Text

Application for Amend to License NPF-58,revising TSs to Increase Surveillance Test Intervals & Allowable Outage Times for Instrumentation.Ge Proprietary Documents Supporting Request Encl.Ge Documents Withheld
	ML20101L909
Person / Time
Site:	Perry
Issue date:	06/29/1992
From:	Lyster J; CENTERIOR ENERGY
To:	; NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
Shared Package
ML19311A938	List: ML20101L913; PY-CEI-NRR-1496, Application for Amend to License NPF-58,revising TSs to Increase Surveillance Test Intervals & Allowable Outage Times for Instrumentation.Ge Proprietary Documents Supporting Request Encl.Ge Documents Withheld;
References
	PY-CEI-NRR-1496, NUDOCS 9207070409
	Download: ML20101L909 (42)
	v • d • e

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ce _.m PERRY NUCLEAR POWER PLANT s:

Michael D. Lysier 10 E T R ROAD PERRt OHIO 44081 VICE PRESIDENT NUCLEAR (216) 259 37J7 June 29, 1992 PY-CEI/NRR-1496 L U. S. Nuclear Regulatory Commission Document Control Desk Vashington, D. C. 20555 Perry Nuclear Power Plant Docket.No. 50-440 Technical Specification Change Request to Increase Surveillance Test Intervals and Allowable Outage Times for instrumentation Gentlemen Enclosed is a request for amendment to the Facility Operating License NPF-58 ,

for the Perry Nuclear Power Plant, Unit 1. This letter requests revision to various instrumentation Technical Specifications. The amendmer.t vould extend the Allovable Outage Times (A0Ts) of the instruments involved, and increase the Channel Functirnal Surveillance test interval (STI) from a Monthly to a Quarterly requitement.

1 The Technical Specifications involved include sect 2ons 3.3.1 " Reactor Protection System Instrumentation," 3.3.2 " Isolation Actuation Instrumen-tation," 3.3.3 " Emergency Core Cooling System Actuation Instrumentation," l 3.3.4.1 "ATVS Recirculation Pump Trip System Instrumentation," 3.3.4.2 l "End-of-Cycle Recirculation Pump Trip System Instrumentation," 3.3.5 " Reactor i Core Isolation Cooling System Actuation Instrumentation " 3.3.6 " Control Rod Block Instrumentation," 3.3.9 " Plant System Actuation Instrumentation," 3.4.2.1 -

" Safety / Relief Valves," and 3.4.2.2 " Safety / Relief Valves Low-Low Set -

Function."

r These proposed changes are the result of an extensive efinrt between the BVR Owner's Group (BVROG), the General Electric (GE) Company, and the Nuclear Regulatory Commission (NRC) on determining _ proper test-intervals and A0Ts for-various Technical Specification instrumentation.

o Attachment 1 provides the Background, Description of Changes, Justification of

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l Proposed Changes, and=the Significar.t Hazards and Environmental Impact rjgt Considera_tions. Attachment 2.is a copy of the marked up Technical l g Specification pages. Enclosures 1, 2, 3 and 4 contain supporting information j g.o for this proposed change.

Please note that for the documents contained in Enclosures 1 and 3,'it is J

, hereby requested that these documents be withheld from public disclosure per j g4 10CFR 2.790(a)(4). Affidavits are provided within each Enclosure in accordance s l b. with 10CFR 2.790(b)(1). These GE documents are identified as HDE-86-0485-

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[ 'l USNRC June 29, 1992 PY-CEI/NRR-1496 L

" Technical Specification Improvement Analysis for the Reactor Protection System For Perry Nuclear Power Plant, Units 1 and 2," dated April 1985, and RE-028,

" Technical Specification Improvement Analysis for Emergency Core Cooling System Actuation Instrumentation for Perry Nuclear Power Plant," dated December 1991, for Enclosures 1 and 3 respectively.

If you have any enestions, please feel free to call.

Sincerely, is Wa -

i Michael D. Lyster HDL BSFiss Attachment / Enclosures Enclosures 1 and 3 contain 10CFR 2.790(a)(4) information, to be withheld from public disclosure.

cet NRC Project Manager NRC Resident Inspector Office NRC Region III State of Ohio

O E N E R,_A_L

_ E L E 9_T R I C C0MPANY AFFIDAyli I, David J. Robare, being duly sworn, depose and state as follows:

1. I am Manager, plant Licensing Services, General Electric Company, and l have been delegated the function of reviewing the information described in paragraph 2 which is sought to be withheld and have been authorized to apply for its withholding.

2. The information sought to be withhcid is contained in the. report entitled

" Technical Specification Improvement Analysis for the Emergency core Cooling System Actuation Instrumentation for Perry Nuclear Power plant '

Units 1 and 2," RE-028, Rev.1, December 1991.

. 3. In designating material as proprietary, General Electric utilizes the de-finition of proprietary it?Srmation and trade secrets set forth in the American Law Institute's Restatement of Torts, Section 757. This j definition provides

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"A trade secret may consist of any formula, pattern, device or compilation of information which is used in ono's business and which gives him an opportunity to obtain an adykatate over competitors who do not know or use it.... A substantial element of secrecy must exist, so that, except by the use of improper means, there would be difficulty in acquiring information.... Some factors to be considered in determining whether given information is one's trade ser at ares (1) the extent to which the information is known outside of is business; (2) the extent to which it is known by employees chere involved in his business; (3) the extent of measures tax by him to guard the secrecy of the informations.(4) the value of tne information to him and to his competitors; (5) the amount of effort or money expended by him in developing the information; (6) the ease or difficulty with the which the information could be

. properly acquired or duplicated by'others."

4. Some examples of categories of information which fit into the definition of croprietary information ares

a. Information that discloses a process, method or apparatus where prevention of its use by General Electric's competitors without license from General Electric _ constitutes a competitive economic advantage over other companies;

b. Information consisting of' supporting data and analyses, including test data, relative to a process, method or apparatus, the application of which provide a competitive economic advantage, e.g., by optimization oc improved marketability;-

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l l c. Information which if used by a competitor, would reduce his expenditure of resources or improve his competitive position in the design, manufacture, shipment, installation, assurance of quality or licensing of a similar product; l

d. Information which reveals cost or price information, production capacities, budget levels or commercial strategies of General Electric, its customers or suppliers;

o. Information which reveals aspects of past, present or future General Electric customer-funded development plans and programs of potential commercisi value to General Electric; l

f. Information which discloses patentable subject matter for which it may be desirable to obtain patent protection;

g. Information which General Electric must treat as proprietary-according to agreements with other parties.

l l S. Initial approval of proprietary treatment of a document is typically mado by the Subsection manager of the originating component, who is most

, likely to be-acquainted with the value and sensitivity of the information 4

! in relation to industry knowledge. Access to such documents within the l Company is limited on a "need to know" basis and such documents are clearly identified as proprietary.

6. The procedure for approval of external release of such a document typically requires review by the Subsection Manager, Project Manager, Principal Scientist or other equivalent authority, by the subsection l Hanager of the cognizant Marketing. function (or delegate)'and by the Legal Operation for technical content, competitive effect and determination of the accuracy of the proprietary designation in accordance with the standards enumerated above. Disclosures outside General Electric are generally limited to regulatory bodies, customers and potential customers and their agents, suppliers and licensees then only with appropriate protection by applicable regulatory provleions cr proprietary agreements.

I 7. The document mentioned in paragraph 2 above has been evaluated in L accordance with the above criteria and procedures and has been found to contain information which is proprietary and which is customarily held in confidence by General Electric.

i 8. The information to the best of my knowledge and belief has consistently been held in confidence by the General Electric Company, no public disclosure has been made, end it is not available in public sources. All disclosures to third parties have been made pursuant to regulatory provisions of proprietary agreements which provide for maintenance of the information in confidence.

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9. Pdlic disclosu , of th.' information sought to be withheld is like1y to; cause substantias hare +o the competitive position of the General _ _

Electric Company'ar.) #eprive or reduce the availability of_ profit making opportunities because it would provide other parties, including competitors, with valuable.:information regarding the application of-reliability based methodology to BWR instrumentation.--A substantial effort has bsen expended by General Electric to development this -

information in support of the BWR; Owners' Group Technical Specification Improvement-Program.

- STATE OF CALIFORNIA ) ,,,

COUNTY OF SANTA CLARA )

David J. Robare, being duly sworn, deposes and says:

That he his read the foregoing affidavit and the matters stated therein are-tr;.r. and correct to.the best of his knowledge, information,,and belief.

Executed at San Jose, t...ifErnia, this1O day.of fEthDNQTJ,l1991 M MNQ David J. Robare 7eneral' Electric Company v

Subscribedandswornbeforemethisfb1{. day of'1dfvaN 1993 OFFICIAL SEAL Qnax41a.sw

_ NOTARY PUBLIC, - STATE - OD CM.IFORN :bi PAULA F. HUSSEY ,

NOTARY PU8t.lc CAUFORNIA SANTA Ct. AIR COUNTY -

.- My comm. expires APR 5,1994

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GENERAL ELECTRIC COMPANY AFFIDAVIT 1, David J. Robare, being duly sworn, depose and state as follows:

1. I am Mana;er, Plant Licensing Services, General Electric Company, and have been delegated tle function of reviewing the information described in paragraph 2 which is sought to be withheld and have been authorized to apply for its withholding.

2. The information sought to be withhe.id is contained in the report entitled " Technical 5

Specification improvement Analysis for the Reactor Protection System for Perry Nuclear j Power Plant Units 1 and 2", MDE 86-0485, April 1985.

4 j 3. In designating material as proprietary, General Electric utilizes one definition of proprietary information and trade secrets set forth in the American Law Institute's Restatement of Torts, Section 757. This definition provides:

"A trade secret may consist of any formula, pattern, device or compilation of information which is used in one's business and which gives him an opportunity to

, obtain an advantage over competitors who do not know or use it...A substantial element of secrecy must exist, so that, except by the use of improper means there 3

would be difficulty in acquiring information...Some factors to be considered in determining whether given information is one's trade secret are (1) the extent to which the information is known outside of his busiaess; (2) the extem to which it is known by employees and others involved in his business; (3) the extent of measures taken by him to guard the secrecy of the information; (4) the value of the information to him and to his competitors;(5) the amount of effort or money expanded by him developing the information; (6) the ease or difficulty with which

, the information coald be properly acquired or duplicated by others."

4. Some examples of categories of information which fit into the definition of Proprietary Information are:

! a. Information that discloses a process, method or apparatus where prevention of its

use by General Electric's competitors without license from General Electric constitutes a competitive economic advantage over other companies; 2

b. Information consisting of supporting data and analyses, including test data, relative to a process, method or apparatus, the application of which provide a competitive -

economic advantage, e.g., by optimization or improved marketability;

c. Information which if used by a competitor, would reduce his expenditures of resources or improve his competitive position in the design, manufacture, shipment, installation, assurance of quahty or licensing of a similar product;

O EN E R A L E LECT RIC CO M P/.N Y

d. Information which reveals cost or price information, production capacities, budget j levels or commercial strategies of General Electric, its customers or suppliers; -

e. Information which reveals aspects of past, present or future _ General Electrie customer funded development plans and programs of potential commercial value to General Electric;

f. Information which discloses patentable subject matter for which it may be desirable

to obtain patat protection;

g. Information which General Electric must treat as proprietary according to

agreements with other parties.

5. Initial approval of proprietay treatment of a document is typically made by the Subsection Manager of the origmating component, the person who is most likely to be acquainted with the value and sensitivity of the information in relation to industy knowledge. Access to such documents within the Company is limited on a "need to know" basis and such

documents are clearly identified as proprietary.

6. The procedure for approval of external release of such a document tyr., illy requires review by the Subsection Manager, Project Manager, Principal Sciei .st or other $

equivalent authority, by the Subsection Manager of the cognizant Marketing function (or delegate) and by the Legal Operation for technical content, competitively effact and determination of the accuracy _of the proprietary designation in accordance with the standards enumerated above. Disclosures outside General Electric are generally limited to i regulatory bodies, customers and potential customers and their agents, suppliers and i licensees then only with appropriate protection by applicable regulatory provisions or proprietary agreements.

7. The document mentioned in paragraph 2 above has been evaluated in accordance with the above criteria and procedures and has been found to contain information which is l proprietary and which is customarily held in confidence by General Electric.

8. The information to the best of my knowledge and belief has consistently been held in confidence by the General Electric Company, no public disclosure has been made, and it is not available in public sources. All disclosures to third parties have been made pursuant to regulaton provisions of proprietary agreements which provide for maintenance of the l information in confidence.

9. Public disclosure of the information sought to be withheld is likely to cause substantial r

harm to the competitive position of the General Electric Company and deprive or reduce -

the availability of profit making opportunities because it would provide other parties. ;

including competitors, with valuable information.

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] STATE OF CALIFORNIA }

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1 COUNTY OF SANTA CLARA }

, ' David J. Robare, being duly sworn, deposes and says:

1-d That he has read the foregoing affidavit and the matters stated therein are truly and correct to the best of his, knowledge, information, and belief. *

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i i Executed at San Jose, California, this 6TH day of J\tNE, - 1990.

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Subscribed and sworn before me thish' day of Ol A 19 9_0.-

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Attachant 1 PY-CEI/NRR-1496 L ;

Page 1 of 33 )

Background

During late 1983, the BVR's Ovner's Group (BVROG) formed a Technical ,

Specification Improvement Program (TSIP) Committee, of which the Perry Nuclear !

Power Plant (PNPP) is a member. This committee subsequently established a program for the development of reliability analyses to justify improvements to surveillance test intervals (STIs) and allovable ontage times (A0Ts) for

instrumentation spacified in the BVR Standard Technical Specifications. The primary objective of this program was to minimize, for applicable instrumentation, unnecessary testing and excessively restrictive A0Ts that

could potentially degrade overall plant safety and availability. Examples of some of the problems experienced with the current Technical Specification requirements are inadvertent scrams or engineered safety feature actuations due to frequent testing: A0Ts which are not long enough to perform repairs on a reasonable basis; excessive actuation af equipment for testing contributing to wear-out; and unnecessary radiation exposure to personnel performing Technical Specification required testing. A reduction in the number of Technical Specification required surveillance tests vill allow plant personnel

to perform other activities to increase the overall safety of the plant. ,

Vi, thin the same time frame, the RC Staf f issued NUREG-104, " Technical Sp;ecifications - Enhancing the Safety Impact," which recommended that surveillance test requirements and Technical Specification Action Statements be' reviewed to assure that they have an adequate technical-basis and do indeed minimize plant risk. Use of reliability analysis to support o gineering judgment was recognized as a primary basis for improving the Technical Specification requirements. NUREG-1024 thus reinforced the BVROG's program objectives and implementation methodology.

To this end, the BVROG submitted a series of Licensing Topical Reports addressing the Technical Specification instrumentation requirements for the Reactor Protection System (NEDC-30851P), Emergency Core Cooling Systems (NEDC-30936P), the Control Rod Block System (NEDC-30851P, Supplement 1), and for the Isolation Actuation Instrumentation (NEDC-30851P Supplement 2, and NEDC-31677P). Each of these Licensing Topical Reports has been revievv and approved by the NRC. In addition, the BVROG has submitted a Licensing iopical Report (GENE-770-06-1) and its Addendum (GENE-770-06-2), which address Technical Specification requirements for other instruments which are similar to those addressed in the Licensing Topical Reports previously reviewed and approved by the NRC.

As a member of the BVROG Technical Specifications Committee, PNPP is requesting that the results of the BVROG Licensing Topical Reports on Technical Specification improvements be a;) plied to the Perry Nuclear Power Plant. For convenience in reviewing this request, it has been divided into five separate parts addressing the functional-areas and associated BVROG Licensing Topical Report (s). Each part contains its own description of proposed changes, justification, and- Basis for No Significant Hazards Consideration. Included in Attachment 2 are. marked-up copies of pages from the current PNPP Technical Specifications indicating the combined effe r of the changes requested in each part of this attachment. Although not a tormal part of the Technical Specifications (as described in 10CFR50.36), Bases changes are also provided, in Attachment 3 to this letter. j

=

Attachm:nt 1 PY-CEI/NRR-1496 L Page 2 of 33 Part I - Reactor Protection Syctem (RPS)

Description of Proposed Changes The following changes to Technical Specification 3/4.3.1, " Reactor Protection System Instrumentation," are proposed:

1. Actions a. and b. have been revised to provide a repair allovable outage time (A0T) of either 1, 6 or 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , depending upon the degree of redundancy remaining in the other trip channels for that Functional Unit, as well as incorporating a check for loss of function into the ACTIONS and their footnotes.

2. The surveillance A0T.of Note (a) to Table 3.3.1-1 is being increased from two hours to six h?ars.

a 3. The surveillance test interval (STI) for CHANNEL FUNCTIONAL TEST's specified on Techrical Specification (TS) Table 4.3.1.1-1, " Reactor Protection System Instrumentation Surveillanca Requirements," is being increased from veekly (V) or monthly (H), as applicable, to quarterly (0) forthefellowingFunctionaqUnits:

a. item 2.b, Average Pover' Range Monitor ( APRH) Flow-Biased Simulated Thermal Power - High,

b. item 2.c, APRM Neutron Flux - High,

c. item 2.d, APRH Inoperat'ive,

d. item 3, Reactor Vessel Steam Dome Pressure - High,

e. item 4, Reactor Vessel Vater Level - Lov, Level 3, f- item 5, Reactor Vessel Vater Level - High, Level 8,

g. item 6, Main Steam Line Isolation Valve - Closure,

h. item 7 Main Steam Line Radiation - High, i, item 8, Dryvell Pressure - high, J. item 9.a. Scram Discharge Volume Vater Level - High, Level Transmitter,

k. item 9.b, Scram Discharge Volume Vater Level - High, Float Switches.

1. item 10, Turbine Stop Valve - Closure, and

- m. Item 11, Turbine Control Valve Past Closure Valve Trip System 011 Pressure - Lov

4. The STI for CHANNEL FUNCTIONAL TEST's specified on TS Table 4.3.1.1-1 item 13, Manual Scram is being revised from Monthly (H) to Veekly (V).

5. The analog trip module calibration interval specified by footnote (g) to Technical Specification Table 4.3.1.1-1 is being increased from 31 days to 92 days.

Justification for Proposed Changes On May 31, 1985 the BWROG submitted Licensing Topical Report NEDC-30851P,

" Technical Specification Improvement Analyses for BVR Reactor Protection

System," for NRC review. This Topical Report provides justification for the l

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4 Attach:2nt-1 PY-CEI/NRR-1496 L Page 3 of 33 proposed changes identified as 1 through 5 above. The analyses documented in NEDC-30851P utilized fault tree modeling to estimate the impact of the proposed changes on the average Reactor Protection System (RPS) failure frequency.

1 The average RPS failure frequency is a function of the frequency of scram i demands and the probability that the RPS is unavailable when demanded. The

initiating events which require successful operation of the RPS for ensuring safe reactor shutdovn are identified and their annual occurrence frequencies vere estimated. The initiating events were divided into three groups based on the number of diverse sensors that initiate the scram for that event.

' For each initiating event, a top-level failure event was identified using the success criteria described below. For each top failure event, a fault tree was developed which modeled all of the components needed for generation and-processing of the RPS signals including the sensors, analog trip modules, logic cards, load drivers and scram solenoids. The common cause failure of 1 these components was also modeled. A fault tree analysis was then performed i using the VAN series computer code, VAMCUT, to obtain the major failure cut sets that contribute to the top failure event probability. The failure cut sets obtained were then analyzed using the FRANTIC III compute code to determine the average RPS system unavailability upon demand.

The average RPS unavailability was calculated for each initiating event group based on inputs which included component failure rates (time and demand related), common cause failure rates, human error rates, testing intervals, and test repair times. Sensitivity studies were conducted by changing the input parameters by factors of 2, 5 and 10 (and 30, where appropriate) to

, determine the resultant impact on the average RPS unavailability and the total RPS failure frequency. The STIs and A0Ts were then varied to determine the resulting effect on the average RPS failure frequency.

The scram success criteria used for this analysis is defined below for two specific failure modest

a. Failare Hods A: One or more RPS electrical control rod groups fail to insert into the core. The success criteria for this failure mode vas.that two of the total four rod groups must fully insert.

b. Failure Mode B: One or more control rods in a random pattern fail to insert. The success criteria for this failure mode was that, if the control rods are inserted in a random manner, 69% of all the rods must fully insert to achieve success.

The acceptance guideline used by the BVROG for the proposed changes is based on a net change in risk. The net change-in risk is the difference between the increase in risk that vould result from the proposed changes and the decrease in risk that would result from the . reduced likelihood of inadvertent scrams.

If the net change in risk is determined to be insignificant., the BVROG considered the proposed changes to be acceptable.

The BVROG concluded that the overall effect of the proposed RPS Technical Specification changes provides a net increase in safety and improves plant

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$ Attachm:nt 1 PY-CEI/NRR-1496 L Page 4 of 33 operation. The improvement is achieved by reducing the rotential for:

(a) unnecessary plant scrams (reduced challenges to plant shutdown systems and improved plant availability); (b) excessive test cycles on equipment (reduced wear-out potential); and (c) diversion of plant personnel and resources on unnecessary testing (potential safety and operational improvement). The BVROG the cal

reportconclgdedthatfrom4.6x10~/yearto5.4x10gulatedaverageRPSfailurefrequencyincrease

/ year with a reduction in inadvertent scrams

, from an average of .56 scrams / year to .23 scrams / year with incorporation of the proposed RPS Technical Specification changes.

By letter from Ashok C. Thandani (NRC) to Terry A. Pickins (BVROG) dated July 15, 1987, the NRC provided their Safety Evaluation Report of NEDC-30851P.

The NRC concluded in their Safety Evaluation Report that NEDC-30851P applies to plants employing a Relay RPS system such as PNPP and that the proposed

changes vould have a negligible impact on plant risk. On this basis, the NRC determined that these proposed changes are acceptable. However, the staff

identified three requirements for any applicant who vished to reference this document for proposed Technical Specification Changes. These three

requirements are discussed below.

1. Confirm the applicability of the generic ar.alysis for NEDC-30851P to its plant.

4 A BVR-6 RPS relay model_ plant was used for the generic analysis for NEDC-30851P. PNPP is a BVR-6 vith a standard RPS relay system.

Therefore, the generic analysis employed by NEDC-30851P is applicable to 4

PNPP. In addition, General Electric did perform a PNPP plant specific analysis which is discussed belov for requirement-3. This analysis confirmed the applicability of the generic analysis for NEDC-30851P to PNPP.

2. Demonstrate by use of current drift information provided by the equipment vendor or plant-specific data that the drift characteristics for instrumentation used in the RPS channels in the plant are bounded by the

assumptions used in NEDC-30851P vhen functional test interval is extended from monthly to quarterly.

Vith respect to the Staff's concern about instrument drift over a 3 month (quarterly) period, the RPS instrumentation setpoint calculations at PNPP-include the effects of instrument drift over 18 months for all-instrument loop components. In addition, PNPP reviewed the results of-monthly calibration checks performed over a one year period on all of the-RPS Rosemount and Magnetrol instrumentation. Review of these calibration checks showed that the quarterly drift is within the present calibration tolerances. As a result, PNPP has concluded that. lengthening the CHANNEL FUNCTIONAL TEST interval _and analog trip module calibration' interval, as applicable, for the RPS instruments from veekly or monthly to quarterly i vill not result in excessive instrument drift relative to the current,_

established setpoints. In addition, a CHANNEL CHECK-is required at-least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for those-instruments with redundant channels. These routine CHANNEL CHECKS will help identify excessive drift of the RPS instrumentation.

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Attech&:nt 1 PY-CEI/NRR-1496 L Page 5 of 33

3. Confirm that the differences between the RPS in the plant and the RPS of the generic analysis plant vere included in the plant specific analysis using the procedures of Appendix K of NEDC-30851P.

A plant specific analysis was performed by General Electric using the procedures of Appendix K of NEDC-30851P. The results of this analysis are documented in Enclosure 1. The analysis determined three differences existed which required either further engineering asses + ment or analysis.

The plant specific analysis performed these additional assessments or analysis and concluded that the differences did not significantly affect the improvements in plant safety obtained through the Technical Specification changes evaluated in NEDC-30851P.

Vith respect to NRC approval of plant-specific changes to the RPS Technical

Specifications-based upon NEDC-30851P, PNPP understands that the NRC has expressed concern that the specific changes to the ACTIONS proposed in NEDC-30851P vould allow continued plant operation for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months with a combination of failures which could prevent a particular reactor scram function from completing its logic when called upon. This.could occur for e relay-type plant (vith one-out-of-tvo-tvice logic) if, for example, both channels of the high reactor pressure function vere inoperable in one trip system [ this is one of the two RPS scram functions that are assumed to mitigate the Pressure-Regulator Failure-Increasing transient (see Table F-1 of NEDC-30851P)]. Actions 3.3.la and 3.3.lb and their footnotes have therefore been revised to aliminate this concern.

For 3.3.la, with one channel required by Table 3.3.1-1 inoperable in one or more Functional Unit (s) (i.e. any number of Functional Units having only one inoperable channel in each Functional Unit), the entire RPS scram capability remains intact, assuming no additional single failure.. The action which allows continued operation for'12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months was evaluated and-the reliability of the system shown to be acceptable in NEDC-30851P. Vithin 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months the inoperable channels and/or trip system must be placed in the tripped condition. This action restores the RPS capability to accommodate a single failure and allows operation to continue with no further restrictions. If the inoperable channel (s) and/or trip system is not placed in the tripped condition within the allowed time, then the ACTION required by Table 3.3.1-1 must be taken to place the plant in a condition that obviates any need for that inoperable channel's function.

For 3.3.lb, with two or more channels inoperable in any Functional Unit, the Reactor Protection System m_ag a not be capable of performing its intended function (e.g., a " loss of scram function" may exist, depending on which two (or more) channels are inoperable). In this condition, during the period allowed to place the inoperable channels and/or trip system in the tripped condition, if a valid trip signal was received, a failure.to automatically scram could result. In order to reduce the probability of this occurrence, the ACTION for this condition requires that steps be taken to ensure each required Functional Unit maintains trip capability within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . This time period allows the operator time to evaluate, to repair or to trip the channels. This time period is reasonable considering the diversity of sensors available to provide trip signals, and the low probability of an event .

i- requiring the initiation of a scram. This time period is also. consistent with the current Technical Specifications which address this condition. In i

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' Attachmsnt 1 PY-CEI/NRR-1496 L Page 6 of 33

) addition, if it has been verified that a loss of scram function situation does 3

not exist, an_ allowance of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is provided in order toirestore a level of i~ RPS Reliability equivalent to that provided by ACTION a. The requirement to pla:e the inoperable channel (s) in one Trip System (or one entire Trip-System), in the tripped condition limits the time the RPS scram _ logic for_any

- Functional Unit vould not accommodate a single failure in either Trip System.

The 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months time period is considered acceptable based on the remaining l capability to trip, the diversity available to provide trip signals, the lov- _

4 probability of extensive numbers of inoperabilities affecting all diverse 4

functions, and the low probability of an event requiring the initiation of a-I scram. By the end of the six hour period, each Functional Unit vill either i have all required channels OPERABLE, or at least one Trip System vill have its inoperable channels placed into the tripped condition. This provides a j similar level of RPS reliability as found in Action a, above, and_ evaluated in NEDC-30851P to be acceptable for a 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allovable outage time. Vithin 12 l

hours, all the inoperable channels in the other trip system vill have been j restored to OPERABLE status, or else the inoperable channels vill be placed in i trip. For all of the proposed ACTIONS, if the inoperable channels are not placed in trip within the allowed time, then the ACTION required by Table ,

3.3.1-1 must be taken, which, places the plant in a condition 1that obviates any

. ~

j g need for the inoperable channels' function.

[ Basis For No Significant Hazards Consideration In accordance with 10CFR50.92, a proposed change to_the operating license (Technical Specifications) involves no significant hazards considerations if-

operation of the facility in accordance vith the proposed change vould not -

g (1) involve a significant increase in the probability or consequences of any a accident previously evaluated, or_(2) create the. possibility of a new or different kind of accident from any accident previously evaluated, or

_ (3) involve a significant reduction in a margin of safety.-.-The proposed RPS j Technical Specification changes are evaluated against each of these criteria below.

l (1) These proposed changes do not involve a change to-the plant design or- .

operation, they simply involve the frequency at which. testing.of the RPS

! instrumentation is performed and the allovable outage time'(A0T) for instruments. Failure of the RPS instrumentation itself cannot create an accident. As a result, these proposed changes cannot increase the probability of occurrence of any. design basis accident'previously-evaluated.

proposed change increase the average-

' As identified in NEDC-30851P,_thesp/ year-to 5.4x10'p/ year. -This increase-RPSfajlurefrequencyfrom4.6x10' (8x10' / year) is considered to be insignificant. As identified.in_the

-NRCLStaff's Safety Evaluation Report of__NEDC-30851P, this increase in average RPS' failure _ frequency would contribute to a very small: increase

in core-melt frequency. The small increase in average RPS failure-d frequency is offset'by safety benefits such as_a reductiontin the number-of inadvertent test-induced scrams,la reduction in wear.d.ue to: excessive-equipment test cycling, and better optimization of plant' personnel L resources. Hence, the net change in risk resulting from these proposed 4

- - ~ -

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Attachm:nt 1 PY-CEI/NRR-1496 L Page 7 of 33 l

changes vould be insignificant. Therefore, these proposed changes do not result in a_significant increase in either the probability or the consequences of any accident previously evaluated.

(2) The proposed changes do not result in any change to the plant design or operation, only to the A0T and frequency at which testing of the RPS instrumentation is performed. Since failure of the RPS instrumentation itself cannot create an accident, these proposed changes can at most affect only accidents which have been previously evaluated. Therefore, these proposed changes cannot create the possibility of a new or 4

different kind of accident from any accident previously evaluated.

(3)Asidentifiedabove,theseprogosedchangesinegeasetheaverageRPS failure frequency from 4.6x10~ / year to 5.4x10 / year. The NRC Staff's Safety Evaluation Report of NEDC-30851P cencluded that this small average RPS failure frequency increase vould contribute to a very small increase in core-melt frequency. This small increase in average RPS failure frequency vould be offset by safety benefits such as a reduction in the number of-inadvertent test-induced scrams, a reduction in wear due to excessive equipment test cycling,.and better optimization of plant personnel resources. ,Hence, the net change in risk resulting from_these proposed changes would be insignificant. In addition, PNPP has confirmed that the proposed changes to the functional test intervals vill not :

result in excessive instrument drift relative to the current, established setpoints. Therefore, these proposed changes do not result in a 2 significant reduction'in a margin of safety. .

Based upon the foregoing, PNPP concludes that these proposed changes do not involve a significant hazards consideration.

4

I Attach::nt 1 PY-CEI/NRR-1496 L Page 8 of 33 Part II - Emergency Core Cooling System (ECCS)

Description of Proposed Changes The following changes to Technical Specification 3/4.3.3, " Emergency Core Cooling System Actuation Instrumentation," are proposed

1. The surveillance A0T of footnote (a) to Tecnnical Specification Table 3.3.3-1 is being increased from two hours to six hours.

2. The repair allovable outage times (A0Ts) of Technical Specification Table 3.3.3-1, " Emergency Core Cooling System Actuation Instrumentation,"

Actions 30, 32, 34, 35, 36, and 39 are being increased from one hour to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ; Action 33 is being increased from eight hours to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ; and Action 31 is being identified as 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

3. The surveillance test interval (STI) for CHANNEL FUNCTIONAL TESTS specified on Technical Specification Table 4.3.3.1-1, " Emergency Core

, Cooling System Actuation Instrumentation Surveillance Requirements," is being increased from monthly (H) to quarterly (0) for the following Trip ,

Functions:

I

a. item A.1.a. Division 1 Trip System RHR-A (LPCI Mo'de) and LPCS System, Reactor Vessel Vater Level - Lov, Level 1,'

b. item A.1.b, Dryvell Pressure - High,

c. item A.1.c, LPCS Pump Discharge Flov - Lov (Bypass),

d. item A.1.d, Reactor Vessel- Pressure - Lov (LPCS Injection Valve Permissiv.),

e. item A.1.e, Reactor Vessel Pressure - Low (LPCI Injection Valve Permissive),

f. item A.1.f, LPCI Pump A Start Time Delay Relay,

g. item A.1.g, LPCI Pump A Discharge Flov - Low (Bypass),

h. item A.2.a. Division 1 Trip System, Automatic Depressurization System Trip System "A", Reactor Vessel Vater Level - Lov, Level 1,

i. item A.2.b, Manual Inhibit, J. item A.2.c, ADS Timer,

k. item A.2.d, Reactor Vetsel Vater Level - Lov, Level 3 (Permissive),

1. item A.2.e, LPCS Pump Discharge Pressure - High (Permissive),

m. item A.2.f, LPCI Pump A Discharge Pressure - High (Permissive),

n. item B.1.a, Division 2 Trip System, RHR B and C (LPCI Mode), Reactor Vessel Vater Level - Lov, Level 1,

o. Item B.1.b, Dryvell Pressure - High,

, p. item B.1.c, Reactor Vessel Pressure - Lov (LPCI Injection Valve Permissive),

q. item B.l.d, LPCI Pump B Start Time Delay Relay, r, item B.1.a. LPCI Pump Discharge Flov - Lov (Bypass),

s. item B.2.a, Division 2 Trip System, Automatic Depressurization System Trip System "B", Reactor Vessel Vater Level Lov, Level 1,

t. item B.2.b, Manual Inhibit,

u. item B.2.c, ADS Timer,

v. Item B.2.d, Reactor Vessel Vater Level - Lov, Level 3 (permissive),

v. item B.2.e, LPCI Pump B and C Discharge Pressure - High l (Permissive),

l I

Attachm2nt 1 PY-CEI/NRR-1496 L Page 9 of 33

x. item C.l.a, Division 3 Trip System, !!PCS System, Reactor Vessel Vster Level - Lov, Level 2,

y. item C l.l, Dryvell Pressure - High,

z. item C.l.c, Reactor Vessel Vater Level - High, Level 8, aa. item C l.d, Condensate Storage Tank Level - Lov, bb. item Col.e, Suppression Pool Vater Level - High, cc. item C.l.f,.HPCS Pump Discharge Pressure - High, and dd. item C.l.g, HPCS System Flow Rate - Lov.

4. The analog trip module calibration interval specified by footnote (a) to Technical Specification Table 4.3.3.1-1 is being increased from 31 days to 92 days.

J_ustification for Proposed Changes 4

On July 23, 1987 the BVROG submitted Licensing Topical Report NEDC-30926P, "BVR Owners' Group Technical Specification Improvement Methodology (vith Demonstration for BVR ECCS Actuation Instrumentation) Part 2," for NRC review.

This report provides justification for the proposed changes identified as -1 through 4 above. Similar to the RPS report discussed in Part I of this

' submittal, the analyses documented in NEDC-30936P 1Part 2) utilized fault tree I modeling (based upon a BVR-5/6 relay plant design) 'o estimate the impact of

the proposed changes on the average water injection Utnction failure '

frequency.

The calculation of average water injection failure frequency depends on two sets of parameters. The first set consists of initiating events vhich i eventually call for water injection. The second set consists of the' l probability that the water injection function is unavailable given a demand for injection. Depending on each initiating event, the number of components that are needed for successful completion of the vater injection function varies. Therefore, the water injection unavailability for a given initiating event may differ from that of another initiating event.

A function fault tree was developed for each initiating event in order to quantify the water injection unavailability per demand. The function fault tree modeled the logical relationship of the faults that contribute to the water. injection unavailability. The function fault tree was used to estimate-t the water injection unavailability based upon the current. Technical Specification requirements and the effect of proposed changes. The results were considered acceptable by the BVROG if the proposed changes resulted in less than a 4% increase in the average water injection' failure frequency.

The only initiating events studied in this analysis vere loss of offsite power (LOOP) initiating events. The LOOP ever t was chosen for consideration because,- based on prior Probabilistic Risk Assessment calculations, LOOP. i events contribute from 40% to 90% of the calculated core damage frequency for most BVRs. Also, the LOOP analysis is a more severe test of ECCS actuation instrumentation than other accident sequences such as turbine trip, loss of feedvater, and recirculation pump failure. Therefore, the effect of the proposed changes on water injection unavailability and failure frequency for ,

the LOOP initiating event vill dominate contributions for all initiating j events. a i

j

l Attachmnt 1-4 PY-CEI/NRR-1496 L )

Page 10 of 33 l By letter of Charles E. Rossi (NRC) to Donald N. Grace (BVROG) dated December 9, 1988, the NRC provided their Safety Evaluation Report of

NEDC-30936P (Part 2). The NRC concluded in their Safety Evaluation Report that the methods and acceptance criteria provided in NEDC-30936P (Part 2) are acceptable for implementation on a plant-specific basis. However, the NRC's Safety Evaluation Report states that in order for a licensee to use the generic analyses provided in NEDC-30936P (Part 2), the licensee must confirm the applicability of the generic analysis to the plant and: onfirm that any

, increase in instrument drift due to the extended surveillance intervals is properly accounted for in the setpoint calculation methodology.

In addition to NEDC-30936P (Part 2), a letter clarifying the ECCS Actuation Instrumentation Technical Specification Changes was submitted to the NRC staff

by the GE BVROG on March 22, 1990 (Enclosure 2). This letter, OG 90-319-32D, ,

has been incorporated into the changes being submitted.

A generic BVR-5/6 Relay plant was modeled in NEDC-30936P (Part 2). In addition, Section 5.5 of NEDC-30936P (Part 2) documented the analyses of three other enveloping cases to model known differences in either. instrumentation logic or support system configuration. GE conducted a PNPP plant specilic ECCS review to determine the extent of differences between PNPP and the generic model. This review was documented in RE-028 Revision 1, December 1991

" Technical Specification Improvement Analysis for the Emergency Core Cooling I

System Actuation Instrumentation fer Perry Nuclear Power Plant, Units 1 and 2." (Enclosure 3) The results of this review are noted in Section 3 of this-l report and indicate the,re vere four dif ferences between the generic model and l PNPP. One of the enveloping cases (Case SC) of Section-5.5 of NEDC-30936P (Part 2) was determined to bound the PNPP differences. Therefore, the generic

! analysis is applicable to PNPP. As indicated in Table 5-6 of NEDC-30936P (Part 2), the water injection function frequency for case 5C vith current TS is 1.386E-4 per year and this value is changed by 1.1% (to 1.401E-4 per year)

! when the STIs are increased to quarterly, test A0Ts are increased to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , l and repair A0Ts are increased to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . This small increase in failure frequency is within the acceptability guidelines of NEDC-30936P (Part 2)..

With respect to the NRC's concern about instrument drift over a 3 month l (quarterly) period, the ECCS actuation instrumentation setpoint calculations l

at PNPP include the effects of drift over 18 months for all instrument loop components. To verify drift of the analog trip modules, PNPP reviewed the results of monthly calibration checks performed over a one-year period on the affected ECCS actuation analog trip modules. y Review of these calibration checks showed that the quarterly drift is-within the present calibration tolerances. As a result, PNPP has concluded that lengthening the CHANNEL PUNCTIONAL TEST interval and ' analog trip module calibration _ interval, as applicable, for the_ECCS actuation instruments from monthly to_ quarterly vill not result in excessive drift relative to the current, established setpoints.

In addition, a CHANNEL CHECK is required at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for those instruments with redundant channels. These routine CHANNEL' CHECKS will help to identify excessive drift of the ECCS actuation instrumentation.

l

Attecha nt 1 PY-CEI/NRR-1496 L Page 11 of 33 Basis For No Significant Hazards Consideration In accordance with 10CFR50.92, a proposed change to the operating license (Technical Specifications) involves no significant hazards considerations if operation of the facility in accordance with the proposed change vould nots (1) involve a significant increase in the probability or consequences of any accident previously evaluated, or (2) create the possibility of a new or different kind of accident from any accident previously evaluated, or (3) involve a significant reduction in a~ margin of safety. The proposed ECCS actuation instrumentation Technical Specification changes are evaluated against each of these criteria below.

(1) These proposed changes do not involve a change to the plant design or operation, only to the allovable outage time (A0T) and frequency at which testing of the ECCS instrumentation is performed. Failure of the ECCS actuation instrumentation itself cannot create an accident. As a result, these proposed changes cannot increase the probability of any acciden*

previously evaluated.

As identified in NEDC-30936P (Part 2), these proposed changes increase the calculated average water injection failure frequency from 1.386E 4/ year to 1.401E-4/ year. This represents an increase of 1.5E-6/ year (1.1%), which is well within the acceptance criteria (4%).

4 provided in NEDC-30936P (Part 2) and the NRC's Safety Evaluation Report.

This small increase in average water injection failure frequency is offset by benefits such as a reduction in the number of' inadvertent test-induced scrams and engineered safety featur'e actuations, a reduction -

in vear due to excessive test cycling, and better optimization of plant personnel resources. Hence, the net change in risk resultinc from these proposed changes would be insignificant. Therefore, these proposed changes do not result in a significant increase in the probability or the consequences of any accident previously-evaluated.

(2) These proposed changes do not result in any change to the plant design or operation, only to the A0T and frequency at which testing of the ECCS ,

instrumentation is performed. Since failure of the ECCS actuation instrumentation itself cannot create an accident, these proposed changes can at most affect only accidents which have been previously evaluated.

Therefore, these proposed changes cannot create the possibility of a new or different kind of accident from any. accident previously evaluated.

(3) As identified above, these proposed changes increase the calculated average water injection failure frequency frem 1.386E-4/ year to 1.401E-4/ year. This increase is well within the acceptance criteria found acceptable in the NRC Staff's Safety Evaluation Report for NEDC-30936P-(Part 2). Further, this small increase in average water injection failure frequency would be_ offset by safety benefits such as a reduction in the number of inadvertent test-induced scrams and engineered safety feature-actuations, a reduction in vear due to excessive test cycling. and better optimization of plant personnel resources. In addition, PNPP has confirmed that the proposed changes to the functional I

4 Attachment 1 PY-CEI/NRR-1496 L 4

Page 12 of 33 test intervals vill not result in excessive instrument drif t relative to

, the current, established setpoints. Therefore, these proposed changes do not result in a significant reduction in a margin of safety.

Based on the foregoing, PNPP concludes that these proposed changes do not involve a significant hazards consideration.

1

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Attach:2nt 1 PY-CEI/NRR-1496 L Page 13 of 33 l-Part III - Control Rod Block Description of Proposed Changes l

! The following changes to Technical Specification 3/4.3.6, " Control Rod Block Instrumentation," are proposed *:

! 1. The CHANNEL FUNCTIONAL TEST interval _specified on Technical Specification l Table 4.3.6-1, " Control Rod Block Instrumentation Surveillance- '

4 Requirements," is being increased from monthly (H) to quarterly (0) for

the following Trip Functions:

) a. item 1.a, Rod Pattern Control System, Low Power Setpoint,

b. item 1.b, Rod Pattern Control System, RVL High Pover Setpoint,

c. Item 2.a. APRM Flov Biased Neutron Flux -Upscale. [1) and 2)]

! d. item 2.b, APRM Inoperative,

! e. item 2.c, APRM Downscale, i f. item 2.d, APRM Neutron Flux - Upscale, Startup, .

i . g. item 5.a, Scram Discharge Volume, Vater Level - High, and

h. item 6.a, Reactor _ Coolant System Recirculation Flov, Upscale.

1

2. Theanalogtripmodulecalibrationintervalspecifiedby! footnote #to Technical Specification Table 4.3.6-1 is being increased ;from 31 days to 92 days.

l

Additienal chcnges_to Technical Specification.3/4.3.6 ard proposed in

~

Part V of this submittal.-

l I Justification for Proposed Changes i

j On June 23, 1986 the BVROG submitted Licensing Topical Report NEDC-30851P,

Supplement 1, " Technical Specification Improvement Analysis-for-BVR Control-j Rod Bluck Instrumentation," for NRC review. .This report provides7

+

-justification for each of the proposed changes identified above.

t

[ Unlike the analyses discussed in Parts I and II of-this submittal, no~ specific fault trees were developed for the control. rod' block instrumentation.-

'. Instead, the impact on the average. control rod block failure rate was .

! estimated based upon-the results of the RPS instrumentation analyses presented j in Part I of this_ submittal. 'This approach vas:taken-because the Reactor

! Protection System-(RPS) and control rod block functions share common j instrument inputs.-

4 i The BVROG report determined ghat the average control rod block failure rate i vould increase less than 10' / year.(0.06%) from_the. current failure rate of 0.16/ year (based on industry experience). NEDC-30851P, Supplemant'1. states that the benefits associated with th2 proposed changes to the RPS and control rod block instrumentation offset any potentia 1' negative impact of extending the control rod-block instrumentation test-intervals.-

I.

By letter from Charles E. Rossi (NRC) to Donald N. Grace (BVROG)' dated

-September 22, 1988, the NRC provided their Safety. Evaluation Report of NEDC-30851P, Supplement 1. The NRC' concluded in their_ Safety Evaluation Report that_NEDC-30851P,. Supplement 1.provides-an. acceptable basis for-

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Attachmant 1 PY-CEI/NRR-1496 L Page 14 of 33 implementing the above proposed control rod block instrumentation changes.

However, the NRC's Safety Evaluation Raport states that in order for a licensee to use the generic analyses provided in.NEDC.-30851, Supplement 1, the licensee must confirm the applicability of the generic analyses to the plant and confirm that any increase in instrument drift due to the-extended ,

intervals is properly accounted for in the setpoint calculation methodology. 1 PNPP has confirmed that the control rod block instrumentation configuration ,

(described in NEDC-30851P and Supplement 1 as the Rod Control and Information System) is identical to that.at PNPP. As a result, the-analyses presented in NEDC-30851P, Supplement I are directly applicable to PNPP.

Vith respect to the NRC's concern about instrument drift over the'3 month '

(quarterly) period, the control rod block instrumentation setpoint calculations at PNPP include the effect of instrument drift over 18 months for all instrument loop components. In addition,.PNPP reviewed the results'of

~

monthly calibration checks performed over a one-year period on the affected control rod block Rosemount and Magnetrol instrum'entation'. Review of these calibration checks showed that_the quarterly drift is vithin the present calibration tolerances. As a result, PNPP has concluded that lengthening.the CHANNEL FUNCTIONAL TEST interval _and analog trip' module calibration interval, ~

as applicable, for'the control rod block instrumentation from monthly to quarterly vill not result'in excessive drift r_ elative to the current, established setpoints. In addition, a CHANNEL CHECK'is required'ut least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for those instruments with redundant channels. -These routine CHANNEL CHECKS vill help to identify excessive drift of the control rod block instrumentation.

Basis For No Significant Hazards Consideration 4

4 In accordance-with 10CFR50.92, a proposed change to the operating license l (Technical Specifications) involves no significant hazards considerations if l- operation of the facility in accordance vith the proposed change vould nott (1) involve a significant increase-in the probability.or consequences of'any

. accident previously evaluated .or (2) create.the possibility: of a new or

! different kind of accident from-any. accident previously evaluated,'or,(3)-

l- invol ve a significant reduction in a margin of safety. The proposed control i rod block instrumentation. Technical' Specification changes;are' evaluated'

i. against-each of~these criteria-below.

(1) These proposed changes do not involve a change _to?the_ plant design or

- operation, only to the allovable outage time (A0T)'and-frequency at-which testing of the' control rod block instrumentation is performed. > Failure 3 of the control rod block instrumentation itself cannot create"an >

accident. As a result, these proposed changes cannot increase 1 the' probability of any accident previously evaluated.

l '

As identifled'in NEDC-30851P, Supplement-1,-these proposed changes increase _the average control' rod block failure frequency less than-0.06%.

As provided in_the NRC. Staff's: Safety Evaluation Report'of NEDC-30851P, Supplement 1, this increase-is very slight and is offset by the safety benefits associated with the proposed' changes.'o'the RPS and control rod block instrumentation. .As-a result, the combined effect--of!the changes proposed for the RPS andicontrol rod block' instrumentation requirementsL

_ __ _ . . . - - . . _ , , . -_..s.. . ~u - _ , . . _ _ _ _ _ . ._

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

i i Attachusnt 1

PY-CEI/NRR-1496 L' .3 1 Page 15 of 33 j

' should result in an overall improvement in-plant safety._ Therefore, .

these proposed changes do not result in a significantiincrease in.the )

^

probability or-the consequences of any accident previously evaluated.

i 1

(2) These proposed changes do not result in any change to the plant design or operation, only to _ the A0T and f requency' at 'which tes ting. of-_ the control - ~

j rod block instrumentation is performed. Since failure of the control rod :i

block instrumentation itself cannot create an accident, these proposed _

! changes can at most.affact_only accidents whichLhave,been previously l evaluated. Therefore, these proposed-changes cannot create _the-- l possibility of a new or different kind of accident from-any. accident' l previously evaluated.

(3) As identified above,.these proposed chany 4 increase the average control 3

rod block failure frequency less:thar L - This increase-is very.

slight and is offset by the safety benef. . _ssociated with the proposed

" ~

changes to-the RPS'and control rod block inscrumentation. As a result,-

j- the combined.effect of the. changes _ proposed for the RPS and. control rod- -

block instrumentation requirements should result in an-overall f . improvement.in plant safety. In addition,-PNPP has confirmed-that the-f proposed changes to the functional test intervals vill not result in excessive instrument drift relative to the current, established

[

setpoints. Therefore, these proposed _changre do_nSt, result in a 4 significant teduction in a margin of; safety..

i l Based on the foregoing, ,PNPP concludes that'these proposed changes _do not 4

involve a significant hazards consideration. -

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Attachmsnt 1 PY-CEI/NRR-1496 L Page 16 of 33 Part IV - Isolation Actuation Instrumentation Description of Proposed Changes j

i The following changes to Technical Specification 3/4.3.2, " Isolation l Actuation Instrumentation," are proposed: - ,

3 I

1. Actions b and c have been revised-to_ provide a repair allovable outage

time (A0T) of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for trip functions common to RPS, and of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months i for trip functions not common to RPS.

2. The Surveillance A0T identified in footnote (a) to Technical Specification Table 3.3.2-1, " Isolation Actuation Instrumentation," is being increased from.two hours to six hours.

! 3. The surveillance test interval (STI) for CHANNEL FUNCTIONAL TEST's 4 specified on Technical Specification Table 4.3.2.1-1, " Isolation i Actuation Instrumentation-Surveillance Requirements," is being increased

from monthly (M) to quarterly (0) for the following Trip Functions

9 Item 1.a, Primary Containment Isolation, Reactor Vessel Vater Level

} , - Lov, Level 2, item 1.b, Dryvell Pressure - High, t

h.

c. item 1.c, Containment and Dryvell Purge Exhaust Plenum Radiation -

i ,

High, _ _

l d. item 1.d, Reactor Vessel-Vater-Level - Lov, Level 1,.

e. item 2.a, Main Steam Line Isolation, Reactor Vessel Vater Level -

Lov, Leve? 1.-

f. item 2.b, Main Steam Line Radiation 'High,

g. item 2.c, Main. Steam Line Pressure - Lov, i h. item 2.d, Main Steam Line Flov - High,

i. item 2.e, Condenser Vacuum -;Lov,

j. item 2.f, Main _ Steam Line_ Tunnel-. Temperature - High,

k. item 2.g, Main Steam Line Tunnel Delta Temperature - High,__

~

l. Item 2.h, Turbine Building: Main Steam Line Temperature =High,_

., m. item 3.a, Secondary Containment Isolation,. Reactor Vessel' Vater -

l Level - Lov, Level.2,_

n.- item 3.b, Dryvell Pressure - High,.

o. item 4.a, Reactor Vater Cleanup System Isolation, Delta-Flov - High

p. Item 4.b,. Delta Flov-Timer, i q. item 4.c., Equipment-Area Temperature --High,

r. item-4.d., Equipment: Area Ventilation Delta Temperature - High, 1

s. -item 4.e, Reactor Vessel Water Level - Lov, Level 2, -!

t. Item 4.f, Main: Steam Line Tunnel Ambient Temperature - High,

u. item 4.g,: Main Steam _Line Tunnel Delta' Temperature --High,-

v. item 4.h, SLCS~_ Initiation, L - v. item 5.a Reactor Core Isolation Cooling System Isolation,.RCIC i- Steam Line. Flow - High, ~

x. item 5.b, RCIC. Steam Supply; Pressure' 'Lov,

y, item 5.c, RCIC Turbine Exhaust' Diaphragm Pressure -;High,

z. Item 5.d,:RCIC Equipment-Room Ambient _ Temperature.- High,.

aa. item 5.e, RCIC' Equipment Room Delta Temperature - High,- -

- bb. Item 5.f Main Steam Line Tunnel Ambient Temperature: - High, i- -cc. Item 5.g, Main Steam Line Tunnel Delta Temperature-- High, i

4- W - - - a-. - - + = w r w v y-ar 7 - y=

Attachmint 1 PY-CEI/NRR-1496 L Page 17 of 33 dd. item 5.h, Main Steam Line Tunnel Temperature Timer, ee. item 5.1, RHR Equipment Room Ambient Temperature - High, ff. item 5.j, RHR Equipment Room Delta Temperature - High, gg. item 5.k, RCIC Steam Line Flow - High Timer, hh. item 5.1, Dryvell Pressure - High, ii. item 6.a, RHR System Isolation, RHR Equ2pment Area Ambient Temperature - High, jj. item 6.b, RHR Equipment Area Delta Temperature - High kk. item 6.c, RHR/RCIC Steam Line Flov - High,

11. item 5.d, Reactor Vessel Vater Level - Lov, Level 3, J mm. itec 6.e, Reactor Vessel (RHR Cut-in Permissive) Pressure - High, and nn. item 6.f., Dryvell Pressure - High.

4. The staggered test interval specified by footnote (a) to T;.chnical Specification Table 4.3.2.1-1 is being increased from 31 days to 92 days.

5. The analog trip module calibration interval specified by footnote (b) to Technical Specification Table 4.3.2.1-1 is being increased from 31 days to 92 days. ,

6. A##footnoteisbeingadded[toTechnicalSpecificationTable4.3.2.1-1 to identify those TRIP FUNCTIONS which utilize instruments that are common to RPS TRIP FUNCTIONS.,

Justification For Proposed Changes On August 29, 1986 the BVROG submitted Licensing Topical Report NEDC-30851P, Supplement 2, " Technical specification Improvement Analysis for BVR Isolation Instrumentation Common to RPS and ECCS Instrumentation," for NRC review. On June 27, 1989 the BVROG submitted Licensing Topical Report NEDC-31677P,

" Technical Specification Improvement Analysis for BVK Isolation Actuation Instrumentation," for NRC review. The combination of the rasults from these

, two reports provides justification for the proposed changes identified as 1 through 6 above.

As stated in NEDC-30851P, Supplement 2, Technical Specification requirements for isolation instrumentation vere originally established largely on the basis of RPS and ECCS requirements. That is, the surveillance test intervals and allovable outage times generally do not need to be more stringent for isolation instruments than for RPS or ECCS instruments. Even though isolation is a safety function, failure to isolate vould not of itself result in an l accident. The overall containment and reactor vessel isolation function is I made up of several'. subfunctions, each of which must operate upon demand during l an accident. Failure of an isolation subfunction during an accident could potentially increase the offsite release risks. l The analysis presented in NEDC-30851P, Supplement 2 applies only to those Isolation Actuation instruments which are common to the RPS or-ECCS actuation instruments. Similar to the analyses discussed in Parts I and II of this submittal, fault trees vere developed for the instruments in each of the common isolation Trip Functions. These fault trees were then evaluated probabilistically to determine the impact of the proposed changes on isolation

Attcch :nt 1 PY-CEI/NRR-1496 L

' Page 18 of 33 unavailability. The proposed change for the repair allovable outage time is 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for those instruments common to RPS, and 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for instruments

, common to ECCS. Other proposed changes are consistent with those discussed in both the RPS and ECCS Topical Reports. As provided in NEDC-30851?, Supplement 2, the impact on the average isolation unavailability for the affected isolation instruments due to the proposed changes to Surveillance test intervals was determined to be negligible (an increase of less than 1%) when 4 combined with the individual valve failure probabilities. The analyses demonstrate that the individual valve failure probabilities dominate the overall isolation failure probability. NEDC-30851P Supplement 2 also determined that extending the A0Ts has less than a 2% effect on the probability of failure of the isolation function given the demand.

4 By letter from Charles E. Rossi (NRC) to Donald N. Grace (BVROG) dated January 6, 1989, the NRC provided their Safety Evaluation Report of NCDC-30851P, Supplement 2. The NRC concluded in their Safety Evaluation Report that the methods and results provided in NEDC-30851P, Supplement 2 are acceptable for implementation on a plant-spec 1 9 c basis. However, the NRC's l Safety Evaluation Report states that in order for a licensee to use thu generic analyses provided in NEDC-30851P, Supplement 2, the licensee must ,

confirm that any increase in instrument drift due to the extqnded surveillance intervals is properly accounted for in the setpoint calculat(on methodology.

With respect to the NRC Staff's concern about confirming the' plant-specific applicability of NEDC-30851P, Supplement 2, the PNPP configuration for Isolation Actuation Instrumentation Common to RPS and ECCS is essentially the s'me a as the generic conff$aration modeled in NEDC-30851, Supplement 2 (identified as Bkk 5/6 (Kelay) Plani. Any differences are within those noted in Section 3.2 of Supplement 2. Therefore, the generic results are directly applicable to PNPP.

a Vith respect to the NRC's concern about instrument drift over the 3 m: nth (quarterly) period, the Isolation Actuation instrumentation setpoint calculations at PNPP include the effects of instrument drift over 18 months for all instrument loop components. In addition, PNPP reviewed the results of monthly calibration checks performed over a one-year period on the affected Isolation Actuation analog trip modules which are common to RPS or ECCS.

Review of these calibration checks shoved that the quarterly drift is within the present calibration tolerances. As a result, PNPP has concluded that lengthening the CHANNEL FUNCTIONAL TEST interval and analog trip module calibration interval, as applicable, for the Isolation Actuation instrumentation common to RPS or ECCS from monthly to quarterly vill not result in excessive drift relative to the current, established setpoints. In addition, a CHANNEL CHECK is required at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for those instruments with redundant channels. These routine CHANNEL CHECKS vill help to identify excessive drift of the Isolation Actuation instrumentation.

The analysis presented'in NEDC-33677P applies to the remaining Isolation Actuation Trip Functions (i.e., those Isolation Actuation instruments which are not common to RPS or ECCS actuation instrumentation). Similar to previous analyses discussed above, the analyses presented in NEDC-31677F are based upon fault trees which were evaluated to determine the impact of the proposed changes on the average isolation failure frequency. In this case, the average-

. isolation failure frequency is defined as the product of the accident 4

-e- , 4r-e ,

Attschmant 1 PY-CEl/NRR-1496 L Page 19 of 33 initiating event frequency (such as a pipe break or high radiation event) and the probability of failure of the isolation function given a demand. The proposed changes vere considered acceptable by the BVROG if-the proposed changes results in less than a 10% increase in the. average isolation failure frequen 1.0x10~9y or if the average failure frequency was calculated to be less than

/ year.

The results for the BVR 5/6 (Relay) plant demonstrate that these proposed changes only slightly increase the overall average isolation failure frequency for these instruments. As identified on Table 5-2 of NEDC-31677P, the calculated average isolation failure frequency actually decreases by 1.97x10-8 per year and hence clearly meets the above acceptance criteria.

By letter from Charles E. Rossi (NRC) to S. D. Floyd (BVROG) dated June 18, 1990, the NRC provided their Safety Evaluation Report of NEDC-31677P. 'the NRC concluded in their Safety Evaluation Report that the methodology and acceptance criteria provided in NEDC-31677P are acceptable for implementation on a plant-specific basis. However, the NRC's Safety Evaluation Report states that in order for a licensee to use the generic analyses presented in NEDC-31677P, the licensee must confirm the applicability of the generic analyses to the plant and confirm that any increase in instrument drift due to the extended surveillance inta vals is properly accounted for 3n the setpoint calculation methodology.

Vith respect to the NRO staff request to confirm the plant - specific applicability of NEDC-31677P, section 5.5 of the NEDC discusses the application of the review to other plants, and provides Appendix C which indicates the plant specific requirements. As can be seen in Appendix C, Perry i:: one of the plants included in this Table. PNPP has verified that the Table is accurate and-therefore the conclusion given in section 5.5 of the NEDC document that the proposed STI and A0T changes are applicable to Perry is acceptable.

Vith respect to the NRC's concern about instrument drift over the 3 month (quarterly) period, the Isolation Actuation instrumentation setpoint calculations a PNPP include the effects of instrument drift over 18 months for all instrument loop components. In addition, PNPP reviewed the results of monthly calibration checks performed over a one-year period on-the affected Isolation Actuation Rosemount and Riley instrumentation which are not common to RPS or ECCS. Review of these calibration checks showed that the quatterly drift is within-the present calibration tolerances. As a result, PNPP has concluded that lengthening the CHANNEL FUNCTIONAL TEST interval and analog trip module calibration interval, as applicable,_for the Isolation Actuation instrumentation not common to'RPS or ECCS from monthly to quarterly vill not result in excessive drift relative to the current. established setpoints. In.

addition, a' CHANNEL CHECK is required at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for those instruments with redundant chwnnels. These routine CHANNEL CHECKS will help to identify excessive drift of the Isolation Actuation instrumentation.

ACTION statements 3.3.2.b and 3.3.2.c have been reviseo to meet the intent of the changes described to the NRC staff in a letter from the BVROG to the NRC staff, OG90-579-32A dated June 25, 1990 (Enclosure 4).- FNPP has changed the.

proposed ACTION statements-to meet the intent of this letter, but has

i Attachm:nt 1 PY-CEI/NRR-1496 L Page 20 of 33 rearranged the vording to add clarification, and to be more consistent with the present PNPP Technical Specification format and with the format of the RPS Instrumentation Specification proposed in Attachment 2, pages 1 and 2.

The differences between this proposal and the example contained in the June 18, 1990 NRC SER are as follows:

1. The example markup of the 3.3.2 Specification in the June 18, 1990 NRC SER incorporated the

footnote into ACTIONS b.1 and b.2. Enclosure (4) recommended that the other footnote of Specification 3.3.2 also be incorporated into the ACTION statements. However, PNPP has proposed keeping the footnotes, and rewording them to be consistent with the proposed wording of the footnotes in the RPS Instrumentation section.

This vill provide clarity and maintain consistency between these Specifications.

i 2. ACTIONS b.1 and b.2 have been combined into one action, ACTION b. As stated in Enclosure (4), the primary reason why two A0Ts had been created in the Topical Report markup was to retain the current technical specification format while incorporating the footnotes into the ACTIONS, and there is no strong technical reason for retaining two A0T conditions.

In combining ACTIONS b.1 and b.2 into one action, the six hour repair ACT is no longer used since the analysis in NEDC-31677P supports the 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and 24 repair hour A0Ts for RPS and non-RPS instruments respectively, regardless of whether placing the inoperable instrument in trip would cause the trip function to occur. Therefore, the intent of the a,

recommendations'of Enclosure (4) have been incorporated into this proposal.

3. Enclosure (4) recommended changes to ACTION c of Specification 3.3.2 that vere not included in the example used in the June 18, 1990 NRC SER. The reason for the recommendation is to provide a more appropriate action when inoperable instruments are discovered in both trip systems.

Presently the actions specified in the SER example require that at least one trip system be placed in the tripped condition within one hour for this condition. Hovever, placing a trip system in the tripped condition vould in almost all cases isolate an important system, and therefore may not be the best action to take. A more appropriate action may be to trip the inoperable channel (s) without tripping the system. The PNPP proposed change thecefore requires that the inoperable channel (s) in one trip system, and/or that trip system, be placed in the tripped condition within one hour, and that the inoperable channel (s) in the other trip system be placed in the tripped condition within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months or 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for RPS and.non-RPS instrumentation respectively. These proposed PNPP actions are consistent with the intent of Enclosure (4), but some rewording has been done to make the wording consistent with that being proposed in the RPS Instrumentation section.

Basis For No Significant Hazards Consideration In accordance with 10CFR50.92, a proposed change to the operating license (Technical Specifications) involves no significant hazards considerations if operation of the facility in accordance with the proposed change would not:

(1) involve a significant increase in the probability or consequences of any

Attachm:nt 1 PY-CEI/NRR-1496 L Page 21 of 33 accident previously evaluated, or (2) create the possibility of a new or different kind _of accident from any accident previously evaluated, or (3) involve a significant reduction in a margin of safety. The proposed Isolation Actuation instrumentation Technical Specification changes are evaluated against each of these criteria below.

(1) The* 1 proposed changes do not involve a change to the plant design or

operation, only to the allovable outage time (A0T) and frequency _at which testing of the Isolation Actuation instrumentation is performed. Failure of the Isolation Actuation instrumentation itself cannot create an accident. As a result, these proposed changes cannot increase the probability of any accident previously evaluated.

As identified in NEDC-30851P, Supplement 2, the proposed changes to the surveillan e test interval requirements for the Isolation Actuation instruments which are common to RPS or ECCS have a negligible (less than 1%) impact on the average isolation unavailability when combined with the d

individual valve failure probability, and that the changes to the A0Ts has less than a 2% impact. The ant'.yses demonstrate that the individual ,

valve failure probabilities dominate the overall irolation failure

probability. As identified in NRC Staff's Safety Evaluation Report of NEDC-30851P, Supplement 2, these proposed changes vould have a very small impact on plant risk. As a result, overall plant safety is not reduced by these proposed changes.

As identified in NEDC-31677P, the proposed changes to the requirements for Isolation Actuation instrumgntation not common to RPS or ECCS result in a small decrease of 1.97x10' / year in the average isolation failure frequency. As identified in the NRC Staff's Safety Evaluation Report of NEDC-31677P, the NRC agreed that these proposed changes are acceptable because the failure frequency impact is minimal. . As a result, overall plant safety is not reduced by these proposed changes.

The small increase in the average failure frequency of the instruments common to RPS or ECCS due to the proposed-changes to the Isolation .

Actuation instrumentation requirements is offset by safety benefits such as a reduction in the number of inadvertent test-induced scrams and engineered safety feature actuations, a reduction in wear due to excessive test cycling, and better optimization'of plant personnel resources. Hence, the net change in risk resulting from these proposed changes would be insignificant. Therefore, the proposed changes do not represent a significant increase in the probability or the consequences of any accident previously evaluated.

(2) These proposed changes do not' result in any change to the plant design or operation, only to the A0T and frequency at which testing of the Isolation Actuation instrumentation is performed. Since failure of the Isolation Actuation instrumentation itself cannot create an accident, these proposed changes can at most affect only accidents which have been previously evaluated. Therefore, these proposed changes cannot create the possibility of a new or different kind of accident from any accident previously evaluated.

-.. . . - - .~ . . - _ . _ - - - . - . - . - .. . . . . ... . . - . . - .

i Attachmtnt-I

'PY-CEI/NRR-1496-L Page 22 of 33 4

(3) As identified above, these proposed changes to the requirements for Isolation Actuation instruments common'to RPS or ECCS have a negligible

! impact on the average isolation unavailability when. combined with the-- :

individual: valve failure probability. The analyses: demonstrate that.the i .. individual valve failure probabilities:domics.te the~overall isolation .

! failure probability. -The: proposed changes tofthe_ requirements for i

IsolationActuation-instrumentsnotcommontoRPSorECCSgecreasetheir-j- average-isolationJfailure frequency approximately l.97x10' / year.

The small increases in average Isolation Actuation. instrumentation failure frequency of the instruments common to RPS or ECCS are offset by safety-benefits-such as a reduction in.the number.of: inadvertent- .

test-induced scrams:and engineered safety feature actuations, a1 reduction j- in wear-due to excessive equipment-test: cycling, and better optimization

[ of plant personnel resources. As a' result, the NRC Staff'sl Safety J.

Evaluation Repcrts for these-BVROG reports: concluded that_these proposed changes vould have a very small impact on plant risk. In addition, PNPP j has confirmed that-the proposed changes-to the-functional test intervals

vill not result in exce.,sive instrument drlft relative to the current,.

8- established setpoints. Therefore, these proposed. changes ,do not result-in a significant'redu' tion [n a margin of safety.

! Based upon the foregoine . PNPP c'oncludes that.these proposed changes'do not involve a significant hazards co'nsideration, i t

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Attachacnt 1 PY '_2I/NRR-1496 L Page 23 of 33 Part V - Other Tectnical Specifiention Instrumentation Description of Proposed Changes 5

The following changes are proposed:

1. Technical Specification 3/4.3.4.1, "ATUS Recirculation Pump Trip System Instrumentation"

a. The repair allowable outage time (A0T) of Technical Specification 3.3.4.1 Action b and c.1 are being increased from I hour to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

b. The surveillance allovable outage time (A0T) of footnote (a) to Technical Specification Table 3.3.4.1-1, "ATVS Recirculation Pump Trip System Instrumentation," is being increased from two hours to six hours.

c. The surveillance test interval _(STI) for CHANNEL FUNCTIONAL TEST's specified on Technical Specification Table 4.3.4.1-1, "ATVS Recirculation Pump Trip Actuation Instrumentation Survqillance Requirements," is being increased from monthly (M) to quarterly (0) for the following Trip Functions: ,

(1) item 1, Reactor Vessel Vater Level - Lov, Level 2, and' (ii) item 2, Reactor Vessel-Pressure - High.

d. The trip unit calibration interval specified by footnote "*" to Technical Specification Table 4.3.4.1-1 is being increased from 31 days to 92 days. A typographical errot in footnote "*" is also being corrected.

2. Technical Specification 3/4.3.4.2, "End-of-Cycle Recirculation Pump Triy System Instrumentationd

a. The repair A0Ts of Technical Specification 3.3.4.2 Action b and c.1 are being increased from one hour to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ,

b. The surveillance A0T of footnote (a) to Technical Specification Table 3.3.4.2-1, "End-of-Cycle Recirculation Pump Trip System Instrumentation," is being increased from two hours to six hours.

c. The STI for CHANNEL FUNCTIONAL TESTS specif.ied on Technical Specification Table 4.3.4.2.1-1, "End-of-Cycle Recirculation Pump Trip System Surveillance Requireme7ts," is being increased from monthly (H) to quarterly (0) for c.ie toiloving Trip Functions:

(i)- item 1, Turbine Stop Valve - Closure, and (ii) item 2, Turbine Control Valve - Fast Closure.

l l

-l

- _ ~ _

A Attechm:nt 1 PY-CEI/NRR-1496 L Page 24 of 33

3. Technical Specification 3/4.3.5, " Reactor Core Isolation Cooling System Actuation Instrumentation" 4

a. The surveillance A0T of footnote (a) to Tschnical Specification Table 3.3.5-1 is being increased from two hours to six hours.

b. The repair A0Ts of Technical Specification Table 3.3.5-1, " Reactor Core Isolation Cooling System Actuation Instrumentation," Actions 50.a and 52 are beirg increased from one hour tc 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ; Action 53 is being increased from eight hours to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ; and Action 51 is being identified as 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

c. The STI for CHANNEL FUNCTIONAL TESTS specified on Technical Specification Table 4.3.5.1-1, " Reactor Core Isolation Cooling System Actuation Instrumentation Surveillance Requirements," is being increased from monthly (H) to quarterly (0) for the following Functional Units:

4 item a, Reactor Vessel Vater Level - Lov, Level 2, (i) 1

( * *. ) item b, Reactor Vessel Vater Level - High, Level 8, (x41) item c, Condensate Storage Tank Level - Lov, and I

, (iv) item d, Suppression Pool Vater Level - High. ,

d. The analog trip module calibration interval specified by footnote (a) to Technical Specification Table 4.3.5.1-1 is be ng increased i

from 31 days to 92 days.,

4. Technical Specification 3/4.3.6, " Control Rod Block Instrumentation"

a. Footnote (e) is being added to Technical Specification Tabla 3.3.6-1 to allow control rod block instrumentation channels to be inoperable for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for Surveillance Test A0Ts.

b. The repair A0T of Technical Specification Table 3.3.6-1 Action 62 is being increased from one hour to twelve hours.

5. Technical Specification 3/4.3.9. " Plant Srptems Actuation Instrumentation"

a. The Technical Specification 3.3.9 Action Statements b, c, and d have been deleted and replaced by the standard Action b to become consistent with generic Technical Specification format.

b. An ACTIONS column has besn added to Technical Specification Table 3.3.9-1 " Plant Systems Actuation Instrumentation" to make PNPP format consistent with generic Technical Specification format.

Also, a new page has been added-to Table 3.3.9-1 which presents the appropr te Actions (new Actions 130 through 132) for each of-the Plant Systems Actuation instruments, in the generic Technical Specification format.

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Attechtent 1 PY-CEI/NRR-1496 L Para 25 of 33

c. The surveillance A0T of footnote "a" to Technica' 3 .ication Table 3.3.9-1 is being increased from two hours s- hours. A typographical error in footnote (a) is also being co.. cted.

d. The repair n0Ts of Technical Specification Table 3.3.9-1, " Plant Systems Actuation Instrumentation," Action 130.a and 131 are being increased from one hour to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

e. The STI for CHANNEL FUNCTIONAL TESTS specified on Technical Specification Table 4.3.9.1-1, " Plant Systems Actuation Instrumentation Surveillance Requirements," is being increased from monthly (H) to quarterly (0) for the following Trip Functionst item 1.a, Containment Spray System,'Dryvell Pressure -

(i)

High, (ii) item 1.b, Containment Pressure - High,.

, (iii) item 1.c, Reactor Vessel Vater Level --Lov -Level 1, (iv) item 1.d Timers [(1) and (2)],

(v) item 2.a. Feedvater System / Main Turbine Trip System,

. Reactor Vessel Vater Level - High, Level 8,,

(vi) item 3.a. Suppression Pool Hakeup System, Dryvell Pressure

- High, (vii) item 13.b Reactor Vessel Vater Level - Lov, Level 1, (viii) item 3.c, Suppression Pool Vater Level - Lov, and (ix) item 3.d, Suppression Pool Hakeup Timer.

f. The analog trip module calibration interval specified by footnote

(*) to Technical Specification Table 4.3.0.1-1 is being incre c ed from 31 days to 92 days.

6. Technical Specification'3/4.4.2.1, " Safety / Relief Valves"

a. The STI for CHANNEL FUNCTIONAL TESTS contained in Surveillance Requirements 4.4.2.1.1.a and 4.4.2.1.2.a is being increased from-31 days to 92 days. .

7. . Technical Specification 3/4.4.2.2. " Safety / Relief Valves Low-Lov' Set-Function"

a. The STI for CHANNEL FUNCTIOFAL TESTS contained in Surveillance Requirement 4.4.2.2.1.a is being' increased from 31 days'to 92 days.

Justification for Proposed Changes On February 19, 1991 the BVROG submitted Licensing Topical Report . __

GENE-770-06-01,--" Bases for Changes to Surveillance Test Intervals'and Allowed Outage Times for Selected Instrumentation Technical. Specifications"=for NRC review. This report provides the justification _for' the proposed changes identified above. An addendum to this Report was also submitted concurrently (GENE-770-06-2) which provided additional'information_to support the changes

.to the RCIC System Actuation Instrumenta. ion. A1 Sough GENE-770-06 has not yet been approved by the_NRC Staff (GENE-770-06-2' has-been. approved, but -1 j' has not), PNPP is requesting the Technical Specification changesLidentified in that report (as described above) at=this time-in order to provide'a complete-

Attach = nt 1 PY-CEI/NRR-1496 L 4 Page 26 of 33

request with respect to the instrtmentation reliability-based improvements.

If the proposed changes in Part V of this request are not approved, some of ,

t the improvenents in Parts I through IV of this request vould not be able to be implemented. This is because these instruments perform multiple functions which are addressed by separate Technical Specificationn and hence, are 1 addressed by separate Topical Reports.

J As noted in CENE-770-06-1, the primary purpose for requesting these changes is j to ensure consistency with the changes propos4d for the RPS, ECCS Actuation instrumentation and Isolation Actuation instrumentation. The instrumentation affected by the proposed changes in Part V cf this request consists of either the same or similar instrumentation as that addressed in Parts I through IV.

The primary difference is the safety function performed by the 1 instrumentation.

As also noted in GENE-770-06-1, a detailed analysis of the proposed changes

that are associated with instrumentation that is common to previously analyzed instrumentation was not performed since the analyses 61scussed in Parts I through IV bound them. The remaining proposed changes involve instruments which are of a similar type to the. instruments included in the aaalyses disqussed in Parts I thruugh IV. Existing redundancy of this instrumentation is either comparable to or more extensive than the redundancy of the inst,ruments discussed in Pr.rts I through IV. Further, analyses have generally shown that the most significant contributor to safety function failure probability is associated with the actuated device (such as valves) rather than associated with the actuat M instrumentation. Therefore, the analyses discussed in Parts I through I'i of this request can be used to justify the proposed changes identified in this part.

1 As discussed in Parts I through IV of this request, any expected increase in the probability of function f ailure as a result of these proposed changes will be offset by safety benefits such as a reduction in the number of inadvertent test-induced scrams and engineered safety feature actuations, a reduction in.

j' vear due to excessive equipment test cycling, and better optimization of plant personnel resources. As a result, these proposed changes do not result in a degradation to overall plant safety.

The basis for PNPP's determination that each of these proposed changes are bounded by the analyses discussed in Parts I through IV of this request are discussed belov for each of the affected systems, i

i 1. Technical Lpecification 3/4.3.4.1, "ATVS Recirculation Pump Trip Systems Instrumentation" The ATVS-RPT instrumentation is part of the mitigation system that initiates in the unlikely event of a scram failure. The trip function is initiated by either high reactor pressure or low reactor vater level (Level 2). The ATVS-RPT logic for-PNPP is two-out-of-two channels per trip system for.each Trip Function. Each of the two. trip systems

initiates a trip of both recirculation pumps. The effect of the proposed

-changes to the ATVS-RPT instrumentation requirements on the teactivity shutdown failure fretuency is negligible based on the lov average RPS l

l

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

! Attechn nt i

! PY-CEI/NRR-1496 L Page 27 of 33 failure frequency (5.4x10-6/ year from NEDC-30851P, page 5 29) and the 1

smallchangeinoverallATVS-RPTjunctionunavailabilityduetothe s proposed changes (less than 1x10 / demand calculated from failure rates i of similar instruments as given in Appendix B and C of NEDC-30851P).

k 2. Technical Specification 3/4.3.4.2, "End-of-Cycle Recirculation Pump Trip

{ System Instrumentation"

) The EOC-RPT is initiated by signals and instrumentation common to the RPS

, (turbine stop valve closure and turbine control valve lov hydraulic pressure). The proposed changes for this instrumentation vare evaluated l in NEDC-30851P for the RPS function. Although the EOC-RPT trip functions i vere not explicitly identified in NEDC-30851P, these proposed changes can j be considered bounded by that analysis. The basis for this conclusion is J 4 similar to the basis established in NEDC-30851P, Supplement 2 for the j i control rod block instrumentation common to the RPS. That is, although -

i failure of the EOC-RPT trip function could potentially lead to exceeding i

the Minimum Critical Power Ratio (MCPR) limit (similar to the consequences of an unmitigated rod withdraval error), the slight increase in risk of an MCPR violation due to the proposed EOC-RPT changes.is.

i offset by the safety benefits qssociated with the proposed changes for j the RPS instrumentation. .

i 3. Technical Specification 3/4.3.5', " Reactor Core Isolation Coling System Actuation Instrumentation" ,

I The proposed changes-to'the RCIC system actuation instrumentation vere j evaluated in the BVROG analysis of ECCS actuation instrumentation (NEDC-30936P (Part 2)). The LCIC fault tree models and input data vere developed for the PNPP design (BVR-3/6 Relay). In NEDC-30936P (Part 2),-

i the water injection function failure frequency vas-analyzed as a-function l of the STIs and A0Ts for the ECCS (including RCIC) actuation i instrumentation. The RCIC actuation instrumentation surveillance test j interval (STI) was changed from 1 to 3 months and the associated A0T vas

changed from 1 to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for repair and from 2 to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .for test.

j The analysis results are summarized in:NEDC-30936P (Part:2)f however,

{ model Technical Specification changes;for the RCIC actuation i instrumentation vere not specifically included in NEDC-30936P (Part 2).-

(

These model Technical Specification changes for the RCIC actuation instrumentation vere later provided in GENE-770-06-1 and vere further discussed in its Addendum GENE-770-06-2.-

An analysis was conducted to demonstrate the specific effect'of individual changes to the RCIC actuation instrumentation'STIs on the overall average water injection function unavailability. As noted-above, the analysis vas. performed using the models and input data developed and=

documented in NEDC-30936P (Parts 1 and 2). In' order to. determine the specific-effeet of the STI change on--the RCIC-actuation instrumentation, the RCIC actuation instrumentation STI was' held constant (i.e., STI-- one-month)-while the STI for other ECCS actuation inr mentation was changed to three months. This calculation demonstrated th ethere is 'a very -

small change in the calculated average: vater injection function -

unavailability (less than 1%) for this case when compared with the results of NEDC-30936P (Part 2). The NEDC-30936P (Part 2) analysis

4 1

Attech::nt 1 PY-CEI/NRR-1496 L j Page 28 of 33

! results indicated that the effect of ant changes is significantly less than STI changes. On this bacis, a similar negligible change in average vater injection function unavailability can be expected when the RCIC

^

actuation instrumentation A0Ts (one hour repair and two hours test) are held constant. Therefore, it can be concluded that the STI and A0T i changes to the RCIC actuation instrumentation are justified based on the ;

small effeet on the calculated average water injection function l unavailability and consistency with comparable changes to the actuation j 3

instrumentation for the ECCS subsystems. The NRC Staff issued a Safety l Evaluation Report (SER) for the proposed changes to RCIC in a letter to

G. J. Beck from C. E. Rossi dated September 13, 1991. The NRC Staff concluded that the proposed changes vere acceptable provided the licensee

confirmed the applicability of the generic analysis to the plant and I confirmed that any increase in instrument drift due to the extended surveillance intervals is properk ucounted for in the setpoint calculation methodology.

The PNPP RCIC System was aralyzed as part of the plant-specific analysis performed by GE in RE-020, Revision 1, December 1991 (Enclosure 3). As discussed in Part II above, the results of this review indicated there

vere a total of four differences between PNPP'a ECCS and RCIC, design and i those of the generic plant discussed in the t. ' cal report. The plant-specific analysis concluded that the differences were byunded by the original analyses performed. Therefore the generic analysis is !

applicable to PNPP. ,

Vith respect to the NRC's concern about instrument drift over a 3 month a

(quarterly) period, the RCIC actuation instrumentation setpoint calculations at PNPP include the effects of drift over 18 months for all instrument loop components. To verify drift of the snalog trip modules, PNPP revieved the results of monthly calibration checks performed over a j one-year period on the affected RCIC actuation analog trip modules.

Review of these calibration checks showed that the quarterly drift is within the present calibration tolerances. As a result, PNPP has concluded that lengthening the CHANNEL-FUNCTIONAL TEST interval and analog trip module calibratien interval, as applicable, for the RCIC

, actuation instruments from monthly to quarterly vill not result in excessive drift relative to the current, established setpoints. In addition, a CHANNEL CHECK is required at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for those instruments vi C redundant channels. These routine CHANNEL CHECKS will help to identil;c + <ussive drif t of the RCIC actuation instrumentation.

4. Technical Specification 3/4.3.6, " Control Rod Block Instrumentation" NEDC-30851P, Supplement 1 provided the bases for changing the STIs for the control rod block instrumentation from one month to three months.

Although the above changes to the repair and test A0TS vere.not explicitly identified in NEDC-30851P,' Supplement 1, the same bases used for changing the STIs applies to the A0T changes. The reason for this is because analyses indicate that the effect of A0T changes is significantly v - - - , - a , . -.e

l 1

Attech23nt 1 ,

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PY-CEI/NRR-1496 L- )

4 Page 29 of 33 l

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! less than the effect of STI changes. The proposed changes to the A0Ts for j

the control rod block instrumentation are therefore supported by the i basis provided in NEDC-30851P, Supplement 1.

2 5. Technical Specification 3/4.3.9, " Plant Systems Actuatio_n Instrumentation" j

~

This Technical Specification addresses the requirements for those instruments that provide automatic actuation of the containment spray ;

j system, feedvater/ main-turbine trip system, and the suppression pool ;

l makeup system. Each of these systems are discussed separately below.

PNPP has also taken this opportunity to standardize the format for the

Plant Systems Actuation Instrumentation ACTIONS. ACTIONS be e, and d are ,

being eliminated by creating Table 3.3.9-1 ACTIONS 130, 131, and 132. :

i l

These new Table 3.3.9-1 ACTIONS are either the old ACTION b, c, or d t ACTIONS' rewritten to increase the A0T as proposed by the GENE 770-06-1 j document, or are ACTIONS written to make the required actions for :

inoperable Plant System Actuation Instrumentation consistent with other j i

Technical Specification required actions when the same instruments are- !

}t used in more than one system. For example, the Dryvell Pressure-High,

! and Reactor Vessel Vater Level-Lov Level 1 instruments used in the .

Containment Spray logic are the very same instruments as those used in

~

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j! the Suppression Pool Hakeup System logic and in the ECCS Actuation i j Instrumentation logic. Therefore, ACTION 130 for these instruments was ,

written to be the same required action as ACTION 30 in the ECCS Actuation- i

Instrumentation Specification.'

I f a. Containment Spray System j The containment spray system actuation instrumentation contains ;

instrumentation common to the ECCS actuation instrumentation. In J

addition, the actuation function performed (i.e., closing and

- opening selected valves) is similar to the function performed by the ,

i isolation and ECCS actuation instrumentation.- The dominant ;

i contributor to the unavailability for this type of function is valve :

4 unavailability. Therefore, the analyses of isolation actuation l instrumentation provided in NEDC-30851P, Supplement 2 and '

l NEDC-31677P support similar STI and A0T changes to the containment

spray system instrumentation.- 1 i

b. Feedvater System / Main Turbine Trip System

. The BVR-6 plant-design incorporates a direct scram from high reactor vessel vater level-(Level 8) trip instrumentation (included in the RPS instrumentation). The bases for changes _to the STIs and A0Ts for the reactor vessel vater-Level with the-feedvater system / mainine turb;8= trip instrumentation trip system are therefore- associated bounded by the changes to the-RPS Reactor Vessel Vater Level 8 trip instrumentation provided in NEDC-30851P.

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Attochmnt 1 4 PY-CEI/NRR-1496 L 1 Page 30 of 33

c. Suppression Pool Hakeup The same bases given for the containment spray system instrumentation applies for the suppression pool makeup system instrumentation. The suppression pool makeup system instrumentation ;

contains instrumentation which is common to the ECCS actuation instrumentation. In addition, the actuation function performed (i.e., opening selected valves) is similar to the function performed l by the isolation and ECCS actuation instrumentation. The doeinant ;

contributor to the unavailability for this type of function is valve '

unavailability. Therefore, the aralyses of isolation actuation instrumentation provided in HEDC-30851P, Supplement 2 and '

NEDC-31677P support similar STI and A0T changes to the suppression pool makeup system instrumentation.

6. Technical Specification 3/4.4.2.1, " Safety / Relief Valves" ,

For PNPP, six of the 19 safety / relief valves (SRVs) are required to open in the relief mode (actuated by a pressure transmitter) and seven are >

required to open in the safety mode (actuating against spring pressure) .

to prevent reactor vessel overpressurization. SRV safety mode actuation is diverse from the relief mode actuation. The relief function of the .

F % is performed by three separate sets of logic. Each logic group is l uw- i by one of two two-out-of-two reactor steam dome pressure logic ,

g bt v.fons. The first logic group controls the relief function for one vs,1v a, the second logic group controls nine valves, and the third logic ,

group controls nine valves. If a relief function logic group ~should fail (which requires at least two channel failures), overpressure protection can be provided by the remaining relief logic groups in combination with SRV actuations in the safety mode.

Based en the level of redundancy, unavailability of the relief valve -

pressure actuation function is a small contributor to the overall SRV >

function unavailability. Changes to the-STI forlthe-SRV pressure actuation instrumentation vill therefore have an insignificant effect on the probability of. failure to prevent reactor overpressurization.- The 4 STI changes vill also be consistent with the STI changes to similar instrumentation in the ECCS and isolation systems.

7. Technical Specification 3/4.4.2.2, " Safety / Relief Valves Low-Lov Se_t Function" The Low-Lov Set (LLS) logic for PNPP consists of three individual LLS - '

circuit-groups which control six LLS SRVs. This logic is designed so that no more than one SRV reopens following'a reactor vessel isolation event, ensuring that the containment design. basis is' met. 'After a LLS' SRV initially opens in the relief mode, the associated 8.LS logic is activated and the SRV's closing setpoint is lowered such that the SRV stays.open longer than.without LLS. Two_of-the.LLS~ circuit groups each <

control an individual SRV. These two logic circuit groups also lower the.

SRV's reopening setpoint such that-the SRV vill open prior to activating.

additional SRVs in the relief mode. The third' logic circuit group s

a-== ,w -%ea-+ + - n e,- 4 m c - - e,~-% ey <n---r-r-- , - =. ~ v-= n e + y. wvv., em v

1 Attechnnt 1 PY-CEI/NRR-1496 L Page 31 of 33 controls a group of four LLS SRVs and only lovers their closure setpoints, without affecting their reopening setpoints. The LLS function can normally be performed by either of the first two LLS logic groups.

Because energization of either SRV solenoid pilot valve results in opening the SRV, both solenoid pilot valves must be de-energized for the SRV to close. Opening of the first two LLS logic groups is accomplished by actuation of one of the two two-out-of-two SRV relief mode logic trains. Subsequent closure and reopening of these two LLS logic groups is accomplished by actuation of a one-out-of-one logic for each solenoid pilot valve. The third LLS logic group opens upon actuation of one of two two-out-of-two logic trains and recloses upon deactivation of both two-out-of-two logic trains.

Although the LLS logic has an icportant safety function, its function is not as critical to overall plant safety as the water injection or isolation functions. Therefore, changes to the STIs for the LLS pressure actuation instrumentation vill have less risk impact on the overall plant safety than ECCS and isolation actuation STI changes. Existing analyses of ECCS and isolation actuation instrumentation STI changes can be applied to the LLS logic based on the use of the same or similar type of

, components (i.e., relays, transmitters, trip units, etc.), designed I

redundancy, and safety significance of the LLS logic. The extensive

' redundancy in the LLS circuit logic is comparable with the logic redundancy in the ECCS and isolation actuation instrumentation. Based on 2

this redundancy, similarity of components, and safety function significance of the LLS logic, it can be concluded that the effect of changes for the LLS logic STIs is bounded by the basis established for similar STI changes for the ECCS and isolation actuation instrumentation.

Vith respect to instrument drift for all of the instrumentation addressed in this part, the instrument setpoint calculations for these instruments include the effects of the instrument drift over 18 months for all instrument loop components. In addition, PNPP reviewed the results of monthly calibration checks performed over a one-year period on the affected trip units. Review of these calibration checks shoved that the quarterly drift is within the present calibration tolerances. As a result, PNPP has concluded that lengthening L s CHANNEL FUNCTIONAL M ST interval and trip unit calibration interval, as applicable, for the affected instrumentation from monthly to quarterly will not result in excessive drift relative to the current, established setpoints.

In a,ddition, a CHANNEL CHECK is required at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for those instruments with redundant channels. These routine CHANNEL CHECKS vill help identify excessive drift of the instrumentation affected by these proposed changes.

Basis for No Significant Hazards Consideration In accordance with 10CFR50.92, a proposed change to the operating license (Technical Specifications) involves no significant hazards considerations if operation of the facility in accordance with the proposed change vould not (1) involve a significant increase in the probability or consequences of any accident previously evaluated, or (2) create the possibility of a new or

Attach::nt 1 PY-CEI/NRR-1496 L Page 32 of 33 different kind of accident from any accident previously evaluated, or ,

(3) involve a significant reduction in a margin of safety. The proposed I Technical Specification changes are evaluated against each of these criteria below.

(1) These proposed changes do not involve a change to the plant design or operation, only to the allovabic outage time and frequency at which testing of the associated instrumentation is performed. These instruments are designed to mitigate the consequences of previously analyzed accidents. Failure of these instruments cannot increase, and is independent of, the probability of occurrence of such accidents. As a result, these proposed changes cannot increase the probability of any accident previously evaluated. As identified in GENE-770-06-1, although not specifically analyzed, these proposed changes are bounded by the results of the analyses discussed in Parts I through IV of this request.

Such analyses have shown that the safety function failure frequency is not significantly impacted by similar proposed changes. In addition, any- ;

increase in the probability of failure of these instruments to perform l their required functions vould be offset by safety benefits such as a i reduction in the number of inadurtent test-induced scrams and_ engineered 1 safety features actuations, a rgduction in vear due to excessive equipment test cycling, and bet,ter optimization of plant personnel resources. As a result, these proposed changes should reduce overall plant risk. Therefore, these proposed changes do not result in a significant increase in the pro,bability or the consequences of any acciden+ previously evaluated. 4 (2) These proposed changes do not result in any change to the plant design or operation, only to the allovable outage time and frequency at which testing of the associated instrumentation is performed. As a result, these proposed changes can at most affect only accidents which have been previously evaluated. Therefore, these proposed changes cannot create the possibility of a new or different kind of accident from any accident previously evaluated.

(3) As identified in GENE-770-6-1, although not specifically analyzed, these proposed changes are bounded by the results of the analyses discussed in Parts I through IV of this request. Such analyses have shown that the safety function failure frequency is not significantly impacted by similar proposed changes. In addition, any increase in the probability of failure of these instruments to perform their required functions vould be offset by safety benefits such as a reduction in the number of inadvertent test-induced werams and engineered safety feature actuations, a reduction in vear due to excessive equipment test cycling, and better optimization of plant personnel resources. As a result, these proposed changes vill reduce overall plant risk. In addition, PNPP has confirmed tha* the proposed changes to the functional test intervals vill not result in excessive instrument drift relative to the current, established setpoints. Therefore, these proposed changes do not involve a significant reduction in a margin of safety.

Based upon the foregoing, PNPP has concluded that these proposed changes do not involve a significant hazards consideration.

Attechacnt 1 PY-CEI/NRR-1496 L l Page 33 of 33 i Environmental Consideration The proposed Technical Specification change request has been reviewed against the criteria of 10 CFR 51.22 for environmental considerations. As shown above, the proposed change does not involve a significant hazards consideration, nor increase the types and amounts of effluents that may be i released offsite, nor significantly increase individual or cumulative

occupational radiation exposures. Based on the foregoing, it has been concluded that the proposed Technical Specification change meeta the criteria given in 10 CFR 51.22(c)(9) for a categorical exclusion from the requirement for an Environmental Impact Statement.

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PY-CEI-NRR-1496, Application for Amend to License NPF-58,revising TSs to Increase Surveillance Test Intervals & Allowable Outage Times for Instrumentation.Ge Proprietary Documents Supporting Request Encl.Ge Documents Withheld

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