and suppression systems or the installation of a temporary fire barrier. 4.2.3 Plant Walkdown In the course of this study, several walkdowns were conducted to gather the following specific information:

                "     Ignition Source Walkdowns

• Detailed Fire Modeling Walkdowns
• Fire Barrier Walkdowns 4.2.3.1 Ignition Source Walkdowns These walkdowns in conjunction with plant drawings are used to develop compartment layout drawings which show the locations and type of ignition sources, major equipment and fire protection features within each compartment. Fire barriers and propagation paths associated with each compartment are also noted.

The scope of the walkdowns include a total of 222 compartments in the following areas:

                 " Auxiliary Building
                 " Diesel Generator Rooms

• Turbine Building

                 " Intake Structure
                 " Yard Areas Note that the containments and compartments with high radiation are evaluated through the use of drawings and were not physically walkdown.

4.2.3.2 Detailed Fire Modeling Walkdowns A detailed walkdown of each compartment evaluated for detailed fire modeling was performed. The results of these walkdowns are discussed in Section 4.6.2. 4.2.3.3 Fire Barrier Walkdowns Walkdowns for all fire barriers which establish the compartment groupings associated with each initiating event that are subdivisions of an Appendix R Fire Area were performed. This was done to ensure that there is no concentration of combustibles near the barriers and to determine the quality of the barrier and the number of penetrations (doors, ventilation openings, and piping and electrical penetrations) through the barrier. This is further discussed in Sections 4.3.1 and 4.3.3. RAN 97-031 4-8 BGE 4-8 RAN 97-031

Calvert Cliffs Nuclear Power Plant Inttn*al Fire Anlysis Individual Plant Examination ExtaTnal Events 4.3 Fire Growth and Propagation 4.3.1 Identification of Fire Areas to be Analyzed Fire ignition frequencies are calculated for all fire compartments that contain PRA components and/or cables. Adjacent compartments to compartments containing PRA related components or cables are also evaluated to access the adequacy of the barrier to contain a fire from propagating This approach assures that any reduction in the mitigation capacity of the plant is evaluated. The ignition frequency for a total of 243 compartments determined to contain PRA components or cables and nine adjacent compartments are calculated. Some areas, such as the Turbine Building, Containment, Intake Structure, Warehouse Area and Yard are broken down into separate PRA Compartments so that they could be evaluated in a more appropriate manner. A compartment is a well-defined enclosed room, not necessarily with Appendix R fire barriers. One or more compartments are contained within an Appendix R Fire Area. A Fire Area is defined as an area with Appendix R barriers. See Table 4.3. 1. A screening and binning process is used to evaluated the fire risk associated with these compartments. Compartments with no PRA components or cables, or low functional impact are screened. However, these compartments are still assessed as ignition sources in the cross-zone propagation described in Section 4.3.3. Compartments with low fire ignition frequency are also screened. These compartments are also assessed in the cross-zone analysis, but as potential targets not sources. Each compartment which is not screened is assigned to one or more initiating event designators. The initiating events are assigned an appropriate frequency and set of plant impacts. These impacts are used to modify the base CCPRA in order to determine the fire risk impact. The compartments in Table 4.3,1 below which have brackets around the room designator are screened because they have no PRA Components or Cables, a low functional impact or a low fire hazard. RAN 97-031 4-9 BGE 4-9 RAN 97-031

Calvert Cliffs Nuclear Power Plant Inten Fire Analysis Individual Plant Examination Extdernl Events Table 4.3.1 Appendix R Fire Area to CCFPRA Compartment Fire Area General Desciription unit 1 bfnkiutorý CCFPRA Compartments Within the Mmr 1 21 ECCS PumpRoom AUXIOC .A101 2 22 ECCS Pump Roomn AUXIOC A102 3 12 ECCS Pump Room AUXI0E A118 4 1l ECCS Pump Room AUXIOE A]119 5 11 Charging Pump Room AUXIOB A]15A 6 12 Charging Pump Room AUXIOB AI15B 7 13 Charging Pump Room AUXIOB A] 15C 8 22 .ChargingPump Room Low Impact [AI05B] 9 23 Charging Pump Room Low Impact [AI05C] 10 -10'1-15' Hallways & General Areas AUXIOA A100, A103, AI04, [AIOSA), A106, AIOB, [At1101, JAI11 1, At113, [JA1161 11 -15, -10, 5', 27, 45' and 69' General See Table 4.3.1.1 A107, [A109], [Al 12], At114, [Al 171, [A1201, Areas and Miscellaneous Areas A122, A200, A202, A203, A206, A207, [A208], [A209], (A210], [A2111, A212, A213, [A214], A215, A216, A216A, A217, A218, A219, A220, A221, A222, A223, A224, A227, [A308], A309, A310, [A315], A316, A319, A320, [A321], A322, A323, A324, [A325], A326, [A327], [A328], A408, A410, [A412], A413, [A417], [A4181, A419, A424, [A425), A426, A428, A512, A520, A523, A524, A525, A526, A527, [A528], A530, A531, A533, A586, A587, A588, A589, A590, A591, A592, A593, A594, A595, A596, A597, SHFT 12 Unit 2 CCW Pmnp Room AUPX20B A201 13 Unit 2 5' Fan Room AUX20B A204 14 Unit 1 5' Fan Room A225F(x) A225 15 Unit I CCW Pump Room Low Fire Hazard [A2281 16 Unit I Cable Spreading Room & IC A306F(x) A306, CC1C I Chase 16A . Unit I BatteryRooms See Table 4.3. 1.l A301,PA304 16B Hallway outside Unit 1 CSR FCA300 A300 17 Unit 2 Cable Spreading Room & 2C A302F(x) A302, CC2C Chase 17A Unit 2 Battery Rooms See Table 4.3.1.1 A305, A307 17B Hallway Outside Unit 2 CSR FCA300 A303 18 Unit 2 27' Switchgear Room AM3IlF(x) A311 I&A Umt 2 Purge Air Room FIA312 A312 19 Unit 127' Switchgear Room A317F(x) A317 19A Unit I Purge Air Room FIA318 A31. 20 Cable Chase IA Low Fire Hazard [CCIA] 21 CableChase 1B Low Fire Hazard_ [CCIB] 22 Cable Chase 2A Low Fire Hazard (CC2A] 23 Cable Chase 2B Low Fire Hazard [CC2B] 24 Control Room Complex FIICxxFlCxxx [A400], A401, [A402), [A403], A404, A405, FI2Cxx and A406, A415, A431, A432, [A434], [A436], A405Fx fA4371, [A4381, A442, [A4431, A444 25 Unit 2 45' Switchgear Room A407F(x) A407 BGE 4-10 RAN 97-031

Calvert Cliffs Nuclear Power Plant Intenal Fire Amlyi Individual Plant Examinaijon Emnal Evews Table 4.3.1 (Cont'd) Appendix R Fire Area to PRA Compartment IF*r Area Geearal Msci~ptlow -unit 1Inttr CCFACompartmeits With the IAri Area, 26 Unit 2 East Electrical Penetration Low Impact [A409] Room 27 Unit 2 West Electrical Penetration FIA414 A414 Room 28 2B Diesel Generator Room FIA416 A416 29 Unit 2 RWT Room Low Impat [A440] 30 IB Diesel Generator Room & RC See Table 4.3.1.1 A420, A421 Waste Room 31 2A Diesel Generator Room FIA422 A422 32 Unit I West Electrical Penetration FIA423 A423 Room 33 Unit I East Electrical Penetration FlA429 A429 Room 34 Unit 1 45' Switchgear Room A430F(x) A430 35 Unit 2 Horizontal Chase Low Fire Hazard [A5171 36 Unit I Horizontal Chase Low Fire Hazard [A5181 37 Unit 169' Electrical Room A529FI A529 38 Unit 2 69' Electrical Room Low Impact [A5321 39 Unit I Service Water Pump Room A226F(x) A226 40 Unit 2 Service Water Pump Room AUX20B A205 41 69' Misc. Waste Evap Room No PRA Comps [A5361, [A5371 42 Unit 1 AFW Pump Room T603F(x) T603 43 Unit 2 AFW Pump Room F1T605 T605 44 Unit 1 RWT Pump Room FIA439 A439 AB-l Auxiliary Building Stairtower Low Fire Hazard _AB-I] AB-2 Auxiliary Building Stairtower F__AB2 AB-2 AB-3 Auxiliary Building Stairtower Low Fire Hazard [AB-31 AB-4 Auxiliary Building Stairtower Low Fire Hazard [AB-41 AB-5 Auxiliary Building Stairtower Low Fire Hazard lAB-51 AB-E Auxiliary Building Elevator Shaft Low Fire Hazard lAB-E] IS Intake Structure INTKF(x) IS CNTMT Unit 1 and Unit 2 Containment See Section 4.3.1.5 C121, C123, C229, C230 Buildings Yard Outside yard area and buildings See Table 4.3.1.1 Transformers, Fire Pump House, Well Water Pump House, Tanks, Switchyard Area, Voltage Regulators, IA & OC Diesel Generator Buildings, 13KV Switchgear Houses TB Unit I and Unit 2 Turbine Building TB(x) Turbine Building, Water Treatment, Warehouse, ___ I_ I I[A5591 RAN 97-031 4-11 BGE 4-11 RAN 97-031

Calvert Ctiff Nuclear Power Plant [ntenal Firs Anaysis Individual Pldt Examintion Extemal Evenu When calculating ignition frequencies for the fire propagation analysis it is appropriate to exclude certain plant rooms on the basis that they would not be the source of a fire with sufficient intensity to result in the damage of other plant areas. The rooms listed in Sections 4.3.1.2, 4.3.1.3 and 4.3.1.4 are screened due to absence of PRA components or cables, low functional impact and insufficient fire intensity, respectively. No additional evaluation is performed for these rooms. The Containment Building is also screened due to its low fire hazard. See Section 4.3.1.5. 4.3.1.1 Subdivided Fire Areas Some Appendix R Areas have been divided into compartments or compartment groupings and are represented by two or more initiating events compartments. This subdivding enables more realistic fire modeling. Each common barrier between initiating event groupings is analyzed for fire spread from either direction. The description of the barrier effectiveness assessment is in Section 4.3.3. The following Fire Areas have multiple initiating events: Table 4.3.1.1 Subdivided Fire Areas Fire Area PRA Initiator PRA Compartment II AUXIOD A107, A114 AUX10E A122 (Also includes Al 18 (Area 3) andAl19 (Area 4) AUX20A A200, A202, A203, A207, A212, A213, A215, A216, A216A, A217, A218, A219, A220, A222, A223, A224, SHFT FCA206 A206, A3 10 FCA221 A221, A326 FIA309 A309 FCA319 A319, A320, A322, A323, A324 A419Fx A408, A4!0, A413, A419, A424, A426, A428 FCA227 (Note 1) A227. A316 AS12F(x), A524F(x) AS 12, A520, A524, A525 FCA523 A523, A526, A527, A530, A531, A533, A586, A587, A588, A589, A590, A591, A592, A593, A594. A595, A596, A597 16A FLA301 A301 FLA304 A304 17A F1A305 A305 FIA307 A307 30 FIA420 A420 FIA421 A421 Yard F1AEDG Emergency Diesel Generator IA Building FOCEDO Emergency Diesel Generator OC Building and Aux Building Roof FFPPHS Fire Pump House FCYRDI thru 6 Combinations of Transformers U-25000-1 1, U-25000-12, U-22000-21, U-22000-22, U-4000-11, U-4000-12, U-4000-13, U-4000-21 FCYRDA Unit I 13KV Transformer P-13000-1, Bus 11/12, and Switchgear Voltage Regulators 1111102 and IH1103; Transformers U-4000-11 and U-4000-12, FCYRDB Unit 2 13KV Transformer P-1 3000-2, Bus 21/22, and Switchgear, Voltage Regulators 21H2102 and 2112103; Transformers U-4000-21 and U-4000-22 FCYRDC Voltage Regulator IH11101 and Transformer U4000-13 FCYRDD Voltage Regulator 2H21.01 and Transformer U4000-23; Well Water Pump House Note 1: Although.designated as a Group Compartment Initiator, this compartment is fire modeled and is included in Attachment C. BGE 4-12 RAN 97-031

Calvert CIlffs Nuclear Power Plot Internal Fire Analysis Individual Plant Examination EDternal Events 4.3.1.2 Screened Rooms - No PRA Components The compartments listed below are screened due to the absence of PRA components and due to the absence of cables having the potential to cause failure of a PRA function. No additional fire propagation evaluation within the compartment is performed for these compartments. However, these compartments are still assessed as ignition sources in the cross-zone propagation described in Section 4.3.3. Table 4.3.1.2 Screened Rooms - No PRA Components or Cables Room Fire Area Room Descriptlonw.,.:.. A112 11 12 Reactor Coolant Waste Receiver Tank Room A116 10 North Hallway by Personnel Elevator A208 II Waste Gas Surge Tank Room A209 II Deoon Room A210 II RCP Seal Decon Room A325 II Personnel Elevator Area A327 11 Spent Fuel Pool Cooling Denineralizcr Room A328 II Spent Fuel Pool Cooling Fitter Room A400 24 Control Room Vestibule A402 24 Toilet - Control Room A403 24 Janitor Storage Adj To Control Room Toilet A412 II Cask Washdown Pit A417 II Cask Loading Area A425 11 Personnel Elevator Area - 45' A434 24 Turbine Building Passage To AB-I & TSC A436 24 Technical Support Center A437 24 Technical Support Annex A438 24 Shift Supervisors Office A443 24 Reserve Battery Room Passage Way A528 1I Personnel Elevator Area A536 41 Miscellaneous Waste Evaporator Control Panel Room A537 41 Miscellaneous Waste Evaporator Room 4.3.1.3 Screened Rooms - Low Functional Impact The compartments identified in Table 4.3.1.3 are screened due to low functional impact. The functions impacted by these compartments are individually examined and qualitatively screened based on the knowledge of risk resulting from similar impacts previously evaluated. Note that the equipment and cables included in the base CCPRA are identified for these compartments and the loss of this equipment and cables are evaluated to make this determination. It is estimated that the risk resulting from fire in these compartments is well below 1E-7. Examples of the type of functions impacted by the screened rooms are listed below. The analyses of these screened compartments did not show any indication that a reactor or turbine trip would result. However, all cables which could cause a plant trip through various secondary and supporting systems have not been identified. As a result, fire in compartments containing PRA identified equipment are assumed to result in a trip. BGE 4-13 RAN 97-031

Calvet Cliffs Nuclear Power Plant Intrnial Fire Atnyaly Individu Pland Examination External Evet

               "     Cable faults whose sole impact is to challenge the associated load breaker or breakers of a single bus. If the associated load breaker opens on demand, then the supplying bus is protected. If the load breaker fails to open then the bus is lost.

Since an independent breaker failure is required, the failure probability of the associated bus is small. Therefore, the resulting plant risk is small.

               " Failures of standby equipment; such as, the loss of an EDG and/or Unit 2 safety-related air compressors. In this case both normal 4KV power and normal instrument air are not impacted.

Table 4.3.1.3 Screened - Low Functional Impact Rom. ' Fire Area Dcrtptio " Al05A 10 21 Charging Pump Room AI05B 8 22 Charging Pump Room AI05C 9 23 Charging Pump Room A109 11 12 Reactor Coolant Waste Monitor Tank Room Al 10 10 RCW Pump Area Nrth/South Hall Al 11 10 Cryogenics - Waste Processing Control Room A] 17 I1 Personnel Elevator Equipment Room A120 II Unit 2 Recirculation Pipe Tunnel A211 II Unit 2 West Piping Penetration Room A214 II Unit 2 Volume Control Tank Room A321 I1 Unit 2 West Piping Penetration Room A409 26 Unit 2 East Electrical Penetration Room A418 1 Solid Waste Processing Area A440 29 Unit 2 RWT Room A532 38 Unit 2 69' Electrical Room A559 ACA* Plant Computer Room

• The Access Control Area (ACA) is part of the Turbine Building Fire Area.

4.3.1.4 Screened Rooms - Low Fire Ignition Frequency The following compartments are screened due to low fire ignition frequency. The detailed results of the fire hazard evaluation for each compartment below is addressed in Section 4.6.2. The evaluation of each compartment is included as an attachment to Section 4. Note that these compartments are assessed in the cross-zone analysis as potential targets but not as sources. See Section 4.3.3. BGE 4-14 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Aiaymsi Individual Plant Examination External Events Table 4.3.1.4 Screened Rooms - Low Fire Ignition Frequency Room Fire Area Description A228 15 Unit I CCW Pump Room A308 II North/South Passage A315 II Unit I Main Steam Piping Penetration Room CCIC 20 Cable Chase IC CCIC 21 Cable Chase IC AB-1 AB-l AWxliary Building Stairtower A1-3 AB-3 Auxiliary Building Stairtower AB-4 AB-4 Auxiliary Building Stairtower AB-5 AB-5 Auxiliary Building Stairtower ABE AB-E Auxiliary Building Elevator Shaft 4.3.1.5 Screened Rooms - Containment The FIVE methodology does not include ignition source information for the containment location because of the small number of fire events and the conclusion, by previous fire PRAs, that such fires were not risk significant. FIVE indicates that risk significant fires are unlikely because: I. A hot gas layer is unlikely to form in most areas of containment which can damage cables.

2. A large percentage of past fires were reactor coolant pump (RCP) fires which are unlikely to occur in the future due to oil collection systemn design improvements.

However, FIVE cautions that plant-unique features may not provide the equivalent protection against fire found in the examined plants. FIVE recommends a qualitative assessment to determine if a further, more detailed, analysis of the containment is needed. FIVE cites two issues that should prompt a detailed analysis:

1. Plant experience indicating that containment fires have occurred on a recurring basis.

2. The potential for redundant trains of critical equipment within containment to be exposed to the same fire plume or be in a confined space subject to damage by a hot gas layer.

There have been no recorded fires in the Unit I Containment during plant operation. Electrical penetrations enter into the Calvert Cliffs containment on opposite (east and west) sides. Inside the containment, the cable routings, and their associated fire load concentrations, remain segregated in an cast-west division as the cables travel to their end location. RAN 97-031 4-15 BGE 4-15 RAN 97-031

Calvert Cliffs Nuclmr Power Plant Irnal Fire Analysis Individual Plant Examination External Events Although the containment is a single Appendix R fire area, the Interactive Cable Analysis (ICA, see Section 4.2.2.2) subdivides the containment into three zones. East, west, and a twenty foot wide buffer area centered on the containment north-south center-line. The buffer zone has little fire loading. (Four cable east-west cable trays traverse the buffer zone. These trays have covers to prevent flame spread across the east west zones.) The principle fire loads in each zone, east and west, are cables and reactor coolant pump (RCP) lube oil. The cables themselves are not ignition sources and do not propagate fire. The RCP lube oil system is encapsulated and uses an oil collection system to divert and control any leakage. In addition, the chosen oil has characteristics that minimize fire hazard. So, the concentration of loading is such that any credible fire and resulting plume is limited to the east or west zone. The ICA analyzed all containment components necessary to place the reactor in cold shutdown based on a safety function (for example, reactivity control). The analysis shows that cold shutdown is possible using equipment in either zone, east or west, even with the added loss of the north-south buffer. A separate analysis, ES 199602166, reviewed instrument tubing interactions. In summary: I. There is no plant specific history of, or known susceptibility to fires inside containment.

2. The separation of redundant critical equipment and cable trains is such that no single fire (plume or hot gas layer) will damage both trains. When necessary, shielding or other measures prevent flame spread across the redundant trains.

BGE 4-16 RAN 97-031

Calvert CUMlNuclear Power Plant Internal Yfe Analysis Individual Plant Examinaion External Events Figure 4.3 - 1 Auxiliary Building -10 & -15' Level Charging Pump Room At15A, B, C (AUXIOB) RAN 97-031 4-17 BGE 4-17 RAN 97-031

Calvert Cliffs Nuclear Powe Plant Inenal Fire Anaysis Individual Plant Examination External Events Figure 4.3 - 2 Auxiliary Building 5' Level A227 (FCA227) (IncIlude A316 frtm lIe 27' Level) A211 Screened (Includes A321 from lthe 27' Level) A206 (FCA206) (Includes A310 from the 27 Level) RAN 97-031 4-18 BGE 4-18 RAN 97-031!

Calvedt Clif Nuclear Power Plant Interna Fire Analysis Individual Plant Examination External Events Figure 4.3 - 3 Auxiliary Building 27' Level A316 (FCA227) (Includes A227 from the 3' Level) (FA318) IA31R) (Includes A221 from the 5" Level). n Unit I SWGR (A3I7Fx A317 Non-App R Barth See Section 4.3.3

                                                                                            /A301 Battery RoomB (FIA3OI)

A304 (FLA304) Al IVA (AL& I( No-AMp R Barrier See Section 4.3.3 urbine A31 miding

                                                                                                " A300/A303 AIO1*A                                                            (FIC300)

(A".11(

                                                                                                " Battery Roons A305 (FIA305)

A307 (FIA307) (Intludes A21 1 from the 5' Level) A310 (FCA206) (Includes A206 from the S' Level) RAN 97-031 4-19 BGE BGE 4-19 RAN 97-031

Calved Cliffs Nuctew Powr Plait laiermi Fire Analysis Individual Plant Exminaion Eternal Events Figure 4.3- 4 Auxiliary Building 45' Level A429 (A429Fx) Non-App R Barrier See Section 4.3.3 Turbine Building Screened A409 Screeed RAN 97-031 4-20 BGE 4-20 RAN 97-031

Calvet Clif Nuclear Power Plant Internal Fire Analysis Individual Plant Examination Extemal Event RAN 97-031 4-21 BGE 4-21 RAN 97-031

Cahvn Cliffs Nulear Power Plant Internal Fie Analysis Individual Plant Examination Extwnal Evet 4.3.2 Quantification of Fire Ignition Frequencies The process of determining fire frequencies for each of the fire compartments involved the following steps:

1. Identify all potential fire sources/components in a selected location, i.e., the total number of each components type in the location.

2. Select generic fire frequencies from the EPRI Fire Events Database applicable to the fire sources/components in the selecte location. See Table 4.3.2

3. Determine the location weighting factor for the Area/Compartment. This weighting factor is used to translate generic fire frequencies for a location to specific, single-unit fire frequencies. The weighting factors are designed to account for the relative amount of ignition sources in CCNPP compared to the "average' plant. The following location weighting factors are used:

Table 4.3.2a Fire Ignition Room Weighting Factors Plant Location Weithtinf Factors CCNPP Auxiliary Building number of units / number of auxiliary buildings 2/I 2 Diesel Generator Room number of diesels / number of diesel rooms per site 5/7 0.714 Switchgear Room number of units / number of switchgear rooms 2/13 = 0.154 Battery Room number of units / number of battery rooms 2/9 0.22 Control Room number of units / number of control rooms 2/1 2 Cable Spreading Room number of units / number of cable spreading rooms 2/2 1 Intake Structure number of units / number of intake structures 2/1 2 Turbine Building number of units / number of turbine buildings 2/1 2 Radwaste Area number of units / number of radwaste areas 2/1 2 Transformer Yard number of units / number of switchyards 2/1 2 Plant-Wide Components number of units 2

4. Determine source weighing factors, i.e., the number of components in the selected location versus the total number of components in similar types of locations. The following codes contained in Table 4.3.2 are used to establish the weighting factors:

A. No ignition source weighting factor is necessary. B. Obtain the ignition source weighting factor by dividing the number of ignition sources in the fire compartment by the number in the selected location. C. Obtain the ignition source weighting factor by calculating the inverse of the number of compartments in the locations. Exclude any areas contained in locations other than in this table. BGE 4-22 RAN 97-031

Calvert CliA Nuclear Power Plant Internal Fire Analysai Individual Plant Examination External Eventa D. Obtain the ignition source weighting factor by summing the factors for ignition sources which are allowed in the zone and divided by the number of zones in the locations in this table. For example, if cigarette smoking is prohibited do not include cigarette smoking factor in the calculation. The factors are: Cigarette Smoking 2 (Not applicable at CCNPP) Extension Cord 4 Heater 3 Candle 1 (Not applicable at CCNPP) Overheating 2 Hot pipe 1 Note that candles are not allowed in accordance with SA-1-100 (See Section 4.2.2.6) and cigarette smoking is prohibited throughout the analyzed areas. E. Obtain the ignition source weighting factor by dividing the weight (or BTUs) of cable insulation in area by the total weight (or BTUs) of cable insulation in Appendix R fire areas, not including fire areas in either the Radwaste area or the containment. Cable insulation weights (or BTUs) are provided in Appendix R combustible loading. F. Obtain the ignition source weighting factor by dividing the number of ignition sources in the fire area by the total number in all the locations in this table. G. Obtain the ignition source weighting factor by dividing the number of ignition sources in the fire area by the total number in all plant locations, including locations that were not specified in this table.

5. Calculate fire ignition frequency for each source and location.

6. The fire compartment frequency for each ignition source is calculated by multiplying:

• The generic frequency for an ignition source present in the compartment
• The weighting factor for the location determined in Step 3
• The weighting factor for that ignition source as calculated in Step 4 The calculation is repeated for each ignition source and the results are summed to obtained the total fire frequency for that fire compartment.

RAN 97-031 4-23 BGE 4-23 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Ardalyis Individual Plara Examination External Evus Table 4.3.2b Fire Ignition Sources

• g ito So rc . .... i Plant Location Fire Ignition Source. Weighting Factor Number of Fires. Fire Frequency Auxiliary Building Electrical cabinets B 15 1.9E-2 Pumps B 15 1.9E-2 Diesel Generator Diesel generators A 65 2.6E-2 Room Electrical cabinets A 6 2.4E-3 SwitchRear Room Electrical cabinets A 19 1.5E-2 Battery Room Batteries A 4 3.2E-3 Control Room Electrical cabinets A 12 9.5E-3 Cable Spreading Room Electrical cabinets A 4 3.2E-3 Intake Structure Electrical cabinets A 3 2.4B-3 Fire Pumps A 5 4.OE-3 Other Pumps A 4 3.2E-3 Turbine Building TiG Exciter B 5 4.OE-3 T/G Oil B 17 1.3E-2 T/G Hydrogen B 7 5.5E-3 Electrical cabinets B 16 1.3E-2 Other pumps B 8 6.3E-3 Main feedwater pumps A 10 4.oE-3 Boiler B 2 1.6E-3 Radwaste Area Miscellaneous components A II 8.7E-3 Transformer Yard Yard transformers A 5 4.OE-3 (propagating to Turbine Building)

Yard transformers (LOOP) A 2 1.6E-3 Yard transformers (Others) F 19 1.5E-2 Plant-Wide Components Fire protection panels F 3 2.4E-3 CEA-MG sets F 7 5.5E-3 Non-qualified cable run E 8 6.3E-3 Junction box/splice in non- E 2 1.6E,-3 qualified cable Junction box in qualified E 2 1.6E-3 cable Transformers (Dry) F 10 7.9E-3 Transformers (Wet) O F n/a 1.9E-4 Battery chargers F 5 4.OE-3 H2 Recombiner G 41 8.6E-2 Hydrogen Tanks G 4 3.2E-3 Misc. Hydrogen Fires C 4 3.2E-3 Air compressors F 6 4.7E-3 Ventilation Subsystems F 12 9.5E-3 Elevator motors F 8 6.3E-3 Dryers F II 8.7E-3 Transients D 1'3 1.3E-3 Cable fire caused by C 4 5.1E-3 welding Transient fires caused by C 24 3.IE-2 welding and cutting Note 1: Based on an EPRI study on the economic risk for electrical equipment containing PCBs. BGE 4 -24 RAN 97-031

Calvert Cliffs Nuclear Power Plant Intenl Fire Analysis Individmua Pan EPamination Exrn Events 4.3.3 Treatment of Cross-Zone Fire Spread This section addresses the evaluation of a fire starting in one compartment and spreading to other compartments. This evaluation includes an assessment of both fire suppression and barrier effectiveness. The frequency of cross-zone propagation is determined by using the following equation: Cross-Zone Propagation Frequency = I

• N
• B where I = Barrier Challenge Frequency N = Suppression Failure Rate B = Barrier Failure Probability The zones in this cross-zone evaluation are represented by initiating events. Each PRA fire initiating event represents a fire ignition frequency for a compartment, a set of compartments or a fire scenario within a compartment. For the cross-zone evaluation, the barriers between the initiating event compartment ot compartment grouping is assessed. Barriers within an initiating event group are assumed to be ineffective.

For initiating events which represent a fire scenario, the set of fire scenarios for a compartment is used to represent that compartment. For example, Initiating Events A419F1, A419F2 ... A419F7 are represented by the designator A419Fx. Only severe fires are considered for the determination of the barrier challenge frequency. If the compartment or compartment group represented by the initiating event is fired modeled, then only the fire scenarios which could result in the loss of the entire compartment are used as the basis for the barrier challenge frequency. If no compartment lost fire scenarios are identified, then the barrier challenge frequency is considered to be zero. For non-fire modeled compartments, the compartment ignition frequency is multiplied by a severity factor. See Section 4.3.3.2. For non-fire modeled compartment groups, the individual compartment fire frequencies are added and then multiplied by a severity factor. The suppression failure rate is determined for each compartment of origin. The suppression failure rate of the compartment which the fire is spreading to is assumed to be unavailable. Although conservative, this assumption avoids the evaluation of common failure modes between the compartments' fire suppression systems. All barriers, both Appendix R and non-Appendix R, between the zones represented by the initiating events were determined and assessed. The failure assessment considers the number of doors, dampers and penetration seals. All credited non-Appendix R barriers are being added to a plant inspection and/or control program. Compartments are screened from further evaluation if the propagation likelihood is <1.OE-07. The following sections provide additional detail as to the approach used for the cross-zone analysis, The quantification of fire-induced core damage frequency is obtained by propagating fire-induced failures through a modified version of the CCNPP PRA as described in Section 4.6. The results of the Barrier Analysis are addressed in Section 4.6.6. RAN 97-031 4-25 BGE 4-25 RAN 97-031

Calvat Clif Nuclear Power Plant Internal Fire Analdis Individual Plant Exarmination External Events 4.3.3.1 Barrier Inspection Evaluation Ths section addresses the ispecdion and configuration control of the comparzuent boundaries. Barriers without an adequate inspection and/or configuration control program are assumed to be ineffmctive. Barriers are considered to have an adequate program if they meet oe of the following criteria.

     "     Barriers inecd -o meet AppMdix R requements.

STP-F-591-1, Inspection of Fire Doors, Watertight Doors, and Dampers in Fire Rated Barriers and STP-F-592-1, Penetration Fire Barrier Inspection, are currently perfoiried on a periodicity of 18 months for aU Appedix R barriers.

• Barriers walked down and determined to be HELB barrie.

HELB and other adequate barriers are being added to an inspection program. Table 4.3.3a provides a list of the non-Appendix R barriers credited. These barriers are analyzed as having the same failure probabilities as those stated for Appendix R barriers. See Section 7, Improvement 5.

     "     Barriers with no pletirations Barriers walked down and determined to be constructed of a fire resistant material, such as concrete, with no penetrations, doors or vnilation openings. These barriers are being added to a configuration control program. Table 4.3.3b provides a list of these barriers. Also see Section 7, Improvement 5.

Table 4.3.3a Barriers in an Inspection Program Fire PRA Initiator to PRA Barrier ID From Room Description To Room Description Area Initiator II AUX20AFIA211 <<2BARR-203i2I>>>> U2 5' PIPING AREA U2 WEST PIPING PEN RM AUX2OA/FIA206 <<2BARR-203/206>> U2 5 PIPING AREA U2 EAST PIPING PEN RM AUX2OA/FIA221 <<IBARR-221/224>> Ul WEST PIPING PEN RM UI 5' PIPING AREA FCA319/FIA309 <<OBARR.303/309>> CORRIDOR U2 MSIV RM FCA319/FIA315 <<OBARR-308/315>> CORRIDOR U1 MSIV RM FIA221/A419F(x) <<IBARR-3241419>> UI LTDWN HT XCHOR RM CASK LDG & TRUCK BAY FCA3 19F(xYA419F(x) <<2BARR-322/49>> U2 LTDWN HT XCHGR RM CASK LDG & TRUCK BAY FLA221/A419F(x) <<IBARR-326/419>> Ul WEST PIPING PEN RM CASK LDG & TRUCK BAY FCA5 L2/A419F(x) <<1BARR-423/524>> UI 45 PIPING AREA Ul MN PLANT EXH EQ RM FCAS12/A419FEx) <> UI 45' PIPING AREA U1 CNTMT ACCESS AREA TB TBMFWI/TBMFW2 <<OBARR-601/606>> Ul 12' Turbine Building U2 12' Turbine Building TBMFWI/TBMFW2 <<OBARR-607/608>> Ut 12'TB Heater Bay U2 12' TB Heater Bay TBMFWI/TBMFW2 <<1BARR-L27A/L27B> Ul 27' Turbine Building U2 27' Turbine Build YARD FIAEDG/FOCEDO <<<0BARR.t1G004/SB004>> IA DG TRENCH SO0 CABLE TRAY AREA FIAEDG/FOCEDG <<OBARR-DG203iSB204>> IA DG FAN ROOM SBO HVAC EQUIP AREA FPAEDG*FOCEDG <<OBARR-D0204/SB204>> , A DO MAINT SHOP SBO HYAC EQUIP AREA BGE 4-26 RAN 97-031

Calvert Cliffs Nuclear Power Plant Intertal Fire Analysis Individual Plant Examination External Events Table 4.3.3b Barriers in a Control Program Fire NUA Inkafth to PRA BarrkrII) Fvmn Romn Deacription To Room Deacdploa Area lutfator ,....  : . tI AU'XIODA*UX2OA << IBARR-1I 2/216>> 12 RC Waste Rec Tank RM UI RCM/U Pum RM

                                         <<IBARR.I 14/221>>         II RC Waste Rec Tank RM       U) West Pipins PEN RM I1         AUX2OAiFCA319                <<OBARR-200/222>>         East/West Hallway              Hot EQ Shop
                                         <<2BARR-216A/323>>        U2 RC M/U Pump RM              Valley Alley 11          AUX20A/SHFT                  <<OBARR.212/SHFT>>        North/Soueh Passageway by VCT  Equipmut Shaft
                                         <<2BARR-203/SHF>>>>        U2 Piping Area                 Equipment Shaft I1         AUXIOD/FCA319F               <<iBARR-1 14/323>>         I1 RC Waste Rec Tank RM       Valve Alley
                                         <<2BARR-107/323>>          II RC Waste Mon Tank RM       Valve Alley
                                         <<2BARR-109/323>>           12 RC Waste Mon Tank RM      Valve Alley II          AUX20A/A308                  <<OBARR-200/308>>          East/West Hallway             Conidor
                                         <<IBARR-202/308>>         Norlh/South Passageway by MCC  Conridor
                                         <<2BARR-224/308>>          Ul Piping Area                Corridor
                                         <<2BARR-203/308>>          U2 Piping Area                Corridor II          AUX20A/FCA319F               <<OBARR-200/319>>          East/West Hallway             Corridor
                                         <<OBARR-200/320>>          East/West Hallway             SFP Cooling Pump RM
                                         <<OBARR-200/323>>          East/West Hallway             Valve Alley
                                         <<OBARR-200/327>>          East/Wedt Hallway             SFP Cooling DEMIN
                                         <<OBARR-200/328>>          East/West Hallway             SFP Cooling FILTER
                                         <<0BARR-212/319>>          North/South Passageway by VCT Corridor
                                         <<2BARR-214/322>>          U2 VCT RM                     U2 Letdown Heat EX
                                         <<IBARR-217/323>>          Ul BAST RM                    Valve Alley
                                         <<IBARR-218/324>>          UI VCT RM                     Ul Letdown Heat EX
                                         <<IBARR-218/323>>          UI VCT RM                     Valve Alley
                                         <<IBARR-219/325>>          Vestibule S' Elevation        Vestibule 27' Elevation
                                         <<1BARR-220/3 19>>          Ul Degasiier Pump RM         Corridor
                                         <<lBARR-220/324>>           U1 Degasifier Pump RM        UI Letdown Heat EX
                                         <<2BARR-2091320>>            DECON RM                     SFP Cooling Pump RM
                                         <<2BARR-210/320>>           Hot Machine Shop             SFP Cooling Pump 1W
                                         <<2BARR-213/319>>           U2 Degasifier Pump RM        Corridor
                                          <<2BARR-214/323>>          U2 VCT RM                    Valve Alley
                                         <<2BARR-215/323>>           U2 BAST RM                    Valve Alley I          FCA319F/A321                <<2BARR-32!/322>>           U2 W Piping PEN RM           U2 Letdown Heat Exchanner RM 11          AUXIODIFCA319               <<1BARR.2/323>>             12 RC Was* Rec Tank RM       Valve Alley 16A         FIA301/FIA304                <<IBARR-301/304>           Ut Batter RM 11              UI BatteryRM 12 17A         FIA305/FIA307                <<IBARR-30S/307>>          U2 Battery RM 21             U2 Battery RM 22 11          FCA319/FCA419F(x)            <<OBARR-319/413>>          Corridor                     U2 NSSS Sample RM
                                          <<0BARR.319/419>>          Corridor                     CASK Loading & Truck Bay
                                          <<0BARR-319/424>>          Corridor                      U1 NSSS Sample RM 11          AUX10D/A418                  <<2BARR-107/419>>          1 RC Waste Mon Tank RM        Solid Waste Proc
                                          <<2BARR. 109/418>>         12 RC Waste Mon Tank RM       Solid Waste Proc 11          FCA319/A412                  <<OBARR-320/412>>          SFP CoolinpPump RM            Cask Washdown Pit 11          FCA3191FCA419F(x)            <<OBARR-320/426>>          SFP Cooling Pump RM           Passageway
                                          <<IBARR.3241424>>          Ui Letdown Heat Exch RM       Ul NSSS Sample RM
 -11         FIA221/FCA419F(x)            <IBARR.326/424>>           UlI Wes Piping PEN RM         Ul NSSS Sample RM 11          FCA319/FCA419F(x)            <<IBARR-327/426>>          SFP Cooling DEMIN             Passageway
                                          <<IBARR-328/426>>          SFP Cooling FILTER            PaOsageway 11          FIA420/FIA421                <<lBARR-420/421>           RC Coolant Waste Evap Tank    IB ED. RM 1A/OC       FIAEDW/FOCEDO                <<0BARR-DGI02/SBl03>>       IA EDO RM                    SBO Switchgear RM
                                          <<OBARR-D0I02/SlB04>>       IA EDG RM                    SBO Cornrol RM II          FCA419F(xYFCA512F(x)         <<0BARR-410/525>>          Passageway                    UI CNMT ACCESS AREA II          FCA419F(xYFCA523             <<OBARR.410/523>>          Passageway                    North/South Passage
                                          <<OBARR-410/527>>          Passageway                    U2 CNMT Access Area
                                          <<OBARR-410/530>>          Passageway                    CASK Handling Area
                                          <<OBARR-426/530>>          Passageway                    CASK Handling Area
                                          <<OBARR-419/531>>           Cask Loading & Truck Bay     Waste Proc Area FAN
                                           <<0BARR-419/533>>          Cask Loading & Truck Bay     New Fuel Storage Area
                                           < BARR-520/S23>>           SFP Area HVAC Equip RM       North/South Passage
                                           <<IBARR-520/591>>          SFP Area HVAC Equip RIM      Anti-C Dress Out BGE                                                            4-27                                           RAN 97-031

Calver Cliffs NudlmPoer Plant Internal Fire Analysis Individual Plant Examination External Evona 4.3.3.2 Barrier Challenge Frequency Determination (I) For non-fire modeled compartments, the compartnent ignition frequency is multiplied by a severity factor which is based on the EPRI Fire PRA Implementation Guide. The Implementation Guide uses a severity factor to estimate the likelihood that a fire damages other components than that of the ignition soure component. This same factor is used in this analysis to estimant the lielihood tha a fire will be severe enough to dcallenge a barrier. With the exception of diesel fuel oil component% a Fire Severity Factor of 0.20 is used to bound the severity impact of all plant compartments. For conpartmnits containing diesel fuel, such as the Emergency Diesel Generator Rooms, a Severity Factor of 0.40 is used in the calculation of dth barrier challenge fiequency. For those comparnents that have been modeld, the analyzed ignition frequency of fire scenari which result in the lost of the compartment is used as the barrier challenge frequency. In those instances where no lost of compartment fire swaios are identified, a frequency of zero is used. Some cwopartments are fire modeled for the sole purpose of identifying whether a severe fire which would challenge a barrier is possible. In addition to the fire modeling techniques described in Section 4.3.4, this fire modeling considers: I. Ignition sources to determine if the compartment has ignition sources which could challenge a barrier.

2. Combustion concentration to determine if the compartment configuration is such that a fire could occur in a location that would challenge the barrier.

3. Fire Brigade response to determine if timely response to manually suppress the fire prior to barrier challenge is likely, given failure of automatic suppression, The following compartments listed in Table 4.3.3c are modeled for barrier assessment and are determined to have a low fire hazard likelihood, such that a fire is unlikely to propagate into adjacent areas. These non-Appendix R barriers are assumed to not be challenged by a fire in the compartment. Regardless of a barrier failure probability for these compartment, any fire would not be sufficiently severe so as to propagate to an adjacent compartment. For these compartments the barrier challenge firquency is zero.

RAN 97-031 4-28 BGE 4-28 RAN 97-031

Calval Cliffs Nuclear Pow- Plant Infmnal Frue Analys Individual Plant Examination ExtWral Evxi Table 4.3.3c Rooms Fire Modeled for Barrier Effectiveness Flnr A"ei PRA i.r. ... ' .UNIua.Me:mw it AUXIOD*I) A107, A109 II AUXIOD(2) A112, A] 14

          !             AUX20A                A200, A202, A203,  A207, A212, A213, A215, A216, A216A, A217, A219, A.220, A222, A223, A224, SHIFT II            FLA206                A206, A310 I             FL4A221               A221, P.326 I1              IA227               A227, A316 SI          FIA309                A309 11            FCA319                A319, A320, A322,  A323, A324, A325, A327, A328 1I            FIA418                A418 11            FCA523                A.523, A526. A527, A530, A531, A533, A586, A587, A.588, A589, A590, A591, A5.94, A595. A596 16A           FIA301                A301 16A           F1A304                A304 17A            FLA305               A305 17A            FLA307               A307 30            FIA420                A420 41             FIA536               A536, A537 YARD           FIAEDG               DGIA I FOCEDG                DGOC. ARF Turbine        TBALLB               Turbine 4.3.3.3          Compartment Barrier Failure Probability Determination Failure rates are calculated for barriers containing penetrations by using the probabilities contained in the EPRI PRA Implemnentation Guide for fire dampers, fire rated hatches and electrical and mechanical penetrations, including fire rated cable tray and conduit seals, and piping and sleeve seals. Only barriers that are in an inspection and/or control program are evaluated. All other barriers are assumed to be ineffective.

Barrier Attribute Failure Probability Doors 7.4E-3 Dampers 2.7E-3 Walls 1.2E-3 Penetration Seals 1.2E-3 The equation below is utilized to probabilistically calculate the contribution of penetrations to the barrier failure rate. Bve.iar Filu* = I - [(1 - Bw.,j) (1 - BID) M o (1 - Bonpc) # Damper(j - Bpeactatiom) # Pcnatiom] RAN 97-031 4-29 BGE 4-29 RAN 97-031

Calveritliffs Nucr Po*ve* Flwt hIaM Fre Aaydsl Iivid Plant Examination Exmal Eveats 4.3.3.4 Automatic Suppression Systems Failure Probability Determination (N). The actuation of a properly designed and installed automatic fire suppression system is assumed to effectively mitigate a potential challenge to a fire barrier. FIVE provides nominal unavailabilities for various automatic fire suppression system types that are used in CCFPRA. See Section 4.5 for these values. The suppression failure rate is determined for each compartment of origin. The suppression failure rate of the compartment which the fire is spreading to is assumed to be unavailable. Although conservative, this assumption avoids the evaluation of common failure modes between the compartments' fire suppression systems. Halm suppression requires effective isolation, which would also need to be evaluatedL Howvver Halon was not credited in the propagation analysis. All the plant compartments that have a halon suppression systems are fire modeled and nmoe were found to have scenaruo which result in the loss of the compartlmet Therefore the barrier challenge fiequency for these compartments is set to zero. 4.3.4 Detailed Fire Modeling Compartments which exhibited unacceptable conditional CDFs when fully burned or those which have a large system functional loss potential are evaluated to determine targets and fire sources. This evaluation results in the development of credible fire scenarios. The FIVE methodology was used to estimate the environmental conditions that could develop at a target as a result of a specified exposure fire scenario. Temperature and heat flux are used. If the estimated maximum environmental condition does not exceed the damage threshold of a target, then the target is screened. If the estimated maximum environmental condition is exceeded, then the appropriate functional impact is determined and the impacts of each scenario are coded into the CCFPRA. This approach, consistent with the guidance in the EPRI Fire PRA Implementation Guide (Ref. 4-3), involves the following steps: Step 1: Ignition Source Evaluation Step 2: Detailed Fire Modeling of Fixed Ignition Sources Step 3: Detailed Fire Modeling of Transient Ignition Sources Step 4: Assessment of Fire Suppression Step 5: Assessment of Compartment Fire-Induced Core Damage Frequency Step 6: Refinement of Fire Modeling (as necessary) Each of these steps are discussed in the subsequent sections. Compartment walkdowns are not addressed as a separate step as they are an iterative process, apply to more than one step, and depend upon the configuration and contents of the room. Walkdowns are generally performed for evaluation of ignition sources (i.e., separate fire scenarios); evaluation of spacial considerations for fire damage modeling; and verification of final fire damage modeling assumptions and inputs. Walkdowns are also performed to calculate the compartment fire ignition frequency total and to identify compartment boundaries (e.g., fire doors, fire dampers); however, these issues are used as inputs to the fire damage modeling process. See Section 4.2.3. BGE 4-30 RAN 97-031

Calvert ClifUM Nuclear Power Plant Internal FiUrAnalysi Individual Pant Examination External Events 4.3.4.1 Step 1: Ignition Source Evaluation The first step in the fire damage modeling process is to review (typically via a walkdown), the ignition sources in the compartment to dismiss ignition sources that do not impact the plant and do not propagate. This step also includes identifying ignition source characteristics, such as oil-filled pumps, open top electrical cabinets, and spacial distances to critical targets, for further analysis in the fire damage modeling. Ignition sources that cannot damage other equipment and do not impact equipment modeled in the PRA can be dismissed. Such ignition sources are typically fixed. In some cases, transient sources can be dismissed because they are determined not to be realistically representative of the compartment during power operation. Examples of excluded ignition sources are battery-operated emergency lights, fluorescent light fixtures, and fire protection panels. Given an electrical cabinet fire, the finctions of the cabinet are assumed disabled. However, sealed electrical cabinets and panels are also possible to dismiss from further analysis if they are separated from other cabinets by an air gap and failure of the equipment inside the cabinet does not impact equipment modeled in the PRA. Electrical cabinets which will not impact surrounding equipment given a postulated cabinet fire, but which contain PRA finctions are retained as fire scenarios and are functionally evaluated. Based on guidance in the EPRI Fire PRA Implementation Guide, which references cabinet fire experiments conducted by Sandia National Laboratories, sealed electrical cabinets that are separated from other electrical cabinets by an air gap can be assumed to result in damage only to the cabinet in question and it is assumed that no damage occurs to other cabinets. The size of an "air gap" is not defined in the Fire Implementation Guide. The definition used here is that no metal-to-metal contact exists that would support sufficient heat conduction between cabinets, and is typically considered to be eight millimeters of air. An exception to this empirically-based rule is that the immediately adjacent cabinets do not contain sensitive equipment. "Sensitive equipment" is defined as solid state electronic equipment. The primary targets are typically horizontal cable trays overhead of ignition sources. Targets may also be vertical cable trays or other equipment located radially from an ignition source. During an initial walkdown of a compartment, it is resource efficient to identify the nominal distances from the fire source to the nearest target in either direction, such as two feet to the nearest horizontal cable tray, or three feet radially to the nearest vertical cable tray. If subsequent fire damage modeling, as discussed in Steps 2 and 3, show that the configuration for a particular postulated fire scenario does not result in target damage, distances to additional targets are inconsequential. However, if fire damage modeling results in damage to the nearest targets, drawings (i.e., equipment location drawings, cable tray drawings) and additional walkdowns are used to find distances to additional targets, as necessary. 4.3.4.1.1 Ignition Source Frequencies Through a review of the compartment ignition frequency evaluation (see Section 4.3.2), it is typically straightforward to breakdown the total compartment ignition frequency by individual sources. For example, if the compartment ignition frequency tabulation shows a contribution of 8E-03/yr for electrical cabinets and the room contains 20 electrical cabinets, the ignition frequency is apportioned to the individual cabinet as 8.00E-03/20 = 4.OOE-04/yr. Resolution in the industry data analysis for ignition frequencies does not afford a reasonable basis to assign different ignition frequencies to like components in a compartment based on distinguishing characteristics between one like compartment and another. RAN 97-031 4-31 BGE 4-31 RAN 97-031

Calvert Cliffs Nudear Power Plant Inmmtl Fire Analysis Individual Plat Examinaný External Events Simply stated, all electrical cabinets in the compartment will result in equivalent ignition frequencies, all pumps in the compartment will result in equivalent frequencies, and so on. This equal weighting approach is deviated from in the Control Room evaluation. Since the Control Room panels has significant size variations, a size weighting factor is used. See Attachment 4-I. Although transient ignition frequencies are also identfied in the compartment frequency analysis, the development of specific transient fire scenarios frequencies is described in Step 3, Section 4.3.4.3. 4.3.4.2 Step 2: Detailed Fire Modeling of Fixed Ignition Sources The detailed fire modeling for fixed ignition sources uses inputs from the previous step to analyze unique fire scenarios, including identification of specific fixed ignition sources, associated characteristics, and distances to targets. 4.3.4.2.1 Fire Damage Worksheets The fire damage modeling uses worksheets as provided in the FIVE methodology. The results derived from these worksheets is the critical distance from the ignition source for which damage to targets will occur. Targets outside this distance are not damaged by the postulated fire.

                 " Target In-Plume: This worksheet is used to assess damage for targets located overhead of the fire source in the fire plume. The geometry of the fire plume is essentially a cone with a radius as a function of height that can be estimated by r = 0.2z, where z is the height of the target above the fire source. These cases result in the most severe damage conditions.
                 " Target Outside-Plume: This worksheet is used to assess target damage fbr targets located overhead of the fire source but outside the cone of the fire plume. This worksheet addresses target damage due to potential ceiling jet and hot gas layer (HGL). Such cases are less severe than the in-plume case. If the in-plume case does not result in damage to a particular target, then similar targets at the same elevation or higher and located outside the plume will also not be damaged.

• Radiant Exnosure: This worksheet is used to assess target damage for targets located radially from the fire source. These cases typically result in the least severe conditions.

The worksheets require the input of the following information:

• geometry of the room (length, width, height)

                 " distance from source to target

• general location of the fire source (in comer, against wall, in center of room)

                 " damage threshold of target
                 " heat release rate of fire source
                 " radiant/convective heat release fraction

• heat loss fraction BGE 4-32 RAN 97-031

Ca Cliffis Nuclear Powe Plant Intnal Fre Analysis Individual Plant Emination Exnma! Evenl The first three items are obtained from drawings and walkdowns. The remaining inputs are determuned as follows. 4.3.4.2.2 Damage Thresholds Damage thresholds are based on empirical evidence and are summarized in the FIVE methodology and the EPRI Implementation Guide for various targets. With respect to IEEE 383 cables, the recommended damage thresholds for in-plume and outside-plume targets are 700 degrees Fahrenheit for cable failure and 932 degrees Fahrenheit for cable ignition. Cable ignition creates a situation where a cable tray fire now exists and fire propagation to additional trays overhead must be treated. With respect to the radiant heat calculations, the damage threshold is expressed in units of Btu/sec/ft. The FIVE methodology and the EPRI Implementation Guide both suggest that a value of I Btu/sec/f12 is a representative value for IEEE 383 cables. 4.3.4.2.3 Heat Release Rate The heat release rate of the fire source is a widely varying parameter. Industry tests, summarized in the FIVE methodology and the EPRI Implementation Guide, have been performed to aid in the selection of suitable heat release rate for various fire sources. Given the variability of heat release rate as a function of fuel package geometry, fuel type, test conditions and fire duration. Judgment must be used to allow consistent selection of heat release rates for similar sources and configurations. A heat release rate of 65 Btu/sec is used for electrical cabinets containing IEEE 383 cable or equivalent. For cabinets containing non rated cable, 8.5E-4 times the Btu loading in the cabinet is used. The EPRI Implementation Guide provides the following recommendations for a number of fire source configurations, with the following being the most common configurations:

• Vented electrical cabinet (65 Btu/sec)

                  " Open top electrical cabinet (8.50E-04 x Btu loading in the cabinet)

• Motor windings (< 65 Bltu/sec)

                  " Motor oil spill (135 Btu/sec/ft'2 ); an equation for estimating the area of the spill area is also provided in the FIVE methodology Some situations may arise in which judgment is necessary to select an appropriate heat release rate. Such judgment are made using experience, common sense and consideration of insights in the EPRI Implementation Guide. Compartment specific application of heat release rates is addressed in the attachments to Section 4.

4.3.4.2.4 Heat Release Fraction The heat release fraction is a measure of the fraction of heat generated by the postulated fire that is released via convection and that released via radiation. The FIVE methodology and the EPRI Implementation Guide suggests a conservative approach in which the convective fraction is 80 percent and the radioactive fraction is 40 percent. The 0.80 convective heat release fraction is employed in the In-Plume and Outside-Plume worksheets. The 0.40 radioactive heat release fraction is employed in the Radiant Exposure worksheets. RAN 97-031 4-33 BGE BGE 4-33 RAN 97-031

C~lvn Cliffs Nuclear Power Plnt Internal Fare Analysis Individual Plant Examination External Events 4.3.4.2.5 Heat Loss Fraction The heat loss fraction is a measure of the heat lost to the compartment boundaries and other heat sinks in the room. The FIVE methodology suggests that a heat loss fraction of 0.7 is a conservative value. The EPRI Implementation Guide recognizes that 0.7 is a conservative value and that 0.85 may be more realistic for many configurations. The value of 0.85 is used in CCFPRA (given that most compartments have concrete or block walls which act as better heat sinks). 4.3.4.2.6 Pre-Calculated Critical Distances Worksheets are completed for general cases to pre-calculate critical distances. As an example, a compartment may contain numerous electrical cabinets with louvers rising up the back to a height of seven feet. This case would be analyzed using the In-Plume and the Radiant Exposure worksheets to determine the critical distances around such a fixed ignition source, such as damage to cables located three feet overhead, or damage to equipment located one foot radially. This information is then used to identify the configurations in the compartment that fall within these distances; fixed fire ignition and target scenarios that fall outside these pre-calculated distances are categorized as fire scenarios involving damage to just the fixed component itself. Fixed ignition and target scenarios that fall inside these pre-calculated distances are then inspected to identify the need to perform Outside-Plume cases. If fire damage modeling results in damage to these nearest targets, equipment location, cable trays and conduit drawings, are used to find distances to additional targets, as necessary. Using the r = 0.2z equation for the cone of a fire plume, a few concentric circles are drawn over the key fixed ignition sources to show the zone of damage. 4.3.4.2.7 Results The result of this step is a list of the fixed ignition sources and their associated fire-induced damage states. This information is presented in a table that contains a comprehensive list of the fire ignition sources in a compartment. The table summarizes ignition sources, ignition source frequencies, adjacent cabinet and cable tray considerations, damage states and associated comments necessary to describe modeling details or assumptions. These fire scenarios for each fire modeled compartment is included in the attachments to Section 4. 4.3.4.3 Step 3: Detailed Fire Modeling of Transient Ignition Sources Operating experience, as indicated in the EPRI FEDB, reveals that transient fires typically involve small amounts of combustibles. In two industry events, the only items involved in the fire incident were an extension cord. In another event, a small muslin cloth used to collect radiation samples was accidentally ignited and burned. With respect to hot work induced fires, the majority of the events involved ignition of transient combustibles, only a few incidents involved sparks impacting cable insulation. Given the variability of transient related fires, the FIVE methodology categorizes transients into the following categories:

• Hot work induced cable fires

                 " Hot work induced transient fires

• Other transient induced fires BOE 4-34 RAN 97-031

Calvert Clf Nuclear Power Plant Internal Fire Analysis Individual Plant Examination Externl Eventa Hot work induced cable fires should be dismissed as a fire damage scenario for the following two reasons:

1) The number of hot work induced cable fires is very small and the incidents are minor in nature, 2) The plant is equipped with IEEE 383 cables which does not support fire propagation. This approach is consistent with NSAC-ll, Fire PRA Requantification Studies. Review of the EPRI FEDB indicates that transient combustible fires are almost always ignited by transient ignition sources; fixed ignition sources do not play a significant role in the creation of transient combustible fires.

4.3.4.3.1 Characterization of Transient Fire The appropriate approach to modeling transient fires is to perform the fire damage modeling assuming the fire is a transient fuel package that may be located anywhere in the compartment, consistent with the EPRI Implementation Guide. The EPRI Implementation Guide provides test data on the heat release rate for a variety of fuel packages, including human occupancy refuse, maintenance refuse, and radiation protection clothing. Selection of the fuel package that represents a generic transient fire in a given compartment requires judgment by the analyst. Based on a review of the transient fuel test summarized in the EPRI Implementation Guide, a representative fire in most areas of the plant can be best characterized as a maintenance refuse package of 100 Btu/sec with a fire duration of not greater than 15 minutes. Review of housekeeping procedures, in conjunction with walkdowns and interviews of fire protection personnel are used to reasonably characterize unique fuel packages to individual fire compartments. Probabilistically, the fire may be located in any open area on the compartment floor. Consistent with the EPRI Implementation Guide, the conservative approach is to construct various transient fire scenarios impacting each PRA modeled component. Once the locations are determined, the In-Plume, Outside-Plume, and Radiant Exposure worksheets are used to determine the critical damage distances. The height of the fire above the floor is a parameter required for completion of the In-Plume and Outside-Plume worksheets. Typically, a representative fire is determined to be a trash can fire, three feet from the floor. Such a fire is postulated to be more conservative than the example fire in the FIVE methodology, which places the fire on the floor, due to the closer proximity to targets, such as cable. Distance and location of transient fires, however, is largely determined on a compartment by compartment basis. 4.3.4.3.2 Frequency of a Transient Fire Once the critical distances are calculated and the associated worst-case equipment damage state is detenmined, the next step is to determine the frequency of the transient fire scenaro. The previously calculated transient ignition frequency is based on the FEDB and merely indicates that a transient ignition of some type may be located in the compartment The frequency does not indicate that a fuel package is involved in a fire or that such a postulated fire is even near critical equipment. The FIVE methodology recomm=ens a general formula for estimating the fire induced core damage frequency due to transient combustible fires. A modified version of this formula (with the Conditional Core Damage Probability term removed) is used to calculate the ignition frequency of a transient fire. RAN 97-031 4-35 BGE BGE 4-35 RAN 97-031

Calvein Cliffs Nudear Power Plant Internal Fire Analysi Individual ant Examination Extrnal Events F, = Fit *au *P, where: F, = transient fire scenario frequency (Note that FIVE uses this term to represent the induced core damage frequency for the compartment. This is calculated separately in the Fire CCPRA) Fit = transient ignition frequency for the compartment u = probability that transient combustible located in the range of target components Pf = probability of fire suppression failure given that the system would actuate prior to target damage 4.3.4.3.3 Transient Combustible in Range of Targets (u) This parameter assesses the probability that given the modeled transient combustible fuel package exists in the compartment, the transient combustible fire will occur near targets in that compartment Per the FIVE methodology, this parameter is estimated as a ratio of exposure area to total floor area, as follows: u = (A.+AYJ/Ar where: A. = Exposed surface area of cable trays overhead A, = Floor area around targets within the critical radial separation distance determined from Radiant Exposure worksheet. A, = Floor Area where combustibles could be placed. As with many of these parameters in the fire damage modeling analysis, estimation of the u parameter requires somejudgment. For example, if the fire dama worksheets indicate that no overhead cable tray is close enough to the floor to be impacted by the modeled transient fire, then the contribution from A. in the calculation of u is set to 0.0. In the determination of the A, contribution, the question arises whether to calculate the area with respect to the particular location in the compartment designated as the worst-case or to calculate the area with respect to all the critical targets in the compartment. If there is only a single worst-case spot in the compartment, then the appropriate approach may be to deermine A. with respect to this single location. If there are a number of potential worst-case locations in the compartment and it requires a judgment call or assignment of a representative damage state to characterize the worst-case damage, then it would be appropriate to calculate A., with respect to more than one (or potentially all) target in the compartment. The floor area in the denominator should be that floor area where it is possible for a transient combustible fuel package to be located (i.e., the area of floor mounted equipment should be subtracted from the entire floor area - this may be a best guess percentage estimate). 4.3.4.4 Step 4: Assessment of Fire Suppression The FIVE methodology and the EPRI Implementation Guide both provide guidance on the treatmen of fire suppression. These issues may be addressed in initial fire damage modeling analyses or may be deferred until after the core damage frequency quantification runs to determine if consideration of fire suppression is even warranted (see Step 6). BGE 4-36 RAN 97-031

Calvert Clffs Nuclear Power Plant Inrnal Fire Analysis Individual Plant Examination External Events Fire suppression is divided into the following general categories:

1. Installed automatic suppression systems

2. Installed manually actuated suppression

3. Fire brigade response (including Control Room operators and Hot Work Firewatches) 4.3.4.4.1 Automatic Suppression Systems Before automatic suppression is credited, a determination of whether the suppression system will actuate prior to target damage is made. This is pefomed by using the Thermally Thick and Thin Target workshect supplied in the FIVE methodology. These worksheet assess whether target damage will occur prior to the detectors (e.g.,

fbiisle links in sprinkler heads) actuating. The completion of these workheets require identfation of the spacial geometry of the detector with respect to the fire source and target, and the actuation temperature of the detector. If the workshms show that the detectors will actuate prior to target damage, then automatic suppression can be credited. Another consideration regarding actuation delay applies to a Halon system Halon systems are designed with a built-in actuation delay following detection. Note that localized suppression zones in a compartment indicate that automatic fire suppression can only be credited for the individual fire scenarios postulated in that localized suppression zone. If detection and actuation is determined to occur prior to target damage, the next consideration is the failure probability of the suppression system. The FIVE methodology provides generic failure rates for suppression system types. If multiple systems exist then the failure probabilities may be multiplied together. These is no case where such a multiplication is done in CCFPRA. The final issue regarding automatic suppression is fire suppression induced equipment failure. This issue is discussed separately at the end of this step. 4.3.4.4.2 Manually Actuated Suppression Systems The discussion above for automatic suppression systems applies to manually actuated suppression systems with one major exception - manual response time versus time available prior to target damage must be considered. The manual response time is the time between fire detection to target damage. For example, if an installed detector will indicate a fire in 20 seconds following fire initiation and the time to target damage is 60 seconds following fire initiation, the time available for manual response is 40 seconds. Typically, manually actuated systems are located in very few areas and do not enter into fire damage modeling analyses. In addition, the available time for manual response for most postulated fires is on the order of seconds to minutes, such that the human error probability for failure to actuate the system before target damage approaches 1.0. No credit for manual suppression systems is taken in CCFPRA. RAN 97-031 4-37 BGE BGE 4-37 RAN 97-031

Calvert Cliffs Nuclear Power Plant inte-na Fire Analysis Indivdua Plant Examination Externl Events 4.3.4.4.3 Fire Brigade Response Issues regaiding fire brigade responses are similar to that of manually actuated suppression systems. The allowable response times before target damage occurs are comparatively small. However, the EPRI Implementaton Guxie does provide guidance on estimate damage times incertain cases such a:

• damage resulting from fire propagation from one cable tray to the next
• damage resulting from a fire in one cabinet impacting sensitive equipment in an adjacent cabinet As in the manually actuated suppression system case, the prudent approach is to not credit fire brigade response in the iniial fire damage modeling, but to defer such consideration until alter core damage frequency quantification runs to detemin1 if mowmidcratmi of fire brigade response is warranted.

The fire brigade response to a Control Room fire is included in the CCPRA. See Section 4.6.1 Top Event VL. In addition, qualitative assessment of the fire brigade is included as part of the cross-zore analysis. See Section 4.3.3.2. 4.3.4.4.4 Suppression Induced Equipment Damage The FIVE methodology and the EPRI Implaemntation Guide do not treat the issue of suppression induced equipM2nt damage probabilistically. Response to the IPEEE Program regarding this issue is addressed dererministically under the Fire Risk Scoping Study issues of the internal fires facet of the IPEEE. The issue is treated by walkdowns and plant design reviews to determine if configurations exist anywhere in the plant where actuation of a suppression system could simultaneously disable redundant safe shutdown trains. See Section 4.9.2, Generic Issue-57, "Effmcs of Fire Protection System Actuation on Safety-Related Equipment." 4.3.4.5 Step 5: Fire-Induced Core Damage Frequency The previous four steps represent the fire damage modeling portion of the assessment of fire induced plant risk The results of the first four steps are a list of individual fire scenarios. These fire scenaios are characterized by the following

• scenario frequency (e.g., frequency of Pump X fire, frequency of generic transient fire)
• associated fire-induced damage (e.g., Pump X and cable tray ABC 123 disabled)

This information is used in the accident sequence analysis (i.e., core damage event tree modeling and quantification) to determine the associated core damage accident sequence frequency given the postulated fire-induced damage. See Section 4.6. The core damage sequence frequencies of all the postulated fire scenarios of a given compartment are summed to determine the compartment fire-induced core damage f1equency. BGE 4-38 RAN 97-031

Calveut CliWNuclear Power Plant Internal Fire Analysis Individual Plant Examination External Evcn 4.3.4.6 Step 6: Refinement of Fire Modeling The approach to fire damage modeling is gmenrally performed with suitably (not excessively) conservative ass and parameters. As such, initial fire damage modeling will esult in cmain comparwe that require additional analysis following accident sequece quantification. Options to consider inthe refinemft of fire modeling include the following:

                 "   Determine more realistic Heat Release Rates

• Credit fire suppression and/or fire brigades

                 "   Explicitly credit time delays in fire propagation among cable trays

• Determine more realistic fire-induced equipment damage states
• Relax conservatisms in transient combustible fire scenario frequency.

4.4 Evaluation of Component Fragilities and Failure Modes For the majority of the compartments, a fire which consumes the entire compartment is assumed. Under these conditions, the equipment, cables and human actions within the compartment are evaluated for functional impact. For compartments where specific fire scenarios are developed, the specific ignition sources and key targets are evaluated. Again, the equipment, cables and human actions within the bounds of the scenario are evaluated for functional impact FIVE provides a means to make conservative estimates about conditions that could develop to a target as a result of a specified fire. These conditions are then compared with the target damage threshold criteria and if the criteria are not exceeded, the specified target is assumed to have no direct fire impact. 4.4.1 Cable Analysis The fire related vulnerabilities for the functions credited in the CCFPRA are obtained by examining the electrical diagrams associated with the base CCPRA model's basic events. The base CCPRA model is very comprehensive and includes the explicit treatment of key electric relays and logic devices. The fire related impacts are obtained by evaluating the associated cables with each of the basic events. This required the integration of the existing Appendix R cabling data and supplemental cable routing research for "non-Appendix W" components. The plant circuit and raceway database (CRS) is used to obtain raceway routing information for the cables identified through this process. Each raceway containing at least one cable associated with a PRA component failure (basic eventy is identified and spatially located in the plant using the fire compartment designators. It should be noted that CRS only supplies the trays and conduits associated with each cable. A query was developed to spatially locate the cable by locating the trays and conduits. This process is conservative in nature because a cable may be in a tray for a short distance before it jumps into another tray. If a tray actually went through more compartments, then these fire compartments are identified as having a cable of concern even though the cable is not in them. This conservative cable to compartment identification BGE 4-39 RAN 97-031

Calvert C1itf Nuclear Power Plant inlnal Fire AnrA1ysi Individual Plat Examination External Evaft process likely results in more top events impacted in many postulated compartment fires. Although this is conservative, the resources and time necessary to identify each cable route was not available. The cable failure modes which are considered in this evaluation are open circuits, short circuits and hot shorts. An open circuit condition could result in component failure due to loss of motive power or critical signal failure. A short circuit failure mode could also result in component failure due to loss of motive power or critical signal failure. A hot short failure mode involves the cross energizing of conductors within a cable (conductor to conductor). Cable to cable failures are not considered in this analysis. A conductor to conductor hot short has the potential to cause undesired spurious actuation. The open, short and hot short failure modes are conservatively treated with a conditional failure probability of 1.0. If multiple failure modes of cables due to a single fire can occur, the most severe functional impact is assessed. The resulting data provides a link between cables associated with PRA equipment and the base CCPRA model basic event. An existing relationship provides the association between basic event identifiers and model top events. The functional impacts which result from a postulated fire in a compartmrent can then be determined. In most cases the impacted top events are further evaluated to determine whether the top event failed or is degraded as a result of the cable impact. This evaluation is used as input to modify the base CCPRA to reflect the various fire scenarios. 4.5 Fire Detection and Suppression The consequences of a postulated fire event may be minimized if fire suppression activities are available and effective. The evaluation of fire detection and suppression effectiveness was performed on a case by case bases. See Section 4.3, Fire Growth and Propagation. The reliability values for automatic suppression systems provided in the EPRI FIVE methodology are used in CCFPRA. System Tvye Unavailability of System Wet Pipe Sprinkler 2.0E-2 Preaction Sprinlder 5.OE-2 Deluge Sprinkler 5.0E-2 C02 4.OE-2 Halon 5.OE-2 The EPRI FIVE methodology also provides for the crediting of manually actuated suppression systems and fire brigade response. The crediting of these systems requires that a timing analysis be performed to verify that fire suppression would occur prior to cable or equipment damage. The CCFPRA only credited manual fire suppression actions in support of the Control Room analysis. This is discussed in Section 4.6.2. RAN 97-031 4-40 BGE BGE 4-40 RAN 97-031

Calven Cliffs Nuclear Power Plant Internal Fire Analysis Idiviual Plant Exaiminaion Extnal Even*s 4.6 Analysis of Plant Systems, Sequences and Plant Response The quantification of fire-induced core damage frequency (CDF) is obtained by propagating fire-induced failures through a modified version of CCNPP's PRA (CCPRA). This modified version is constructed from the General Transient module of CCNPP's updated internal events Level I PRA. The resulting model is mfered to as the "CCFPRA." The term plant model is used below and refers to a set of logic rules developed using PLG's RISKMAN Workstation Software (Ref 4-19) which represent CCNPP Unit 1. Each fire scenario (or initiating event) has a specific impact on the functions (or top events) contained in the plant model. Some of these impacts are complicated enough to warrant unique fimctions not contained in the CCPRA. Additional functions unique to the Fire CCPRA are described in Section 4.6.1. The Fire CCPRA unlike the Seismic CCPRA has only a few new functions added. Although few new functions are added, many new boundary conditions for those functions (or split firctions) are required. These additional split fractions are described in Section 4.6.2. One of the largest contributors of risk due to a fire is the effiet of the fire on human action success likelihoods. A human action's likelihood of success varies depending on the location of the fire and the path the operator must travel to complete the action (See Section 4.6.3). For each of these areas, new human action failure probabilities are developed:

• Auxiliary Building
• Turbine Building
• Intake Structure
• Outside & OC EDG Building (due to similar impacts these are combined)
• Control Room Based on the human actions value changes, new split fraction values are developed for each of the fire areas listed above. Depending on the point of fire initiation, the appropriate split fraction is questioned.

Each fire scenario is evaluated to determine the extent of the fire impact on the plant model. The scenario is then assigned an initiating event designator and a frequency. This is described in Section 4.6.4. The incorporation of all of this inlormation into the CCFPRA generates a model considerably larger than the base CCPRA model. The base CCPRA model has five linked events trees consisting of 1377 assignment statements (rules). The CCFPRA model has eight linked events trees consisting of 1642 assignment statements for the Control Room related scenarios, and eight linked event trees consisting of 1588 assignment statements for the non-Control Room related scenarios. The larger size of the CCFPRA also forces a different approach to the handling of sequence truncation limits. The CCFPRA results, as with the IPE results, are post-sequence processed to reduce tnmcation errors. All success split fractions not directly related to the likelihood of core damage or the determination of a Plant Damage State (PDS) are eliminated. This makes the sequences similar to cutsets. Given this approach, one of the key factors in determining a truncation limit is the amount of sequences associated with an initiating event. Most fire initiating events have at least 100 sequences. RAN 97-031 4-41 DOE BGE 4-41 RAN 97-031

Calval Cliffs Nuclear Power Plant intnal Fire Analysis Individual Plant Examination External Events Those that have less than 100 sequences have an unaccounted frequency less than 1E-7. All initiating events produce at least one sequence regardless of the unaccounted frequency limit. It should be noted that the CCFPRA has well over 180,000 sequences for the 177 initiating events contained within the plant model. See Table 4.6a for a listing of the unaccounted frequencies and sequence count for each initiating event. 4.6.1 Fire Top Events The new top events developed for the CCFPRA all relate to the presents of smoke in the control room. The amount of smoke in the control room can have these effects:

• None - The level of smoke is barely perceptible and only mildly degrades operator performance.
• Noticeable - The level of smoke will degrade operator performance, but the control room is habitable.
• Severe - The level of smoke is excessive and the operators are forced to abandon the control room and man the auxiliary (aux) shutdown panel.

These categories in additional to establishing functional impacts due to the evacuation of the Control Room also determine which the Control Room related Human Action Model to use. Top Event CL - Cable Spreading Room Dampers Close of a CSR Fire. The cable spreading rooms (CSRs) and Control Room (CR) are connected through a common ventilation system. If the CSR dampers close following a CSR fire, then the level of smoke in the Control Room is considered none. If the dampers fail, the level of smoke is considered noticeable. For most CSR fires, the failure likelihood is driven by hardware failures, but some fires will either disable required cabling or fail a necessary support system thereby guarantying the failure of this function. Top Event CR - Operator Abandons the Control Room This top event considers these abandonment scenarios:

• Control Room Panel Fire - The panel fire is not suppressed in a timely fashion. This causes excessive smoke generation and forces the abandonment of the CR.
• A Large Turbine Building Fire - The operators fail to or cannot isolate the CR outside air intakes causing thick smoke to enter the CR forcing abandonment.
• A Outside Transformer Fire - The operators fail to or cannot isolate the CR outside air intakes causing thick smoke to enter the CR forcing abandonment. This scenario differs from the Large Turbine Building Fire scenario in that it is less likely that the smoke from a transformer fire will reach the intake.

Control Room Abandonment has both a human action impact and an equipment impact. Human Action All human actionus which do not contain an AOP-9 compliment are considered failed. The essential impact of this is that the only actions left are those associated with AFW Pumps 11, 12, 13 and AFW flow control. BGE 4-42 RAN 97-031 5.,

Calvert Cliffi Nuclear Power Plant Intemu Fire Analysis !nd*MA Plud ExmnrAlion Exnea) Events Equipment Impact Given the Control Room is abandoned, the Unit I operators through implementing AOP-9A are considered to secure this key Unit 1 equipment:

• Steam Generator Feed Pumps I1 & 12
• High Pressure Safety Injection Pumps 11, 12, & 13

           "     Turbine Building SRW Headers I & 12

• Containment Spray Pumps I & 12
• Containment Air Coolers 13 & 14

            "    Battery Charger Feeds 12, 13, 22, and 23
            "    Off-site power feeds to the 4 KV Buses The equipment is secured either during abandonment or after manning the auxiliary shutdown panel. The equipment/functions listed above are not recovered in AOP-9A. In addition, to this equipment/function loss, the operators shed almost all electrical loads, and re-power the critical loads. The re-powering of critical loads is addressed in Top Event VB.

Top Event VL - Fire Brigade Suppresses a Control Room Panel Fire following Control Room Evacuation prior to further Control Room Panel Loss This function models the likelihood that the fire brigade prevents fire spread beyond those panels initially impacted by the Control Room panel fire, Failure of this is assumed to not only result in the failure of Top Event VB, re-loading key equipment, due to spurious equipment operation, but the failure is assume to result in the failure of all containment isolation equipment. The method of the containment isolation equipment failure is determined by examining all other plant model fire scenarios and using the worst case failure modes. For example, both Hydrogen Purge motor operated valves are considered to spuriously open. Although there are AOP-9A actions available to mitigate these failures, quantification of the likelihood of successful implementation is not included in the CCFPRA. Top Event VB - Operator re-loads Key Equipment Shed as part of AOP-9 following Control Room Abandonment This function models the likelihood that the operator will re-power all equipment shed in AOP-9 and slated for re-powerment in AOP-9. Failure of this function is assumed to result in the failure of all electrical power. Without electrical power, the batteries will deplete. Failure is likely to result in core damage. Top Event FW - Operator mans the Auxiliary Shutdown Panel following Control Room Abandonment Once the Control Room is abandoned, the operators are directed to man the auxiliary shutdown panel. The auxiliary shutdown panel is consider successfully manned when the operators have control of the turbine driven AFW Pumps. Failure to man the auxiliary shutdown panel causes the failure of the AFW Pumps which results in core damage. RAN 97-031 4-43 BGE 4-43 RAN 97-031

Calvert Cliffs Nuclear Pown Plant Internal ret Anaf)yis Mndividual PlantExamination External Evaets 4.6.2 Fire Split Fractions Although most fire scenarios have an equipment impact similar to a support system failure, some fire scenarios cause unique impacts which require new failure likelihoods while other can be successfully modeled using existing split fractions. For example, there is a function in the plant model which requires the Control Room HVAC to provide adequate ventilation to a common header (Top Event Mi). This top event models the functionality of both CR HVAC Unit 11 and CR HVAC Unit 12. If a fire fails Unit 11 it is equivalent to a loss of power to a single Unit. In this case a new split fraction is not required as the power loss split fraction which already exist is selected. Some impacts are not as straightforward, those impacts are listed below: Fire Faults Electrical Equipment A fire induced equipment failure is assumed to cause any electrical equipment to fault. If the associated equipment's breaker fails to open, then the bus which feeds that equipment is assumed to fault as well. Although these types of failures are considered in the internal flooding analysis, these failures are not in the base general transient model upon which the fire plant model is built. This effect is consider for all 13 KV, 4 KV, and 480 VAC equipment. Additionally, the 13 KV and 4 KV breakers are powered from 125 VDC. If this DC power source is not available, then the entire electrical facility (either A or B, but not both) is considered failed. EDG Mission Time The EDG mission times vary based on the perceived difficult of recovery of NSR power to the 4 KV buses. The three EDG mission times are:

• 24 hour Mission: This mission time is used when either a Switchyard Fire occurs, or the operators are forced to evacuate the Control Room. When the Control Room is evacuated the operators purposely remove off-site power from the 4 KV Buses.
• 4 hour Mission: This mission time is used when one or more of the U-4000 transformers is unavailable as a result of the fire.
• 2 hour Mission: This mission time is used when all of the U-4000 transformers are available.

This contrasts with the internal events analysis which has EDG mission times of 1, 2, 4, 11, and 24 hour based on the duration of the Loss-of-Off-site Power Event. Switchgear (SWGR) Room Ventilation Damper Recovery The SWOR room dampers must remain open to ensure adequate ventilation to the SWGR rooms (A31 1, A317, A407, and A430). In the case of a fire in the SWGR rooms, the dampers by design will close. Most fires in the SWGR rooms are considered recoverable. The exception is those fires involving oil cooled transformers. Due to the PCBs within the oil, the operators will not re-establish ventilation following these fires. BGE 4-44 RAN 97-031

Calvert Clfs Nulear!Power Plart Internal Fire Analysis Individual Plant Ex*mination External Events Another challenge to the SWGR room dampers, occurs as a result of outside fires. A large turbine building fire or a large outside transformer fire could result in smoke migration through the ventilation intakes of the SWGR rooms. If operators action is not take to recover or prevent this, then SWGR room ventilation will be lost. Control Room Damper Isolation Prior to Smoke Entering the Control Room In the event smoke reaches the CR. Inlet Dampers, the operators must isolation the dampers prior to smoke entering the Control Room in such quantities as to reduce the operators likelihood of successfully performing human actions. This action is questioned following a large turbine building fire, and a large outside transformer fire. Failure to perform this action is assumed to result in CR evacuation. Cable Spreading Room Damper Isolation following CSR Fire In the event of a CSR fire, the CSR Inlet and Outlet Dampers are designed to isolate. If the dampers do not isolate, then smoke will reach the Control Room. Smoke in the Control Room increases the failure rate of most human actions significantly. Operator Isolate PORV using the PORV Feeder Breakers (per AOP-9) A fire on 1C06 or Control Room evacuation prevents the use of the normal PORV isolation techniques. These events prevent the operator's use of the PORV override or the PORV block MOVs. When this occurs the operator is forced to isolate the PORVs using the PORV Feeder Breakers. As the PORVs fail closed on loss of power, this is an alternative method which is credited in AOP-9. Even with the success of this human action, there is still a noticeable likelihood that the PORVs will fail to isolate following relief. Operator Locally Trips RCPs (per AOP-9) Some Control Room fires prevent the operators from remotely securing the RCPs. When this occurs the operators must locally secure the RCPs per AOP-9. Even following the success of this action, there is still some likelihood that the RCP seal will fail. Auxiliary Shutdown Panel Human Actions If the operator evacuates the Control Room or if key Control Room functions are lost, then the operator must implement certain actions from the auxiliary shutdown panel including:

            "    Manually aligning AFW Pump 13
            " Manually aligning the Turbine Driven AFW Pump Room Emergency Ventilation

• Manually controlling the AFW flow rate

            " Manually starting the Turbine Driven AFW Pumps
            " Manually opening the Turbine Driven AFW Pump Steam Admission Valves
            " Manually aligning a long term AFW Water Supply Although these actions already exist in the general transient plant model, when the operator mans the auxiliary shutdown panel the likelihood of human action failure increases significantly.

RAN 97-031 4-45 BGE 4-45 RAN 97-031

Calvert Cliffs Nuclear Power Plant Inzerna Fire Analys hdMivadul Plant Examination External Evenu HPSI Loop Header MOVs The four HPSI LOOP motor operated valves (MOVs) associated with the main header are all powered from MCC 104R. The four HPSI LOOP MOVs associated with the auxiliary header are all powered from MCC 114R. In the general transient model, split fractions already exist to account for the failure of four MOV associated with either the main or auxiliary headers. But in certain fire scenarios only two-of-four MOVs associated with a header may fail. To support this condition, new split fractions are developed. Hydrogen Purge MOVs and other Containment Isolation Equipment The failure of the hydrogen purge MOVs will cause a breach in containment integrity. Since these valves are not normally opened, even if power were to be lost in a sequence which results in core damage, there is only a small chance that containment integrity would be lost. But some fire scenarios can cause the MOVs to spuriously open. As a result, new split fraction were required. 4.6.3 Evaluation of Human Recovery Actions The CCFPRA, uses a hybrid human action reliability analysis method which takes into account the best features of the SLIM-MAUD and HCR (Human Cognitive Reliability) models. The base CCPRA Human Action analysis uses the SLIM-MAUD methodology's Success Likelihood Index (SLI) and Performance Shaping Factors (PSFs) and uses the HCR model to determine the conversion constants which convert the SLI to a failure probability. The EPRI Operator Reliability Experiments (ORE) were then used to validate the failure probabilities generated by CCPRA's human action model. In addition, the specific operator action in question is divided into three phases: identification, diagnosis and performance. This allows the potential operator errors to be characterized in terms of various influencing factors. Each of the aforementioned phases is also characterized by its possible types of cognitive behavior, namely, knowledge-based, rule-based or skill-based. The combination of the above characteristics and careful use of expert judgment and calibration methods are believed to result in more realistic human action failure probabilities as compared with conventional methodologies. The base CCPRA human actions are modified as described in Section 4.6.1.1 to. reflect the impact of fire and smoke on the performance of actions already included in the PRA. If additional recovery actions are required, these actions are interviewed using the above methodology and added to the CCFPRA. See Section 4.6.1.2 for these actions. To address the direct fire impact on the operator actions, the plant location of where each action is performed is determined (called the destination room(s)). Also determined is the most likely path an operator will travel in order to reach the destination room(s) (given that the action required a plant operator to perform a function outside of the Control Room). If a fire occurs in the destination room or along the travel route, the human action in question is analyzed in detail as to whether the human action should be set to guaranteed failure or degraded. This determination is done by analyzing such things as the location and severity of ignition sources and combustible loading relative to key targets in a specific area and the timing associated with the human action. RAN 97-031 4-46 BGE 4-46 RAN 97-031

Calvert CiA Nuclear Power Ptat Innt!m Fire Analysis Individual Phst Examination Extern Events For fires occurring in the Control Room, a more detailed analysis is given a loss of one or several control panels. Furthermore, credit is taken for the operators utilizing certain functions on the auxiliary shutdown panel if a fire destroyed the operator's ability to complete the action from the Control Room. The functional impacts associated with operator actions in implementing the abnormal operating procedure for the evacuation of the Control Room (AOP-9a) is also considered. Since the ventilation system of the Cable Spreading Room (CSR) is common to that of the Control Room, any fires that originated in the CSR could result in smoke in the Control Room. The CSR ventilation system is demanded to isolate on sensing smoke and Halon is demanded to discharge. On a failure of the CSR ventilation system to isolate, the human action failure probabilities for smoke in the Control Room are used. In the case where a fire originated in the CSR and ventilation isolates the smoke from the Control Room, the human action failure probabilities generated for a turbine building fire, a clear Control Room condition (Human Action Models 1 through 6 in Section 4.6.1.1 depending on the specific human action), are conservatively used. This selection of the turbine building binning is made since access to the CSR is either through the turbine building or via stairtower from the CR. Top Event CL, CSR dampers close on a fire demand, has been added to the CCFPRA to allow the selection of the appropriate human actions. For certain actions that are not required until late (about 6 hours) in the transient; such as, supplying an alternate water source for AFW, the baseline human action failure probabilities are utilized. For these actions, it is assumed that the specific fire will be suppressed before the operators will even be required to identify, diagnose, or perform the specific human action in question. The only exception to this occurs during a large Turbine Building fire. Given that the operators may have some difficulty getting to particular external locations due to severe damage done to the Turbine Building, the degraded human action failure probabilities generated for the turbine building bin will be used for such long term actions. 4.6.3.1 Approach to Modifying Base CCPRA Human Actions This section provides additional detail on how the selected human action performance shaping factors are modified to account for the fire. The human action methodology used in the CCFPRA modifies critical performance shaping factors (PSFs) depending on the location of the fire and its associated smoke, the timing requirements of the action, and the availability of indication. The number and degree of the impact associated with the PSFs varies not only with the physical characteristics stated above, but also with the phases of the action (identification, diagnosis and performance) and the cognitive behavior used in each phase (knowledge-based, rule-based or skill-based). The performance shaping factors which could be impacted include: RAN 97-031 447 BGE 4-47 RAN 97-031

Calvert Clif Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Perfonnance Shaping Factors Impacted by Fire PSF Description VT1 Time Rush index VEI Training and experience in identifying the need for the required action VE2 Training and experience in diagnosing what needs to be done VE3 Training and experience in carrying out the required action VAI Adequacy of manning in the Control Room VA2 Distraction due to unnecessary personnel in the Control Room VA3 Adequacy of manning outside the Control Room VA4 Barriers to communication and coordination between the Control Room and others VA5 Barriers to communication and coordination within the Control Room VA6 Barriers to communication and coordination outside the Control Room Vii Adequacy of initial indication available V12 Adequacy of back-up indication available VD3 Number of proceeding and concurrent unrelated actions VL1 Difficulties of access, quality and location of equipment in the Control Room VL2 Difficulties of access to equipment outside the Control Room The result of addressing the various physical parameters is 11 different human action models. The parameters for these models are shown in Table 4.6.3. Ia. Each model also addresses the variations in the characteristics of the human action (3 cognitive process types and 3 phases). Since the performance phase is always assumed to be skill-based, this results in 7 sub-models for each base model. An example showing which of the PSFs are impacted when considering a human action performed when the Control Room is clear of smoke and has multiple indication available, and with smoke at the action performance location (Human Action Fire Model 5) is shown in Table 4.6.3. lb. Table 4.6.3.1a Human Action Fire Models Model Control Room Status Location Location Indication (Least to Moot Status Severe) 1 Clear Control Room Clear Multiple 2 Clear Control Room Clear Single 3 Clear Other Clear Multiple 4 Clear Other Clear Single 6 Clear Other Smoke Single 7 Smoke: CR Evacuated Auxiliary Shutdown Panel Clear n/a 8 Smoke: action timeframe > 15 rain Control Room Smoke n/a 9 Smoke: action timeframe-> 15 min Other Clear n/a 10 Smoke: action timeframe-< 15 rain Control Room Smoke n/a II Smoke: action timeframe < 15 rain Other Clear n/a a _= BGE 4-48 RAN 97-031

Cav CliU Nucear Power Plant InUrnal Fire Analysis Individual Plant Examination External Events Table 4.6.3.1b Human Action Fire Model 5 Performance Shaping Factors Impacted Skill-Based Rule-Based Knowledge-Based PSF Identification Diagnosis Performance Identification Diagnosis Identification Diagnoss VTI X X X X X X X VE1 X I X VE2 X X VE3 X VA2 X X X X X X X VA3 X VA4 X X X X X X X VA6 X VII X X X X X X VI2 X X x X x VD3 X X X X X X X VL2 I I X I I A base value for the percentage of smoke degradation for each PSF was established as a benchmark to evaluate each Human Action Model. See Section 4.6.3.2 for the development of the base value. In the human action fire models above, the appropriate PSFs for those actions whose conditions are ranked as being most severe are degraded more that the base value. Whereas, the PSFs for those actions whose conditions are ranked as being less severe are degraded less than the base value. It should be noted that the weighting factor associated with a specific PSF is assumed to remain the same for a fire scenario. The weighting factor accounts for how important a PSF is in a transient. The PSF is assumed to have the same importance in a fire situation although the ability associated with a specific PSF may be degraded. The way to account for this degradation is by adjusting the survey response for the specific PSF rather than adjusting the weighting factor linked to the PSF. The conversion constant ('a' constant) that is used to convert the Success Likelihood Index (SLI) to a failure probability is also assumed to remain constant in a fire scenario. The human action methodology for CCFPRA uses seven 'a' constants to calculate failure probabilities for different cognitive binning of the specific action in question. These same 'a' constants are utilized to calculate the fire human action failure probabilities since the 'a' constant is just a conversion constant. The specific impact of the fire will be seen in the degradation of the specific PSFs as stated earlier. This is best illustrated through as example. Example of a Human Action modified for the Fire CCPRA: RAN 97-031 4-49 BGE 4-49 RAN 97-031

CAlvest Cliffs Nuclear Power Plain lnteri Fire Analysis lndividual Plant Examina:ion External Evests The first step in analyzing a particular human action is to determine where the action needs to be completed. This particular action requires the auxiliary operator in the AFW Turbine Driven Pump Room (Room T603) to place the AFW Turbine Driven Pump to its pre-test configuration within 10 minutes. This 10 minute timeftame includes the time for the operators in the Control Room to identify that MFW has been lost, direct the auxiliary operator to complete the desired task, and for the auxiliary operator to physically complete the task. If a fire occurs in Room T603 this action is set to guaranteed failure. This particular destination room also includes a common access area just outside the AFW Turbine Driven Pump Room near the main feedwater pumps. If a fire occurs in this area has the potential to fail this particular action since the operators will not be able to access Room T603. However, for this particular human action, the operators will already be stationed in Room T603 during the testing of the pump so there will be no need for the operators to traverse through main feedwater pump area. The human action will conservatively uses the failure probability associated with a turbine building fire (Human Action Model 5, smoke at the action location) for any turbine building fire though the affect of the fire on the operators ability to return the pumps to pre-test configuration will be minimal. This action is determined to have a rule-based identification phase, a knowledge-based diagnosis phase, and a skill-based performance phase. The following table represents the options available to adjust the Performance Shaping Factors (PSFs) for the Rule-based identification phase only. The relevant PSFs that are assumed to be degraded due to a fire are VTI (time rush), VA2 (distraction of number of people who are in the control room), VA4 (communication between the control room and the auxiliary operator), VII (initial indications), V12 (secondary indications) and VD3 (number of concurrent actions in progress and overall distractions). Rule-Based Identification Binning Status Percentape of Degradation Used CR Location Indication PSF PSF PSF PSF PSF PSF Status Status Status VT1 VA2 VA4 VII V12 VD3 C C Multiple 10% 10% N/A 5% 5% 10% C C Single 10% 10% N/A 20% 20% 10% Single 20% 10% 20% 20% 20% 20% C - Clear S - Smoke The highlighted row above shows the appropriate values selected. The particular action in question is assumed to have a clear control room with smoke in the area that the auxiliary operator will be performing the desired task. The Control Room has multiple indications that MFW has been lost and that AFW needs to be established. The average percentage of degradation derived for a rule-based identification action is determined to be 20%. Since this particular action falls about midrange in the hierarchical listing of human action models described earlier, the 20% factor is directly applied to the critical PSFs such as time rush, communication, and concurrent actions in progress. The other percentages of degradation applied to the remaining PSFs arc generic factors applied to all cognitive phases. It is important to note that this example only shows the percentages of degradation applied to one of the phases of the human action in question. A similar process is repeated for the knowledge-based diagnosis and skill-based performance phases with BGE 4-50 RAN 97-031

Calved Cliffs Nuclear Power Plant Internal Fire Amnlyuis Individual Plant Examination External Events differing percentages of degradation. Once all three phases have been evaluated, a failure probability can be generated. For this particular example, a failure probability of 1.54E-02 is generated and is utilized in the fire model for this particular human action for all turbine building fires. The plant model also uses this action if there is a fire in the auxiliary building, intake structure, SBO Diesel building, outside areas, or Control Room. For a fire occurring in the auxiliary building, intake structure, SBO Diesel building, or any outside areas, the auxiliary operator in the AFW Turbine Driven Pump Room will not be affected by smoke. Therefore, the first row on Table 4.6.3.1c for the rule-based identification phase for a clear control room, clear destination room and multiple indications available (Human Action Model 1). Note that a similar process is again followed from the diagnosis and performance phases. This particular binning for a clear Control Room, clear destination room, and multiple indication available falls on the lower range (less severe) of the hierarchical list of models discussed earlier. Since this action under these conditions now bins to a less severe model, a PSF percentage of degradation of 10% is used for critical PSFs such as time rush, communication, and concurrent actions in progress. A human action failure probability of 8.74E-03 is generated for the remaining areas except for the Control Room fire. Since Control Room fires can have a severe impact on human actions, one would expect that the number generated for a Control Room fire (as pertaining to this particular human action) to use a PSF percentage of degradation greater than 20%. In fact, for a Control Room fire, a PSF percentage of degradation of 40% is used for short term actions for the critical PSFs. This yields a human action failure probability of 5.80E-02 for this particular action. 4.6.3.2 Basis for the Degree of Human Action Degradation This section provides the basis for the benchmark values used for the percentage of performance shaping factor degradation in the Human Action Fire Models. The impact of fire is evaluated by first calculating the probabilities of failure assuming a SLI of 10 (perfect values for all PSFs) for each phase and cognitive behavior. The results yield the most favorable failure probability that could be obtained if all PSFs are set to their most favorable value. The failure probabilities are then increased by a factor of 10 and fed back into the SLIM-MAUD equation solving for the SLI required to obtain the increased failure probability. This factor of 10 is based on expert opinion and is assumed to be the average increase, for each phase, to the failure probability due to a fire situation. The resulting SLI that is obtained for the increased failure probability is then converted to a percentage of degradation for use as an average guideline or benchmark to adjust various PSFs that will be affected in a fire scenario. By treating the different human action base fire models in a hierarchical manner, the rank ordering of the physical conditions ensure the appropriate percentage of degradation is assigned. Degradation severities were assigned using expert opinion. 4.6.3.3 Fire Recovery Human Actions The consequences of fire-induced damage range from total equipment failure to spurious actuation. In many instances, it is reasonable to credit post-fire recovery actions. The base CCPRA human actions are modified as described in Section 4.6.3.1 to reflect the impact of fire and smoke on the performance of actions already included in the PRA. If additional recovery actions are required, these actions are interviewed using the above methodology and added to the CCFPRA. Listed below are those additional actions added to the base CCPRA to recover from the impacts of various fire scenarios. BGE 4-51 RAN 97-031

Calvet Cliffs Nuclear Power Plant Analysis Internal FAme Individual Plait Examination External Events Data Designator Descriptionu Failure Probability BHEFIH Operator transfers control of AFW Turbine Driven Pumps to 1.30E-02 the Auxiliary Shutdown Panel within 45 minutes of a Control Room fire at 1C04, IC05 and IC06 BHEPVA Operator isolates PORVs by manually opening the PORV 1.86E-02 feeder breakers within I hour following a Control Room fire at IC04, IC05 and 1C06 BHESLY Operator trips all Unit 1 RCPs from Metal Clad within 45 4.06E-03 minutes of fire in Switchgear Room BHEHF4 Operator restores ventilation to the 45 ft Switchgear Room 2.63E-02 within 45 minutes following halon actuation due to a Switchgear Room fire BHEHF5 Operator restores ventilation to the 27 ft. Switchgear Room 2.69E-02 within 45 minutes following halon actuation due to a Switchgear Room fire BHEVBI Operator restores specific electrical loads after successfully L.OOE-01 stripping the loads when evacuation of the Control Room was initiated (See Note 1) BHEVLI Fire Brigade suppresses a fire in a Control Room Panel within 2.49E-02 25 minutes of arriving (prior to more panels being damaged) BHERH3 Operator starts Containment Air Coolers and Containment 4.19E-04 Spray Pumps within 5 hours of a Control Room fire on IC05 and IC06 BHECR2 Operator places Control Room HVAC in recirc mode within 5 5.OOE-03 minutes of an outside fire (See Note 2) a I Note 1- This particular operator action failure probability is an estimate provided by the human action analyst. The operators strip various electrical loads when they evacuate the Control Room. These electrical loads are manually reestablished once the operators have successfully shifted control of the plant to the auxiliary shutdown panel. Since this action is being utilized for a variety of electrical loads with a multitude of varying parameters, operator interviews would not be efficient or practical. Therefore, a conservative failure probability of 1.OOE-01 is assigned. This failure probability is deemed conservative due to the fact that the operators have explicit guidance for each of the loads that needs to be reestablished. Note 2- This particular operator action failure probability is an estimate. The estimate is based on certain commitments that were made by Operations to change procedures and implement the appropriate training of the operators. See Section 7.2. RAN 97-031 4-52 BGE 4-52 RAN 97-031

i Nucle Power Plant Calvnd CUM Internal Fire Analysis Individual Pl Examination Extemal Evet 4.6.4 Initiating Events Several types of initiating events are used in the Fire CCPRA. These include: Single Compartment Initiator This initiator type is used for single compartments which are assumed to completely bum due to a fire from that compartment. These compartments which have acceptable functional impact when lost. An example of this initiator type is FIA414, Unit 2 West Electrical Penetration Room, where the last four digits typically represent the compartment. Group Compartment Initiator This initiator type is used for compartments which have minimal impact and where conservatively grouping compartments with similar functional impact has a negligible impact on CDF. Note that these groups are modeled as if all functions associated with all rooms within the group are lost. An example of this initiator type is AUXIOC, Unit 2 ECCS Pump Rooms. Also included in this category are initiators coded as FCAxxx. Fire Scenario Initiator This initiator type is used for compartments which if failed by a large fire may have an unacceptable impact on CDF. Fire scenarios are developed using the detailed fire modeling process described in Section 4.3.4. An example of this initiator type is A31IF1. These initiators are typically referred to as A31 lFx. Each compartment analyzed using this technique is described fully in Section 4.6.2. Cross-Zone Initiator This initiator type is used for compartments which are grouped to address cross-zone fire spread. See Section 4.3.3 for the analysis approach and Section 4.6.6 for the results of this analysis. For each initiator, the functional impact is modeled. This impact considers:

• the equipment and cable lost due to the fire damage
• equipment impact due to fire suppression and ventilation isolation
• human action impact due to fire, smoke and confusion Equipment, cable and human action impacts are mapped to their associated functions. The impacted functions are modeled by either failing the associated top events or by modifying the top events failure probability (selecting the appropriate split fraction(s)). For each fire initiating event the top events which are impacted are identified by a two letter code, e.g. "AA" is the top event for 4KV Bus 11 remains energized. Those top events which are impacted but not failed are annotated with an asterisk (*).

BGE 4-53 RAN 97-031

Calved Cliffs Nuclear Powe Plait Intemal Fire Analysis Individual Plant Examination Extenal Events Table 4.6b provides a complete list of top events used by the CCFPRA. 4.6.5 Compartment Analysis This section addresses the analysis and results of all the Compartments. Compartments which are conservatively modeled by burning the entire compartment are listed in Table 4.6.2a. Compartment groups are listed in Table 4.6.2b. Compartments which are fire modeled are listed in Table 4.6.2c and are described in detail in attachments to Section 4. Table 4.6.5a Single Compartment Fire Initiators Initiator Frequency Description' Functional Impacts CDF FIA301 8.48E-04 Battery Room 11 (Note 1) DA, XA, TA, TB, F7*, 2.98E-06 TH, FIA304 7.92E-04 Battery Room 12 (Note 1) DB, XB 5.78E-08 FIA305 8.84E-04 Battery Room 21 (Note 1) DC, XC, NR, GW, GZ, 3.52E-06 F9 FIA307 9. 14E-04 Battery Room 22 (Note 1) DD, XD 5.ISE-08 FLA309 4.84E-04 Unit 2 Main Steam Piping Area QF, GH, DM*, PG, GZ 3.65E-09 FIA312 4.51E-04 Unit 2 Purge Air Room QD, QF, QE, Y3, Y4, 1.12E-07 DM*, F9 FIA414 3.28E-03 Unit 2 West Electric Penetration GF, GH, M3, HL, Y4, 3.43E-08 Room H9, NR*, FO*, SH* FIA416 2.23E-02 2B Diesel Generator Room GF, Y4.__ 1.02E-07 FIA420 1.58E-03 Reactor Coolant Waste Evaporator GG, AB*, Y4, FC*, 1.56E-08

                 ,                         Room                               CV, DL*,SG*

FIA421 2.23E-02 IB Diesel Generator Room GG, Y3, Y4, 1.39E-07 FIA422 2.23E-02 2A Diesel Generator Room GH, Y3, RA*, RB* 4.OOE-07 FIA439 1.24E-03 Unit 1 RWT Pump Room RE, RW, RA*, RB* 4.39E-08 FIMAB2 3.90E-04 Auxiliary Building Stairtower AB-2 CV 2.29E-09 F1T605 6.97E-04 Unit 2 AFW Pump Room Y3, Y41 GW, GZ, F9 8.88E-09 CDF Subtotal Single Compartment Initiators 7.47E-06 Note 1: Battery fluid, although corrosive, is not flammable or combustible. The battery casings are in contact with the fluid and are unlikely to be an ignition source. Therefore, the only plausible ignition source considered for these compartments is maintenance refuse. BGE 4-54 RAN 97-031

Caivert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination Extnal Evenad Table 4.6-5b Group Compartment Fire Initiators Initiator Frequency Description Functional Impacts CDF AUXIOA 4.04E-03 -10'/-15' Hallways Y4, FC, CV, HW, WJ 8.58E-08 AUXIOB 3.19E-03 Unit 1 Charging Pump Rooms FC CV 3.48E-08 AUXIOC 5.9&E-03 Unit 2 ECCS Pump Rooms Y3, Y4, GW 4.22E-08 AUXIOD 7.85E-04 Reactor Coolant Waste Tank Y4, FC*, CV, HW*, 1.05E-08 Rooms DL*, S(O, HA AUXIOE 6.23E-03 Unit I ECCS Pump Rooms and Y3, Y4, CV, VM, V1, 4.49E-07 Rcvirc Tunnel V2, MV, HA, HB, HW, CS, CT( SR*, TE, TW AUX20A 2.21E-02 5' Multi-compartment Area (Fire Y3, Y4, GW, FF, FC*, 2.83E-06 Area 11) F10, CV, VI, BB, V5, HW, DL*P, CTr, SH*, GG AUX20B 7.84E-03 Unit 2 Service Water, Component Y3, Y4, GW, GZ, FO, 1.13E-07 Cooling and Radiation Exhaust F9, NR*, NS* Rooms FCA206 9.29E-04 Unit 2 East Electrical Penetration DM*, F9*, SR* 3.27E-09 Room FCA221 3.46E-04 Unit 1 West Piping Pentration DL* 2.62E-09 Rooms FCA300 6.20E-04 Hallways Outside the Control Room HR 1.87E-08 FCA319 4.19E-03 27' Multi-compartment Area (Fire NR*, CV, DL*, SR* 4.62E-08 Area 11) FCA523 1.23E-02 69' Multi-compartment Area (Fire GG, GH, H9, H6, XW, 1.22E-07 Area 1t) HH* CDF Subtotal Group Compartment Initiators 3.76E-06 Table 4.6.5c Fire Modeled Compartments Attachment Room Fire Area. Description CDF A A225 14 Unit 1 Radiation Exhaust Equipment Room 3.99E-09 B A226 39 Unit I Service Water Pump Room 3.47E-08 C A227 11 Unit 1 East Piping Penetration Rooms 6.82E-07 D A228 15 Unit I Component Cooling Pump Room O.OOE-00 E (CSR) A302 17 Unit 2 Cable Spreading Rtoom 6.81E-07 A306 16 Unit I CableSprea___dinRoom 6.72E-06 El A308 11 North/South Passage Way O.OOE-O0 F (SWGR) A311 18 Unit 2 27' Switchgear Room 2.22E-07 A317 19 Unit 1 27' Switchgear Room 4.28E-06 A407 25 Unit 2 27' Switchgear Room 1.19E-07 I A430 34 Unit 1 45' Switchgear Room 1.54E-06 G A315 11 Unit I Main Steam Isolation Valve Room O.OOE-00 H A318 19A Unit 1 Purge Air Room 1.15E-09 I (MCR) A405 24 Main Control Room 2.53E-05 BGE 4-55 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Table 4.6.5c Fire Modeled Compartments (Continued) J A419 11 Cask and Equipment Loading Area-Truck 1.86E-07 Bay K A423 32 Unit I West Electric Penetration Room 6.78E-08 L A429 33 Unit I East Electric Penetration Room 7.10E-08 M A512 11 Control Room HVAC Room 1.91E-09 A520 11 Spent Fuel Vent Room O.OOE-00 A524 11 Unit 1 Main Vent Fan Room 2,37E-08 A525 11 Unit 1 Containment Access Are 0.OE-00 N A529 37 Unit 1 69' Electrical Room 9.18E-08 0 AB AB- Stairtowers 0.OOE-01 1_3,4,5_E P CC-A&B 20,21,22,23 Cable Chass.IAIB2A2B. 9.67E-07 0 CC-C 16.17 Cable Chases 1C,2C O.OOE-00 R INTAKE IS Intake Structure 1.22E-08 S T603 42 Unit I AFW Pump Room 4.76E-07 T TB TB Turbine Building 1.66E-05 U YARD YARD Transformers, Tanks and Independent 3.53E-06 Structures CDF Subtotal Fire Modeled Compartments Total 6.16E-05 4.6.6 Cross-Zone Analysis This section provides the results of the cross-zone analysis described in Section 4.3 for propagation frequencies > I.OE-07/yr. The quantification of fire-induced core damage frequency (CDF) is obtained by propagating fire-induced failures through a modified version of the CCNPP PRA as described in Section 4.6. For many of the compartment combinations, the functional impact of the loss of one of the compartments is a subset of the other compartment. For these compartment combinations, no new initiating event is developed. The risk impact is determined by simply multiplying the cross-zone propagation frequency by the conditional core damage frequency of the bounding compartment. These compartment combinations are shown in Table 4.6.6a as having an "unassigned" initiating event. In six cases, the impact of fire damage is not a subset by an existing initiator and a new Cross-Zone Fire Initiator is used. Table 4.6.6a Cross-Zone Fire Inititators Analysis PRA Initiator Room Pairs Propagation Functional Impacts CDF Frequency S FCCMBI FIA42 I/FIA422 1.06E-05 GG, GH, Y3, RE, 9.40E-10 FIA421/FIA439 1.56E-05 RW FCCMB2 FIA416/FIA418 8.53E-07 GF, Y4, SH* 1.50E-12 FCCMB3 AUX1OA/AUXIOC 1.56E-06 Y3, Y4, GW, FC, CV, HW, WJ 7.64E-1 I FCCMB4 AUXIOA/AUXIOE 1.61E-06 Y3, Y4, FC, CV, MV, HW, SR*, 1.42E-10 TE, TW BGE 4-56 RAN 97-031

Calvert Cliffs Nuclear Power Plant Intemal Fire Analysis Individual Plant Examination External Events Table 4.6.6a Cross-Zone Fire Inititators Analysis (Continued) PRA Initiator Room Pairs Propagation Functional Impacts CDF FCCMB5 AUXIOA/AUXIOD 5.75E-05 Y4, FC, CV, HA, HW, SG*, WJ 1.05E-09 FCCMB6 A423F(x)/FIA421 1.91E-06 El, E2, E3, E4 (Back up Bus 1.19E-07 A423F(x)/FIA422 9.77E-06 fails), GO, Ml, HR, HL, Y3, XW, QZ*, NR*, NS*, H6, RS*, RR, PS, PV*, Fr, CV, RE, RW, WY*, SO, SHK GH Unassigned AI05B/AUX10A 2.14E-06 Represented by AUX1OA 4.54E-1 1 Unassigned A105CiAUX1OA 1.15E-06 Represented by AUX1OA 2.44E-1 1 Unassigned A117/AUX10A 1.92E-06 Represented by AUX20A 4.08E-11 Unassigned A117/AUX10E 1.78E-07 Represented by AUX WE 1.28E-1 1 Unassigned Al 17/AUX20A 1.78E-07 Represented by AUX20A 2.28E-1 1 Unassigned A120/AUX20A 2. 1OE-06 Represented by AUX20A 2,69E-10 Unassigned A440/FIA416 1.3 1E-05 Represented by FIA416 5.97E- I1 Unassigned A536/FIA420 4.65E-06 Represented by FlA420 4.59E-11 Unassigned AB-1/AUX10A 7.OOE-07 Represented by AUX 10A 1.49E-1 1 Unassigned AB-E/AUXIOA 2.07E-05 Represented by AUX1OA 4.39E-10 Unassigned AUX1OA/AUX1OB 7.28E-05 Represented by AUXIOA 7.94E-10 Unassigned AUX10A/AUX20A 2.07E-05 Represented by AUX20A 2.65E-09 Unassigned AUXIOA/FIMAB2 2.89E-06 Represented by AUX1OA 1.69E-1 1 Unassigned AUXIOB/AUX20A 1.22E-07 Represented by AUX20A 1.56E-11 Unassigned FIA414/FIA416 9.81E-06 Represented by FIA414 4.47E-11 Unassigned FIA420/FIA421 2.14E-07 Represented by FIA420 1.33E-12 CDF Subtotal Cross-zone Analysis Total 1.26E-07 4.6.7 Unit 1 Fire Risk Assessment Results The results of the CCFPRA are summarized below in Table 4.6.7a by analysis type. The majority of the contribution is as expected from the compartments which are fire modeled. However, it should be noted that the compartments which are not fire modeled, the single and group compartment initiators, would likely be substantially reduced with additional effort. The cross-zone fire analysis results in an insignificant contribution to risk. The top 100 sequences quantified are shown in Table 4-6c. The dominant issues apparent from these sequences are identified in the following sections. Table 4-6d provides the descriptions and values of the split fractions used in the top 100 sequences. BGE 4-57 RAN 97-031

Calved CHi5 Nuclear Povwr Plan! Internal Fire Analysis Inuividual Plazu Examinktion Extemnal Evema Table 4.6.7a CCFPRA Results Summary Analysis Event T~ype-,:`. CDF Coitribuion PeCIentage Single Compartment (Initiators) 7.47E-6 10.2% Group Compartment (Initiators) 3.76E-6 5.2% Fire Modeled Compartments 6.16E-5 84.4% Cross-zone Analysis 1.26E-7 0.2% Total CDF 7.30E-5 100% 4.6.7.1 Large Turbine Building Fire (Initiating Event TBALLB) A large turbine building (TB) fire through equipment failure causes the loss of off-site power. The large fire in the TB also prevents several key human actions:

• Human Action to align the OC EDG: This is considered failed as access to the SWGR rooms is more difficult. Even if the OC EDG is aligned it will probably be aligned to Unit 2 as Unit 1 has the IA EDG.

Human Actions to align make-up to the SRW head tanks: This is considered failed as access to fire protection and condensate feeds to the SRW head tanks is by procedure through the turbine building. Even if the operators could use fire protection to directly feed the head tanks located in the auxiliary building, it is unlikely that the fire protection system would have adequate pressure due to the turbine building fire fighting activities. The final avenue of make-up is using the SW system to direly feed the SRW system. The normal route of access is through the turbine building, but access through the auxiliary building is possible. No credit is taken for this alternate make-up route.

• Human Action to _Oen the AFW Pump Room Doors: This action is considered failed as the AFW Pump room doors open directly into the turbine building (the fire location).
• Human Action to Align AFW Pump 23 to Unit 1: This action is considered failed as Unit 2 is considered to be in the same dire straights as Unit 1.
• Human Action to align Portable Fanrs to the SWGR Rooms is lost: This action is considered failed as the portable fans are located in the TB.

BGE 4-58 RAN 97-031

Calvert CiHs Nuclear Power Plant [ntemal Fire Analysis Individual Plant Examination Extrnal Events These impacts alone are not sufficient to cause core damage. But any of these independent failures combination with the impacts listed above will cause core damage:

• 1A EDO Fails gTop Event GE) with high SRW pre-existin, Leakage (Top Event RL): When the SRW System has high pre-existing leakage, the head tanks can not maintain sufficient inventory to prevent SRW pump failure over a full 24 hr mission. The failure of SRW causes the EDGs cooled by SRW to be lost. This station blackout condition causes the failure of all of the Unit 1 AFW Pumps. The motor driven pumps fail due to loss of power while the turbine driven AFW Pumps fail due to loss of room cooling. As mentioned above, the human action to open the turbine driven AFW pump room doors (for cooling) is assumed failed.

a Oerater Fails to Open SWGR DanMurs (Top Event HF): The large turbine building fire is considered to cause both SWGR room dampers to close. The mechanism of closure is either due to smoke

• entering the outside air intake or through the failure of the Halon control panel. If the operators fail to open these dampers, then a Unit I blackout is assumed.
• Operator fails to provide long term wMter for AFW following CST 12 Depletion gTop Event F3):

Following the depletion of CST 12, operator action is required to align another water source for AFW. Although the tank farm is removed from a turbine building fire, it does have an impact on the success of this action by restricting operator access to the AFW Turbine Driven Pump Room. Normally when the turbine driven pumps are operating, an operator is stationed in the pump room. Even if the control room fails to align an alternate water source prior to the AFW Pumps losing Net Positive Suction Head (NPSH), the operator stationed in the pump room would notice pump cavitation. This provides an addition check in preventing the failure of the operating AFW pumps due to loss of NPSH. The presents of a turbine building fire eliminates this redundant check there by increasing the likelihood of failure. Operator fails to Isolation Control Room Inlet Dampers (Top Event CR): Failure to isolate this inlet dampers is assumed to result in control room evacuation. Given that there is a large fire in the turbine building limiting local access to the turbine driven AFW pumps, no credit is taken for the operators manning the aux shutdown panel. As a result, core damage is assumed. 0 IB EDO Fails (ToD Event GG) with a Unit 1 SWGR HVAC Failure (Top Eyent HS): This case is similar to the first case, but Unit 1 power is lost due to a loss of SWGR ventilation. The Unit 1 SWGR Room must be cooled to prevent the SR electrical busses from being lost. This cooling can be supplied be either the portable fans or the SWGR HVAC system. As the portable fans are lost in this scenario, only the HVAC system is available. The loss of the 1B EDG cause the failure of one of the SWGR HVAC headers, while the remaining header independently fails (mostly likely as a result of header unavailability), Without SWGR HVAC, a Unit I blackout is assumed. 4.6.7.2 Fire on Auxiliary Feedwater (1C04) and Reactivity Control (1CO5) A fire on 1C04 disables MFW, OTCC, and AFW. If the operator does not man the auxiliary shutdown panel (1C43) and establish AFW flow in a timely fashion core damage occurs. In the short term, the most likely failure scenarios are the aux shutdown control is not established (Top Event FW), or that both of the turbine driven pumps fail (Top Events TF and TG). In the long term, the most likely failure scenario is the failure to establish a long term water source of AFW (Top Event F3). BGE 4-59 RAN 97-031

ClifBS Nuclear Power Plat Internal Fire Analysis Individual Plant Examnination Extrntal Evafs 4.6.7.3 Battery Room Fire (Initiating Events FIA305 & FIA301) The loss of a battery is a significant event in the general transient evaluation, and even more so when a fire is the cause of the loss. Recovery from a battery loss requires several local human actions: Local AFW Flow Control UTom Events HX and UO): The loss of DC power causes MFW to be lost and the AFW flow control valves to fail open. Without operator action, the S/G will overfill which would cause the turbine driven AFW pumps to fail. Additionally in attempting to rectify the overfill situation the operators may underfeed the S/Gs.

• Local Trip the RCP IoT Event SL): The loss of DC power isolates cooling to the RCPs. If the operators do not trip the RCPs locally, then the RCP Seals may fail prior to the pump stopping. Subsequent safety injection failures (Top Event HA) could lead to core damage.

Although the likelihood of a battery loss is much lower due to a fire then through other mechanisms, the likelihood of human action failure increases dramatically during a fire. For this reason, the battery room fires are significant. 4.6.7.4 Control Room Panel Fire which Leads to Evacuation Every Control Panel Fire can lead to Control Room evacuation. If the fire is not suppressed (Top Event CR), then the operators are forced to evacuate. Once the Control Room is evacuated, the operators are required to load shed most of the electrical loads, and manually re-start these loads (Top Events VB). If the re-start is not done, then site is in a self-induced station blackout condition. This condition will eventually result in the loss of the 125 VDC batteries. This causes a loss of all indication. This is assumed to result in core damage. Even if the operators, successfully re-load the buses, a failure of either EDG lA or EDG 213 will leave the site with only one-of-two facilities (A or B). This will eventually cause 2-of-4 batteries to be lost which will cause an SSSA condition (See 3.1.5.6 in the Seismic Sequence Analysis for more information on this condition). An SSSA condition with the auxiliary shutdown panel as the operators only source of indication is assumed to result in core damage. The key to mitigating all Control Room evacuation scenarios is that the operators man the auxiliary shutdown panel and establish AFW flow prior to core damage from lack of decay heat removal. 4.6.8 Unit 2 Fire Assessment Since a Unit 2 specific PRA model has not been developed, an assessment of the differences between units with respect to fire is performed. The following sections describe the methodology and results. 4.6.8.1 Methodology The main difference between Unit 1 and Unit 2 is a SRW dependency on the EDGs. Both Unit I EDGs are SRW-cooled, while only one of two Unit 2 EDGs are SRW-cooled. Because of this difference, even if the fire impacted Unit 1 and Unit 2 equipment in the exact same fashion, Unit 2 would be affected differently than Unit 1. As a result, the first step is to determine the change in risk for Unit 2 assuming the fire impacts on Unit 2 are the same as those impacts on Unit 1 (See 4.6.8.1.1). The second step is to determine which Unit 2 fire scenarios do not have a Unit 1 equivalent fire scenario (See 4.6.8.1.2). "The change in risk is estimated for each Unit 1 fire scenario which does not have a functionally equivalent Unit 2 impact. BGE 4-60 RAN 97-031

Calvert ClifS Nuclear Power Plant Interna Fire Analysis Individual Plai Examination Extenal Eva 4.6.8.1.1 Emergency Diesel Generator Difference The most significant non-cable routing difference between Unit I and Unit 2 is the lack of a SRW dependency on Emergency Diesel Generator IA. EDG IA is a newly-installed safety-related self-cooled diesel generator and backs up Unit l's safety-related 4KV Bus 11. The Unit 2 equivalent bus is 4KV Bus

24. It is backed up by SRW-ependent EDG 2B.

The EDGs tie into the 4KV buses which in turn power the 480V, 125VDC, and vital inverters which power the 120VAC vital buses. At the 125VDC and 120VAC levels, multiple trains and cross ties between the units electrical buses eliminates the impact of the SRW dependency. That is, at the lower voltage levels, Unit 2 has half of its trains ultimately powered from the non-SRW-dependent EDG lA, just as Unit I has. However, at levels above these (4KV and 48OV), there are no Unit 2 buses backed by EDG IA and the SRW dependency exists. The most significant impact of the increased SRW dependency of Unit 2 is on the motor driven AFW pump. Unit 2's motor driven AFW pump (AFW Pump 23) is aligned to 4KV Bus 24, which is backed up by SRW dependent EDG 2B. Unit l's motor driven pump is aligned to EDG IA-backed 4KV Bus 11, and does not have the SRW dependency. However, this does not mean that Unit 2 AFW is entirely SRW dependent. Unit I AFW may be cross-connected to Unit 2, but this requires a human action. Alignment of Unit I AFW PP 13 to Unit 2 is only possible if Unit 1 already has adequate decay heat removal through use of MFW or the Unit 1 turbine driven pumps. If Unit 1 does not have MFW or at least one Unit 1 turbine driven AFW, then Unit I AFW Pump 13 is not available to Unit 2. A Unit 2 Fire CDF is evaluated by quantifying a modified version of the Unit 1 CCFPRA. For the Unit 2 model, the diesel generators are 'rewired' to the 4 KV Buses. 4.6.8.1.2 Cable Routing Differences Three types of cable routing comparisons are performed: fire modeled to fire modeled compartments, non-fire modeled to fire modeled compartments and non-fire modeled to non-fire modeled compartments. These comparisons are limited to top event level and are described below. That is, if like top events are impacted in scenarios or compartments which are being compared, then no additional review is performed. If differences are noted where there is a loss of a Unit 2 function which is not included in the like Unit 1 assessment, then additional review is performed to determine if the top event which is not bounded is only degraded. Non-bounded differences which can not be resolved are quantified. Fire Modeled to FireModeled Compartment Comparisons If the Unit 2 compartment and its equivalent Unit 1 compartment are both fire modeled, then the Unit 2 impacts on top events are compared to Unit I impacts for the equivalent fire scenarios. Fire impacts for the following compartments are evaluated in this way.

1. A311 and its equivalent compartment A317 (27' switchgear rooms)

2. A407 and its equivalent compartment A430 (45' switchgear rooms)

3. A306 and its equivalent compartment A302 (cable spreading rooms)

BGE 4-61 RAN 97-031

Calvurt Cli Nuclear Power Plant Inlrrul Fire Analysis Individual Ptant Examination External Events Note that many Unit 2 compartments have an impact on the Unit 1 fire analysis. This is true for the three pairs of compartment listed above. For example, both cable spreading rooms are evaluated in the Unit I CCFPRA. Therefore two comparisons must be made when comparing Unit I with Unit 2. Cable Spreading Room Comparisons Compartment Evaluation Comparison Perspective Compartment A302 Unit 2 Cable Spreading Room Unit 2 A306 as modeled in Unit l's CCFPRA A306 Unit 1 Cable Spreading Room Unit 2 A302 as modeled in Unit l's CCFPRA Non-FRre Modeled to FireModeled Compartment Comparisons Unit 2 impact compartments A414, A409 and A532 are not fire modeled for the Unit 1 analysis. The equivalent Unit 1 compartments A423, A429 and A529 are fire modeled. Using knowledge from the equivalent Unit 1 compartments and additional information from walkdowns, cable raceways, in A414, A409 and A532 that would be impacted by fire arc identified. The impact of burning the identified raceways in the Unit 2 compartments is compared to the impact of similar fire scenarios developed for the Unit I compartments. Non-FireModeled to Non-FireModeled Comparisons For the compartments that are not fire modeled in the Unit I analysis, a list of Unit 2 impacts is generated for each compartment. The Unit Fire Initiating Event that includes the equivalent Unit I Compartment is selected and a list of Unit 1 impacts caused by the fire initiating event is generated, The list of Unit 2 top impacts are then compared to the Unit I list. 4.6.8.3 Unit 2 Fire Assessment Results The estimated Unit 2 fire CDF is 1.1 E-05 per reactor year. The emergency diesel generators configuration differeces account for 97% of the difference is risk between the units. This contribution was estimated using the CCFPRA with only the diesel generators 'rewired' so that the SRW-dependent diesels supply the 4KV buses on the Unit 1 side. Following this, the risk due to the rewired diesels and other cable routing differences was estimated. This combination increased the estimated risk by an additional 3% to the calculated risk yielding the total of 1.1E-04. The large turbine building fire contributes about a quarter to the risk of Unit 2 as opposed to 17% for Unit I and is responsible for about a half of the overall increase in risk. This contribution results from the degradation of SRW makeup, both hardware and human actions. Both Unit 1 and 2 CCFPRAs consider the probability that the SRW system leakage will be high enough to result in the failure SRW within 24 hours. Such a failure results in the loss of Emergency Diesel Generators 2A and 2B (and lB for Unit 1). BGE 4-62 RAN 97-031

Calvert Clif Nuclear Power Plait lnternal Fire Analysis Individual Plait Examination Extran Events 4.7 Analysis of Containment Performance This section describes the results of the Level Ii containment performance analysis. CCFPRA explicitly evaluates the fire impact on the containment mitigation and isolation functions. Therefore, the methodology used to determine the containment failure modes is essentially the same as that used in the Calvert Cliffs IPE Summary Report (Rd.4-6). The plant damage states (PDSs) are determined for each initiator. Like the IPE, these PDSs are related to key PDSs. The key PDSs are those for which the accident progression was determined. The contribution of these key PDSs to containmmet failure is shown in Table 4-7. Note that this approach assumes that the accident progression for a given CCFPRA key PDS is not significantly difference than that of the IPE. The two dominate key PDSs are HRIF and HGIP. These key PDSs represent a high pressure core melt with the containment isolated and either no containment cooling (F) or containment sprays available (P). Both of these PDSs were also identified as high contributors in the IPE submittal. A new key PDS, HRWF, is also identified. This PDS represents a high core melt with large early containment failure and no containment cooling. Fire sequences which could result in spurious actuation of containment isolation valves are conservatively mapped to this PDS. Many of the spurious actuation sequences result from fires where the Control Room is evacuated. It also should be noted IPE submittal has a larger early small containment failure contribution. The IPE's contribution is primarily due to a steam generator tube rupture which is not a concern in the CCFPRA. The impact of fire on interfacing LOCAs is also evaluated. All cables which could affect the probability of having an interfacing LOCA (V-sequence) are routed and assessed. It is determined that even though some cable failures could cause an increase in the likelihood of a V-sequence, none of these cables are impacted by a plausible fire scenario. Therefore, with the exception of the Control Room noted in the paragraph above, a V-sequence is not initiated by a fire initiating event. 4.8 Treatment of Fire Risk Scoping Study Issues This section provides the results of the evaluation of the Fire Risk Scoping Study issues for CCNPP. The discussion of these issues for CCNPP is presented here consistent with the NRC recommendation that resolution of the FRSS issues be coordinated with the Fire IPEEE. These issues are identified in NUREG-1407 as well as in NRC Generic Letter 88-20 Supplement 4. Sandia National Laboratories, as part of the Fire Protection Research Project, undertook two tasks in what is now referred to as the Fire Risk Scoping Study (FRSS). The tasks were to review and update the perspective of fire risk in light of the information developed through the Fire Protection Research Project, and to identify and perform initial investigations of any potential unaddressed issues of fire risk. As a result of that study, the NRC identified six issues to be addressed in any future fire evaluation methodology. Subsequent to NUREG-1407, Generic Letter 88-20, Supplement 4, was also issued which addressed the six issues contained within the FRSS. These issues are:

• Seismic/Fire Interactions
• Fire Barrier Qualifications
• Manual Fire Fighting Effectiveness
• Total Environment Equipment Survival
• Control Systems Interactions BGE 4-63 RAN 97-031

Calvert Cliffs Nuclear Power Plat Internal Fire Analysis Individual Plant Examination External Events 0 Improved Analytical Codes The approach taken to address these issues was similar to that described in FIVE regarding each of the above issues. A summary of the results of the investigation into these issues is provided in the following sections. The last issue, namely "Improved Analytical Codes", involves some questions regarding the available fire models for use in the Fire IPEEE. These questions are considered resolved with the development of the FIVE methodology and no additional evaluation of this last issue is addressed. 4.8.1 Seismic/Fire Interactions The Seismic/Fire Interactions involves three specific concerns as follows: 9 Seismically-Induced Fires 0 Seismic Actuation of Fire Suppression Systems

• Seismic Degradation of Fire Suppression Systems 4.8.1.1 Seismically-Induced Fires Descriptionof the Issue A verification that hydrogen or other flammable gas or liquid storage vessels in areas with seismic safe shutdown or safety-related equipment are not subject to leakage under seismic conditions.

Resolution of Issue This issue is considered resolved. At CCNPP an evaluation, was performed which determined there are no seismic induced flammable gas or liquid leakage potentials that could impact safe shutdown equipment. This issue is further addressed in Section 3.1.3.3 of this summary report. 4.8.1.2 Seismic Degradation of Fire Suppression Descriptionof the Issue A verification that the design of water suppression systems considers the effiects of inadvertent suppressions system actuation and discharge on that equipment credited as part of the seismic safe shutdown path in a margins assessment that was not previously reviewed relative to the internal flooding analysis or concerns as those discussed in IE Information Notice 83-41. Resolution of Issue This issue is considered resolved. At CCNPP an evaluation was performed on the design of both water suppression and gas fire suppression systems to consider the effects of inadvertent actuation and discharge on safe shutdown equipment. As a result of this evaluation, it is determined that there are no impacts to safe shutdown due to inadvertent actuation of water suppression systems. However, should the switchgear room Halon systems spuriously activate, they could isolate the ventilation to both the 45' and 27' Switchgear rooms. This would require timely operator action to restore ventilation and this has been factored into the CCFPRA. See Section 4.8.4. 1. Additionally, the Cable Spreading Room Halon system BGE 4-64 RAN 97-031

Calvet Clifs Nclear Power Plad inal Fir Anasis I-dividual Plant Examination External Events could be activated by fire in the Control Room resulting in the isolation of the ventilation system to both cable spreading rooms. 4.8.1.3 Seismic Actuation of Fire Suppression Systems Descriptionof Issue A verification that fire suppression systems have been structurally installed in accordance with good industrial practices and reviewed for seismic considerations such that suppression system piping and components will not fail and damage safe shutdown path components nor is it likely that leaking or cascading of the suppressant will result. Resolution of Issue This issue is considered resolved. Walkdowns were performed that verified fire suppression systems and components are structurally installed with due consideration for seismic events. 4.8.2 Fire Barrier Qualification Description of the Issue Fire barriers and components such as fire dampers, fire penetration seals and fire doors for fire barriers considered in the Fire PRA are included in a plant surveillance and maintenance program. Additionally fire penetration seals have been installed and maintained to address concerns in IE Notice 88-04; and fire dampers have been inspected, installed and maintained to address concerns in IE Notices 83-69 and 89-52. Resolution of Issue This issue is addressed and considered resolved. At CCNPP the barriers required for Appendix R separation are included in a surveillance and maintenance program. The fire penetration seals associated with these barriers have been inspected and evaluated to satisfy concerns raised in IE Notice 88-04. Fire dampers have been inspected and evaluated to satisfy concerns raised in EE Notice's 83-69 and 89-52. Additionally, non Appendix R Fire Barriers which are credited in the CCFPRA are being added to an inspection or control program to ensure the barrier integrity is maintained. See Section 4.3.3.1 and Section 7. 4.8.3 Manual Firefighting Effectiveness Descriptionof the Issue The Sandia Fire Risk Scoping Evaluation addresses a number of attributes of an acceptable fire brigade training and preparedness program. An evaluation of these attributes such as reporting fires, brigade personal and training, practice and drills and records should be performed. Resolution of Issue This issue has been evaluated and is considered resolved. The CCFPRA takes moderate credit for manual firefighting. Such action is credited for Control Room fire scenarios where operators and/or the fire brigade is successful in extinguishing the fire. Credit for manual firefighting was also taken into account in the analysis for determining fire barrier failure probabilities. See Section 4.3.3.2. BOE 4-65 RAN 97-031

Calvert Ciit Nucear Power Plant Internal Fire Analysis individual Plant Examination External Events Nevertheless, the effeciveness of manual firefighting activities at CCNPP was reviewed using Table 4-3 of the EPRI FPRA Guide. Based on a review of the established program for Fire Prevention, Fire Fighting and Strtegies, periodic assessment of the program, and the performance during drills and actual fire events; the plant fire brigade and manual firefighting capability is considered to be effective. 4.8.4 Total Environment Equipment Survival Descriptionof the Issue The Total Environment Equipment Survival issue involves three specific concerns as follows:

                 "    Potential Advcrse Effects of Plant Equipment by Combustion Products

• Spurious or Inadvertent Fire Suppression Activation
• Operator Action Effectiveness 4.8&4.1 Potential Adverse Effects of Plant Equipment by Combustion Products Descriptionof the Issue The immediate effects of smoke and non-thermal fire effects on plant equipment are addressed indirectly by conservatively assuming all equipment within the fire area is disabled by the postulated fire. In cases where a fire scenario does not screen out (i.e. fire modeling is required), explicit treatment of smoke and non-thermal fire effcts is not possible due to lack of industry tests and studies. However, it is assumed that the conservative treatment of fire ignition frequencies, propagation factors and target damage adequately compensates for any uncertainty.

Resolution of Issue This issue is considered to be adequately addressed in CCFPRA. The CCFPRA addresses the impact smoke has on all human actions, on inadvertent Halon actuation and on Control Room evacuation. The impact of smoke on human actions is extensively discussed in Section 4.6.3. The degradation of recovery actions is a significant risk contribution to CCPRA. For the issue of inadvertent Halon actuation, smoke from external sources outside the protected compartment could result in the inadvertent actuation of Halon and the coincident isolation of ventilation. The compartments found to be of concern are the switchgear rooms and cable spreading rooms. Human actions to recover ventilation to these rooms are explicitly modeled. The most interesting aspect of this issue is the potential for the loss of ventilation to critical areas as a result of a fire in a non-critical area such as the turbine building or an outside transformer fire. The evacuation of the Control Room due to smoke is also explicitly modeled. See Section 4.6. By addressing these key issues above, it is believed that the most significant aspects of smoke are capture in CCFPRA. 4.8.4.2 Spurious or Inadvertent Fire Suppression Activation-Description of the Issue Verify that the design of fire suppression systems considers the effects, if appropriate, of inadvertent suppression system actuation and discharge on equipment credited for safe shutdown, for concerns such as those discussed in NRC I & E Information Notice 83-41. BGE 4-66 RAN 97-031

Calvert Cliffs Nuclea Powr Plant neal Fire Analysis Individual Plant Examination Exterml Evcnts Resolution ofIssue This issue is considered resolved. See Section 4.8.1.2. As a result of this evaluation, it is determined that there are no impacts to safe shutdown due to inadvertent actuation of water suppression systems. However, should the Switchgear Room Halon system spuriously activate, it could isolate the ventilation to both the 45' and 27' Switchgear Rooms or the cable spreading rooms. This would require timely operator action to restore ventilation and this has been factored into the CCFPRA. See Section 4.8.4.1. 4.8.4.3 Operator Action Effectiveness Description of the Issue There are safe shutdown procedures identifying the steps for planned shutdown when necessary in the event of a fire, and operators receive training on these procedures. If in the performance of these procedures operators are expected to pass through or perfbnn manual actions in areas that contain fire or smoke, suitable SCBA equipment and other protective equipment are available for operators to perform their function. Resolution of Issue This issue has been evaluated and is considered resolved. Operator actions required at CCNPP in the event of a fire are delineated in AOP-09, Alternate Safe Shutdown/Control Room Evacuation procedures. See Section 4.2.2.4. All licensed and non-licensed operators are trained together at least once each training cycle on these procedures. Additionally, all operator actions are evaluated for possible degradation due to fire impacts on the operators ability to perform their function(s) as described in Section 4.6.1. 4.8.5 Control Systems Interactions Descriptionof the Issue Safe shutdown circuits are physically independent of, or can be isolated from, the control room for a fire in the control room fire area. Resolution of lssue This issue has been evaluated and is considered resolved. The CCNPP Appendix R analysis included a specific assessment of the consequences of a bounding worst case Control Room fire. Such a fire is conservatively assumed to disable all Control Room controls and functions and require operator evacuation of the Control Room area. The evaluation of the scenario, as described in the Appendix R Interactive Cable Analysis (References 4-8 and 4-9), confirmed that safe plant shutdown can be achieved by using available controls and indications located on the Auxiliary Shutdown Panels located in the 45' Switchgear room for each unit. The assessment also confirmed that the circuits associated with these features are located remote to the Control Room or can otherwise be isolated from the Control Room. Additionally, certain safe shutdown components are provided with local/remote switching capabilities to provide local control under certain fire scenarios. RAN 97-031 4-67 DOE BGE 4-67 RAN 97-031

Calvert Cliffs Nucles Power Plant Internal Fire Analysis Individal Plait Examinaton External Events 4.8.6 Improved Analytical Codes The fire modeling methodology for CCNPP uses FIVE worksheets that are based on correlation's used as the foundation for COMPBRN Hie. The worksheets allow for even more conservative assumptions than COMPBRN Ilie to reduce the complexity and number of variables required for calculation. This utilizes look-up tables for quantifying the potential fire exposure to targets. Though some limited uses of the look-up tables have been shown to be less conservative than experimental data, the difference is small and other conservatism's are considered to more than compensate for these differences. 4.9 USI A-45 and other Safety Issues The purpose of this report section is to describe how the CCNPP IPEEE evaluates the Decay Heat Removal Safety Function based on the results from the CCNPP Fire PRA. The evaluation was performed to identify potential decay heat removal vulnerabilities for fire induced initiating events, and to determine if the risk associated with the loss of decay heat removal can be reduced in a cost-effctive manner. The results of this evaluation support closure of Unresolved Safety Issue (USI) A-45. 4.9.1 USI A-45 Background The primary objectives of USI A-45 are to evaluate the adequacy of the decay heat removal systems, determine the benefit of providing an alternate means of decay heat removal, and assess the benefit and cost of alternative measures (See Section 3.2.1) 4.9.1.1 Evaluation The CCNPP IPE addressed the issue of decay heat removal (DHR). With the exception of external events, the CCNPP WPE concluded that USI A-45 is resolved for Calvert Cliffs. This section provides an evaluation of the CCNPP DHR functions with respect to the CCFPRA. During the development of the IPEEE, several fire scenarios revealed potential vulnerabilities. These potential vulnerabilities are addressed by introducing new fire recovery human actions and developing procedure changes to address the control of transient ignition sources in the cable chases and to control and in some cases inspect critical fire barriers. These improvements are identified in Section 7. As a result of these improvements, no other weaknesses are identified. A further review of fire initiating event contributions in the CCFPRA reveals that there are no additional unique decay heat removal vulnerabilities for events initiated at power for CCNPP that were not already identified in the CCNPP IPE. Based on these results, the CCFPRA. has effectively evaluated the DHR function at CCNPP and USI A-45 is resolved. BGE 4-.68 RAN 97-031

Calert CUifMbNuclear Power Plazt Interral Fize Analys Indvidual Plant Examination External Events 4.9.2 Generic Issue 57, "Effects of Fire Protection System Actuation" 4.9.2.1 Generic Issue 57 Background NUREG-1407 requires that the IPEEE address Generic Issue-57, "Effects of Fire Protection System Actuation on Safety-Related Equipment". The NRC staff expects that if a vulnerability in this area is identified through the IPEEE, that the issue will be addressed rather than waiting for the GI-57 resolution. It is expected that during walkdowns information will be collected on whether actuated fire protection systems would spray safety-related equipment and institute proective measures to prevent damage. 4.9.2.1 Evaluation BGE has reviewed GI-57 and related Information Notices for comparisons with site configurations and to identify problem areas. It was determined that single failure of a fire protection system would lead to fire suppressant release in only two cases: Halon systems (smoke detector actuated), and deluge systems (manually-actuated or beat detector actuated). Halon release will not cause equipment damage, although the ventilation dampers to that room will have to be re-opened. Deluge system actuation will release water onto the protected equipment. Deluge systems are installed in the large outdoor transformers. These deluge systems have, in the past, inadvertently actuated with no affect to operability of equipment. The impact of the loss of ventilation on the cable spreading rooms and switchgear rooms is explicitly modeled in the CCFPRA. As a result of BGE's review of GI-57, several changes were implemented.

1) E-406, Electrical Design Standard (Ref 4-20), was changed to require conduit seals.

Holes are also required to be drilled in the bottom of junction boxes in the event of water entry.

2) All compartments protected by automatic sprinklers with open pathways were previously walked down in November 1996 to verify and update of results conducted on 1984 in response to Information Notice 83-41 (Ref 4-21). Electrical equipment in those compartments that could be damaged by water intrusion were identified. As a result of the 1984 walkdowns, modifications (FCR 84-1014, Ref. 4-23) were performed to protect equipment from minor water leakage between fire areas, through sealing conduits and cabinets, and equipping isolation switches with water shields.

The issue and associated information notices are concerned with a non-fire scenario that actuates suppression and causes equipment damage. Most plant systems are wet pipe systems. If a wet pipe system inadvertently actuated (i.e., due to high temperatures or equipment failure) spray down is not considered to be a problem due to electrical installation configuration. Mechanical equipment (such as pumps, valves, and piping) are generally close cased so that water intrusion is not possible. Insulation is provided for hot metal components so that cold sprinkler water will not result in thermal shock. Likewise, electrical equipment is protected by casing or water shields. Cable and conduit is protected by insulation, covered trays, and seals. It is concluded that no additional actions are required to address the issue of spurious actuation of fire suppression systems. These findings were verified during the compartment walkdowns performed in BWE 4-69 RAN 97-031

Calvert Cliffs Nucler Power Plant Ioenial Fire Analysis Individual Plant Examination Extenal Events conjunction with CCFPRA detailed fire modeling cfforts and are documented in the Section 4 compartment evaluation attachments. BGE 4-70 RAN 97-031

Calvert Cliffs Nuclear Power Plant Intmal Fire Analys Individual Plant Examination External Events 4.10 References 4-1 USNRC, Generic Letter No. 88-20, Supplement 4, "Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities", June 28, 1991 4-2 USNRC, NUREG-1407, "Procedural and Submittal Guidance for the Individual Plant Examination of External Events for Severe Accident Vulnerabilities", Final Report, June 1991 4-3 EPRI "Fire PRA Implementation Guide," EPRI TR-105928, Final Report, December 1995 4-4 EPRI "Fire Events Data Base for U.S. Nuclear Power Plants, NSAC-178L, December 1991 4-5 EPRI "Fire-Induced Vulnerability Evaluation (FIVE), EPRI TR-10037, Final Report, April 1992 4-6 BGE, "Calvert Cliffs Individual Plant Examination Summary Report," December 1993 4-7 BGE, Calvert Cliffs Nuclear Power Plant Fire Hazards Analysis Summary Document, Revision 0, June 4, 1997 4-8 BGE, Interactive Cable Analysis for Calvert Cliffs Nuclear Power Plant Unit 1, Revision 6, October 18, 1996 4-9 BGE, Interactive Cable Analysis for Calvert Cliffs Nuclear Power Plant Unit 2, Revision 5 October 18, 1996 4-10 CCNPP Fire Protection Evaluation Program 4-11 CCNPP, Nuclear Program Directive, "Fire Protection Program," SA-l, December 18, 1996 4-12 USNRC NUREG-1335, "Individual Plant Examination: Submittal Guidance," August 1989 4-13 USNRC NUREG/CR-4840, "Procedures for the External Event Core Damage Frequency Analysis for NUREG-1 150, November 1990 4-14 BGE, Calvert Cliffs Nuclear Power Plant Units 1 and 2 Combustible Loading Re-Analysis Calculation, July 1993 4-15 EPRI Economic Risk Management Models for Electrical Equipment Containing PCBs 4-16 "The SFPE Handbook of Fire Protection Engineering", 2nd Edition, Society of Fire Protection Engineering 4-17 BGE, Independent Spent Fuel Storage Installation Updated Environmental Report, Revision I 4-18 BGE, Independent Spent Fuel Storage Installation Updated Evaluation Report, Revision 4 4-19 PLG RISKMAN PRA Workstation Software, Revision 8.0 4-20 BGE, Calvert Cliffs Nuclear Power Plant, E-406, 61-406-A SEC.A05.4 Sheet 1, Revision 0, March 25, 1992 BGE 4-71 RAN 97-031

Calven Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Exmintion Ext*eral Eves 4-21 USNRC Information Notice 83-41, "Actuation of Fire Suppression System Causing Inoperability of Safety-Relatcd Equipment," June 22 1983 4-23 BGE, Calvert Cliffs Nuclear Power Plant, Facility Change Request 84-1014, modifications as a result of USNRC IE Notice 83-41 walkdowns BGE 4-72 RAN 97-031

Calvei Cliffs Nuclear Power Plant hiernal Fire Analysis Individual Plant Examination Extenal Events TABLE 4.6a Unaccounted Frequencies & Sequence Count MFF IE Unaccounted Frq Truncation Sequence Unaccounted Greater Sequence Count Limit Count Than IE.7 Less Than 100 AUX A225F1 6.77E-08 1.19E-04 1.00E-13 458 AUX A225F2 6.76E-08 1.19E-04 1.00E-13 466 AUX A225F3 4.09E-07 2.85E-04 1.00E-12 283 Yes AUX A225F4 1.24E-08 2.52E-06 1.00E-13 136 AUX A318F8 9.94E-08 6.28E-06 1.00E-12 113 AUX A419F1 3.92E-08 3.92E-05 1.OE-13 103 AUX A419F2 5.55E-08 3.92E-05 1.00E-13 798 AUX A419F3 5.77E-09 1.92E-07 1.OOE-13 1516 AUX A419F5 8.01E-10 1.92E-07 1.00E-14 4 Yes* AUX A423F1 2.93E-06 2.11E-03 1.00E-11 638 Yes AUX A423F2 5.60E-08 7.12E-05 1.00E-13 237 AUX A423F3 5.68E-08 7.12E-05 1.OOE-13 238 AUX A423F4 3.76E-08 5.92E-06 1OOE-12 20 Yes AUX A429F1 1.32E-06 2.84E-04 1.00E-11 551 Yes AUX A512F1 1.18E-07 1.93E-04 1.00E-13 955 Yes AUX A512F2 1.11E-07 1.72E-04 1.00E-13 829 Yes AUX A524F1 1.56E-07 1.10E-04 1.00E-12 795 Yes AUX A524F2 4.41E-08 1.03E-05 1.00E-12 469 AUX A524F3 1.82E-07 1.19E-04 1.00E-12 1005 Yes AUX A529F1 2.01E-06 9.91E-04 1.00E-11 942 Yes AUX AUX10A 6.36E-06 4.04E-03 1.00E-11 894 Yes AUX AUX10B 4.92E-06 3.19E-03 1.00E-11 371 Yes AUX AUX10C 5.95E-06 5.88E-03 1.00E-11 408 Yes AUX AUX10D 7.56E-07 7.852E-04 1.00E-12 1127 Yes AUX AUX10E 2.15E-05 6.23E-03 1.OOE-10 500 Yes AUX AUX20A 3.68E-05 2.21 E-02 1.OOE-10 2338 Yes AUX AUX20B 5.99E-06 7.84E-03 1.00E-11 1110 Yes AUX FCA206 6.86E-07 9.29E-04 1.00E-12 266 Yes AUX FCA221 4.23E-07 3.46E-04 1.00E-12 275 Yes AUX FCA227 3.26E-06 4.26E-04 1.00E-10 747 Yes AUX FCA319 4.96E-06 4.19E-03 1.00E-11 441 Yes AUX FCA523 2.13E-05 1.23E-02 1.00E-10 128 Yes AUX FCCMBI 7.65E-08 2.62E-05 1.00E-12 110 AUX FCCMB2 1.68E-09 8.53E-07 1.002-14 14 Yes AUX FCCMB3 9.58E-09 1.56E-06 1.00E-13 71 Yes AUX FCCMB4 9.83E-09 1.61 E-06 1.OOE-13 143 AUX FCCMB5 2.00E-07 5.75E-05 1.00E-12 110 Yes AUX FCCMB6 6.02E-07 1.17E-05 1.00E-10 115 Yes AUX FIA309 5.82E-07 4.84E-04 1.00E-12 373 Yes AUX FIA312 2.94E-06 4.51E-04 1.00E-11 1215 Yes AUX FIA414 2.86E-05 3.28E-03 1.00E-10 281 Yes BIGE 4 -73 RAN 97-031

Calved Cliffs Nuclear Power Plant Interal Fire Analysis Individual Plant Examination External Events TABLE 4.6a Unaccounted Frequencies & Sequence Count (Continued) MFF IE Unaccounted Frq Truncation Sequence Unaccounted Greater Sequence Count Limit Count Than IE-7 Lees Than 100 AUX FIA416 9.13E-06 2.23E-02 1.OOE-11 1041 Yes AUX FIA420 3.11E-06 1.58E-03 1.OOE-11 227 Yes AUX FIA421 2.74E-05 2.23E-02 1.00E-10 144 Yes AUX FIA422 2.70E-06 2.23E-02 1.OOE-10 451 Yes AUX FIA439 2.22E-06 1.24E-03 1.O0E-11 459 Yes AUX FIMAB2 4.01E-07 3.90E-04 1.OOE-12 225 Yes CR A302F1 6.60E-07 9.04E-06 1.00E-11 2938 Yes CR A302F2 4.01E-07 8.28E-05 1.OOE-12 454 Yes CR A302F3 2.01E-08 2.34E-06 1.00E-13 326 CR A302F4 9.89E-08 3.12E-06 1,00E-12 1690 CR A302F5 1.05E-06 3.98E-05 1.0OE-11 863 Yes CR A302F6 7.84E-08 2.34E-06 1.00E-12 1914 CR A302F7 2.56E-07 4.32E-05 1.0OE-12 624 Yes CR A302F8 1.60E-06 1.58E-04 1.OOE-11 289 Yes CR A302F9 1.54E-08 2.01E-06 1.002-13 113 CR A302FA 4.75E-07 9.31E-06 1.00E-11 1113 Yes CR A302FB 2.82E-08 2.45E-06 1.OOE-13 181 CR A302FC 2.62E-07 3.48E-06 1.00E-12 4867 Yes CR A302FM 2.31E-08 3.71E-06 1.OOE-13 38 Yes CR A302FN 1.24E-06 6.29E-04 1.00E-12 1548 Yes CR A306F1 3.18E-07 1.58E-05 1.00E-12 200 Yes CR A306F2 1.88E-05 1.16E-04 1.002-10 1993 Yes CR A306F3 2.25E-07 2.41E-05 3.00E-13 1901 Yes CR A306F4 5.83E-07 2.01E-04 1.OOE-12 2340 Yes CR A306F5 6.69E-07 2.01E-04 1.00E-12 373 Yes CR A306F6 1.66E-09 1.74E-07 1.00E-14 1447 CR A306F7 1.33E-07 4.37E-06 1.00-E12 5851 Yes CR A306F8 7.61E-07 7.59E-06 1.00E-11 2360 Yes CR A306F9 5.36E-08 5.58E-06 i.OOE-13 417 CR A306FA 2.78E-06 4.07E-05 1.00E-11 1269 Yes CR A306FB 2.49E-08 7.36E-07 1.00E-13 49 Yes CR A306FC 1.14E-07 8.52E-07 1.00E-12 6214 Yes CR A306FD 3.01E-06 3.76E-05 1.00E-11 5213 Yes CR A306FE 9.76E-08 1.47E-06 1.00E-12 146 CR A306FF 4.19E-06 3.76E-05 1O0E-10 373 Yes CR A306FG 6.75E-09 7.36E-07 1.00E-14 584 CR A306FH 2.24E-06 3.76E&05 1.00E-11 693 Yes CR A306FI 6.91 E-09 7.36E-07 1.00E-14 931 CR A306FJ 6. 16E-08 3.22E-06 1.00E-12 263 CR A306FK 5.24E-08 3.68E-06 1.00E-13 1060 CR A306FL 2.47E-07 1.43E-06 1.00E-12 1328 Yes BGE 4-74 RAN 97-031

I Calvert Cliff Nuclear Power Plarn Internal Fire Analysis Individual Plant Examination External Evects TABLE 4.6a Unaccounted Frequencies & Sequence Count (Continued) MFF IE Unaccounted Frq Truncation Sequence Unaccounted Greater Sequence Count Limit Count Than IE-7 Less Than 100 CR A306FM 6.53E-07 7.11E-06 1.00E-11 4833 Yes CR A306FN 1.76E-06 6.262E-04 1.O0E-12 1326 Yes CR A306FO 9.47E-08 2.18E-05 1.00-E13 258 CR A405F1 6.83E-06 1.97E-04 1.OOE-10 1383 Yes CR A405F2 3.33E-06 1.58E-04 1.OOE-10 714 Yes CR A405F3 2.06E-06 3.94E-06 1.00E-10 238 Yes CR A405F4 4.17E-06 1.18E-04 1.00E-10 551 Yes CR A405F5 1.76E-06 5.91E-05 1.00E-10 339 Yes CR A406FM 5.40E-06 3.55E-04 1.00E-10 1242 Yes CR A405FN 1.21E-05 1.34E-03 1.OCE-10 3074 Yes CR FCA300 4.09E-06 6.20E-04 3.00E-12 656 Yes CR FlIC03 3.82E-06 7.88E-05 1.00E-10 1227 Yes CR FlIC04 7.98E-06 1.18E-04 1.00E-10 3168 Yes CR FIICO6 3.20E-06 1.18E-04 1.00E-11 1352 Yes CR FI1C07 4.82E-06 1.58E-04 1.00E-10 905 Yes CR FIIC09 2.14E-06 7.88E-05 1.OOE-10 407 Yes CR FIIC1O 1.95E-06 7.88E-05 1.00E-10 401 Yes CR FIIC13 8.69E-07 7.88E-05 1.00E-11 4690 Yes CR FIIC17 3.92E-06 7.88E-05 1.OOE-10 403 Yes CR FIICI8 1.32E-05 7.88E-05 1.00E-10 1538 Yes CR FI1C19 1.83E-05 7.88E-05 1.00E-09 363 Yes CR FI1C20 4.09E-06 7.88E-05 1.00E-10 654 Yes CR F11C34 6.85E-07 3.94E-05 1.00E-11 1293 Yes CR F12C05 4.18E-06 2.36E-04 1.00E-10 963 Yes CR FI2CO9 2.18E-06 7.88E-05 1.00E-10 403 Yes CR FI2C13 1.90E-06 7.88E-05 1.00E-10 391 Yes CR F12C17 2.34E-06 7.88E-05 1.00E-10 403 Yes CR FIA301 5.98E-05 8.48E-04 5.00E-10 307 Yes CR FIA304 4.69E-06 7.92E-04 1.00E-11 469 Yes CR FIA305 3.44E-05 8.84E-04 1.00E-09 319 Yes CR FIA307 5.14E-06 8.14E-04 1.00E-11 378 Yes CR FIC18A 1.24E-06 3.94E-05 1.00E-10 467 Yes CR FIC18B 1.26E-06 3.94E-05 1.00E-10 324 Yes CR FIC19C 5.77E-07 3.94E-05 1.00E-11 1337 Yes CR FIC20A 1.24E-08 3.94E-05 1.00E-10 377 Yes CR FIC20B 1.26E-06 3.94E-05 1.002-10 324 Yes CR FIC24A 3.OOE-06 7.88E-05 1.00E-10 587 Yes INTK INTKFI 6.81E-08 8.10E-05 1.00E-13 2089 INTK INTKF2 7.12E-08 8.10E-05 1.00E-13 4782 INTK INTKF3 1.04E-07 1.62E-04 1.00E-13 2366 Yes INTK- INTKF4 5.00-E08 8.10E-05 1.00E-13 405 BGE 4-75 RAN 97-031i

Calvet Cliffs NucleaI Power Plant Inumal Fire Analysis Individual Plant Examination External Events TABLE 4.6a Unaccounted Frequencies & Sequence Count (Continued) MFF 1E Unaccounted Frq Truncation Sequenm Unaccounted Grater Sequence Count Limit Count Than IE-7 Less Than 100 INTK INTKF5 5.41E-08 8.10E-05 1.00E-13 251 TB A226F1 3.04E-07 1.34E-04 1.00E-12 344 Yes TB A226F2 2.77E-07 1.34E-04 1.OOE-12 298 Yes TB A226F3 1.97E-07 6.67E-05 1.OOE-12 1572 Yes TB A311F1 6.22E-07 4.62E-05 I.O0E-11 522 Yes TB A311F2 3.22E-06 6.97E-04 1.OOE-11 1213 Yes TB A311F3 7.48E-07 9.18E-04 1.OOE-12 1236 Yes TB A317F1 2.96E-06 2.03E-04 1.OOE-11 5450 Yes TB A317F2 9.47E-06 3.46E-04 1.OOE-10 896 Yes TB A317F3 1.22E-06 4.50E-05 1.OOE-11 1265 Yes TB A317F4 1.36E-05 2.84E-03 1.OOE-10 237 Yes TB A317F5 1.17E-06 1.23E-04 1.OOE-11 479 Yes TB A317F6 1.17E-06 1.23E-04 1.OOE-11 479 Yes TB A317F7 1.38E-05 7.44E-04 1.OOE-10 549 Yes TB A317F8 8.98E-07 3.19E-05 1.ODE-11 960 Yes TB A317F9 3.06E-06 3.19E-05 1.00E-10 421 Yes TB A317FA 3.06E-06 5.63E-04 1.00E-11 1223 Yes TB A317FB 1.04E-05 2.54E-04 1.OOE-10 685 Yes TB A317FC 9.91E-07 1.60E-04 1.OE-11 343 Yes TB A407F1 6.83E-07 4.62E-05 1.OOE-11 424 Yes TB A407F2 1,53E-06 2.32E-04 1.00E-11 399 Yes TB A407F3 1.99E-06 4.65E-04 1.00E-11 357 Yes TB A407F4 5.22E-07 5.93E-04 1.00E-12 746 Yes TB A430F1 8.05E-07 5.80E-05 1.00E-11 917 Yes TB A430F2 6.86E-08 4.14E-04 1.O0E-10 274 Yes TB A430F3 7.26E-08 9.24E-05 1.00E-13 926 TB A430F4 6.26E-06 3.03E-04 1.O0E-10 504 Yes TB A430F5 5.60E-07 5.77E-04 1.OOE-12 360 Yes TB A430F6 2.63E-06 4.55E-04 1.OOE-1 1 2448 Yes TB A430F7 2.80E-06 4.96E-04 1.OOE-11 1808 Yes T8 A43OF8 3.91E-06 2.89E-03 1.OOE-11 1452 Yes TB FIT605 5.81E-07 6.97E-04 1.OOE-12 868 Yes TB T603F1 1.63E-07 8.83E-05 1.0OE-12 652 Yes TB T603F2 7.93E-08 1.94E-05 1.00E-12 1447" T8 T603F3 5.78E-07 8.83E-05 1.OOE-11 1398 Yes TB T603F4 3.03E-07 1.94E-05 1.OOE-11 1130 Yes TB T603F5 2.59E-07 2.17E-05 1.O0E-11 412 Yes TB T603F6 4.44E-08 5.74E-05 1.OOE-13 282 TB TBALLB 3.15E-D6 2.91E-04 1.OOE-10 5596 Yes TB TBMFW1 3.94E-05 3.92E-03 1.OOE-10 1407 Yes TB TBMFW2 2.28E-05 3.92E-03 1.OOE-10 2393 Yes BGE 4-76 RAN 97-031

Calvert Clifif Nuclear Power Plant Intertal Fire Anabsis JlnividuaJ Plant Examination External Events TABLE 4.6a Unaccounted Frequencies & Sequence Count (Continued) MFF iE Unaccounted Frq Truncation Sequence Unaccounted Greater Sequence Count Limit Count Than IE-7 Less Than 100 YRD FOCEDG 1.03E-05 2.50E-02 1.00E-11 1546 Yes YRD FIAEDG 9.11E-06 2.63E-02 1.00E-11 2852 Yes YRD FCYRDI 1.45E-07 6.52E-06 1.00E-11 600 Yes YRD FCYRD2 5.77E-07 5.86E-05 1.00E-11 1503 Yes YRD FCYRD3 2.552-08 1.75E-06 1.OOE-12 584 YRD FCYRD4 3.02E-07 4.78E-05 1.00E-12 933 Yes YRD FCYRD5 2.31E-08 1.65E-06 1.00E-12 1382 YRD FCYRD6 1.23E-07 3.86E-05 1.00E-12 136 Yes YRD FCYRDA 4.85E-05 1.12E-02 1.00E-10 1405 Yes YRD FCYRDB 3.86E-05 1.14E-02 1.00E-10 1110 Yes YRD FCYRDC 5.99E-06 3.27E-03 1.00E-11 1003 Yes YRD FCYRDD 1.29E-06 4.24E-03 1.00E-12 1869 Yes YRD FFPPHS 8.74E-06 1.81E-02 1.00E-11 720 Yes TOTAL: 184075 I RAN 97-031 4-77 BGE 4-77 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External E'vets TABLE 4.6b Top Events Top Event Description AA 4KV Bus 14 energized AD 4KV Bus 14 energized AC 4KV Bus 21 energized AD 4KV Bus 24 energized AE 4KV Bus 12 energized AF 4KV Bus 13 energized AL Auxiliary Feedwater maintains system itgrity from the Ist hour to the 24th hour AQ Op starts boration given control rods stock AU Fraction of time a non-PORV challenging MTC exists over core life AV Large Negative Moderator Temperature Coefficient (MTC) Allows ATWS Mitigation BS Turbine Bypass Valves modulate BV Turbine Bypass Valves quick open (4-of-4) CA OP aligns condensate or Fire Protection to either Service Water or Componem Cooling Water given more than enough time CB OP aligns condensate or Fire Protection to either Service Water or Component Cooling Water within 95-119 minutes of plant trip CD OP aligns condensate or Fire Protection to Component Cooling Water within 24 hours, given CKV-105 fails Cl OP starts stand-by NSR Chilled Water Pump CL Cable Spreading Room Dampers close on a CSR fire CR Operator abandons the Control Room due to fire or smoke CS CNTMT Spray Header I I operates as required CT CNTMT Spray Header 12 operates as required CV 2o00 Charging Pumps operate to mitigate an ATWS or to support OTCC CX ESFAS Logic Cabinet A coolg operates CY ESFAS Logic Cabinet B cooling operates DA 125VDC Bus l1 energized for 4 hrs DB 125VDC Bus 12 energized for 4 hrs DC 125VDC Bus 21 energized for 4 hrs DD 125VDC Bus 22 energized for 4 hrs DL Safety Injection provides sufficient flow DM Demineralized water supplies water to Service Water and Component Cooling Water DV ADVs modulate, given the ADVs quick open DW ADVs quick open El 120VAC Vital Panel 11 energized for 4 hrs E2 120VAC Vital Panel 12 energized for 4 hrs E3 120VAC Vital Panel 13 energized for 4 hrs E4 1ZOVAC Vital Panel t4 energized for 4 hrs E5 208/120VAC Instrument Bus I I energized E6 208/120VAC Instn-ment Bus 12 energized EA CSAS Channel A actuates EB CSAS Channel B actuates ES 48VDC Power supply IROIA energized BGE 4-78 RAN 97-031

Calved Ciff Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events TABLE 4.6b Top Events (Continued) Top Event Descrition EW 120VAC Vital Panel I I energized long term EX 120VAC Vital Panel 12 energized long tenr EY 120VAC Vital Panel I3 energized long term EZ 120VAC Vital Panel 14 energized long term FI Auxiliary delivers Feedwaterr adequate flow F Auxiliary O3 Feedwater has adequate inventory F7 Auxiliary Feedwater Pume13 provides adequate flow F9 jAuxiliary Feedwater Pump 23 supplies Unit I with Aux.iliary Feedwater PC jAuxiliary Feedwater Turbine Pump Room cooling operates FF O0perator aligns Auxiliary Feedwatef Turbine P"m Room Emergency Cooling Fans FG Operator recovers all Auxiliary Feedwater Pumps from testing FH Operator st A riartseedwater Salty Pump 13 from the ConArol Room FJ' Operator recovers one Axiliary Feedwater Turbine Pump from testing PN Opetator aligns N2 or starts Salt Water Air Compressors to Auxiliary Feedwatet CVs FO Operator starts U-2 Salt Water Air Compressors and aligns air to U-2 Auxiliary Feedwater CVs FP Fuel Oil Storage Tank 21 provides sufficient fuel oil to EDO 2A & 2B FQ Fuel Oil Storage Tank I I provides sufficient fuel oil to EDOG B & OC FT Feedwater trips (SOIS) FW Operator mans the Auxiliary Shutdown Panel following Control Room abandonment GE EDO IA starts & provides power to 4KV Bus 11 GF EDO 2D starts & provides power to 4KV Bus 24 GO EDO 1B starts & provides power to 4KV Bus 14 GH EDG 2A starts & provides power to 4KV Bus 21 GJ EDGO0C starts & provides power to a 4KV Bus GW Sall Water & Service Water HDR 22 operate OZ Salt Water HDR 21 & Service Water HDR 21 operate H3 OP starts standby Switchgear HVAC train within 45 min. H4 OP starts standby Control Room HVAC HS OP altenates supply to 4KV busses with 13KV on loss of normal 13KV Bus feed to the 4KV bus H6 OP cross-connects MCC 104 & 114 H9 OP x-connects U2 MCCs and aligns one U2 vital 120VAC Bus to the back-up instrument bus HA HP Safety Injection aux header operates RB HP Safety Injection main header operates HC Control Room HVAC dampers remain open HF 27' Switchgear Room IRVAC dampers remain open HG 45' Switchgear Room HVAC dampers remain open HH CRICSR HVAC header operates HL Unit 2 Cable Spreading Room HVAC dampers remain open HP Operator recovers CR/CSR dampers within 3 brs of detection HR Unit 1 Cable Spreading Room HVAC dampers remain open HS SWOR HVAC header operates HU OP re-throttles Auxiliary Feedwater flow given no flow exists in 3 out of 4 Auxiliary Feedwater flow paths 3/4. BGE 4-79 RAN 97-031

Calvert Clif Nuclear Powe Plant Internal Fire Analysis Individual Plait Examination External Events TABLE 4-6b Top Events (Continued) Top Event Descripdou HV OP locally opens ECCS Cooler Salt Water CVs HW HP Safety Injection 12 provides adequate flow to Aux Hdr HX Operator controls Auxiliary Feedwatcr flow from Control Room HZ OP locally ventilates both switchgear rooms with temporary fans Ii Salt Water AC Header 11 supplies adequate air 12 Salt Water AC Header 12 supplies adequate air IA Steam Generator Isolation Signal Ch A actuates M9 Steam Generator Isolation Signal Ch B actuates IC Operator places Component Cooling Water and Service Water Throttle valves in the Open position within 10 minutes of loss of IYO0 or IY02 (Pre-Trip) ID 120VAC Vital Panel fails (Common Cause Inverter failure) after occurrence of a 120VAC Inverter Initiating Event IG Operator successfully controls Pressurizer Level on loss of IY0 or IYOZ (due to LI2VI or 2 initiating event) IH OP staurs both Salt Water Air Compressors during a (LOOP or Non-LOOP) IL Salt Water Air Compressor 11 Header maintains integrity IN Salt Water Air Compressor 12 Header maintains integrity IP SR & NSR CA systems do not become contaminated and common Salt Water Air Compressors piping maintains integrity IZ Salt Water Air Compressor Headers II and 12 supply adequate air JA ESFAS Sequencer I I actuates, no LOCA, all support available IB ESFAS Sequencer 14 actuates K3 Component Cooling Water HX II cools Component Cooling Water K4 Component Cooling Water HX 12 cools Component Cooling Water KS Component Cooling Water maintains inventory KE Component Cooling Water Pump 11 or 13 operates KH OP starts Component Cooling Pump 13, given OP opens Component Cooling HX 12 KI OP aligns stand-by Component Cooling Water HX within 2 hours of a RAS KI OP opens Component Cooling HX 12 and stams Component Cooling Pump 13 given HX II flow path fails KL Component Cooling Water HX flow paths remain open KM Component Cooling Water HX 11 flow path remains open KN Component Cooling Water HX 12 flow path remains open KS Component Cooling Water flow path to the RCP Seals exists KX Component Cooling Water Pump I I operates KY Component Cooling Water Pump 12 operates KZ Component Cooling Water Pump 13 operates LF Op initiates low pressure feed using Condensate MI 480VAC MCC 104R energized M2 480VAC MCC 114R energized M3 480VAC MCC 204R energized M7 480VAC MCC 106T energized M8 480VAC MCC 116T energized MC Main Condensate provides adequate flow MF Operator aligns Salt Water to Service Water within 150 minutes of plant trip MG Operator aligns Salt Water to Service Water within 114-124 minutes of plant trip BGE 4-80 RAN 97-031

Calvert Cliffh Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events TABLE 4-6b Top Events (Continued) Top Event Descmrpfie MH Operator recovers failed steam admission line to Auxiliary Feedwater turbine driven pumps MN MFW is adequate after reactor trip MP MFW ramps back after reactor nip MS Main Steam Isolation Valves shut on SGIS MT Op trips Steam Generator Feed Pumps or throttles flow after S/0 high level trip w/in 30 minmtes MV MOV 659 and 660 remain open MX Operator cross-connects MCC 104 & 114 NI 480VAC Bus IIA energized N2 480VAC Bus lIB energized N3 480VAC Bus 14A energized N4 480VAC Bus 14B energized N5 480VAC Bus 21A energized N6 480VAC Bus 21B energized N7 480VAC Bus 24A energized N8 480VAC Bus 24B energized NR Non-safety related IA/PA supplies Unit I air loads NS Non-safety related IA/PA supplies Unit 2 air loads OP Grid fails to remain energized following a plant trip and over the next 24 hours OT Operator aligns for OTCC and opens PORVs PG Fire Protection provides adequate make-up to Service Water/Component Cooling Water PH Operator isolates PORVs on lowering RCS pressure PN At least one PORV re-closes PS Both PORVs open as required PT Reactor Vessel Failure from PTS PV Both PORVs re-close on low RCS pressure QI OP recovers Auxiliary Feedwater at onset (w/in 10 minutes) of a spurious AFAS block Q5 Operators fail Auxiliary Feedwater Pump Alignment actions (global failure) Q6 Operators fail Auxiliary Feedwater flow control actions (global failure) QC U-4000-11 Service Transformer Provides Adequate Current QD U-4000-21 Service Transformer Provides Adequate Current QE U-4000-12 Service Transformer Provides Adequate Current QF U-4000-22 Service Transformer Provides Adequate Current QQ OP Recovers spurious ESFAS QZ OP recovers Auxiliary Feedwater following a spurious AFAS block R3 Salt Water header I is unavailable R4 Salt Water header 12 is onavailable RA RAS Channel A actuates RB RAS Channel B actuates RE East RWT Header operates RH Operator manually stans Safety Injection equipment following SIAS failure RI Operator recovers ADV control after long term failure of Reactor Regulating System BGE 4-81 RAN 97-031

Calvert Clif Nuclear Power Plant Internal Fire Analysis Individual Plant Examination Extmal Evean TABLE 4-6b Top Events (Continued) Top Evaet Desription RL Service Water maintains adequate inventory RQ Late Manual Reactor Trip successu. RR Reactor Reg. System Channel X controls Ite Atmospheric Dump Valves (ADV$) and Turbine Bypass Valves (TBVs) RS R=actr Trip actuates RU Prssurizer SRVs open as required on high RCS pressure RV Safety Relief Valves (SRVs) re-close on low RCS pressure SI Sall Water nrain 11 supplies flow S2 Salt Water train 12 supplies flow S3 Service Water train I'I supplies flow S4 Service Water train 12 supplies flow SA SIAS Channel A actuates SB SIAS Channel B actuates SC Common Salt Water discharge header operates as required SG Hydrogen purge line operates SH Penetrations less than or equal to 4" function SI Penetrations greater than 4" function SL RCP seals remain intact SP OP starts a stand-by Component Cooling pump within 30 minutes to prevent RCP seal challenge SR Cntnt Normal Sump Drain Line isolates on a LOCA ST OP starts 13 Salt Water Pump within 30 minutes SV Main Steam Safety Relief Valves open on denmnd (8ofl6) SW Main Steam Relief Valves close TI Condensate Storage Tanks II and 21 do not spuriously make up to main condensate TA Service Water Turbine Building header IL provides cooling TB Service Water Turbine Building header 12 provides cooling TE East Containment Sump Supply Header operates TF Auxiliary Feedwater TURB PP I I provides adequate flow TG Auxiliary Feedwater Pump 12 provides adequate flow TH Unavailable Salt Water HDR is recovered within 4 hrs Tr Turbine Stop and Control Valves shut TW West Contro Sump Supply Header operates TX Turbine Trip Bus energized UA IUV Channel A actuates UB IUV Channel B actuates UQ OPs do not underfiUl S/Gs when Auxiliary Feedwater flow control is lost VI ECCS Pump Room Air Cooler I I operates V2 ECCS Pump Room Air Cooler 12 operates V5 ECCS Pump Room Exhaust Fans Operate as Required VB Operator re-loads key equipment shed as part of AOP-9 following Control Room abandonment VC Condenser Vacuum maintained VII Service Water Header II is unavailable BGE 4-82 RAN 97-031

Calvert Cliffs Nuclear Power Plant , Intranal Fire Analysis Individual Plant Examinatio External Events TABLE 4-6b Top Events (Continued) Top Event Descrilpion VI Service Water Header 12 is unavailable VL Fire Brigade suppresses a Control Room panel fire following Control Room evacuation prior to further Control Room panel loss VM OPS starts ECCS Coolers and aligns CVs open from the Control Room W3 Salt Water header 21 is unavailable W4 Salt Water header 22 is unavailable WJ OPS secures sampling line-up. WY Containment Air Coolers (CACs) operate as required (2 of 4) XA 12SVDC Bus 11 energized long term XB 12SVDC Bus 12 energized long term XC 125VDC Bus 21 energized long term XD 125VDC Bus 22 energized long term XW OP supplies a 120VAC Vital Panel from 2081120 VAC Instrument Bus YI 13KV Bus I Ienergized Y2 13KV Bus 21 energized Y3 13KV/4KV Facility A related components do not fault Y4 13KV/4KV Facility B related components do not fault Zi Demineralized Water Storage Tank (DWST) fails due to tornado missile Z2 Condensate Storage Tank (CST) #21 falls due to tornado missile Z3 Condensate Storage Tank (CST) #11 fails due to tornado missile Z4 #11 Pretreated Water Storage Tank (PTWST) falls due to a tornado missile Z5 #12 Pretreated Water Storage Tank (PTWST) fails due to a tornado missile Z6 EDG OC fails due to tomado missile ZD EDG 2A fais due to a tornado missile Z8 EDG IB fails due to a tornado missile Z9 #11 Fuel ON Storage Tank (FOST) fails due to a tornado missile ZA #11 Refueling Water Storage Tank (RWT) falls due to a tornado missile ZB Control Room HVAC and UI Swltchgsw Room HVAC fail due to tornado ZC Unit 1 Service Water Head Tanks fail due to a tornado missile ZD #21 Refueling Water Storage Tank (RWT) falls due to a tornado missile ZE EDG 2B fais due to a tornado missile ZF Unit 2 Swltchgear HVAC fails due to a tornado ZG Unit 2 Service Water Head Tanks fail due to tornado missile ZRH Tank Farm receives point strike and the Fire Protection Building fails RAN 97-031 4-83 BGE 4-83 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events TABLE 4.6c Top 100 Sequences I MPA.. Initiator Core PDS Sequence ... .... Sequence Cumulative Da'Magwe .hpri D~t 1 Turbine TBALLB 2.61E-06 HRIF GE3*RL9 3.58% 3.58% 2 Control F1IC04 1.49E-06 HEM FWIO(I-(HA4*HBDIHWW)) 2.04% 5.62% Room I 1 1 3 Turbine TBALLB 1.46E-06 HRIO CR2 1.99% 7.61% 4 Turbine TBALLB l,46E-06 HRIF HF3 1.99% 9.60% 5 Control FIA305 1.29E-06 HI-P HXA*UQS 1.77% 11.37% Room 6 Control FIA305 1.09E-06 MBIP SLR*HA4 1.49% 12.86% Room III 7 Control A4OSFN 1.02E-06 HRIF CRI*VBI*(I-(RL9+R31+WY4+HX7*SRA+SW3*PT6*HX7)) 1.39% 14.26% Room 8 Turbine TBALLB 1,OOE-06 HHIP F33*(1-(RL9*VM2*VlI+R31*f9+RL9*V14+R3L*GGD)) 1.37% 15.63% 9 Control FIA301 9.92E-07 HHIP HXA*UQS*(1.(MG2*HB4*HWR+IH3*HB4*HWR)) 1.36% 16.99% Room 10 Control FIC19 7.84E-07 HRIF CRIV(-(VLI)) 1.07% 18.06% Room 11 Control FIICIS 7.82E-07 HRIF CRI*(1-(VLI+HX7*SRA+HSV*HX7*SG4)) 1.07% 19.13% Room 1 12 Control A306F2 6.32E-07 HI'P QSI(i-(HSN*HZI+HB4*HWR)) 0.87% 20.00% Room 13 Control A306F2 6.23E-07 HHIP FH2*MH2(I- 0.85% 20.85% Room (MG2*HB4*HWR+IH3*HB4*HWR+HHH*HB4*HWR+QI 14 HB4*HWR)) 14 Turbine TBALLB 5.92E-07 HRIF OGD*HSJ 0.81% 21.66% 15 Control A306F2 5.75E-07 HI'IP HXS*UQ5*(I. 0.79% 22.45% Room (IH3*MG2*HB4*HWR+HHHWMG2*HB4*HWR+HHH*Q 1'* IH3*HB4*HWR+HHH*IH3*CB2*HB4.HWR)) 16 Turbine TBALLB 5.52E.07 HRIF GE3HSO 0.76% 23.21% 17 Control FI1C04 5.34E-07 HHIP TFI*TOE*(t-(H41*HA4HBDHWW)) 0,73% 23,94% Room 18 Turbine TBALLB 5.24E-07 HRIPF 0EP3 D 0.72% 24.66% 19 Control FIA30I 5.OOE-07 HHIP FH5*TFI*TGC 0.69% 25.34% Room 1_1 20 Control F1IC19 4.75E-07 HRIF XW2*GZPFCH 0.65% 25.99% Room 21 Control A405FN 4.50E-07 HRIF CRI*GF3*(I-(RL9+R31+WY4+HX7*SRA+SW3*PT6*HX7)) 0.62% 26.61% Room 22 Control FlIC03 4.30E-07 HHIP TFIOTG5 0.59% 27.20% Room 23 Control A306F2 4.28E,07 HHIP FH2HU2(I-(HHH*QI i*IH3*MG2*HB4*HWR)) 0.59% 27.78% Room I 24 Turbine TBALLB 4.28E-07 HHIP 0E3*TF2 0.59% 28.37% 25 Control A306F2 4.21E-07 HHIP FH2*HXS*(l- 0.58% 28.95% Room (MG2*HB4*HWR+IH3*HB4*HWR+HHH*HB4*HWR+QI 1* HB4*HWR+CB2*HB4*HWR)) 26 Control A405FN 4.17E-07 HRIF CRI*GE3*(I-(RL9+R31÷WY44HX7*SRA+SW3*PT6*HX7)) 0.57% 29.52% Room 27 Control A405FN 4.07E-07 HRIF CR1*W41*(I-(RL9+R31+WY4+HX7*SRA+SW3*PT6*HX7)) 0.56% 30.08% Room BGE 4-84 RAN 97-031

Calvert Clif Nuclear Power Plant homalu Fire Analysk Individual Plant xaminatioa External Event TABLE 4.6c Top 100 Sequences (Continued) 1E. M"F Iniiater Cbre FDM Seq~enm..: . Sequncer Cumlatve Damag . .invortsane importfinte 28 Control FlIC13 4.04E,07 HRIF CRI*HSU,(I-(IX7SRA)) 0.55% 30.63% Room_ 29 Control FIIC19 3.94E-07 HRIF HSI*H91*GZI*HX3FIR 0.54% 31.17% Room ____ _____________________ 30 Control FICISA 3.92E-07 HRIF CRI*(I-(VLl+HSV*H-I*HX7*SRA)) 0.54% 31.71% Room 31 Control FIC20A 3.91E-07 HRIF CRI(1-(VLI-SRA)) 0.54% 32.24% Room 32 Control Fl1004 3.76E-07 HHIP FH7*HX6*FIR 0.52% 32.76% Room I 33 Turbine TBALLB 3.64E-07 HRIF HSB 0.50% 33.26% 34 Aux. Bldg. AUX2OA 3.63E-07 MRIO NRI*SL2 0.50% 33.75% 35 Control A4OSFN 3.40E-07 HRWF CRI*VLIP(I-(HX7*SPA+SW3*PT611X7)) 0.47% 34.22% Room 36 Control A405FN 3.37E-07 HRIO CRI*FFA*(I.(HxT*SRA+SW3*PT6*HX7)) 0.46% 34.68%" Room 37 Control FIIC19 3.27E-07 HRIF XW2*GZ[HXS*FIR*VSE 0.45% _ _ __03 35.13% R oom X4_0_5N 7_ 33 Turbine TBALLB 3.19E-07 HRIF CR2*RL9 0.44% 35.56% 39 Control FIICIS 3.11E-07 IHIP IHI*HX2*FIR 0.43% 35.99% - Room 40 Control A4OSFN 3.02E-07 HRPF CRIOGGD*HSU 0.41% 36.40% Room I I 41 Control FIlCO4 2.96E-07 HHIP D3E 0.41% 36.81% Room 42 Control FIIC19 2.94E-07 HRIF XW2*QII*GZI*HX*FIR 0.40% 37.21% Room 43 Control FIA301 2.88E_07 MBIP SLQ*HB4*HWR 0.39% 37.61% _Room 44 Control A405FM 2.83E-07 HRIF CRI*VBI*(I-(RL9)) 0.39% 37.99% Room 45 Turbine TBALLB 2.79E-07 HRIF R41*HSJ 0.38% 39.38% 46 Control FIA305 2.61E-07 HBlP HXA*UQ5*HA4 0.36% 38.73% Room 47 Control A306FF 2.49E-07 MRiO PVZ*PHZ 0.34% 39.08% Room 1 48 Turbine TBALLB 2.47E-07 HRIF R41*GE3 0.34% 39.41% 49 Control FIICI9 2.44E-07 HHIP Q! I*HXS*UQ5 0.33% 39.75% Room 50 Yard FCYRDA 2.38E-07 HHIP GE3*TFI TGAOF9E 0.33% 40.07% 51 Aux. Bldg AUX20A 2.34E-07 HRIF NIZ*N3Z*N4Z*NSZ*FIR 0.32% 40.39% 52 Aux. Bldg AUX20A 2.34E-07 HRIF NIZ*N3Z*NSZ*N64*FIR 0.32% 40.71% 53 Contrl FIA3Ot 2.30E-07 HHIP FH5*FF2*FCH 0.31% 41.03% Room 54 Control A306F2 2.29E207 HI-P FH2-TFl-TGC 0.31% 41.34% __Room F _ 55 TTubine A317F2 2.23E-07 HH]P TFI*TGA*F9E 0.31% 41.65% 56 Turbine A317F2 2.13E&67 HHIP TFI*TGAOFO2 0.29% 41.94% 57 Control FI1CI9 2.10E-07 HR[F XW2*QII*Q_4-GZI*VSE 0.29% 42.23% Room - __ 58 Control FICI8B 2.03E-07. HIUF CRI*HSU 0.28% 42.51% Room BGE 4-85 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fie Analysis Individual Plant Examinalion External Events TABLE 4.6c Top 100 Sequences (Continued) E& NWFF Initiator Core: PS Sequene .Sequence -. Cumulaitive Dam'ange motne ~prn Vreguency__ ______________ ____ 59 Control FIC20B 2.03E.07 HRIF CRI*HSU 0.28% 42.78% Room 60 Control FlIC04 1.94E-07 HHIP FH7TFITGH 0.27% 43.05% Room I 1__ 61 Control FI1C03 1.94E,-07 HHEP F3E*(i.(CRI+H41MG2*HA4*HID*H* WW)) 0.27% 43.32% Rown 62 Control FI2C05 1.88E-07 HRIF CRI*VB10(1.(RL9)) 0.26% 43.57% Room 63 Yard FCYRDA 1.83E-07 HHEP OE3*TFI*TGA*F02 0.25% 43.82% 64 Control FIlC18 1.80E-07 HRIF OH3*OJOXW2*HX3FIR 0.25% 44.07% Room ____ _____________________ 65 Control FIIC19 I.79E.07 HRIF H31*HSP,*li91Z*HX3*FIR 0.25% 44.31% Room 66 Turbine A317F2 1.78E-07 H1IP 1 IHI*TFIOTGA 0.24% 44.56% 67 Control A405FN 1.77EU07 HRIO CRI*FWP*(I-(HX SRA+SW3*PT6*HX7)) 0.24% 44.80% Room 68 Control A405F 1.73E-07 HRIF CRI-GFS*(..(RL9)) 0.24% 45.04% Room 69 Control FIA301 1.71E-07 HHIP MG2 9FHS*HXA*FIR 0.23% 45.27% Room 70 Control FlIC07 1.68E-07 MBIP NRI*SLZ 0.23% 45.50% Room 71 Control FLA305 1.66E.07 H1-1P F73*TF9*TGC 0.23% 45.73% Room I 72 Control FLA305 1.64E-07 ATWS RS4 0.23% 45.95% Room 73 Turbine A317FB 1.64E,07 HIP TFI*TGA*F9E 0.22% 46.18% 74 Control FIA301 1.62E-07 HHIP IH3*FHS*HXA*FIR 0.22% 46.40% Room 1 _ 75 Turbine TBALLB 1.60E.07 HRIF CR2*GF5 0.22% 46.62% 76 Control FIlC8 I1.59E-07 HRIF W31*GJGOXW2*aX3*FIR 0.22% 46.84% Room 77 Turbine A317F9 1.5SE-07 MRIO SLY*(I.(JB3+GGD+R41)) 0.22% 47.05% 78 Control A306FD 1.58E-07 MRIO PVZ*PHZ,(I-(WY3+HW7)) 0.22% 47.27% Room 79 Control A405F1 1.57E-07 HRIF CRI*VBIO(I-(RL9)) 0.21% 47.49% Room I I 80 Turbine A317FB 1.57E,47 HHIP TF1*TGA*F02 0.21% 47.70% 81 Aux. Bldg. FCA227 1.51E-07 HHIP NRI*IHI 0.21% 47.91% 82 Turbine TBALLB 1.49E,07 HHIP GE3*HX2 0.20% 48.11% 83 Turbine TBALLB 1.46E-07 HRIF CR2*VBI 0.20% 48.31% 84 Control A405FN 1.43E-07 HRIF CR1*R410HSU 0.20% 48.51% Room 85 Yard FCYRDA 1.42E-07 HHIP GE3*IHI6TFI*TOA 0.19% 48.70% 86 Turbine A317F9 1.42E-07 HRIO QZ2*(I-(JB3+GGD+R41)) 0.19% 48.89% 87 Turbine T603F3 1.42E-07 MGIP F73*F9X 0.19% 49.09% 88 Turbine A317F7 1.38E-07 ATWS RS4 0.19% 49.28% 89 Control A405FN 1.36E-07 HRIO CRl*TF2*TGG 0.19% 49.46% Room - - BGE 4-86 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events TABLE 4.6c Top 100 Sequences (Continued) lr MW. Initiator Core PDS -Sequence Sequence. Cunmulatwe

                                                                              .mportance Importance 90     Control      FIICI8       1.35E.07   HHIP TFI*TGAOFO2                     0.18%            49.65%

Room 91 Control A306F2 1.32E-07 HBIP QSI*HB4*HWR 0.18% 49.83% Room 1 _ 92 Turbine A317F1 1.31E-07 HHIP TFI*TOA*F9E 0.18% 50.01% 93 Turbine A317FB 1.31E-07 HHIP 1HIrFFI*TOA 0.13% 50.19% 94 Turbine TDALLB 1.28E-07 HHIP F72*TFA 0.13% 50.36% 95 Control FIA301 1.28EF07 HBIP MG2*HXA-UQS*HB4*HWR 0.17% 50.54% Room 96 Yard FCYRDA 1.27E-07 HRIF DAIXW2*HX3*FIR 0.17% 50.71% 97 Turbine TBALLB 1.27E-07 HHIP GE3*FFI 0.17% 50.89% 98 Control A405F2 1.26E-07 HRIF CRI*VB1'(l4RL9)) 0.17% 51.06% Room _ 99 Control FIIC07 1.26E-07 HRIF CRI*VBI*(IL.( )) 0.17% 51.23% Room 100 Turbine A317FI 1 .25E-07 FRHIP TFI-TGA-FO2 0.17% 51.40% RAN 97-03 1 4-87 BGE 4-87 RAN 97-031

Calvert Cliffs Nuclear Power Plant Iternal Fire Analysis Individual Plant Examination External Events TABLE 4.6d Split Fraction Descriptions PLANT AUX TB FIRE INTAKE OUTSIDE CONT RM MODEL SPLIT FRACTION DESCRIPTION BLDG MFF FIRE MFF MFF FIRE FIRE MFF SF FIRE MNF CB2 OP aligns condensate or FP toe ither SRW or 1.07E-01 I,07E-0I 5.96F-02 5.96E-02 3.07E-01 CCW within 95-119 minutes of plant trip, EOP-8 or LOCA CRI Operations abandons Control Room, given Control 1.02E-02 1.02E-02 1.02E-02 1.02E-02 1.02E-02 Room Panel Fire CR2 Control Room HVAC goes into recirculation, 5.OOE-03 5.OOE-03 5.OOE-03 5.00E-03 5.OOE-03 given tire which enters HVAC DAI 125VDC Bus 11 energized for 4 brs, LOOP and 5.75E-04 5.75E-04 5.75E-04 5.75E-04 5.75E-04 all supports available FIR AFW delivers adequate flow, given SBO with S/G 5.74E-01 5.74E-01 4.79E-01 4179E-01 7.06E-01 _overfill F33 AFW has adequate inventory (includes op action 2.1 IE-03 3.47E-03 2.1lE-03 2.1 IE-03 2.11 E-O3 for tank switchover) given no indication F3E AFW has adequate inventory (includes op action 2.51E-03 2.51E-03 2.51E-03 2.51E-03 2.51E-03 for tank switchover), shutdown from the Auxiliary Shutdown Panel - otherwise boundary conditions per F31, F32 or F3D1 F72 AFW Pump 13 provides adequate flow, given 9.23E-03 9.23E-03 9.23E-03 9.23E-03 9.23E-03 Operators recover from all testing (FG=S), 4KV Bus 11 losses offsite power from U4000-1 1, the Shutdown Sequencer Ch. A (JA) is successful, and the operators fail to manually start the AFW Pump locally or remotely F73 AFW Pump 13 provides adequate flow, given 8.95E-03 8.95E-03 8.95E-03 8.95E-03 8.95E-03 Operators recover from all testing (FG-S), 4KV Bus 11 provided offsite power from U-4000-11 (QC=S), and the operators fail to manually start the AFW Pump locally or remotely (FH=F). F9E AFW Pump 23 supplies Unit I with AFW, given 5.72E-02 6.30E-02 5.72E-02 5.72E-02 7.61E-02 either (1)13 AFW PP not? & at least one of II & 12 AFW PPs fails or (2) 12 & 13 AFW PPs succ and 11 fails; Also DC Bus 1 avail, U2 MEW not avail, Op action to recover testin succ F9X AFW Pump 23 supplies Unit I with AFW, given 1.76E-01 1,79E-01 1.76E-01 1.76E-0l 1.87E-01 AFW PPs II, 12, & 13 fail, DC Bus II avail, Op action to recover from testing sucessful, U2 MFW succ/fail FCH AFW PP RM cooling operates, given a SBO 3.66E-03. 9.60E-03 3.66E-03 3.66E-03 3.02E-02 condition,EOP8 FFI Operator aligns AFW Turbine Pump Room 1.86E.02 1.06E-02 1.06E-02 1.06E-02 4.69E-02 Emergency Cooling Fans, ASA FF2 Operator aligns AFW Turbine Pump Room 9.32E-02 5.32E-02 5.32E-02 5.32E-02 2.35E-01 Emergency Cooling Fans, EOP-8 FFA Operator aligns AFW Turbine Pump Room 2.47E-02 2.47E.02 2.47E-02 2.47E-02 2.47E-02 Emergency Cooling Fans, given CR evacuation land S/D from Aux S/ID Panel FH2 Operator starts AFW Pump 13 locally, ASA 3.82E-02 5.41E-02 3.82E-02 3.82E-02  !.28E-01 FH5 Operator starts AFW Pump 13, given fire in the 3.82E-02 3.82E-02 3.92E-02 3.82E.02 3.82E-02 CSR and dampes isolate fire - BGE 4-88 RAN 97-031

Calvert Cli5 Nuclear Power Pl Interal Fire Analysis Individual Plait Examination External Event TABLE 4.6d Split Fraction Descriptions (Continued) PLANT AUX TB FIRE INTAKE OUTSIDE CONT RM MODEL SPLT FRACTION DESCRIPTION BLDG MFF FIRE MFF MFF FIRE E MFF SF FIRE NW FH7 1Operator starts AFW Pump 13 locally, CR 1.28E-01 1.28E-01 1.281-01 1.28E-01 1.28E-01 evacuated to Aux Shutdown Panel FO2 Operator starts U-2 SWACs and aligns air to U-2 4.39E-02 6.021E-02 4.391-02 4.39E-02 1.23E-01 AFW CVs, given: support available to at least one Unit 2 SWAC, a Ul SWAC is succ and other Ul SWAC succ or not?, FN (Op aligns N2 or starts SWACs) & IH(Ops starts both SWACs) are not questioned or succ FWl Auxiliary Feedwater control transferred to the 1.30E.-02 1.30E-02 1.30E-02 1.30E-02 1.30E-02 Auxiliary Shutdown Panel (Control Room Evac) GE0 EDG IA starts & provides power to 4KV Bus 11, 2.81E-02 2.81E-02 2.811-02 2.81E-02 2.81E-02 LOOP < I hour (INIT=LOOP I), ASA GE3 EDO IAstarts&providespowerto4KVBus II, 4.10E-02 4.10E-02 4.10E-02 4.1OE-02 4.10E-02 LOOP initiating events between 2 and 4 hours, and 4KV electrical power losses which occur post

           .trip, (ASA)

GF3 EDG 2B starts & provides power to 4KV Bus 24, 4.42E-02 4.42E-02 4.422-02 4.42E-02 4.42E-02 LOOP initiating events between 2 and 4 hours, and 4KV electrical power losses which occur post trip, (ASA) GF5 EDG2B starts & provides power to 4KV Bus 24, 1.IOE-0l 1.10E-01 1.10E-01 1.10E-O1 1.101-01 LOOP > 11 hours, (ASA) GGD EDG IB starts & provides power to 4KV Bus 14, 4.39E-02 4.39E-02 4.39E-02 4.39E-02 4.39E-02 LOOP initiating events between 2 and 4 hours, and 4KV electrical power losses which occur post trip, EDG 2B succeeds or not ?d, (ASA) GH3 EDG 2A starts & provides power to 4KV Bus 21, 4.51E-02 4.51E-02 4.51E-02 4.51E-02 4.51E-02 LOOP initiating events between 2 and 4 hours, and 4KV electrical power losses which occur post trip, EDG IB & 2B not ?d or succeed, ASA GJG EDG 0C starts & provides power to a 4KV Bus, 2.311-01 2.36E-01 2.31E-01 2.921-01 4.211-01 LOOP > 11 hours, EDO IA not ?d, ASA GZI SW HDR 21 & SRW HDR 21 operate, given one 5.49E-01 6.49E-01 5.49E-01 5.49E-01 9.64E-01 or more of the preceding SW & SRW HDRs fail (including SW/SRW 22 HDR - GW), Unit 1 Inventory (RL) not questioned, Dentin fails, Unit 2 SW provides makeup to SRW H31 OP starts stand-by Switchgear HVAC train within 1.59E-02 8.57E-03 8.57E-03 8.57E-03 3.92E-02

            ,45 min., no LOOP H41 OP starts stand by Control Room HVAC, no                    2.29E-01     2.29E-01   2.29E-01   2.29E-01      4.91E-01 LOOP H91       OP x-connects U2 MCCs and aligns one U2 vital          1.01B-01    7.37E-02    7.37E-02  7.37B-02      2.07E-01 120VAC Bus to the back-up instrument bus, LOOP                                                            I                                                   I HA4 HPSI aux header operates, low sump terperature, 4.82E-02                 4.82E-02   4.82E-02   4.82E-02      2.02E-01 no LLOCA, EOP8 11B4 HPSI main header operates, low sump                         4.79E-02    4.791-02   4.791-02   4.79E-02      2.01E-01 temperature, no LLOCA, aux header not questioned, EOP8 BGE                                                              4-89                                          RAN 97-031

Cvat Cliffs Nuclear Pow"r Plait Intenul Fire Aalysis fndividual Ptant Examination Extrnal Events TABLE 4.6d Split Fraction Descriptions (Continued) PLA4T AUX TB FIRE INTAKE OUTSIDE CONT RM ODEL SPUT FRACTION DESCRIPTION BLDG 1FF FIRE 11FF M? FIRE FIRE MFF S P_ _ _ _ _ _ FIRE 11FF ____ N___ ME MY HBD HPSI main header operates, low sump 1.12E-01 i,12E-01 1.12E-01 1.12E-Ol 1.73E-01 temperature, no LLOCA, aux header fails, (ASA) I

   -F3     27 Switchgear Room HVAC dampers remain                5.00E-03    5.OOE-03     5.OOE-03   5.00E-03      5.OOE-03 open, given an outsidellB fire produces smoke which challanges the outside air intake HH8      CR/CSR HVAC header operates, LOOP, OP fails           5.04E-01    5.04E-01     5.04E.01   5.04E-01      5.04E-01 to start stand-by A/C, one A/C header provided power with required support DA(DC)=S and
           .JA(JD-S for that header                                        I HHH       CR/CSR HVAC header operates, no LOOP, OP              5.0IE-O1     5.0lE-0l    5.01E-01   5.01E-01      5.01E-0l fails to start stand-by A/C and support to NSR chiller & one A/C header lost HSB       SWGR HVAC HDR OPERATES given both                     1.25E-03    1.25E-03     1.25E-03  1.25E.03      1.25E-03 HVAC trains have support; electrical power is momentarily lost to 4KV Bus II and/or 14 due to LOOP or XFMER failure; Operator can start standby   train; istnruent Air available or not.

HSI SWGR HVAC HDR OPERATES given HVAC 4.32E-02 4.32E-02 4.32E-02 4.32E-02 4.32E-02 train 12 is failed due to loss of support; HVAC train II has support; 4KV XFMER II and Bus 11 remain energized; Operator can start standby train; Instrument Air available or not questioned. f HSJ SWOR HVAC HDR OPERATES given HVAC 4.63E-02 4.63E-02 4.63E-02 4.63E-02 4.63E-02 train 12 is failed due to loss of support, HVAC train II has support; 4KV XFMER 11 failure or LOOP causes momentary loss of 4KV Bus 11; Operator can start standby train; Instrument Air available or not questioned. HSN SWGR HVAC HDR OPERATES given HVAC 4.32E-02 4.32E-02 4.32E-02 4.32E-02 4.32E-02 train 1I is failed due to loss of support; HVAC train 12 has support; 4KV XFMER 21 and Bus 12 remain energized; Operator can start standby train; Instrument Air available or not questioned. HSO SWGR HVAC HDR OPERATES given HVAC 4.63E-02 4.63E-02 4.63E-02 4.63E-02 4.63E-02 train 1I is failed due to loss of support; HVAC train 12 has support; 4KV XFMER 21 failure or LOOP causes momentary loss of 4KV Bus 12; Operator can start standby train; Instument Air

           ,available or not questioned.

HSR SWOR HVAC HDR OPERATES givn HVAC 5.01E-01 5.01E-01 5.01E-01 5.01E-01 5.01E-01 train 12 is failed due to loss of support; HVAC train 11 has support; 4KV XFMER 1I and 4KV Bus 11 remain energized; Operator fails to start standby train; Instrument Air available or not question. BGE 4-90 RAN 97-031

Calver Cliffs Nuclear Power Plant bnteal Fire Analyusi Individual Plant Examiation External Evema TABLE 4.6d Split Fraction Descriptions (Continued) PLANT AUX TB FIRE INTAKE OUTSIDE CONT RM MODEL SPLIT FRACTION DESCRIPTION BLDG M1FF FIRE MFF MFF FIRE FIRE MFF SF FIRE MFF HSU SWORHVAC HDR OPERATES given HVAC 5.04E-0I 5.04E-01 5.04E-01 5.04E-01 5.04E-01 train 12 fails due to loss of support; HVAC train I I has support; 4KV XFMER 11 failure or LOOP causes momentary loss of 4KV Bus 11; Operator fails to start standby train; Instrument Air available or not not questioned. HSV SWGR HVAC HDR OPERATES given HVAC 5.04E-01 5.04E-01 5.04E-01 5.04E-01 5.04E-01 train I1 is failed due to loss of support; HVAC train 12 has support; 4KV XFMER 21 failure or LOOP causes momentary loss of 4KV Bus 12; Operator fails to start standby train; Instrunent Air available or not questioned. ,, HU2 OP re-throttles AFW flow given no flow exists in 3.56E-03 3.56E-03 3.56E-03 3.56E-03 2.93E-02 3 out of 4 AFW flow paths, EOP-8 HW7 HII 12 provides adequate flowtoAuxHdr, 1.55E-01 1.41E-Ol 1.41E-01 1.41-01 3.53E-01 given 11 HPSI not 7d, 13 not ?'d or succeeds, low sump temp, EOP8 HWR HJPSI 12 provides adequate flow to Aum Hdr, 4.66E-01 3.39E-01 3.39E-01 3.39E-01 8.58E-01 given 11 HPSI fails, 13 not 7d or succeeds, high sump temp, EOP8 _ HWW HPSl 12 provides adequate flow to Aux Hdr, 5.15E-01 3.77E-01 3.77E-01 3.77E-01 8.77E-01 given 11 & 13 HPSI fail, high sump temp, EOPS HX2 Operator controls AFW flow locally due to CR 2. 1OE-02 1.25E-02 1.25E-02 1.25E-02 4.94E-02 AFW Flow control support unavailable for either flowpath where flow exists HX3 Operator controls AFW flow locally due to CR 6.59E-01 5.60E-01 5.60E-01 5.60E-01 8.22E-01 AFW Flow control support unavailable for either flowpath where flow exists, and no S/G level ind avail, EOP-O8 M-I5 Operator controls AFW flow locally due to CR 2. 10E-02 1.25E-02 1.25E-02 1.25E-02 4.99E-02 AFW Flow control support unavailable for either flowpath where flow exists, S/G Level lad avail, EOP-08 0HX6 Operator controls AFW flow locally due to CR 3.53E-02 3.53E-02 3.53E-02 3.53E-02 3.53E-02

            'AFW Flow control support unavailable for either flowpath where flow exists, shutdown from Auxiliary Shutdown Panel HX7 Operator controls AFW flow locally due to CR              8.08E-01    8.08E-01    8.08E-01    8.08E-01      8.08E-01 AFW Flow control support unavailable for either flowpath where flow exists, and no 8/0 level ind avail, EOP-08, given shutdown from the Auxilairy Shutdown Panel HXA Operator controls AFW flow locally due to CR              1.25E-02    1.25E.02     1.25E-02   1.25E-02      1.25E-02 AFW Flow control support unavailable for either flowpath where flow exists, S/G Level Ind avail, EOP-08 and CSR fire that is isolated HZI OP locally ventilates both Swgr Rms using                 3.73E-02    5.84E-02     3.73E-02   3.73E-02      1.04E-01 temporary fans, no LOOP                                      I                                     I 1H1 OP starts both SWACs during a (LOOP or Non-              3.41&-02    5.03M-02     3.41E-02   3.41E-02      1.13E-01 LOOP), non-EOP-08 12!a                                        I                   ----

BGE 4-91 RAN 97-031

Calver Cliffs Nuclear Power lait htarna Fire Analysi Individual Plant Examrinutio Exurnal Events TABLE 4.6d Split Fraction Descriptions (Continued) PLANT AUX TB FI INTAKE OUTSIDE CONT RM MODEL SPLIT FRACTION DESCRIPI'ON BLDG MFF FIRE MFF MFF FIRE FIRE M'F SF Fre ME N IH3 OP starts both SWACs during a LOOP or NON- 1.70E-0I 2.52E.01 1.70E-01 1.70E-01 5.66E-01 LOOP, EOP8 JB3 ESFAS Sequencer 4 actuates, Sequenoer 11 4.AOE-02 4.40E.02 4.40E,02 4.40E-02 4.40E-02 failed, no LOCA. (ASA) _ 1 M02 Operator aligns SW to SRW within 114-124 1.82E-01 2.82E-O1 1.82IeO1 1.82E-01 5.97E-01 minutes of plant trip, EOP-8 MR2 Operator recovers failed steam admission line to 9,52E-03 9.52E-03 9.52E-03 9.52E-03 6.75E-02 AFW turbine driven pumpsM EOP-NIZ 480VAC Bus 1 A energized, during a fire or flood 8.64E-04 8.64E-04 8.64E-04 8.64E-04 8.64E-04 (7 bkrs chalenged) I N3Z 490VAC Bus 14A energized, Buses I IA & 11B 2.SOE-01 2.50E-01 2.50E-01 2.50E.01 2.50E-01 fail, all support available, fire or flood (6 bkrs challenged) N4Z 480VAC Bus 14B energized, Buses I IA, I 1B & 2.85E-01 2.95E-01 2.,5E-01 2.85E-01 2.85E-01 14A fail, all support available, fire or flood (8 bkrs challenged) N5Z 480VAC Bus 21A energized, given all four Unit 3.00E-0l 3.OO0-l 3.OOE-0l 3.OOE-O1 3.00E-01 I 490V Buses (NI-N4) fail, ASA, fire or flood (3 bkrs challenged) N64 480VAC Bus 21B energized, given three of 2.84E-01 2.84E-01 2.84E-01 2.84E-01 2.84E-01 previous questioned buses (Unit I 4B0V Buses NI-N4 and 21A - NS) and others succeed or not questioned, ASA NRI Non-safety related IA/PA supplies Unit I air 1.04E-02 1.04E-02 1.04E-02 1.04E-02 1.04E-02 loads, no LOOP, ASA including PA Compressor 21 PHiZ Operator isolates PORVs on lowering RCS 3.72E-02 3.72E-02 3.72E-02 3.72E-02 3.72E.02 pressure, both PORVs spuriously open, both MCCs available, given CSR fire where dampers isolate CSR PT6 Reactor Vessel Failure from PTS. Large SLB 4.OOE-03 4.OOE-03 4.OOE-03 4.OOE-03 4.OOE-03 PVZ Both PORVs re-close on low RCS pressure, both 1.78E-01 1.78E.01 1.78E-01 1.78E-01 1.78E-01 PORVs spuriously open, both MCCs available, CSR fire where dampers isolate CSR Qli OP recovers AFW at onset (w/in 10 minutes) of a 2.37E-01 2.37E-01 2.37E-01 2.37E-01 5.30E-01 spurious AFAS block (Cowboy) I Q51 Operators fail AFW Pump Alignment actions 8.88E-04 8.&SE-04 8.88E-04 8.88E-04 6.62E-03 (global failure) QZ4 JOP recovers AFW following a spurious AFAS 7.47E-03 7.47E-03 7.47E-03 7.47E-03 4.26E-02 block, given PORVs open on SSSA R31 SW header I I is unavailable 2.07E-02 2.07E.02 2.07E.02 2.07E-02 2.07E-02 R41 SW header 12 is unavailable 2.07E-02 2.07E-02 *2.07E-02 2.07E-02 2.07E-02 RL9 SRW maintains adequate inventory, no support 2.19E-01 2.19E.01 2.19E-01 2.19E.01 2.19E-01 available RS4 Reactor Trip actuates, one or more of 120VAC 1.86E-04 1.86E-04 1.86E.04 1.86E3-04 1.86E-04 Vital Panel I1l&12 fails and one ofthe 125VDC Buses fails S4 Hydrogen purge line operates, no support 1.15E-03 1.15E-03 l.1 5E-03 .1SE-03 1.15E-03 3available - - -- BGE 4-92 RAN 97-031

Calvert CiffsM Nuclear Power Plaot Intenial Fire Analysis Jndiidual Plat Exuaiton External Events TABLE 4.6d Split Fraction Descriptions (Continued) PLANT AUX TB FIRE INTAKE OUTSIDE CONT RM MODEL SPLIT FRACTION DESCRIPTION BLDG MFF FIRE MFF MFF FIRE F]RE MFF SF FIRE WFF SL2 RCP seals remain intact given RCPs are secured 1.58E-03 1.58E-03 1.58E-03 1.58E.03 2.21E-03 byOP when CCW fails, post trip, 125VDC Bus II &21 (DA &DC)and 120VAC Buses II and 12 EI & -2) available, not EOP-08 SLQ RCP seals remain intact given RCPs are locally 1.97E-03 1.97E-03 1.97E-03 1.97E-03 1.97E.03 secured by the OPs, 125VDC Bus 21 and 120VAC Buses 1 & 12 available, CSR fire which is isolated SIR RCP seals remain intact given RCPs are secured 6.09E-03 6.09E-03 6.09E-03 6.09E-03 6.09E-03 by a loss of power (including LOOP), given CSR fire which is isolated (SL9 with CL=S) SLY RCP seals remain intact, given Operators secure 5.56E-03 5.56E-03 5.56E-03 5.56E-03 5.56E-03 RCPs from the Metal Clad SLZ RCP seals remain intact, given RCPs are never 1.02E-01 1.02E-OI 1.02E-OI 1.02E-OI 1.02E-01 secured SRA Cntt Normal Sump Drain Line isolates on a 2.01E-03 2.01E.03 2.01E-03 2.01E-03 2.01E-03 LOCA, no support available I SW3 Main Steam Relief Valves close, all banks re- I.46E-Ol 1.46E-01 1.46E-Ol 1.46E-01 1.46E-01 close & modulate when "BVs (or TBVs & ADVs) fail to quick open, ADVs and TBVs fail to modulate long term TFM AFW TURB PP 11 provides adequate flow given 3.17E-02 3.17E-02 3.17E-02 3.17E-02 3.17E-02 _PP 13 successful or noted, OP actions successful TF2 AFW TURB PP 11 provides adequate flow, given 3.59E-02 3.59E-02 3.59E-02 3.59E-02 3.59E-02 PP 13 successful or notTed, TURB Rec fails TF9 AFW TURB PP II provides adequate flow given 4.30E-02 4.30E-02 4.30E-02 4.30E-02 4.30E-02 PP 13 fails, OP actions successful TFA AFW TURB PP 11 provides adequate flow given 4.76E-02 4.76E-02 4.76E-02 4.76E-02 4.76E-02 PP 13 fails, TURB Rec fails TG5 AFW Pump 12 works, AFW PP I I fails and 13 1.28E-01 1.39E-01 1.28E-01 1.28E-O0 1.72E-01 suc, Turb pump maint recovery succeeds TGA AFW Pump 12 works, AFW PP II fails and 13 2.86E-01 3.23E-01 2.86E-01 2.86E-01 4.39E.01 fails, Op actions succeed TGC AFW Pump 12 works, AFW PP II fails and 13 3.55E-01 3.87E-01 3.55E-01 3.55E-01 4.87E-01 fails, Turb Rec from maint success, EOP8 I a TOE AFW Pump 12 works, shutdown from Aux Shut 1.45E-01 1.45E-01 1.45E-01 1.45E-01 1.45E-01 Panel given either 1. AFW PP II successful & 13 fails, EOP8 - OR- 2. AFW PP Il fails and 13 succ, Tuirb pump maint recovery succeeds (comb of T04 & TG5 for remote s/d) TGG AFW Pump 12 works, shutdown from Aux Shut 2.78E-01 2.78E-01 2.78E-01 2.78E-01 2.78E-01 Panel - otherwise given TG3, 6, 7, or 8 boundary conditions TGH AFW Pump 12 works, shutdown from Aux Shut 4.06E-01 4.06E-01 4.06E-01" 4.06E-01 4.06E-01 Panel - otherwise given TG9, A. B, or C boundary conditions UQ5 OPs do not underfill S/Gs when AFW flow control 5.31E-02 4.04E-02 4.04E-02 4.04E-02 1.17E-01 is lost, given: S/G Level lId avail, remote flow control failed, EOP-8 - - - BGE 4-93 RAN 97-031

Culvert Cliu Nude.ar Power Plait Intmal Fire Analyms Individual Plant Examinc Exiternal Events TABLE 4.6d Split Fraction Descriptions (Continued) PLANT AUX TB FI INTAKE OUTSIDE CONT RM MODEL SPLIT FRACTION DESCRIPTION BLDG MFF FIRE MIT Mu FIRE FIRE MIT SF FIRE MNW VII ECCS Pump Room Air Cooler II operates, OCA 1.10E-01 1.10E-01 1.10E-01 1.10E.01 1.10E-01

           <0.02 sq. ft. operator recovery fails, (ASA)

V14 ECCS Pump Room Air Cooler II operates, all 1.17E-02 1.17E-02 1.17E-02 1.17E-02 1.17E-02 rator recoveries sce __,A_ VWE ECCS Pump Room Exhaust Fans Operate as 1.81E-01 1.S1E-01 1.81E-01 1l.8E-O 5.90E-01 Required, MCC 104Ror 14R avail, temploss of power (QC &/or QD=S) to available MCC, Op actions to align ECCS coolers fail or VI & V2 fail or comb, EOP-08 VBI Electrical Realignment on AOP-9 perfonned 1.00E-0 1.00E-01 1.00E-01 1.00E-01 1.OOE.01 succesfully on Control Room Evacuation VLi Fire Brigade supresses Control Room Panel fire 1.00E-02 1.00,E02 1.00E-02 1.00,E02 1.00E-02 within 30 minutes (prior to fire involving further

           ,anels)

VM2 OPS starts ECCS Coolers and aligns CVs open 3.20E-02 3.20E-02 3.20E-02 3.20F-02 1.61E-0I from the Control Roomi, EOP-8 W31 SW header 21 is unavailable 4.OOE-02 4.OOE-02 4.OOE-02 4.OOE-02 4.OOE-02 W41 SW header 22 is unavailable 4.OOE-02 4.OOE-02 4.OOE-02 4.OOE-02 4.OOE-02 WY3 CACs operate as required (2of4), no LOOP with 1.29E-02 1.28E-02 1.28E-02 1.28E-02 I .28E-02 _support for 2 of 4 CACs failed WY4 CACs operate as required (2of4), LOOP with 1.33E-02 1.33E-02 1.33E-02 1.33E-02 1.33E-02 support for 2 of 4 CACs failed I I XW2 OP supplies a 120VAC Vital Panel from 208/120 1.01E-01 7.37E.02 7.37E-02 7.37E-02 2.07E-01 VAC Instrument Bus, given MCC 104R is available RAN 97-031 4-94 BGE 4-94 RAN 97-031

Calver Cliffs Nuclear Power Plant lucaial Fire Analysis Individual Plant Examination External Events Table 4.7 Frequencies of Major Containment Failure Categories HRIF HGIP MMO MRIO MRIF HRWF ATWS MCIF LDIO HRSF Contahmnent Failure Category Percemtage Totals 3.67E-05 2.42E-05 3.OOE-06 2.52E-06 2.22E-06 2-34E-06 1.16E-06 5.20E-07 4.25E.07 1.24E-07 Intact Cmoaimnent 37.1% 2.67E-05 2.1RE.05 2.32E-06 1.12E-06 1.06E-06 3.1E,-07 Le Containment Failurv 56.5% 4.07E-05 3.49E-.0 9.66E.07 6.27E-07 1.38E-06 2.21E-06 4.77E-08 4,51E-07 7.09E-08 Early Small Containment Failure 1.7% 1.21E-06 6.61E.-07 3.14E.07 3.60E-0F 7.55E-09 6.65E-09 8.1SE-09 535E-08 1.27E-09 1.20E-07 Early Larp Contaimuet Failure 6.5% 4.67E.06 t.l1E-06 l.06E-06 1.SOE-08 5.04E-09 4.44E-09 2.34E-06 4.42E-O8 1.SIE-02 1.27E.09 4.23E.09 Small Conlaibmadt Bypass 0.0% 0.OOE+00 Large Containment Bypass 0.0% O.OOE+00 RAN 97-031 4-95 BGE 4-95 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events A225 Unit 1 Radiation Exhaust Location: 5' Auxiliary Building Equipment Room (Fan Room) Fire Area: 14 CDF: 3.99E-9 This compartment has exhaust ventilation equipment including two charcoal filters. It also contains piping associated with the Main Steam System, and the main and Auxiliary Feedwater Systems. The compartment is approximately fifty-eight feet long and thirty feet wide with 1,725 square feet of area. Floor mounted equipment and interferences occupy approximately 925 square feet, leaving 800 square feet of open floor. The ceiling height is approximately twenty feet for a room volume of 34,500 cubic feet. The compartment has a concrete floor, concrete walls and a concrete ceiling. Fire Analysis Results Thirteen fire scenarios are identified for A225. Ten are the result of fixed ignition sources and three are due to transient ignition sources. Five scenarios are screened due to low functional impact. The screening is based on ,the same criteria described in Section 4.3.1.3. The remaining eight scenarios identified in Table 4-A-1 are represented by four fire initiating events identified in Table 4-A-2. The consolidation of fire scenarios is based on an assessment of the functional impact and ignition frequency of each scenario. The frequency of each initiator is the sum of the frequencies of all the fire scenarios it represents. Table 4-A-1 A225 Fire Scenarios Summary Fire Scenario Description Equipment Damaged I I AFW Pump Room Exhaust Subsystem No other effects Fire + Transient Fire 12 AFW Pump Room Exhaust Subsystem No other effects Fire + Transient Fire I I ECCS Pump Room Exhaust Subsystem No other effects Fire + Transient Fire 12 ECCS Pump Room Exhaust Subsystem No other effects Fire + Transient Fire Control Panel IC107 Fire No other effects Transient Fire Location I Conduits: IA1576, IA0366, IA0278, IA0367, IA2901, IA2794 Transient Fire Location 2 Cable Trays: IACO9, IAC19 Transient Fire Location 3 Cable Trays: IAA6I BGE 4-A-1I RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Table 4-A-2 A225 Fire Analysis Results

               -l Initiating           Fire         Frequency                  Ignition                  Functional                CDF Event            Scenario                                   Source                     Impact A225FI                1,2           1.19E-4   I I or 12 AFWRm Exhaust Fans               FF, FC              4.58E-10 A225F2                3,4           1.19E-4    11 or 12 ECCS Pump Rm Exhaust             FF, V5              4.63E- 10 Fans A225F3                 10           2.85E-4   Control Panel 1C107                        FF, CV              2.95E-09 A225F4             11,12,13         2.52E-6   Maintenance Refuse                   Y4, 11,12, S3, S4,         1.23E-10 TA, TD, KY, FF, CV, HW, CT, SR*,

TH A225 Fire Ignition Freauency Both fixed and transient ignition frequencies are determined for the 5' Fan Room. Fixed Ignition Freguency The fixed ignition frequency is determined by starting with the compartment fixed ignition frequency results of Section 4.3.2 and then developing a scenario specific ignition frequency as described in Section 4.3.4.3. The sources and parameters used for A225 are: Source Generic Fire Location Source Total Sources in Room Specific Frequency Weighting Weighting Aux Bldg Frequency Ventilation Subsystem 9.5E-3 2 9 331 5.17E-4 Electrical Cabinet 1.9E-2 2 1 135 2.81E-4 The nine ventilation subsystems are considered to be motors for fire modeling. Non-motor driven components that could contribute to the ignition (shaft bearings and belts) are considered less damaging than the motor. Although the belts are a plausible ignition source, they do not represent significant loading or heat release rate. Some units house internal charcoal elements: These elements are considered benign with regard to room fire modeling because they are contained within the plenum housing. All the motors have a 65 Btu heat release rate and are treated as radiant sources. A radiant exposure worksheet calculates the associated critical damage distance. In all cases, there is no cabling or equipment damage associated with a motor failure. RAN 97-031 4-A-2 BGE 4-A-2 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Since there are nine ventilation subsystems, each subsystem is assigned one ninth of the compartment specific frequency of 5.74E-5. Initiating Events A225FI and A225F2 contain two ventilation units each. The fixed frequency contribution for these initiating events is therefore: A225FI or A225F2 Fix Ipition = 5.74E-5

• 2 = 1.15E-4/yr Panel 1C107 is the sole electrical cabinet in the fan compartment and is a totally enclosed cabinet with no ventilation openings, grills or louvers. For this cabinet, a fire will not propagate beyond the confines of the cabinet itself because combustion products suppress fire growth. As an ignition source, sealed enclosures have a 65 Btu heat release rate with a damage range analyzed using a radiant exposure worksheet. No other components or cables are within the damage range.

Since there is only one electrical cabinet or panel in the compartment, the ignition frequency for IC107 is simply the fixed ignition frequency value for electrical cabinets in A225. A225F3 Fixl gnition = 2.81E-4/yr Transient Ignition Frequency The transient ignition frequency is determined by starting with the compartment transient ignition frequency results of Section 4.3.2 and then developing a scenario specific ignition frequency as described in Section 4.3.4.3. The sources and parameters used for A225 are: Source Generic Fire Location Source Total Sources in Room Specific Frequency Weighting Weighting Aux Bldg Frequency Transient fire - other 1.3E-3 2 10 232 1.122E-4 p-,-

                                                                                                                           'jL-
                                                                                                                             ý.

The likelihood a hot work induced transient fire is very small since a Hot Work Permit is required for this compartment. This means that there is continual fire watch during any hot work activities and for a period of at least thirty minutes after work is complete. See Section 4.2.2.6.2 for additional information on controlling ignition sources. The formula for calculating the damage frequency due to transient combustible fires is contained in Section 4.3.4.3.2. The floor area of the 5' Fan Room is approximately 1,725 square feet. Floor mounted equipment and interferences occupy approximately 925 square feet of floor area, leaving 800 square feet of open floor (=AF). BGE 4-A-3 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Each ventilation unit is a transient ignition source target. Assuming a radiant damage distance of approximately three feet extended as a semi-circle around each unit motor, the floor area where a transient could cause damage equals about fourteen square feet. Therefore: u = (0ft2 +14f2)/800ft'

                                                        =  0.0175 and        Ft= 1.12E1-04

• 0.0175
• 1

                                                      =   1.96E-06 As above, A225F I and A225F2 contain two ventilation units each. Therefore:

A225FI or A225F2mit = 1.96E-06

• 2 =3.92E-6/yr Similarly, panel IC107 is a transient target. Using a 1.8 foot damage distance, the area around the panel perimeter is estimated at twenty-five square feet. Therefore:

u = (0 ft2 + 25 ft2 ) / 800 ft2

                                                       = 0.03125 and         F,= 1.12E-04

• 0.03125
• I 3.5E-06 A225F3=,siknt = 3.50E-6/yr Based on the transient fire worksheets for this compartment, the Critical Damage Distance to the lowest overhead target is approximately eleven feet from the floor when the fire is in a comer location. Three corners have cable trays or conduits that are potential targets. Each location presents a six square foot overhead target. Therefore:

u = (6ft +0te)/800ft'

                                                        =   0.0075 and      F, = 1.12E-04

• 0.0075
• 1 8.4E-07 However, the three cable target transient fire scenarios are consolidated into one initiating event.

A225F4Tnaie = 8.41E-7

• 3 = 2.52E-6/yr RAN 97-031 4-A-4 BGE 4-A-4 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Total Ignition Frequency The total ignition frequency is the sum of fixed and transient frequencies (as applicable). Fire SupDression Although smoke detection and a wet pipe sprinkler system provide fire suppression mitigation for this area, these are not credited in the fire analysis. Fire Suppression Induced Equipment Failures Based on the approach described in Section 4.3.4.4.4, equipment failure due to the inadvertent actuation of the automatic fire suppression system is assumed not to occur, Cable and conduit, pumps and other PRA equipment in the room are not considered to be susceptible to water damage, BGE 4-A-5 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events A226 Unit I Service Water Location: 5' Auxiliary Building Pump Room Fire Area: 39 CDF: 3.47E-08 This compartment contains the three Service Water (SRW) Pumps, two SRW heat exchangers and their associated control valves for Unit 1. It also the contains the Unit I Auxiliary Feedwater (AFW) motor driven pump and associated flow control valves. Both safety-related Saltwater System Air Compressors (SWAC) are also located in this compartment. This room is located on the 12' elevation at the east end of the Auxiliary Building, but access is from the Turbine Building. The room entry is through a water tight door on the east side of the room. This compartment is a relatively large open room eighty-two feet long by thirty feet wide for a total room area of approximately 2,460 square feet. The height of the room is twenty-two feet for a total room volume of 54,120 cubic feet. The room has a sealed (painted) floor which provides a smooth slick surface. The room is divided approximately halfway up by open grating which separates the SRW pumps below from the SWACs above. This area has products 6f combustion and flame detection and a wet pipe sprinkler system. Fire Analysis Results Thirteen fire scenarios were identified for A226. Nine are the result of fixed ignition sources and four are due to combined transient and fixed ignition sources. These scenarios are represented by three fire initiating events. The consolidation of fire scenarios is based on an assessment of the functional impact and ignition frequency of each scenario. The frequency of each initiator is the sum of the frequencies of all the fire scenarios it represents. Table 4-B-i1 A226 Fire Scenario Summary Scenario Initiating Scenario Size Suppression Effect Equipment Description 11 SWAC Oil Spill Small N/A SW Air Compressor 11, SRW Pump 12 2 12 SWAC Oil Spill Small N/A SW Air Compressor 12, SRW Pump 13 3 11 SWAC Oil Spill Large Yes SW Air Compressor 11, SRW Pump 12 4 12 SWAC Oil Spill Large Yes SW Air Compressor 12, SRW Pump 13 5 11SWAC Oil Spill Large No SW AirCompressors I1 and 12; ZBIAC21; SRW Pumps 11, 12 and 13; AFW Pump 13 1B1E 4-B-I IA I703 BGE 4-B- 1 RAN 97-031i

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Table 4-B-I A226 Fire Scenario Summary (Continued) Scenario Initiating Scenario Size Supprension Effect Equipment Description 6 12 SWAC Oil Spill Large No SW Air Compressors I I and 12; ZBIAC21; SRW Pumps 11, 12 and 13; AFW Pump 13 7 12SRW Oil Spill Large No SW Air Compressors 11 and 12;ZBIAC2I; SRW Pumps 1I, 12 and 13; AFW Pump 13 8 13 SRW Oil Spill Large No SW Air Compressors I I and 12; ZBIAC21; SRW Pumps 1I, t2 and 13; AFW Pump 13 9 13 AFW Oil Spill Large Yes SW Air Compressors II and 12; ZBIAC21; SRW Oil Spill Large No Pumps 11, 12 and 13; AFW Pump 13 10 13 AFW Motor Failure, N/A N/A 13 AFW Transient, N/A N/A Oil Spill Small N/A I1 1i SRW Motor Failure, N/A N/A 11 SRW Transient, N/A N/A Oil Spill Small NIA Oil Spill Large Yes Oil Spill Large No 12 12 SRW Motor Failure, N/A N/A 12 SRW Transient, N/A N/A Oil Spill Small N/A Oil Spill Large Yes 13 13 SRW Motor Failure, N/A N/A 13 SRW Transient, N/A N/A Oil Spill Small N/A Oil Spill Large Yes Table 4-B-2 A226 Fire Analysis Results Initiating Fire Frequency Ignition Functional CDF Event Scenario Source Impact A226FI 1,3 1.34E-4 1I SWAC small spill; Y3, Y4, It, S4 3.40E-9 II SWAC large spill with suppression A226F2 2,4 1.34E-4 12SWAC small spill; Y3, Y4, 12, (S3, S4: 3.12E-9 12SWAC large spill with SRW PP 13 only) suppression BGE 4-B-2 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Table 4-B-2 A226 Fire Analysis Results (Continued) Initiating Fire Frequency Ignition Functional CDF Event Scenario Source Impact A226F3 5,6,7, 8, 9 6.67E-5 I ISWAC large spill no suppression; Y3, Y4, I, 12, S3, 2.82E-8 12SWAC large spill no suppression; S4, F7 12SRW large spill no suppression; 13SRW large spill no suppression; 13AFW large spill Screened 10, II, 12, N/A 13AFW motor, transient, small spill; None 13 1I SRW motor, transient, small spill, large spill; 12SRW motor, transient, small spill, large spill with suppression; 13SRW motor, transient, small spill, large spill with suppression Fire Ignition Frequency Both fixed and transient ignition frequencies were determined for the Service Water Pump Room. Fixed Ignition Frequency The fixed ignition frequency is determined by starting with the compartment fixed ignition frequency results of Section 4.3.2 and then developing a scenario specific ignition frequency as described in Section 4.3.4.3. The sources and parameters used for A226 are: Source Generic Fire Location Source Total Sources in Room Specific Frequency Weighting Weighting Aux Bldg Frequency Air Compressor 4.7E-3 2 2 35 5.37E-4 Pump 1.9E-2 2 4 54 2.81 E-3 Ventilation Subsystems 9.5E-3 2 2 331 1.15E-4 Note: Failure of the ventilation systems in the SRW Pump Room has been screened for plant impact. Fire modeling showed that upon ignition, neither unit had any impact other than damage to the units themselves. Therefore, the ventilation systems are not discussed here. The fire ignition frequency for devices with oil (compressors and pumps) does not indicate that each ignition results in a large fully developed fire if not suppressed. Review of the EPRI Fire Events Database shows that approximately fifty percent of pump fire events involve lubricating oil fires and fifty percent represent motor winding fires or other miscellaneous ignitions. The Fire PRA Implementation Guide indicates that approximately eighty-eight percent of oil spill fires are "small" spills and twelve percent are "large" spills. This information is used to calculate scenario frequencies. BGE 4-11-3 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events An additional factor used in the calculations is the fire suppression failure rate. Per the FIVE methodology, the wet pipe sprinkler system failure rate is 0.02. SALTWATERAIR COMPRESSORS (SWAC) This area contains two air compressors located on the upper level grated floor, I1 SWAC and 12 SWAC. Two SRW pumps are located essentially directly below (13 SRW Pump below 12 SWAC and 12 SRW pump below 11 SWAC). An electrical motor fire or a lubricating oil spill fire can be postulated for these compressors. As there is no equipment closer than a couple feet to each compressor other than its own electrical feed, a motor fire would not damage any other equipment other than disable the compressor (an electric motor is modeled as a 65 Btu/s radiant heat case, yielding a critical damage distance of 1.4 ft). The most conservative fire is that associated with an oil spill. As such, 1 and 12 SWAC fires are modeled as postulated oil spill and ignition fires. However, this compartment has an area-wide automatic sprinkler system that, if successfully actuated, will minimize fire induced damage to other equipment, as discussed below. The air compressors contain approximately 0.8 gallons of oil. The large oil spill fire for each compressor is postulated to be a spill of the entire 0.8 gallon oil inventory. Given the small size of these compressors and the relatively small inventory of oil in each one, the effects of the small oil spill fire are assumed to be confined to the comjoressor itself. 11 SWAC, Small Oil Spill: Fire induced damage limited to unavailability of the compressor itself and 12 SRW pump directly below. Scenario I = 5.37E-4 +2

• 50%
• 82% = 1.1OE-4 12 SWAC, Small Oil Spill: Fire induced damage limited to unavailability of the compressor itself and 13 SRW pump directly below.

Scenario 2 = 5.37E-4 + 2

• 50%
• 82% = 1.1OE-4 The oil is modeled as having the combustion characteristics of transformer oil and the spill characteristics of DTE 797 lubricating oil (these correspond to representative parameters provided in the FIVE methodology).

The one complicating configuration issue is that the air compressors are located on the upper level on the grate floor. Any oil spill could be postulated to be dispersed as it falls to and through the grate floor and hits the concrete floor below. The fire models available in pertinent literature do not provide guidance as to the treatment of such a configuration. Common sense indicates that modeling the oil as dispersed into small pools and widely spread droplets would yield less conservative results than modeling an oil pool fire. As such, the air compressor oil spill fire is modeled as 1) an oil pool fire, that 2) occurs on the concrete floor below, and 3) disables the SRW pump below. This assumption addresses the configurational issue of each compressor being located above a SRW pump. BGE 4-B-4 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events The postulated spill is treated as a confined spill. The idealized fire modeled in FIVE calculates a fire duration of just eight seconds if an unconfined oil spill is postulated. Information provided in the Fire PRA Implementation Guide indicates that qualified cables would need to be exposed to hot gases for a "significant time" to result in damage. In the case of ignition, NUREG/CR-4527 states that tests show that direct flame impingement for ten minutes is necessary to ignite qualified cables. Therefore, an idealized eight second fire is non-conservative in that damage to able targets would not be indicated. The duration of an oil spill fire is linearly related to the thickness of the oil pool and, thus, the spill area. Therefore, to lengthen the fire duration, it is necessary to lessen the spill area by postulating a confined spill. This is consistent with the Fire PRA Implementation Guide which states that it is unrealistic to assume that the only factor affecting spill size is the viscosity of the oil. Depressions in the floor, floor drains, obstructions in the floor (e.g., berms, columns, equipment pedestals) and housekeeping practices that direct cleaning up of spills, all support the conclusion that an idealized unconfined spill is an unrealistic assumption for a representative fire. As such, the spill size was adjusted to obtain a fire duration of approximately one minute. This results in a spill surface area of 12.5 square feet and a corresponding peak fire intensity of 1,434 Btu/sec. Postulation of longer durations is not considered justified due to the very small spill area that would be required to be postulated; such a spill would not be consistent with the location of the compressor (i.e., on an elevated grated floor). A walkdown of the coinpartment and a review of arrangement and cable tray drawings determined that the nearest, and only, cable tray ZB1AC21 is under the grated floor and toward the south-west comer. However, the majority of a large oil spill from either of the overhead compressors would most likely be confined between the pedestals of 12 and 13 SRW pumps, placing this tray at least eight feet laterally from the edge of the oil spill on the floor. However, directly overhead of the postulated oil spill are located a number of electrical conduits running generally north and south approximately ten feet above the floor. Two of these conduits contain the electrical feeds for 12 and 13 SRW Pumps. In addition, a run of various electrical conduits, also running north and south and approximately ten feet above the floor, are located a couple feet laterally from the edge of the postulated oil spill. This run of conduits contains the electrical feed for 11 SRW Pump and cabling to 13 AFW Pump. All the previously mentioned targets are inside the oil spill fire plume (based on plume cone radius of r = 0.2z). Therefore, a postulated large oil spill fire from either of the above air compressors has the potential to simultaneously disable all three SRW pumps and 13 AFW Pump. The in-plume fire damage worksheet for this configuration shows that all the previously mentioned targets are within the critical damage distance (i.e., damage to the cabling is indicated). The radiant exposure worksheet for this configuration shows that the critical damage distance from the edge of the oil spill (assuming a damage criteria of 3.75 Btu/sec/ft2 for motors, per the Fire PRA Implementation Guide) is about three and a half feet. Given the distances between the SRW pumps and the AFW pump, it is judged that radiant induced damage to the other pumps (i.e., other than the pump directly below the SW air compressor) may occur. An oil spill from 12 SWAC may place 12 SRW within the critical damage distance (approximately three feet); the motor of the AFW pump is outside the critical damage distance. RAN 97-031 4-B-S BGE 4-B-5 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events 11 SWAC, Large Oil Spill Without Suppression: Fire induced damage includes damage to both SWACs, 11, 12, and 13 SRW Pumps, and 13 AFW Pump. Scenario 5 = 5.37"E-4 + 2 # 50%

• 18%
• 0.02 = 4.83E-7 12 SWAC, Large Oil Spill Without Suppression: Fire induced damage includes damage to both SWACs, 11, 12, and 13 SRW Pumps, and 13 AFW Pump.

Scenario 6 = 5.37E-4 + 2

• 50%
• 18%
• 0.02 = 4.83E-7 3 In the above analysis, the transient thermal response of the targets is not explicitly considered and is assumed to be negligible; the targets are assumed to instantly reach the critical temperature. Considering the existence of fire suppression in the room, it is appropriate to explicitly model the transient thermal response of the targets. If the actuation time of the wet pipe sprinklers (based on transient thermal response) is less than the time to target damage, then the damage to the targets can be prevented (given successful actuation of the sprinklers).

The automatic sprinkler heads in the area are equipped with link type elements and have a temperature rating of 212TF. No specific information has been identified regarding the time constants of the heads. The FIVE methodology recommends time constants in the range of 60-120 seconds for fusible link type heads; a value of one hundred seconds is assumed here. The sprinkler heads for the lower level are approximately twelve feet above the floor and are equidistant throughout the room on approximate ten foot centers. Based on a plume cone radius of r = 0.2z, at least one sprinkler head, and most likely more than one, will be in the plume of the postulated oil spill fire. Using the FIVE fire modeling worksheets for transient thermal response, it was determined that suppression system actuation would occur in approximately twenty seconds, whereas damage to nearby pumps would occur in thirty-six seconds and to the cabling overhead in forty seconds (this estimate is conservative as it does not account for the shielding provided by the conduit). 11 SWAC, Large Oil Spill With Suppression: Fire induced damage includes damage to the compressor itself and 12 SRW pump directly below. Scenario 3 -- 5,37E 2

• 50%
• 18% * (1- 0.02) = 2.3713-5 12 SWAC, Large Oil Spill With Suppression: Fire induced damage includes damage to the compressor itself and 13 SRW pump directly below.

Scenario 4 = 5.37E-4 + 2

• 50%
• 18% * (1 -0.02) = 2.37E-5 RAN 97-031 4-B-6 BGE 4-B-6 RAN 97-031

Calvert Cliffs Nuclear Power Plant internal Fire Analysis Individual Plant Examination External Events SERVICE WATER PUMPS (SRW): A pump fire may include an electrical motor fire or a lubricating oil spill fire. As there is no equipment closer than six feet to each pump other than its own electrical feed, a motor fire would not damage any other equipment other than disable the pump (an electric motor is modeled as a 65 Btu/s radiant heat case, yielding a critical damage distance of 1.4 ft). The most conservative fire is that associated with an oil spill. As such, the SRW Pumps are modeled as postulated oil spill and ignition fires. This compartment has an area-wide automatic sprinkler system that, if successfully actuated, will minimize fire induced damage to other equipment, as discussed below. The SRW pumps water pumps each contain approximately one gallon of oil. The large oil spill fire for each SRW pump is postulated to be a spill that includes the entire one gallon oil inventory. As no guidance is available in industry literature regarding the size of a "small" oil spill, judgment is used here to select a spill volume of one quart to represent a small oil spill fire for these pumps. Like the compressor oil fires, the oil is modeled as having the combustion characteristics of transformer oil and the spill characteristics of DTE 797 lubricating oil (these correspond to representative parameters provided in the FIVE methodology). Like the compressor oil spill fires, the postulated SRW pump oil spills are treated as confined. As such, the spill size was adjusted to obtain a fire duration of approximately one minute. This results in a spill surface area of approximately four square feet and a corresponding peak fire intensity of 448 Btu/sec for the small oil spill. The large oil spill is approximately 15.5 square feet and 1,779 Btu/sec. 11 SRW Pump is located at the north end of the compartment and far removed from the other pumps. The nearest pump is 15-20 feet to the south with no intervening combustibles or overhead cable trays. As such, any oil spill fire associated with 11 SRW Pump would only damage the pump itself. Oil spill fire effects for the other pumps are discussed below. 11 SRW Pump, Small or Large Oil Spill, With or Without Suppression; Motor: Fire induced damage is limited to unavailability of the SRW pump itself. Scenario lltix = [2.81E-3 + 4

• 50%] + [2.81EE-3 + 4
• 50%] = 7.03EE4 A walkdown of the compartment and a review of arrangement and cable tray drawings determined that the nearest, and only, cable tray (ZB1AC21) is under the grate floor and toward the south-west comer.

This target is outside the damage influence of 12 SRW; although, it may be within the damage influence of an oil spill fire of 13 SRW. Whether cable tray ZB1AC21 is damaged by an oil spill fire of 13 SRW Pump depends on the configuration of the oil spill (e.g., which side of the pump pedestal the oil spill propagates). This analysis assumes that cable tray ZBIAC21 is damaged following an oil spill fire of 13 SRW Pump if damage to other overhead targets is indicated. As discussed earlier, overhead of the postulated oil spill are located a number of electrical conduits running generally north and south approximately ten feet above the floor. Conduits containing the electrical feeds for the SRW pumps and the AFW pump are located in these conduit runs. Depending on the configuration of the oil spill, some or all of these conduits may be in the fire plume. This analysis BGE 4-13-7 RAN 97-031

Calven Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events assumes that for an oil spill fire of 12 or 13 SRW Pump the overhead electrical feeds for all pumps in the room are within the fire plume. Therefore, a postulated large oil spill fire from 12 or 13 SRW Pump has the potential to simultaneously disable all three SRW pumps and 13 AFW Pump. 12 SRW Pump, Large Oil Spill Without Suppression: Fire induced damage includes damage to 11, 12, and 13 SRW Pumps, 13 AFW Pump, and both SWACs. 13 SRW Pump, Large Oil Spill Without Suppression: Fire induced damage includes damage to 11, 12, and 13 SRW Pumps, 13 AFW Pump, and both SWACs. Scenario 8 = 2.8111 4

• 50%
• 18%
• 0.02 = 1.26E-6 In the case of the small oil spill fire, the in-plume fire damage worksheet and the radiant exposure worksheet show that damage to adjacent equipment or overhead cabling is not indicated. As such, in the case of small oil spill fires of the pumps, the only impact is damage to the pump itself.

For the large oil spill, the in-plume fire damage worksheet for this configuration shows that all the previously mentioned targets are within the critical damage distance (i.e., damage to the cabling is indicated). The radiant exposure worksheet for this configuration shows that the critical damage distance from the edge of the oil spill (assuming a damage criteria of 3.75 Btu/sec/ft2 for motors, per the Fire PRA Implementation Guide) is about four feet. Given the distances between the SRW pumps and the AFW pump, it is judged that radiant induced damage to the other pumps may occur. Like the compressor oil spill fire, the transient thermal response of the targets in the above analysis is not explicitly considered and is assumed to be negligible; the targets are assumed to instantly reach the critical temperature. This is conservative. Considering the existence of fire suppression in the room, it is appropriate to explicitly model the transient thermal response of the targets. If the actuation time of the wet pipe sprinklers (based on transient thermal response) is less than the time to target damage, then the damage to the targets can be prevented (given successful actuation of the sprinklers). The automatic sprinkler heads in the area are equipped with link type elements and have a temperature rating of 212°F. No specific information has been identified regarding the time constants of the heads. The FIVE methodology recommends time constants in the range of 60-120 seconds for fusible link type heads; a value of one hundred seconds is assumed here. The sprinkler heads for the lower level are approximately twelve feet above the floor and are generally equidistant throughout the room on approximate ten foot centers. Based on a plume cone radius of r = 0.2z, at least one sprinkler head will be in the plume of the postulated oil spill fire. Using the FIVE fire modeling worksheets for transient thermal response, it was determined that suppression system actuation would occur in approximately eighteen seconds, whereas damage to nearby pumps would occur in forty-four seconds and damage to the cabling overhead would occur in thirty seconds. These results indicate that the suppression system will actuate prior to, and prevent, damage to other equipment. BGE 4-B-8 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events 12 SRW Pump, Small Oil Spill With or Without Suppression;Large Oil Spill With Suppression;Motor Scenario 12f-,= 2.81E-3 + 4

• 50% * {82% + [18% * (1-0.02)]) + [2.81E-3 + 4
• 50%] = 7.01E-4 13 SRW Pump, Small Oil Spill With or Without Suppression; Large Oil Spill With Suppression; Motor Scenario 13flx = 2.81E-3 + 4
• 50% * (82% + [18% * (1 - 0.02)]} + [2.81E-3 + 4
• 50%] = 7.01E-4 ]

AUXILIARY FEEDWATER PUMP (AFW): The AFW pump fire is modeled in the same manner as the SRW pumps. The AFW pump contains approximately 1.4 gallons of oil. The large oil spill fire for the AFW pump is postulated to be a spill that includes the entire oil inventory. As no guidance is available in industry literature regarding the size of a "small" oil spill, judgment is used here to select a spill volume of one quart to represent a small oil spill fire for these pumps. Like the compressor and SRW pump oil spill fires, the oil is modeled as having the combustion characteristics of transformer oil and the spill characteristics of DTE 797 lubricating oil (these correspond to representative parameters provided in the FIVE methodology). Like the compressor and SRW pump oil spill fires, the postulated AFW pump oil spills are treated as confined. As such, the spill size was adjusted to obtain a fire duration of approximately one minute. This results in a spill surface area of approximately four square feet and a corresponding peak fire intensity of 448 Btu/sec for the small oil spill. The large oil spill is approximately twenty-two square feet and 2,525 Btulsec. Cable tray ZB 1AC21 is located approximately twenty feet away and outside the damage influence of the AFW pump oil spill fire. However, as discussed earlier, overhead of the postulated oil spill are located a number of electrical conduits running generally north and south approximately ten feet above the floor. Conduits containing the electrical feeds for the SRW pumps and the AFW pump are located in these conduit runs. Depending on the configuration of the oil spill, some or all of these conduits may be in the fire plume. If the AFW pump oil spill fire occurs against the east wall, near which the AFW pump is located, these conduits would be outside the fire plume and most likely undamaged by the postulated fire. This analysis assumes that the oil spill occurs on the side of the AFW pump toward the center of the room, such that the overhead electrical feeds for all pumps in the room are within the fire plume. Therefore, the postulated large oil spill fire of 13 AFW Pump has the potential to simultaneously disable all three SRW pumps and 13 AFW Pump. In the case of the small oil spill fire, the in-plume fire damage worksheet and the radiant exposure worksheet show that damage to adjacent equipment or overhead cabling is not indicated. As such, in the case of small oil spill fires of the pumps, the only impact is damage to the pump itself. RAN 97-031 4-B-9 BGE BGE 4-B-9 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Five Analysis Individual Plant Examination External Events 13 AFW Pump, Small Oil Spill With or Without Suppression; Motor: Fire induced damage limited to unavailability of the AFW pump itself. Scenario 10flx = [2.81E-3 + 4

• 50%
• 82%] + [2.81E-3 + 4
• 50%] = 6.39E-4 For the large oil spill, the in-plume fire damage worksheet for this configuration shows that all the previously mentioned targets are within the critical damage distance (i.e., damage to the cabling is indicated). The radiant exposure worksheet for this configuration shows that the critical damage distance from the edge of the oil spill (assuming a damage criteria of 3.75 Btu/sec/ft2 for motors, per the Fire PRA Implementation Guide) is about four and a half feet. Given the distances between the SRW pumps and the AFW pump, it is judged that radiant induced damage to the other pumps may occur.

Like the compressor and SRW pump oil spill fires, the transient thermal response of the targets in the above analysis is not explicitly considered and is assumed to be negligible; the targets are assumed to instantly reach the critical temperature. This is conservative. Considering the existence of fire suppression in the room, it is appropriate to explicitly model the transient thermal response of the targets. If the actuation time of the wet pipe sprinklers (based on transient thermal response) is less than the time to target damage, then' the damage to the targets can be prevented (given successful actuation of the sprinklers). The automatic sprinkler heads in the area are equipped with link type elements and have a temperature rating of 212°F. No specific information has been identified regarding the time constants of the heads. The FIVE methodology recommends time constants in the range of 60-120 seconds for fusible link type heads; a value of one hundred seconds is assumed here. The sprinkler heads for the lower level are approximately twelve feet above the floor and are generally equidistant throughout the room on approximate ten foot centers. Based on a plume cone radius of r = 0.2z, at least one sprinkler head will be in the plume of the postulated oil spill fire. Using the FIVE fire modeling worksheets for transient thermal response, it was determined that suppression system actuation would occur in approximately fourteen seconds, whereas damage to nearby pumps would occur in sixteen seconds and damage to the cabling overhead would occur in thirteen seconds. These results do not provide confidence that the suppression system will prevent damage to the overhead electrical feeds. 13 AFW Pump, large Oil Spill With or Without Suppression: Fire induced damage includes damage to 11, 12, and 13 SRW Pumps, and both SWACs. Scenario 9 = 2.81E-3 + 4

• 50%/a
• 18% = 6.32E-5 BGE 4-B-10 B RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Transient Ignition Frequency The transient ignition frequency is determined by starting with the compartment transient ignition frequency results of Section 4.3.2 and then developing a scenario specific ignition frequency as described in Section 4.3.4.3. The sources and parameters used for A226 are: Note that welding related transients are not considered for damage. Approximately twenty percent of the SRW Pump Room floor area is obstructed and would not allow for the placement of combustibles. Therefore, total available floor area: AF = 2460 ft2

• 80% = 1968 ft2 The only plausible transient targets are the pumps or compressors themselves and these are susceptible to radiant damage at a distance of 1.8 feet. Each pump pedestal is of a similar dimension: The area formed by extending 1.8 feet around each pedestal perimeter is approximately sixty square feet (-Asr).

Therefore: u = (As+Asr)/AF (Oft + 60ft2)/1968fte

                                                         = 3.05E-2 and     Ft= L.O0E-4

• 3.05E-2
• I Pump.an = 3.08E-6 The area surrounding each SWAC is estimated to be twenty square feet (=A,,). Therefore:

u = (0ft2 + 20ft2)/1968ft

                                                         = 1.02E-2 and    F, = 1.01E-4

• 1.02E-2
• I Compressortms = 1.03E-6 The SWAC transient frequency is not combined with other room fire scenarios. As an individual scenario it is subsumed by the normal equipment failure frequency. Therefore, the SWAC transient frequency is not considered for impact.

RAN 97-031 4-B-il BGE 4 11 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Total Ignition Frequency Fixed scenarios and transient scenarios with like impacts were added together. Scenario 10 = Scenario 10f,- + Pumpt,,n = 6.39E-4 + 3.08E-6 = 6.42E-4 Scenario 11 = Scenario I Ir, + Pump,. = 7.03E-4 + 3.08E-6 = 7.06E-4 Scenario 12 = Scenario 12r,, + Pumpha, = 7.01E-4 + 3.08E-6 = 7.04E-4 Scenario 13 = Scenario 13r, + Pumptn, = 7.01E-4 + 3.08E-6 = 7.04E-4 Initiating event frequencies are then summed using the individual scenario frequencies. [ A226FI = Scenario I + Scenario 3 = 1.10E-4 + 2.37E-5 = 1.34E-4 J A226F2 = Scenario2 + Scenario4 = 1.101E-4 + 2.37E-5 = 1.34E-4 A226F3 = Scenario 5 + Scenario 6 + Scenario 7 + Scenario 8 + Scenario 9 4.83E-7 + 4.83E-7 + 1.26E-6 + 1.26E-6 + 6.32E-5 = 6.67E-5

• Scenarios 10, 11, 12, and 13 total impact is screened.

Fire Suppression The compartment contains both flame and smoke detectors for alarm purposes. Five of the six smoke detectors are located in the ceiling and spaced generally equidistant down the center of the room; the sixth is located under the grate floor at the north end. The three flame detectors are located under the grate floor, one above each of the three SRW pumps. The compartment is equipped with a wet pipe sprinkler system. One subsystem is located in the ceiling of the upper elevation and the other subsystem is located under the grate floor. There are approximately thirty to forty heads generally uniformly spaced on each elevation. The wet pipe sprinkler heads are equipped with thermal fusible links rated at 2120 F. BGE 4-B- 12 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Fire Suppression Induced Equipment Failure The compartment has several floor drains which would remove accumulated fire system spray. In addition, the pump motors are pedestal mounted and compressor motors are on the upper level grating. All the motors appear to be a drip-proof or closed design with qualified connections. All cabling is assumed to be impervious to water. Therefore, suppression induced damage is judged unlikely in this room. RAN 97-031 4-B-13 BGE 4-B- 13 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events A227/A316 East Piping Penetration Rooms Location: 5' Auxiliary Building 27' Auxiliary Building Fire Area: 11 CDF: 7.34E-7 This compartment is approximately eighty-nine feet in length with a width of about sixteen feet, for a compartment area of 1,424 square feet. The height of this area is thirty-eight feet from the ceiling, giving the compartment a room volume of 54,112 cubic feet. This area contains several very small pumps and motor-operated valves which are insignificant ignition sources. There are no cable trays to provide an ignition target within the critical damage distance of these ignition sources. Conduit is not located near any potential ignition sources. Grating separates the two rooms. At the 5' level is a three hour fire door. There is also a three hour non-rated emergency escape hatch which provides an adequate fire barrier. At the 27' level is a normally closed non-rated three hour fire door. The hatch at the 27' level is a one and a half hour door, which is considered adequate. Barriers between A3 16, A317 and A429 contain dampers that are adequate fire barriers as installed for original construction. Propagation beyond this compartment is unlikely due to the configuration of the area and the low combustible loading. A227 Fire Analysis Results No fire scenarios are identified for this room. Given the configuration of the room, damage due to a pump or motor-operated valve fire is limited to the component itself. Plausible fire scenarios were disregarded due to the low fire frequencies and limited fire damage. The worst case postulated transient fire would cause no damage to conduits. The plant impact due to fire frequency is bounded by the individual component failure rates used in the internal events CCPRA, and as a result, this room has no additional equipment impact due to fire. However, these rooms are destination locations for several human actions associated with the recovery of AFW flow control functions. Smoke and increased temperatures in these rooms will degrade these actions. Table 4-C-1 A227/A316 Fire Analysis Results Initiating Fire Frequency Ignition Major CDF Event Scenario Source Impact FCA227 None 4.62E-04 No equipment damage; however, l-C, UQ, F1* 2.53E.05 Human Actions are degraded due to smoke and increased temperature in the room. BGE 4-C-1 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Suppression Systems Flame detectors are installed at the 5' level throughout the room, and smoke detectors are installed at the 27' level. The compartment has installed wet pipe fire suppressions at both levels. Fire Suppression Induced Equipment Failures Based on the approach described in Section 4.3.4.4.4, equipment failure due to the inadvertent actuation of the automatic fire suppression system is assumed not to occur. Conduit, valves and other PRA equipment in the room are not considered to be susceptible to water damage. RAN 97-031 4-C-2 BGE 4-C-2 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events A228 Unit I Component Cooling Location: 5' Auxiliary Building Water Pump Room Fire Area: 15 CDF: Screened - Low Fire Ignition Frequency Three Component Cooling Water Pumps (CCW 11, 12 and 13) and the two CCW Heat Exchangers (II and 12) are located in Room A228. During normal operation one pump and one heat exchanger provide the necessary cooling. The major cooling loads for this system are the RCPs, the Letdown Heat Exchanger, and the Liquid Waste Evaporators. The CCW Pump Room is approximately eighty-four feet long by approximately thirty-nine feet wide for an area of 3,265 square feet. The height of the compartment is twenty feet for a approximate room volume of 65,000 cubic feet. The compartment has a concrete floor, walls, and ceiling. A228 Fire Analysis Results Three fire scenarios are identified for this room, one for each pump. Given the configuration of the room, damage due to a pump fire is limited to the pump itself. The pump scenarios are screened due to the low fire frequencies and limited fire damage. The worst case postulated transient fire wguld cause no damage to cable trays or conduits and the only other targets are the CCW pumps. The plant impact due to fire frequency is bounded by the individual component failure rates used in the internal events CCPRA, and as a result, this room has no additional equipment impact due to fire. This room is screened due to low ignition frequency. Fixed Ignition Sources In the CCW Pump Room, the battery-operated emergency lighting, general area lighting, and small junction boxes are excluded from the fire modeling process on the basis that they would not be the source of fire intensity sufficient to result in other equipment damage. Several control and relief valves, which have a metal housing, are also excluded. A fire in these items would be small and confined within the boundaries of the item itself. Therefore. the only plausible ignition sources in the CCW Pump Room are the three CCW pumps. Suppression Systems The CCW Pump Room is equipped with a wet pipe automatic sprinkler fire suppression and smoke detectors. Compartment fire modeling does not take credit for the suppression. Fire SuDnression Induced Equipment Failures Based on the approach described in Section 4.3.4.4.4, equipment failure due to the inadvertent actuation of the automatic fire suppression system is assumed not to occur. Cable and conduit, pumps and other PRA equipment in the room are not considered to be susceptible to water damage. In the event of a suppression actuation, the motors are of a design that prevents water spray intrusion and their connections and wiring also resist water intrusion. In addition, cabling in the room is not affected by water spray. BGE 4-D-1 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events A306 Unit 1 Cable Spreading Room Location: 27' Auxiliary Building Fire Area: 16 CDF: 6.72E-6 The Unit I Cable Spreading Room (CSR) is the merging point for cables traveling to and from the Control Room. It also contains the following PRA related equipment:

• Unit I 120VAC Vital AC Distribution Panels (IYO0, IY02, 1Y03 and IY04) and their associated inverters
• 125VDC Distribution Panels (iDOl and ID02), associated DC sub-panels, and four associated chargers

                "     Unit I 120VAC Instrument Buses (IY09 and lYI0)
                " Unit 1 Engineering Safety Features Actuation System logic and actuation cabinets
                " Unit I Auxiliary Feedwater Actuation System logic and actuation cabinets The cable spreading room is rectangular with approximate dimensions forty-five feet wide, sixty-five feet long, and sixteen feet high. The nominal room area is 2,925 square feet. The room is separated from Unit 2 Cable Spreading Room by a common east-west wall which is a one hour fire rated barrier; a steel door is located in this wall at the west end.

The room contains numerous vertical floor mounted electrical cabinets aligned in rows. The majority of the cabinets are enclosed steel cabinets with sealed conduit entries. Some of the cabinets are designed with grates or vents in the top and/or sides (e.g., inverters). Numerous cable trays traverse horizontally in the ceiling. No motor driven equipment of significance exist in either compartment. Deterministic fire modeling will involve numerous cabinet fire scenarios with potential damage to overhead cable trays; depending on the details of the analysis, the individual cabinet fires may result in localized damage (i.e., damage only to the cabinet itself) or damage to abutted cabinets and/or cable trays due to radiant and conductive heat transfer. Fire Analysis Results One hundred and nineteen fire scenarios were identified for Unit 1 Cable Spreading Room. Ninety-four are the result of fixed ignition sources and twenty-five are due to transient ignition sources. These scenarios are represented by twenty-four fire initiating events. The consolidation of fire scenarios is based on an assessment of the functional impact and ignition frequency of each scenario. The frequency of each initiator is the sum of the frequencies of all the fire scenarios it represents. The tables below list individual fire scenarios. For each scenario the initiating component is damaged. RAN 97-031 4-E- I BGE 4-E- I RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Table 4-E-1 A306 Fixed Ignition Fire Scenarios Summary Scenario Fire Scenario Description Trays and Panels Damaged by Fire CI Reserve Battery Charger IAK30, IAH23 C2 23 Battery Charger No other effects C3 24 Battery Charger No other effects C4 II Battery Charger No other effects C5 12 Battery Charger No other effects C6 120VAC Instrument Transformer 11 No other effects C7 120VAC Instrument Bus i No other effects C8 120VAC Instrument Transformer 12 No other effects C9 120VAC Instrument Bus 12 No other effects C IO IB DG Logic Panel No other effects CI1 2A DG Logic Panel No other effects C12 125VDC Bus II IPNLIDII, IPNLIDI2, IPNLIDi3 C13 125D Distribution Panel ID IIPNLIDOI, IPNLID12, IPNLlDI3 C14 125D Distribution Panel ID12 IPNLIDO, IPNLIDI1, IPNLID13 C15 125D Distribution Panel ID13 IPNLIDOI, IPNLIDl I, IPNLIDI2 C16 125VDC Bus 12 IPNLIDI4 C17 125D Distribution Panel ID14 IBUSID02 C18 125D Distribution Panel ID15 IPNLID16, IPNLID17 C19 125D Distribution Panel ID16 IPNLIDIS, IPNLID17 C20 125D Distribution Panel ID17 IPNLIDI5, IPNLIDI6 C21 I ESFAS ACT RELAY Panel ZA IPNLIC67L C22 I ESFAS ACT Panel ZA IPNLIC67, IPNLIC91 C23 I ESFAS ACT RELAY Panel ZB IPNLIC68L C24 I ESFAS ACT Panel ZB IPNLIC68, IPNLIC94 C25 I ESFAS Sensor Panel ZD IPNLIC67L, IPNLIC92 C26 I ESFAS Sensor Panel ZE IPNLIC91, IPNLIC93 C27 I ESFAS Sensor Panel ZF IPNLIC92, IPNLIC94 C28 I ESFAS Sensor Panel ZG IPNLIC68L, IPNLIC93 BIGE 4-E-2 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Table 4-E-I A306 Fixed Ignition Fire Scenarios Summary (Continued) Scenario Fire Scenario Description Trays and Panels Damaged by Fire C29 AFAS A ACT Cabinet IAG51, IAG49, IAG33, IPNLICIOOD, IPNLICIOOF C30 AFAS B ACT Cabinet IAG51, lAG49, IAG33, IPNLICI00E, IPNLICI0OG C31 AFAS D Sensor Cabinet IAGSl, lAG49, 1AG33, IPNLICIOOA, IPNLICIOOE, IPNLICI00F C32 AFAS E Sensor Cabinet IAG51, lAG49, IAG33, IPNLICIOOB, IPNLIC100D, PNLICi00G C33 AFAS F Sensor Cabinet IAG51, lAG49, lAG33, IPNLICIOOA, IPNLICI00D C34 AFAS G Sensor Panel 1AG51, IAG49, IAG33, IPNLICI00B, IPNLICIOOE C35 120VAC Inverter Backup Bus No other effects C36 120VAC Inverter I I IAL06, IAJOI, IAL76, IAJ07, IAL93, IAJI3, 1AL86 C37 120VAC Distribution Panel II No other effects C38 REACTOR CLNT SYS CHANNELS 1AG26, 1AK77 C39 120VAC Inverter 12 IAH91, 1AL40, 1AK24 C40 120VAC Distribution Panel 12 No other effects C41 120VAC Distribution Panel I AG23 C42 120VAC Inverter 13 IAF96, IWW55, IAL22, lAGO2 C43 120VAC Distribution Panel 13 No other effects C44 120VAC Regulating X I I No other effects C45 120VAC Inverter 14 IAH52, IAF25 C46 120VAC Distribution Panel 14 No other effects C47 120VAC Computer Inverter II 1AJ23, IAL59, IAJ30, IAF98 C48 IROIB Instrument Power Supply 1PNLIR0IB C49 IROWB Instrument Power Supply IPNL1R0IA C50 Reactor Trip Switchgear Cabinet A IAH33, IAH26, IPNLIQOIB C51 Reactor Trip Switchgear Cabinet B IAH33, IAFII, IAH26, IAF04, IPNLIQOIA, IPNLIQ0IC C52 Reactor Trip Switchgear Cabinet C IAH33, IAFII, IAH26, IAF04, 1PNLIQOIB, IPNLIQOID C53 Reactor Trip Switchgear Cabinet D IAH33, IAE96, IAF03, IAH26, IAHI0, IPNLIQOIC, IPNLIQOIE C54 Reactor Trip Switchgear Cabinet E IAH26, IAF03. IAE96, IAH33, IPNLIQ01D C55 II MT EHC Panel IAL90, IAJO9, IAL04, I11I5 C56 TUIRB AUX SUPERVISORY INST IAJI5 13GE 4-E-3 RAN 97-031

Calvert Cliff Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Table 4-E-1 A306 Fixed Ignition Fire Scenarios Summary (Continued) Scenario Fire Scenario Description Trays and Panels Damaged by Fire C57 Shutdown CCP Panel IQ02B SEC3 1AG64, 1AF87, 1AG69, IPNLIQ02A/S2, IPNLIQ02B/S4 C58 Shutdown CCP Panel IQ02B SEC4 IAFIO, 1AG65, IAG70, IPNLIQ02B/S3, IPNLIQ02B/S5 C59 Shutdown CCP Panel IQ02B SEC5 IAFIO, 1AG65, lAG70, IPNLIQ02B/S4, IPNLIQ02B/S6 C60 Shutdown CCP Panel IQO2B SEC6 IAG6S, IAG70, IPNLIQO2B/S5, IPNLIQ02B/S7 C61 Shutdown CCP Panel IQ02B SEC7 1AG65, IAG70, IAF03, IPNLIQ02B/S6, IPNLIQ02B/S8 C62 Regulating CCP Panel IQ02C SEC-8 IAG70, IAF03, lAG65, IPNLIQ02B/S7, IPNLIQ02B/S9 C63 Regulating CCP Panel IQ02C SEC 9 lAG70, IAG65, IPNLIQ02B/S8, IPNLIQ02B/SIO C64 Regulating CCP Panel 1Q02C SEC 10 IAE95, IAG71, 1AG66, IPNL1Q02B/S9, IPNLIQ02B/SI I C65 Regulating CCP Panel IQ02C SEC I I IAE95, IAG71, IAG66, IPNLIQ02B/SIO, IPNLIQ02B/SI2 C66 Regulating CC, Panel IQ02C SEC 12 1AF77, IAG71, 1A73, IPNLIQ2B/S 11, 1PNLI Q2B/S13 C67 Regulating CCP Panel IQ02C SEC 13 IAF77, IAG7I, IAF73, IAG66,IPNLIQB 2B!SI2, IPNLIQ02BIS14 C68 Regulating CCP Panel IQ02C SEC 14 1AF77, IAG7I, IAF73, lAG ,IPNLIQ02B/SI Q,1P/2B/SIS C69 Regulating CCP Panel IQ02C SEC 15 1AG72, 1AG67, IPNLIQ02B/SI4, IPNLIQ02B/S16 C70 Regulating CCP Panel IQ02C SEC 16 1AG72, 1AG67, IPNLIQ02B/SI5 C71 Transformer/Generator Relay Panel 1AG73, lAF40, 1AF37, IPNLIC40B C72 Transformer/Generator Relay Panel A lAG73. LAF40, 1AF37, IAK97, 1AL95, IPNLIC40A, IPNLIC40C C73 Transformer/Generator Relay Panel B IAF40, IPNLIC40B, IPNLIC40D C74 Transformer/Generator Relay Panel C 1AF33, IAL95, 1AK97, 1AF62, 1AG73, lAF35, IINLIC40C, IPNLIC40E C75 Transformer/Generator Relay Panel D IAF35, 1AF62, lAF32, IAF31, IAF30, 1AF33, IAF29, IAF28, IAG73, IPNLlC40D, IPNLIC40F C76 Transformer/Generator Relay Panel E 1AF32, 1AF28, 1AF29, IAF31, lAF30, IFNLIC4OE, IPNLIC400 C77 Transformer/Generator Relay Panel F IAF30, lAF31, 1AF28, 1AF32, 1AF29, IPNL1C40F C78 Annunciator Logic Panel IK03 IAF25, IAH32 C79 125D Reserve Charger Disconnect DS0 No other effects C80 125D Reserve Charger Disconnect ID5 No other effects C81 125D Reserve Charger Disconnect ID56 No other effects C82 125D Reserve Charger Disconnect ID58 < No other effects > BGE 4-E-4 RAN 97-031

Calvert Cliffs Nuclear Power Plant Interal Fire Analysis Individual Plant Examination External Events Table 4-E-1 A306 Fixed Ignition Fire Scenarios Summary (Continued) Scenario Fire Scenario Description Trays and Panels Damaged by Fire C83 Battery Transfer Switch No other effects C84 Annunciator Logic Cabinet IPNLIK02, IJ207 C85 Annunciator 12 Logic Panel IPNL1K0I C86 CEDS CEA Control Panel IPNLIQ03-2, IPNLIQ03A C87 CEDS CEA Control Panel IPNLIQ03-1, IPNLIQ03-3 C88 CEDS CEA Control Panel IPNLIQ03-2, IPNLIQ03-4 C89 CEDS CEA Control Panel IPNLIQ03-3, IPNLIQ03B C90 CEDS CEA Control Panel IPNLIQ03-1 C91 CEDS CEA Control Panel IPNLIQ03-4 C92 Transformer I X21 No other effects C93 1201 Bus IY09/I YI0 TIE BK No other effects C94 Unit XFRM Net Power Output Panel < No other effects > Table 4-E-2 A306 Transient Fire Scenarios Summary Scenario Description Trays and Panels Damaged by Fire Tl ESFAS (Component only) T2 AFAS (Component only) T3 IQ02(s) (Component only) T4 Any IQ03 section (Component only) TS Any IC40 panel (Component only) T6 Any 1Q01 section (Component only) T7 IY09 OR IYI0 (Component only) TS ITI I (Component only) T9 IT 14 (Component only) TIO IROIA/B (Component only) Ti1 Single battery charger (Component only) BGE 4-E-5 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Table 4-E-2 A306 Transient Fire Scenarios Summary (Continued) Scenario Description Trays and Panels Damaged by Fire T12 Single inverter (Component only) T13 DC21 (IDIS, 1D16, or 1D17) (Component only) T14 DCI2 (ID02 or ID14) (Component only) TI5 IKO1/IKO2 (Component only) T16 IK03 (Component only) T17 EDG Logic Panels (IC70, 1C69/2C70) (Component only) TI 8 Single Vital AC panel (Component only) T19 Both IX08 and IX09 (Component only) T20 1D131, ID12, ID13, OR ID01 (Component only) T21 1Y03 and IY04, (Component only) T22 Reserve charger (Component only) T'23 Reserve switchgcar (Component only) T24 Back up Bus (Component only) T25 Computer Inverter (Component only) BGE 4-E-6 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Table 4-E-3 Cable Spreading Room Fire Analysis Results Initiating Fire Freq Ignition Functional CDF Event Scenario Source Impact A306FI CI, C57-59, I.SE-5 Reserve Battery Charger, Shutdown HRM XW, QZ*, QQ, 3.02E-9 C66-68, C78 CCP Panel I Q02B SEC3, Shutdown RS*, TX*, DW, DV, CCP Panel IQ02B SEC4, Shutdown BS, PV*, MN, IA*, CCP Panel IQ02B SEC5, Regulating IB*, CV, SA*, SB*, CCP Panel IQ02C SEC 12, Regulating EA*, EB*, RA*, RB*, CCP Panel IQ02C SEC 13, Regulating PA*, PB* CCP Panel 1Q02C SEC 14, Annunciator Logic Panel IK03 A306F2 Cl 1-15, C47, 1.16E-4 2A DG Logic Panel, 125VDC Bus 11, DA, GH, HR, XW, QQ, 4.23E-6 TI 1, T17, 125D Distribution Panel IDI 1, 25D NR, NS, KY, KS, RS*, T20 Distribution Panel It) 12, 125D TX*, TI, VC, RQ, Distribution Panel ID1)3, 120VAC MP*, SL*, MN, FT, Computer Inverter 11, Single battery Fl0, LF, CV charger, Transient damage to EDG Logic Panels (tC70, 1C69/2C70), IDI I, ID12, ID13, OR IDOl A306F3 C3, C5, C16, 2.41E-5 125VDC Bus 12, 125D Distribution DB, HR, XW, QQ l.OIE-8 C17, TI 1, Panel IDI4, 24 Battery Charger, 12 T14 Battery Charger, Transient damage to Single battery charger, DCI2 (ID02 or ID14) A306F4 C6, C7, T7 2.OIE-4 120VAC Instrument Transformer 11, HR, XW, QQ, E5 2.56E-8 120VAC Instrument Bus 11, Transient damage to IY090 A306F5 C8, C9, T7 2.O0E-4 120VAC Instrument Transformer 12, HR, XW, QQ, E6 6.53E-9 120VAC Instrument Bus 12, Transient Damage to IYI0 A306F6 T19 1.74E-7 Transient induced IXOS and IX09 fires HR., XW, QQ, ES, E6 2.30E-10 A306F7 CIO, C18-20, 4.37E-6 IB DG Logic Panel, 125D Distribution DC, GG, HR, XW,QQ 5.91E-8 T13, T17 Panel iDIS, 125D Distribution Panel 1D16, 125D Distribution Panel 1D17, Transient damage to DC21 (ID 15, ID16, or IDI7), EDG Logic Panels (IC70, 1C69/2C70) A306F8 C21-27. TI 7.59E-6 ESFAS Actuation Relay Panel ZA, ESFAS Spurious 2.2 1E-7 ESFAS Actuation Panel ZA, ESFAS Channel A or B Actuation Relay Panel ZB, ESFAS actuation, HIR XW, QQ Actuation Panel ZB, ESFAS Sensor Panel ZD, ESFAS Sensor Panel ZE, ESFAS Sensor Panel ZF, Transient damage to ESFAS RAN 97-031 4-E-7 BGE 4-E-7 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Table 4-E-3 Cable Spreading Room Fire Analysis Results (Continued) Initiating Fire Freq Ignition Functional CDF Event Scenario Source Impact A306F9 C29-34, T2 5.58E-6 AFAS A Actuation Cabinet, AFAS B HR. XW, QZ*, QQ, S4, 6.77E-10 Actuation Cabinet, AFAS D Sensor FI*, K4, PA*, PB* Cabinet, AFAS E Sensor Cabinet, AFAS F Sensor Cabinet, AFAS G Sensor Panel, Transient damage to AFAS A306FA C36, C51, 4.07E-5 120VAC Inverter 1I, Reactor Trip El, EA*, EB*, GE, 2.33E-7 C52, T6, T12, Switchgear Cabinet B, Reactor Trip GG*, GH, SAM, SB*, TIS Swltchgear Cabinet C, Transient damage HS, HS*, AC*, HH*, to Single inverter, Single Vital AC HR, XW, QQ, QZ*, panel, Any IQ01 section N&, NS*, S3, KX, KZ, KS, RS*, TX*, MC, VC, RR, BV, DW, DV, BS, RQ, MP, MN, IA, IB*, FT*, LF, CV. HA, RA, WY*, CS, K3, PA, PV*, PBO, RB$ A306FB C37 7.36E-7 120VAC Panel IYOI El, HR, XW, QQ 1.10E-10 A306FC C38, T21 8.52E-7 120VAC Panel IYOI-1, and Transient E3, E4, HR, XW, QQ, 6.17E-8 induced IY03 and IY04A fires RS*,TX*, TI A306FD C39, T12, 3.76E-5 120VAC Inverter 12, and Transient E2, GO, HS*, HH*, 5.19E-7 T18 induced inverter and vital AC panel fires HR, XW, QZ*, QQ, NRs, S2, S4, TA, TB, KY, RS*, TX*, TT*, TI, PS*, PV#, PN, MP, SL*, MN, IA*, IB, FT, LF, CV, SA*, SB*, MV, HB, DL*, EA*, EB*, RA*, RB, CT, SRO, K4, TW, PA', PB* A306FE C40, C41 1.47E-6 120VAC Panel 12 (1Y02) E2, HR, XW, QQ, 2.05E-9 A306FF C42, T12, 3.76E-5 120VAC Inverter 13, and Transient E3, GE, OH, HH*, HR, 4.36E-7 T18 induced inverter and vital AC panel fires XW, QZ*, QQ, KS, PV*, MN*, IAO, IB*, FT*. CV, SAO, SB*, V 1, MV, VS. DLO, EA. WY*, SH*, SR*, TE A306FG C43 7.36E-7 120VAC Panel 13 (1Y02) E3, HR, XW, QQ 1.39E-10 A306FH C45, T12, 3.76E-5 120VAC Inverter 14, and Transient E4, HRM XW, QZ*, QQ, 8.61E-8 T18 induced inverter and vital AC panel fires RSO, TX*, DW, DV, BS, PV*, MN, IB*, CV, SAO, SBO, EA*, EB*, PA', PB' BGE 4-E-8 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Table 4-E-3 Cable Spreading Room Fire Analysis Results (Continued) Initiating Fire Freq Ignition Functional CDF Event Scenario Source Impact A306FT C46 7.36E-7 120VAC Panel 14 (1Y04) E4, HR, XW, QQ 1.87E-10 A306FJ C48, C49, 3.22E-6 NSR DC Instrument PWR Supply HR, XW, QQ, ES, BS 3.45E-9 TI0 (IROIA), and Transient induced IROIA/B fmrs A306FK C50, C53, 3.68E-6 Reactor Trip SWGR A, C or D HH*, HRi XW, QZ*, 1.69E-9 C54, C64, QQ, S3, TA, TB, RS*, C65 TX, RR, PV*, SA*, SB*, EA*, EB*, CS, SG*, K3, PA*, PB* A306FL C55, T8 1.43E-6 EHC Panel 11, and Transient induced Y I, AA, HR, XW, QQ, 3.09E-8 ITI I fires NR*, NSO, TA, TB, KS, TX, TT*, BV, DW, BS, RQ, SL*, MN, FT, LF, CV, WY*, CS, K3 A306FM C71-77, TS 7.11 E-6 Transformer/Generator Relay panels: OP, GJ, AA, HR, XW, 7.67E-7 IC40AB,C,D,E,F or G, and Transient QQ, KZ, RS*, RR. DW, induced IC40 panel fires PV*, RQ, SL*,CV, SA*, SB*, HB, EA*, EB*, PA*, PB* A306FN C35, C44, 6.26E.4 120VAC Inverter Backup Bus (lYI1), HR, XW, QQ 2.32E-8 C56, C60-63, 120VAC Regulator X Transformer 11, C69, C70, Turb Aux Supervisory Inst Panel (IT14), C79-94, T3, Shutdown Rod Panels 5 or 6, Regulator T4, T9, TIS, Rod Panels 8 9,15 or 16, 125VDC T16, T22-25 Reserve Battery breakers and disconnect switches, Annunciator Panels IKOI or IK02, CEA Control Power cabinets, and Transient induced IQ02, IQ03, IT14, IKOI/IK02, IK03, reserve charger, reserve SWGR, BUB, and computer inverter induced fires A306FO C2, C4, TI I 2.1SE-5 Battery Charger II or 23, and Transient HR, XA*, XW, QQ 5.69E-10 induced battry charger fires

 *Note: The asterisk (*) indicates those top events which are impacted but not failed.

A306 Analysis The Cable Spreading Room damage is evaluated using screening distances. The screening included a radiant, and three (center, along wall, in comer) in-plume cases for both damage and ignition. Targets within the screening range are considered damaged or ignited. The screening calculation uses standard FIVE heat release rates except for open equipment, where the heat release rate is calculated. BGE 4-E-9 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events The screening distances, ignition source equipment heights, and cable tray heights are then analyzed to determine which trays are damaged or ignited. The results are then checked in the field for accuracy. Conservative judgment is applied when open cable trays are in stacks where lower trays ignited. In general, the fire propagation continued up the stack, or to a covered tray. No targets are analyzed as outside-plume cases. Targets that are potential outside-plume cases are treated as inside-plume plume targets and analyzed accordingly. When the ignition source abutted other panels, those panels were also considered damaged. The table below summarizes the various CSR equipment and configuration cases. Pre-Calculated Critical Damage Distances I p p- p CRITICAL DAMAGE DISTANCE FROM SOURCE IN FEET Damage I [gnition FIRE SOURCE R A D In-Plume I In-Plume HEAT Cony Rad A RELEASE HRR HRR N RATE Fracl Frac T TYPE ITEM SPECIFIC LFI LF2 LF4 LF1IILF2JILF4 hM I = Fixed Electrical Cabinet Closed 65 BTU/scc 0.8 0.4 N/A N/A N/A 1.4 NIA I /A INIA Vented 65 BTU/sec 0.8 0.4 3.4 4.5 6.0 1.4 2.8 3.7 4.9 Transformer Open 65 BTU/sec 0.8 0.4 3.4 4.5 6.0 1.4 2.8 3.7 4.9 Inverter Open 170 BTU/sec 0.8 0.4 5.2 N/A N/A 2.1 4.3 N/A N/A 101 Batery Charger Open 170 BTU/sec 0.8 0.4 N/A 7.0 N/A 2.1 N/A 5.5 N/A IC40B and E Open 270 BTU/scc 0.8 N/A 6.4 N/A N/A N/A 5.2 NIA N/A IC40A,C,D,F Open 190 BTU/sec 0.8 N/A 5.4 N/A N/A N/A 4.5 N/A N/A IC40G Open 130 BTU/sec1 0.8 N/A N/A 6.1 N/A N/A N/A 5.0 N/A Transient Trash Refuse 100 BTU/sec 0.8 0.4 4.5 5.9 7.8 .7 3.8 4.9 6.4 BGE 4-13-10 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events A306 Fire Ignition Frequency Both fixed and transient ignition frequencies were determined for the Unit 1 Cable Spreading Room. Fixed Ignition Frequency The fixed ignition frequency is determined by starting with the compartment fixed ignition frequency results of Section 4.3.2 and then developing a scenario specific ignition frequency as described in Section 4.3.4.3. The sources and parameters used for A306 are: Source Generic Fire Location Source Total Sources in Room Specific Frequency Weighting Weighting Aux Bldg Frequency Battery Chargers 4.OE-3 2 5 15 2.67E-3 Electrical Cabinets 3.2E-3 I - 3.20E-3 Transformers (Dry) 7.9E-3 2 5 80 9.88E-4 Fire Protection Panels 2.4E-3 2 1 35 1.37E-4

                                                                  -     -I BAT.ITERY CHARGERS The station battery chargers are analyzed as sealed electrical cabinets since their cooling fans have louvered shutters.

The Reserve Battery Charger, and open top cabinet, is evaluated using a calculated heat release rate based on an open door cabinet with unqualified cable, using the formula: HRR = 8.5E-04

• fuel loading The estimated HRR is 170 btu/sec.

ELECTRICAL CABINETS In accordance with FIVE, cabinets, control panels, and inverters fall into this category. Electrical cabinets represent potential fire sources that are difficult to characterize given the range of potential configurations. To facilitate the analysis, electrical cabinets are categorized consistent with the EPRI Fire PRA Implementation Guide as sealed, vented, and open. The fire modeling for each of these cabinet categories is performed as follows.

 ,    Sealed Cabinets Cabinets that are enclosed on all four vertical sides, as well as top and bottom, with no ventilation openings, grills or louvers are classified as sealed. For this type of cabinet it is assumed that the fire would not propagate beyond the contents of the cabinet itself. Damage to adjacent cabinets and nearby metal encased cable trays is analyzed using the air gap approach Combustion products will suppress fire growth; as such, a significant fire will not result to warrant more than the Radiant Heat Worksheet calculation.

RAN 97-031 4-E-1 I EGE BGE 4-E-1I1 RAN 97-031

Calvert Cliffs Nuclear PoweT Plant Internal Fire Analysis Individual Plant Examination External Events Fires in enclosed vertical electrical cabinets are assumed to fail only components within that particular cabinet. It is assumed that no damage occurs to adjacent cabinets, provided that cabinets are separated by a double wall with an air gap, and there is no sensitive equipment contained within the adjacent cabinet. Enclosed cabinets in the cable spreading room are assumed not to propagate a fire beyond the boundaries of the cabinet itself.

• Vented Cabinets Cabinets with no top ventilation, but having grills or louvers on at least one vertical side, are classified as vented. The analyzed height of fire is assumed to be the height of the top louver.

Damage to adjacent cabinets and nearby metal encased cable trays is analyzed using the air gap approach. Fire damage analysis for targets above these cabinets used the In-plume Worksheets, using a convective Heat Release Rate (HRR) of 80% (subtracting 20% of the HRR associated with radiant heat), per the EPRI Fire PRA Implementation. These cabinets are also analyzed for potential fire damage using the Radiant Heat worksheet for nearby exposed vertical and horizontal (overhead) cable trays; conservatively, 40% of the total HRR is assumed to be radiant.

• Open Cabinets (Inverters)

Cabinets with ventilation on the top of the cabinet (e.g., screened tops, ventilation fans) are categorized as open. The analyzed height of fire is assumed to be the height of the top of the cabinet. Damage to adjacent cabinets and nearby metal encased cable trays is analyzed using the air gap approach. In the cable spreading room, the only open top cabinets are the inverters. Fire damage analysis for targets above such cabinets is used In-plume Worksheets. Using the HRR for an open door cabinet with non-qualified cable, the calculated HRR for inverters is 170 btu/sec. These cabinets are also analyzed for potential fire damage using the Radiant Heat worksheet for nearby exposed vertical and horizontal (overhead) cable trays.

• IC40 Panels The unit protection panels (A through F) are located behind a partial height gypsum wall and locked door. They are full height vertical switchboards typical of station protection equipment including mounted drawout protective relays, lockout devices, indicators, and test facilities.

These components represent a small fuel loading (the largest equipment is protective relays which are inside a sealed metal enclosure). There are no barriers or metal extensions between panel sections. Due to their vertical construction, it is unlikely that a fire in these panels would spread or propagate in a horizontal plane. Conservatively, it is assumed that the fire would be one panel wide (about three feet). BGE 4-E--12 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Due to the open configuration, panel heat release rates (HRR) are calculated based on an open door cabinet with unqualified cable, using the formula: HRR = 8.5E-04

• fuel loading The HRRs are then binned into one of three ratings, 130, 190, or 270 btu/sec.

Cabinet and control panel (but not inverter) ignition frequencies are multiplied by a 0.2 severity factor: This value bounds various severity factors (except diesel generators) and is, therefore, conservative. It is assumed that only severe fires generate enough smoke to challenge room habitability, but, any fire is sufficient to actuate the room fire suppression. TRANSFORMERS Transformers in the cable spreading room have a single slit vent at the top edge and are analyzed consistent with the approach used for vented electrical cabinets. The analyzed height of fire is assumed to be the height of the top louver. Damage to adjacent cabinets and nearby metal encased cable trays is analyzed using the air gap approach. The damage distance to targets above the transformers is calculated using In-plume Worksheets and a convective Heat Release Rate (HRR). They are also analyzed for potential fire damage using the Radiant Heat worksheet for nearby exposed vertical and horizontal (overhead) cable trays. Because of dense wiring mass, the transformer severity factor is assumed to be 1.0. FIRE PROTECTION PANELS The sole fire protection panel is a small sealed cabinet with sealed conduit entries. It has been excluded from further analysis since any ignition would be small and confined within the cabinet itself. CALCULATION OFCOMPONENTFIXED IGNITION FREQUENCY Each individual component is assigned an ignition frequency apportioned by dividing the compartment specific frequency for the component type by the total number of each ignition source of that type. The chart below summarizes the calculation and incorporates the applicable severity factor. A306 Equipment Count and Individual Frequency Summary Equipment Panel Room Specific Severity Individual Type Count Frequency Factor Frequency Battery Chargers 5 2.67E-3 0.2 1.07E-5 Electrical Cabinets or Panels 87 3.20E-3 (Cabinet or Panel) (80) 0.2 7.36E-7 (Inverter) (7) 1.0 3.68E-5 Transformers 5 9.88E-4 1.0 1.98E-4 Fire Protection Panels I 1.37E-4 0.2 2.74E-6 I __ __ _I RAN 97-031 4-E-13 BGE BGE 4-E- 13 RAN 97-031!

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Transient Ignition Frecuency The transient ignition frequency is determined by starting with the compartment transient ignition frequency results of Section 4.3.2 and then developing a scenario specific ignition frequency as described in Section 4.3.4.3. The sources and parameters used for A306 are: Source Generic Fire Location Source Total Sources in Room Specific Frequency Weighting Weighting Aux Bldg Frequency Cable fires - welding 5.1 E-3 2 1 232 4.40E-5 Transient fires - welding 3. IE-2 2 1 232 2.67E-4 Transient - other 1.3E-3 2 7 232 7.84E-5 The transient fire is modeled as a maintenance refuse fire and, therefore, uses the "Transient - other" as the ignition frequency, F1 , = 7.84E-05. Fire suppression is not credited in this analysis. Therefore, conservatively, Pp = 1.0. TRANSIENT COMBUSTIBLE IN RANGE OF TARGETS (U) AND RESULTING FREQUENCY The formula for the Transient Combustible in Range of Targets (u) is: u = (As + As,) AF The refuse fire In-Plume worksheets show that the worst case plume (a comer configuration) is eight feet above the source, a three feet tall fire. The lowest overhead CSR cable trays are about ten feet up, but the comer location trays are higher. Therefore, it is judged unlikely that overhead cable damage will result from a postulated transient fire and A, = zero. The remaining damage assessment centered on radiant damage to floor mounted equipment. The radiant damage distance for the 100 btu/sec trash can fire is 1.8 feet (using a critical flux value of 1.0 btu/sec/f 2 ). The Asr for each component or equipment grouping. (depending on the physical arrangement) is estimated by multiplying a 1.8 foot margin times the available floor area around the target component. The cable spreading room floor area is approximately 2,925 square feet. The floor area displaced by cabinets is calculated by summing the individual cabinet areas using the Asr perimeter dimensions as length and width. The total cabinet area is 496 square feet, so: A, = 2925ft - 496ft2 = 2,429ft2 and for the CSR, u = As, / AF and: Pp= 1 Since: F,= F,

• u
• P1 3 = F,, * [A,/AF]
• I

                                                   =   7.84E-4 * [A / 2429W)]

BGE 4-E-14 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events The grouping of similar components resulted twenty-five scenarios, tabularized below. Table 4-E-4 A306 Transient Fire Scenarios and Frequency Summary Scenario Description A. Fit Number of Floor cabinets Area TI ESFAS 76 2.44E-06 1 38 T2 AFAS 36 1.16E-06 1 16 T3 IQ02(s) 99 3.20E-06 1 63 T4 Any IQ03 section 52 1.69E-06 1 42 T5 Any IC40 panel 61 1.96E-06 1 8 T6 Any IQ01 section 52 1.69E-06 1 48 T7 IY09 OR IYIO 23 7.56E.07 2 24 T8 ITI1 22 6.98E-07 1 10 T9 IT14 10 3.34E-07 1 2 TIO IROIA/B 54 1.74E-06 1 36 TI1 Single battery charger 16 5.14E-07 4 32 T12 Single inverter II 3.68E-07 4 32 T13 DC21 (IDI5, 1D16, or ID17) 28 9.01E-07 1 0 T14 DC12 (1D02 or ID14) 25 8.14E-07 1 17 TI5 1KOI/IK02 28 8.91E-07 1 7 T16 1K03 10 3.20E-07 1 7 T17 EDG Logic Panels (IC70, IC69/2C70) 16 5.23E-07 2 10 T18 Single Vital AC panel 13 4.07E-07 4 10 T19 Both IX08 and IX09 5 1.74E-07 1 7 T20 IDI 1, ID12, ID13, OR IDO1 37 1.20E-06 1 31 T21 IY03 and IY04A 4 1.16E-07 I 0 T22 Reserve charger 3! 1.0E-06 1 17 T23 Reserve switchgear 13 4.07E-07 6 36 T24 Back up Bus 8 2.62E-07 1 5 T25 Computer Inverter 27 8.72E-07 I 1i L-. RAN 97-031 4-E- 15 BGE 4-E- 15 RAN 97-031

Calvert Clifts Nuclear Power Plant Intrnal Fire Analysis Individual Plant Examination External Events Total Ignition Frequency Equipment and trays damaged in each scenario (transient and fixed) were mapped to corresponding plant model top events. The top events are then binned for impact. The binnings are then used to group the fire scenarios into plant model scenarios. Each plant model scenario is the sum of individual fire scenarios listed below. Plant model scenario A306FI: CI Reserve Battery Charger 1.07E-05 C57 Shutdown CCP Panel IQ02B SEC3 7.36E-07 C58 Shutdown CCP Panel IQ02B SEC4 7.36E-07 C59 Shutdown CCP Panel I Q02B SEC5 7.36E-07 C66 Regulating CCP Panel IQ02C SEC 12 7.36E-07 C67 Regulating CCP Panel 1Q02C SEC 13 7.36E-07 C68 Regulating CCP Panel I Q02C SEC 14 7.36E-07 C78 Annunciator Logic Panel 1K03 7.36E-07 Total frequency for plant model A306F1 is; 1.58E-05 Plant model scenario A306F2: C11 2A DG Logic Panel 7.36E-07 C12 125VDC Bus I I 7.36E-07 C 13 125D Distribution Panel I D 1 7.36E-07 C14 125D Distribution Panel ID12 7.36E-07 C 15 125D Distribution Panel 1D 13 7.36E-07 C47 120VAC Computer Inverter I 1 1.1OE-04 T11 Single battery charger 5.14E-07 T 17 EDG Logic Panels (1C70, IC69/2C70) 5.23 E-07 T20 IDI1, 1D12, ID13, OR 1D01 1.20E-06 Total frequency for plant model A306F2 is: 1.16E-04 BGE 4-E-16 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Plant model scenario A306F3: C16 125VDC Bus 12 7.36E-07 C17 125D Distribution Panel ID14 7.36E-07 C3 24 Battery Charger 1.07E-05 C5 12 Battery Charger 1.07E-05 Ti i Single battery charger 5.14E-07 T14 DCi2 (1D02 or ID14) 8.14E-07 Total frequency for plant model A306F3 is: 2.4 1E-05 Plant model scenario A306F4: C6 120VAC Instrument Transformer 11 2.OOE-04 C7 120VAC Instrument Bus 11 7.36E-07 T7 IY09 OR IYl0 (1Y09) 7.56E-07 Total frequency for plant model A306F4 is: 2.01E-04 Plant model scenario A306F5: CS 120VAC Instrument Transformer 12 2.00E-04 C9 120VAC Instrument Bus 12 7.36E-07 T"7 IY09 OR lY10 (lYlO) 7.56E-07 Total frequency for plant model A306F5 is: 2.01E-04 Plant model scenario A306F6: T19 Both IX08 and IX09 1.74E-07 Total frequency for plant model A306F6 is: i .74E-07 RAN 97-031 4-E-1 7 BGE 4-E- 17 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Plant model scenario A306F7: CIO l B DG Logic Panel 7.36E-07 C18 125D Distribution Panel ID15 7.36E-07 C19 125D Distribution Panel 1D16 7.36E-07 C20 125D Distribution Panel 1D 17 7.36E-07 T13 DC21 (1D15, 1D16, or ID17) 9.01E-07 T17 EDG Logic Panels (1C70, 1C69/2C70) 5.23E-07 Total frequency for plant model A306F7 is: 4.37E-06 Plant model scenario A306F8: C21 I ESFAS ACT RELAY Panel ZA 7.36E-07 C22 1 ESFAS ACT Panel ZA 7.36E-07 C23 I ESFAS ACT RELAY Panel ZB 7.36E-07 C24 I ESFAS ACT Panel ZB 7.36E-07 C25 1 ESFAS Sensor Panel ZD 7.36E-07 C26 1 ESFAS Sensor Panel ZE 7.36E-07 C27 1 ESFAS Sensor Panel ZF 7.36E-07 TI ESFAS 2.44E-06 Total frequency for plant model A306F8 is: 7.59E-06 Plant model scenario A306F9: C29 AFAS A ACT Cabinet 7.366E-07 C30 AFAS B ACT Cabinet 7.36E-07 C3 1 AFAS D Sensor Cabinet 7.36E-07 C32 AFAS E Sensor Cabinet 7.36E-07 C33 AFAS F Sensor Cabinet 7.36E-07 C34 AFAS G Sensor Panel 7.36E-07 12 AFAS 1.1 6E-06 Total frequency for plant model A306F9 is: 5.58E-06 BGE 4-E- 18 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Plant model scenario A306FA: C36 120VAC Inverter I I 3.68E-05 C51 Reactor Trip Switchgear Cabinet B 7.36E-07 C52 Reactor Trip Switchgear Cabinet C 7.36E-07 T12 Single inverter 3.68E-07 TI 8 Single Vital AC panel 4.07E-07 T6 Any 1Q01 section 1.69E-06 Total frequency for plant model A306FA is: 4.07E-05 Plant model scenario A306FB: C37 120VAC Distribution Panel II 7.36E-07 Total frequency for plant model A306FB is: 7.36E-07 Plant model scenario A306FC: C38 REACTOR CLNT SYS CHANNELS 7.36E-07 T121 1Y03 and IY04A 1.16E-07 Total frequency for plant model A306FC is: 8.52E-07 Plant model scenario A306FD: C39 120VAC Inverter 12 3.68E-05 T12 Single inverter 3.68E-07 TI8 Single Vital AC panel (1Y02) 4.07E-07 Total frequency for plant model A306FD is: 3.76E-05 RAN 97-031 4-E-19 BGE 4-E-19 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Plant model scenario A306FE: C40 120VAC Distribution Panel 12 7.36E-07 C41 120VAC Distribution Panel 7.36E-07 Total frequency for plant model A306FE is: 1.47E-06 Plant model scenario A306FH: C45 120VAC Inverter 14 3.68E-05 T12 Single inverter 3.68E-07 TIS Single Vital AC panel (IY04) 4.07E-07 Total frequency for plant model A306FH is: 3.76E-05 BGE 4-E-20 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Plant model scenario A306FI: C46 120VAC Distribution Panel 14 7.36E-07 Total frequency for plant model A306FI is: 7.36E-07 Plant model scenario A306FJ: C48 IROIB Instrument Power Supply 7.36E-07 C49 IRROB Instrument Power Supply 7.36E-07 TIO 1ROIA/B 1.74E-06 Total frequency for plant model A306FJ is: 3.22E-06 Plant model scenario A306FK: C50 Reactor Trip .Switchgear Cabinet A 7.36E-07 C53 Reactor Trip Switchgear Cabinet D 736E-07 C54 Reactor Trip Switchgear Cabinet E 7.36E-07 C64 Regulating CCP Panel 1Q02C SEC 10 7.36E-07 C65 Regulating CCP Panel IQ02C SEC 1I 7.36E-07 Total frequency for plant model A306FK is: 3.68E-06 Plant model scenario A306FL: C55 11 MT EHC Panel 7.36E-07 T8 ITI I 6.98E-07 Total frequency for plant model A306FL is: 1.43E-06 BGE 4-E-21 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Plant model scenario A306FM: C71 Transformer/Generator Relay Panel 7.36E-07 C72 Transformer/Generator Relay Panel A 7.36E-07 C73 Transformer/Generator Relay Panel B 7.36E-07 C74 Transformer/Generator Relay Panel C 7.36E-07 C75 Transformer/Generator Relay Panel D 7.36E-07 C76 Transformer/Generator Relay Panel E 7.36E-07 C77 Transformer/Generator Relay Panel F 7.36E-07 T5 Any IC40 panel 1.96E-06 Total frequency for plant model A306FM is: 7.11 E-06 Plant model scenario A306FO: C2 23 Battery Charger 1.07E-05 C4 11 Battery Charger 1.07E-05 Ti1 Single battery charger 5.14E-07 Total frequency for plant model A306FO is: 2.18E-05 B3GE 4-E-22 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Plant model scenario A306FN: C35 120VAC Inverter Backup Bus 7.36E-07 C44 120VAC Regulating X 11 4.OOE-04 C56 TURB AUX SUPERVISORY INST 7.36E-07 C60 Shutdown CCP Panel IQ02B SEC6 7.36E-07 C61 Shutdown CCP Panel IQ02B SEC7 7.36E-07 C62 Regulating CCP Panel 1Q02C SEC-8 7.36E-07 C63 Regulating CCP Panel 1Q02C SEC 9 7.36E-07 C69 Regulating CCP Panel IQ02C SEC 15 7.36E-07 C70 Regulating CCP Panel IQ02C SEC 16 7.36E-07 C79 125D Reserve Charger Disconnect 1D50 7.36E-07 C80 125D Reserve Charger Disconnect 1D55 7.36E-07 C81 125D Reserve Charger Disconnect ID56 7.36E-07 C82 125D Reserve Charger Disconnect ID58 7.36E-07 C83 Battery Transfer Switch 7.36E-07 C84 Annunciator Logic Cabinet 7.36E-07 C85 Annunciator 12 Logic Panel 7.36E-07 C86 CEDS CEA Control Panel 7.36E-07 C87 CEDS CEA Control Panel 7.36E-07 C88 CEDS CEA Control Panel 7.36E-07 C89 CEDS CEA Control Panel 7.36E-07 C90 CEDS CEA Control Panel 7.36E-07 C91 CEDS CEA Control Panel 7.36E-07 C92 Transformer 1X21 2.OOE-04 C93 1201 Bus IY09/1Y10 TIE BK 7.36E-07 C94 Unit XFRM Net Power Output Panel 7.36E-07 T3 1Q02(s) 3.20E-06 T4 Any IQ03 section 1.69E-06 T9 1T14 3.34E-07 TIS IK01/1K02 8.91E-07 T16 1K03 3.20E-07 T22 Reserve charger 1.01E-06 T23 Reserve switchgear 4.07E-07 T24 Back up Bus 2.62E-07 T25 Computer Inverter 8.72E-07 Total frequency for plant model A306FN is: 6.26E-04 RAN 97-03 1 4-E-23 BGE 4-E-23 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Fire Suppression Although an automatic total flooding halon suppression system is installed in the Cable Spreading Room, the probability of actuation prior to target damage is not evaluated as is the likelihood of fire brigade response to manually suppress the fire prior to target damage. Fire Suppression Induced Equipment Failure Further, when suppression actuates, the suppression agent (halon) causes no equipment damage. BGE 4-E-24 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events A302 Unit 2 Cable Spreading Room Location: 27' Auxiliary Building Fire Area: 17 CDF: 6.81E-7 The Unit 2 Cable Spreading Room (CSR) is the merging point for cables traveling to and from the Control Room. It also contains the following PRA related equipment:

                "     Unit 2 120VAC Vital AC Distribution Panels (2Y01, 2Y02, 2Y03 and 2Y04) and their associated inverters for 2Y03 and 2Y04
                "     125VDC Distribution Panels (2D01 and 2D02), associated DC sub-panels, and four associated chargers

• Unit 2 120VAC Instrument Buses (2Y09 and 2Y10)

                " Unit 2 Engineering Safety Features Actuation System logic and actuation cabinets
                "     Unit 2 Auxiliary Feedwater Actuation System logic and actuation cabinets The cable spreading room is rectangular with approximate dimensions forty-five feet wide, sixty-five feet long, and sixteen feet high. The nominal room area is 2,695 square feet. The room is separated from Unit I Cable Spreading Room by a common east-west wall which is a one-hour fire rated barrier and a steel door is located in this wall at the west end.

The room contains numerous vertical floor-mounted electrical cabinets aligned in rows. The majority of the cabinets are enclosed steel cabinets with sealed conduit entries. Some of the cabinets are designed with grates or vents in the top and/or sides (e.g., inverters). Numerous cable trays traverse horizontally in the ceiling. No motor-driven equipment of significance exist in either compartment. Deterministic fire modeling will involve numerous cabinet fire scenarios with potential damage to overhead cable trays; depending on the details of the analysis, the individual cabinet fires may result in localized damage (i.e., damage only to the cabinet itself) or damage to abutted cabinets and/or cable trays due to radiant and conductive heat transfer. Fire Analysis Results One hundred and eleven fire scenarios are identified for Unit 2 Cable Spreading Room. Eighty-eight are the result of fixed ignition sources and twenty-three are due to transient ignition sources. These scenarios are represented by twenty-four fire initiating events. The consolidation of fire scenarios is based on an assessment of the functional impact and ignition frequency of each scenario. The frequency of each initiator is the sum of the frequencies of all the fire scenarios it represents. The tables below list individual fire scenarios. For each scenario the initiating component is damaged. RAN 97-031 4-E-25 BGE 4-E-25 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Table 4-E-5 A302 Fixed Ignition Fire Scenarios Summary Scenario Fire Scenario Description Trays and Panels Damaged by Fire Ci 21 Battery Charger < No other effects > C2 22 Battery Charger < No other effects > C3 13 Battery Charger < No other effects > C4 14 Battery Charger < No other effects > C5 120VAC Instrument Transformer 21 < No other effects > C6 120VAC Instrument Bus 21 < No other effects > C7 120VAC Instrument Transformer 22 < No other effects > CS 120VAC Instrument Bus 22 < No other effects > C9 120VAC Bus 2YO9/2Y10 Tie Breaker < No other effects > CIO 2B DG Logic Panel < No other effects > CI1 125VDC Bus 21 2PNL2D 15, 2PNL2DI6, 2PNL2DI7 C12 125VDC Distribution Panel 2D1 S 2PNL2DOI, 2PNL2DI7, 2PNL2DI6 C13 125VDC Distribution Panel 2D 16 2PNL2DOI, 2PNL2DI5, 2PNL2DI7 C14 125VDC Distribution Panel 2D17 2PNL2DOI, 2PNL2D]5, 2PNL2DI6 C15 125VDC Bus 22 2PNL2DI4 C16 125VDC Distribution Panel 2D14 2BUS2DO2 C17 125VDC Distribution Panel 2D1 I 2PNL2DI2, 2PNL2DI3 C8 125VDC Distribution Panel 2D 12 2PNL2D 11, 2PNL2DI 3 C19 125VDC Distribution Panel 2D113 2PNL2D1 1, 2PNL2DI2 C20 ESFAS Actuation Relay Panel ZA 2PNL2C67L C21 ESFAS A Actuation Cabinet 2PNL2C67, 2PNL2C91 C22 ESFAS Actuation Relay Panel ZB 2PNL2C68L C23 ESFAS B Actuation Cabinet 2PNL2C68, 2PNL2C94 C24 ESFAS D Sensor Cabinet 2PNL2C67L, 2PNL2C92 C25 ESFAS E Sensor Panel 2PNL2C91, 2PNL2C93 C26 ESFAS F Sensor Cabinet 2PNL2C92, 2PNL2C94 C27 ESFAS 3 Sensor Cabinet 2PNL2C68L, 2PNL2C93 C28 AFAS A Actuation Cabinet 2AH53, 2AH51, 2PNL2C I00D, 2PNL2CI0OF BGE 4-E-26 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Table 4-E-5 A302 Fixed Ignition Fire Scenarios Summary (Continued) Scenario Fire Scenario Description Trays and Panels Damaged by Fire C29 AFAS B Actuation Cabinet 2AH53, 2AH51, 2PNL2CIOOE, 2PNL2CIOOG C30 AFAS D Sensor Cabinet 2AH53, 2AHS1, 2PNL2CI1OA, 2PNL2CIOOE, 2PNL2CI00F C31 AFAS E Sensor Cabinet 2AH53, 2AH51, 2PNL2CI1OB, 2PNL2CI00D, 2PNL2CI OOG C32 AFAS F Sensor Cabinet 2AH53, 2AH51, 2PNL2CIOOA, 2PNL2CI00D C33 AFAS 0 Sensor Cabinet 2AH53, 2AH5 I, 2PNL2C 100B, 2PNL2C IOOE C34. 120VAC Inverter Back up Bus < No other effects > C35 120VAC Inverter 21 2AKI 1, 2AI46, 2AJ38, 2AJ50, C36 120VAC Distribution Panel 21 < No other effects > C37 REACTOR COOLANT SYS CHANN 2AK12, 2AG43, 2AG37 C38 120VAC Inverter 22 2AF62, 2AG59 C39 120VAC Distribution Panel 22 < No other effects > C40 REACTOR CLNT SYS CH TR-12 2AG87, 2AH37, 2AG79 C41 120VAC Inverter 23 2AG53, 2AH99, 2AG60 C42 120VAC Distribution Panel 23 < No other effects > C43 120VAC Inverter 24 2AG26, 2AG44, 2AG38 C44 120VAC Distribution Panel 24 < No other effects > C45 120VAC Computer Inverter 2AG36, 2AH19, 2AG24 C46 Regulating Transformer for Back up Bus 2AH32 C47 2ROIA instrument Power Supply 2PNL2R0IB C48 2R01B Instrument Power Supply 2PNL2ROIA C49 2 RPS ReactorTrip Switchgear Cabinet A 2AH90, 2AF78, 2AH79, 2PNL2QOIB C50 2 RPS ReactorTtip Switchgear Cabinet B 2AH89, 2AH78, 2PNL2QO1A, 2PNL2QO1C C51 RPS Unit 2 ReactorTrip Switchgear 2AF72, 2AH89, 2AH71, 2AH78, 2PNL2QOIB, 2PNL2QOID C52 2 RPS ReactorTrip Switchgear Cabinet C 2AF72, 2AH89, 2AH71, 2AH78, 2PNL2QOIC, 2PNL2QOIE C53 2 RPS ReactorTrip Switchgear Cabinet D 2AF68, 2AH89, 2AH71, 2AH78, 2AH61, 2PNL2QOID C54 Electro-Hydraulic Control 2AK71, 2AJ48, 2AL05, 2AF80, 2AK09, 2AJ44, 2AJ36 C55 Shutdown CCP Panel 2Q02B SEC3 2AF84, 2AG93, 2AF82, 2AG85, 2PNL2Q02B/S04 C56 Shutdown CCP Panel 2Q02B SEC4 2AF84, 2AG93, 2AF82, 2PNL2QO2B/S03, 2PNL2QO2B/SO5 aI BGE 4-E-27 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Table 4-E-5 A302 Fixed Ignition Fire Scenarios Summary (Continued) Scenario Fire Scenario Description Trays and Panels Damaged by Fire C57 Shutdown CCP Panel 2Q02B SEC5 2AF84, 2AG93, 2AF82, 2PNL2QO2B/S04, 2PNL2QO2B/S06 C58 Shutdown CCP Panel 2QO2B SEC6 2AF77, 2AG93, 2AG85, 2PNL2QO2B/SO5, 2PNL2QO2B/S07 C59 Shutdown CCP Panel 2Q02B SEC7 2AF77, 2AG92, 2AG84, 2PNL2QO2B/S06, 2PNL2QO2B/SO8 C60 Regulating CCP Panel 2Q02C SEC 8 2AG92, 2AG84, 2PNL2Q02B/S07, 2PNL2QO2B/S09 C61 Regulating CCP Panel 2Q02C SEC 9 2AF72, 2AG92, 2AG84,2PNL2QO2B/S8,2PNL2QO2B/SIO C62 Regulating CCP Panel 2Q02C SEC 10 2AF72, 2AG92, 2AG84, 2PNL2QO2B/S09, 2PNL2QO2B/S1I C63 Regulating CCP Panel 2Q02C SEC 11 2AG92 2AG84,, 2PNL2QO2B/S0I, 2PNL2QO2B0I2 C64 Regulating CCP Panel 2Q02C SEC 12 2AG92, 2AF67, 2PNL2QO2C/SI 1, 2PNL2QO2C/S13 C65 Regulating CCP. Panel 2Q02C SEC 13 2AF67, 2AG84, 2A.55, 2AG92, 2PNL2QO2C/S 12, 2PNL2QO2C/SI4 C66 Regulating CCP Panel 2Q02C SEC 14 2A155, 2AG83, 2AG91, 2PNL2QO2C/S13, 2PNL2QO2C/S15 C67 Regulating CCP Panel 2Q02C SEC 15 2AG83, 2AG91, 2PNL2QO2C/SI4, 2PNL2QO2C/S16 C68 Regulating CCP Panel 2Q02C SEC 16 2AG83, 2AG91, 2PNL2QO2C/S I5, 2PNL2QO2C/S 17 C69 Regulating CCP Panel 2Q02C SEC 17 2AF61, 2AG91,2PNL2QO2C/S 16 C70 Transformer/Generator Relay Panel A 2AJ85, 2AJ31, 2AJ39, 2AG95, 2AG78, 2PNL2C40B C71 Transformer/Generator Relay Panel B 2AJ3 I, 2AG95, 2AJ.85, 2AJ39, 2PNL2C4OA, 2PNL2C40C C72 Transformer/Generator Relay Panel C 2AG95, 2AK04, 2PNL2C40B, 2PNL2C40D C73 Transformer/Generator Relay Panel D 2AG95, 2AJ21, 2AJ29, 2AJ27, 2PNL2C40C, 2PNL2C40E C74 Transformer/Generator Relay Panel E 2AG95, 2AJ21,2AJ29, 2AJ27, 2PNL2C40D, 2PNL2C40F C75 Transformed[Generator Relay Panel F 2AH94, 2AJ07, 2AJ14, 2AH82, 2AG95, 2AH93, 2PNL2C40E, 2PNL2C40G C76 Transformer/Generator Relay Panel G 2AH93, 2AH94, 2AJ07, 2AH82, 2AJ 14, 2PNL2C4OF C77 Annunciator Logic Panel 2AH88, 2AF62, 2AH77, 2AH70, 2AJ71 C78 Annunciator 21 Logic Control Panel 2PNL2KO2 C79 Annunciator 22 Logic Control Panel 2PNL2KOI C80 CEDS UNIT 2 CEA Control Panel 2PNL2Q03-2, 2PNL2QO3A C81 CEDS UNIT 2 CEA Control Panel 2PNL2QO3-1, 2PNL2QO3-3 C82 CEDS UNIT 2.CEA Control Panel 2PNL2QO3-2, 2PNL2QO3-4 C83 CEDS UNIT 2 CEA Control Panel 2PNL2QO3-3, 2PNL2QO3B BGE 4-E-28 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual'Plant Examination External Events Table 4-E-5 A302 Fixed Ignition Fire Scenarios Summary (Continued) Scenario Fire Scenario Description Trays and Panels Damaged by Fire C84 CEDS UNIT 2 CEA Control Panel 2PNL2QO3-, C85 CEDS UNIT 2 CEA Control Panel 2PNL2QO3-4 C86 Reserve Battery Disconnect Switch ID57 No other effects C85 CEDS UNIT 2 CEA Control Panel 2PNL2Q03-4 C87 125V Banery 01 DISC SW #2 No other effects C88 Transformer 2X2 1 No other effects RAN 97-031 4-E-29 BGE 4-E-29 RAN 97-031!

Calven Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examinaliod External Events Table 4-E-6 A302 Transient Fire Scenarios Summary Scenario Description Trays and Panels Damaged by Fire TI ESFAS (Component only) T2 AFAS (Component only) T3 2Q02(S) (Component only) T4 Any 2Q03 section (Component only) T5 Any 2C40 panel (Component only) T6 Any 2Q01 section (Component only) T7 2Y09 OR 2Y!0 (Component only) T8 2TII (Component only) T9 2RUIA/B (Component only) TIO Single battefy charger (Component only) TI 1 Single inverter (Component only) T12 DCI 1(2Di 1, 2D12, or 2113) (Component only) T13 DC22 (21302 or 2D14) (Component only) T14 2K01/2K02 (Component only) T15 2K03 (Component only) T16 DIESEL LOGIC (2C69) (Component only) T17 Single Vital AC panel (Component only) T18 2X08 and 2X09 (Component only) T19 2Di5, 21316,22D17, OR 2D01 (Component only) T20 2Y03 and 2Y02A (Component only) T21 Reserve Switchgcar (Component only) T22 Back up Bus (Component only) T23 Computer Inverter (Component only) BGE 4-E-30 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Table 4-E-7 Cable Spreading Room Fire Analysis Results Initiating Fire Freq Ignition Functional CDF Event Scenario Source Impact A302PI C20-27, TI, 9.04E-6 ESFAS Cabinets: 2C67, 2C67L, 2C68, HL, H9, QQ 2.73E-7 T20 2C68L, 2C91, 2C92, 2C93, 2C94. Transient induced ESFAS fires A302F2 C35-36, C38- 8.28E-5 120VAC AC AC Inventor 21, 12OVAC IlL, g9,QQ 5.49E-9 40, C42, AC Distribution Panel 21,12OVAC AC C44, TI 1, AC Inventor 22, 120VAC AC Ti7 Distribution Panel 22A, Distribution Panel 23, Distribution Panel 24, Transient induced inverter and/or Vital AC panel fires A302F3 C51-53 2.34E-6 Reactor Trip switchgear C, Reactor Trip AC, HL, H9, QQ 3.83E-10 switchboard D,Reactor Trip Switchgear E A302F4 C72-74, C77 3.12E-6 Transformer/Generator Relay Panel C, OP, AC, HL, H9, QQ 2.42E-8 Transformer/Generator Relay Panel D, Transformer/Generator Relay Panel E, Annunciator Logic Panel A302FS C43, C75 3.98E-5 120VAC Inverter 24, OP, HL, H9, QQ, NS 9.73E-8 Transformer/Generator Relay Panel F A302F6 C54, C70-71 2.34E-6 Electro-Hydraulic Control, OP, AC, HL, H9, QQ, 3.53E-8 Transformer/Generator Relay Panel A, F9 Transformer/Generator Relay Panel B A302F7 CI-4, TIO 4.32E-5 21 Battery Charger, 22 Battery Charger, HL, H9, QQ, XC*, 1.12E-8 13 Battery Charger, 14 Battery Charger, XD* Transient damage to a single battery charger A302F8 C41, C45, 1.58E-4 120VAC Inverter 23, 12OVAC GF, HL, H9, QQ, S4, 3.OIE-8 C49, CSS-59 Computer Inverter, RPS Reactor Trip TI, F9 Switchgear Cabinet A, Shutdown CCP Panel 2Q02B SEC6, Shutdown CCP Panel 2Q02B SEC7 A302F9 CIO, C37, 2.011E6 2B DO Logic Panel, 120VAC GM, HL, H9, QQ 9.02E-1 I T16 Distribution Panel 22A, Diesel Logic Cabinet (2C69) RAN 97-031 4-E-31 BGE 4-E-31 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Table 4-E-7 Cable Spreading Room Fire Analysis Results (Continued) Initiating Fire Freq Ignition Functional CDF Event Scenario Source Impact A302FA Cl 1-14, C28- 9.31E.-6 125VDC Bus 21,125VDC Distribution DC,HL, H9, QQ i. 19E-7 33, T19 Panel 2D15, 125VDC Distribution Panel 2D16, Distribution Panel 2D17, AFAS A Actuation Cabinet, AFAS B Actuation Cabinet, AFAS D Sensor Cabinet, AFAS E Sensor Cabinet, AFAS F Sensor Cabinet, AFAS G Sensor Cabinet, 2D 15, 2D16, 2D17, OR 2D01 A302FB C15-16. T13 2.45E-6 125VDC Bus 22, 125VDC Distribution DD, HL, H9, QQ 2.64E-10 Panel 2D14, DC22 (2D02 or 2DI4) A302FC C17-19, T 12 3.48E-6 125VDC Distribution Panel 2D1 I, DA, HL, H9, QQ 6.49E-8 125VDC Distribution Panel 2D12, 125VDC Distribution Panel 2D13, DCI I (2D1 1, 2D12, or 2D!3) A302FM C9, T7, T9, 3.7 1E-6 120VAC Bus 2Y09/2Y10 Tie Breaker, No Unit 2 MFW, HL, 4.84E-I I TI8 Transient damage to 2X08 and 2X09, H9, QQ 2Y09 OR 2Y 10, or 2ROIA/B A302FN C5-8, C34, 6.29E-4 120VAC Inverter Back up Bus, 120VAC HL, H9, QQ 1.99E-8 C55, C60-69, Instrument Transformer 21, Shutdown C76, C78-86, CCP Panel 2QO2B SEC3, 120VAC C88, T2-6, Instrument Bus 21, Regulating CCP T8, T14-15, Panel 2Q02C SEC 8, Regulating CCP T21-23 Panel 2Q02C SEC 17, 120VAC Instrument Transformer 22, Transformer/Generator Relay Panel G, Annunciator 21 Logic Control Panel, Annunciator 22 Logic Control Panel, 120VAC Instrument Bus 22, CEDS CEA Control Panel 1, CEDS CEA Control Panel 2, CEDS CEA Control Panel 3, CEDS CEA Control Panel 4, CEDS CEA Control Panel A, CEDS CEA Control Panel B, Reserve Battery Disconnect Switch ID57, Transformer 2X21, Transient damage to: 2K01/2K02, 2K03, AFAS, Reserve Switchgear, Back up Bus, Computer Inverter, 2Q02(S), Any 2Q03 section, Any 2C40 panel, Any 2Q01 section, 2T II BGE 4-E-32 RAN 97-031

Calvert ClifU Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events A302 Analysis The A302 analysis is similar to A306. Therefore, the descriptions and tables aire omitted except when significant differences exist. A302 Fire Ignition Frequency Both fixed and transient ignition frequencies are determined for the cable spreading room. Fixed Ignition Frequency The fixed ignition frequency is determined by starting with the compartment fixed ignition frequency results of Section 4.3.2 and then developing a scenario specific ignition frequency as described in Section 4.3.4.3. The sources and parameters used for A302 are: Source Generic Fire Location Source Total Sources In Room Specific Frequency Weighting Weighting Aux Bldg Frequency Battery Chargers 4.0E-3 2 4 15 2.13E-3 Electrical Cabinets 3.2E-3 I - 3.20E-3 Transformers (Dry) 7.9E-3 2 5 80 9.88E-4 Fire Protection Panels 2.4E-3 2 1 35 1.37E-4 THESE COMPONENT DESCRIPTIONS, HEAT RELEASE RATES, AND ANALYSES ARE SIMILAR TO THOSE IN A306. BATTERY CHARGERS ELECTRICAL CABINETS TRANSFORMERS FIRE PROTECTIONPANELS CALCULATION OF COMPONENTFIXED IGNiTION FREQUENCY Each individual component is assigned an ignition frequency apportioned by dividing the Room Specific Frequency for the component type by the total number of each ignition source of that type. The chart below summarizes that calculation and incorporates the applicable severity factor. Equipment Count and Individual Frequency Summary (A302) Equipment Panel Room Specific Severity Individual Type Count Frequency Factor Frequency Battery Chargers 4 2.13E-3 0.2 1.07E-5 Electrical Cabinets or Panels 82 3.20E-3 (Cabinet or Panel) (75) 0.2 7.80E-7 (Inverter) (7) 1.0 3.90E-5 Transformers 5 9.88E-4 1.0 1.98E-4 Fire Protection Panels I 1.37E-4 0.2 2.74E-6 BGE 4-E-33 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Transient Ignition Freauency The transient ignition frequency is determined by starting with the compartment transient ignition frequency results of Section 4.3.2 and then developing a scenario specific ignition frequency as described in Section 4.3.4.3. The sources and parameters used for A302 are: Source Generic Fire Location Source Total Sources in Room Specific Frequency Weighting Weighting Aux Bldg Frequency Cable fires- welding 5.!E-3 2 1 232 4.40E-5 Transient fires - welding 3. IE-2 2 1 232 2.67E-4 Transient - other 1.3E-3 2 7 232 7.84E-5 The transient fire modeling method parallels the method used to model A306. The calculation is presented below. TRANSIENT COMBUSTIBLE IN RANGE OF TARGETS (U) AND RESULTING FREQUENCY The Cable Spreading Room floor area is approximately 2,695 square feet. The floor area displaced by cabinets is calculated by summing the individual cabinet areas using the Asr perimeter dimensions as length and width. The total cabinet area is 477 square feet, so: A, = 2695ft 2 - 477ft2 = 2,218ft2 and for the CSR, u = Asr / AF and: Pf, I Since: F,= Fit

• u
• P/,= Fit * [Asr/AF]
• I

                                                  =   7.84E-4 * [A5, /2,218ft2]

The grouping of similar components resulted 25 scenarios, tabularized below. BGE 4-E-34 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Table 4-E-8 A302 Transient Fire Scenarios and Frequency Summary Scenario Description A, Fig Number of Floor cabinets Area T1 ESFAS 76 2.67E-06 I 38 T2 AFAS 36 1.27E-06 I 16 T3 2Q02(S) 99 3.50E.06 1 63 T4 Any 2Q03 section 52 1.85E-06 1 42 T5 Any 2C40 panel 61 2.14E-06 1 8 T6 Any 2Q01 section 52 1.85E-06 1 48 T7 2Y09 OR 2Y 10 23 8.27E-07 2 24 T8 , 2Ti1 29 1.04E-06 1 14 T9 2ROIA/B 54 1.91E-06 1 36 TI0 Single banery charger 14 4.99E-07 4 19 Til Single inverter II 4.03E-07 4 32 T12 DCI 1(2DI l, 2D12, or 2D13) 32 1.14E-06 I 18 T13 DC22 (2D02 or 2DI 4) 25 8.91E-07 I 17 T14 2K01/2K02 31 I. 1OE-06 1 22 TI5 2K03 10 3.50E-07 1 7 TI 6 DIESEL LOGIC (2C69) 13 4.46E-07 2 10 TI7 Single Vital AC panel 13 4.46E-07 4 10 T18 2X08 ad 2X09 5 1.91E-07 1 7 T19 2D15,2DI6,2DI7. OR 2D01 43 1.51E-06 1 31 T20 2Y03 and 2Y02A 4 1.27E-07 1 0 121 Rescrvc Switchgear 47 1.65E-06 2 12 T22 Back up Bus 8 2.86E-07 I 5 T23 Computer Inverter 27 9.55E-07 I 19 BGE 4-E-35 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Total Ignition Frequency Equipment and trays damaged in each scenario (transient and fixed) are mapped to corresponding plant model top events. The top events are then binned for impact. The binnings are then used to group the fire scenarios into plant model scenarios. Each plant model scenario is the sum of individual fire scenarios listed below. Plant model scenario A302FI: C20 ESFAS Actuation Relay Panel ZA 7.80E-07 C21 ESFAS A Actuation Cabinet 7.80E-07 C22 ESFAS Actuation Relay Panel ZB 7.80E-07 C23 ESFAS B Actuation Cabinet 7.80E-07 C24 ESFAS D Sensor Cabinet 7.80E-07 C25 ESFAS E Sensor Panel 7.80E-07 C26 ESFAS F Sensor Cabinet 7.80E-07 C27 ESFAS G Sensor Cabinet 7.80E-07 Ti ESFAS 2.67E-06 T20 2Y03 and 2Y02A 1.27E-07 Total frequency for plant model A302FI is 9.04E-06 Plant model scenario A302F2: C35 120V Inverter 21 3.90E-05 C36 120V Distribution Panel 21 7.80E-07 C38 120V Inverter 22 3.90E-05 C39 120V Distribution Panel 22 7.80E-07 C40 120V Distribution Panel 22A 7.80E-07 C42 120V Distribution Panel 23 7.80E-07 C44 120V Distribution Panel 24 7.80E-07 TI 1 Single inverter 4.03E-07 TI 7 Single Vital AC panel 4.46E-07 Total frequency for plant model A302F2 is: 8.28E-05 BGE 4-E-36 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Plant model scenario A302F3: C51 RPS Reactor Trip Switchgear 7.80E-07 C52 RPS Reactor Trip Switchgear Cabinet C 7.80E-07 C53 RPS Reactor Trip Switchgear Cabinet D 7.80E-07 Total frequency for plant model A302F3 is: 2.34E-06 Plant model scenario A302F4: C72 Transformer/Generator Relay Panel C 7.80E-07 C73 Transformer/Generator Relay Panel D 7.80E-07 C74 Transformer/Generator Relay Panel E 7.80E-07 C77 Annunciator Logic Panel 7.80E-07 Total frequency for plant model A302F4 is: 3.12E-06 Plant model scenario A302FM: C43 120V Inverter 24 3.90E-05 C75 Transformer/Generator Relay Panel F 7.80E-07 Total frequency for plant model A302F5 is: 3.98E-05 RAN 97-031 4-E-37 RGE 13GE 4-E-37 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination Externa Events Plant model scenario A306F7: CIO IB DG Logic Panel 7.36E-07 C18 125D Distribution Panel ID15 7.36E-07 C19 125D Distribution Panel 1D 16 7.36E-07 C20 125D Distribution Panel 1D17 7.36E-07 T13 DC21 (ID15, ID16, or ID17) 9.01E-07 T17 EDG Logic Panels (I C70, IC69/2C70) 5.23E-07 Total frequency for plant model A306F7 is: 4.37E-06 Plant model scenario A306F8: C21 I ESFAS ACT RELAY Panel ZA 7.36E-07 1 ESFAS ACT Panel ZA 7.36E-07 C23 1ESFAS ACT RELAY Panel ZB 7.36E-07 C24 I ESFAS ACT Panel ZB 7.36E-07 C25 1 ESFAS Sensor Panel ZD 7.36E-07 C26 I ESFAS Sensor Panel ZE 7.36E-07 C27 I ESFAS Sensor Panel ZF 7.36E-07 TI ESFAS 2.44E-06 Total frequency for plant model A306F8 is: 7.59E-06 Plant model scenario A306F9: C29 AFAS A ACT Cabinet 7.36E-07 C30 AFAS B ACT Cabinet 7.36E-07 C3 1 AFAS D Sensor Cabinet 7.36E-07 C32 AFAS E Sensor Cabinet 7.36E-07 C33 AFAS F Sensor Cabinet 7.36E-07 C34 AFAS G Sensor Panel 7.36E-07 12 AFAS 1.1 6E-06 Total frequency for plant model A306F9 is: 5.58E-06 BGE 4-E- 18 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Plant model scenario A306FA: C36 120VAC Inverter 11 3.68E-05 C51 Reactor Trip Switchgear Cabinet B 7.36E-07 C52 Reactor Trip Switchgear Cabinet C 7.36E-07 T12 Single inverter 3.68E-07 TI 8 Single Vital AC panel 4.07E-07 T6 Any 1Q01 section 1.69E-06 Total frequency for plant model A306FA is: 4.07E-05 Plant model scenario A306FB: C37 120VAC Distribution Panel 11 7.36E-07 Total frequency for plant model A306FB is: 7.36E-07 Plant model scenario A306FC: C38 REACTOR CLNT SYS CHANNELS 7.36E-07 T21 IY03 and IY04A 1.16E-07 Total frequency for plant model A306FC is: 8.52E-07 Plant model scenario A306FD: C39 120VAC Inverter 12 3.68E-05 T12 Single inverter 3.68E-07 T18 Single Vital AC panel (1Y02) 4.07E-07 Total frequency for plant model A306FD is: 3.76E-05 BGE 4-E-19 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Exanination External Events Plant model scenario A306FE: C40 i20VAC Distribution Panel 12 7.36E-07 C41 120VAC Distribution Panel 7.36E-07 Total frequency for plant model A306FE is: 1.47E-06 Plant model scenario A306FF: C42 120VAC Inverter 13 3.68E-05 T12 Single inverter 3.68E-07 T18 Single Vital AC panel 1Y03 4.07E-07 Total frequency for plant model A306FF is: 3.76E-05 Plant model scenario A306FH: C45 120VAC Inverter 14 3.68E-05 T12 Single inverter 3.68E-07 TIS Single Vital AC panel (1Y04) 4.07E-07 Total frequency for plant model A306FH is: 3.76E-05 BGE 4-E-20 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Plant model scenario A306FI: C46 120VAC Distribution Panel 14 7.36E-07 Total frequency for plant model A306FI is: 7.36E-07 Plant model scenario A306FJ: C48 IROIB Instrument Power Supply 7.36E-07 C49 IROMB Instrument Power Supply 7.36E-07 TIO IROIA/B 1.74E-06 Total frequency for plant model A306FJ is: 3.22E-06 Plant model scenario A306FK: C50 Reactor Trip Switchgear Cabinet A 7.36E-07 C53 Reactor Trip Switchgear Cabinet D 7.36E-07 C54 Reactor Trip Switchgear Cabinet E 7.36E-07 C64 Regulating CCP Panel 1Q02C SEC 10 7.36E-07 C65 Regulating CCP Panel IQ02C SEC 11 7.36E-07 Total frequency for plant model A306FK is: 3.68E-06 Plant model scenario A306FL: C55 11 MT EHC Panel 7.36E-07 T8 IT11 6.98E-07 Total frequency for plant model A306FL is: 1.43E-06 BGE 4-E-21 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Plant model scenario A306FM: C71 Transformer/Generator Relay Panel 7.36E-07 C72 Transformer/Generator Relay Panel A 7.36E-07 C73 Transformer/Generator Relay Panel B 7.36E-07 C74 Transformer/Generator Relay Panel C 7.36E-07 C75 Transformer/Generator Relay Panel D 7.36E-07 C76 Transformer/Generator Relay Panel E 7.36E-07 C77 Transformer/Generator Relay Panel F 7.36E-07 T5 Any 1C40 panel 1.96E-06 Total frequency for plant model A306FM is: 7.1 lE-06 Plant model scenario A306FO: C2 23 Battery Charger 1.07E-05 C4 I1 Battery Charger 1.07E-05 T I1 Single battery charger 5.14E-07 Total frequency for plant model A306FO is: 2.18E-05 BGE 4-E-22 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Plant model scenario A306FN: C35 120VAC Inverter Backup Bus 7.36E-07 C44 120VAC Regulating X 11 4.00E-04 C56 TURB AUX SUPERVISORY INST 7.36E-07 C60 Shutdown CCP Panel I Q02B SEC6 7.36E-07 C61 Shutdown CCP Panel IQ02B SEC7 7.36E-07 C62 Regulating CCP Panel IQ02C SEC-8 7.36E-07 C63 Regulating CCP Panel 1Q02C SEC 9 7.36E-07 C69 Regulating CCP Panel IQ02C SEC 15 7.36E-07 C70 Regulating CCP Panel IQ02C SEC 16 7.36E-07 C79 125D Reserve Charger Disconnect 1D50 7.36E-07 C80 125D Reserve Charger Disconnect 1D55 7.36E-07 C81 125D Reserve Charger Disconnect ID56 7.36E-07 C82 125D Reserve Charger Disconnect 1D58 7.36E-07 C83 Battery Transfer Switch 7.36E-07 C84 Annunciator Logic Cabinet 7.36E-07 C85 Annunciator 12 Logic Panel 7.36E-07 C86 CEDS CEA Control Panel 7.36E-07 C87 CEDS CEA Control Panel 7.36E-07 C88 CEDS CEA Control Panel 7.36E-07 C89 CEDS CEA Control Panel 7.36E-07 C90 CEDS CEA Control Panel 7.36E-07 C91 CEDS CEA Control Panel 7.36E-07 C92 Transformer 1X21 2.OOE-04 C93 1201 Bus IY09/1Y10 TIE BK 7.36E-07 C94 Unit XFRM Net Power Output Panel 7.36E-07 T3 IQ02(s) 3.20E-06 T4 Any IQ03 section 1.69E-06 T9 1T14 3.34E-07 TIS IKO1/1K02 8.91E-07 T16 IK03 3.20E-07 T22 Reserve charger 1.OIE-06 T23 Reserve switchgear 4.07E-07 T24 Back up Bus 2.62E-07 T25 Computer Inverter 8.72E-07 Total frequency for plant model A306FN is: 6.26E-04 RAN 97-03 1 4-E-23 BGE 4-E-23 RAN 97-031I

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Fire Suppression Although an automatic total flooding halon suppression system is installed in the Cable Spreading Room, the probability of actuation prior to target damage is not evaluated as is the likelihood of fire brigade response to manually suppress the fire prior to target damage. Fire Suppression Induced Equipment Failure Further, when suppression actuates, the suppression agent (halon) causes no equipment damage. BGE 4-E..24 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events A302 Unit 2 Cable Spreading Room Location: 27' Auxiliary Building Fire Area: 17 CDF: 6.81E-7 The Unit 2 Cable Spreading Room (CSR) is the merging point for cables traveling to and from the Control Room. It also contains the following PRA related equipment:

• Unit 2 120VAC Vital AC Distribution Panels (2Y01, 2Y02, 2Y03 and 2Y04) and their associated inverters for 2Y03 and 2Y04
• 125VDC Distribution Panels (2D01 and 2D02), associated DC sub-panels, and four associated chargers
• Unit 2 120VAC Instrument Buses (2Y09 and 2Y10)
• Unit 2 Engineering Safety Features Actuation System logic and actuation cabinets
• Unit 2 Auxiliary Feedwater Actuation System logic and actuation cabinets The cable spreading room is rectangular with approximate dimensions forty-five feet wide, sixty-five feet long, and sixteen feet high. The nominal room area is 2,695 square feet. The room is separated from Unit I Cable Spreading Room by a common east-west wall which is a one-hour fire rated barrier and a steel door is located in this wall at the west end.

The room contains numerous vertical floor-mounted electrical cabinets aligned in rows. The majority of the cabinets are enclosed steel cabinets with sealed conduit entries. Some of the cabinets are designed with grates or vents in the top and/or sides (e.g., inverters). Numerous cable trays traverse horizontally in the ceiling. No motor-driven equipment of significance exist in either compartment. Deterministic fire modeling will involve numerous cabinet fire scenarios with potential damage to overhead cable trays; depending on the details of the analysis, the individual cabinet fares may result in localized damage (i.e., damage only to the cabinet itself) or damage to abutted cabinets and/or cable trays due to radiant and conductive heat transfer. Fire Analysis Results One hundred and eleven fire scenarios are identified for Unit 2 Cable Spreading Room. Eighty-eight are the result of fixed ignition sources and twenty-three are due to transient ignition sources. These scenarios are represented by twenty-four fire initiating events. The consolidation of fire scenarios is based on an assessment of the functional impact and ignition frequency of each scenario. The frequency of each initiator is the sum of the frequencies of all the fire scenarios it represents. The tables below list individual fire scenarios. For each scenario the initiating component is damaged. RAN 97-031 4-E-25 BGE 4-E-25 RAN 97-031l

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Table 4-E-5 A302 Fixed Ignition Fire Scenarios Summary Scenario Fire Scenario Description Trays and Panels Damaged by Fire CI 21 Battery Charger < No other effects > C2 22 Battery Charger < No other effects > C3 13 Battery Charger < No other effects > C4 14 Battery Charger < No other effects > C5 120VAC Instrument Transformer 21 < No other effects > C6 120VAC Instrument Bus 21 < No other effects > C7 120VAC Instrument Transformer 22 < No other effects > C8 120VAC Instrument Bus 22 < No other effects > C9 120VAC Bus 2Y09/2Y10 Tie Breaker < No other effects > CIO 2B Dr Logic Panel < No other effects > CHI I25VDC Bus 21 2PNL2DI 5, 2PNL2DI6, 2PNL2DI7 C12 125VDC Distribution Panel 2D15 2PNL2DOI, 2PNL2DI7, 2PNL2DI6 C13 125VDC Distribution Panel 2D 16 2PNL2DO0, 2PNL2DIS, 2PNL2DI7 C14 125VDC Distribution Panel 21)17 2PNL2DOI, 2PNL2DI5, 2PNL2DI6 C15 125VDC Bus 22 2PNL2DI4 C16 125VDC Distribution Panel 2D14 2BUS2DO2 C17 125VDC Distribution Panel 2D111 2PNL2DI2, 2PNL2DI 3 CIS 12MVDC Distribution Panel 2D12 2PNL2D 11, 2PNL2DI3 C19 125VDC Distribution Panel 2D 13 2PNL2D 11, 2PNL2DI 2 C20 ESFAS Actuation Relay Panel ZA 2PNL2C67L C21 ESFAS A Actuation Cabinet 2PNL2C67, 2PNL2C91 C22 ESFAS Actuation Relay Panel ZB 2PNL2C68L C23 ESFAS B Actuation Cabinet 2PNL2C68, 2PNL2C94 C24 ESFAS D Sensor Cabinet 2PNL2C67L, 2PNL2C92 C25 ESFAS E Sensor Panel 2PNL2C9g, 2PNL2C93 C26 ESFAS F Sensor Cabinet 2PNL2C92, 2PNL2C94 C27 ESFAS 0 Sensor Cabinet 2PNL2C68L, 2PNL2C93 C28 AFAS A Actuation Cabinet 2A1153, 2AH5 ], 2PNL2CI00D, 2PNL2CI0OF BGE 4-E-26 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Table 4-E-5 A302 Fixed Ignition Fire Scenarios Summary (Continued) Scenario Fire Scenario Description Trays and Panels Damaged by Fire C29 AFAS B Actuation Cabinet 2AH53, 2AH51, 2PNL2CIOOE, 2PNL2CIOOG C30 AFAS D Sensor Cabinet 2AH53, 2AH51, 2PNL2CIGOA, 2PNL2CIOOE, 2PNL2CIOOF C31 AFAS E Sensor Cabinet 2AH53, 2AH5 I, 2PNL2CI DOB, 2PNL2C IOOD, 2PNL2CI 00G C32 AFAS F Sensor Cabinet 2AH53, 2AH51, 2PNL2C100A, 2PNL2CI00D C33 AFAS GSensor Cabinet 2AH53, 2AH51I, 2PNL2CI00B, 2PNL2CI00E C34 120VAC Inverter Back up Bus < No other effects > C35 120VAC Inverter 21 2AKI 1, 2AJ46, 2AJ38, 2AJ50, C36 120VAC Distribution Panel 21 < No other effects > C37 REACTOR COOLANT SYS CHANN 2AK12, 2AG43, 2AG37 C38 120VAC Inverter 22 2AF62, 2AG59 C39 120VAC Distribution Panel 22 < No other effects > C40 REACTOR CLNT SYS CH TR-12 2AG87, 2AH37, 2AG79 C41 120VAC Inverter 23 2AG53, 2AH99, 2AG60 C42 120VAC Distribution Panel 23 < No other effects > C43 120VAC Inverter 24 2AG26, 2AG44, 2AG38 C44 120VAC Distribution Panel 24 < No other effects > C45 120VAC Computer Inverter 2AG36, 2AH19, 2AG24 C46 Regulating Transformer for Back up Bus 2AH32 C47 2RO1A Instrument Power Supply 2PNL2R0IB C48 2RO1B Instrument Power Supply 2PNL2R0IA C49 2 RPS ReactorTrip Switchgear Cabinet A 2AH90, 2AF78, 2AH79, 2PNL2Q0IB C50 2 RPS ReactorTrip Switchgear Cabinet B 2AH89, 2AH78, 2PNL2QO IA, 2PNL2QOIC C51 RPS Unit 2 ReactorTrip Switchgear 2AF72, 2AH89, 2AH71, 2AH78, 2PNL2QOIB, 2PNL2Q0ID C52 2 RPS ReactorTrip Swithgear Cabinet C 2AE72.2AH89,2AH71,2Af78,2PNL2QO1C, 2PNL2QOIE C53 2 RPS ReactorTrip Switchgear Cabinet D 2AF68, 2AH89, 2AH71, 2AH78, 2AL 2PNL2QOID 016I, C54 Electro-Hydraulic Control 2AK71, 2AJ48, 2AL05, 2AF80, 2AK09, 2AJ44, 2AJ36 C55 Shutdown CCP Panel 2Q02B SEC3 2AF84, 2AG93, 2AF82, 2AG85, 2PNL2QO2B/S04 C56 Shutdown CCP Panel 2Q02B SEC4 2AF84, 2AG93, 2AF82, 2PNL2Q02B/S03, 2PNL2QO2B/SO5 BGE 4-E-27 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examnination External Events Table 4-E-5 A302 Fixed Ignition Fire Scenarios Summary (Continued) Scenario Fire Scenario Description Trays and Panels Damaged by Fire C57 Shutdown CCP Panel 2Q02B SEC5 2AF84, 2AG93, 2AF82, 2PNL2QO2B/S04, 2PNL2QO2B/S06 C58 Shutdown CCP Panel 2QO2B SEC6 2AF77, 2AG93, 2AG85, 2PNL2QO2B/SO5, 2PNL2QO2B/S07 C59 Shutdown CCP Panel 2QO2B SEC7 2AF77, 2AG92, 2AG84, 2PNL2QO2B/S06, 2PNL2QO2B/SO8 C60 Regulating CCP Panel 2Q02C SEC 8 2AG92, 2AG84, 2PNL2QO2B/S07, 2PNL2QO2B/S09 C61 Regulating CCP Panel 2Q02C SEC 9 2AF72, 2AG92, 2AG84, 2PNL2QO2B/SOS, 2PNL2QO2B/S10 C62 Regulating CCP Panel 2Q02C SEC 10 2AF72, 2AG92, 2AG84, 2PNL2Q02B/S09, 2PNL2QO2B/SI I C63 Regulating CCP Panel 2Q02C SEC I I 2AG92, 2AG84, 2PNL2QO2B/SIO, 2PNL2QO2B/SI2 C64 Regulating CCP Panel 2Q02C SEC 12 2AG92, 2AF67, 2PNL2QO2C/SI I, 2PNL2QO2C/SI 3 C65 Regulating CCP.PanIel 2Q02C SEC 13 2AF67, 2AG84, 2AJ55, 2AG92, 2FNL2QO2C/SI2, 2PNL2Q02C/S14 C66 Regulating CCP Panel 2Q02C SEC 14 2AJ55, 2AG83, 2AG91, 2PNL2QO2C/S13, 2PNL2QO2C/S15 C67 Regulating CCP Panel 2Q02C SEC 15 2AG83, 2AG9l, 2PNL2Q02C/S]4, 2PNL2QO2C/S]6 C68 Regulating CCP Panel 2Q02C SEC 16 2AG83, 2AG9I, 2PNL2QO2C/SI5, 2PNL2QO2C/SI7 C69 Regulating CCP Panel 2Q02C SEC 17 2AF61, 2AG91,2PNL2QO2C/S16 C70 Transformer/Generator Relay Panel A 2A.85, 2AJ3 I, 2AJ39, 2AG95, 2AG78, 2PNL2C40B C71 Transformer/Generator Relay Panel B 2AJ3 I, 2AG95, 2AJ85, 2AJ39, 2PNL2C40A, 2PNL2C40C C72 Transformer/Generator Relay Panel C 2AG95, 2AK04, 2PNL2C40B, 2PNL2C40D C73 Transformer/Generator Relay Panel D 2AG95, 2AJ21, 2AJ29, 2AJ27, 2PNL2C40C, 2PNL2C40E C74 Transformer/Generator Relay Panel E 2AG95, 2A1J21, 2AJ29, 2AJ27, 2PNL2C40D, 2PNL2C40F C75 Transformer/Generator Relay Panel F 2AH94, 2AJ07, 2AJ14, 2AH82, 2AG95, 2AH93, 2PNL2C40E, 2PNL2C40G C76 Transformer/Generator Relay Panel G 2AH93, 2AH94, 2AJ07, 2AHE2, 2AJ14, 2PNL2C4OF C77 Annunciator Logic Panel 2AH88, 2AF62, 2AH77, 2AH70, 2AJ71 C78 Annunciator 21 Logic Control Panel 2PNL2KO2 C79 Annunciator 22 Logic Control Panel 2PNL2KO0 C80 CEDS UNIT 2 CEA Control Panel 2PNL2QO3-2, 2PNL2QO3A C81 CEDS UNIT 2 CEA Control Panel 2PNL2QO3-1, 2PNL2QO3-3 C82 CEDS UNIT 2.CEA Control Panel 2PNL2QO3-2, 2PNL2QO3-4 C83 CEDS UNIT 2 CEA Control Panel 2PNL2QO3-3, 2PNL2QO3B BGE 4-E-28 RAN 97-031

Calvert Cliffs Nuclear Power Plant Intemal Fire Analysis Individual'Plant Examination External Events Table 4-E-5 A302 Fixed Ignition Fire Scenarios Summary (Continued) Scenario Fire Scenario Description Trays and Panels Damaged by Fire C84 CEDS UNIT 2 CEA Control Pane! 2PNL2QO3-1 C85 CEDS UNIT 2 CEA Control Panel 2PNL2QO3-4 C86 Reserve Battery Disconnect Switch ID57 No other effects C85 CEDS UNIT 2 CEA Control Panel 2PNL2QO3-4 C87 125V Battery 01 DISC SW #2 No other effects C88 Transformer 2X21 No other effects RAN 97-031 4-E-29 BGE 4-E-29 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examinatiod External Events Table 4-E-6 A302 Transient Fire Scenarios Summary Scenario Description Trays and Panels Damaged by Fire Ti ESFAS (Component only) T2 AFAS (Component only) T3 2Q02(S) (Component only) T4 Any 2Q03 section (Component only) T5 Any 2C40 panel (Component only) T6 Any 2Q01 section (Component only) T7 2Y09 OR 2Y10 (Component only) I"8 2T 11 (Component only) T9 2R0IA/B (Component only) TIO Single battey charger (Component only) TI 1 Single inverter (Component only) T12 DC1I (2DI 1, 2D!2, or 2D13) (Component only) T13 DC22 (2D02 or 2D14) (Component only) T14 2K01/2K02 (Component only) T15 2K03 (Component only) T16 DIESEL LOGIC (2C69) (Component only) TI 7 Single Vital AC panel (Component only) Tl8 2X08 and 2X09 (Component only) T19 2D15, 2D16, 2DI 7, OR 2D01 (Component only) T20 2Y03 and 2Y02A (Component only) T21 Reserve Switchgear (Component only) T22 Back up Bus (Component only) T23 Computer Inverter (Component only) BGE 4-E-30 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Table 4-E-7 Cable Spreading Room Fire Analysis Results

                            -I Initiating          Fire           Freq                      Ignition                     Functional                CDF Event          Scenario                                     Source                        Impact A302Fi         C20-27, TI,       9.04E-6    ESFAS Cabinets: 2C67, 2C67L, 2C68,           HL, H9, QQ              2.73E-7 T20                         2C6SL, 2C91, 2C92, 2C93, 2C94, Transient induced ESFAS fires A302F2        C35-36, C38-       8.28E-5    120VAC AC AC Inventor 21 I,12OVAC            HL, H9, QQ               5.49E-9 40, C42,                   AC Distribution Panel 21, 120VAC AC C44, T 11,                       AC Inventor 22, 120VAC AC TV7                        Distribution Panel 22A, Distribution Panel 23, Distribution Panel 24, Transient induced inverter and/or Vital AC panel fires A302F3           C51-53          2.34E-6    Reactor Trip switchgear C, Reactor Trip   AC, HL, H9, QQ             3.83E-10 switchboard D, Reactor Trip Switchgear E

A302F4 C72-74, C77 3.12E-6 Transformer/Generator Relay Panel C, OP, AC, HIL, H9, QQ 2.42E-8 Transformer/Generator Relay Panel D, Transformer/Generator Relay Panel E, Annunciator Logic Panel A302F5 C43, C75 3.98E-5 120VAC Inverter 24, OP, HL, H9, QQ, NS 9.73E-8 Transformer/Generator Relay Panel F A302F6 C54, C70-71 2.34E-6 Electro-Hydraulic Control, OP, AC, HL, H9, QQ, 3.53E-8 Transformer/Generator Relay Panel A, F9 Transformer/Generator Relay Panel B A302F7 CI-4, TIO 4.32E-5 21 Battery Charger, 22 Battery Charger, HL, H9, QQ, XC*, 1.12E-8 13 Battery Charger, 14 Battery Charger, XD* Transient damage to a single battery charger A302F8 C4 1, C45, 1.58E-4 120VAC Inverter 23, 12OVAC GF, HL, H9, QQ, S4, 3.0IE-8 C49, C58-59 Computer Inverter, RPS Reactor Trip TI, F9 Switchgear Cabinet A, Shutdown CCP Panel 2Q02B SEC6, Shutdown CCP Panel 2Q02B SEC7 A302F9 CIO, C37, 2.01E-6 2B DG Logic Panel, 120VAC GiK, HL, H9, QQ 9.02E- 11 T16 Distribution Panel 22A, Diesel Logic Cabinet (2C69) BGE 4-E-31 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Table 4-E-7 Cable Spreading Room Fire Analysis Results (Continued) Initiating Fire Freq Ignition Functional CDF Event Scenario Source Impact A302FA Cl 1-14, C28- 9.31E-6 125VDC Bus 21, 125VDC Distribution DC,HL, H9. QQ 1.19E-7 33, T19 Panel 2D15, 125VDC Distribution Panel 2D16, Distribution Panel 2DI 7, AFAS A Actuation Cabinet, AFAS B Actuation Cabinet, AFAS D Sensor Cabinet, AFAS E Sensor Cabinet, AFAS F Sensor Cabinet, AFAS G Sensor Cabinet, 2D 15, 2D16, 2D17, OR 2D01 A302FB C15-16. T13 2.45E-6 125VDC Bus 22, 125VDC Distribution DD, HL, H9, QQ 2.64E-10 Panel 2DI4, DC22 (2D02 or 2D14) A302FC C17-19, T12 3.48E-6 125VDC Distribution Panel 2D1 1, DA, HL, H9, QQ 6.49E-8 125VDC Distribution Panel 21312, 125VDC Distribution Panel 2D13, DCI I (2D11, 2D12, or 2D13) A302FM C9, T7, T9, 3.71E-6 120VAC Bus 2Y09/2Y10 Tie Breaker, No Unit 2 MFW, HL, 4.84E-I 1 T18 Transient damage to 2XO8 and 2X09, H9, QQ 2Y09 OR 2Y10, or 2R10A/B A302FN C5-.8, C34, 6.29E-4 120VAC Inverter Back up Bus, 120VAC HL, H9, QQ 1.99E-8 C55, C60-69, Instrument Transformer 21, Shutdown C76, C78-86, CCP Panel 2Q02B SEC3, 120VAC C88, T2-6, Instrument Bus 21, Regulating CCP T8, T14-15, Panel 2Q02C SEC 8, Regulating CCP T21-23 Panel 2Q02C SEC 17, 120VAC Instrument Transformer 22, Transformer/Generator Relay Panel G, Annunciator 21 Logic Control Panel, Annunciator 22 Logic Control Panel, 120VAC Instrument Bus 22, CEDS CEA Control Panel 1, CEDS CEA Control Panel 2, CEDS CEA Control Panel 3, CEDS CEA Control Panel 4, CEDS CEA Control Panel A, CEDS CEA Control Panel B, Reserve Battery Disconnect Switch I1D57, Transformer 2X21, Transient damage to: 2K01/2K02, 2K03, AFAS, Reserve Switchgear, Back up Bus, Computer Inverter, 2Q02(S), Any 2Q03 section, Any 2C40 panel, Any 2QO section, 2T II BGE 4-E-32 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events A302 Analysis The A302 analysis is similar to A306. Therefore, the descriptions and tables arie omitted except when significant differences exist. A302 Fire Ignition Frequency Both fixed and transient ignition frequencies are determined for the cable spreading room. Fixed Ignition Frequency The fixed ignition frequency is determined by starting with the compartment fixed ignition frequency results of Section 4.3.2 and then developing a scenario specific ignition frequency as described in Section 4.3.4.3. The sources and parameters used for A302 are: Source Generic Fire Location Source Total Sources in Room Specific Frequency Weighting Weighting Aux Bldg Frequency Battery Chargers 4.OE-3 2 4 15 2.13E-3 Electrical Cabinets 3.2E-3 I - - 3.20E-3 Transformers (Dry) 7.9E-3 2 5 80 9.88E-4 Fire Protection Panels 2.4E-3 2 1 35 1.37E-4 THESE COMPONENT DESCRIPTIONS, HEAT RELEASE RATES, AND ANALYSES ARE SIMILAR TO THOSE IN A306. BATTERY CHARGERS ELECTRICAL CABINETS TRANSFORMERS FIRE PROTECTIONPANELS CALCULA TION OF COMPONENTFIXED IGNITION FREQUENCY Each individual component is assigned an ignition frequency apportioned by dividing the Room Specific Frequency for the component type by the total number of each ignition source of that type. The chart below summarizes that calculation and incorporates the applicable severity factor. Equipment Count and Individual Frequency Summary (A302) Equipment Panel Room Specific Severity Individual Type Count Frequency Factor Frequency Battery Chargers 4 2.1 3E-3 0.2 1.07E-5 Electrical Cabinets or Panels 82 3.20E-3 (Cabinet or Panel) (75) 0.2 7.80E-7 (Inverter) (7) 1.0 3.90E-5 Transformers 5 9.88E-4 1.0 1.98E-4 Fire Protection Panels I 1.37E-4 0.2 2.74E-6 BGE 4-E-33 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Transient Ignition Frequency The transient ignition frequency is determined by starting with the compartment transient ignition frequency results of Section 4.3.2 and then developing a scenario specific ignition frequency as described in Section 4.3.4.3. The sources and parameters used for A302 are: Source Generic Fire Location Source Total Sources in Room Specific Frequency Weighting Weighting Aux Bldg Frequency Cable fires, welding 5. 1E-3 2 1 232 4.40E-5 Transient fires - welding 3.I E-2 2 i 232 2.67E-4 Transient - other 1.3E-3 2 7 232 7.84E-5 The transient fire modeling method parallels the method used to model A306. The calculation is presented below. TRANSIENT COMBUSTIBLE IN RANGE OF TARGETS (U) AND RESULTING FREQUENCY The Cable Spreading Room floor area is approximately 2,695 square feet. The floor area displaced by cabinets is calculated by summing the individual cabinet areas using the A,, perimeter dimensions as length and width. The total cabinet area is 477 square feet, so: AF = 2695ft2 - 477ft2 = 2,218ft' and for the CSR, u = A, / AF and: Pf, = 1 Since: F, = F,,

• u
• P, = Fi, * [Asr/AF]
• I

                                                  =   7.84E-4   * [A,/2,218ft2]

The grouping of similar components resulted 25 scenarios, tabularized below. BGE 4-E-34 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Table 4-E-8 A302 Transient Fire Scenarios and Frequency Summary Scenario Description A. Fit Number of Floor cabinets Area TI ESFAS 76 2.67E-06 I 38 T2 AFAS 36 1.27E-06 I 16 T3 2Q02(S) 99 3.50E-06 1 63 T4 Any 2Q03 section 52 1.85E-06 1 42 T5 Any 2C40 panel 61 2.14E-06 I g T6 Any 2QOI section 52 1.85E-06 1 48 T7 2Y09 OR 2Y 10 23 8.27E-07 2 24 Ts , 2T11 29 1.04E&06 1 14 T9 2ROIA/B 54 1.91E-06 1 36 TIO Single batery charger 14 4.99E-07 4 19 TiIl Single inverter I1 4.03E-07 4 32 T12 DCI I (2DI l, 2D12, or 2D13) 32 1.14E-06 1 18 T13 DC22 (2D02 or 2D14) 25 8.91E-07 I 17 TM4 2K01/2K02 31 I.IOE-06 1 22 TI5 2K03 10 3.50E-07 I 7 T16 DIESEL LOGIC (2C69) 13 4.46E-07 2 10 T17 Single Vital AC panel 13 4.46E-07 4 10 TI8 2X08 and 2X09 5 1.91E-07 1 7 T19 2D15,2DI6,2DI7. OR 2DOI 43 1.51E-06 I 31 T20 2Y03 and 2Y02A 4 1.27E-07 1 0 T21 Rcscrvc Switchgear 47 1.65E-06 2 12 T22 Back up Bus 8 2.86E-07 I 5 T23 Computer Inverter 27 9.55E-07 1 19 BGE 4-E-35 RAN 97-031

Calvert Clifns Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Total Ignition Frequency Equipment and trays damaged in each scenario (transient and fixed) are mapped to corresponding plant model top events. The top events are then binned for impact. The binnings are then used to group the fire scenarios into plant model scenarios. Each plant model scenario is the sum of individual fire scenarios listed below. Plant model scenario A302FI: C20 ESFAS Actuation Relay Panel ZA 7.80E-07 C21 ESFAS A Actuation Cabinet 7.80E-07 C22 ESFAS Actuation Relay Panel ZB 7.80E-07 C23 ESFAS B Actuation Cabinet 7.80E-07 C24 ESFAS D Sensor Cabinet 7.80E-07 C25 ESFAS E Sensor Panel 7.80E-07 C26 ESFAS F Sensor Cabinet 7.80E-07 C27 ESFAS G Sensor Cabinet 7.80E-07 T1 ESFAS 2.67E-06 T20 2Y03 and 2Y02A 1.27E-07 Total frequency for plant model A302F1 is 9.04E-06 Plant model scenario A302F2: C35 120V Inverter 21 3.90E-05 C36 120V Distribution Panel 21 7.80E-07 C38 120V Inverter 22 3.90E-05 C39 120V Distribution Panel 22 7.80E-07 C40 120V Distribution Panel 22A 7.80E-07 C42 120V Distribution Panel 23 7.80E-07 C44 120V Distribution Panel 24 7.80E-07 TI ! Single inverter 4.03E-07 T17 Single Vital AC panel 4.46E-07 Total frequency for plant model A302F2 is: 8.28E-05 BGE 4-E-36 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Plant model scenario A302F3: C51 RPS Reactor Trip Switchgear 7.80E-07 C52 RPS Reactor Trip Switchgear Cabinet C 7.80E-07 C53 RPS Reactor Trip Switchgear Cabinet D 7.80E-07 Total frequency for plant model A302F3 is: 2.34E-06 Plant model scenario A302F4: C72 Transformer/Generator Relay Panel C 7.8011-07 C73 Transformer/Generator Relay Panel D 7.80E-07 C74 Transformer/Generator Relay Panel E 7.80E-07 C77 Annunciator Logic Panel 7.80E-07 Total frequency for plant model A302F4 is: 3.12E-06 Plant model scenario A302FM: C43 120V Inverter 24 3.90E-05 C75 Transformer/Generator Relay Panel F 7.80E-07 Total frequency for plant model A302F5 is: 3.98E-05 BGE 4-E-37 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Plant model scenario A302F6: C54 Electro-Hydraulic Control 7.80E-07 C70 Transformer/Generator Relay Panel A 7.80E-07 C71 Transformer/Generator Relay Panel B 7.80E-07 Total frequency for plant model A302F6 is: 2.34E-06 Plant model scenario A302F7: CI 21 Battery Charger 1.07E-05 C2 22 Battery Charger 1.07E-05 C3 13 Battery Charger 1.07E-05 C4 14 Battery Charger 1.07E-05 TI0 Single battery charger 4.99E-07 Total frequency for plant model A302F7 is: 4.32E-05 Plant model scenario A302F8: C41 120V Inverter 23 3.90E-05 C45 120V Computer Inverter 1.17E-04 C49 RPS Reactor Trip Switchgear Cabinet A 7.80E-07 C58 Shutdown CCP Panel 2Q02B SEC6 7.80E-07 C59 Shutdown CCP Panel 2Q02B SEC7 7.80E-07 Total frequency for plant model A302F8 is: 1.58E-04 BGE 4-E-38 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Plant model scenario A302F9: CIO 2B DG Logic Panel 7.80E-07 C37 120V Distribution Panel 21A 7.80E-07 T16 DIESEL LOGIC (2C69) 4.46E-07 Total frequency for plant model A302F9 is: 2.0 1E-06 Plant model scenario A302FA: C11 125VDC Bus 21 7.80E-07 C12 125D Distribution Panel 2D15 7.80E-07 C13 125D Distribution Panel 2Dl6 7.80E-07 C14 125D Distribution Panel 2D17 7.80E-07 C28 AFAS A Actuation Cabinet 7.80E-07 C29 AFAS B Actuation Cabinet 7.80E-07 C30 AFAS D Sensor Cabinet 7.80E-07 C31 AFAS E Sensor Cabinet 7.80E-07 C32 AFAS F Sensor Cabinet 7.80E-07 C33 AFAS G Sensor Cabinet 7.80E-07 T19 2D15, 2D16, 2D17, OR 2D01 1.51E,-06 Total frequency for plant model A302FA is: 9.31E-06 Plant model scenario A302FB: C15 125VDC Bus 22 7.80E-07 C16 125D Distribution Panel 2D14 7.80E-07 T13 DC22 (2D02 or 2D14) 8.91E-07 Total frequency for plant model A302FB is: 2.45E-06 RAN 97-03 1 4-E-39 I3GE BGE 4-E-39 RAN 97-031!

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Plant model scenario A302FC: C17 125D Distribution Panel 2D 1I 7.80E-07 C18 125D Distribution Panel 2D1 2 7.8011-07 C19 125D Distribution Panel 2D 13 7.80E-07 T12 DCII (2D), 2D12, or 2D13) 1.14E-06 Total frequency for plant model A302FC is: 3.48E-06 Plant model scenario A302FM: C9 120V Bus 2Y09/2Y 10 Tie Breaker 7.80E-07 T18 2XO8 and 2XO9 1.91E-07 T7 2Y09 OR 2Y 10 8.27E-07 T9 2RO1A/B 1.91E-06 Total frequency for plant model A302FM is: 3.71E-06 BGE 4-FA0 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Plant model scenario A302FN: C34 120V Inverter Back up Bus 7.80E-07 C5 120V Instrument Transformer 21 1.98E-04 C55 Shutdown CCP Panel 2Q02B SEC3 7.80E-07 C6 120V Instrument Bus 21 7.80E-07 C60 Regulating CCP Panel 2Q02C SEC 8 7.80E-07 C61 Regulating CCP Panel 2Q02C SEC 9 7.80E-07 C62 Regulating CCP Panel 2Q02C SEC 10 7.80E-07 C63 Regulating CCP Panel 2Q02C SEC 11 7.80E-07 C64 Regulating CCP Panel 2Q02C SEC 12 7.80E-07 C65 Regulating CCP Panel 2Q02C SEC 13 7.80E-07 C66 Regulating CCP Panel 2Q02C SEC 14 7.80E-07 C67 Regulating CCP Panel 2Q02C SEC 15 7.80E-07 C68 Regulating CCP Panel 2Q02C SEC 16 7.80E-07 C69 Regulating CCP Panel 2Q02C SEC 17 7.80E-07 C7 120V Instrument Transformer 22 1.98E-04 C76 Transformer/Generator Relay Panel G 7.80E-07 C78 Annunciator 21 Logic Control Panel 7.80E-07 C79 Annunciator 22 Logic Control Panel 7.80E-07 C8 120V Instrument Bus 22 7.80E-07 C80 CEDS CEA Control Panel 7.80E-07 C81 CEDS CEA Control Panel 7.80E-07 C82 CEDS CEA Control Panel 7.80E-07 C83 CEDS CEA Control Panel 7.80E-07 C84 CEDS CEA Control Panel 7.80E-07 C85 CEDS CEA Control Panel 7.80E-07 C86 Reserve Battery Disconnect Switch 1D57 7.80E-07 C88 Transformer 2X21 1.98E-04 T14 2K01/2K02 1.1OE-06 TIS 2K03 3.50E-07 T2 AFAS 1.27E-06 T21 Reserve Switchgear 1.65E-06 T22 Back up Bus 2.86E-07 T23 Computer Inverter 9.55E-07 T3 2Q02(S) 3.50E-06 T4 Any 2Q03 section 1.85E-06 T5 Any 2C40 panel 2.14E-06 T6 Any 2Q01 section 1.85E-06 T8 2TI I 1.04E-06 Total frequency for plant model A302FN is: 6.29E-04 RAN 97-031 4-E-41 BGE 4-E-41 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Fire Suprression Although an automatic total flooding halon suppression system is installed in the Cable Spreading Room, the probability of actuation prior to target damage is not evaluated as is the likelihood of fire brigade response to manually suppress the fire prior to target damage. Fire Suppression Induced Eguipment Failure When suppression actuates, the suppression agent (halon) causes no equipment damage. BGE 4-E-42 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events A31 1 Unit 2 27' Switchgear Room Location: 27' Auxiliary Building Fire Area: 18 CDF: 2.22E-7 A317 Unit 1 27' Switchgear Room Location: 27' Auxiliary Building Fire Area: 19 CDF: 4.28E-6 A407 Unit 2 45' Switchgear Room Location: 45' Auxiliary Building Fire Area: 25 CDF: 1.19E-7 A430 Unit 1 45' Switchgear Room Location: 45' Auxiliary Building Fire Area: 34 CDF: 1.54E-6 Four switchgear rooms were analyzed for Unit 1. Two of the rooms (A317 and A430) primarily support Unit I equipment and the other two rooms (A3 11 and A407) primarily support Unit 2 equipment. A311 Contains the 4KV Buses (21 and 22), 480 volt load centers and their associated transformers (21 A, 21 B, 22A and 22B), and cabling feeding the related buses and equipment. A317 Contains the 4KV Buses (II and 12), 480 volt load centers and their associated transformers (I IA, 1IB, 12A and 12B), and cabling feeding the related buses and equipment. A407 Contains the 4KV Buses (23 and 24), 480 volt load centers and their associated transformers .1.1 (23A, 23B, 24A and 24B), and cabling feeding the related buses and equipment. A430 Contains the 4KV Buses (13 and 14), 480 volt load centers and their associated transformers (13A, 13B, 14A and 14B), and cabling feeding the related buses and equipment. In the event of a fire, the inlet and outlet ventilation isolation dampers for the affected room will close prior to actuation of halon suppression shutting of the HVAC system to the affected SWGR Room. The unaffected SWGR Room will continue to have HVAC cooling. Fire Analysis Results The results of each switchgear room are addressed sequentially in the following sections. Unit 2 27' Switchgear Room (A311) Twenty-eight fire scenarios were identified for A31 1. Twenty-three are the result of fixed ignition sources and five are due to transient ignition sources. Five scenarios are screened due to low functional impact. The remaining twenty-five scenarios identified in Table 4-F-I are represented by three fire initiating events shown in Table 4-F-2. The consolidation of fire scenarios is based on an assessment of the functional impact and ignition frequency of each scenario. The frequency of each initiator is the sum of the frequencies of all the fire scenarios it represents. BGE 4-F-1 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Table 4-F-1 Unit 2 27' Switchgear Room (A31 1) Fire Scenario Summary Scenario Fire Scenario Description Equipment Damaged 01 4.16kV Switchgear Bus 21 Cubicle Fire Loss of Bus 21 or Individual Cubicles or Load Center; Loss of impacting bus or load (14 cubicles) Ventilation; Dampers Close (recoverable). Note that this Bus 21 failure does not impact cable trays. 02 4.16kV Switchgear Bus 21 Bus Fire with Loss of Bus 21; Loss of Ventilation; Dampers Close (recoverable); cable tray impact 2AD74,2AD73, 2AB 13, 2AB14, 2ABi 5, 2AF21, 2AF22, 2AD93, 2AB02, 2AB03 04 4.16kV Switchgear Bus 22 Bus Fire with Loss of Bus 22; Loss of Ventilation; Dampers Close (recoverable); cable tray impact 2AM5I, 2AD72, 2AD71, 2AF23, 2AF24, 2AB04, 2AB05, 2AB06, 2AB17, 2AB16, 2ABi5 07 Minor Transformer 21A Liquid Fire Loss of Bus 21A (Transformer only); Loss of Ventilation; Dampers I Close (not recoverable); 2A0654, 2A0655, 2A0656 08 Severe Transformer 2IA Liquid Fire Loss of Bus 21 A (Transformer and Switchgcar cabinet); Loss of Ventilation; Dampers Close (not recoverable); 2A0654, 2A0655, 2A0656, 2AF16, 2AFI7, 2AB09, 2ABIO 09 Minor Transformer 21B Liquid Fire Loss of Bus 21 B (Transformer only); Loss of Ventilation; Dampers Close (not recoverable); 2A0657, 2A0658, 2A0659 10 Severe Transformer 21 B Liquid Fire Loss of Bus 21 B (Transformer and Switchgear cabinet); Loss of Ventilation; Dampers Close (not recoverable); 2A0657, 2A0658, 2A0659, 2AF17, 2AB09 II Minor Transformer 22A Liquid Fire Loss of Bus 22A (Transformer only); Loss of Ventilation; Dampers Close (not recoverable); 2A0660, 2A0661, 2A0662 12 Severe Transformer 22A Liquid Fire Loss of Bus 22A (Transformer and Switchgear cabinet); Loss of Ventilation; Dampers Close (not recoverable); 2A0660, 2A0661, 2A0662, 2AF i8, 2AF 19, 2ABOS, 2AB07 13 Minor Transformer 22B Liquid Fire Loss of Bus 22B (Transformer only); Loss of Ventilation; Dampers Close (not recoverable); 2A0654, 2A0655, 2A0656 14 Severe Transformer 22B Liquid Fire Loss of Bus 22B (Transformer and Switchgear cabinet); Loss of Ventilation; Dampers Close (not recoverable); 2A0654, 2A0655, 2A0656, 2AF19, 2AB58 15 480V SWGR 21A Bus Fire Loss of Bus 21A; Loss of Ventilation; Dampers Close (recoverable); 2A0461, 2A2125, 2A0460, 2A0459, 2AO45S, 2A2127, 2A0462, 2Ai449, 2A0323, 2AI448, 2A0318, 2AF17, 2AF16, 2AFiS, 2AB09, 2ABI0, 2ABI I 16 480V SWGR 21A Cubicle Fire Loss of Individual Cubicle or Load Center, Loss of Ventilation; Dampers Close (recoverable) BGE 4-F-2 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Table 4-F-1 Unit 2 27' Switchgear Room (A31 1) Fire Scenario Summary (Continued) Scenario Fire Scenario Description Equipment Damaged 17 480V SWGR 21B Cubicle Fire Loss of Individual Cubicle or Load Center;, Loss of Ventilation; Dampers Close (recoverable) 18 480V SWGR 21B Bus Fire Loss of Bus 21B; Loss of Ventilation; Dampers Close (recoverable); 2A0243, 2A!454, 2A5296, 2A0452, 2A0453, 2A0454, 2A5074, 2A0391, 2A0242, 2A5076, 2A0457, 2A0972, 2AF17, 2AFI8, 2AB09, 2AB08 19 480V SWGR 22A Bus Fire Loss of Bus 22A; Loss of Ventilation; Dampers Close (recoverable); 2A0451, 2A0153, 2A0450, 2A0449, 2AO152, 2A0447, 2A051, 2AF19, 2AB07, 2AB58 20 480V SWGR 22B Bus Fire Loss of Bus 22B; Loss of Ventilation; Dampers Close (recoverable); 2A0446, 2A0150, 2AI478. 2A5009, 2A0441, 2AI400, 2A0442, 2A0154, 2A0443, 2A1304, 2AF19, 2AB07, 2AB58 21 Disconnect (6) Loss of Disconnect Panel (no other impact); Loss of Ventilation; Dampers Close (recoverable) 24 4KV Bus 21 Transient Fire Loss of Bus 21 26 480VAC Bus 21A Transient Fire Loss of Bus 21A 27 480VAC Bus 2 1B Transient Fire Loss of Bus 21B 28 480VAC Buses 22A and 22B Transient Loss of Bus 22A and 22B (Frequency represents both Buses; Fire individual Bus would have 1/2 frequency) RAN 97-031 4-F-3 BGE 4-F-3 RAN 97-031!

Calvert Cliffs Nuclear Power Plant Intemal Fire Analysis Individual Plant Examination External Events Table 4-F-2 Unit 2 27' Switchgear Room (A311) Fire Analysis Results Initiating Fire Frequency Ignition Functional CDF Event Scenario Source Impact A31 IF1 2,4 4.62E-5 4KV Bus 21 or 22 Bus fire (does not Y2, QD, AC, Y3, 6.01E-8 include breaker failures that do not Y4 impact the bus) A31 IF2 8,10,12,15, 6.97E-4 Severe Transformer 21A, 21B or 22A, QD, AC, Y3, Y4 1.49E-7 19,20 fire or 480VAC SWGR 21A, 22A or 22B Bus fires A311 F3 1,7,9,11,13, 9.18E-4 4KV Bus 21 Cubicle (load losses AC, Y3 i.32E-8 14,16,17,18, only) or Minor Transformer 21 A. 24,26,27, 21B, 22A or 22B fire or Severe Transformer 22B fire, or 480VAC SWGR 21 A, 21 B. cubicles fires or 21B bus fire or Transient fires Unit 1 27' Switchgear Room (A317) Twenty-eight fire scenarios were identified for A317. Twenty-three are the result of fixed ignition sources and five are due to transient ignition sources. These scenarios identified in Table 4-F-3 are represented by twelve fire initiating events shown in Table 4-F-4b. The consolidation of fire scenarios is based on an assessment of the functional impact and ignition frequency of each scenario. The frequency of each initiator is the sum of the frequencies of all the fire scenarios it represents. BGE 4-F-4 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Table 4-F-3 Unit 1 27' switchgear Room (A317) Fire Scenarios Scenario Fire Scenario Description Equipment Damaged 01 4.16kV Switchgear Bus II Cubicle Fire (14 Loss of Bus I I or Individual Cubicle or Load Center; Loss cubicles) impacting bus or load of Ventilation; Dampers Close (recoverable). Note that this Bus I I loss does not impact cable trays. 02 4.16kV Switchgear Bus I I Bus Fire with Loss of Bus 11; Loss of Ventilation; Dampers Close cable tray impact (recoverable); LAD67, IAD68, IAK27, IAK48, IAK49, IAK50, IAK95, IABIS, 1AB16, IAB17, IABI8, 1AB27, 1AB28, IAB29 03 4.16kV NSR Switchgear Bus 12 Cubicle Fire Loss of Bus 12 or Individual Cubicle or Load Center, Loss impacting bus or load OR (480V SWGR 12A of Ventilation; Dampers Close (recoverable). Note that this OR 12B Cubicle Fire) Bus 12 loss does not impact cable trays. 04 4.16kV Switchgear Bus 12 Bus Fire with Loss of Bus 12; Loss of Ventilation; Dampers Close cable tray impact (recoverable); 1AD67, IAD68, IAKSI, IAK52, IAK53, lAB91, 1AB13, IAB14, IAB90, IAB25, IAB26 05 RCP 11 Breaker Cubicle (2) Loss of RCP I I (no other impact); Loss of Ventilation; Dampers Close (recoverable); IA0161, IA0162 06 RCP 12 Breaker Cubicle (2) Loss of RCP 12 (no other impact); Loss of Ventilation; Dampers Close (recoverable) 07 Transformer I IA (IXU-440-1 IA) - DRY Loss of Bus IIA (Transformer only); Loss of Ventilation; Dampers Close (recoverable); IA804, IAK37, IABI9 08 Severe Transformer IIA Liquid Fire Not a plausible fire scenario for a dry transformer. 09 Minor Transformer 1 B Liquid Fire Loss of Bus IIB (Transformer only); Loss of Ventilation; Dampers Close (not recoverable); IA0807, IA0808, IA0809 10 Severe Transformer I IB Liquid Fire Loss of Bus 1 B (Transformer and Switchgear cabinet); Loss of Ventilation; Dampers Close (not recoverable); IA0807, IA0808, IA0809, IAK38, IAB20, 1AB32, IAB44 II Minor Transformer 12A Liquid Fire Loss of Bus 12A (Transformer only); Loss of Ventilation; Dampers Close (not recoverable); IA0807, 1A0808, IA0809, IAK39, IAB21, 1AB33, lAB45

                                                                                                                       ~.AN 97-031 4-F-5 BGE                                                             4-F-5                                                  RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Table 4-F-3 Unit 1 27' Switchgear Room (A317) Fire Scenarios (Continued) Scenario Fire Scenario Description Equipment Damaged 12 Severe Transformer 12A Liquid Fire Loss of Bus 12A (Transformer and Switchgear cabinet); Loss of Ventilation; Dampers Close (not recoverable); 1A0807, IA0808, 1A0809, IAK39, IAK40, IAB21, 1AB22, IAB33, IAB45 13 Minor Transformer 12B Liquid Fire Loss of Bus 12B (Transformer only); Loss of Ventilation; Dampers Close (not recoverable); IA0801, 1A0802, IA0803, IAK41, IAB23, 1AB35, IAB47 14 Severe Transformer 12B Liquid Fire Loss of Bus 12B (Transformer and Switchgear cabinet); Loss of Ventilation; Dampers Close (not recoverable); IA0801, 1A0802, IA0803, IAK41, 1AB23, IAB35, 1AB47, IAK40, IAB2I, IAB22 15 4S0V SWGR IIA Cubicle Fire Loss of Individual Cubicle or Load Center; Loss of Ventilation; Dampers Close (recoverable) 16 480V SWGR IIA Bus Fire Loss of Bus I IA; Loss of Ventilation; Dampers Close (recoverable); IA0157, IA0790, 1A0322, IA0324, IA0325, 1A0313, IA0326, IA0327, 1A0328, IA0662, IAK37, IAK27, IABIB, IABI9 17 480V SWGR II B Cubicle Fire Loss of Individual Cubicle or Load Center, Loss of Ventilation; Dampers Close (recoverable) 18 480V SWGR IIB Bus Fire Loss of Bus IIB; Loss of Ventilation; Dampers Close (recoverable); IA0333, IA5053, IA0335, IA5057, 1A0336, IA0314, 1A5055, IA0338, lAB76, IA0339, IA0663, IA2782, IA0315, IA2064, IA2278, IAK38, IAB20 19 480V SWGR 12A Bus Fire Loss of Bus 12A; Loss of Ventilation; Dampers Close (recoverable); 1A0155, IA0344, 1A0345, 1A0158, IA0346, IA0450, IA0348, 1AK39, IAK40, IAB21, IAB22 20 480V SWGR 12B Bus Fire Loss of Bus 12A; Loss of Ventilation; Dampers Close (recoverable); IAK41, IAK40, IAB23, IAB21, IA0348, IA1452, IA0349, 1A0161, 1A5034, lAB46, IA0162, IA5055, 1A1251, IA2278, IA0353, IA0352, 1A0351, 1AB76, 1A0156, IA0355, IA0357, IA0358 21 Disconnect (6) Loss of Disconnect Panel (no other impact); Loss of Ventilation; Dampers Close (recoverable) 22 IPNLIC86 Loss of IC86 (no other impact); Loss of Ventilation; Dampers Close (recoverable) BGE 4-F-6 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis individual Plant Examination External Events Table 4-F-3 Unit 1 27' Switchgear Room (A317) Fire Scenarios (Continued) Scenario Fire Scenario Description Equipment Damaged 23 RPS MG sets Loss of MG (no other impact); Loss of Ventilation; Dampers Close (recoverable) 24 4KV Bus II Transient Fire Loss of 4kV Bus 1i 25 4KV Bus 12 Transient Fire Loss of 4kV Bus 12 26 480VAC Bus I IA Transient Fire Loss of 480VAC Bus I IA 27 480VAC Bus IEB Transient Fire Loss of 480VAC Bus 1IB 28 480VAC Buses 12A and 12B Transient Fire Loss of Bus 12A and 12B (Frequency represents both Buses; individual Bus would have 1/2 frequency) Table 4-F-4 Unit 1 27' Switchgear Room (A317) Fire Analysis Results lnitlatina Fire Freamencv Imnition Functional CDF Event Scenario Source Impact A317FI 7,10 2.03E-4 Severe Transformer IIA(Dry) or GE, AA, HS*, HF, 6.52E-7 I IB(Wet) fire AE, NI, N2, HI-I*, NR1,NS*, DM*, PGO, KX, KZ, RS*, VC, MN, LF, CV, WY* A317F2 1,9,14 3.46E-4 4KV Bus I I Cubicle, Minor AA, HF, AE 9.84E-7 Transformer 11 B fire, Severe Transformer 12B fire A317F3 12,11,13 4.5E-5 Severe Transformer 12A fire, Minor GE, AA, HF, AE, 1.38E-7 Transformer 12A or 12B fires HH*, NR*, NS*, DMO, PG*, KX, KZ, VC, RS*, RQ, MN, LF, CV, WY*, SRO A317F4 5,6,8,23,28 2.84E-3 RCP II or 12 Breaker Cubicle, Severe HF 2.30E-7 Transformer I IA fire, IC86, 480VAC Bus 12A, I2B transient fires A317F5 15,26 1.23E-4 480VAC SWGR IIA Cubicle or -F, N I 5.07E-8 Transient fire BGE 4-F-7 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Table 4-F-4 Unit 1 27' Switchgear Room (A317) Fire Analysis Results (Continued) Initiating Fire Frequency Ignition Functional CDF Event Scenario Source Impact A317F6 17,27 1.23E-4 480VAC SWGR 1 B Cubicle or HF, N2 5.07E-8 Transient fire A317F7 18,19,20 7.44E-4 480VAC SWGR IIB,12A, or 12B GE, HS*, HF, AE, 6.18E-7 Bus fire NI, N2, HH*, NR*, NS*, DM*, PG*, KX, KZ, RS*, VC, RQ, MN, LF, CV, WY*, SR* A317F8 2.24 3.19E-5 4KV Bus II Bus or transient fire Yl, QD, AA, HF, AE, 1.18E-7 Y4, RS*, MN, IAV, IB*, FT, LF, CV, VI, DLO, SG*, SH*, SR*, TH, K3 A317F9 4,25 3.19E-5 4KV Bus 12 or transient fire QD, QE, JA, GE, GJ*, 4.78E.7 AA HF, AE, NI, N2, Y3, QZ*, 11, DM*, PG*, VC, BV, SL, IAO, IB*, F7, LF, CV, HB, V5, CS, CT. SG* SH* A317FA 3 5.63E-4 4KV Bus 12 Cubicle fire HF,AE, 1.3 1E-7 A317FB 16 2.54E-4 480VAC SWGR IIA Y1, GE, HS*, HF, NI, 7.93E-7 HH*, NR*, DM*, PG*, KX, KZ, RS*, VC, BV, MN, FT, LF, CV, WY*, SG*, SH*, TH, K3 A317FC 21,22 1.60E-4 Disconnect Panel or IPNLIC86 HF, RS*, HB 3.82E-8 Unit 2 45' Switchgear Room (A407) Twenty-nine fire scenarios were identified for A407. Twenty-four are the result of fixed ignition sources and five are due to transient ignition sources. Fourteen scenarios are screened due to low functional impact. The remaining scenarios identified in Table 4-F-5 are represented by four fire initiating events shown in Table 4-F-6.. The consolidation of fire scenarios is based on an assessment of the functional impact and ignition frequency of each scenario. The frequency of each initiator is the sum of the frequencies of all the fire scenarios it represents. BGE 4-F-8 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Table 4-F-5 Unit 2 45' Switchgear Room (A407) Fire Scenario Summary Scenario Fire Scenario Description Equipment Damaged 02 4.16kV Bus 23 Bus Fire with cable tray Loss of Bus 23; Loss of Ventilation; Dampers Close (recoverable); impact 2AD71, 2AD72, 2AD70, 2AM51, 2AF02, 2AC40, 2AC45, 03 4.16kV Bus 24 Cubicle Fire impacting Loss of Individual Cubicle or Load Center; Loss of Ventilation; bus or load Dampers Close (recoverable). Note that this Bus 23 failure does not impact cable trays. 04 4.16kV Bus 24 Bus Fire with cable tray Loss of Bus 24; Loss of Ventilation; Dampers Close (recoverable); impact 2AD75, 2AD73, 2AD74, 2AF06, 2AC40, 2AC52 07 Minor Transformer 23A Liquid Fire Loss of Bus 23A (Transformer only); Loss of Ventilation; Loss of Ventilation; Dampers Close (not recoverable); 2A0663, 2A0664, 2A0665 08 Severe Transformer 23A Liquid Fire Loss of Bus 23A (Transformer and Switchgear cabinet); Loss of Ventilation; 2A0663, 2A0664, 2A0665, 2AF07, 2AC35, 2AC47, 2AC59 09 Minor Transformer 23B Liquid Fire Loss of Bus 23B (Transformer only); Loss of Ventilation; Dampers Close (not recoverable); 2A0666, 2A0667, 2A00668 10 Severe Transformer 23B Liquid Fire Loss of Bus 23B (Transformer and Switchgear cabinet; Loss of Ventilation; Dampers Close (not recoverable); 2A0666, 2A0667. 2A00668, 2AF08. 2AC36, 2AC48, 2AC60 II Minor Transformer 24A Liquid Fire Loss of Bus 24A (Transformer only); Loss of Ventilation; Dampers Close (not recoverable); 2A0669, 2A0670, 2A0671 12 Severe Transformer 24A Liquid Fire Loss of Bus 24A (Transformer and Switchgear cabinet); Loss of Ventilation; Dampers Close (not recoverable); 2A0669, 2A0670, 2A0671, 2AF09, 2AC37, 2AC49, 2AC61 16 Transformer 24B (2XU-440-24B) - Loss of Bus 24B (Transformer only); Loss of Ventilation; Dampers DRY Close (not recoverable); 2A0672 17 480V SWGR 23A Bus Fire Loss of Bus 23A; Loss of Ventilation; Dampers Close (recoverable); 2A0473. 2A0472, 2A4123, 2A0471. 2A0470, 2A0469, 2A0468, 2A0474, 2A0475, 2A0476, 2AF07, 2AC35, 2AC59 20 480V SWGR 24A Bus Fire Loss of Bus 24A; Loss of Ventilation; Dampers Close (recoverable); 2A0481. IA0677, 2A0482, 2A!989. 2A0234. 2A0466, 2A0484, 2A1243, 2A0322, 2AFOB, 2AF09, 2AC36,2AC37, 2AC48. 2AC49 RAN 97-03 1 4-F-9 BGE 4-F-9 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Table 4-F-5 Unit 2 45' Switchgear Room (A407) Fire Scenario Summary (Continued) Fire Scenario Description Equipment Damaged 480V SWGR 24B Bus Fire Loss of Bus 24A; Loss of Ventilation; Dampers Close (recoverable); 2A0467, 2A2126, 2A0486, 2A5077, 2A0971, 2A5075, IA0676, 2A0235, 2A0489, 2A0490, 2A0485, 2A2364, 2A0236, 2AFIO, 2AFI 1, 2AC38, 2AC39 4KV Bus 22 Transient Fire Loss of Bus 22 480VAC Buses 22A and 22B Transient Loss of Bus 22A and 22B (Frequency represents both Buses; Fire individual Bus would have 1/2 frequency) Table 4-F-6 Unit 2 27' Switchgear Room (A407) Fire Analysis Results Initiating Fire Frequency Ignition Functional CDF Event Scenario Source Impact A407FI 2,4 4.62E-5 4KV Bus 23 or 24 Bus Fire Y2, QD, QF, QE, 3.88E-8 GF, G(J, AD, N7, N8, Y3, Y4, DM*, PG*, GW, U-2 Feedwater, F9 A407F2 8,10,12,20 2.32E.4 480VAC 23A, 23B, 24A Severe Y2, QD, QF, GF, 3.51E-8 Transformer Fire, or 480VAC 24A G(J, AD, N7, N8, Bus fire HH*, Y4, DM*, PG*, U-2 Feedwatcr, FO* A407F3 17,22 4.65E-4 490VAC SWGR 23A, 24B Bus Fire GF, G), N7, N8, 3.77E-8 HH*, Y4, NR, PG*, U-2 Fccdwater, FO* A407F4 3,7,9.11,16,2 5.93E-4 4KV Bus 23 Bus Fire, 480VAC AD, Y4, U-2 7.431-9 6,29 Transformer 23A, 23B, 24A Liquid Feedwater Fire Transformer 24B Dry Fire, 4KV Bus 12 Transient Fire or 480VAC Bus 12A, 12B Transient Fire BGE 4-F- 10 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Unit 1 45' Switchgear Room (A430) Twenty-seven fire scenarios were identified for A3 11. Twenty-two are the result of fixed ignition sources and five are due to transient ignition sources. These scenarios identified in Table 4-F-7 are represented by eight fire initiating events shown in Table 4-F-8. The consolidation of fire scenarios is based on an assessment of the functional impact and ignition frequency of each scenario. The frequency of each initiator is the sum of the frequencies of all the fire scenarios it represents. Table 4-F-7 Unit 1 45' Switchgear Room (A430) Fire Scenarios Scenario Fire Scenario Description Equipment Damaged 01 4.16kV NSR Bus 13 Cubicle Fire Loss of Bus 13 or Individual Cubicle or Load Center; Loss of impacting bus or load OR (480V SWGR Ventilation; Dampers Close (recoverable). Note that this Bus 13 13A AND 13B Cubicle Fire) failure does not impact cable trays. 02 4.16kV Bus 13 Bus Fire with cable tray Loss of Bus 13; Loss of Ventilation; Dampers Close impact (recoverable); IAK57, 1AK64. lAC37, IAC35, IAC38, IAC34 03 4.16kV Bus 14 Cubicle Fire impacting bus Loss of Bus 14, Individual Cubicle or Load Center; Loss of or load Ventilation; Dampers Close (recoverable). Note that this Bus 14 failure does not impact cable trays. 04 4.16kV Bus 14 Bus Fire with cable tray Loss of Bus 14; Loss of Ventilation; Dampers Close impact (recoverable); IAK65, IAK59, IAK60, IAC33, IAC40, IAC41, IAC45 05 RCP 13 Breaker Cubicle (2) Loss of RCP 13 (no other impact); IA0125, IA0127 06 RCP 14 Breaker Cubicle (2) Loss of RCP 14 (no other impact); 1A0126, 1A0128 07 Minor Transformer 13A Liquid Fire Loss of Bus 13A (Transformer only); ; Loss of Ventilation; Dampers Close (not recoverable); 1A0804, IA0813, l A08 14, IA0815 08 Severe Transformer 13A Liquid Fire Loss of Bus 13A (Transformer and Switchgear cabinet); Loss of Ventilation; Dampers Close (not recoverable); IA0804, IA0813, IA0814, IA0815, 1AK63, 1AC35 09 Minor Transformer 13B Liquid Fire Loss of Bus 13B (Transformer only); Loss of Ventilation; Dampers Close (not recoverable); IA0816, IA0817, IA0818 I0 Severe Transformer 13B Liquid Fire Loss of Bus 13B (Transformer and Switchgear cabinet); Loss of Ventilation; Dampers Close (not recoverable); IA816, IA0817, IA0818, IAK64, IAC34, 1AC46, IAC58 II Minor Transformer 14A Liquid Fire Loss of Bus 14A (Transformer only); Loss of Ventilation; Dampers Close (not recoverable); IA0819, IA0820, IA0821, 1AK65, IAC33, IAC45, IAC57 BGE 4F-ilRAN 9-03 BGE 4-F- I I RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Table 4-F-7 Unit 1 45' Switcbgear Room (A430) Fire Scenarios (Continued) Scenario Fire Scenario Description Equipment Damaged 12 Severe Transformer 14A Liquid Fire Loss of Bus 14A (Transformer and Switchgear cabinet); Loss of Ventilation; Dampers Close (not recoverable); IA0819, 1A0820, IA0821, 1AK65, IAC33, IAC45, lAC57, IAK64, IAC34, IAC46 13 Minor Transformer 14B Liquid Fire Loss of Bus 14B (Transformer only); Loss of Ventilation; Dampers Close (not recoverable); IA0822, 1A0823, IAI812, IAK66, IAC32, 1AC44, IAC56 14 Severe Transformer 14B Liquid Fire Loss of Bus 14B (Transformer and Switchgear cabinet); Loss of Ventilation; Dampers Close (not recoverable); IA0822, IA0823, IA1812, IAK66, IAC32, IAC44, IAC56, 1AK67, IAC31 15 480Vr SWGR 14A Cubicle Fire Loss of Individual Cubicle or Load Center, Loss of Ventilation; Dampers Close (recoverable) 16 480V SWGR 13A Bus Fire Loss of Bus 13A; Loss of Ventilation; Dampers Close (recoverable); IAI593, IA0452, 1A0453, IA0454, IA0455, IA0456, IA0864, IA0450, IA1253, IA1252, IA0458, IA0459, IA0650, IA0460, IAD77, 1AD78, IAK56, 1AK63, IAK57, IAC30, IAC47, IAC59 17 480V SWGR 14B Cubicle Fire Loss of Individual Cubicle or Load Center; Loss of Ventilation; Dampers Close (recoverable) 18 480V SWGR 13B Bus Fire Loss of Bus 13B; Loss of Ventilation; Dampers Close (recoverable); IA0466, 1A0465, IA0463, 1A0464, IA0478, 1A1594, IA1246, IA1250, IA1252, IA0461, IAK63, IAK64, 1AC34, IAC35 19 480V SWGR 14A Bus Fire Loss of Bus 14A; Loss of Ventilation; Dampers Close (recoverable); IA0480, IA0477, IA0435, IA5056, IA2185, 1A0475, IA0474, IA0690, IA2109, IA0434 20 480V SWGR 14B Bus Fire Loss of Bus 14B; Loss of Ventilation; Dampers Close (recoverable); IA0480, 1A0477, IA0435, IA5056, IA2185, IA0475, IA0474, IA0690, IA2109, IA0434, IA2109, IA2782, 1AK66, IAK67. IAC31, IAC32 21 Disconnects (6) Loss of Disconnect Panel (no other impact); Loss of Ventilation; Dampers Close (recoverable) 22 RPS MG sets Loss of MG (no other impact); Loss of Ventilation; Dampers Close (recoverable) 23 4KV Bus 1I Transient Fire Loss of Bus 11 BGE 4-F-12 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Table 4-F-7 Unit 1 45' Switchgear Room (A430) Fire Scenarios (Continued) Scenario Fire Scenario Description Equipment Damaged 24 4KV Bus 12 Transient Fire Loss of Bus 12 25 480VAC Bus 1 IA Transient Fire Loss of Bus I IA 26 480VAC Bus II B Transient Fire Loss of Bus 11 B 27 480VAC Buses 12A and 12B Transient Loss of Bus 12A and 12B (Frequency represents both Buses; Fire individual Bus would have 1/2 frequency) RAN 97-031 4-F-13 BGE 4-17-13 RAN 97-031!

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Table 4-F-8 Unit 1 45' Switchgear Room (A430) Fire Analysis Results Initiating Fire Frequency Ignition Functional CDF Event Scenario Source Impact A430F1 2,4,8,25 5.80E-5 4KV Bus 13 Cubicle, 4KV Bus 14 QD, QF, JB, -G, 9.91E-8 Bus, Severe Transformer 13A liquid GJ, AB, HZ, HG*, fire or 480VAC Bus I IA transient fire AF, N3, N4, M8, Y4, QQ, 12, PG*, KY, KH, KZ, MC, RQ, SL*, F9* CV, HB, HW A430F2 7.9,15,19 4.14E-4 Minor Transformer 13A, 13B Liquid AB, HZ, HG*, Y4, 2.33E-7 Fire, 480V SWOR 14A Cubicle or KH, SL* Bus fire or 480V Bus 12A and 12B Transieni fire A430F3 5,6 9.24E-5 RCP 13 or 14 Breaker Cubicle HZ, HG*, Y3, Y4, 8.99E-10 KH, SL* A430F4 10,11,12,13, 3.03E-4 Severe Transformer 13B liquid fire, QF, AB, HZ, HG*, 5.45E-7 14,20 Severe or Minor Transformer 14A, AF, N3, N4, M 1, 14B liquid fire or 480VAC SWGR M8, Y4, QQ, 12, 14B PG*, KY, KH, KZ, RS*, MC, RQ, SL*, F9#, CV A430F5 1,23,26 5.77E-4 4KV Bus 13 Cubicle or transient fire, HZ, HG*, AF,Y3, 3.53E-9 or Minor Transformer 13A or 13B KH, SL* liquid fire A430F6 3,17,24 4.55E-4 4KV Bus 14 Cubicle fire, 480VAC AB, HZ, HG*,Y4, 2.77E-7 SWGR 14B Cubicle Fire or 4KV Bus KH, SL* 12 Transient Fire A430F7 16,18 4.96E-4 480VAC SWGR 13A or 13B Bus fire QF, HZ, HG*, AF, 2.01E-7 N4, MS, QQ, NR*, NS*, PGO, KY, KH, KZ, RS*, MC, RQ, SLO, F9*, CV A430F8 21,22 2.89E-3 Disconnect Panel HZ, HG*, KM, RS*, 1.81E-7 or SL*, HB CEDM Motor Generator Set BGE 4-F-14 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Fire Ignition Frequency Both fixed and transient ignition frequencies were determined for all four of the Switchgear Rooms. Fixed Ignition Frequency The fixed ignition frequency is determined by starting with the compartment fixed ignition frequency results of Section 4.3.2 and then developing a scenario specific ignition frequency as described in Section 4.3.4.3. The sources and parameters used for the switchgear rooms are: Source Electrical Cabinet Motor Generator Set Transformer (Dry)(A31 1) Transformer (DryXA317, A407, A430) Transformer (Wet)(A317, A407) Transformer (Wei)(A3 i1, A430)

*Note: The fire frequency for 480V PCB Oil Filled Transformers was determined to be 2.5E-5. The derivation of this value is explained further in this section.

The table below, based on walkdowns, shows the total panel count for each switchgear room. RAN 97-031 4-P-15 BGE 4-F- 15 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events The EPRI Fire Events Database identifies 17 electrical cabinet fire events. The breakdown is as follows: Event Type No. of Events Percentage Bus/Transformer Connection 8 47% Breaker 6 35% Other Cubicle Component 3 18% Given the above operating experience, the percentage of breaker cubicle fires that result in de-energizing the bus is calculated as 6/9 (67%). The percentage of breaker cubicle fires that result in isolating/failing the load is calculated as 3/9 (33%). The frequency of breaker cubicle fires resulting in failure of the breaker or load center is calculated as: (2.3 1E-03 / total number of cubicles) x number of cubicles for Bus x 33% of incidents The frequency of breaker cubicle fires that result in de-energizing the bus is calculated as: (2.3 1E-03 / total number of cubicles) x number of cubicles for Bus x 67% of incidents Transformers The largest potential ignition source are the four 4KV to 480VAC transformers in each switchgear room. Based on a search of the EPRI Fire Events Database, ten indoor transformer fires have occurred, two of them in Auxiliary Building Switchgear Rooms. Although the impact of these fires appears to be insignificant, "dry" transformers are typically installed inside, while yard transformers are generally oil-filled. Accidents with oil-filled (wet) transformers can occur as the result of an internal fault, resulting in a build up of flammable gases inside the trahsformer casing. Such a fault could lead to electrical arcing which, in turn, could ignite the flammable gases. The burning gases cause a pressure increase within the casing which results in either 1) the venting of transformer oil out through a relief valve, or, in a more severe scenario, 2) an explosion that dumps the burning oil to the surrounding area. In order to minimize the risk of a transformer fire that destroys the entire room, the transformer fluid can contain additives that decrease the flammability of the fluid, such as silicone or PCBs. Polychlorinated biphenyl (PCB) was added to the transformer fluid as a fire-retarding agent. However, the properties that make PCB advantageous for fire protection also make PCB a hazard poison that does not readily break down. Therefore, while PCB will slow the spread and limit the impact of the fire, it will impede recovery and cleanup after the fire extinguished. ASKAREL is a generic name for a class of fire-resistant synthetic chlorinated hydrocarbons and mixtures used as dielectric fluids that commonly contain between 30% and 70% PCBs. INERTEENTM is a trade name for dielectric fluid marketed by Westinghouse Electric and used at CCNPP. The fluid used in the transformers in.the Switchgear Rooms contain 60 percent PCBs and is essentially nonflammable. BGE 4-F-16 RAN 97-031

Calvert Cliffs Nuclear Power Plant In(emal Fire Analysis Individual Plant Examination External Events The fire ignition frequency for the 480VAC transformers is based on an EPRI analysis titled, "EPRI Economic Risk Management Models for Electrical Equipment Containing PCBs." The following ignition frequencies are used: Oil-Filled Transformer Ignition Frequencies Event Frequency Type per reactor year Smoke/No Fire 2E-5 Large Fire 5E-6 Total 2.5E-5 These values credit the following factors associated with the 480VAC transformers:

• The transformers are highly visible yet have limited access
• The transformers are regularly inspected for leaks and maintained
• The transformers have both high and low side electrical fault protection Note: the following values are used in the below calculations:

0.20 = severity factor where 20% of all transformer fires are severe transformer fires 0.80 = severity factor where 80% of all transformer fires are minor transformer fires 0.67 = frequency of breaker cubicle fires that result in de-energizing the bus 0.33 = frequency of breaker cubicle fires resulting in failure of the breaker or load center Any scenarios not included in the below calculations were screened due to low functional impact. A3FI F! = A311F! Fixlgnition = F2 + F4

                          - (2.3 1E-3/100 cabinets in room) + (2.3 1E-3/100 cabinets in room)

A311F1 = 4.62E-5 RAN 97-031 4-F-17 BGE BGE 4-F- 17 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events A31 1F2 = A31 IF2 FixIgnition = F8 + Flo+ F12 + F15 + Fi 9 + F 20

                = [(I.OE-4/4 transformers in room)*(0.2 severity factor) +

(1.OE-4/4 transformers in room)*(0.2 severity factor) + (1.OE-4/4 transformers in room)*(0.2 severity factor) + (2.3 IE-3/100 cabinets in room)*(16 cubicles in panel)*(.67) + (2.31E-3/1 00 cabinets in room)*(14 cubicles in panel)*(.67) + ((2.31E-3/100 cabinets in room)*(14 cubicles in panel)*(.67)] A311 F2 = 6.97E-4 A3 IIF3 Fix Ignition = F, + F7 + F9 + FI + F13 + F14 + F16 + F17 + Fig

                = [(2.3 IE-3/100 cabinets in room)*(14 cubicles in panel)*(.67) +

(2.3 1E-3/100 cabinets in room)*(14 cubicles in panel)*(.33) + (1.OE-4/4 transformers in room)*(0.8 severity factor) + (1.OE-4/4 transformers in room)*(0.8 severity factor) + (1.OE-4/4 transformers in room)*(0.8 severity factor) + (1.OE-4/4 transformers in room)*(0.8 severity factor) + (1.OE-4/4 transformers in room)*(0.2 severity factor) + (2.3 1E-3/100 transformers in room)*(] 6 cubicles in panel)*(0.33) + (2.3 IE-3/100 transformers in room)*(1 6 cubicles in panel)*(0.33) + (2.3 IE-3/100 transformers in room)*(] 6 cubicles in panel)*(0.67) A31 IF3 Fix IgSifion = 9.00E-4 Initiating Event frequencies for rooms A317, A407, and A430 were performed in a similar manner. Transient Ignition Frequency The transient ignition frequency is determined by starting with the compartment transient ignition frequency results of Section 4.3.2 and then developing a scenario-specific ignition frequency as described in Section 4.3.4.3. The sources and parameters used for the switchgear rooms are: Source Generic Fire Location Source Total Sources In Room Specific Frequency Weighting Weighting Aux Bldg Frequency Transient - other 1.3E-3 2 7 232 7.84E-5 The critical height for the Target-In-Plume case is approximately four feet. There are no cable trays lower than ten feet, therefore, no overhead transient targets are evaluated. BGE 4-F- 18 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events The formula for calculating the damage frequency due to transient combustibles is contained in Section 4.3.4.3.2. The floor area of the 27' level Switchgear Room is 3,162 square feet. Floor mounted panels, including Switchgear Cabinets and Transformers, occupy approximately 989 square feet of the area. This leaves approximately 2,173 square feet of floor area available for combustibles to be placed. Based on the In-Plume Exposure worksheets for transient fires in this room, the Critical Damage Distance within which damage to cable trays is expected is four feet. Given that there are no cable trays lower than approximately ten feet, A. is zero. The floor area around targets with the critical radial separation distance, was determined from the Radiant Exposure worksheet. For the 27' level Switchgear Room, the Radiant Exposure Critical Damage Distance is a radius of approximately 1.5 feet. As, is, therefore, approximately 958 square feet of area around equipment where it is possible for a transient fire to occur. Therefore, for the Switchgear Room, the following values are calculated for Transformers and Switchgear Cabinets (4.16 kV and 480 VAC):

1) Transformers and 480 VAC Switchgear (12A and 12B)

Su = (0.0 + 120 ft2)/2,173 ft2

                                                     = 5.52E-02

2) Transformers and 480 VAC Switchgear (11 A or I 1B) u = (0.0 + 60 ft)/2,173 f2

                                                     - 2.76E-02

3) 4.16 kV Switchgear u = (0.0 + 250 ft2)/2,173 ft2

                                                     = 1.15E-01

4) RCP Breaker(l or 12) u = (0.0 + 230ft2 )/2,173 ft2

                                                     = 1.06E-01

5) MG Set u= (0.0 + 30 ft2)/2,173 ft2 1.38E-02 RAN 97-03 1 4-F-19 BGE BOE 4-F- 19 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Using the value of 1.1 5E-I for "Transformers and 480 VAC Switchgear (11 A or I IB)", the ignition frequency for A3 11 F3 can then be calculated as follows: A3 I 1F3 = A3 11F3 Fix Ignition + A31 1F3 Transient

                      = 9.00E-4 + [ F24 + F 26 + F 27 ]
                      = 9.00E-4 + [(7.84E-5)*( 1.151E-1) + (7.84E-5)*(2.76E-2) + (7.84E-5)*(2.76E-2)]
                      = 9.18E-4 A31 1F3 = 9.18E-4 The above remaining values for transient combustible in vicinity of targets (u) are used in a similar manner for rooms A317, A407, and A430.

Fire Suppression Each room contains detectors that alarm in the presence of smoke. All eight of the detectors are located in the ceiling. The room is equipped with a total flooding halon suppression system. Nine cylinders of Halon 1301 are arranged on the west wall of the 45' level of the SWGR such that, if the smoke detectors in the 27' level SWGR actuate the system, five cylinders of halon will discharge into the room. Should the smoke detectors in the 45' level actuate the system, then all nine halon cylinders will discharge. A single smoke detector actuation will only initiate a fire signal. Halon suppression is released only when a smoke detector monitoring a second zone is actuated. Smoke detector actuations provide a signal to 1C24B, resulting in an audible and visible alarm in the Control Room. Fire Suppression Induced Eiuipment Failures Halon 1301 (bromotrifluormethane) is a chemical compound that is effective against flammable liquid surface fires, most solid combustible fires, and electrical fires. Only a low concentration of halon is needed to stop the combustion process and prevent further flame propagation. Halon is non-conductive, and leaves no residue, and does not create electrical short circuits and grounds or cause corrosive damage to equipment. The Halon 1301 used at CCNPP complies with the requirements of NFPA 12A. No equipment damage is assumed to result from actuation of the halon system. BGE 4-F-20 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events A315 Unit I Main Steam Isolation Location: 45' Auxiliary Building Valve Room Fire Area: I1 CDF: Screened - Low Fire Ignition Frequency The total length of this room is forty-eight feet, the width is nominally twenty-eight feet, and the resulting area is 1,344 square feet. The ceiling is sixteen and a half feet high for a total volume of 21,504 cubic feet. There is also a pipe tunnel between this room and the Turbine Building that is credited as a fire barrier. The tunnel is thirty-two feet long by fourteen feet wide with a 61/2 foot ceiling. The distance from this room to the Turbine Building is approximately thirty-five feet. There are wet pipe suppression devices and smoke detectors installed throughout the room. The tunnel contains various smoke detectors and a minimal amount of combustibles. Fire Analysis Results Four fire scenarios are -identified for this room. One for the Main Steam Penetration Room HVAC Unit and three transient scenarios which impact the HVAC Unit, 11 MSIV and 12 MSIV. The impact of each of these scenarios are limited to the equipment itself. The plant impact due to fire frequency is bounded by the individual component failure rates used in the internal events CCPRA, and as a result, this room has no additional equipment impact due to fire. This room is screened due to low ignition frequency. Fixed IgLnition Sources Pressurized oil in fluid power systems presents a fire hazard, particularly where ignition sources are present, including welding. Hydraulic fluids are generally petroleum based, non-corrosive, compatible with a variety of seals, and have good lubricating properties. Flashpoints range from 300 to 600 degrees Fahrenheit and auto-ignition temperatures from 500 to 750 degrees Fahrenheit. High-pressure pipe with welded and screwed joints, steel tubing, and metal-reinforced rubber hose are used to conduct oil at pressures up to 10,000 psi. Typically, failure of piping at threaded sections, failure of valves and gaskets or fittings, and rupture of flexible hose are the principal causes of oil release from fluid power systems. Lack of adequate supports to prevent vibration contributes to the failure. Repeated flexing and abrasion creates weak spots that eventually fail. When oil under pressure is released through equipment failure, the result is usually an atomized spray of mist or oil droplets, which depending upon the pressure, may encompass large areas. The oil spray is easily ignited and results in a fire that is torch-like with a very high rate of heat release. To protect the Main Steam System against such fires, FYRQUEL 220, a fire resistant hydraulic fluid, is used in the MSIVs. Each of the MSIVs contains approximately nine gallons of FYRQUEL. FYRQUEL 220 is not flammable or combustible. It will, however, decompose in a fire situations and release toxic materials including phosphorus oxides and flammable organic substituents. FYRQUEL is self-extinguishing once the source of ignition is removed. Effective fire suppression media is water spray, carbon dioxide, foam, or dry chemical or agents. FYRQUEL has a flashpoint of 475 degrees Fahrenheit but no auto-ignition temperature. FYRQUEL is stable at ambient temperatures and BGE 4-G- I RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events atmospheric pressures, and is not self-reactive or sensitive to static discharge. The MSIVs are, therefore, not considered to be a plausible ignition source. Transient Ignition Sources The likelihood a hot work induced transient fire is very small since a Hot Work Permit is required for these rooms. This means that there is continual fire watch during any hot work activities and for at least a period of thirty minutes after work is complete. Therefore, for the purpose of analyzing transient ignition sources in this room, the transient combustible is assumed to be maintenance refuse that comes in contact for a significant length of time with the hot piping (assumed to be in excess of 225 degrees Fahrenheit) to cause combustion. The EPRI Fire PRA Implementation Guide indicates that fixed ignition sources do not play a significant role in the creation of transient combustible fires and that transient combustible fires are most often ignited by transient ignition sources. It is assumed that the transient fire occurs on the floor. This is consistent with FIVE Methodology as representative of the most likely scenario plausible for this room. It is unlikely that a trash can would be left in this room for a length of time sufficient to become an ignition target. Suppression Systems These rooms are equipped with wet pipe suppression devices and smoke detectors throughout the room. Fire Suppression Induced Equipment Failures Based on the approach described in Section 4.3.4.4.4, equipment failure due to the inadvertent actuation of the automatic fire suppression system is assumed not to occur. Cable and conduit, valves, piping and other PRA equipment in the room are not considered to be susceptible to water damage. RAN 97-031 4-0-2 flOE BGE *4-G-2 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events A318 Unit 1 Purge Air Supply Location: 27' Auxiliary Building Fan Room Fire Area: 19A CDF: 1.15E-9 This compartment houses the containment purge fan, hot water piping, and a hot water circulating pump to heat the purge air. It also contains conduit, junction boxes, and cabling associated with 13kV and 4kV electrical protection as well as auxiliary feedwater controls. The room also houses repeater transmitters for the plant radio communications and a small chilled water air handler to cool the room. The room is approximately twenty-one feet long and thirty feet wide for 630 square feet of area. The ceiling is approximately sixteen feet high for a room volume of 10,080 cubic feet. The compartment has concrete floors, walls, and ceilings. Fire Analysis Results Seven fire scenarios were identified for A318. Five are the result of combined fixed and transient ignition sources, and two are due to transient ignition sources only. Five scenarios are screened due to low functional impact. The screening is based on the same criteria described in Section 4.3.1.3. The remaining two scenarios are combined into one fire initiating event. This consolidation is based on an assessment of the functional impact and ignition frequency of each scenario. The frequency of each initiator is the sum of the frequencies of all the fire scenarios it represents. Table 4-H-1 A318 Transient Fire Scenarios Summary Scenario Fire Scenario Description Trays and Panels Damaged by Fire T6 Transient Damage IJ005A T7 Transient Damage I J005B Table 4-H-2 A318 Fire Analysis Results Initiating Fire Frequency Ignition Functional CDF Event Scenario Source Impact A318FM T6, T7 6.28E-6 Transient damage, IJ005A or IJ005B YI, QD 1.15E-9 0 BGE 4-H-1 RAN 97-031i

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plani Examination External Events A318 Fire Ignition Frequency Both fixed and transient ignition frequencies were determined for the Purge Air Supply Fan Room. Fixed Ignition Frequency The fixed ignition frequency is determined by starting with the compartment fixed ignition frequency results of Section 4.3.2 and then developing a scenario-specific ignition frequency as described in Section 4.3.4.3. The sources and parameters used for A3 18 are: Source Generic Fire Location Source Total Sources in Room Specific FrequenEy Weighting Weighting Aux Building Frequency Ventilation Subsystem 9.5E-3 2 2 331 1.1 5E-4 Electrical Cabinet 1.9E-2 2 4 135 1.13E-3 Neither ventilation unit had either plant or fire impact, so there are no fire modeling scenarios described here. Similarly, the electrical cabinet room frequency is apportioned among the four electrical panels (transmitters and their power supplies) in the room. These too, had no plant or fire modeling impact. Their fire modeling is not described. Transient Ignition Freguency The transient ignition frequency is determined by starting with the compartment transient ignition frequency results of Section 4.3.2 and then developing a scenario specific ignition frequency as described in Section 4.3.4.3. The sources and parameters used for A318 are: Source Generic Fire Location Source Total Sources in Room Specific Frequency Weighting Weighting Aux Building Frequency Cable fires - welding 5.!E-3 2 1 232 4.40E-5 Transient fires - welding 3.iE-2 2 1 232 2.67E-4 Transient - other 1.3E-3 2 7 232 7.84E-5 For a description of transients and transient fire analysis see Section 4.3.4.3. The transient fire is modeled as a maintenance refuse fire and therefore uses the "Transient - other" as the ignition frequency, Fi, = 7.84E-05. The Unit I Purge Air Supply Room has only, therefore P13 = 1.0. The room floor area is approximately 630 square feet. Floor mounted equipment and interferences occupy approximately 255 square feet of floor area, therefore: AF = 630fl2 - 255ft = 375fl 2 u = (As + A! AF = (As + Ar) / 375f P13 = I And: Ft=Fit *u *Pf, = Fit * [(As+Asr)/AF]* I

                                               = 7.84E-5 * [(A, + Asr) / 375f12]

BGE 4-H-2 RAN 97-031

Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events JUNCTION BOXES The refuse fire In-Plume worksheets show the comer configuration plume screening distance is 8.6 feet: Wall configuration plume distance is 6.6 feet and room center plume distance is five feet. The postulated transient fire is three feet high. The lowest overhead targets are conduits approximately ten feet from the floor. Based on the transient fire worksheets for this room, the worst case in-plume Critical Damage Distance is 8.6 feet, at comer locations. Since the fire bums at a height of three feet, damage will occur up to twelve feet high, but there are no conduit targets in the comer area. Against the wall, the Critical Damage Distance is less than seven feet, so damage stops below ten feet. (In addition, the targets are conduit which provides additional protection to the wires/cables inside.) The lowest Purge Air Supply Room cable trays are thirteen feet overhead, well beyond the transient damage. The large junction boxes, overhead targets, each present fifteen square feet of floor area within the open plume. Therefore: J-BoXTansiln = 7.84E-5 * [(As+Asr) /375ft 2 ] = 7.84E-5 * [(15ft2 + Oft5)/375ft2 ] = 3.14E-6 Total Ignition Frequency The total ignition frequency is the sum of the appropriate fixed and transient scenarios. In this case, the sole scenario is the combined junction box transient damage. A318F8 = J-BoXT.,ient

• 2 = 3.14E-6
• 2 = 6.28E-6 Suppression Systems The Purge Air Supply Fan Room is equipped with smoke detection only.

Fire Suppression Induced Equipment Failures Based on the approach described in Section 4.3.4.4.4, equipment failure due to the inadvertent actuation of the automatic fire suppression system is assumed not to occur since there is no automatic suppression systems installed. RAN 97-031 4-H-3 BGE 4-H-3 RAN 97-031

a Calvert Cliffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events A405 Main Control Room (MCR) Location: 45' Auxiliary Building Fire Area: 24 CDF: 2.53E-5 The Control Room, which is accessible from both the Auxiliary and Turbine Buildings, houses benchboard control boards and miscellaneous vertical control boards for both Unit I and Unit 2. The room contains numerous vertical floor mounted electrical cabinets aligned in rows. The majority of the cabinets are open steel cabinets forming a horseshoe along the West wall. Some of the panels are enclosed and are at a height to accommodate handswitches and other operator controls. Cables transverse horizontally in cable trays between panels. Office equipment, including CRTs, copier and fax machine do not have sufficiently large motors to offer a significant ignition source. The Control Room is an enclosed rectangular structure, approximately fifty-five feet x ninety feet x twenty-two feet for a total volume of over 100,000 ft3, having a three-hour minimum fire rating. Fire detection consists of ionization detectors strategically located directly above the main control board. One foot beneath the ceiling are seismically qualified metal egg crate panels that serve to protect the operators from falling glass and debris from broken light fixtures. Fire Analysis Results Ninety-nine panels are located in the Control Room. These panels are grouped and represented by 29 fire initiating events shown in Table 4-1-1. Table 4-I-1 Control Room Panels Initiator Panels Description Panel Propagation Functional CDF (Frequency) Left Right Impact FTIC03 IC03 Condensate and Feedwater Control SW2 SW2 QQ, TI, MC, RI, BV, DW, DV, L.ISE-6 (7. SE-05) Board BS, MN, FT. MS. FN*. HX*, UQ-, HU, TG, F9, MH, F3*, LF, OT F!IC04 IC04 Auxiliary Feedwater and Computer SW2 Y QZ*, QQ, MC, RR, RI, PS, PV* 3.23E-6 (lt.I E-04) Control Board IC05 Reactivity Control Board Y Y FI*, FN, FH, F70, HX*, TF, TG, F9. MT, ME*, F34, LF, Or FI IC06 IC06 Reactor Coolant Control Board Y SW2 QQ, KX RS (DSS fails), RR, RI 1.42E-7 (1.I1E-04) ICOS Reactivity Control Board Y Y PS, PV*, AQ, SLW,CV, OT, SA BGE 4-1-1 RAN 97-031

Calvert CUiffs Nuclear Power Plant Internal Fire Analysis Individual Plant Examination External Events Table 4-I-1 Control Room Panels (continued) Initiator Panels Description Panel Propagation Funetioasl CDF (Frequency) Left Right Impact FIIC07 IC07 Chemical and Volume Control Board SW2 Y QQ, TB, AQ, SL*, MS*, CV, 7.22E-7 OT, RJ HA, HB, (l.58E.04) ICO Engineering Safeguards Y SW2 HW, DL*, CS, SR* FIIC09 IC09 Engineering Safeguards SW2 SW2 AA*, AB*, KI, OT, MV, RH, 2.96E-7 (7.88E-05) HA, HB, HW, EA, WY*, CT, SR* FIICIO ICIO Engineering Safeguards SW2 End HZ, KI, KL, OT, VM, HA, 2.95E-7 (7.98E-05) HB, VS, HW, EB, SO$, WJ, SH*, SR*, SI FIlCI3 IC13 Salt Water, Service Water and DW7 End GOG, HS, NR*, 11, 12, SI, S2, 9.99E-7 (7.88E-05) Component Cooling Water Control KX, KY, KZ, VC, FC, FO,}}