Text

Application for Amends to Licenses DPR-57 & DPR-5 Revising Units 1 & 2 TS to Be Consistent w/NUREG-1433 Standard TS GE Plants,BWR/4
	ML20064C344
Person / Time
Site:	Hatch
Issue date:	02/25/1994
From:	Beckham J; GEORGIA POWER CO.
To:	; NRC
Shared Package
ML20064C348	List: HL-4495, Application for Amends to Licenses DPR-57 & DPR-5 Revising Units 1 & 2 TS to Be Consistent w/NUREG-1433 Standard TS GE Plants,BWR/4;
References
	RTR-NUREG-1433 HL-4495, TAC-M873110, TAC-M873111, NUDOCS 9403090320
	Download: ML20064C344 (8)
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,, .. Georgi 2 Power Company . j

. 40 invemess Center Pukway '

Post Oftc) Box 1295 Birmingham, Alabama 35201 Telephone 20s 877-7279

' .j Me",;,2 % , Georgia Power February 25, 1994 Docket Nos. 50-321 HL-4495 50-366 TAC Nos. - M87310 M87311 Edwin 1. Hatch Nuclear Plant Request to Revise Technical Specifications Conversion to Improved Standard Technical Specifications Consistent With NUREG 1433 Genticmen:

In accordance with the provisions of 10 CFR 50.90, as required by 10 CFR 50.59(c)(1),

Georgia Power Company (GPC) hereby proposes changes to the Plant Hatch Units 1 and 2 Technical Specifications, Appendix A to Operating Lic enses DPR-57 and NPF-5.

This submittal proposes to revise the Units 1 and 2 Technical Specifications in their entirety to be consistent with NUREG 1433, " Standard Technical Specifications General

).. Ekctric Plants, BWR/4." The proposed changes aiso include technically justified dcMations from the NUREG and technically justified changes to the current licensing '

basis. The following documents are attached:

1. Application of NRC Final Policy Statement Selection Criteria (Units I and 2).

2. Proposed Hatch Technical Specifications (Units 1 and 2).

3. Proposed Hatch Technical Specifications Bases (Units 1 and 2).

4. Markup of the current Technical Specifications with a discussion of the proposed changes (Units 1 and 2).

5. No Significant Hazards Determination for the proposed changes.

In addition, a markup of NUREG 1433 and justifications for GPC deviations from the NUREG are provided as part of this submittal. Please note the industry and NRC proposed / accepted changes to the NUREG through January 31,1994, are reflected in the NUREG markup. Any deviations from the proposed / accepted changes are justified on a plant-specific basis. The enclosure to this letter is a synopis of the information contained in each attachment, including definition of pertinent designators, e.g., "A" for Administrative change.

9403090320 PDR 940225 I ADOCK 05000321 00 i PDR c2 1 OK

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GeorgisPbwerk U.S. Nuclear Regulatory Commission Page 2 -

February 25~, 1994-Implementation of the proposed amendments is tentatively scheduled for March 30,1995f This date is based on the training schedules for both licensed and nonlicensed personnel,-

.the . timing of implementation with respect to refueling outages, licensed operator examination schedules, and the time required for procedure revisions and development of new programs. This date is also predicated on issuance of an SER in Fall 1994.

~Although the 'new Standard Technical Specifications contain many improvements, they also impose a number of new surveillance requirements which have not been performed at Plant' Hatch. GPC intends to treat these new surveillance requirements as " met" at the time of implementation of the new Technical Specifications, with the first' test to be performed within the required frequency from the implementation date. Any revisions to the Emergency Plan or Final Safety Analysis' Reports (FSAR) necessitated. by the conversion to the Improved Standard Technical Specifications will be submitted in accordance with the requirements of 10 CFR 50.54.

Georgia Power Company requests to meet with you at your earliest convenience to discuss a review schedule and the contents of this submittal package.

In accordance with the requirements of 10 CFR 50.91, a copy of this letter and all applicable enclosures will be sent to the designated State oflicial of the Environmental

' Protection Division of the Georgia Department of Natural Resources.

Mr. J. T. Beckham, Jr. states he is Vice President of Georgia Power Company and is authorized to execute this oath on behalf of Georgia Power Company, and to the best of his knowledge and belief, the facts set fonh in this letter are tme.

GEORGIA POWER COMPANY BY:

J. T. Beckham, JU Sworn to andsubscribed before me this25_ day of%m , I99 l.

Swam IM thqmw_;

Notary Public-

.c . . 'L T SRM/cr

Georgia Power d U.S Nuclear Regulatory Commission Page 3 February 25, 1994

Enclosure:

Improved Technical Specifications Submittal Synopsis Attachments:

1. Application of Selection Criteria

2. Unit 1 Improved Technical Specifications

3. Unit 2 Improved Technical Specifications

4. Unit 1 Improved Bases

5. Unit 2 Improved Bases

6. Unit 1 Markup of Current Technical Specifications and Discussion of Changes

7. Unit 2 Markup of Current Technical Specifications and Discussion of Changes

8. Unit 1 No Significant Hazards Determination

9. Unit 2 No Significant Hazards Determination

10. NUREG 1433 Comparison Document - Specifications

11. NUREG 1433 Comparison Document - Bases

12. NUREG 1433 Comparison Document - Justification for Deviation cc: Georcia Power Company Mr. H. L. Sumner, Nuclear Plant General Manager NORMS U.S. Nuclear Regulatory Commission. Washington. D.C.

Mr. K. Jabbour, Licensing Project Manager - Hatch Mr. C. Grimes, Technical Specifications Branch

)).S. Nuclear Regulatory Commission. Region ll Mr. S. D. Ebneter, Regional Administrator Mr. L. D. Wert, Senior Resident Inspector - Hatch State ofGeorgia Mr. J. D. Tanner, Commiss:oner - Department of Natural Resources l .. .

. ENCLOSURE IMPROVED TECHNICAL SPECIFICATIONS SUBMI' ITAL SYNOPSIS The Edwin I. Hatch Nuclear Plant Conversion to Improved Technical Specifications (ITS) submittal consists of 12 documents. Below is a listing of the volumes and a brief description of the volume contents. In addition, a brief explanation of how the material was prepared and the designations utilized is included.

UNITS 1 AND 2 APPLICATION OF SEI.ECTION CRITERIA This volume provides, for each unit, a discussion of how the NRC Final Policy Statement was applied to the current Units 1 and 2 Technical Specifications. Also, included for each unit, is a matrix cross referencing the following documents: 1) the current Technical Specifications (CTS); 2) the Standard Technical Specifications, or STS Rev. 4, (Unit 1 only); 3) the proposed Technical Specifications, where applicable; and 4) the Final Policy Statement Selection criteria. For the current Technical Specifications that do not meet any of the criteria and are not retained in the ITS, an explanation of why each Specification does not meet the selection criteria is provided (Appendices A and B). These Specifications are proposed to be relocated to owner-controlled documents.

UNIT 1 SPECIFICATIONS UNIT 2 SPECIFICATIONS These volumes contain only the proposed Technical Specifications for Units 1 and 2 in the NUREG 1433 format. The current Specifications requirements that are to be relocated are not included in these volumes.

UNIT 1 BASES UNIT 2 BASES These volumes contain the proposed Technical Specifications Bases for Units 1 and 2.

Information regarding the basis for each Specification, as well as details of what comprises OPERABLE subsystems, is provided.

UNIT 1 MARKUP OF CURRENT TECHNICAL SPECIFICATIONS AND DISCUSSION OF PROPOSED CHANGES (2 Volumes)

UNIT 2 MARKUP OF CURRENT TECHNICAL SPECIFICATIONS AND DISCUSSION OF PROPOSED CHANGES (2 Volumes)

These volumes contain annotated copies of the CTS to show the disposition of the existing requirements into the ITS. The pages are in ITS order, e.g., ITS 3.5.1 (ECCS - Operating) contains all appropriate pages from current ECCS requirements, as well as the LPCI inverter requirements in CTS Section 3.8, since the LPCI inverter requirements will now reside in ITS Section 3.5.

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ENCLOSURE (Continued)

IMPROVED TECHNICAL SPECIFICATIONS SUBMITTAL SYNOPSIS Each CFS page is annotated with the ITS Specification number at the top of the page, reflecting the ITS location of the CTS requirements. Items on the CTS page, which are located in ITS Specifications other than that referenced at the top of the page, are noted adjacent to the items. Where the ITS requirement differs from the CTS requirement, the individual details of the CFS being revised are annotated with alpha-numeric designators which relate to an appropriate Discussion of Change (DOC). The DOC provides a concise justification for the change outlined. The DOCS associated with each ITS section are located after the marked-up CTS pages. The alpha-numeric designators also relate to the no significant hazards determination (NSHD) evaluations contained in another volume of the submittal.

The current Plant Hatch Technical Specifications Bases pages are not individually annotated, since they are being replaced in their entirety. However, so that all current Technical Specifications pages can be accounted for, a page has been inserted behind the last DOC. This page details which CTS pages have not been included which are the following; CTS Bases pages and pages which indicate "left blank".

Current Technical Specifications pages containing requirements in more than one ITS Specification are repeated in the appropriate section(s). In this instance, portions of a single CFS Specification may relate to more than one ITS requirement, and as such, the requirement is contained within several ITS Specifications. For these CTS requirements, the CTS page is repeated for each ITS Specification, and may have differing alpha-numeric designators (with corresponding different DOCS), e.g., Unit 1 CTS Table 3.2.8, Functions 1 and 3, are located in three ITS LCOs (3.3.6.1,3.3.6.2, and 3.10.1). Thus, the appropriate CFS pages are found in all three ITS sections of the CFS markups.

The alpha-numeric designators relating to the CTS changes are numbered sequentially within each letter category and within each ITS Specification. The changes for each CFS are separated into the following categories:

Designator Category A ADMINISTRATIVE -

associated with restructuring, interpretation, and complex rearranging of requirements, and other changes not substantially revising an existing requirement.

R RELOCATED - specific requirements that do not meet the NRC Final Policy Statement selection criteria.

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ENCLOSURE (Continued)

IMPROVED TECHNICAL SPECIFICAT1.ONS SUBMITTAL SYNOPSIS Designator Category M MORE RESTRICTIVE - changes to the CTS being proposed in converting to the ITS, resulting in added restrictions or eliminating flexibility.

LA,LB,LC LESS RESTRICTIVE - justified with a single No Significant Hazards Determination (NSHD). The "LA" changes consist of '

climination of detail from the CTS. Typically, this involves details of system design and function, or procedural detail on methods of conducting a surveillance. "LB" changes are related to the extension of allowed outage times (AOTs) and surveillance test intervals (STIs) conducted in accordance with GE NRC approved Topical Rg orts. "LC" changes reflect elimination of various instrumentation requirements, where the instrument is an alarm or indication-only instrument that does not otherwise meet the NRC Final Policy Statement selection criteria.

L LESS RESTRICflVE - those in which requirements are relaxed or eliminated, or new flexibility is provided. Each Less Restrictive change has a unique corresponding NSHD (while there is a single NSHD for each of the other categories).

The DOCS associated with the LA, LB and LC less Restrictive changes are labeled

" Generic" and are discussed first after 2he Administrative, Relocated, and More Restrictive changes. The plant specific changes a.e labeled " Specific" and follow the " Generic" changes.

UNIT 1 NO SIGNIFICANT HAZARDS DETERMINATION UNIT 2 NO SIGNIFICANT HAZARDS DETERMINATION These volumes, containing the .0 CFR 50.92 required NSHDs, show that the proposed changes do not contain any significant hazard considerations that would indicate the change should not be made. Many of the proposed changes are grouped together based on similarities; e.g., requirements that are admiriistrative, certain types of less restrictive changes, mere restrictive changes, and requirements proposed to be relocated. " Generic" NSHD evaluations are presented for these categories.

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IMPROVED TECHNICAL SPECIFICATIONS SUBMITI'AL SYNOPSIS The first section of the NSHD volume contains an NSHD for each of the " generic" categories of changes (generic categories are all categories except category "L"). A single

, NSHD applies to all numbered changes of that type (e.g., a single "LA" NSHD is provided l for all"LA.x" labeled changes). These generic NSHDs are ordered alphabetically (i.e., A, LA, LB, LC, M, and R). Additionally, the generic Environmental Assessment is located at the end of this section.

The NSHD sections following the generic NSHDs contain separate NSHDs corresponding l to each "L" DOC, and are provided in ITS order, consistent with the CTS markup and l DOCS. For instance, an "L1" change noted in the CTS markup for ITS LCO 3.5.1 has a unique NSHD labeled "L1" in the section for ITS LCO 3.5.1 NSHDs.

UNIT 1 AND UNIT 2 NUREG 1433 COMPARISON DOCUMENT (3 Volumes)

These volumes contain a copy of NUREG 1433 (Specifications and Bases) annotated to

! compare the NUREG to the proposed Plant Hatch Improved Technical Specifications. The annotations include any deviations made in either Unit's proposed Specifications. The l justifications for each deviation from the NUREG are found in the third volume.

A deviation affecting only one Unit is indicated beside the deviation (e.g., Unit 1 only). For Secondary Containment Section 3.6, a Unit 1 markup followed by a Unit 2 markup is provided, >ecause the two Units differ in design.

For the purposes of determining deviations from NUREG 1433, the NUREG is considered to be NUREG 1433, dated 9/28/92, as modified by all generic changes submitted as of 1/31/94, whether or not they have been accepted, consistent with the generic change Matrix Rev. 7, dated 1/31/94. l There are two types of deviations identified -- Plant Specific and Generic. The plant-specific deviations are annotated by a "P," and the deviations due to generic changes in the NUREG are annotated with either a "GA" for generic accepted or "GP" for generic pending.

The plant-specific deviations cover all deviations that have not been submitted as a generic change. Both types of deviations (plant specific and generic) are numbered sequentially.

All generic changes, accepted and pending, adopted by Plant Hatch are indicated on the applicable pages and annotated with a "GA" or "GP". The discussion of the origin of the generic change (e.g., NUREG choge package BWR-18, Item C.1) is included in the Justification for Deviation section. A single "G" designator identifies each NUREG change package (e.g., BWR-18).

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IMPROVED TECHNICAL SPECIFICATIONS SUBMITTAL SYNOPSIS ,

Plant Hatch's rationale for not adopting certain generic changes is based on plant-specific factors, which are annotated in the NUREG Comparison. These annotations follow one of the following formats:

a. A non-adopted generic change that is small (i.e., a few words) and does not make the ,

markup too difficult to read is annotated and lined out. A "P" designator is placed beside the line-out. The Justification for Deviation identifies the generic change package and Plant Hatch's rationale for not adopting the change.

b. A large generic change is annotated by indicating the NUREG change package number (e.g., Note added by BWR-18, Item C.1). The change is lined out, and a "P" number is placed beside the line out. The Justification for Deviation identifies the generic change package and Plant Hatch's rationale for not adopting the change.

c. If the generic change is made to a section that has been deleted entirely (e.g., an LCO, ACTION, SR, or the applicable Bases), the deviation is identified in the markup near the lined-out section with words similar to "also modified by BWR-18 Item C.1."

The "P" deviation states the reason the origine NUREG requirement was not adopted, and thus, did not adopt the generic change. (The entire requirement is being delete i; thus,it appears unnecessary to state that a change to the NUREG is also not adopted.)

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O APPLICATION OF SELECTION CRITERIA TO THE EDWIN 1. HATCH NUCLEAR PLANT UNIT 1 TECHNICAL SPECIFICATIONS i O i 1

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1. INTRODUCTION ........................... 1-1

2. SELECTION CRITERIA ........................ 2-1

3. PROBABILISTIC RISK ASSESSMENT INSIGHTS .............. 3-1

4. RESULTS OF APPLICATION OF SELECTION CRITERIA ........... 4-1 S. REFERENCES ............................ 5-1 ATTACHMENT Summary Disposition Matrix Plant Hatch Unit 1 l

APPENDIX A Justification for Specification Relocation APPENDIX B Plant Specific Risk Justification 1

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1. INTRODUCTION l

The purpose of this document is to confirm the results of the BWR Owners' Group l

application of the Technical Specifications selection criteria on a plant specific basis for Edwin I. Hatch Nuclear Plant Unit 1. Georgia Power Company has reviewed the application of the selection criteria. to each of the Technical Specifications utilized in BWROG report NE00-31466, " Technical Specification Screening Criteria Application and Risk Assessment", including Supplement 1 (Reference 1), and NUREG 1433, " Standard Technical Specifications, General l Electric Plants BWR/4," (Reference 2), as well as applying the criteria to each of the current Plant Hatch Unit 1 Technical Specifications. Additionally, in accordance with the NRC guidance, this confirmation of the application of selection criteria to Plant Hatch Unit 1 includes confirming the risk insights from PRA evaluations, provided in Reference 1, as applicable to Plant Hatch Unit 1.

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V 2. SELECTION CRITERIA l

Georgia Power Company (GPC) has utilized the selection criteria provided in the NRC Final Policy Statement on Technical Specification Improvements (52 FR 3788) of July 23, 1993 (Reference 3) to develop the results contained in the attached matrix. Probabilistic Risk Assessment (PRA) insights as used in the BWROG l submittal were utilized, confirmed by GPC, and are discussed in the next section of this report. The selection criteria and discussion provided in the NRC Final Policy Statement are as follows:

Criterion 1: Installed instrumentation that is used to detect, and indicate in the control room, a significant abnormal degradation of the reactor coolant pressure boundary:

Discussion of Criterion 1: A basic concept in the adequate protection of the public health and safety is the prevention of accidents. Instrumenta-tion is installed to detect significant abnormal degradation of the Q reactor coolant pressure boundary so as to allow operator actions to

either correct the condition or to shut down the plant safely, thus j reducing the likelihood of a loss-of-coolant accident.

i This criterion is intended to ensure that Technical Specifications control those instruments specifically installed to detect excessive reactor coolant system leakage. This criterion should not, however, be interpret- j ed to include instrumentation to detect precursors to reactor coolant j i '

pressure boundary leakage or instrumentation to identify the source of actual leakage (e.g., loose parts monitor, seismic instrumentation, valve position indicators).

1 Criterion 2: A process variable, design feature, or operating restriction l that is an initial condition of a Design Basis Accident or Transient analysis that either assumes the failure of or presents a challenge to the integrity of a fission product barrier:

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Discussion of Criterion 2: Another basic concept in the adequate protection of the public health and safety is that the plant shall be operated within the bounds of the initial conditions assumed in the existing Design Basis Accident and Transient analyses and that the plant will be operated to preclude unanalyzed transients and accidents. These analyses consist of postulated events, analyzed in the FSAR, for which a structure, system, or component must meet specified functional goals.

These analyses are contained in Chapters 6 and 15 of the FSAR (or equivalent chapters) and are identified as Condition II, III, or IV events (ANSI N18.2) (or equivalent) that either assume the failure of or present a challenge to the integrity of a fission product barrier.

As used in Criterion 2, process variables are only those parameters for which specific values or ranges of values have been chosen as reference bounds in the Design Basis Accident or Transient analyses and which are monitored and controlled during power operation such that process values

, remain within the analysis bounds. Process variables captured by V Criterion 2 are not, however, limited to only those directly monitored and controlled from the control room. These could also include other features or characteristics that are specifically assumed in Design Basis Accident and Transient analyses even if they cannot be directly observed in the control room (e.g., moderator temperature coefficient and hot channel l factors).

The purpose of this criterion is to capture those process variables that have initial values assumed in the Design Basis Accident and Transient analyses, and which are monitored and controlled during power operation.

As long as these variables are maintained within the established values, risk to the public safety is presumed to be acceptably low. This criterion also includes active design features (e.g., high pressure / low pressure system valves and interlocks) and operating restrictions (pressure / temperature limits) needed to preclude unanalyzed accidents and transients.

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Criterion 3: A structure, system, or component that is part of the ,

(,) primary success path and which functions or actuates to mitigate a Design I Basis Accident or Transient that either assumes the failure of or presents I a challenge to the integrity of a fission product barrier:

Discussion of Criterion 3: A third concept in the adequate protection of j the public health and safety is that in the event that a postulated Design l Basis Accident or Transient should occur, structures, systems, and l components are available to function or to actuate in order to mitigate the consequences of the Design Basis Accident or Transient. Safety l sequence analyses or their equivalent have been performed in recent years and provide a method of presenting the plant response to an accident These can be used to define the primary success paths.

A safety sequence analysis is a systematic examination of the actions required to mitigate the consequences of events considered in the plant's Design Basis Accident and Transient analyses, as presented in Chapters 6

-3 and 15 of the plant's FSAR (or equivalent chapters). Such a safety

() sequence analysis considers all applicable events, whether explicitly or implicitly presented. The primary success path of a safety sequence analysis consists of the combination and sequences of equipment needed to operate (including consideration of the single failure criteria), so that the plant response to Design Basis Accidents and Transients limits the consequences of these events to within the appropriate acceptance criteria.

It is the intent of this criterion to capture into Technical Specifica-tions only those structures, systems, and components that are part of the ;

primary success path of a safety sequence analysis. Also captured by this criterion are those support and actuation systems that are necessary for !

items in the primary success path to successfully function. The primary j success path for a particular mode of operation does not include backup l and diverse equipment (e.g., rod withdrawal block which is a backup to the average power range monitor high flux trip in the startup mode, safety l 2-3 1

1 Discussion of Criterion 3: (continued) valves which are backup to low temperature overpressure relief valves during cold shutdown).

Criterion 4: A structure, system, or component which operating experience or probabilistic safety assessment has shown to be significant to public health and safety:

Discussion of Criterion 4: It is the Commission policy that licensees retain in their Technical Specifications LCOs, actions _ statements, and

. Surveillance Requirements for the following systems (as applicable), which operating experience and [probabilistic safety assessment (PSA)] PSA have ,

generally shown to be significant to public health and safety and any other structures, systems, or components that meet this criterion:

Reactor Core Isolation Cooling / Isolation Condenser,

Residual Heat Removal,

Standby Liquid Control, and

Recirculation Pump Trip.

The Commission recognizes that other structures, systems, or components may meet this criterion. Plant- and design-specific PSAs have yielded valuable insight to unique plant vulnerabilities not fully recognized in -

the safety analysis report Design Basis Accident or Transient analyses.

It is the intent of this criterion that those requirements that PSA or operating experience exposes as significant to public health and safety, consistent with the Commission's Safety Goal and Severe Accident Policies, be retained or included in Technical Specifications.

i The Commission expects that licensees, in preparing their Technical l Specification related submittals, will utilize any plant-specific PSA or l risk survey and any available literature on risk insights and PSAs. This material should be employed to strengthen the technical bases for those requirements that remain in Technical Specifications, when applicable, and O

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r i Discussion of Criterion 4: (continued) to verify that none - of the requirements to be relocated contain con-

{ straints of prime importance in limiting the likelihood or severity of the

accident sequences that are commonly found to dominate risk. Similarly, l the NRC staff will also employ risk insights - and PSAs in evaluating i Technical Specifications related submittals. Further, as'a part of the 4

Commission's ongoing program of improving Technical Specifications, it will continue to consider methods to make better use of the risk and j reliability information for defining future generic Technical Specifica-tion requirements. ,

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3. PROBABILISITIC RISK ASSESSMENT INSIGHTS Introduction and Ob.iectives The Final Policy Statement includes a statement that NRC expects licensees to utilize the available literature on risk insights to verify that none of the requirements to be relocated contain constraints of prime importance in limiting j the likelihood or severity of the accident sequences that are commonly found to dominate risk. l 1

Those Technical Specifications proposed for relocation to other plant controlled j documents will be maintained under the 10 CFR 50.59, safety evaluation review program. These Specifications have been compared to a variety of Probabilistic Risk Assessment (PRA) material with two purposes: 1) to identify if a component i or variable is addressed by PRA, and 2) to judge if the component or variable is risk-important. In addition, in some cases risk was judged independent of any specific PRA material. The intent of the review was to provide a supplemental screen to the deterministic criteria. Those Technical Specifications proposed to remain a part of the Improved Technical Specifications were not reviewed. '

This review was accomplished in Reference 1, except where discussed in Appendix :

A, " Justification For Specification Relocation", and has been confirmed by GPC l for those Specifications to be relocated. Where Reference 1 did not review a Technical Specification against the criteria of Reference 2, GPC performed a review similar (but not identical) to that described below for Reference 1. The results of these reviews are presented in Appendix B.

Assumptions and Approach Briefly, the approach used in Reference 1 was the following:

The risk assessment analysis evaluated the loss of function of the system or component whose LC0 was being considered for relocation and qualita-tively assessed the associated effect on core damage frequency and offsite releases. The assessment was based on available literature on plant risk 3-1 l

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insights and PRAs. Table 3-1' lists the PRAs used for making the assess-

, ments. A detailed quantitative calculation of the core damage and offsite release effects was not performed. However, the analysis did provide an !

l indication ' of the relative significance of those' LCOs proposed for relocation on the likelihood or severity of the accident sequences that are commonly found to dominate plant safety risks. The following analysis steps were performed for each LC0 proposed for relocation: l

a. List the function (s) affected by removal of the LC0 item. ;

b. Determine the effect of loss of the LCO item on the function (s).

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the loss of the LCO item.

d. Determine the relative frequency (high, medium, and low) of the loss of the function (s) assuming the LC0 item is removed from Technical Specifications and controlled by other procedures or programs. Use information from current PRAs and related analyses to establish the relative frequency.

e. Determine the relative significance (high, medium, and low) of the '

loss of the function (s). Use information from current PRAs and related analyses to establish the relative significance.

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f. Apply risk category - criteria -to establish the potential risk significance or non-significance of the LC0 item. Risk categories

, were defined as follows:

i RISK CRITERIA Conseauence Freauency High Medium Lqw High S S .NS

Medium S S NS Low NS NS NS S - Potential Significant Risk Contributor ,

NS = Risk Non-Significant

g. List any comments or caveats that apply .to the above assessment.

The output from the above evaluation was a. list of LCOs proposed for ,

relocation that could have potential plant safety risk significance if not properly controlled by other procedures or programs. - As a result these Specifications will be relocated to other plant controlled documents outside the Technical Specifications. ,

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TABLE 3-1 BWR PRAs USED IN NEDO 31466 (AND SUPPLEMENT 1)

RISK ASSESSMENT

BWR/6 Standard Plant, GESSAR II, 238 Nuclear Island, BWR/6 Standard Plant Probabilistic Risk Assessment, Docket No. STN 50-447, March 1982.

La Salle County Station, NED0-31085, Probabilistic - Safety Analysis, l February 1988. l

Grand Gulf Nuclear Station, IDCOR, Technical Report 86.2GG, Verification of IPE for Grand Gulf, March 1987.

Limerick, Docket Nos. 50-352, 50-353, 1981, "Probabilistic Risk Assess-ment, Limerick Generating Station", Philadelphia Electric Company.

Shoreham, Probabilistic Risk Assessment Shoreham Nuclear Power Station, Long Island Lighting Company, SAI-372-83-PA-01, June 24, 1983.

Peach Bottom 2, NUREG-75/0104, " Reactor Safety Study", WASH-1400, October 1975.

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Millstone Point 1, NUREG/CR-3085, " Interim Reliability Evaluation Program-Analysis of the Millstone Point Unit 1 Nuclear Power Plant", January 1983. l

Grand Gulf, NUREG/CR-1659, " Reactor Safety Study Methodology Applications Program: Grand Gulf #1 BWR Power Plant", October 1981.

NEDC-30936P, "BWR Owners' Group Technical Specification Improvement Methodology (with Demonstration for BWR ECCS Activation Instrumentation)

Part 2", June 1987.

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4. _RESULTS OF APPLICATION OF SELECTION CRITERIA l

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The selection criteria from Section 2 were applied to the- Plant Hatch Unit 1 1 Technical Specifications. The attachment is a summary of that application ,

indicating which Specifications are being retained or relocated. Discussions

that document the rationale for the relocation of each Specification which failed to meet the selection criteria are provided in Appendix A. No Significant Hazards Determination (10 CFR 50.92) evaluations for those Specifications j relocated are provided with the Discussion of Changes for the specific Technical a Specifications. GPC will relocate those Specifications identified as not

satisfying the criteria-to plant specific controlled documents whose changes are <

governed by 10 CFR 50.59. ,

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, 5. REFERENCES ;

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1. NED0-31466 (and Supplement 1), " Technical Specification Screening Criteria Application and Risk Assessment," November 1987.

2. NUREG 1433, " Standard Technical Specifications, General Electric Plants BWR/4," September 1992.

3. NRC No.93-102 " Final Policy Statement on Technical Specification Improvements," July 23, 1993.

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DISPOSITION MATRIX i

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PLANT HATCH UNIT 1 I

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( V d SIRNARY DISPOSITION MATRIX PLANT HATCH UNIT 1 Retained /

Current STS Criterion Unit 1 Rev. 4 New Unit 1 for Bases for Inclusion / Exclusion I *II*I Nurnber Title Number TS Number Inclusion M DEFINITIONS M M Yes See Note 1 and Note 4 3.10.1 None Reactor Mode Switch Interlock Testing Table 1.2 3.10.2 Yes See Note 4 1.1/1,2 SAFETY LIMITS L,0,,, M 1.1 Fuel Cladding Integrity 1.1.A Reactor Pressure > 800 psia and Core Flow 2.1.2 2.1.1.1 Yes See Note 2.

> 101 of Rated 1.1.B Core Thermal Power Limit, (Reactor Pressure 2.1.1 2.1.1.2 Yes See Note 2.

\ 800 psia) 1.1.C Power Transient None Deleted No Deleted. See Safety Limit technical change discussion.

1.1.D Reactor Water Level (Hot or Cold Shutdown Condition) 2.1.4 2.1,1.3 Yes See Note 2, 1.2 Reactor Coolant System Integrity 1.2.A.1 Reactor Vessel Steam Dome Pressure - Irradiated 2.1.3 2.1.2 Yes See Note 2.

Fuel in Reactor 1.2.A.2 Reactor Vessel Steam Dome Pressure - Operating None Deleted No Deleted. See Safety Limit technical change discussion.

RHR SDC Mode

\

I 2.1/2.2 LIMITING SAFETY SYSTEM SETTINGS 2.1 Fuel Cladding Integrity 2.2.1 3.3.1.1 Yes The application of Technical Specification selection 3.3.3 3.3.5.1 criteria is not appropriate. However, the fuel cladding integrity LSSS have been included as part of the RPS and ECCS instrumentation Specifications, which has been re-tained since the Functions either actuate to mitigate consequences of Design Basis Accidents (DBAs) and tran-sients or are retained as directed by the NRC as the Functions are part of the RPS.

2.2 Reactor Coolant System Integrity 2.2.1 3.3.1.1 Yes The application of Technical Specification selection 3.4.2.1 3.4.3 criteria is not appropriate. However, the Reactor Coolant System integrity LSSS has been included as part of RPS and safety relief valve Specifications, which have been re-tained since the instrument Functions and the safety relief valves mitigate the consequences of DBAs and transients wtach would result in overpressurization of the RCS.

Page 1 of 14 l

. =_s .. .m. .

f

[%

SUtHARY DISPOSITION MATRIX PLANT HATCH UNIT 1 Retained /

Current STS Criterion Unit 1 Rev. 4 New Unit 1 for Nusher Title Number TS Nisaber Inclusion Bases for Inclusion / Exclusion (aMc) i o

Lone LIMITING CONDITIONS FOR OPERATION APPLICABILITY M LCO 3.0.1 Yes See Note 3.

1 HEE LCO 3.0.7 None SURVEILLANCE REOUIRD1ENTS APPLICABILITY M SK 3,0,1 Yes See Note 3. !

1hI2 SR 3,0,4 3/4.1 (b) REACTOR PROTECTION SYSTD1 3/4.3.1 3.3.1.1 3/4.1.A Sources of a Trip Signal which Initiate a 3/4.3.1 .3.3.1.1 Yes-2,3 Retained as directed by the NRC as it is part of the RPS, Reactor Scram or it actuates to mitigate consequences of a DBA and/or &

transients, or it is an initial anstusption in a Transient analysis, or it provides an enticipe. tory scram to ensure the scram discharge voltsee and thus RPS remains operable.

M M E PROTECTIVE INSTRUMENTATION 3/ M ,!

3/4.2.A Initiates Reactor Vessel and Containment Isolation 3/4.3.2 3.3.6.1 Yes-3,4 Acttetes to mitigate the consequences of a DBA LOCA or is 3.3.6.2 retained due to risk significance.

t I

3/4.2.A.4 Main Steam Line Radiation 3/4.3.2.3.b Deleted No Deleted. See Primary Contairmnent Isolation Instrumentation technical change discussion for MSLRM. ;

3/4.2.A 8 RWCU Differential Flow 3/4.3.2.4.a Deleted No Deleted. - See Primary Containment Isolation Instrumentation i technical change discussion.

[

3/4.2.B Initiates or Controls HPCI 3/4.3.2.6 3.3.5.1.3 Yes-4 Actuation instrumentation actuates to mitigate consequences !

of a LOCA.

I

3/4.2.B.3 BPCI Turbine Overspeed - Mechanical None Relocated No See Appendix A, Page 1.

3/4.2.B.4 HICI Turbine Exhaust Pressure - High None Relocated No See Appendix A Page 1.

f 3/4.2.B.5 HPCI Pump Suction Pressure - Low None Relocated No See Appendix A. Page 1.

! 3/4.2.B.16 HPCI Logic Power Failure Monitor None Deleted No Deleted. See EOCS Instrtssentation technical change discussion.

i

! 3/4.2.C Initiates or Controls RCIC 3/4.3.2.5 3.3.5.2 Yes-4 Retained in accordance with the NRC Final Policy Statement I on Technical Specific ation improvements due to risk signif-icence.

3/4.2.C.2 RCIC Turbine Overspeed - Electrical and Mechanical None Relocated No See Appendix A, Page 2. ,

i i i !

i Pese 2 of 14

__ - - _. _ - _ - - - - __ _ - _ _ _ _ _ _ _ = _ _ _ _ . . __ _ - - - - _ _ . _ _ - - - - _ - - _ _ _ _ _ _ _ _ _ _ .

s SUtt1ARY DISPOSITION MATRIX PLANT HATCH UNIT 1 Retained /

STS Criterion ;

Current IJnit 1 Rev. 4 New Unit 1 for Number Title Number TS Ntmaber Inclusion Bases for Inclusion / ExclusionI "NCI t

3/4.2.C.3 RCIC Turbine Exhaust Pressure - High None Relocated No See Appendix A. Page 2.

3/4.2.C.4 RCIC Pump Suction Pressure - Low None Relocated No See Appendix A, Page 2.

3/4.2.C.6 RCIC Pump Discharge Flow None Relocated No See Appendix A. Page 2.

None Deleted No Deleted. See NCIC Instrtamentation technical change discussion.

3/4.2.C.13 RCIC Logic Power Failure Monitor 3/4.2.D Initiates or Controls ADS 3/4.3.3.4 3.3.5.1.4 Yes-3 Functions to mitigate the consequences of small break LOCAs. !

3.3.5.1.5 3/4.2.D.7 Automatic Blowdown Control Power Failure Monitor None Deleted No Deleted. See ECI:S Instrumentation tecimical change discussion. ,

3/4.2.E Initiates or Controls the LPCI Mode of RHR 3/4.3.3.2 3.3.5.1.2 Yes-3 ECCS mitigate the consequences of a DBA LOCA.

3/4.2.E.5 LPCI Cross Connect Valve Open Annunciator None Relocated . No See Appendix A. Page 4 3/4.2.E.8 Valve Selection Times None Relocated No See Appendix A. Page 5.

t 3/4.2.E.9 RER Relay Logic Power Failure Monitor None Deleted No Deleted. See ICCS Instrismentation technical change discussion.

3/4.2.F Initiates or controls Core Spray 3/4.3.3.1 3.3.5.1.1 Yes-3 ECCS mitigate the consequences of a DBA LOCA. ,

3/4.2.F.4 Core Spray Sparger Differential Pressure 3/4.5.1 Deleted No Deleted. See ECCS Instrumentation technical change discus-

'sion.

3/4.2.F.6 Core Spray Logic Power Failure Monitor None Deleted No Same es above.

3/4.2.G Initiates Control Rod Blocks 3/4.3.6 3.3.2.1 3/4.2.G.1 SRM 3/4.3.6.3 Relocated No See Appendix A, Page 6.

3/4.2.G.2 IRM 3/4.3.6.4 Relocated No See Appendix A Page 7.

3/4.2.G.3 APRM 3/4.3.6.2 Relocated No See Appendix A. Page 8. >

3/4.2.G.4 RBM 3/4.3.6.1 3.3.2.1.1 Yes-3 Prevents continuous withdrawal of a high worth control rod tnet could challenge the MCPR Safety Limit.

3/4.2.G.5 Scram Discharge Volume ~ 3/4.3.6.5 Relocated No See Appendix A. Page 9.

3/4.2.H Limit Radioactive Release 3/4.3.2' 3.3.6.2 3/4.3.7.1 3.3.7.1 l 3/4.2 H.1 Off-Ges Post Treatment Radiation Monitors 3/4.3.7.1.4. Relocated No See Appendix A, Page 10.

3/4,2.H.2 Refueling Floor Exhaust Vent Radiation tbnitors 3/4.3.2.2.c 3.3.6.1.2.e Yes-3 Actuates to mitigate consequences of a DBA LOCA and Fuel 3.3.6.2.4 handling accident.

3/4.2.H.3 Reactor Building Exhaust vent Radiation Mon?pors None 3.3.6.1.2.d Yes-3 Sune as above.

3.3.6.2.3 1

Page 3 of 14

% gg

\

b') V SUtHARY DISPOSITION MATRIX PLANT HATCH UNIT 1 Retained /

Current STS Criterion Unit 1 Rev. 4 New Unit 1 for Number Title Ntunbe r TS Number Inclusion Bases for Inclusion / ExclusionI *3I*I 3/4.2.H.4 Control Room Intake Radiation Monitors 3/4.3.7.1.5 3.3.7.1 Yes-3 Actuates to maintain control room habitability so that operation can continue from the control room following a DBA.

3/4.2.H.S Main Steem Line Radiation Monitor None Deleted No Deleted. See radiation monitoring technical change discus-sion for MSLRM.

3/4.2.I Initiates Recirculation Pump Trip 3/4.3.4.1 3.3.4.1 3/4.3.4.2 3.3.4.2 3/4.2.I.1/2 ATWS-RPT 3/4.3.4.1 3.3.4.2 Yes-4 ATWS-RPT is being retained in accordance with the NRC Final Policy Statement on Technical Specification Improvements due to risk significance.

3/4.2.I.3 EOC-RPT 3/4.3.4.2 3.3.4.1 Yes-3 EOC-RPT aids the reactor scram in protecting fuel cladding integrity by ensuring the fuel cladding integrity Safety Limit is not exceeded during a load rejection or turbine trip transient.

3/4.2.J Monitors Leakage into the Drywell 3/4.4.3 3.4.5 Yes-1 Leak detection is used to indicate a significant abnormal condition of the reactor coolant pressure boundary.

3/4.2 K Provides Surveillance Information 3/4.3.7.5 3.3.3.1 Yes-3 RG 1.97 Type A and Category 1 variables retained. See Appendix A, Page 11 for full discussion of all variables.

3/4.2.L Degraded Station Voltage Protection Instrumentation 3/4.3.3.5 3/4.2.L.1 4.16kv Emergency Bus Undervoltage Relay 3/4.3.3.5.1 3.3.8.1 Yes-3 Actuates DGs to mitigate consequences of a loss of offsite (Loss of Voltage Condition) power event.

3/4.2.L.2 4.16kv Emergency Bus Undervoltage Relay 3/4.3.3.5.2 Deleted No Deleted. See LOP Instrunentation technical change (Degraded Voltage Condition) discussion.

3/4.2.M Deleted in Amendment No. 186 3/4.2.N Arms Low Low Set S/RV System 3/4.4.2.1 3.3.6.3 Yes-3 Actuates LLS S/RVs, which are assumed to function in the 3/4.4.2.2 containment loading safety analysis.

None Remote Shutdown System 3/4.3.7.4 3.3.3.2 Yes-4 Being added as directed by the NRC as it is a significant j

contributor to risk reduction.

None Feedwater and Main Turbine Trip Instrumentation 3/4.3.9 3.3.2.2 Yes-3 Acts to limit feedwater addition to the reactor vessel on l

feedwater controller f ailure consistent with safety analy-sia assumptions. Limits neutron flux peak and thermal transient to avoid fuel damage.

Page 4 of 14

- . - . _ . _ . . . _ , _ _ _ . _ . _ _ .__.m _m a !

SIM4ARY DISPOSITION MATRIX ;

PLANT HATCH UNIT 1 r

Retained / ;

Current STS Criterion !

Unit 1 Rev. 4 New Unit 1 for Number Title Number TS Number Inclusion Bases for Inclusion / ExclusionI *M*3 t

3/4.3 REACTIVITY CONTROL 3/4.1 L.),

3/4.3.A Core Reactivity Margin 3/4.1.1 3.1.1 Yes-2 Not a measured process variable, but is important parameter [

that is used to confirm the acceptability of the accident ,

analysis. In addition the LCO is retained as directed by [

the NRC.

3/4.3.B Inoperable Control Rods j 3/4.3.B.1 No Movement by Control Rod Drive Pressure 3/4.1.3.1 3.1.3 Yes-3 Control rods are part of the primary success path in mitigating the consequences of DBAs and transients.

3/4.3.B.2 Excessive Screa Time 3/4.1.3.2 3.1.3 Yes-3 Same as above.

3/4.3.B.3 Inoperable Accumulators 3/4.1.3.5 3.1.3 Yes-3 Same as above.

3/4.1.3.7 3.1.5 3/4.3.B.4 Limiting Number of Inoperable Control Rods 3/4.1.3.1 3.1.3 Yes-3 Same as above.

3/4.3.C Control Rod Drive System 3/4.3.C.1 Control Rod Drive Coupling Integrity 3/4.1.3.6 3.1.3 Yes-3 Same as above. ;

3/4.3.C.2 Scram Insertion Times 3/4.1.3.3 3.1.4 Yes-3 Same es above.

3/4.1.3.4 3/4.3.C.3 Control Rod Drive Housing Support System 3/4.1.3.8 Coleted No See CRD Housing Support System technical change discussion.

3/4.3.D Minimum Count Rate for Rod Withdrawal 3/4.3.7.6 3.3.1.2 Yes Does not satisfy the selection critoria, however is being retained because the NRC considers it necessary for flux monitoring during shutdown, startup and refueling opera-tions.

3/4.3.E Rod Worth Inventory Determination 3/4.1.2 3.1.2 Yes-2 Confirms asssssptions made in the reload safety analysis.

3/4.3.F Operation with a Limiting Control Rod Pattern 3/4.3.6.1 3 . 3 . 2 .1'.1 Yes-3 Prevents continuous withdrawal of a high worth control rod that could challenge the MCPR Safety Limit.

3/4.3.G Rod Worth Minimizer t 3/4.3.G.1 Operability 3/4.1.4.1 3.3.2.1.2 Yes-3 Prevents withdrawal of control . rods outside BPWS con-straints that might set up high rod worth conditions beyond CRDA asstssptions.

3/4.3.G.2 Special Test Exceptions 3/4.10.2 3.10.7 Yes See Note 4 i

3/4.3.H Shutdoo.t Requirements 3/4.1 (all) 3.1 (all) Yes-3 The LCOs this Specification is associated with provide the i reactivity control requirements that mitigate the conse- [

quences of, or prevent a DBA or transient. Therefore this !

Specification has been incorporated into Actions for the !

associated LCDs.

Page 5 of 14

- _ ~ _

\

SIM1ARY DIEFOSITION MATRIX L PLANT HATCH UNIT 1 .

Current STS Criterion Unit 1 Rev. 4 New Unit 1 for Bases for Inclusion / ExclusionI

IICI Number Title Ntamber TS Ntsaber Int.lusion 1

3/4.3.I Scran Discharge Voltane vent and Drain Velves 3/4.1.3.1 3.1.8 Yes-3 Coatributes to the operability of the control rod screm .

function.

None Rod Pattern Control None 3 1.6 Yes-3 Assures initial conditions for the C3tDA analysis are maintained. [

None SHUTDOWN MARGIN (SDM) Test - Refueling 3/4.10.3 3.10.8 Yes See Note 4 l

2/4,4 STANDBY LIOUID CONTROL EYSTD1 3/4,1,5 3.1.7 Yes-4 Being retained in accordance with the NRC Final Policy Statement on Technical Specification Improvements due to risk significance.

r E Co"E AND CONTAINMENT COOLING SYSTEMS E M 3/4.7 3.7 3/4.8 3.8 5 3/4.5.A Core Spray (CS) System 3/4.5.1 3.5.1 Yes-3 Functions to mitigate the consequences of a DBA LOCA.

3/4.5.B Residual Heat kemoval (RHR) System 3/4.4.9.2 3.4.8 Yes-3.4 LPCI and containment cooling mode fuh..:tions to mitigate the 3 (LPCI and Containment Coolin? Mode) 3/4.5.1 3.5.1 consequences of a DBA LOCA. The RLR Shutdown eculing mode -

3/4.6.2.3 3.6.2.3- is being retained in accordance with the NRC Final Policy 3/4.9.11.1 3.9.7 Statement on Technical Specification Improvements due to 3/4.9.11.2 3.9.8 risk significance.

3/4.5.C RER Service Water System 3/4.7.1.1 3.7.1 Yes-3 Designed for heat removal from RER heat excFangers follow-ing a DBA. As such, acts to mitigate the consequences of an accident.

i 3/4.5.D High Pressure Coolant Injection (HPCI) System 3/4.5.1 3.5.1 Yes-4 While not asstaned in a licensing basis accident analysis.

UFCI is considered risk significant since it functions to mitigets the consequences of small break LOCAs. ,

I '

3/4.5.E Reactor Core Isolation Cooling (RCIC) System 3/4.7.4 3.5.3 Yes-4 Being retained in accordance with the NPC Final Policy 4

' Statement on . Tecimical Specification Improvements due to risk significance.

I 1 3/4.5.F Automatic Depressurization System (ADS) 3/4.5.1 3.5.1 Yes-3 Functiens to mitigets the consequences of small break LOCAs.

3/4.5.G Minimum Core and Contairunent Cooling Systems 3/4.5.2 3.5.2 Yes-3 Ensures inoperability of a diesel generator does not result Availability 3/4.8.1.1 3.8.1 in loss of containment cooling functions. Since ECCS is assumed to function to mitigate the consequences of a DBA

{ ,

! LOCA. this requirement has been maintained and has been r

moved to the Actions Table of LCO 3.8.1. The low pressure ECCS requirement ensures systems are available to mitigste the consequences of a vessel draindown ev-it.

1 i

I Page 6 of 14 i l

. - - ,.. - - . . = . - - - - + - , .

- . . . ~ . __._m_ _ . ._._. m.___._ m-. _ .. ... . . _ . _.~m . - -_m_. _._.mm ...._._m_._

_ ~_.m.__.m.. ..-- -

b\ g V

SLPfa.ARY DISPUSITION MATRIX PLANT BATCH UNIT 1 Retained /

Current STS Criterion Unit 1 Rev. 4 New Unit 1 for Number Title Number TS Number Inclusion Bases for Inclusion /ErclusionI

M*I' 9

3/4.5.H Maintenance of Filled Discherse Pipes 3/4.5.1 3.5.1 Yes-3 This Specification ensures the OPERA *!I,ITY of the ECCS and 3.5.2 RCIC, which function to mitigste the consequences of a DBA 3.5.3 LOCA (ECCS) or is required to be retained by the NRC Interim Policy Statement on Technical Specification Improvements (RCIC).

' Yes-3 Beat sink for heat removal from safety related systems 3/4.5.I Minimura River Level 3/4.7.1.3 3.7.2 i following a DBA. As such, acts to mitigate the consequenc-es of an accident.

3/4.5.J Plant Service Water Systera 3/4.7.1.2 3.7.2 Yes-3 Designed for heat removal from various safety related 3.7.3 systems following a DBA. As such, acts to mitigate the ,

consequences of an occident.

3/4.5.K Equipment Area Coolers None None No Relocated to the Bases as they are part of ECCS and RCIC Operability. See ECCS and RCIC technical change discus-

' sion.

l 2

s

?

E PRIMARY SYSTEM BotWDARY 3/4,4 34 3/4.6.A Reactor Coolant Heat-Up and Cooldown 3/4.4.6.1 3.4.9 Yes-2 Establishes initial conditions to operation such that g operation is prohibited in areas or at temperature rate ccanges that might cause undetected flaws to propagate in turn challenging the reactor coolant pressure boundary integrity.

3/4.6.B Reactor Vessel Temperature and Pressure 3/4.4.6.1 3.4.9 Yes-2 Same as above.

t 3/4.6.C Reactor Vessel Head Stud Tensioning 3/4.4.6.1 3.4.9 Yes-2 Same as above.

3/4.6.D Idle Recirculation Loop Startup 3/4.4.1.4 3.4.9 Yes-2 Same as above.

3/4.6.E Recirculation Pump Start 3/4.4.1.4 3.4.9 Yes-2 Same es above.

i e 3/4.6.F Reactor Coolant Chemistry i

3/4.6 F.1 Radioactivity 3/4.4.5 3.4.6 Yes-2 Specific activity provides an indication of the onset of l

! significent fuel cladding failure end is an initial condi-j tion for evaluation tradiological calculations) of the consequences of an accident due to main steam line break outside contairement.

,' 3/4.6.F.2 Conductivity and Chloride 3/4.4.4 Relocated No See Appendix A, Page 13.

i l

Page 7 of 14

_. m . __ m_- -_ .

A A ')

U V SUtHARY DISPOSITION KATRIX PLANT HATCH UNIT 1 Retained /

Current STS Criterion Unit 1 Rev. 4 New Unit 1 for I*I Number Title Ntsnber TS Ntanbsr Inclusion Bases for Inclusion /Erclusion 3/4.6.G Reactor Coolent Leakage 3/4.6.G.1 Unidentified and Total 3/4.4.3.2 3.4.4 Yes-1 Leakage beyond limits would indicate an abnormal condition of the reactor coolant pressure boundary. Operation in this condition may result in reactor coolant pressure boundary failure.

3/4.6.G.2 Leakage Detection Systems 3/4.4.3.1 3.4.5 Yes-1 Leak detection is used to indicate an abnormal condition of the reactor coolant pressere bour.dary.

3/4.6.G.3 Shutdown Requirements 3/4.4.3.1 3.4.4 Yes The LCOs thia Dpecification is associated with provide the 3/4.4.3.2 3.4.5 leakage requirements which meet criterion 1 (as listed in the two previous entries). Therefore, this Specification has been incorporated as Actions for the associated LCOs.

3/4.6.H.1 Relief / Safety Valves 3/4.4.2.1 3.3.6.3 Yes-3 A minisszs number of S/RVs is assumed in the oefety analysis 3.4.3 to mitigate overpressure events.

3/4.6.H.2 Relief / Safety Valves Low Low Set Function 3/4.4.2.2 3.3.6.3 Yes-3 A minimum ntsnber of S/RVs is assumed in the containment 3.6.1.6 loading safety analysis.

3/4.6.I Jet Pumps 3/4.4.1.2 3.4.2 Yes-3 Jet pump operability is asstaned in the LOCA analysis to assure adequate core reflood capability.

3/4.6.J Recirculation System 3/4.4.1.1 3.4.1 Yes-2 Recirculation loop flow is an initial condition in the safety analysis.

None RHR - Hot Shutdown 3/4.4.9.1 3.4.7 Yes-4 Being retained in accordance with the NRC Final Policy Statement on Technical Specification Improvements due to risk significance.

None Reactor Steam Dome Pressure 3/4.4.6.2 3.4.10 Yes-3 Reactor steam dame pressure is an initial condition in the reactor vessel overpressure safety analysis.

3/4.6.K Structural I ategrity 3/4.4.8 Relocated No See Appendix A. page 14, 3/4.6.L Snubbers 3/4.7.5 Deleted No Deleted. See technical change discussion for Snubbers.

, 3/4.7 CONTAINMENT SYSTEMS 3/4,6 L6 3/4.7.A Primary Contalrunent 3/4.7.A.1 Pressure Suppression Chamber 3/4.6.2.1 3.6.2.1 Yes-2 & 3 Suppression pool water level and temperature are initial 3.6.2.2 conditions in the DBA LOCA analysis and mitigate the consequences of the DBA.

3/4.7.A.2 Primary Contairenent Integrity 3/4.6.1.1 3.6.1.1 Yes-3 Primary containment integrity functions to mitigate the 3/4.6.1.2 3.6.1.2 consequences of a DBA. Primary Containment leakage 3/4.6.1.3 is an asstunption utilf red in the LOCA safety analysis 3/4.6.1.5 to ensure Primary Containment Operability.

t t

Page 8 of 14

V x SlMMRY DISPOSITION HATRIX PLANT BATCH UNIT 1 Retained /

Current STS Criterion Unit 1 Rev. 4 New Unit 1 for Number Title Number TS Number Inclusion Bases for Inclusion / ExclusionI "

3/4.7.A.3 Reactor Building to Pressure Suppression 3/4.6.4.2 3.6.1.7 Yes-3 Reactor building to pressure suppression chamber vacuum Chamber - Vacuum Relief System breaker operation is relied on to limit negative pressure differentiel, secondary to primary containment, that could challenge primary containment integrity.

3/4.7.A.4 Pressure Suppression Chamber to Drywell 3/4.6.4.1 3.6.1.8 Yes-3 Pressure suppression chamber to drywell vacuwe breaker Vacuum Breakers operation is assumed in the IJDCA analysis to limit drywell pressure thereby ensuring primary contalrunent integrity.

3/4.7.A.5 Oxygen Concentration 3/4.6.6.4 3.6.3.2 Yes-2 Oxygen concentration is limited such that when combined with hydrogen that is postulated to evolve following a LOCA the total explosive ses concentration remains below explo-sive levels. Therefore, containment integrity is main-tained.

3/4.7.A.6 Containment Atmosphere Dilution (CAD) 3/4.6.6.2 3.6.3.1 Yes-3 System ensures crygen concentration is maintained below the explosive level following a LOCA by inerting the drywell with nitrogen. Therefore, conteirunent integrity is main-tained.

3/4.7.A.7 Primary Containment Purge System 3/4.6.1.8 3.6.1.3 Yes-3 Isolation valves function to limit DBA consequences.

3/4.7.A.8 Shutdown Requirements 3/4.6.1 3.6.1 Yes-3 The LCOs that this Specification are associated with.

3/4.6.2 3.6.2 provide the primary conteirunent and combustible ses control 3/4.6.4 3.6.3 requirements that mitigate the consequences of a DBA.

Therefore, this Specification has been incorporated into Actions for the associated LCOs.

None RHR Suppression Pool Spray 3/4.6.2.2 3.6.2.4 Yes-3 Suppression pool spray functions to limit the effects of a DDA.

None Primary Containment Pressure 3/4.6.1.6 3.6.1.4 Yes-2 Primary containment pressure is an initial condition in the LOCA safety analysis.

None Primary Containment Air Temperature 3/4.6.1.7 3.6.1.5 Yes-2 Primary containment sir temperature is an initial condition in the LOCA safety analysis.

3/4.7.B Standby Gas Treatment System 3/4.6.5.3 3.6.4.3 Yes-3 SGT operation following a DBA act s to mitigate the conse-quences of offsite releases.

3/4.7.C Secondary Containment 3/4.6.5.1 3.6.4.1 Yes-3 Secondary containment integrity is relied on to limit the 3/4.6.5.5 3.6.4.2 offsite dose during vi accident by ensuring a release to contairunent is delayed and treated prior to release to the envirorunent. Damper operation within time limits estab-lishes secondary containment and limits offsite releases to acceptable values.

3/4.7.D Primary Containment Isolation Valves 3/4.6.3 3.6.1.3 Yes-3 Isolation Valves function to limit DBA consequences.

Page 9 of 14

( ,

3 SUPNARY DISPOSITION MATRIX PLANT HATCH UNIT 1 Retained /

Current STS Criterion Unit 1 Rev. 4 New Unit 1 for TS Number I *II*I Bases for Inclusion / Exclusion msnber Title Number Inclusion W RADI0 ACTIVE MATERIALS 3/4,7,6 3/4.8.A Miscellaneous Radioactive Materials Sources 3/4.7.6 Relocated No See Appendix A, page 16. ,

3/4,9 AUXILIARY ELECTRICAL SYSTEMS 3/4,8 M 3/4.9.A Requirements for Reactor Startup 3/4.9.A.1 Offsite Power Sources 3/4.8.1.1 3.E.1 Yes-3 Required to mitigate the consequences of a DBA.

3/4.9.A.2 Standby AC Power Supply (Diesel 3/4.8.1.1 3.8.1 Yes-3 Same es above.

Generators LA, IB, and IC) 3.8.3 3.8.4 3.8.6 3/4.9.A.3 125/250 Volt DC Emergency Power System 3/4.8.2.1 3.8.4 Yes-3 Same as above.

(Plant Batteries LA and IB) 3.8.6

} 3/4.9.A.4 Emergency 4160 Volt Buses (IE. IF. and IG) 3/4.8.3.1 3.8.7 Yes-3 Same as above.

1 3/4.9,A.5 Emergency 600 Volt Buses (1C and ID) 3/4.8.3.1 3.8.7 Yes-3 Same as above.

3/4.9.A.6 Emergency 250 Volt DC to 600 Volt AC Inverters 3/4.8.3.1 3.5.1 Yes-3 Same as above.

Yes-3 Same as above.

3/4.9.A.7 Logic Systems 3/4.8.1.1 3.8.1 ,

3/4.9.B Requirements for Continued Operation 3/4.8 (all) 3.8 (all) Yee-3 The LCOs that this Specification are associated with, with Inoperable Components provide the electrical systems requirements that mitigate a the consequences of a DBA. Therefore, this Specification has been incorporated into Actions for the associated LCOs. [

3/4.9.C Diesel Generator Requirements (Reactor in the 3/4.8.1.2 3.8.2 Yes-3 Functions to mitigate the consequences of a vessel drain- I Shutdown or Refuel Mode) 3.8.3 down event and is needed to support NRC Final Policy t 3.8.5 Statersent requirement for decay heat r wwal. I 6

3.8.6 I 3/4.9.D Electric Power Monitoring for the Reactor 3/4.8.4.4 '3.3.8.2 Yes-3 Provides protection for the RFS bus powered instrumentation l Protection System against unacceptable voltage and frequency conditione. that s 4 could degrada the instrumentation so thal it .:td not' i perform the intended safety function.

r None AC Sources - Shutdown 3/4.8.1.2 3.8.2 Yes-3 Functions to mitigate the consequences of a vessel drain-down event and is needed to support NRC Final Policy

Statement 'equirements for decay beat removal.

6 1

j None DC Sources - Shutdown 3/4.8.2.2 3.8.5 Yes-3 Same as aDow l None Distribution Systems - Shutdown 3/4.8.3.2 3.8.8 Yes-3 Same as above. ;

i 7

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t j

Page 10 of 14

,_ _ _ _ _ _ . _ _ _ _ _ ___ _ _ _ _ _ _ . _. . _ ,-,_ .~ - . . - - . . . . . - .

,mm.. . ._ _ m m _ - _ ....m.. - ..

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SUtHARY DISPOSITION MATRIX PLANT HATCH UNIT 1 Retained /

Current STS Criterion v Unit 1 Rev. 4 New Unit 1 for Ntumber Title Number TS Number Inclusion Bases for Inclusion / Exclusion 3/4.10 REFUELING M4.a9 L9 3/4.10.A' Refueling Interlocks 3/4.9.1 3.9.1 Yes-3 Provides an interlock to preclude fuel loading with control 3.9.2 rods withdrawn. Operation is aestssed in the control rod removal error during refueling and fuel assembly insertion ;

error during refueling accident analysis.

3/4.10.B Fuel Loading 3/4.9.3 3.9.3 Yes-2 All control rods are required to be fully inserted when i loading fuel. This requirement is aestmed as an initial condition in the fuel assembly insertion error during i

refueling accident analysis, 3/4 10.C Core Monitoring During Core Alterations 3/4.9.2 3.3.1.2 Yes Does not entisfy criteria for inclusion but is retained because the NRC considers it necessary for flux monitoring during shutdown, startup, and refueling operations.

3/4.10.D Spent Fuel Pool Water Level 3/4.9.9 3.7.8 Yes-2 A minimum amount of water is required to assure adequate scrubbing of fission products following a fuel handling accident.

3/4.10.E Control Rod Drive Maintenance 3/4.9.10.1 3.10.4 Yes See Note 4 3/4.9.10.2 3.10.5 3.10.6 i

None Single Control Rod Removal - Hot Shutdown Nons 3.10.3 Yes See Note 4 o 3/4.10.F Reactor Building Cranes 3/4.9.6 Relocated No See Appendix A, Page 17.

3/4.10.G Spent Fuel Cask Lifting Trunnions and Yoke 3/4.9.6 Relocated No See Appendix A. Page 17.

3/4.10.8 Time Limitation 3/4.9.4 Relocated No Although this LCD satisfied criterion 2, the activities necessary prior to consooncing movement of irradiated fuel ensure that there will always be 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months of suberiticality before movement of any irradiated fuel. Hence this Speci-fication has been relocated. !

i 3/4.10.I Crane Travel - Spent Fuel Storage Pool 3/4.9.7 Relocated No See Appendix A. Page 19. '

None Control Rod Position Indication 3/4.1.3.7 3.9.4 Yes-3 Control Rods are part of the primary success path in mitigating the consequences of DBAs.

None Control Rod OPERABILITY-Refueling 3/4.1.3.5 3.9.5 Yes-3 Same as above.

None Reactor Pressure vessel Water Level 3/4.9.8 3.9.6 Yes 2 A minimum amount of water is required to assure adequate scrubbing of fission products following a fuel handling accident.

Page 11 of 14

. m .. m_.- .__-m .. ._, __....--....~_-m__.-._.. . _ . m .m._ . . _ - . _ . . . - . - . . ___ . _ _ .,. - - .. - - m.__. m . . .

J J

SUPNARY DISPOSITION MATRIX PLANT HATCH UNIT 1 Retained / j Current STS Criterion Unit 1 Rev. 4 New Unit 1 for Number Title !! umber TS Number Inclusion Bases for Inclusion / ExclusionI *NCI 3/4,11 FUEL RODS 3/4.2 32 3/4.11.A Average Planer Lineer Heat Generation 3/4.2.1 3.2.1 Yes-2 Peak cladding temperature following a LOCA is primarily Rate (APLEGR) dependent on initial APLHGR As such, it is an initial ,

condition of a DBA analysis.

3/4.11.B Linear Beat Generation Rate (LHGR) 3/4.2.4 Deleted No Deleted. See LHGR technical change discussion.

3/4.11.C Minimum Critical Power Ratio (PCPR) 3/4.2.3 3.2.2 Yes-2 Utilised as an initial condition of the design basis transients. Transient analysis are performed to establish the largest reduction in Critical Power Ratio. This value is added to the fuel cladding integrity safety limit . to determine the ICPR value.

3/4_12 Main Control Room Environmental Systems 3/4.3.7.1 3.3.7.1 Yes-3 Maintains habitability of the control room so that opera-W 3(4. 7. 2 tors can remain in the control room following an accident.

As such, it mitigates the consequene.,s of an accident by allowing operators to continue accident mitigation activit-

,*, 1es from the control room.

1 4

3 None Main Control Room Air Crnditioning System None 1.7.5 Yes-3 Ensures control room temperatur* is maintained such that control room safety related equipment remains OPERABLE following an accident. As such, functions to mitigate the consequences of an accident.

i t

, 3/4,13 Removed in Amenenent No. 133

! A4 4

1 J

3/4 14 RADI0 ACTIVE EFFLUENT INSTRUMENTATION None None 3/4.14.1 Removed in Amen &nent 190 3/4.14.2 Explosive Gas Monitoring Instrumentation None Relocated No See Appendix A. Page 20.:

I 3/4.15 RADIOACTIVE EFFLUENTS None None j 3/4.15.1 Li, paid Effluents j 3/4.15.1.1- Removed in Amendment No. 190 3/4.15.1.3 l

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4 i Page 12 of 14 I

ex . . -. . .- . - - _ _ = _ . . . . . . ., . - - . . . . . . . _ - . --

C'i [N V (

SUPHARY DISPOSITION MATRIX PLANT HAICH UNIT 1 Retained /

Current STS Criterion Unit 1 Rev. 4 New Unit 1 for Number Title Minnber TS Number Inclusion Bases for Inclusion / ExclusionI

IICI 3/4.15.1.4 Liquid Holdup Tanks None 5.5.8 Yes Although this specification does not meet any criteria of the NRC Final Policy statement, it has been retained in accordance with NRC letter from W. T. Russell to the Indus-try ITS chairpersons, dated October 25, 1993.

3/4.15.2 Geseous Effluents 3/4.15.2.1- Removed in Amendnent No. 190 3/4.15.2.5 3/4.15.2.6 Explosive Gas Mixture None 5.5.8 Yes Same as above.

3/4.15.2.7 Main Condenser None 3.7.6 Yes-2 Main condenser offges activity is an initial condition in the offges systers failure event.

3/4.15.3 Removed in Amendment No. 190 3/4.16 Removed in Amendnent No. 190 M MAJOR DESIGN FEATURES M M Yes See Note 5.

O AININISTRATIVE CONTROLS 6.0 5.0 Yes See Note 6.

Page 13 of 14 f

\

SUfHARY DISPOSITION MATRIK PLANT BATCH UNIT 1

3TE 1; DEFINITIONS This section provides definitions for several defined terms used throughout the remainder of Technical Specifications. They are provided to improve the meaning of certain terms. As such, direct application of the Technical Specification selection criteria is not appropriate. . However, only those definitions for defined terms that remain as a result, of application of the selection criteria, will remain as definitions in this section of Technical Specifications, flOTE 2. SAFETY LIMITS /LSSS Application of Technical Specification selection criteria is not appropriate. However, Safety Limits and Limiting Safety System Settings (as part of Reactor Protection System Instrsanentation) will be included in Technical Specifications as required by 10 CFR 50.36.

NOTE 3; 3, 0 /4 .0 These Specifications provide generic guidance applicable to one or more Specifications. The information is provided to facilitate understanding of Limiting Conditions for Operation and Surveillance Regairements. As such, direct application of the Technical Specification selection criteria is not appropriate.

However, the general requirements of 3.0/4.0 will be added to the Plant Hatch Unit 1 Technical Specifications consistent with NUREG 1433.

NOTE 4; SPECIAL TEST EXCEPTIONS These Specifications are provided to allow relaxation of certain Limiting Conditions for Operation under certain specific conditions to allow testing and maintenance. They are directly related to one or more Limiting Conditions for Operations. Direct application of the Technical Speelfication selection criteria is not appropriate. However, those special test exceptions, directly tied to Limiting Conditions for Operation that remain in Technical Specifications, will also remain as Technical-Specifications, Those special test exceptions not applicable to Plant Hatch Unit 1 have been deleted.

NOTE 5; DESIGN FEATURES Application of Technical Specification selection criteria is not appropriate. However, Design Features will be included in Technical Specifications as required by 10 CFR 50.36.

NOTE 6; ADMINISTRATIVE CONTROLS Application of Technical Specification selection criteria is not appropriate. However, A&ninistrative Controls will be included in Technical Specificatione as required by 10 CFR 50.36.

a. Where a current Technical Specification is referred to as being deleted, the technical change discussion is found ' the Discussion of Changes associated with the markup of the current Specification.

b. For current Technical Specifications 3/4.1, RPS, and 3/4.2, Protective Instrumentation, the current Technical Specification number consists of the Specification nsasber and the instrtunentation channel's number from the associated 3.1.x or 3.2.x Table. For example, the Main Steam Line Radiation channel for the RPS is numbered 3/4.1.A.9, where "3/4.1.A* is the Specification ntenber and *9= is the scram number for the IRM channels in Table 3.1-1.

c. The applicable accident analyses are discussed in the Bases for the individual Technical Specif1' cation.

Page 14 of 14

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1 APPENDIX A J

JUSTIFICATION FOR l e I SPECIFICATION RELOCATION 1

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i APPENDIX A 3/4.2 PROTECTIVE INSTRUMENTATION LCO Statement:

The Limiting Conditions for Operation of the protective instrumentation affecting each of the following protective actions shall be as indicated in the correspond-ing LC0 table.

3/4.2.B Initiates or Controls HPCI 3/4.2.B.3 HPCI Turbine Overspeed - Mechanical' 4 3/4.2.B.4 HPCI Turbine Exhaust Pressure - High 3/4.2.B.5 HPCI Pump Suction Pressure - Low Discussion:

The function of these instruments is to provide a close signal to .the HPCI

- turbine stop valve. In turn, the injection valve and minimum flow valve will close. All of which will prevent the system from operating. Signals from any ,

of these three instruments will result in the valves listed above receiving a signal to close (directly or indirectly). These instruments actuate to provide turbine / pump protection only to preclude turbine / pump damage and possible breach ,

of the system. The valves are not credited with providing primary containment !

isolation on these signals, nor are they credited with closing to isolate a O primary coolant leak on these signals. No design basis analysis takes credit for these instruments.

Comparison to Deterministic Screenina Criteria: .

r

1. These instruments, in securing the HPCI System from operation, are not used for, nor capable of, detecting a significant abnormal degradation of the ,

reactor coolant pressure boundary prior to a design basis accident (DBA). l

2. These instruments do not sense a process variable that is an initial -

condition of a DBA or transient analysis. j i

3. These instruments are not part of a primary success path in the mitigation i of a DBA or transient. They are not assumed to function during a DBA or j transient. In addition, the valves closed by these instruments are not primary containment isolation valves.

As discussed in Appendix B (Page 1 of 8) of this document, the loss of these instruments was found to be a non-significant risk contributor to core damage frequency and offsite releases.

Conclusion:

Since the screening criteria have not been satisfied, these HPCI Instrument LCOs and Surveillances may be relocated to other plant controlled documents outside the Technical Specifications.

UNIT 1 A-1

APPENDIX A O

V 3/4.2 PROTECTIVE INSTRUMENTATION LCO Statemen_t:

The Limiting Conditions for Operation of the protective instrumentation affecting each of the following protective actions shall be as indicated in the correspond-ing LC0 table.

3/4.2.C Initiates or Controls RCIC 3/4.2.C.2 RCIC Turbine Overspeed - Electrical and Mechanical 3/4.2.C.3 RCIC Turbine Exhaust Pressure - High 3/4.2.C.4 RCIC Pump Suction Pressure - Low 3/4.C.2.6 RCIC Pump Discharge Flow Discussion:

The function of the first three above listed instruments is to provide a close signal to the RCIC turbine trip throttle valve. In turn, the injection valve and

, minimum flow valve will close. All of which will prevent the system from operating. Signals from any of these three instruments will result in the valves listed above receiving a signal to close (directly or indirectly). These instruments actuate to provide turbine / pump protection only to preclude

(] turbine / pump damage and possible breach of the system. The valves are not 1

V credited with providing primary containment isolation on these signals nor are they credited with closing to isolate a primary coolant leak on these signals.

No design basis analysis takes credit for these instruments. l l

The fourth instrument listed above controls the minimum flow valve. Failure of 1 this valve could result in failure of the RCIC System. The instrument actuates i 4

to provide pump protection only to preclude pump damage. No design basis I analysis takes credit for these instruments. l Comparison to Deterministic Screenina Criteria:

I. These instruments, in securing the RCIC System from operation or operating -

the minimum flow valve, are not used for, nor capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary prior to a design basis accident (DBA).

2. These instruments do not sense a process variable that is an initial condition of a DBA or transient analysis.

3. These instruments are not part of a primary success path in the mitigation of a DBA or transient. They are not assumed to function during a DBA or transient. In addition, the valves closed by these instruments are not primary containment isolation valves.

.- As discussed in Appendix B (Page 4) of this document, the loss of these instruments was found to be a non-significant risk contributor to core damage frequency and offsite releases.

UNIT I A-2

a

- APPENDIX A

Conclusion:

! Since the screening criteria have not been satisfied, these RCIC Instrument LCOs i

and Surveillances may be relocated to other plant controlled documents outside the Technical Specifications.

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UNIT 1 A-3

- - - . . - - . - _ _ - . . . _ _ _ _ _ ._ __ .i

APPENDIX A '

3/4.2 PROTECTIVE INSTRUMENTATION LCO Statement:

The Limiting Conditions for Operation of the protective instrumentation affecting each of the following protective actions shall be as indicated in the correspond-ing LC0 table.

3/4.2.E Initiates or Controls the LPCI Mode of RHR 3/4.2.E.5 LPCI Cross Connect Valve Open Annunciator Discussion: ,

This instrument initiates. annunciation in the control room when the LPCI cross-tie valve is not closed. During normal operation, the LPCI cross-tie valve is ,

required, by current Specification 3.5.B.1.d, to be closed and the associated control circuit breaker (to the valve) locked in the off position. Thus, this instrument is not the primary method for ensuring the valve remains closed, nor does any accident analysis take credit for this instrument.

Comparison to Deterministic Screenino Criteria:

p 1. The LPCI cross connect valve open annunciator is not used for, nor capable V of, detecting a significant abnormal degradation of the reactor coolant pressure boundary prior to a design basis accident (DBA).

2. The LPCI cross connect valve open annunciator is not a process variable that is an initial condition of a DBA or transient analysis.

3. The LPCI cross connect valve open annunciator is not part of the primary success path in the mitigation of a DBA or transient. It is not assumed to function during a DBA or transient.

As discussed in Section 6 and summarized in Table 6-1 (Item 332) of NED0-31466, Supplement 1, the loss of the LPCI cross connect valve open annunciator was found to be a non-significant risk contributor to core damage frequency-and offsite l releases. GPC has reviewed this evaluation and considers it applicable to Plant Hatch Unit 1.

l

Conclusion:

Since the screening criteria have not been satisfied, the LPCI Cross Connect Valve Open Annunciator LC0 and Surveillances may be relocated to other plant controlled documents outside the Technical Specifications.

O

! UNIT 1 A-4

l APPENDIX A iIl lO 3/4.2 PROTECTIVE INSTRUMENTATION LC0 Statement:

The Limiting Conditions for Operation of the protective instrumentation affecting each of the following protective actions shall be as indicated in the correspond-ing LC0 table.

3/4.2.E Initiates or Controls the LPCI Mode of RHR 3/4.2.E.8 Valve Selection Timers Discussion:

l The purpose of these instruments is to interlock open the RHR outboard isolation t

valves upon receipt of a LOCA signal, to ensure maximum LPCI flow to the reactor vessel. This ensures that a loss of LPCI flow will not occur due to an operator inadvertently closing these valves. However, while this feature may provide I added assurance of LPCI flow under certain circumstances, it is not assumed in any design basis analysis. In addition, under certain conditions the operator must secure LPCI flow, and thus do so by other means that are not interlocked (e.g., secure the RHR pumps).

/ Comoarison to Deterministic Screenina Criteria:

1. The valve selection timers are not used for, nor capable of, detecting a l significant abnormal degradation of the reactor coolant pressure boundary prior to a design basis accident (DBA).

2. The valve selection timers are not a process variable that is an initial condition of a DBA or transient analysis.

3. The valve selection timers are not part of the primary success path in the mitigation of a DBA or transient. They are not assumed to function during a DBA or transient.

As discussed in Appendix B (Page 7) of this document, the loss of the valve selection timers was found to be a non-significant risk contributor to core damage frequency and offsite releases.

Conclusion:

Since the screening criteria have not been satisfied, the Valve Selection Timers LC0 and Surveillances may be relocated to other plant controlled documents l outside the Technical Specifications.

b) u UNIT 1 A-5 1

r APPENDIX A 3/4.2 PROTECTIVE INSTRUMENTATION LC0 Statement:

The Limiting Conditions for Operation of the protective instrumentation affecting each of the following protective actions shall be as indicated in the correspond-ing LC0 table.

3/4.2.G Initiates Control Rod Blockt 3/4.2.G.1 SRM Discussion:

The Source Range Monitor (SRM) control rod block functions to prevent a control rod withdrawal error during reactor startup utilizing SRM signals to create the l rod block signal. SRM signals are used to monitor neutron flux during refueling, shutdown and startup conditions. No design basis accident or transient analysis.

takes credit for rod block signals initiated by the SRMs.

Comparison to Screenino Criteria:

1. The SRM control rod block is not used for, nor capable of, detecting a

'p significant abnormal degradation of the reactor coolant pressure boundary i

d prior to a design basis accident (DBA).

2. The SRM control rod block instrumentation is not used to monitor a process variable that is an initial condition of a DBA or transient analyses.

l 3. The SRM control rod block signal is not a part of a primary success path in the mitigation of a DBA or transient.

i As discussed in Sections 3.5 and 6, and summarized in Table 4-1 (Item 137) of NED0-31466, the loss of the SRM control rod block function was found to be a non-l significant risk contributor to core damage frequency and offsite releases. GPC has reviewed this evaluation and considers it applicable to Plant Hatch Unit 1.

Conclusion:

l Since the screening criteria have not been satisfied, the Control Rod Block LC0 and Surveillances applicable to SRM instrumentation may be relocated to other plant controlled documents outside the Technical Specifications.

l l

O UNIT 1 A-6

l l

APPENDIX A

(~T O

3/4.2 PROTECTIVE INSTRUMENTATION LC0 Statement:

The Limiting Conditions for Operation of the protective instrumentation affecting each of the following protective actions shall be as indicated in the correspond-ing LCO table.

3/4.2.G Initiates Control Rod Blocks 3/4.2.G.2 IRH Discussion:

l The Intermediate Range Monitor (IRM) control rod block functions to prevent a l control rod withdrawal error during reactor startup utilizing IRM signals to i create the rod block signal. IRMs are provided to monitor the neutron flux levels during refueling, shutdown and startup conditions. No design basis accidents or transient analysis takes credit for rod block signals initiated by IRMs.

1 Comparison to Screenina Criteria:

r 1. The IRM control rod block is not used for, nor capable of, detecting a Q] significant abnormal degradation of the reactor coolant pressure boundary prior to a design basis accident (DBA).

2. The IRM control rod block instrumentation is not used to monitor a process variable that is an initial condition of a DBA or transient analyses.

3. The IRM control rod block signal is not a part of a primary success path in the mitigation of a DBA or transient.

As discussed in Sections 3.5 and 6, and summarized in Table 4-1 (Item 138) of NE00-31466, the loss of the IRM control rod block function was found to be a non-significant risk contributor to core damage frequency and offsite releases. GPC has reviewed this evaluation and considers it applicable to Plant Hatch Unit 1.

Conclusion:

Since the screening criteria have not been satisfied, the Control Rod Block LCO and Surveillances applicable to IRM instrumentation may be relocated to other plant controlled documents outside the Technical Specifications.

UNIT 1 A-7 l

APPENDIX A 3/4.2 PROTECTIVE INSTRUMENTATION LCO Statement:

The Limiting Conditions for Operation of the protective instrumentation affecting each of the following protective actions shall be as indicated in the correspond-ing LCO table.

3/4.2.G Initiates Control Rod Blocks 3/4.2.G.3 APRM Discussion:

! The Average Power Range Monitor (APRM) control rod block functions to prevent a control rod withdrawal error during power range operations utilizing LPRM signals to create the APRM rod block signal. APRMs provide information about the average core power and APRM rod blocks are not used to mitigate a DBA or transient. l Comparison to Screenina Criteria:

1. The APRM control rod block is not used for, nor capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary (3 prior to a design basis accident (DBA). I

2. The APRM control rod block instrumentation is not used to monitor a process variable that is an initial condition of a DBA or transient analyses.

3. The APRM control rod block signal is not a part of a primary success path in the mitigation of a DBA or transient.

As discussed in Sections 3.5 and 6, and summarized in Table 4-1 (Item 135) of NED0-31466, the loss of the APRM control rod block function was found to be a non-significant risk contributor to core damage frequency and offsite releases.

GPC has reviewed this evaluation and considers it applicable to Plant Hatch Unit 1.

Conclusion:

Since the screening criteria have not been satisfied, the Control Rod Block LC0 and Surveillances applicable to IRM instrumentation may be relocated to other plant controlled documents outside the Technical Specifications.

O v

UNIT 1 A-8

1 1

1 i - ;

APPENDIX A I o :

i l

3/4.2 PROTECTIVE INSTRUMENTATION l

LCO Statement: ,

I

, The Limiting Conditions for Operation of the protective instrumentation affecting each of the following protective actions shall be as indicated in the correspond-ing LC0 table.

3/4.2.G Initiates' Control Rod Block i

j 3/4.2.G.5 Scram Discharge Volume j Discussion:

i The SDV control rod block functions to prevent control rod withdrawals during power range operations, utilizing scram discharge volume (SDV) signals to create 2

the rod block signal if water is accumulating in the SDV. The purpose -of l measuring the SDV water level is to ensure that there is sufficient volume to contain the water discharged by the control rod drives during a scram, thus

ensuring that the control rods will be able to insert fully. This rod block l

signal provides an indication to the operator that water is accumulating in the '

SDV and prevents further rod withdrawals. With continued water accumulation, a reactor protection system initiated scram signal will occur. Thus, the SDV water level rod block signal provides an opportunity for the operator to take action

! to avoid a subsequent scram. No design basis accident or transient takes credit l j for rod block signals initiated by the SDV instrumentation. l

' Comparison to Screenino Criteria:

1. The SDV control rod block is not used for, nor capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary prior to a design basis accident (DBA).

2. The SDV control rod block instrumentation is not used to monitor a process variable that is an initial condition of a DBA or transient analyses.

3. The SDV control rod block signal is not a part of a primary success path in the mitigation of a DBA or transient.

I As discussed in Sections 3.5 and 6, and summarized in Table 4-1 (Item 139) of NED0-31466, the loss of the SDV control rod block function was found to be a non-significant risk contributor to core damage frequency and offsite releases. GPC has reviewed this evaluation and considers it applicable to Plant Hatch Unit 1.

Conclusion:

I Since the screening criteria have not been satisfied, the Control Rod Block LC0 and Surveillances applicable to SDV instrumentation may be relocated to other plant controlled documents outside the Technical Specifications.

Ov UNIT 1 A-9

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APPENDIX A I v

3/4.2 PROTECTIVE INSTRUMENTATION LCO Statement:

The Limiting Conditions for Operation of the protective instrumentation affecting each of the following protective actions shall be as indicated in the correspond- ;

ing LC0 table. )

i 3/4.2,H Limit Radioactive Release l 1

3/4.2.H.1 Off-Gas Post Treatment Radiation Monitors j

Discussion

l The radioactive gas processing system is not a safety system and is not connected i to the primary coolant piping. The off-gas post treatment monitors are used to !

show conformance with the discharge limits of 10 CFR 20. There is another :

Specification (which is being retained-proposed LC0 3.7.6) that ensures 10 CFR 100 limits are not exceeded. Information provided by these instruments on the radiation levels would have limited or no use in identifying / assessing core damage and they are not installed to detect excessive reactor coolant leakage, l Comparison to Deterministic Screenina Criteria:

O

( ,/ 1. These monitors are not used for, nor are capable of, detecting a signifi-cant abnormal degradation of the reactor coolant pressure boundary prior to a design basis accident (DBA).

2. The monitored parameters are not assumed as initial conditions of a DBA or transient analyses that assumes the failure of, or presents a challenge to l the integrity of a fission product barrier. !

3. These monitors do not act as part of a primary success path in the mitigation of a DBA or transient that assumes the failure of, or presents

, a challenge to the integrity of a fission product barrier.

As discussed in Sections 3.5 and 6, and summarized in Table 4-1 (Item 145) of NED0-31466, the loss of these monitors was found to be a non-significant risk contributor to core damage frequency and offsite releases. GPC has reviewed this evaluation and considers it applicable to Plant Hatch Unit 1.

Conclusion:

Since the screening criteria have not been satisfied, the Off-Gas Post Treatment Radiation Monitors LC0 and Surveillance may be relocated to other plant controlled documents outside the Technical Specifications.

UNIT 1 A-10

n APPENDIX A U

3/4.2 PROTECTIVE INSTRUMENTATION LC0 Statement:

The Limiting Conditions for Operation of the protective instrumentation affecting each of the following protective actions shall be as indicated in the correspond-ing LC0 table.

3/4.2.K Provides Surveillance Information Discussion:

Each individual accident monitoring parameter has a specific purpose, however, the general purpose for all accident monitoring instrumentation is to provide sufficient information to confirm an accident is proceeding per prediction, i.e.

automatic safety systems are performing properly, and deviations from expected accident course are minimal.

Comparison to Deterministic Screenina Criteria:

The NRC position on application of the deterministic screening criteria to post-accident monitoring instrumentation is documented in letter dated May 7, 1988 from T.E. Murley (NRC) to R.F. Janecek (BWR0G). The position was that the post-A accident monitoring instrumentation table list should contain, on a plant U specific basis, all Re;ulatory Guide 1.97 Type A instruments specified in the plant's Safety Evaluation Report (SER) on Regulatory Guide 1.97, and all Regulatery Guide 1.97 Category 1 instruments. Accordingly, this position has been applied to the Plant Hatch Unit 1 Regulatory Guide 1.97 instruments. Those instruments meeting this criteria have remained in Technical Specifications. The instruments not meeting this criteria may be relocated from the Technical Specifications to plant controlled documents.

The following summarizes the Plant Hatch Unit 1 position for those instruments currently in Technical Specifications.

From NRC SER dated 7/30/85,

Subject:

Conformance to R.G. 1.97.

Tvoe A Variables

1. Reactor Pressure

2. Drywell Temperature

3. Suppression Chamber Water Temperature

4. Hydrogen and Oxygen Analyzer Other Tvoe. Cateaory 1 Variables l l

1. Reactor Vessel Water Level l

2. Shroud Water Level

3. Drywell Pressure h

V 4.

5.

Suppression Chamber Water Level Drywell High Range Pressure

6. Drywell High Range Radiation UNIT 1 A-11

i

APPENDIX A

\

For other post-accident monitoring instrumentation currently in Technical 4

Specifications, their loss is not considered risk-significant since the.

Varieble they monitor does not qualify as a Type A or Category 1 variable (one that is important to safety, and needed by the operator so that the ,

o?'rator can perform necessary manual actions).

Conclusion Since the screening criteria have not been satisfied for non-Regulatory Guide +

1 1.97 Type A or Category 1 variable instruments, their associated LC0 and 4

Surveillances may be relocated to other plant controlled documents outside the Technical Specifications. The instruments to be relocated are as follows: ,

1 1. Suppression Chamber Air Temperature i 2. Suppression Chamber Pressure

3. Rod Position Information System

4. Post LOCA Radiation Monitoring System

5. Safety / Relief Valve Position Indication

6. Main Stack Post-Accident Effluent Monitor

7. Reactor Building Vent Plenum Post-Accident Effluent Monitor I

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i 3/4.6.F.2 CONDUCTIVITY AND CHLORIDE i

! LCO Statement: (paraphrased) i j The chemistry of the reactor coolant system shall be maintained within the limits

specified in 3/4.6.F.2.a b, and d.

1 Discussion:

Poor reactor coolant water chemistry may contribute to the long term degradation of system materials and thus is not of immediate importance to the plant

, operator. Reactor coolant water chemistry is monitored for a variety of reasons, j One reason is to reduce the possibility of failures in the reactor coolant system pressure boundary caused by corrosion. Severe chemistry transients have resulted !

in failure of thin walled LPRM instrument dry tubes in a relatively short period

- of time. However, these LPRM' dry tube failures result in -loss of the LPRM i function and are readily detectable. In summary, the chemistry monitoring i

activity serves a long term preventative rather then mitigative purpose. 3 j Comparison to Screenina Criteria:

i

1. Reactor coolant water chemistry is not used for, nor capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary A prior to a design basis accident (DBA).

U 2. Reactor coolant water chemistry is not used to monitor a process variable

, that is an initial condition of a DBA or transient.

! 3. Reactor coolant water chemistry is not supportive of any primary success l path in the mitigation of a DBA or transient.

i As discussed in Sections 3.5 and 6, and summarized in Table 4-1 (Item 211) of i NED0-31466, the reactor coolant water chemistry was found to be a non-significant l

risk contributor to core damage frequency and offsite releases. GPC has reviewed i j this evaluation and considers it applicable to Plant Hatch Unit 1.

Conclusion:

{

Since the screening criteria have not 'been satisfied, the Conductivity and i Chloride LC0 and Surveillances may be relocated to other plant controlled i documents outside the Technical Specifications.

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UNIT 1 A-13 l l l

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APPENDIX A U l 3/4.6.K STRUCTURAL INTEGRITY !

LC0 Statement:

The structural integrity of ASME Code Class 1, 2, and 3 (equivalent) components I I

shall be maintained in accordance with the Surveillance Requirements of Specification 4.6.K.

Discussion:

The inservice testing requirements on pumps and valves required by 4.6.K.1 have been moved to Specification 5.5.6 and are not part of this discussion.

The inspection programs for ASME Code Class 1, 2, and 3 components ensure that i

the structural integrity of these components will be maintained throughout the ccmponents life. Other Technical Specifications require important systems to be l operable (for example, ECCS 3/4.5.1) and in a ready state for mitigative action. l This Tet.hnical Specification is more directed toward prevention of component '

l degradation and continued long term maintenance of acceptable structural l conditions. Hence it is not necessary to retain this Specification to ensure immediate operability of safety systems.

l l Further, this Technical Specification prescribes inspection requirements which q are performed during plant shutdown. It is, therefore, not directly important l CJ for responding to design basis accidents.

Comparison to Screenina Criterial

1. The inspections stipulated by this Specification are not used for, nor capable of, detecting a significant abnormal degradation of the reactor toolant pressure boundary prior to a design basis accident (DBA).

2. The inspections stipulated by this Specification do not monitor process '

variables that are initial assumptions in a DBA or transient analyses.

3. The ASME Code Class 1, 2, and 3 components inspected per this Specification are assumed to function to mitigate a DBA. Their capability to perform this function is addressed by other Technical Specifications. This Technical Specification, however, only specifies inspection requirements for these components; and these inspections can only be performed when the plant is shutdown. Therefore, Criterion 3 is not satisfied.

l As discussed in Sections 3.5 and 6, and summarized in Table 4-1 (Item 216) of '

NED0-31466, the assurance of operability of the entire system as verified in the l system operability Specification dominates the risk contribution of the system.

As such, the lack of a long term assurance of structural integrity Specification was found to be a non-significant risk contributor to core damage frequency and offsite releases. Furthermore, the requirement is currently covered by 10 CFR 50.55a and the plant's Inservice Inspection Program. GPC has reviewed this evaluation and considers it applicable to Plant Hatch Unit 1.

UNIT 1 A-14

APPENDIX A Os

Conclusion:

Since the screening criteria have not been satisfied, the Structural Integrity LCO and Surveillances may be relocated to other plant controlled documents outside the Technical Specifications.

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UNIT 1 A-15

APPENDIX A (G]

3/4.8.A MISCELLANEOUS RADI0 ACTIVE MATERIALS SOURCES LC0 Statement:

1. The leakage test shall be capable of detecting the presence of 0.005 microcurie of radioactive material on the test sample. If the test reveals the presence of 0.005 microcurie or more of removable contamination, it shall immediately be withdrawn from use, decontaminated and repaired, or disposed of in accordance with Commission regulations. Sealed sources are exempt from such leak tests when the source contains 100 microcuries or less of beta and/or gamma emitting material or 10 microcuries or less of alpha emitting material.

2. A complete inventory of radioactive materials in possession shall be maintained current at all times.

4 Discussion:

The limitations on sealed source contamination are intended to ensure that the total body or individual organ irradiation doses does not exceed allowable limits in the event of ingestion or inhalation. This is done by imposing a maximum limitation of s 0.005 microcuries of removable contamination on each sealed source. This requirement and the associated Surveillance Requirements bear no O relation to the conditions or limitations which are necessary to ensure safe Q reactor operation.

Comoarison to Screenina Criteria:

)

1. Miscellaneous radioactive materials sources are not used for, nor capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary pr br t; a design basis accident (DBA).

2. Miscellaneous radioactive materials sources are not a process variable that is an initial condition of a DBA or transient.

3. Miscellaneous radioactive materials sources are not used in any part of a primary :uccess path in the mitigation of a DBA or transient.

l

. As discussed in Sections 3.5 and 6, and summarized in Table 4-1 (Item 267) of

NED0-31466, the miscellaneous radioactive materials sources being not within limits were found to be non-significant risk contributors to core damage frequency and offsite releases. GPC has reviewed this evaluation er.d considers it applicable to Plant Hatch Unit 1.

Conclusion:

Since the screening criteria have not been satisfied, the Miscellaneous Radioactive Materials Sources LC0 and Surveillances may be relocated to other g plant controlled documents outside the Technical Specifications.

UNIT 1 A-16

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APPENDIX A 3/4.10.F REACTOR BUILDING CRANES l 3/4.10.G SPENT FUEL CASK LIFTING TRVNNIONS AND Y0KE LCO Statement:

1 3/4.10.F j

1. Main Reactor Buildino Crane The initial lifting of a spent fuel cask shall not be undertaken without j prior AEC approval. The reactor building crane will be modified to

! increase its ability to withstand a single failure prior to lifting a spent i fuel cask. Technical Specifications governing spent fuel cask handling

) will be developed prior to lifting the first spent fuel cask.

1

2. Limitina Heiaht Above Refuelino Floor j See note for Specification 3.10.F.1 above.

i 3. Mcnorail Hoist The monorail hoist shall be operating properly whenever new fuel or the fuel pool gates are handled.

3/4.10.G Soent Fuel Cask Liftina Trunnions and Yoke l See note for specification 3.10.F.1 above.

Discussion:

Operability of the above mentioned equipment (cranes, hoists and . lifting l equipment) ensures that only the proper equipment will be used to handle fuel or i casks within the storage pool, hoists have sufficient load capacity for handling

]

fuel assemblies or other loads and the possibility of dropping a load on the core

. internals and pressure vessel are minimized during lifting operations. The i design of the reactor building and crane is such that casks of current design 4 cannot be lifted more than two feet above the refueling floor. An analysis has been made which shows that the floor over which the spent fuel cask is handled can satisfactorily sustain a dropped cask from a height of 2 feet. Administra-tively limiting the height that the spent fuel cask is raised over the refueling i floor serves as a backup to minimize the damage that could result from 'an accident. Although this Technical Specification supports a refueling accident analysis, the crane limits are not monitored and controlled during operation; they are checked on a periodic basis to ensure operability. The deterministic l criteria for Technical Specification retention are, therefore, not satisfied. l UNIT 1 A-17

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Comoarison to Screenina Criteria:

1. The reactor building crane and lifting equipment are not used for, nor capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary prior to a design basis accident (DBA). )

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2. The reactor building crane and lifting equipment are not used to monitor a process variable that is an initial condition of a DBA or transient.

3. The reactor building crane and lifting equipment are not part of a primary success path in the mitigation of a DBA or transient.

As discussed in Sections 3.5 and 6, and summarized in Table 4-1 (Item 287) of NED0-31466, the reactor building crane and lifting equipment was found to be a non-significant risk contributor to core damage frequency and offsite releases.

GPC has reviewed this evaluation and considers it applicable to Plant Hatch l Unit 1. J

Conclusion:

Since the screening criteria have not been satisfied, the Reactor Building Crane and Spent Fuel Cask Lifting Trunnions and Yoke LCOs and Surveillances may be relocated to other plant controlled documents outside the Technical Specifica-tions.

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UNIT 1 A-18

l APPENDIX A

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3/4.10.1 CRANE TRAVEL - SPENT FUEL STORAGE P0OL LCO Statement:

A maximum weight of 1600 pounds may be permitted to be transported over stored spent funi in order to minimize the consequences of a load handling accident.

Discussioq;t The Technical Specification limit of 1600 pounds for loads over the ' spent fuel l contained in the storage pool is further reduced by the heavy loads analysis to 725 pounds or the weight of a single fuel bundle. This 725 pound imposed limit ensures that in the event the load is dropped, the activity release will be bounded by the analysis of the refueling accident and any possible distortion of the fuel in the storage racks will not result in a critical array. Administra-tive monitoring of loads moving over the fuel storage racks serves as a backup ;

to the Unit I crane interlocks. While the Unit ? crane does not have interlocks, I its use is strictly governed by administrative controls.

Although this Technical Specification supports the maximum refueling accident assumption in the DBA, the applicable fuel handling crane travel limits are not monitored and controlled during operation; they are checked on a periodic basis to ensure operability. The deterministic criteria for Technical Specification

,q retention are, therefore, not satisfied.

' ('/

Comparison to Screenino Criteria:

1. The fuel handling crane travel limits are not used for, nor capable of, detecting a significant abnormal degradation of the reactor coolant i pressure boundary prior to a design basis accident (DBA).

2. The maximum severity assumed for the fuel handling DBA is limited by the limits placed on the crane travel. These crane travel limits are not, i however, process variables monitored and controlled by the operator. They '

are interlocks and/or physical stops. Therefore, Criterion 2 is not satisfied.

3. The fuel handling crane travel limits are not a structure, system, or component that is part of the primary success path and which functions or actuates to mitigate a DBA.

Traditional PRAs do not review risks associated with the spent fuel storage pool.

l Design basis analyses indicate that the release associated with fuel assembly l damage in the spent fuel storage pool due to crane accidents is significantly l lower than releases of concern evaluated by PRAs.

Conclusion:

Since the screening criteria have not been satisfied, the Crane Travel - Spent Fuel Storage Pool LC0 and Surveillances may be relocated to other plant

\ controlled documents outside the Technical Specifications.

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UNIT 1 A-19 l

i APPENDIX A O

b 3/4.14.2 EXPLOSIVE GAS MONITORING INSTRUMENTATION LCO Statement:

The explosive gas monitoring instrumentation channels shown in table 3.14.2-1 shall be OPERABLE with their alarm / trip setpoints set to ensure that the limits of Specification 3.15.2.6 are not exceeded.

Djic.ussion:

The explosive gas monitor Specification is provided to ensure that the concentration of potentially explosive gas mixtures contained in the gaseous radwaste treatment system are adequately monitored. This will help ensure that the concentration is maintained below the flammability limit of hydrogen.

However, the offgas system is designed to contain detonation and its loss of function will not affect the function of any safety related equipment. The concentration of hydrogen in the offgas stream is not an initial assumption of any design basis accident or transient analysis.

Comoarison to Screenino Criteria:

1. The explosive gas monitoring instrumentation is not used for, r.or capable of, detecting a significant abnormal degradation of the reactor coolant (3 pressure boundary prior to a design basis accident (DBA).

2. 'ihe explosive gas monitoring instrumentation is not used to monitor a process variable that is an initial condition of a DBA or transient.

Excessive system effluent is not an indication of a DBA or transient.

3. The explosive gas monitoring instrumentation is not part of a primary success path in the mitigation of a DBA or transient. Excessive discharge is not considered to initiate a primary success path in mitigating a DBA or transient.

As discussed in Sections 3.5 and 6, and summarized in Table 4-1 (Items 189 and 306) of NED0-31466, the loss of the explosive gas monitoring instrumentation was found to be a non-significant risk contributor to core damage frequency and l offsite releases. GPC has review this evaluation and considers it applicable to l Plant Hatch Unit 1. '

Conclusion:

Since the screening criteria have not been satisfied, the Explosive Gas

, Monitoring Instrumentation LC0 and Surveillances may be relocated to other plant l controlled documents outside the Technical Specifications.

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APPENDIX B !

4 PLANT SPECIFIC 4

RISK SIGNIFICANT EVALUATIONS

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APPENDIX B lO TECHNICAL SPECIFICATION:

l 3/4.2.B.3 HPCI Turbine Overspeed - Mechanical i

3/4.2.B.4 HPCI Turbine Exhaust Pressure - High 3/4.2.B.5 HPCI Pump Suction Pressure - Low l DESCRIPTION OF REQUIREMENT:

l These protective trips function to reduce the probability of pump / turbine damage under certain conditions. The above listed Technical Specifications specify the minimum number of operable channels per trip system; the limiting trip settings; and the minimum. calibration, functional test and channel check frequencies (channel check and functional test are not applicable to the mechanical overspeed trip system).

REFERENCES:

Hatch IPE l Monticello IPE NUREG 1150 (Peach Bottom) r DISCUSSION:

PRAs do not model conditions in which these trips are required to prevent O pump / turbine damage. If a condition requiring one of the above trips exists, it is typically assumed that HPCI is unavailable for the remainder of the event.

In a risk analysis, it is irrelevant whether HPCI is unavailable because it tripped on overspeed due to a control system failure or failed catastrophically.

l The following insights for the above _ trip signals were extracted from a review of PRAs:

l l 1. Spurious operation of any protective trip could result in failure of I HPCI to inject. The Specifications provide only a maximum setting j l

for the overspeed and exhaust pressure trips and a minimum setting for the low suction pressure trip. Thus, the limiting settings do not provide protection against spurious trips. The functional testing required by these Specifications would provide some

! protection against spurious trips from setpoint drift, but setpoint drift of any magnitude away from the limiting setting would not be a violation of these specifications. Relocation of the Specifica-tiens will not result in any measurable impact on HPCI reliability for the following reasons:

I a. Spurious trips are historically a minor contributor to HPCI l

unavailability, by comparison with active hardware failures and maintenance unavailaoility.

b. Other surveillance tests, some of which remain in the Technical Specifications, provide protection against spurious trips. For example, Technical Specifications require HPCI to be tested O- quarterly, 4

i UNIT 1 B-1 l

_ . - . . . _ _ _ , _ . . - - _ _ _ _ . _ _ _ i

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c. The issue of protection against spurious trips is purely a reliability issue. There are many other activities that affect i HPCI reliability which are not controlled by Technical Specifi-cations. As an example, the total unavailability due to mainte--

nance is a key factor in overall HPCI unavailability: yet the. l' Technical Specifications only limit the duration of individual-4 maintenance events. Other aspects, such as the frequency.of.=

j maintenance and the minimization of downtime, are left within i the control of plant management. Because plant management al-1 ready controls many of the factors affecting HPCI reliability

, via mechanisms not controlled by the Technical Specifications, ;

! the relocation of. the above testing requirements is not ex-i pected to have an appreciable impact on HPCI reliability. E 2

2. The high exhaust pressure trip is used to trip the HPCI turbine'on indication that an exhaust line blockage exists. An additional ;

signal, exhaust diaphragm high pressure,-is used to isolate the steam

supply to the turbine. This signal will also provide a trip signal 4

to the turbine, regardless of the availability of the exhaust pressure signal. The frequency of exhaust line blockage combined

, with both signals failing to trip the HPCI turbine is assessed as low, and the risk significance is consequently small.

3. The low suction pressure trip instrumentation provides protection against mispositioned or failed closed valves in the HPCI pump

suction lines. A mispositioned or failed closed valve could result in damage to the HPCI pump. From a PRA perspective, if the suction 4

paths for HPCI are failed, it is irrelevant whether HPCI fails due to cavitation problems or successfully trips, as it will be unavailable for the remainder of the transient. Human errors leading

to mispositioned valves that are normally locked open and hardware failures of locked open valves are historically small contributors j to HPCI unavailability.

a l 4. The mechanical overspeed could be called upon to function following

a control system failure or during an event in which HPCI was 4

operating when DC power was lost. These two cases are discussed

below

I a. With a control system failure, HPCI will be unavailable for the remainder of the event. From a PRA perspective, regardless of i whether the overspeed trip functions or not, HPCI is unavail-able for continued injection.

n UNIT 1 B-2 4

d g APPENDIX B U

b. The mechanical overspeed could be called upon to actuate if HPCI is operating, and DC power is depleted. Station blackout would be an example of this type of scenario. The response of HPCI following de power depletion is not completely predict-able, but it is possible that HPCI would overspeed. Battery depletion would result in the electrical overspeed control being unavailable, and the mechanical overspeed would be the only operable trip for HPCI. With no AC or DC power, the containment isolation valves in the HPCI steam line would remain open. The HPCI stop and control valves would function to isolate the HPCI steam line when hydraulic power was lost, regardless of whether the turbine mechanical overspeed func-tioned or not.

CONCLUSION:

Based on the above insights it can be concluded that Specifications 3/4.2.B.3, 3/4.2.B.4, and 3/4.2.B.5 may be relocated from the Plant Hatch Unit 1 Technical Specifications to a Plant Hatch controlled document with no significant impact on the potential for core damage and the risk of offsite consequences.

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UNIT 1 B-3

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TECHNICAL SPECIFICATION:

3/4.2.C.3- RCIC Turbine Overspeed - Electrical and Mechanical 3/4.2.C.4 RCIC Turbine Exhaust Pressure - High 3/4.2.C.5 RCIC Pump Suction Pressure - Low 3/4.2.C.6 RCIC Pump Discharge Flow DESCRIPTION OF RE0VIREMENT:

These protective trips function to reduce the probability of pump / turbine damage under certain conditions. The above listed Technical Specifications specify the minimum number of operable channels per trip system; the limiting trip settings; and the minimum calibration, functional, test and channel check frequencies.

(Channel check and functional test are not applicable to the mechanical overspeed trip system.)

REFERENCES:

Hatch IPE Monticello IPE NUREG 1150 (Peach Bottom)

DISCUSSION:

O PRAs do not model conditions in which the first three instruments are required V to prevent pump / turbine damage. If a condition requiring one of the above trips exists, it is typically assumed that RCIC-is unavailable for the remainder of the event. In a risk analysis, it is irrelevant whether RCIC is unavailable because it tripped on overspeed due to a control-system failure or failed catastrophical- ,

ly. The following insights for the above trip signals were extracted from a -

review of PRAs:

1

1. Spurious operation of any protective trip could result in failure of j RCIC to inject. The Specifications provide only a maximum setting for the overspeed and exhaust pressure trips and a minimum setting for the low suction pressure trip. Thus, the limiting settings do not provide protection against spurious trips. The functional testing required by these Specifications would provide some protection against spurious trips from setpoint drift, but setpoint drift of any magnitude away from the limiting setting would not be a violation of these Specifications. Relocation of the Specifica-tions will not result in any measurable impact on RCIC reliability for the following reasons:

a. Spurious trips are historically a minor contributor to RCIC :

unavailability, by comparison with active hardware failures and l maintenance unavailability.

b. Other surveillance tests, some of which remain in the Technical i Specifications, provide protection against spurious trips. For example, Technical Specifications require RCIC to be tested quarterly.

UNIT 1 B-4

APPENDIX B

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c. The issue of protection against spurious trips is purely a

reliability issue. There are many other activities that affect.

RCIC reliability which are not controlled by Technical Specifi-

cations. As an example, the total unavailability due to maintenance is a key factor in overall RCIC unavailability: yet

the Technical Specifications only limit the duration of individual maintenance events. Other aspects, such as the frequency of maintenance and the minimization of downtime, are left within the control of plant management. Because plant management already controls many of the factors affecting RCIC reliability via mechanisms not controlled by the Technical Specifications, the relocation of the above testing require-ments is not expected to have any appreciable impact on RCIC reliability.

i l 2. The high-exhaust pressure trip is used to trip the RCIC turbine on ,

i indication that an exhaust line blockage exists. - An additional signal, exhaust diaphragm high pressure, is used to isolate the steam supply to the turbine. This signal will also provide a trip signal to the. turbine, regardless of the availability of the exhaust pressure signal. The frequency of exhaust line blockage combined with both signals failing to trip the RCIC turbine is assessed as low, and the risk significance is consequently small.

3. The low suction pressure trip instrumentation provides protection against mispositioned or failed closed valves in the RCIC pump suction lines. A mispositioned or failed closed valve could result 4

in damage to the RCIC pump. From a pRA perspective, if the suction paths for RCIC are failed, it is irrelevant whether RCIC fails due to cavitation problems or successfully trips, as it will be unavailable for the remainder of the transient. Human errors leading to mispositioned valves that are normally locked open and hardware

failures of locked open valves are historically small contributors to RCIC unavailability.

! 4. The electrical and mechanical overspeeds could be called upon to function following a control system failure or during an event in

which RCIC was operating when DC power was lost. These two cases are j discussed below (case a applies to both the electrical and mechanical

overspeed trips while case b applies only to the mechanical overspeed

trip)

a. With a control system failure, RCIC will be unavailable for the remainder of the event. From a PRA perspective, regardless of whether the electrical and mechanical overspeed trips function or not, RCIC is unavailable for continued injection.

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UNIT I B-5 4

.,a APPENDIX B

b. The mechanical overspeed could be called upon to actuate if RCIC is operating, and DC power is depleted. Station blackout .

~ would be an example of this type of scenario. The response of RCIC following DC power depletion is not completely predict-l able, but it is possible that RCIC would overspeed. Battery i

depletion would result in' the electrical overspeed control

, being unavailable, and the mechanical overspeed would be the j only operable trip for RCIC. With no AC or DC power, the

containment isolation valves in the RCIC steam line would 4

remain open. The RCIC trip throttle valve would function to j

isolate the RCIC steam line when hydraulic power was lost, regardless of whether the turbine mechanical overspeed func-i tioned or not. >

l - The fourth instrument listed above controls the minimum flow valve. The minimum j flow valve for RCIC is normally closed, and must open only when no flow path is

' available to the vessel or the CST. The pump low flow signal provides the open signal to the minimum flow valve. Because vessel pressure is never expected to '

l exceed the capacity of RCIC to inject, the only causes for loss of a RCIC flow

path are control failures or valve failures in the discharge lines, and operator alignment errors. Control failures and valve failures would be modeled in PRAs

as loss of RCIC, regardless of the availability of the minimum flow path.

Operator errors that result in no flow path for_ RCIC are typically included in an operator error for failure to control flow, or in a human error involving

-( system misalignment. In either case, RCIC would typically be considered failed for the remainder of the event. Failure of the minimum flow path followed by pump failure is thus a superfluous failure with regards to the immediate availability of RCIC.

CONCl.USION:

! Based on the above insights, it can be concluded that Specifications 3/4.2.C.3, 3/4.2.C.4, 3/4.2.C.5, and 3/4.2.C.6 may be relocated from the Plant Hatch Unit 1

, Technical Specifications to a Plant Hatch controlled document, with no 4

significant impact on the potential for core damage and risk of offsite

consequences.

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APPENDIX B Q)

, TECHNICAL SPECIFICATION:

l 3/4.2.E.8 LPCI Injection Valve Selection Timers DESCRIPTION OF RE0VIREMENT:

These instruments function to electrically lock open the RHR outboard isolation valves for ten minutes on receipt of a LOCA signal. The outboard isolation l valves are normally open, and are used to throttle flow once adequate core 1 cooling is established. The inboard isolation valves are normally closed and are the only LPCI valves required to open for LPCI injection. The timers do not affect the LOCA signal to the inboard isolation valves, which remain electrically locked open as long as the LOCA signal exists.

REFERENCES:

Hatch IPE Monticello IPE NUREG 1150 (Peach Bottom)

DISCVSSION:

The following insights were extracted from a review of PRAs:

A V 1. The selection timers have normally closed contacts that transmit the LOCA signal to the outboard isolation valves. These contacts open after 10 minutes to remove the LOCA open signal, and allow the operators to throttle fl ow. If the LOCA timers fail completely, such that the normally closed contacts fail to transmit the LOCA open signal to the normally open outboard injection valve, LPCI injection will still occur.

2. Core cooling is affected only when a failure of the timers is combined with additional failures and human errors. For example, a timer must fail such that the LOCA signal is cleared significantly before 10 minutes, and the timer in the other loop must fail simultaneously, or the other LPCI loop must fail to provide flow. These failures must be combined with one of the following combinations of failures: a) vessel level instrumentation fails such that the operators believe that LPCI flow should be throttled, or b) operators completely misdiagnose the situation and believe that vessel level should be controlled, or c) operators inadvertently close the LPCI valves by mistake. The combinations of errors and hardware failures that would have to occur, in combination with an event such as a large break LOCA that requires low pressure injection in the early stages of the accident, would be insignificant compared to some of the active hardware failures that could result in the same effect. For example, failure of the 4 normally closed inboard injection valves to open would have a much higher probability than any of the combinations of human errors and hardware failures postulated above. l u

UNIT 1 B-7 l

APPENDIX B

3. During an ATWS event with low pressure injection, the operators must throttle LPCI injection to limit reactor power. Procedures direct the operators to override the LOCA signal to these valves before the 10 minute timers expire. These procedures direct the operators to lift leads to bypass the LOCA timer, such that failure of the timer cannot impact the ability to control LPCI flow.

CONCLUSION:

Based on the above insights, relocation of Specification 3/4.2.E.8 to a Plant Hatch controlled document should have no impact on plant safety.

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APPLICATION OF SELECTION CRITERIA TO THE ;

( I EDWIN 1. HATCH NUCLEAR PLANT t UNIT 2 TECHNICAL SPECIFICATIONS i

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'd CONTENTS Paae

1. INTRODUCTION .......................... 1-1 ;

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2. SELECTION CRITERIA ....................... 2-1

3. PROBABILISTIC RISK ASSESSMENT INSIGHTS ............. 3-1

4. RESULTS OF APPLICATION OF SELECTION CRITERIA .......... 4-1

5. REFERENCES .......................... 5-1 ATTACHMENT l

Summary Disposition Matrix Plant Hatch Unit 2 APPENDIX A Justification for Specification Relocation

APPENDIX B Plant Specific Risk Justification

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1. INTRODUCTION i The purpose of this document is to confirm the results of the BWR Owners' Group application of the Technical Specification selection criteria on a plant specific basis for Edwin I. Hatch Nuclear- Plant Unit 2. Georgia Power Company has l reviewed the application of the selection criteria to each of the Technical ]

Specifications utilized in BWROG report NED0-31466, " Technical. Specification Scr-l eening Criteria Application and Risk Assessment" including Supplement 1 (Reference 1), and NUREG 1433, " Standard Technical Specification, General Electric Plants BWR/4," (Reference 2), as well as applying the criteria to each of the current Plant Hatch Unit 2 Technical Specifications. Additionally, in accordance with the NRC guidance, this confirmation of the application of selection criteria to Plant Hatch Unit 2 includes confirming the risk insights from Probabilistic Risk Assessment (PRA) evaluations, provided in Reference 1, as applicable to Plant Hatch Unit 2.

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2. SELECTION CRITERIA Georgia Power Company (GPC) has utilized the selection criteria provided in the NRC Final Policy Statement on Technical SpecificationImprovements (52 FR 3788) of July 23,1993 (Reference 3) to develop the results contained in the attached matrix. Probabilistic Risk Assessment (PRA) insights as used in the BWROG ,

submittal were utilized, confirmed by GPC, and are discussed in the next section of this report. The selection criteria and discussion provided in the NRC Final Policy Statement are as follows:

Criterion 1: Installed instrumentation that is used to detect, and indicate in the control room, a significant abnormal degradation of the reactor coolant pressure boundary:

Discussion of Criterion 1: A basic concept in the adequate protection of the public health and safety is the prevention of accidents. Instrumenta-tion is installed to detect significant abnormal degradation of the reactor coolant pressure boundary so as to allow operator actions to either correct the condition or to shut down the plant safely, thus reducing the likelihood of a loss-of-coolant accident.

l This criterion is intended to ensure that Technical Specifications control those instruments specifically installed to detect excessive reactor coolant system leakage. This criterion should not, however, be interpret-ed to include instrumentation to detect precursors to reactor coolant pressure boundary leakage or instrumentation to identify the source of l actual leakage (e.g., loose parts monitor, seismic instrumentation, valve l position indicators).

Criterion 2: A process variable, design feature, or operating restriction that is an initial condition of a Design Basis Accident or Transient analysis that either assumes the failure of or presents a challenge to the I integrity of a fission product barrier:

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i Discussion of Criterion 2: Another basic concept in the adequate protection of the public health- and safety is that the plant shall be operated within the bounds of the initial conditions assumed in the existing Design Basis Accident and Transient analyses and that the plant will be operated to preclude unanalyzed transients and accidents. These analyses consist of. postulated events, analyzed in the FSAR, for which a structure, system, or component must meet specified functional goals.

These analyses are contained in Chapters 6 and 15 of the FSAR (or equivalent chapters) and are identified as Condition II, III, or IV events (ANSI N18.2) (or equivalent) that either assume the failure of or present j a challenge to the integrity of a fission product barrier.

l As used in Criterion 2, process variables are. only those parameters _ for which specific values or ranges of values have been chosen as reference bounds in the Design Basis Accident or Transient analyses and which are monitored and controlled during power operation such that process values ,

remain within the analysis bounds. Process variables captured by i Criterion 2 are not, however, limited to only those directly monitored and '

controlled from the control room. These could also include other features or characteristics that are specifically assumed in Design Basis Accident and Transient analyses even if they cannot be directly observed in the control room (e.g., moderator temperature coefficient and hot channel factors).

The purpose of this criterion is to capture those process variables that have initial values assumed in the Design Basis Accident and Transient analyses, and which are monitored and controlled during power operation.

As long as these variables are maintained within the established values, risk to the public safety is presumed to be acceptably low. This criterion also includes active design features (e.g., high pressure / low pressure system valves and interlocks) and operating restrictions (pressure / temperature limits) needed to preclude unanalyzed accidents and transients.

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Criterion 3: A structure, system, or component that is part of the V primary success path and which functions or actuates to mitigate a Design Basis Accident or Transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier:

Discussion of Criterion 3: A third concept in the adequate protection of the public health and safety is that in the event that a postulated Design Basis Accident or Transient should occur, structures, systems, and components are available to function or to actuate in order to mitigate the consequences of the Design Basis Accident or Transient. Safety sequence analyses or their equivalent have been performed in recent years and provide a method of presenting the plant response to an accident.

These can be used to define the primary success paths.

A safety sequence analysis is a systematic examination of the actions required to mitigate the consequences of events considered in the plant's Design Basis Accident and Transient analyses, as presented in Chapters 6 and 15 of the plant's FSAR (or equivalent - chapters). Such a safety

() sequence analysis considers all applicable events, whether explicitly or implicitly presented. The primary success path of a safety sequence analysis consists of the combination and sequences of equipment needed to operate (including consideration of the single failure criteria), so that the plant response to Design Basis Accidents and Transients limits the consequences of these events to within the appropriate acceptance criteria.

It is the intent of this criterion to capture into Technical Specifica-tions only those structures, systems, and components that are part of the primary success path of a safety sequence analysis. Also captured by this criterion are those support and actuation systems that are necessary for items in the primary success path to successfully function. 'lhe primary success path for a particular mode of operation does not include backup and diverse equipment (e.g., rod withdrawal block which is a backup to the average power range monitor high Flux Trip in the startup mode, safety O

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Discussion of Criterion 3: (continued) I O

v valves which are backup to low temperature overpressure relief valves during cold shutdown).

Criterion 4: A structure, system, or component which operating experience or probabilistic safety assessment has shown to be significant to public )

health and safety-I Discussion of Criterion 4: It is the Commission policy that licensees retain in their Technical Specifications LCOs, actions statements, and

Surveillance Requirements for the following systems (as applicable), which operating experience and [probabilistic safety assessment (PSA)] PSA have generally shown to be significant to public health and safety and any -

other-structures, systems, or components that meet this criterion: I

Reactor Core Isolation Cooling /Jsolation Condenser, '

Residual Heat Removal,

Standby Liquid Control, and

Recirculation Pump Trip.

The Commission recognizes that'other structures, systems, or components ,

may meet this criterion. Plant- and design-specific PSAs have yielded valuable insight to unique plant vulnerabilities not fully recognized in the safety analysis report Design Basis Accident or Transient analyses.

It is the intent of this criterion that those requirements that PSA or !

operating experience exposes as significant to public health and safety, consistent with the Commission's Safety Goal and Severe Accident Policies, j be retained or included in Technical Specifications.

The Commission expects that licensees, in preparing their Technical Specification related submittals, will utilize any plant-specific PSA or risk survey and any available literature on risk insights and PSAs. This material should be employed to strengthen the technical bases for those requirements that remain in Technical Specifications, when applicable, and O

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Discussion of Criterion 4: (continued)-

to verify that none of the requirements to be relocated contain con-straints of prime importance in limiting the likelihood or severity of the -

accident sequences that are commonly found to dominate risk. Similarly, the NP.C staff will also employ risk insights and PSAs in evaluating Technical Specifications related submittals. Further, as a part of the Commission's ongoing program of improving Technical Specifications, it will continue to ~ consider methods to make better use of risk and reliability information for defining future generic Technical Specifica-tion requirements.

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3. Pl.0BABILISITIC RISK ASSESSMENT INSIGHTS Introductjpn and Ob.iectives .

The Final Policy Statement includes a statement that NRC expects licensees to utilize the available literature on risk insights to verify that none of the :

requirements to be relocated contain constraints of prime importance in limiting !

I the likelihood or severity of the accident sequences that are commonly found to l dominate risk.

l Those Technical Specifications proposed for relocation to other plant controlled documents will be maintained under the 10 CFR 50.59, safety evaluation review l program. These Specifications have been compared to a variety of Probabilistic Risk Assessment (PRA) material with two purposes: 1) to identify if a component or variable is addressed by PRA, and 2) to judge if the component or variable is l

risk-important. In addition, in some cases risk was judged independent of any specific PRA material. The intent of the review was to provide a supplemental screen to the deterministic criteria. Those Technical Specifications proposed to remain a part of the Improved Technical Specifications were not reviewed. '

This review was accomplished in Reference 1, except where discussed in Appendix A, " Justification For Specification Relocation", and has been confirmed by GPC for those Specifications to be relocated. Where Reference 1 did not review a Technical Specification against the criteria of Reference 2, GPC performed a review similar (but not identical) to that described below for Reference 1. The '

results of these reviews are presented in Appendix B.

Assumptions and Acoroach Briefly, the approach used in Reference 1 was the following:

The risk assessment analysis evaluated the loss of function of the system or component whose LC0 was being considered for relocation and qualita-tively assessed the associated effect on core damage frequency and offsite releases. The assessment was based on available literature on plant risk insights and PRAs. Table 3-1 lists the PRAs used for making the assess-3-1

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- ments. A detailed quantitative calculation of the core damage and offsite j (j release effects was not performed. However, the analysis did provide an indication of the relative significance of those LCOs proposed for relocation on the likelihood or severity of the accident sequences that j are commonly found to dominate plant safety risks. The following analysis j steps were performed for each LC0 proposed for relocation: ;

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a. List the function (s) affected by removal of the LCO item. l

b. Determine the effect of loss of the LC0 item on the function (s). I

c. Identify compensating provisions, redundancy, and backups related to the loss of the LC0 item.

d. Determine the relative frequency (high, medium, and low) of the loss of the function (s) assuming the LC0 item is removed from Technical Specifications and controlled by other procedures or programs. Use information from current PRAs and related analyses to establish the h,, relative frequency.

e. Determine the relative significance (high, medium, and low) of the loss of the function (s). Use information from current PRAs and related analyses to establish the relative significance.

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f. Apply risk cat'egory criteria to establish the potential risk significance or non-significance of the LC0 item. Risk categories l were defined as follows:

RISK CRITERIA Conseauence Freauency liLqh Medium Lqw l

High S S NS t Medium S S NS Low NS NS NS ,

i S = Potential Significant Risk Contributor-NS = Risk Non-Significant .-

g. List any comments or caveats that apply to the above assessment. '

The output from the above evaluation was a list of LCOs proposed for ,

relocation that could have potential plant safety risk significance if not properly controlled by other procedures or programs. As a result these Specifications will be relocated to other plant controlled documents outside the Technical Specifications.

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,- 3 TABLE 3-1

() BWR PRAs USED IN NEDO 31466 (AND SUPPLEMENT 1)

RISK ASSESSMENT

BWR/6 Standard Plant, GESSAR II, 238 Nuclear Island, BWR/6 Standard Plant Probabilistic Risk Assessment, Docket No. STN 50-447, March 1982.

La Salle County Station, NED0-31085, Probabilistic Safety Analysis, February 1988.

Grand Gulf Nuclear Station, IDCOR, Technical Report 86.2GG, Verification of IPE for Grand Gulf, March 1987.

Limerick, Docket Nos. 50-352, 50-353, 1981, "Probabilistic Risk Assess-ment, Limerick Generating Station", Philadelphia Electric Company.

Shoreham, Probabilistic Risk Assessment Shoreham Nuclear Power Station,

g. Long Island Lighting Company, SAI-372-83-PA-01, June 24,1983.

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Peach Bottom 2, NUREG-75/0104, " Reactor Safety Study", WASH-1400, October 1975.

Millstone Point 1, NUREG/CR-3085, " Interim Reliability Evaluation Program:

Analysis of the Millstone Point Unit 2 Nuclear Power Plant", January 1983.

Grand Gulf, NUREG/CR-1659, " Reactor Safety Study Methodology Applications Program: Grand Gulf #1 BWR Power Plant", October 1981.

NEDC-30936P, "BWR Owners' Group Technical Specification Improvement Methodology (with Demonstration for BWR ECCS Activation Instrumentation)

Part 2", June 1987.

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4. RESULTS OF APPLICATION OF SELECTION CRITERIA The selection criteria from Section 2 were applied to the Plant Hatch Unit 2 Technical Specifications. The attachment is a summary of that application indicating which Specifications are being retained or relocated. Discussions that document the rationale for tha relocation of each Specification which failed to meet the selection criteria are provided in Appendix A. No Significant i Hazards Determination (10 CFR 50.92) evaluations for those Specifications i

! relocated are provided with the Discussion of Changes for the specific Technical Specifications. GPC will relocate those Specifications identified as not satisfying the criteria to plant specific controlled documents whose changes are l governed by 10 CFR 50.59.

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5. REFERENCES

1. ' NED0-31466'(and Supplement 1), " Technical Specification Screening Criteria Application and Risk Assessment," November 1987.

2. NUREG 1433, -" Standard Technical Specifications, General Electric Plants BWR/4," September 1992.

3. NRC No.93-102 " Final Policy Statement on Technical Specification Improve-ments," July 23, 1993.

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O ATTACHMENT

SUMMARY

DISPOSITION MATRIX PLANT HATCH UNIT 2 O

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% %>l SLTH1.RY DISPOSITIC'7 MATRIX PLANT HATCH UNIT 2 Current Unit 2 New Unit 2 Retained / Criterion TS Number Title TS Number for Inclusion Bases for Inclusion / ExclusionI

N*I M DEFINITIONS M Yes See Note 1 and Note 4.

3.10.1 M SAFETY LIMITS M 2.1.1 THERMAL POWER (Low Pressure or Low Flow) 2.1.1.1 Yes See Note 2.

2.1.2 THERMAL POWER (High Pressure and High Flow) 2.1.1.2 Yes See Note 2.

2.1.3 Reactor Coolant System Pressure 2.1.2 Yes See Note 2.

2.1.4 Reactor vessel Water level 2.1.1.3 Yes See Note 2.

U LIMITING SAFETY SYSTEM SETTINGS 2.2.1 Reactor Protection System Instrumentation Setpoints 3.3.1.1 Yes The application of Technical Specification selection criterie is not appropriate. However, the RPS LSSS have been included as part of the RPS instrumentation Specifica-tion which has been retained since the Functions either actuate to mitigate consequences of design basis accidents and transients or are retained as directed by the NRC as the Functions are part of the RPS.

M LIMITING CONDITIONS FOR OPERATION - APPLICABILITY 3.0.1 Operational Conditions IIO 3.0.1 Yes See Note 3.

3.0.2 Noncompliance LCO 3.0.2 7es See Note 3.

3.0.3 Generic Actions LCO 3.0.3 Yes See Note 3.

3.0.4 Entry into Operational Conditions LCO 3.0.4 Yes See Note 3.

, 3.0.5 Operability Exception 3.8.1 Yes The application of Technical Specification selection criteria is not appropriate. However, this exception to the definition of OPERABILITY has been included as a part of Required Actions in LCO 3.8.1.

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m y f3 SutttARY DISPOSITION MATRIX PIANT HATCH UNIT 2 Current Unit 2 New Unit 2 Retained / Criterion TS Ntsaber Title TS Number for Inclusion Bases for Inclusion / ExclusionI

M SURVEILLANCE REQUIRDtEitTS - APPLICABILITY 4.0.1 Operational Conditions SR 3.0.1 Yes See Note 3.

4.0.2 Time of Perfomance SR 3.0.2 Yes See Note 3.

4.0.3 Nencompliance SR 3.0.3 Yes See Note 3.

4.0.4 Entry into Operational Conditions SR 3.0.4 Yes See Note 3.

4.0.5 A.9?E Code Class 1, 2, 3 Compc.nents 5.5.6 Yes See Note 3.

E REACTIVITY CONTROL SYSTEM 3 M 3/4.1.1 Shutdown Margin 3.1.1 Yes-2 Not a measured process viable, but is important an parame-ter used to confirts the acceptability of the accident analysis. In addition, the LCO is retained as directed by the NRC.

3/4.1.2 Reactivity Anomalies 3.1.2 Yes-2 Confi ms assumptions made in the reload safety analysis.

3/4.1.3 Control Rods 3/4.1.3.1 Control Rod Operability 3.1.3 Yes-3 Control rods are part of the primary success path in mitigating the consequences of design basis accidents (DBAs) and transients.

3/4.1.3.2 Control Rod Maximum Scram Insertion Times 3.1.3 Yes-3 Same as above.

3/4.1.3.3 Control Red Average Scram Insertion Times 3.1,4 Yes-3 Same as above.

3/4.1.3.4 Four Control Rod Group Scram Insertion Times 3.1.4 Yes-3 Same as above.

3/4.1.3.5 Control Rod Scram Accumulators 3.1.5 Yes-3 Same as above.

3.9.5 3/4.1.3.6 Control Rod Drive Coupling 3.1.3 Yes-3 Same as above.

3/4.1.3.7 Control Rod Position Indication 3.1.3 Yes-3 Same as above.

3.9.4 3/4.1.3.8 Control Rod Drive Bousing Support Deleted No See CRD Bousing Support System technical change discussion.

3/4.1.4 Control Rod Program Controls 3/4.1.4.1 Rod Worth Minimizer 3.3.2.1.2 Yes-3 Prevents withdrawal of control rods outside BEWS con-straints that might set-up high rod worth conditions beyon.1 CRDA assumptions.

3/4.1.4.2 Deleted in Amenchnent No. 121 Page 2 of 14

SMt%RY DISPOSITION MAIRIX PLANT HATCH UNIT 2 i Curren' at 2 New Unit 2 Retained /Crfterion TS Numba. Title TS Number for Inclusion Bases for Inclusion / Exclusion I "N*I 4

3/4.1.4.3 Rod Block Monitor 3.3.2.1.1 Yes-3 Prevents continuous withdrawal of a high worth control rod -

that could challenge the MCPR Safety Limit.

3/4.1.$ Standby Liquid Control System 3.1.7 Yes-4 Being retained is accordance with the NRC Final Policy Statement on Technical Specification Improvements due to risk significance.

3/4.1.6 Scram Discharge Voltano Vent and Drain Valves 3.1.8 Yes-3 Contributes to the operability of the control rod scram function.

None Rod Pattern Control 3.1.6 Yes-3 Assures initial conditions for the CRDA analysis are main- ,

tained, i a

E POWER DISTRIBUTION LIMITS 'M 3/4.2.1 Average Planar Linear Beat Generation Rate 3.2.1 Yes-2 Peak cladding temperature following a LOCA is primarily dependent on initial APLHGR As such it is au initial ,

condition of a DBA analysis.

f 3/4.2.2 Deleted in Amendment No. 39 3/4.2.3 Minirans Critical Power Ratio 3.2.2 Yes-2 Utilized as an initial condition of ' the design basis transients.. Transient analysis are perfonned to establish the largest reduction in Critical Power Retto. Thfa value is added to the fuel cladding int *Srity safety limit to determine the MCPR value.

! 3/4 2.4 Linear Heat Generation Rate Deleted No . Deleted. See technical change discussion for LHGR.

i 3/4.3(b) INSTRUMENTATION M

3/4.3.1 Reactor Protection System Instrumentation 3.3.1.1 Yes-3 Retained as directed by the NRC as it is part of the RPS.

I or it actuates to mitigate consequences of a DBA and/or transients, or it provides an anticipatcry scram to ensure the scram discharge voltane and thus F/S rsmains operable.

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V SL991ARY DISPOSITION MATRIX PLANT BATCH UNIT 2 Current Unit 2 New Unit 2 Retained / Criterion TS Ntanber Title TS Number for Inclusion Bases for Inclusion / ExclusionI *3ICI 3/4.3.2 1 solation Actaation Instrumentation 3.3.6.1 Yes-3.4 Actuates to mitigate the consequences of a DBA 1DCA, or 3.3.6.2 actuates to mitigate the consequences of a DBA LOCA release to the enviraranent and a fuel handling accident, or actu-atos to isolate potential leakage paths to secondary conteirunent consistent with safety analysis asstemptions, or is retained due to risk significance, or la retained due to importance of RHR system and risk significance.

3/4.3.2.1.c.1 Main Stearn Line Radiation - High Deleted No Deleted. See Primary Contairment Isolation Instrumentatior technical change discussion for MSLRM.

3/4.3.2.4.J Lvgic Power Monitor Deleted No Deleted. See Primary Containment Isolation Instrumentation technical change discussion.

3/4.3.2.5.1 Logic Power Monitor Deleted No Deleted. See Primary Contairment Isolation Instrsamentation technical change discussion.

3/4.3.3 Emergency Cot s Cooling Systern Actuation 3.3.5.1 Yes-3.4 ECCS mitigate the consequences of a DBA 'OCA, or is being Instrumentation roteined due to risk significance, or functions to mitigate the consequences of a small break LOCA, or a minismsa ntamber a

of S/RVs is assumed to function in the contaitument loading safety analysis.

! 3/4.3.3.1.d Logic Power Monitor Deleted No Deleted. See ECCF Instriseentation technical change discus-sion.

+ 3/4.3.3.2.s Logic Power Monitor Deleted No Deleted. See ECCS Instrumentation technical change discus-sien.

3/4.3.3.3.e Logic Power thitor Deleted No Deleted. See ECCS Instrinnentation technical change discus-sion.

I 3/4.3.3.4.h Control Power Monitor Deleted No Deleted. See ECCS instriseentation technical change discus-sion.

a l 3/4.3.4 Reactor Core Isolation Cooling System Actuation 3.1.5.2 Yes-4 Retained in accordance with the NRC Pinal Policy State-Instrinnentation ment on Technical SpecifJcation Improvements due to risk significance.

3/4 3.5 Control Rod Withdrawal Block Instruments *i,n 3.3.2.1

' 3/4.3.5.1 APRM Relocated- No See Appendix A. Page 1.

3/4.3.5.2 Rod Block Monitor 3.3.2.1.1 Yes-3 Prevents continuous withdrawal of a high worth control rod that could challenge the ICPR Safety Limit.

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SUP91ARY DISPOSITION MATRIX PLANT HATCH UNIT 2 Current Unit 2 New Unit 2 Retained / Criterion TS Mtsaber Title TS Number for Inclusion 5ases for Inclusion / ExclusionI " NCI t

1/4.3.5.3 Source Range Monitors Relocated No See Appendix A Page 2.

3/4.3.5.4 Intermediate Range Monitors Relocated No See Appendix A. Page 3.

3/4.3.5.5 Screm Direharge volume Relocated No See Appendix A. Page 4 a

3/4.3.6 Monitoring Instrumentation 3/4.3.6.1 Radiation Monitoring Instrumentation j 3/4.3.6.1.1 Off-Gas Post Treatment Monitors Relocated No See Appendix A. Page 5.

3/4.3.6.1.2 Control Reem Intake Monitors 3.3.7.1 Yes-3 Actuates to maintain control room habitability so that operation can continue from the control room follcwing DBAs.

3/4.3.6.2 Seismic Monitoring Instrumentation Relocated No See Appendix A, Page 6.

3/4.3.6.3 Remote Shutdown Monitoring Instrumentation 3.3.3.2 Yes-4 Retained as directed by the NRC as it is e significant f contributor to risk reduction.

I 3/4.3.6.4 Post-Accident Monitoring Instrumentation 3.3.3.1 Yes-3 RG 1.97 Type A ' and Category 1 variables retained. See Appendix A. Page 7 for full discussion of all variables.

, 3/4.3.6.5 Source Range Monitors 3.3.1.2 Yes Does not satisfy the selection criteria, however is being retained because the NRC considers it necessary for flux monitoring during shutdown, startup and refueling opera-tions.

3/4.3.6.6 Traversing Incore Probe System Relocated No See Appendix A. Page 9.

3/4.3.6.7 FCRECS Actuation Instrumentation 3.3.7.1 3/4.3.6.7.1 Reactor vessel Water Level - Low Low Low (Level 1) Relocated No See Appendix A, Page 10.

3/4.3.6.7.2 Drywell Pressure - High Relocated No Same as above.

3/4.3.6.7.4 Main Steam Line Flow - High Relocated No Some as above.

l 3/4.3.6.7.5 Refueling Floor Area Radiation - High -Relocated No Same as above.

, 3/4.3.6.7.6 Control Room Air Inlet Radiation - High 3.3.7.1 Yes-3 Actuates to maintain control room habitability so that operation can continue from the control room following DBAs.

3/4.3.6.8 Deleted in Amendment No. 70 3/4.3.6.9' Removed in Admentment No. 129 i

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SL9t8.ARY DISFOSITION MATRIX PLANT HATCH UNIT 2 Current Unit 2 New Unit 2 Roteined/ Criterion TS Number Title TS Neber for Inclusion Bases for Inclusion / ExclusionI " M*I 3/4.3.6.10 Erplosive Gas Monitoring Instrinnentation Relocated No See Appendix A. Page 11.

3/4.3.7 Turbine Overspeed Protection System Relocated No See Appendix A. Pese 12.

3/4.3.8 Degraded Station Voltsgo Protection Instrumentation 3.3.8.1 3/4.3.8.1 4.16kv Emergency Bus Undervoltage Relay 3.3.0.1 Yes-3 Actuates DGs to mitigate consequences of a loss of offsite (Loss of Voltags Condition) power event.

3/4.3.8.2 4.16kv Emergency Bus Undervoltage Relay Deleted No Deleted. See LOP Instrumentation technical charge (Degraded Voltage Condition) discussion.

3/4.3.9 Recirculation Pump Trip Actuation Instrurnentation 3/4.3.9.1 AIWS Recirculation Ptunp Trip System Instrumentation 3.3.4.2 Yes-4 AIWS-RPT is being retained in accordance with the NRC Final Policy Statement on Technical Specification Improvements due to risk significance.

3/4.3.9.2 End of-Cycle Recirculation Pump Trip System 3.3.4.1 Yes-3 EOC-RPT aids t.he reactor scram in protecting fuel cladding Instrumentation integrity by ensuring the fuel cladding integrity safety limit is not exceeded during a load rejection or turbine trip transient.

None Feedwater and Main Turbine Trip Instrumentation 3.3.2.2 Yes-3 Acts to limit feedwater addition to the reactor vessel on feedwater controller f ailure consistent with safety analy-sis assumptions. Limits neutron flux peak and thermal transient to avoid fuel damage.

3/4.4 REACTOR COOLANT SYSTEM L4 3/4.4.1 Recirculation System 3/4.4.1.1 Recirculation Loops 3.4.1 Yes-2 Recirculation loop flow is en initial condition in the safety enelysis.

i 3/4.4.1.2 Jet Pumps 3.4,2 Yes-3 Jet pump operability is esstuned in the LOCA analyses to assure adequate core reflood capability.

3/4.4.1.3 Idle Recirculation Loop Startup 3.4.9 Yes-2 Establishes initial conditions to opetetton such that operation la prohibited in areas or et temperature rate changes that might cause undetected flaws to propagate, in turn challenging the rese:.or coolant pressure boundary

integrity.

3/4 4 2 Safety /Reli." va lves 3/4.4.2.1 Safety / Relief Velve. 3.3.6.3 Yes-3 A minimum ntsaber of S/RVs is asstuned in the safety analyses 3.4.3 to mitigate overpressure events.

4 3/4.4.2.2 S/RV Low-Low Set Function 3.3.6.3 Yes-3 A minimura number of 5/KVs is assumed in the containment loading safety analysis.

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! St99%RY DISPOSITION NATRIX PLANT HATCH UNIT 2 Current Unit 2 New Unit 2 Retained / Criterion TS Mumber Title TS Number for Inclusion Bases for Inclusion / Exclusion I* MCI i

3/4.4.3 Reactor Coolant System Leakage 3/4.4.3.1 Leakase Detection System 3.4.5 Yes-1 Leak detection is used to indicate an abnormal condition of the reactor coolant pressure boundary.

3/4.4.3.2 Operational Leekage 3.4.4 Yes-1 Leakage beyond limits would indicate an abnonsal condition of the reactor coolant pressure boundary. Operation is this condition may result in reactor coolant pressure boundary failure.

3/4.4.4 Chemistry Relocated No See Appendix A, Page 13.

3/4.4.5 Specific Activity 3.4.6 Yes-2 Specific activity provides an indication of the onset of

significant fuel cladding failure end is an initial condi-

< tion for evaluation (radiological calculations) of the consequences of an accident due to main steam line break outside conteirunent.

3/4.4.6 Pressure / Temperature Limits

. 3/4.4.6.1 Reactor Coolant System 3.4.9 .Yes-2 Establishes initial conditions to operation such that operation is prohibited in. areas or at temperature rate i changes that might cause undetected flows to propagate in turn challenging the reactor coolant pressure boundary integrity.

! 3/4.4.6.2 Reactor Steam Dome 3.4.10 Yes-3 Reactor steam dame pressure is an initial condit'on in the j reactor vessel overpressure safety analysis.

3/4.4.7 Main Steam Line Isolation Valves 3.6.1.3 Yes-3 Main steam line isolation within specified time limits

! ensures the release to the environment is consistent with the asstssptions in the LOCA analysis.

3/4.4.8 Structural Integrity Relocated No See Appendix A, Page 14 None Residual Beat Removal - Hot shutdown 3.4.7 Yes-4 Added in accordance with the NRC Interim Policy Statement on Technical Specification Improvements due to risk signif-icance.

d None Residual Heat Removal - Cold Shutdown 3.4.8 Yes-4 Same as above.

!' E EMERGENCY CORE COOLING SYSTENS M 3/4.5.1 High Pressure Coolant Injectior System 3.5.1 Yes-4 While not assumed in a licensing basis accident analysis, i HICI is considered risk significant since it functions to mitigate the consequences of small break LOCAs.

3/4.5.2 Automatic Depressutization System 3.5.1 Yes-3 Functions ' to mitigate the consequences of small break LOCAs.

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D SLTHARY DISPOSITION FATRIX PLANT HAICH UNIT 2 Current Unit 2 New Unit 2 Retained / Criterion TS Number Title TS Number for Inclusion Bases for Inclusion / Exclusion I *II*I 3/4.5.3 Low Pressure Core Cooling Systems 3/4.5.3.1 Core Spray System 3.5.1 Yes-3 Functions to mitigate the consequences of a DBA and a 3.5.2 vessel draindown event.

3/4.5.3.2 Low Pressure Coolant Injection System 3.5.1 Yes-3 Same as above.

3.5.2 3/4.5.4 Suppression Chamber 3.5.1 Yes-3 Same as above.

3.5.2 3.6.2.2 3/4.6 CONTAINMENT SYSTD15 M 3/4.6.1 Primary Containment 3/4.6.1.1 Primary Containment Int *grity 3.6.1.1 Yes-3 Primary containment integrity functions to mitigate the consequences of a DBA.

3/4.6.1.2 Primary Containrnent Leakage 3.6.1.1 Yes-3 Contairunent leakage is an assumption utilised in the LOCA 3.6.1.2 safety analysis (but it is not a process variable). Therefore, 3.6.1.3 it is being retained to ensure Primary Containment Operability.

3/4.6.1.3 Primary Containment Air Lock 3.6.1.2 Yes-3 Credit for air tightness is considered in safety analysis to limit offsite dose rates during a DBA.

3/4.6.1.4 NSIV Leakage Control System None No Deleted. See MSIV-1ES technical change discussion.

3/4.6.1.5 Primary Containment Structural Integrity 3.6.1.1 Yes-3 Primary containment functions to mitigate the consequences of a DBA.

3/4.6.1.6 Primary Contairunent Internal Pressure 3.6.1.4 Yes*2 Primary containment pressure is an initini condition in the LOCA safety analysis.

l 3/4.6.1.7 Drywell Average Air Temperature 3.6.1.5 Yes-2 Drywell air temperature is an initial condition in the LOCA safety analysis.

3/4.6.2 Depressurization Systems 3/4.6.2.1 Suppression Chamber 3.6.2.1 Yes-2 & 3 Suppression pool water level and temperature are initial 3.6.2.2 conditions in the DBA LOCA analysis and mitigate the conse-t quences of the DBA.

3/4.6.2.2 Suppression Pool Cooling 3.6.2.3 Yes-3 Suppression pool cooling functions to limit the effects of a DBA.

Page 5 of 14

SIM %RY DISPOSITION MATRIX PLANT BATCH UNIT 2 Current Unit 2 New Unit 2 Retained / Criterion TS Number Title TS Ntsaber for Inclusion Bases for Inclusion / Exclusion (a Mc)

None Suppression Pool Spray 3.6.2.4 Yes-3 Suppression pool spray functions to limit the effects of a !

DBA.

3/4.6.3 Primary Containment Isolation valves 3.6.1.3 Yes-3 Isolation valves function to limit DBA consequences.

3/4.6.6 Vacuum Relief i 3/4.6.4.1 Suppression Chamber-Drywell Vacutus Breakers 3.6.1.8 Yes-3 Suppression chenber - drywell vacusas breaker operation is ,

assumed in the LOCA analysis to limit drywell pressure i thereby ensuring primary containment integrity.

3/4.6.4.2 Reactor Building - Suppression Chamber Vacuum 3.6.1.7 Yes-3 Reactor building - suppression chamber vacuum breaker Breakers operation is relied on to limit negative pressure differen-tial, secondary to primary contairument, that could challenge primary conteirament integrity.

3/4.6.5 Secondary Containment 3/4.6.5.1 Secondary Contairunent Integrity 3.6.4.1 Yes-3 Secondary contairunent integrity is relied on to limit the 3.6.4.2 offsite dose during an accident by ensuring a release to containment is delayed and treated prior to release to the

, envirormnent.

3 i 3/4.6.5.2 Secondary Containment Automatic 3.6.4.4 Yes-3 Valve operation within time limits establishes secondary - !

Isolation Dampers 3.6.4.5 contairunent and limits offsite dose releases to acceptable l l values.

3/4.6.6 Contairunent Atanosphere Control ,

3/4.6.6.1 Standby Gas Treatment System 3.3.6.2 Yes-3 SGT operation following a DBA acts to mitigate the ,

3.6.4.7 consequences of offsite releases. !

3.6.4.8 i

3/4.6.6.2 Primary Contairunent Hydrogen Recombiner Systems 3.6.3.1 Yes-3 Operates, post LOCA, to limit hydrogen and oxygen concen-

trations to below explosive concentrations that might otherwise challenge conteirunent integrity.

I 3/4.6.6.3 Primary Contairunent flydrogen Mixing System 3.6.3.3 Yes-3 Same as above.

! 3/4.6.6.4 Primary conteirument Drygon Concentration 3.6.3.2 Yes-4 Oxygen concentration is -limited such that when combined with hydrogen that is postulated to evolve following a LOCA

, the total explosive gas concentration remains below explo-g sive levels. Therefore, contairunent integrity is main- t' t

tained.

i 3/4.6.6.5 Primary Contairunent Purge System

3/4.6.6.5.1 Primary Contairunent Purge Valves 3.6.1.3 Yes-3 Isolation valves function to limit DBA consequences. ,

3/4.6.6.5.2 Primary Contairunent Fast Acting Dampers 3.6.1.3 Yes-3 Sane as above. l d

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Page 9 of 14

A StM1ARY DISPOSITION MATRIX j PLANT HATCH tTNIT 2 Current Unit 2 New Unit 2 Retained / Criterion TS Number Title TS Number for Inclusion Bases for Inclusion / Exclusion (a)(c) l 3/4,7 FI. ANT SYSTDE 3 J. l 3/4.7.1 Service Water Systems 3/4.7.1.1 RHRSW System 3.7.1 Yes-3 Designed for heat removal from RER heat exchangera following a DBA. As such, acts to mitigate the consequences of an

accident.

3/4.7.1.2 Plant Service Water System 3.7.2 Yes-3 . Designed for heat removal from various safety related ,

3.7.3 systems following a DBA. As such, acts to mitigate the 5 consequences of an accident.

3/4.7.2 Main Control Room Envirorsnental Control System 3.7.4 Yes-3 Maintains habitability of the control room no that opere- i 4

tors can remain in the control room following en accident.

As such, it mitigates the consequences of an accident by allocing erretors to continue accident mitigation activi- !

ties from the control room.

None Main Control Room Air Conditioning System 3.7.5 Yes-3 Ensures cwtrol room temperature is maintained such that control roas safety related equissnent remains operable l following m accident. As such, functions to mitigate the consequences of an accident.

I 3/4.7.3 Reactor Core Isolation Cooling System 3.5.3 Yes-4 Retained in accordance with the NRC Final Policy Statement l

. on Technical Specification Improvements due to risk signif-

! icance.

3/4.7.4 Snubbers Deleted No Deleted. See technical change discussion for Snubbers.

3/4.7.5 Sealed Source Contamination Relocated No See Appendix A,'Page 15.

, None Main Turbine Bypass System 3.7.7 Yes-3 Acts to mitigate the consequences of a feedwater controller

! f ailure - maxisman demand transient and a turbine trip with

! bypass event, i

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, 3/4,8 ELECTRICAL POWER SYSTEMS 3 ,8 >

i

3/4.8.1 A.C. Sources j 3/4.8.1.1 A.C. Sources - Operating 3.8.1 Yes-3 Required to mitigate the consequences of a DBA. .

l 3.8.3 !

3.8.4 !

3 3.8.6 ;

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, Page 10 of 14 >

l

. m . .. - . - - _ . .mm . . _mm ~ . . -. . . . . .._ . . . - . . ., ... .- , -. _ ~ - _ m.m--- ..,. - _ _ . . - . _ _ . .-. _ . - > .. - . .-~ m - - ....s-i St# NARY DISPOSITION MATRIX PLANT HATCH UNIT 2 4

Current Unit 2 New Unit 2 Retained / Criterion TS Number Title TS Number for Inclusion Bases for Inclusion / Exclusion (aMc) 3/4.8.1.2 A.C. Sources - Shutdown 3.8.2 Yes-3 Functions to mitigate the consequences of a vessel drain-3.8.3 down event and is needed to support NRC Final Policy 3.8.5 Statement requirement for decay heat removal.

3.8.6 3/4.8.2 Onsite Power Distribution Systems r

3/4.8,2.1 A.C. Distribution - Operating 3.8.7 Yes-3 Required to mitigate the consequences of a DBA.

3/4.8.2.2 A.C. Distribution - Shutdown ? 3.8 Yes-3 Functions to mitigate the consequences of a vessel draind-own event and is being retained to support the NRC Final ,

1 Policy Statement requirement for decay heat removal.

3/4.8.2.3 D.C. Distribution - Operating 3.8.4 Yes-3 Required to mitigate the consequences of a DBA. ;

3.8.6 3.8.7 3/4.8.2.4 D.C. Distribution - Shutdown 3.8.5 Yes-3 Functions to mitigate the consegaences of a vessel drain i 3.8.6 down event and is being retained to support the NRC Final-3.8.8 Policy statement requirement for decay heat removal.

3/4.8.2.5 A.C. Circuits Inside Primary Containment Relocated No See Appendix A, Page 16.

3/4.8.2.6 Primary Containment Penetration Conductor Relocated No See Appendix A. Page 17.

Overcurrent Protective Devices l 4

1 3/4.8.2.7 Electric Power Monitoring for 3.3.8.2 Yes-3 Provides protection for the RPS bus powered instrtsmentation l Reacte Protection system against unacceptable voltage and frequency conditions that '

could degrade the instrumentation so that it would not perform the intended safety function.

344.d REFUELING CPERATIONS 39 l 3/4.9.1 Reactor Mode Switch 3.9.1 Yes-3 Provides an interlock to preclude fuel loading with control 3.9.2 rods withdrawn. Operation is assumed in the control rod

removal error during refueling and fuel assembly insertion j error during refueling accident analysis.

3/4.9.2 Instrumentation 3.3.1.2 Tes Does not satisfy selection criteria but is retained because the NRC considere it necessary for flux monitoring during shutdown, sterw;. and refueling operations.

3/4.9.3 Control Rod Position 3.9.3 Yes-2 All control rods are required to be fully inserted when

! loading fuel. This requirement is assumed as an initial condition in the fuel assembly insertion error during !

j refueling accident analysis.

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m St99%RY DISPOSITION MATRIX PLANT HATCH UNIT 2 Current Unit 2 New Unit 2 Retained / Criterion TS Ntunber Title TS Ntznber for Inclusion Bases for Inclusion / Exclusion I* NC) 3/4.9.4 Decey Time Relocated No Although this LCD satisfied criterion 2, the activities necessary prior to conunencing movement of irradiated fuel ensure that there will always be 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months of subcriticality before movement of any irradiated fuel. Eence this Speci-fication has been relocated.

3/4.9.5 Secondary Containment 3/4.9.5.1 Refueling Floor 3.6.4.3 Yes-3 Secondary contairunent integrity is relied on to limit the offsite dose during a fuel handling accident by ensuring the release to contairunent is delayed and treated prior to release to the envirorrnent.

3/4.9.5.2 Secondary Containment Automatic Isolation Dampers 3.6.4.6 Yes-3 Valve operation within time limits establishes secondary conteirament and limits offsite dose releases to acceptable values.

3/4.9.5.3 Standby Gas Treatment System 3.6.4.9 Yes-3 Operation following a fuel handling accident acts to mitigate the consequences of offsite releases.

3/4.9.6 Cormnunic ations Relocated No See Appendix A, Page 19.

3/4.9.7 Crane and Holst Operability Relocated No See Appendia A, Page 20.

3/4.9.8 Crane Travel - Spent Fuel Storage Pool Relocated No See Appendir A Page 21.

3/4.9.9 Water Level - Reactor Vessel 3.9.6 Yes-2 A mintaman amount of water is required to assure adequate scrubbing of fission products following a fuel handling accident.

3/4.9.10 Water Level - Spent Fuel Storage Pool 3.7.8 Yes-2 Same as above.

3/4.9.11 Control Rod Removal 3/4.9.11.1 Single Control Rod Removal 3.10.5 Yes See Note 4 3/4.9.11.2 Multiple Control Rod Removal 3.10.6 Yes See Note 4.

3/4.9.12 Reactor Coolant Circulation 3.9.7 Yes Does not satisfy the selection criteria, however is being 3.9.8 retained in accordance with the NRC Final Policy Statement on Technical Specification Improvements.

3/4.10 SPECIAL TEST EX3FTIONS M 3/4.10.1 Primary Contairunent Integrity Deleted No The latitude of this Special Test Exception is not required at Batch Unit 2.

3/4.10.2 Rod Worth Minimizer 3.10.7 Yes See Note 4 3/4.10.3 Shutdown Margin Demonstrations 3.10.8 Yes See Note 4 Page 12 of 14

SLTttARY DISPOSITION MATRIX PLANT HATCH UNIT 2 l l

l Current Unit 2 New Unit 2 Retained / Criterion .

TS Number Title TS Number for Inclusion Bones for Inclusion / Exclusion (aMc) l 3/4.10.4 Recirculation Loops Deleted No The latitude of this Special Test Exception in not required at Hatch Unit 2.

3/4.10.5 Single Control Rod Withdrawal - Cold Shutdown 3.10.4 Yes See Note 4 None Reactor Mode Switch Interlock Testing 3.10.2 Yes See Note 4 Mene Single Control Rod Withdrawal - Hot Shutdown 3.10.3 Yes See Note 4 3/4.11 RADIOACTIVE EFFLUENTS h 3/4.11.1 Liquid Effluents 3/4.11.1.1- Removed in Admentment No. 129 3/4.11.1.3 3/4.11.1.4 Liquid Holdup Tanks 5.5.8 Yes Although this Specification does not meet any Criteria of l

the NRC Final Policy Stateswnt, it has been retained in I

accordance with the NRC letter frcus W.T. Russell to the 3/4.11.2 Gaseous Effluents k 3/4.11.2.1- Removed in Admentment No. 129 3/4.11.2.5 3/4.11.2.6 Explosive Gas Mixture 5.5.8 Yes Same as above.

3/4.11.2.7 Main Condenser 3.7.6 Yes-2 Main condenser offges activity is an initial condition in the offgas system failure event analysis.

3/4.11.3 Removed in Admentment No. 129 3/4,12 Removed in Admentment No. 129 I

M DESIGN FEATURES M Yes See Note 5.

I l

M ADMINISTRATIVE CONTROLS M Yes See Note 6.

Page 13 of 14 I

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i SL991ARY DISPOSITICrt NATRIX -

FLANT HATCH UNIT 2 NOTTS; DEFINITIONS i NOTE 1.

This section providea definitions for several defined terms used throughout the remainder of Technical Specifications. They are provided to improve the meaning of certain terms. As such, direct application of the Technical Specification selection criteria is not oppropriate. However, only those definitions for defined terms that remain as a result of application of the selection criteria, will remain as definitions in this section of Technical Specifications.

NOTE 2; SAFETT LIMITS /LSSS Application of Technical Specifications selection criteria is not appropriate. However, Safety Limits and Limiting Safety System Settings (as part of Reactor Protection System Instrumentation) will be included in Technical Specifications as required by 10 CFR 53.36. ;

i NOT5 3- 3,0/4,0 These Specifications provide generic guidance applicable to one or more Specifications. The information is provided to facilitate understanding of Limiting i Conditions for Operation and Surveillance Requirements. As such, direct application of the Technical Specification selection criteria is not appropriate.

However, the general requirements of Plant Hatch Unit 2 Technical Specifications 3.0/4.0 will be modified consistent with NUPEG 1433.

, NOTE 4; SPECIAL TEST EXCEPTIONS These Specifications are provided to allow relaxation of certain Limiting Conditions for Operation under certain specific conditions to allow testing and maintenance. They are directly related to one or more Limiting Conditions for Operations. Direct application of the Technical Specification selection criteria is not appropriate. However, those special test exceptions, directly tied to - Limiting Conditions for Operation that remain in Technical Specifications, will also remain as Technical Specifications. Those special test exceptions not applicable to Plant Batch Unit 2 have been deleted.

4 NOTE $, DESIGN FEATURES ;

Application of Technical Specification selection criteria is not appropriate. Bowever, Design Features will be included in Technical Specifications as '

required by 10 CFR 50.36. -

NOTE 6; ADMINISTRATIVE CONTROLS i

Application of Technical Speciff ::ation selection criteria is not appropriate. However, Acheinistrative Controls will be included in Techni al Specifications I as required by 10 CFR 50.36.

i P

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a. Where a current Technical Specification is referred to as being deleted, the technical change discussion is found in the Discussion of Changes associated with the l markup of the current Specification.

b. For current Technical Specification 3/4.3 Instrumentation, the Current Technical Specification number consists of . the Specification number followed by the

^

instrumentation channel number from the associated 3.3.x Table. For example, the Main Steam Line Radiation-Bigh channel for the RPS is numbered 3/4.3.1.6, where

=3/4.3.1* is the Specification number and the last =6= is the functional unit number for the IRM channels in Table 3.3.1-1.

a

c. The applicable accident analyses are discussed in the Bases for the individual Technical Specification.

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b APPENDIX A f JUSTIFICATION FOR

, SPECIFICATION RELOCATION l 4

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- - - . .e e ._m ,, _ _ _ ____a---- - _ _

APPENDIX A

(]

V 3/4.3.5 CONTROL R0D WITHDRAWAL BLOCK INSTRUMENTATION LC0 Statement:

The control rod withdrawal block instrumentation shown in Table 3.3.5-1 shall be OPERABLE with their trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3.5-2.

3/4.3.5.1 APRM Discussion:

The Average Power Range Monitor (APRM) control rod block functions to prevent a control rod withdrawal error during power range operations utilizing LPRM signals to create the APRM rod block signal. APRMs provide information about the average core power and APRM rod blocks are not used to mitigate a DBA or transient.

Comparison to Screenino Criteria:

1. The APRM control rod block is not used for, nor capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary prior to a design basis accident (DBA).

! i

2. The APRM control rod block instrumentation is not used to monitor a process l (n) variable that is an initial condition of a D':,A or transient analyses. l

3. The APRM control rod block signal is not a part of a primary success path in the mitigation of a DBA or transient.

As discussed in Sections 3.5 and 6, and summarized in Table 4-1 (Item 135) of NED0-31466, the loss of the APRM control rod block function was found to be a i non-significant risk contributor to core damage frequency and offsite releases. l GPC has reviewed this evaluation and considers it applicable to Plant Hatch i Unit 2. l

Conclusion:

Since the screening criteria have not been satisfied, the Control Rod Block LCO and Surveillances applicable to APRM instrumentation may be relocated to other plant controlled documents outside the Technical Specification.

4 4

UNIT 2 A-1

APPENDIX A 3/4.3.5 CONTROL R00 WITHDRAWAL BLOCK INSTRUMENTATION LC0 Statement:

The control rod withdrawal block instrumentation shown in Table 3.3.5-1 shall be OPERABLE with their trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3.5-2.

3/4.3.5.3 Source Range Monitors Discussion:

The Source Range Monitor (SRM) control rod block functions to prevent a control rod withdrawal error during reactor startup utilizing SRM signals to create the rod block signal. SRM signals are used to monitor neutron flux during refueling, shutdown and startup conditions. No design basis accident or transient analysis takes credit for rod block signals initiated by the SRMs.

Comparison to Screenina Criteria:

1. The SRM control rod block is not used for, nor capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary prior to a design basis accident (DBA).

" 2. The SRM control rod block instrumentation is not used to monitor a process variable that is an initial condition of a DBA or transient analyses.

3. The SRM control rod block signal is not a part of a primary success path !

in the mitigation of a DBA or transient. l As discussed in Sections 3.5 and 6, and summarized in Table 4-1 (Item 137) of NED0-31466, the loss of the SRM control rod block function was found to be a non-significant risk contributor to core damage frequency and offsite releases. GPC has reviewed this evaluation and considers it applicable to Plant Hatch Unit 2.

Conclusion:

Since the screening criteria have not been satisfied, the Control Rod Block LCO and Surveillances applicable to SRM instrumentation may be relocated to other plant controlled documents outside the Technical Specifications.

k i

O UNIT 2 A-2

].*

APPENDIX A 3/4.3.5 CONTROL R0D WITHDRAWAL BLOCK INSTRUMENTATION LCO Statement:

The control rod withdrawal block instrumentation shown in Table 3.3.5-1 shall be OPERABLE with their trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3.5-2. ,

3/4.3.5.4 Intermediate Range Monitors ,

Discussion:

The IRM control rod block functions to prevent a control . rod withdrawal error during reactor startup utilizing IRM signals to create the rod block signal.

IRMs are provided to monitor the neutron flux levels during refueling, shutdown and startup conditions. No design basis accidents or transient analysis takes credit for rod block signals initiated by IRMs.

Comparison to Screenina Criteria:

1. The IRM control rod block is not used for, nor capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary prior to a design basis accident (DBA).

2. The IRM control rod block instrumentation is not used to monitor a process ;

variable that is an initial condition of a DBA or transient analyses. )

3. The IRM control rod block signal is not a part of a primary success path in the mitigation of a DBA or transient.

As discussed in Sections 3.5 and 6, and summarized in Table 4-1 (Item 138) of NED0-31466, the loss of the IRM control rod block function was found to be a non-significant risk contributor to core damage frequency and offsite releases. GPC has reviewed this evaluation and considers it applicable to Plant Hatch Unit 2.

Conclusion:

Since the screening criteria have not been satisfied, the Control Rod Block LC0 and Surveillances applicable to IRM instrumentation may be relocated to other plant controlled documents outside the Technical Specifications.

O UNIT 2 A-3 l

l APPENDIX A O(7 3/4.3.5 CONTROL R0D WITHDRAWAL BLOCK INSTRUMENTATION LC0 Statement:

The control rod withdrawal block instrumentation shown in Table 3.3.5-1 shall be OPERABLE with their trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3.5-2.

3/4.3.5.5 Scram Discharge Volume Discussion:

The SDV control rod block functions to prevent control rod withdrawals during power range operations, utilizing scram discharge volume (SDV) signals to create the rod block signal if water is accumulating in the SDV. The purpose of measuring the SDV water level is to ensure that there is sufficient volume to contain the water discharged by the control rod drives during a scram, thus ensuring that the control rods will be able to insert fully. This rod block signal provides an indication to the operator that water is accumulating in the SDV and prevents further rod withdrawals. With continued water accumulation, a reactor protection system initiated scram signal will occur. Thus, the SDV water level rod block signal provides an opportunity for the operator to take action to avoid a subsequent scram. No design basis accident or transient takes credit for rod block signals initiated by the SDV instrumentation.

pb Comparison to Screenino Criteria:

1. The SDV control rod block is not used for, nor capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary prior to a design basis accident (DBA).

2. The SDV control rod block instrumentation is not used to monitor a process variable that is an initial condition of a DBA or transient analyses.

3. The SDV control rod block signal is not a part of a primary success path in the mitigation of a DBA or transient.

As discussed in Sections 3.5 and 6, and summarized in Table 4-1 (Item 139) of NED0-31466, the loss of the SDV control rod block function was found to be a non- :

significant risk contributor to core damage frequency and offsite releases. GPC l has reviewed this evaluation and considers it applicable to Plant Hatch Unit 2.

Conclusion:

j Since the screening criteria have not been satisfied, the Control Rod Block LC0 and Surveillances applicable to SDV instrumentation may be relocated to other ;

plant controlled documents outside the Technical Specifications. ]

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UNIT 2 A-4 I

i APPENDIX A 3/4.3.6.1 RADIATION MONITORING INSTRUMENTATION LC0 Statement:

The radiation monitoring instrumentation channels shown in Table 3.3.6.1-1 shall be OPERABLE with their alarm / trip setpoints within the specified limits.

3/4.3.6.1.1 Off-Gas Post-Treatment Monitors Discussion:

I The radioactive gas processing system is neither a safety system nor is it I connected to the primary coolant piping. The off-gas post-treatment monitors are used to show conformance with the discharge limits of 10 CFR 20. There is

. another Specification (which is being retained - proposed LC0 [3.7.6]) that ensures 10 CFR 100 limits are not exceeded. Information provided by these instruments on the radiation levels would have limited or no use in identify-

! ing/ assessing core damage and they are not installed to detect excessive reactor 3

coolant leakage.

Comparison to Deterministic Screenina Criteria:

1. These monitors are not used for, nor capable of, detecting a significant j abnormal degradation of the reactor coolant pressure boundary prior to a i(

t design basis accident (DBA).

2. The monitored parameters are not assumed as initial conditions of a DBA or transient analyses that assumes the failure of, or presents a challenge to the integrity of a fission product barrier.

j 3. These monitors do not act as part of a primary success path in the l mitigation of a DBA or transient that assumes the failure of, or presents a challenge to the integrity of a fission product barrier.

1

! As discussed in Sections 3.5 and 6, and summarized in Table 4-1 (Item 145) of !

l NED0-31466, the loss of these monitors was found to be a non-significant risk l contributor to core damage frequency and offsite releases. GPC has reviewed this 1

evaluation and considers it applicable to Plant Hatch Unit 2.

Conclusion:

l Since the screening criteria have not been satisfied, the Off-Gas Post-Treatment Monitors LCO and Surveillances may be relocated to other plant controlled l

documents outside the Technical Specifications. l

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O l UNIT 2 A-5 L

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APPENDIX A fU) 3/4,3.6.2 SEISMIC MONITORING INSTRUMENTATION

LCO Statement

The seismic monitoring instrumentation shown in Table 3.3.6.2-1 shall be OPERABLE.

Discussion:

4 In the event of an earthquake, seismic instrumentation is required to permit comparison of the measured response to that used in the design basis of the facility to determine if plant shutdown is required pursuant to Appendix A of 10 CFR Part 100. Since this is determined after the event has occurred, it has no bearing on the mitigation of any DBA.

Comparison to Deterministic Screenino Criteria:

1. These instruments are not used for, nor capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary prior to a design basis accident (DBA).

2. These instruments do not monitor a process variable that is an initial condition to a DBA or transient analyses.

(' 3. These instruments do not act as part of a primary success path in the mitigation of a DBA or transient.

As discussed in Sections 3.5 and 6, and summarized in Table 4-1 (Item 151) of NED0-31466, the loss of seismic monitoring instrumentation was found to be a non-significant risk contributor to core damage frequency and offsite releases. GPC has reviewed this evaluation and considers it applicable to Plant Hatch Unit 2.

Conclusion:

l Since the screening criteria have not been satisfied, the Seismic Monitoring I Instrumentation LCO and Surveillances may be relocated to other plant controlled documents outside the Technical Specifications.

UNIT 2 A-6 i

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APPENDIX A LJ 3/4.3.6.4 POST-ACCIDENT HONITORING INSTRUMENTATION

, LCO Statement:

The post-accident monitoring instrumentation channels shown in Table 3.3.6.4-1 shall be OPERABLE.

Discussion:

Each individual accident monitoring parameter has a specific purpose, however, the general purpose for all accident monitoring instrumentation is to provide sufficient information to confirm an accident is proceeding per prediction, i.e.

automatic safety systems are performing properly, and deviations from expected accident course are minimal.

Comoarison to Deterministic Screenina Criteria:

The NRC position on application of the deterministic screening criteria to post-accident monitoring instrumentation is documented in letter dated May 7, 1988 from T.E. Murley (NRC) to R.F. Janecek (BWROG). The position was that the post-accident monitoring instrumentation table list should contain, on a plant ,

specific basis, all Regulatory Guide 1.97 Type A instruments specified in the plant's Safety Evaluation Report (SER) on Regulatory Guide 1.97, and all r Regulatory Guide 1.97 Category 1 instruments. Accordingly, this position has t

been applied to the Plant Hatch Unit 2 Regulatory Guide 1.97 instruments. Those instruments meeting this criteria have remained in Technical Specifications. The instruments not meeting this criteria may be relocated from the Technical

, Specifications to plant controlled documents.

The following summarizes the Plant Hatch Unit 2 position for those instruments currently in Technical Specifications.

From NRC SER dated 7/30/85,

Subject:

Conformance to R.G. 1.97.

Tvoe A Variables

1. Reactor Vessel Pressure

2. Suppression Chamber Water Temperature

3. Drywell Temperature

4. Drywell H, - 0, Analyzer Other Tvoe. Cateaory 1 Variables

1. Reactor Vessel Shroud Water Level

2. Suppression Chamber Water Level i

3. Drywell Pressure l

. 4. Drywell High Range Pressure '

5. Drywell High Range Radiation (V3 1

UNIT 2 A-7 i i

APPENDIX A For other post-accident monitoring instrumentation currently in Technical Specifications, their loss is not risk-significant since the variable they.

monitored did not qualify. as a Type A or Category 1 variable (one that is important to safety and needed by the operator, so that the operator can perform -

necessary manual actions).

Conclusion Since the screening criteria have not been satisfied for non-Regulatory Guide 1.97 Type A or Category 1 variable instruments, their associated LC0 and Surveillances may be relocated to other plant controlled documents outside the Technical Specifications. The instruments to be relocated are as follows:

1. Suppression Chamber Pressure

2. Post-LOCA Gamma Radiation.

3. Safety / Relief Valve Position

-4. Main Stack Post-Accident Effluent Monitor

5. Reactor Building Vent Plenum Post-Accident Effluent Monitor O

I O

UNIT 2 A-8

~N APPENDIX A

]

3/4.3.6.6 TRAVERSING INCORE PROBE SYSTEM LC0 Statement:

The traversing incore probe system shall be OPERABLE with:

a. Four movable detectors, drives and readout equipment to map the core, and

b. Indexing equipment to allow all four detectors to be normalized in a common location.

Discussion:

The TIP system is used for calibration of the LPRM detectors. The TIP system is positioned axially and radially throughout the core to calibrate the local power range monitors (LPRMs). When not in use the TIP instruments are retracted into a storage position outside the drywell. The TIP system supports the operability of the LPRMs. With LPRM operability addressed there is no need to address the TIP system in the Technical Specifications.

Comparison to Screenino Criteria:

1. The TIP system is not used for, nor capable of, detecting a significant r3 abnormal degradation of the reactor coolant pressure boundary prior to a Q design basis accident (DBA).

2. The TIP system alone is not used to monitor a process variable, nor is the system a process variable that is an initial condition of a DBA or transient analyses.

3. The TIP system is not a part of a primary success path in the mitigation of a DBA or transient.

As discussed in Sections 3.5 and 6, and summarized in Table 4-1 (Item 183) of

, NED0-31466, the loss of the TIP system was found to be a non-significant risk contributor to core damage frequency and offsite releases. GPC has reviewed this evaluation and considers it applicable to Plant Hatch Unit 2.

Conclusion:

Since the screening criteria have not been satisfied, the TIP System LC0 and Surveillances may be relocated to other plant controlled documents outside the Technical Specifications.

I ,G t

l UNIT 2 A-9 l

APPENDIX A O-3/4.3.6.7 MAIN CONTROL ROOM ENVIRONMENTAL CONTROL SYSTEM (MCRECS) ACTUATION INSTRUMENTATION LC0 Statement.1.

The MCRECS actuation instrumentation channels shown in table 3.3.6.7-1 shall be OPERABLE, with their trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3.6.7-1.

3/4.3.6.7.1 Reactor Vessel Water Level - Low Low Low (Level 1) 3/4.3.6.7.2 Drywell Pressure - High 3/4.3.6.7.4 Main Steam Line Flow - High 3/4.3.6.7.5 Refueling Floor Area Radiation - High Discussion:

These instruments provide signals to automatically place the MCREC system in the radiation protection mode. However, these instruments are anticipatory only, and are not assumed in any DBA or transient. There is another instrument (which is being retained) that provides the actuation signal assumed in the accident analysis.

Comparison to Screenina Criteria:

1. These instruments are not used for, nor capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary prior to a design basis accident (DBA).

2. These instruments are not used to monitor a process variable that is an initial condition of a DBA or transient analyses.

3. These instruments are not part of a primary success path in the mitigation of a DBA or transient.

As discussed in Appendix B (Page 1 of 1) of this document, the loss of these instruments was found to be a non-significant risk contributor to core damage frequency and offsite releases.

Conclusion:

Since the screening criteria have not been satisfied, these MCRECS Actuation Instrumentation LCOs and Surveillances may be relocated to other plant controlled documents outside the Technical Specifications.

l O

UNIT 2 A-10

i APPENDIX A 3/4.3.6.10 EXPLOSIVE GAS MONITORING INSTRUMENTATION LC0 Statement:

The explosive gas monitoring instrumentation channels shown in table 3.3.6.10-1 shall be OPERABLE with their alarm / trip setpoints set to ensure that the limits of Specification 3.11.2.6 are not exceeded.

4 Discussion:

The explosive gas monitor Specification is provided to ensure that the concentration of potentially explosive gas mixtures contained in the gaseous radwaste treatment system is adequately monitored, which will help ensure that ,

the concentration is maintained below the flammability limit of hydrogen. l However, the offgas system is designed to contain detonations and will not affect i the function of any safety related equipment. The concentration of hydrogen in the offgas stream is not an initial assumption of any design basis accident or transient analysis.

Comparison to Screenina Criteria:

1. The explosive gas monitoring instrumentation is not used for, nor capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary prior to a design basis accident (DBA).

2. The explosive gas monitoring instrumentation is not used to monitor a process variable that is an initial condition of a DBA or transient.

Excessive system effluent is not an indication of a DBA or transient.

3. The explosive gas monitoring instrumentation is not part of a primary success path in the mitigation of a DBA or transient. Excessive discharge i is not considered to initiate a primary success path in mitigating a DBA or transient.

As discussed in Sections 3.5 and 6, and summarized in Table 4-1 (Items 189 and 306) of NED0-31466, the loss of the explosive gas monitoring instrumentation was

. found to be a non-significant risk contributor to core damage frequency and offsite releases. GPC has reviewed this evaluation and considers it applicable to Plant Hatch Unit 2.

Conclusion:

i Since the screening criteria have not been satisfied, the Explosive Gas Monitoring Instrumentation LCO and Surveillances may be relocated to other plant controlled documents outside the Technical Specifications.

UNIT 2 A-11

APPENDIX A 3/4.3.7 TURBINE OVERSPEED PROTECTION SYSTEM LCO Statement:

At least one turbine overspeed protection system shall be OPERABLE.

Discussion:

This Specification is provided to ensure that the turbine overspeed protection instrumentation and the turbine speed control valves are operable and will protect the turbine from excessive overspeed. Excessive overspeed could potentially result in the generation of missiles which could impact and damage safety related components, equipment or structures, depending on the size and trajectory of the missiles. Given that the probability of turbine missile damage is acceptably low, the transient due to the actuation of the turbine stop.or control valves in response to a turbine overspeed event should be considered i.e.

turbine trip or load rejection. For this event the closure of the turbine stop or control valves initiates the design basis transient (turbine trip or load rejection) and not the turbine overspeed itself. The overspeed instruments do not perform a subsequent function to mitigate the effects of the transient.

Comoarison to Screenino Criteria:

1. The turbine overspeed protection system is not used for, nor capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary prior to a design basis accident (DBA).

2. The turbine overspeed protection system is not used to monitor a process variable that is an initial condition of a DBA or transient.

3. The turbine overspeed protection system is not part of a primary success path in the mitigation of a DBA or transient.

As discussed in Sections 3.5 and 6, and summarized in Table 4-1 (Item 201) of NED0-31466, the loss of the turbine overspeed protection system was found to be a non-significant risk contributor to core damage frequency and offsite releases.

GPC has reviewed this evaluation and considers it applicable to Plant Hatch Unit 2.

Conclusion:

Since the screening criteria have not been satisfied, the Turbine Overspeed Protection System LC0 and Surveillances may be relocated to other plant controlled documents outside the Technical Specifications. i O

UNIT 2 A-12

APPENDIX A

,(]

LJ 3/4.4.4 CHEMISTRY LCO Statement:

The chemistry of the reactor coolant system shall be maintained within the limits

, specified in Table 3.4.4-1.

~

Discussion:

Poor reactor coolant water chemistry may contribute to the long term degradation of system materials and thus is not of immediate importance to the plant operator. Reactor coolant water chemistry is monitored for a variety of reasons.

One reason is to reduce the possibility of failures in the reactor coolant system pressure boundary caused by corrosion. Severe chemistry transients have resulted in failure of thin walled LPRM instrument dry tubes in a relatively short period of time. However, these LPRM dry tube failures result in loss of the LPRM function and are readily detectable. In summary, the chemistry monitoring activity serves of a long term preventative rather than mitigative purpose.

Comparison to Screenino Criteria:

1. Reactor coolant water chemistry is not used for, nor capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary O prior to a design basis accident (DBA).

'b 2. Reactor coolant water chemistry is not used to monitor a process variable that is an initial condition of a DBA or transient.

3. Reactor coolant water chemistry is not supportive of any primary success path in the mitigation of a DBA or transient.

As discussed in Sections 3.5 and 6, and summarized in Table 4-1 (Item 211) of NED0-31466, the reactor coolant water chemistry was found to be a non-significant risk contributor to core damage frequency and offsite releases. GPC has reviewed i this evaluation and considers it applicable to Plant Hatch Unit 2.

Conclusion:

Since the screening criteria have not been satisfied, the Reactor Coolant System Chemistry LCO and Surveillances may be relocated to other plant controlled documents outside the Technical Specifications.

UNIT 2 A-13

APPENDIX A

(/

3/4.4.8 STRUCTURAL INTEGRITY LCO Statement:

The structural integrity of ASME Code Class 1, 2 and 3 components shall be maintained in accordance with Specification 4.4.8.

Discussion:

The inspection programs for ASME Code Class 1, 2, and 3 components ensure that the structural integrity of these components will be maintained throughout the components life. Other Technical Specifications require important systems to be 4 operable (for example, ECCS 3/4.5.1) and in a ready state for mitigative action.

This Technical Specificationsis more directed toward prevention of component degradation and continued long term maintenance of acceptable structural conditions. Hence it is not necessary to retain this Specification to ensure immediate operability of safety systems.

i Further, this Technical Specificationsprescribes inspection requirements which are performed during plant shutdown. It is, therefore, not directly important for responding to design basis accidents.

Comparison to Screenina Criteria:

1. The inspections stipulated by this Specification are not used for, nor capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary prior to a design basis accident (DBA).

2. The inspections stipulated by this Specification do not monitor process variables that are initial assumptions in a DBA or transient analyses.

3. The ASME Code Class 1, 2, and 3 components inspected per this Specification are assumed to function to mitigate a DBA. Their capability to perform this function is addressed by other Technical Specifications. This Technical Specification, however, only specifies inspection requirements for these components; and these inspections can only be performed when the plant is shutdown. Therefore, Criterion 3 is not satisfied.

As discussed in Sections 3.5 and 6, and summarized in Table 4-1 (Item 216) of i NED0-31466, the assurance of operability of the entire system as verified in the i system operability Specification dominates the risk contribution of the system. j As such, the lack of a long term assurance of structural integrity Specification was found to be a non-significant risk contributor to core damage frequency and offsite releases. Furthermore, the requirement is currently covered by 10 CFR 50.55a and the plant's Inservice Inspection Program. GPC has reviewed this evaluation and considers it applicable to Plant Hatch Unit 2.

Conclusion:

( Since the screening criteria have not been satisfied, the Structural Integrity V) LC0 and Surveillances may be relocated to other plant controlled documents outside the Technical Specifications.

UNIT 2 A-14

s APPENDIX A 3/4.7.5 SEALED SOURCE CONTAMINATION LCO Statement:

Each sealed source containing radioactive material either in excess of 100 microcuries of beh and/or gamma emitting material or 5 microcuries of alpha emitting material shall be free of a: 0.005 microcuries of removable contamina-tion.

Discussion:

The limitations on sealed source contamination are intended to ensure that the total body or individual organ irradiation doses does not exceed allowable limits in the event of ingestion or inhalation. This is done by imposing a maximum limitation of s 0.005 microcuries of removable contamination on each sealed source. This requirement and the associated Surveillance Requirements bear no relation to the conditions or limitations which are necessary to ensure safe reactor operation.

Comoarison to Screenino Criteria:

1. Sealed source contamination is not used for, nor capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary prior to a design basis accident (DBA).

2. Sealed source contamination is not a process variable that is an initial condition of a DBA or transient.

3. Sealed source contamination is not used in any part of a primary success path in the mitigation of a DBA or transient.

As discussed in Sections 3.5 and 6, and summarized in Table 4-1 (Item 267) of NE00-31466, the sealed source contamination being not within limits was found to be a non-significant risk contributor to core damage frequency and offsite releases. GPC has reviewed this evaluation and considers it applicable to Plant Hatch Unit 2.

Conclusion:

Since the screening criteria have not been satisfied, the Sealed Source Contamination LC0 and Surveillances may be relocated to other plant controlled documents outside the Technical Specifications.

/0 V

UNIT 2 A-15

t APPENDIX A

(.J 3/4.8.2.5 A.C. CIRCUITS INSIDE PRIMARY CONTAINMENT LC0 Statement:

The following A.C. circuits inside primary containment shall be de-energized.

! Discussion:

The circuits involved in this LCO are kept normally de-energized and do not participate in plant safety actions. These circuits are primarily for lighting, utility outlets and convenient power plugs, to be used in the event of plant walkdowns, maintenance and in-situ test and/or observations. Therefore, they are of non-Class IE nature.

They are properly separated from all other Class IE circuits, and operation or failure of these non-Class IE circuits do not impose any degradation on Class 1E circuits. Thus, in any event (energized or de-energized state), these circuits have no impact on plant safety systems.

Comoarison to Screenina Criteria:

1. The AC circuits listed in this Specification are de-energized during operation and are not used for, nor cupable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary prior to a

(p) design basis accident (DBA).

2. The AC circuits listed in this Specification are not uied to monitor a process variable that is an initial condition of a DBA or transient.

3. The AC circuits listed in this Specification are not part of a primary success path in the mitigation of a DBA or transient.

As discussed in Sections 3.5 and 6, and summarized in Table 4-1 (Item 275) of s

NED0-31466, the AC circuits inside primary containment governed by this Specification were found to be a non-significant risk contributor to core damage frequency and offsite releases. GPC has reviewed this evaluation and considers it applicable to Plant Hatch Unit 2.

Conclusion:

Since the screening criteria have not been satisfied, the A.C. Circuits Inside Primary Containment LC0 and Surveillances may be relocated to other plant controlled documents outside the Technical Specifications.

UNIT 2 A-16

APPENDIX A 3/4.8.2.6 PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES LC0 Statement:

All primary containment penetration conductor overcurrent protective devices

shown in Table 3.8.2.6-1 shall be OPERABLE.

Discussion:

The primary feature of these protective devices is to open the control and/or i power circuit whenever the load conditions exceed the preset current demands.

This is to protect the circuit conductors against damage or failure due to overcurrent heating effects. Primary and backup electrical protection for short circuits is provided for all penetrations.

The continuous monitoring of the operating status of the overcurrent protection devices is impracticable and not covered as part of the control room monitoring, except after trip condition indication.

In the event of failure of the primary protective device to trip the circuit, the backup protective device is expected to operate and isolate the faulty circuit.

Thus, the upper level (back-up) protection will prevent loss of redundant power source. In the worst case fault condition, a single division of protec.tive functions can be lost. However, this scenario is covered under single failure

, v criterion.

The overcurrent protection devices ensure the pressure integrity of the containment penetration. With failure of the device it is postulated that the wire insulation will degrade resulting in a containment leak path during a LOCA.

However, containment leakage is not a process variable and is not considered as 3 part of the primary success path. Containment penetration degradation will be identified during the normal containment leak rate tests required by 10 CFR Part 50, Appendix J.

Comparison to Screenina Criteria:

1. The primary containment penetration conductor overcurrent protection devices are not ured for, nor capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundarv prior to a design basis accident (DBA).

2. The primary containment penetration conductor overcurrent protection devices specific circuits are not used to monitor a process variable that is an initial condition of a DBA or transient.

3. The specific circuits of the primary containment penetration conductor overcurrent protection devices are not part of a primary success path in the mitigation of a DBA or transient.

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UNIT 2 A-17

i l

f- ,s APPENDIX A As discussed in Sections 3.5 and 6, and summarized in Table 4-1 (Item 276) of NED0-31466, the loss of the overcurrent protection function of the circuits.

associated with the primary containment penetration conductor overcurrent protection devices was found to be a non-significant risk contributor to core ,

damage frequency and offsite releases. GPC has reviewed this evaluation and i considers it applicable to Plant Hatch Unit 2.

Conclusion:

Since the screening criteria have not been satisfied, the Primary Containment Penetration Conductor Overcurrent Protective Devices LC0 and Surveillances may be relocated to other plant controlled documents outside the Technical l Specifications.

l l

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UNIT 2 A-18

i l

APPENDIX A l ('S V

3/4.9.6 COMMUNICATIONS LC0 Statement:

Direct communications shall be maintained between the control room and refueling platform personnel.

l Discussion:

1 Communication between the control room and refueling floor personnel is maintained to ensure that refueling personnel can be promptly informed of significant changes in the plant status or core reactivity condition during refueling. The communications allow for coordination of activities that require interaction between the control room and refueling floor personnel (such as the insertion of a control rod prior to loading fuel). However, the refueling system design accident or transient response does not take credit for communications and is designed to ensure safe refueling operations.

Comoarison to Screenino Criteria:

I 1. Communications during any mode of plant operation is not used for, nor capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary prior to a design basis accident (DBA).

A

!V

2. Communications during any mode of plant operation is not used to indicate status of, or monitor a process variable that is an initial condition of a DBA or transient. i

3. Communication during any mode of plant operation does not contribute to a !

primary success path in the mitigation of a DBA or transient.

As discussed in Sections 3.5 and 6, and summarized in Table 4-1 (Item 286) of ,

NED0-31466, the loss of direct communication was found to be a non-significant i risk contributor to core damage frequency and offsite releases. GPC has reviewed ,

this evaluation and considers it applicable to Plant Hatch Unit 2. l

Conclusion:

Since the screening criteria have not been satisfied, the Communications LC0 and Surveillances may be relocated to other plant controlled documents outside the Technical Specifications.

O V

UNIT 2 A-19

4 APPENDIX A

/

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3/4.9.7 CRANE AND HOIST OPERABILITY LC0 Statement:

All cranes and hoists used for handling fuel assemblies or control rods within the reactor pressure vessel shall be OPERABLE.

Discussion:

Operability of the refueling platform equipment (crane, main hoist, fuel grapple, and auxiliary hoist) ensures that only the proper refueling platform equipment will be used to handle fuel within the reactor pressure vessel, hoists have sufficient load capacity for handling fuel assemblies and/or control rods, and the core internals and pressure vessel are protected from excessive lifting force if they are inadvertently engaged during lifting operations. Although the interlocks designed to provide the above capabilities can prevent damage to the i

refueling platform equipment and core internals, they are not assumed to function to mitigate the consequences of a design basis accident. Further, in analyzing the control rod withdrawal error during refueling, if any one of the operations involved in initial failure or error is followed by any other single equipment failure or single operator error, the necessary safety actions are taken (e.g.,

rod block or scram) automatically prior to violation of any limits. Hence the refueling platform interlocks are not part of the primary success path in

,o mitigating the control rod withdrawal error during refueling.

(-) Comparison to Screenino Criteria:

1. The refueling platform and associated instrumentation is not used for, nor

capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary prior to a design basis accident (DBA).

2. The refueling platform and associated instrumentation is not used to monitor a process variable that is an initial condition of a DBA or transient.

3. The refueling platform and associated instrumentation is not part of a primary success path in the mitigation of a DBA or transient.

As discussed in Sections 3.5 and 6, and summarized in Table 4-1 (Item 287) of NED0-31466, the refueling platform and associated instrumentation was found to 1 be a non-significant risk contributor to core damage frequency and offsite releases. GPC has reviewed this evaluation and considers it applicable to Plant Hatch Unit 2.

Conclusion:

Since the screening criteria have not been satisfied, the Crane and Hoist Operability LC0 and Surveillances may be relocated to other plant controlled documents outside the Technical Specifications.

O v

UNIT 2 A-20

l l - \

lO I

\. J APPENDIX A ;

i 3/4.9.8 CRANE TRAVEL - SPENT FUEL STORAGE POOL LCO Statement:

Loads in excess of 1600 pounds shall be prohibited from travel over fuel

, assemblies in the spent fuel storage pool racks.

I

! Discussion:

! The Technical Specificationslimit of 1600 pounds for loads over the spent fuel l contained in the storage pool is further reduced by the heavy loads analysis to 725 pounds or the weight of a single fuel bundle. This 725 pound imposed limit

, ensures that in the event the load is dropped, the activity release will be l bounded by the analysis of the refueling accident and any possible distortion of l the fuel in the storage racks will not result in a critical array. Administra-l tive monitoring of loads moving over the fuel storage racks serves as a backup i

to the Unit I crane interlocks. While the Unit 2 crane does not have interlocks, !

l its use is strictly governed by administrative controls.

l Although this Technical Specificationssupports the maximum refueling accident assumption in the DBA, the applicable fuel handling crane travel limits are not n.onitored and controlled during operation; they are checked on a periodic basis to ensure operability. The deterministic criteria for Technical Specificationsr-etention are, therefore, not satisfied.

" Comparison to Screenina Criteria:

1. The fuel handling crane travel limits are not used for, nor capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary prior to a design basis accident (DBA).

2. The maximum severity assumed for the fuel handling DBA is limited by the limits placed on the crane travel. l These crane travel limits are not, l however, process variables monitored and controlled by the operator. They l are interlocks and/or physical stops. Therefore, Criterion 2 is not satisfied.

3. The fuel handling crane travel limits are not a structure, system, or component that is part of the primary success path and which functions or actuates to mitigate a DBA.

Traditional PRAs do not review risks associated with the spent fuel storage pool.

Design basis analyses indicate that the release associated with fuel assembly damage in the spent fuel storage pool due to crane accidents is significantly lower than releases of concern evaluated by PRAs.

Conclusion:

Since the screening criteria have not been satisfied, the Crane Travel - Spent O Fuel Storage Pool LC0 and Surveillances may be relocated to other plant d controlled documents outside the Technical Specifications.

UNIT 2 A-21 ,

i i

N APPENDIX B PLANT SPECIFIC RISK SIGNIFICANT EVALUATIONS J

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p APPENDIX B TECHNICAL SPECIFICATION:

3/4.3.6.7.1' Reactor Vessel Water Level - Low Low Low (Level 1) 3/4.3.6.7.2 Drywell Pressure - High 3/4.3.6.7.4 Main Steam Line Flow - High 3/4.3.6.7.5 Refueling Floor Area Radiation - High DESCRIPTION OF RE0VIREMENT:

The instrumentation covered by the above specifications provides actuation signals to the Main Control Room Environmental Control System (MCRECS) to initiate the pressurization mode of control room ventilation in anticipation of a release.

REFERENCES:

Plant Hatch IPE-NUREG 1150 (Peach Bottom)

Monticello IPE DISCUSSION:

All of the above signals are anticipatory, in that they initiate the pressuriza-tion mode of MCRECS prior to the actual presence of airborne radiation at the O_ Control Room air inlet.

The above actuation signals for the MCRECS have no significance to the risk of core damage and negligible risk to the potential for significant offsite releases. Failure to initiate the pressurization mode of the MCRECS has no bearing on the ability of the operators to bring the plant to a safe shutdown condition. With regards to preventing offsite releases, failure of the above signals is unlikely to have any impact on the progression of events following a severe accident for the following reasons:

1. The MCR air inlet high radiation signal provides reliable automatic actuation for the system when it is realistically required.

2. Failure to pressurize the control room has a very indirect effect on the magnitude of a release. For pressurization to be realistically required, a release must already have occurred. PRAs do not typically model the very subtle impact that increased dose rates to operators might have on the progression of an accident. It is likely l that the operators would continue to attempt to control the accident ,

using available airborne radiation protection equipment, rather than abandoning the control room. The subtle impacts on human error rates are a negligible consideration when the operator actions at that time are primarily recovery actions anyway.

O C/

UNIT 2 B-1

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APPENDIX B O CONCLUSION:

Based on the above insights, it can be concluded that the above specifications may be relocated from the Plant Hatch Unit 2 Technical Specifications to Plant Hatch controlled documents with no significant impact on the potential for core ,

damage.and the risk of offsite consequences.

O p

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UNIT 2 B-2 l

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v t e Letter Sequence Request
TAC:M873110, (Open) TAC:M873111, (Open)
Initiation Request Acceptance... Administration Questions Answers Results Approval... Other:
MONTHYEAR1994-02-25 [Table View]

HL-4495, Application for Amends to Licenses DPR-57 & DPR-5 Revising Units 1 & 2 TS to Be Consistent w/NUREG-1433 Standard TS GE Plants,BWR/4

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