ML19352B002

Forwards Positions Re post-TMI Requirements Outlined in NUREG-0737, Clarification of TMI Action Plan Requirements. Lists Specific Items Addressed

ML19352B002
Person / Time
Site:	Shoreham File:Long Island Lighting Company icon.png
Issue date:	05/29/1981
From:	Novarro J LONG ISLAND LIGHTING CO.
To:	Harold Denton Office of Nuclear Reactor Regulation
References
RTR-NUREG-0737, RTR-NUREG-737, TASK-1.A.2.1, TASK-1.B.1.2, TASK-1.C.1, TASK-1.C.6, TASK-1.D.2, TASK-1.G.1, TASK-2.B.1, TASK-2.B.4, TASK-2.D.1, TASK-2.E.4.2, TASK-2.F.2, TASK-2.K.3.30, TASK-2.K.3.31, TASK-3.A.1.1, TASK-3.A.1.2, TASK-3.D.1.1, TASK-TM SNRC-579, NUDOCS 8106020537
Download: ML19352B002 (150)

Text

{{#Wiki_filter:a _ _ _. - ~. LONG ISLAND LIGHTING COM PANY A g,/LCO > SHOREHAM NUCLEAR POWER STATION www P.O. BOX 618, NORTH COUNTRY ROAD e WADING RIVER, N.Y.11792 wenw m May 29, 1981 SNRC-579 %W 7 yt-5.~ ::b W J. m 1 g Mr. Harold R. Denton, Director jcp Office of Nuclear Reactor Regulation S "rQ d U.S. Nuclear Regulatory Commission g g Washington, DC 20555 cc ~ I Shoreham Nuclear Power Station - Unit 1 -/@s?C~ Docket No. 50-322

Dear Mr. Denton:

Forwarded herewith are sixty (60) copies of our positions related to Post-TMI Requirements outlined in NUREG-0737, " Clarification of TMI Action Plan Requirements". The seventeen specific items addressed are listed in Attachment 1 to this letter. Where applicable, our responses to certain NUREG-0578 items (SNRC-503, dated 8/29/80) are superceded by the respective responses contained herein. Two previous submittals have been made regarding NUREG-0737 i.e., letters SNRC-557 dated 4/15/81 and SNRC-563 dated 5/15/81. As a result of discussions with your staff on these items, the following clarifications are being made: 1. II.K.3.44 - " Evaluation of Anticipated Transients with Single Failure to Verify No Fuel Failure" - The analyses noted in the BWR Owners' Group Evaluation were done for BWR 2's through BWR 6's,. The analyses done for BWR 4's and the conclusions reached as a result of these analyses, i.e., no core uncovery, are applicable to Shoreham. 2. II.K.3.18 " Modification of Automatic Depressurization System Logic" - The proposed modification will be implemented in accordance with the requirements of NUREG 0737, i.e., during the first refueling to occur six months after NRC staff approval of the proposed modi-fication. $'o\\ t! 0 9 i THIS DOCUMENT CONTAltlS. e' " " 53'7 ecoa aunu1v eacEs F C.3 9 3 3 s

Mr. Harold R. Denton May 29, 1981 Page 2 This submittal completes our responses on NUREG-0737. 'All of these submittals and the clarifications noted above will be incorporated into an FSAR Amendment. Ver truly yours, 0 /

• i c%% o I

J. P. Novarro Project Manager Shoreham Nuclear Power Station RWG:mp Enclosures cc: J. Higgins e 4 l t

ATTACEMENT 1 NUREG-0737 ITEMS INCLUDED IN THIS SUBMITTAL I.A.2.1 Immediate-Upgrading of Reactor' Operator and Senior Reactor Operator Training and Qualifications I.B.l.2 Evaluation of Organization and Management I.C.1' Guidance for the Evaluation and Development of Procedures for Transients and Accidents I.C.6 Procedures for Verfication of Correct Performance of Operating Activities I.D.2 Plant Safety Parameter Display Console I.G.1 Training Requirements During Low Power Testing II.B.1 Reactor Coolant System Vents II.B.4 Training for Mitigating Core Damage II.D.1 Performance Testing of Boiling-Water Reactor and Pressurized-Water Reactor Relief and Safety Valves II.E.4.2 Containment Isolation Dependability II.F.2 Identification of and Recovery from Conditions Leading to Inadequate' Core Cooling II.K.3.30 Revised Small Break Loss of Coolant Accident Methods to Show Compliance with 10 CFR 50, Appendix K II.K.3.31 Plant-Specific Calculations to Show Compliance with 10 CFR 50.46 III.A.l.1 Upgrade Emergency Preparedness III.A.1.2 Upgrade Licensee Emergency Support Facilities III.A.2 Improving Licensee Emergency Preparedness - Long Term III.D.l.1 Primary Coolant Sources Outside the Containment Structure 4 - +. - v-y p.

I I SNPS-1 FSAR I.A.2.1 Insnediate Upgrade of Reactor Operator and Senior Reactor Operator Training and Qualitication NRC Position Effective May 1, 1980, an applicant for a senior reactor operator (ShO) license shall have four years of responsible power plant experience of which at least two years shall be nuclear power plant experience. Six months of the nuclear power plant experience shall be at the plant on which the applicant is licensing. A maximum of two years power plant experience may be fultilled by academic or related technical training, on a one-for-one time basis. Effective December 1,

1980, an applicant for a senior reactor operator (SRO) license shall have held an operator's license for one year.

Effective August 1,

1980, an applicant ior a senior reactor i

operator (SRO) license shall have three months of shift training as an extra man on shift. An applicant ior a reactor (RO) license shall have three months training on shift as an extra person in the control rocm. Effective August 1, 1980, training programs shall be moaltied to provide: 1. Training in heat

transfer, fluid

flow, and thermodynamics.

l 2. Training in the use of installed plant systems to control or mitigate an accident in which the core is severely damaged. 3. Increased emphasis on Rx and plant transients. Effective May 1,

1980, certifications that operator license applicants have learned to operate the controls shall be signed by the highest of corporate management for plant operation.

LILCO Position It is LILCO's position that an applicant for a senior reactor I operator (SRO) license shall have four years of responsible power plant experience. A maximum of two years power plant experience l may be fulfilled by academic or related technical training, on a one-for-one time basis. Two years shall be nuclear power plant experience and at least six months of the nuclear power experience uall be at Shoreham Nuclear Power Station (SNPS). Since Shoreham is not yet operational, the two years of nuclear power plant experience requirement may be satisthd by two years of participation in the Shoreham preoperational test program. I.A.2.1-1 4 ,n,- -m,,-- e ,c,-.-,-,-----,-,,--en-,., ,,,a,,-- -,,.,,,,,,w.-, ,,,,,-n,.,,,,,mm_,,,,._--,--m, ,,,,-----,--.e-,.n,- ,,--m-,,,. ---n.,--,v,-

SNPS-1 FSAR In

addition, an applicoat for-a hot SRO license shall be a licensed operator for one year or possess equivalent experience.

Applicants for SRO licenses at SNPS, as cold license applicants, will receive the equivalent of the experience not available to them by participating in the cold license training program. Hot SRO license applicants, who are nondegreed individuals, shall participate in an SRO training program thal includes three months on shift as an extra man and meet the one year experience as a licensed operator by one or more of the following: 1. Hold an operator *s license at SNPS ior a period of one j years or 2. Hold an operator's license at another nuclear power plant for a period of one year; or 3. Possess one year of operating experience in a position that is equivalent to a licensed operator or senior operator at military propulsion reactors; or 4. Have completed the SNPS cold license training program Hot SRO license applicants, who are degree-holding engineers, shall have three months on shift as an extra man and meet the one year experience as a license operator by one or more of the rollowing: '^ 1. Participate in an SRO training program equivalent to a cold applicant training programs or 2. Hold an operator's license at SNPS for a period 01 one year; or 3. Hold an operator's license at another nuclear power plant for a period of one year; or I 4. Possess one year or operating experience in a position l that is equivalent to a licensed operator or senior operator at military propulsion reactors; or 5. 11 ave completed the SNPS cold license training program. Hot RO license applicants shall have three months on shift as an extra man in the control room. i The SNPS operator training program will be modified to provide: i 1. Increased training in heat transfer, fluid flow, and i thermodynamics. I i 1.A.2.1-2 1 ,.,..-.,- --, ~.,,- -,-, - -...,.n . -. - ~ ~.. -.. _. ~.,.., - -....,., -... _,.

SNPS-1 FSAR 2. Training in the use of installed piant systems to control or mitigate an accident in which the core is severely damaged. 3. Increased emphasis on RX and plant transients. In addition, certifications that operator license applicants have learned to operate the controls shall be signed by the Vice President-Nuclear. I.A.2.1-3

SNPS-1 FSAR I.B.1.2 Evaluation of Organization and Management NRC Position Each applicant for an operating license shall establish an onsite independent safety engineering group (ISEG) to pertorm independent reviews of plant operations. The principal function of the ISEG is to a m ine plant operating characteristics, NRC issuances, Licensing Information Service advisories, _ and other appropriate sources of plant design and 4 operating experience information that may indicate areas for improving plant safety. The ISEG is to perform independent review and audits or plant activities including maintenance, modifications, operational

problems, and operational analysis, and aid in the establishaant of program =matic requirements for plant activities.

Where useful improvements can be achieved, it is expected that this group will develop and present detailed recommendations to corporate management for such things as revised procedures or equipsnent modifications. Another function or the ISEG is to maintain surveillance of plant operations and maintenance activities to provide independent verification that these activities are performed correctly and ] that human errors are reduced as far as practicable. ISEG will then be in a position to advise utility management on the overall quality and safety of operations. ISEG need not perform detailed i audits of plant operations and shall not be responsible ror sign-off functions such that it becomes involved in the operating organization. ( The new 1SEG anall not replace the plant operations review consnittee (PORC) and the utility *s independent leview and aucit group as specirled by current staff guidelines (Standard Review Plan, Regulatory Guide 1.33, Standard Technical Specifications).

Ratner, it is an additional independent group of a minimum or five dedicated, full-time engineers, located

onsite, but reporting offsite to a corporate of ficial wno holds a high-level, technically oriented position that is not in the management chain for power production.

The ISEG will increase the available technical expertise located onsite and will provide continuing, systematic, and independent assessment of plant activities. Integrating the Sh11t Technical Advisors into the ISEG in some way would be desiranle in that it could enhance tne group's contact with and knowledge of day-to-day plant operations and provide additional expertise.

However, the shift technical advisor on shift is necessarily a member of the operating staff and cannot be independent of it.

It is expected that the ISEG may interface with the quality assurance (QA) organization, but prererably should not te an integral part of the QA organization. I.B.1.2-1

SNPS-1 FSAR The functions of the ISEG require daily contact with the operating personnel and continued access to plant racilities and records. The ISEG review functions

can, therefore, Dest De carried out by a group physically located onsite.

however, for utilities with multiple

sites, it may be possible to perform portions of the independent safety assea-rat function in a

centralized location for all the utility *s plants. In such cases, an onsite group still-is required, but it may be slightly naaller than would be the case if it were performing the entire independent satety assessment function. Such cases will be reviewed on a case-by-case basis. At this time, the requirement for establishing an ISEG la being applied only to applicants for operating licenses in accordance with Action Plan item I.B.1.2. The stati intends to review this r activity in about a year to determine its ettectiveness and to l see whether changes are required. Applicability to operating l plants will be considered in implementing long-term unprovements in organization and management for operating plants (Action Plan item I.B.1.1). LILCO Position Shift Technical Advisors (STA 's) when not assignea shitt responsibility will perform the functions of the independent On-site Satety Review Group (OSRG) as described in response to Item I.A.1.1. The STA reports to the Reactor Engineer and is, therefore, independent of the operations or maintenance sections. The STA s, when performing OSRG

duties, shall report their findings and concerns directly to the Review of Operations consnittee (ROC).

Duplicates of all reports shall simultaneously De iorwarded to the corporate Nuclear Review Board (NRb). This dCtion will provide assurance of independence from the operating starf in all matters of OSRG concerns. l l l l l l I.B.1.2-2

SNPS-1 FSAR I.C.) Guidance for the Evaluation and Developerent of Procedures for Transients and Accidents NRC Position In letters of September 13 and 27, October 1') and 30, and November 9,

1979, the Office of Nuclear Reactor Regulation required licensees of operating plants, applicants for operating licenses and licensees of plants under construction to perform analyses or transients and accidents, prepare emergency procedure guidelines, upgrade emergency procedures, including procedures for operating with natural circulation conditions, and to conduct operator retraining (see also item I.A.2.1).

Emergency procedures are required to be consistent with the actions necessary to cope with the transients and accidents analyzed. Analyses of transients and accidents were to be completed in early 1980 and implementation of procedures and retraining were to be completed 3 months after emergency procedure guidelines were established; however, some difficulty in completing these requirements has been experienced. Clarification of the scope of the task and appropriate schedule revisions are being developed. In the course of review of these matters on Babcock and Wilcox (B&W)-designed plants, the start will follow up on the bulletin and orders matters relating tc analysis methods and results, as listed in NUREG-0660, Appendix C (see Table C.1, items 31., 4, 16, 18, 24, 25, 26, 27; Table C.2, items 4, 12, 17, 18, 19, 20; and Tanle C.3, items 6, 35, 37, 38, 39, 41, 47, 55, 57). Based on staff reviews to date, there appear to be some recurring deficiencies in the guidelines being developed. Specifically, the staf t has found a lack of justification for the approach used (i.e., sy ptom, event, or function-oriented) in developing diagnostic guidance for the operator and in procedural development. It has also been found that although the guidelines take implicit credit for operation of many systems or components, they do not address the availability or these systems under expected plant conditions nor do they address corrective or alternative actions that should be performed to mitigate the event should these systems or components fail. The analysis conducted to date for guideline and procedure development contain insufficient information to assess the extent to which multiple failures are considered. NOREG-0578 concluded l that the single-failure criterion was not considered appropriate for guideline development and called for the consideration of multiple failures and operator errors. Therefore, the analyses that support guideline and procedure development should consider the occurrences of multiple and ie sequential failures. In

general, the sequence of events for se transients and accidents and inadequate core cooling analyzed should postulate multiple failures such that, if the failures were unmitigated, conditions of inadequate core cooling would result.

Examples of multiple f allure events include: l 1.C.1-1 l

SNPS-1 FSAR (1) Multiple tube ruptures in a single steam generator and tube rupture in more than one steam generator; (2) Failure of main and auxiliary feedwater; (3) Failure of high pressure reactor coolant makeup systen; (84) An anticipated transient without scram (AThS) event following a loss or offsite

power, stuck-open relief i

ralve or safety / relief valve, or loss of :aain feedwater; and (S) Operator errors of omission or conunission. The analyses should be carried out tar enough into the event to assure that all relevant thermal /nydraulic/neutronic phenomena are identified (e.g., upper head voiding due to rapid cceldown, steam generator stratification). Failures and operator errors during the long-term cooldown period should also be addressed. The analyses should support development of guidelines that define a logical transition Irom the emergency procedures into the inadequate core cooling procedure including the use of instrumentation to identify inadequate core cooling conditions. Rationale for thm transition should be discussed. Additional information that sinuld be submitted includes: (1) A detailed description of the methodology used to develop the guidelines; (2) Associated control function diagrams, sequence-of-event diagrams, or others, if used; (3) The bases for multiple and consequential failure considerations; (14) Supporting

analysis, including a

description of any computer codes used; and (5) A description of the applicability of any generic l results to plant-specific applications. l Owners' group or vendar submittals may be referenced as appropriate to support this reanalysis. It owners' group or vendor submittals have already been f orwarded to the staff for review, a brief description of the submittals and justification of their adequacy to support guideline development is all that is required. Pending staff approval of the revised analysis and guidelines, the staff will continue the pilot monitoring of emergency procedures described in task action plan Item I.C.8 (NUREG-0660). For PWRs, this will involve review of the loss-of-coolant, steam-generator-tube

rupture, loss of main feedwater, and inadequate I.C.1-2

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

l SNPS-1 PSAR core cooling procedures. The adequacy of each PWR. vendor s a guidelines will be identified to each NTOL during the emergency-procedure review. Since the analysis and guidelines subnitted by the General Electric Company (GE) owners' group that A ly with l the requirements stated above have been reviewed and approved for l trial implementation of six plants with applications ior operating licenses pending, the interim program for BWRs will consist of trial implementation on these six plants. Following approval of analysis and guidelines and the pilot monitoring of emergency procedures, the staff will advise all licensees ot the adequacy of the guidelines for application to their plants. Consideration will be given to human factors engineering and system operational characteristics, such as information transfer under stress, compatibility with operator training and control-room design, the time required for component and system response, clarity of procedural actions, and control-roosa personnel interactions. When this determination has been l made by the staff, a long-term plan for emergency procedure i review, as described in task action plan Item I.C.9, will be made l available. At that time, the reviews currently being conducted on NTOLs under Item I.C.8 will be discontinued, and the review required for applicants for operating licenses will be as described in the long-term plan. Depending on the information submitted to support development of emergency procedures for each reactor type or vendor, this transition may take place at different times. For example, if the GE. guidelines are shown to t l be effective on the six plants chosen for pilot monitoring, the long-term plan for hWRs may be complete in early 1981. Operating plants and applicants will then have the option of implementing the long-term plan in a manner consistent with their operating

schedule, provided they meet the final date required for implementation.

This may require a plant that was reviewed for i an operating license under Item I.C.8 to revise its emergency procedures again prior to the final implementation date for Item I.C.9. Tne extent to which the long-term program will include review and approval of plant-specific procedures for l operating plants has not been established. Our objective, however, is to minimize the amount of plant-specific proceoure review and approval required. The staff believes this objective can be acceptably accomplished by concentrating the staff review and approval on generic guidelines. A key element in meeting this objective is use of staff-approved generic guidelines and l guideline revisions by licensees to develop procedures. For this approach to be eff ective, it is imperative that, once the staff l has issued approval of a guideline, subsequent revisions of the guideline should not be implemented by licensees until reviewed and approved by the staff. Any changes in plant-specific l procedures based on unapproved guidelines could constitute an unreviewed safety issue under 10CFR50.59. Deviations trom this a approach on a plant-specific basis would be acceptable provioed the basis is sutmitted by the licensee for statt review and approval. In this

case, deviations from generic auidelines should not be implemented until staff approval is formally I.C.1 -3

SNPS-1 FSAR received in writing. Interim implementation of analysis and procedures for small-break loss-of-coolant accident and inadequate core cooling should remain on. the schedule contained in NUREG-0578, Recommendation 2.1.9. _LILCO Position In the clarification of the NUREG-0737 requirement " tor reanalysis of transients and accidents and inadequate core cooling and preparation of guidelines for development of emergency procedures", NUREG-0737 states: Owners

• group or vendor submittals may be rererenced as appropriate to support this reanalysis.

If owners

• group' or vendor anhmittals have already been forwarded to the staff for

review, a

brief description of the submittals and justification of their adequacy to support guideline development is all that is required. LIICO has participated, and will continue to participate, in the BWR Owners' Group program to develop Emergency Procedure Guidelines for General Electric Boiling Water Reactors. Following is a brief description of the submittals to date, and a justification of their adequacy to support guideline development. 1. Description of Submittals a. NEDO-24708, " Additional Information Required for NRC Staff Generic Report on Bolling Water Reactors", August 1979; including additional sections suhmitted in prepublication form since August 1979. i. Section 3.1.1 (Small Break LOCA) Description and analysis of small break loss-l. of-coolant

events, considering a

range of break

sizes, location, and conditions, including equipnent failures and operator errors; description and justification of analysis methods.

ii. Section 3.2.1 (Loss of Feedwater) - revised and resubmitted in prepuDlication torm March 31, 1980. Description and analysis of loss or feedwater events, including cases involving stuck-open relief

valves, and including equipment f allures and operator errors ; description and justification of analysis methods.

iii. Section 3.2.2 (Other Operational Transients) submitted in prepub11 cation form I.C.1-4

1 SNPS-1 FSAR March 31, 1980; revised and resubmitted in prepublication form August 22, 1980. Description and analysis of. each FSAR Chapter 15 event resulting in a reactor system transient; demonstration of applicability of analyses of Sections 3.1.1, 3.2.1, and 3.5.2.1 to each event; demonstration of applicability of Emergency Procedure Guidelines to each event. iv. Section 3.3 (BWR Natural and Forced Circulation) Description of natural and torced circulation cooling; factors influencing natural circulation, including noncondensibles; reestablishment of. forced circulation under transient and accident conditions. v. Section 3.5.2.1 (Analyses to Demonstrate Adequate Core Cooling) submitted in prepublication form November 30, 1979; revised and resubmitted in prepublication form September 16, 1980. Description and analysis of loss-of-coolant events, loss of feedwater events, and stuck-open relief valve

events, including severe multiple equipment failures and operator errors

which, if not mitigated, could result in conditions of inadequate core cooling.

vi. Section 3.5.2.3. (Diverse Methods of Detecting Adequate Core Cooling) Submitted in prepublication form December 28, 1979. Description of indications available to the BWR operator for the detection of adequate core cooling (detailed instrument responses are described in Sections 3.1.1, 3.2.1, and 3.5.2.1). vii. Section 3.5.2.4 (Jusification of Analysis Methods) - submitted in prepublication form September 16, 1980. Description and justification of analysis methods for extremely degraded cases treated in Section 3.5.2.1. b. BWR Emergency Procedure Guidelines (Revision 0 - sulxnitted in prepub11 cation form June 30, 1980. I.C.1-5

SNPS-1 FSAR Guidelines for BWR Emergency Procedures based on identification and response to plant symptoms; including a range of equipment failures and operator errors; including severe multiple equipment failures and operatcr errors which, if not mitigated, would result in conditions of inadequate core cooling; including conditions when core cooling status is uncertain or unknown. 2. Adecuacy of Surunittals The submittals described in 1. above have been discussed l and reviewed extensively among the BWR Owners e

Group, the General Electric Company, and the NRC staff.

The NRC staff has found (refer to NUREG-0737, p. I.C.1-3) that "th e analysis and guidelines submitted by the General Electric Company (GE) Owners

• Group

...cosaply l with the requirements [of the NURF.G-0737 clarification)." In a letter from D. G. Eisenhut (NRC) l to S. T. Rogers (BWR Ownerse Group), regarding Emergency l Procedure Guidelines, dated October 21, 1980, the l Director of the Division of Licensing states, "We find the Emergency Procedure Guidelines acceptable for trial implementation (on six plants with applications for operating licenses pending)." LILCO believes that in view of these findings, no further detailed justification of the analyses or guidelines is necessary at this time. The letter further

states, iduring the course of implementation we may identify areas that require modification or further analysis and justification."

The enclosure to the above letter identitles several such areas. LILCO will work with the bMR Owners

• Group in responding to such requests.

By our commitment to work with the Owner's Group on such requests, on schedules mutually agreed to by the NRC and the Owners' Group, and by reference to the BWR Owners' Group analyses and guidelines already submitted, our response to the requirements "for reanalysis of transients and accidents and inadequate core cooling and preparation of guidelines for development of emergency procedures" by January 1,

1981, is complete.

I I.C.1-6

SNPS-1 FSAR I.C.6 Procedures for Verification of Correct Performance of Operating Activities NRC Position It is required (from NUREG-0660) that licensees

• procedures be reviewed and revised, as necessary, to assure that an etfective system of verifying the correct performance of operating activities is provided as a means of reducing human errors and improving the quality of normal operations.

This will reduce the I frequency of occurrence of situations that could result in or contribute to accidents. Such a verification system may include automatic system status monitoring, human verification of operations, and maintenance activities independent of the people performing the activity (see NOREG-0585, Recossendation 5) or both. l Implementation of automatic status monitoring it required will reduce the extent of human verification of operations and maintenance activities but will not eliminate the need tot such verification in all instances. The procedures adopted by the licensees may consist of two phases - one before and one after installation of automatic status monitoring equipnent, if required, in accordance with item I.D.3 of NOREG-0660. An acceptable program for verification of operating activities is described below. The American Nuclear Society has prepared a draft revision to ANSI Standard N18.7-1972 (ANS 3.2) " Administrative Controls and Quality Assurance for the Operational Phase of Nuclear Power Plants." A second proposed revision to Regulatory Guide 1.33, " Quality Assurance Prograin Requirements (Operation)," which is to be issued for public comment in the near future, will endorse the latest draft revision to ANS 3.2 subject-to the rollowing supplemental provisions: (1) Applicability of the guidance of Section 5.2.6 should be extended to cover surveillance testing in addition to maintenance. (2) In U eu of any designated senior reactor operator (SRO), the authority to release systems and equipment for maintenance or surveillance testing or return-to-service may be delegated to An on-shift SRO, provided provisions are made to ensure that the shift supervisor is kept fully informed of system status. (3) Except in cases of significant radiation exposure, a second qualified person should verify correct implementation of equipment control measures such as tagging of equipaent. l (4) Equipment control procedures should include assurance that control-room operators are informed of changes in equipment status and the effects of such changes. I.C.6-1 / I e -,-,-,--,,,,.-,,n,-- ,,,,,.--,---,,,,-,_,,---,-,,,,m.,,,w, ,n--,,,.-..mn--a_,-,.,---,------.e,--

SNPS-T FSAR (5) For the return-to-service of equipment important to safety, a second qualified operator should verify proper systems alignment unless functional testing can be performed without compromising plant safety, and can prove that all equipment,

valves, and cwitches involved in the activity are correctly aligned.

NOTE: A licensed operator possessing knowledge of the systems involved and the relationship of the systems to plant safety would be a " qualified" person. The staff is investigating the level of qualification necessary for other operators to perform these functions. Fbr plants that have or will have automatic system status monitoring as discussed in Task Action Plan item I.D.3, NUREG-

0660, the extent of human verification of operations and maintenance activities will be reduced.

However, the need for such verification will not be elininated in all instances.

LILCO Position Procedures to implement the intent of the objectives of this Task Action Plan Item are written and included in the Station Operating Manual. LILCO's position is that the Station Procedures that implement equipment control measures will be reviewed and revised as necessary prior to fuel load in order to dssure that: 1. Surveillance testing is addressed in a similar manner to maintenance activities as far as equipment control measures are applicable. 2. The Watch Engineer (Shoreham's Shif t Supervisor) may delegate the authority to release systems and equipment for maintenance or surveillance testing or return-to-service to the on-shift Senior Reactor Operator on duty in the control room provided the Watch Engineer is kept fully informed of the plant system status. 3. A second suitably qualified individual verifies the correct j l implementation of equipment control measures for safety-related equipment (such as, tagging of equipment), except in cases where a significant radiation exposure would be received. 4. Equipment control procedures include provisions for assuring that control room operators are informed of changes in equipment system status and the effects of such changes. 5. A second suitably qualified individual verifies proper systems alignment after the return-to-service of safety-related equipment, except where a functional test is performed which does not compromise plant satety, and proves that all equipment,

valves, and switches involved in the activity are correctly aligned.

I.C.6-2

SNPS-1 FSAR I.D.2 Plant Safety Parameter Display Console ,NRC Position In accordance with Task Action Plan 1.D.2, Plant Safety Parameter Display Console (NUREG-0660), each applicant and licensee shall install a safety parameter display system (SPDS) that will display to operating personnel a minimum set of parameters which define the safety status of the plant. This can be attained through continuous indication of direct and derived _ variables as necessary to assess plant safety status. These requirements are defined in NUREG-0696 which was published in February 1981. LILCO Position The position on a safety parameter display system is discussed in LILCO's position on Item III.A.1.2, Upgrade Licensee Emergency Response Facilities. I.D.2-1

SNPS-1-FSAR I.G.1 Training Requirements During Low Power Testing NRC Position Define and commit to a special low power testing program approved by the NRC to be conducted at power levels no greater than five percent to obtain additional technical information and supplemental training. LILCO Position Chapter 14 describes the initial testing program for Shoreham. Included in this program and outlined in Chapter 14 are those tests to be performed at power levels no greater than five percent. Additionally, LILCO, as a member of the BWR Owners' Group (BWROG), supports the position as submitted in BWROG-8120, dated February 4, 1981 (Attachment 1), and will perform several new tests as identified in Appendix E therein. Detailed test procedures will be prepared and submitted to the NRC for their review at least 90 days before the performance of these tests. l l l I.G.1-1

m m i. ATTACHMENT 1 f v tC v~ b$ fr I k I O 8 UJoters Chairmon P.O. Box 1551

• Aoicigh. North Corohno 27602 e (919) 836-6584 BWROG-8120 February 4, 1981 U. S. Nuclear Regulatory Commission Division of Licensing Office of Nuclear Reactor Regulation Washington, D.C.

20555 Attention: D. G. Eisenhut, Director Gentlemen:

SUBJECT:

BWR OWNERS' GROUP EVALUATION OF NUREG-0737 REQUIREMENT I.G.1, TRAINING DURING LOW POWER TESTING This letter transmits on oehalf of the BWR Owners' Group sixty copies of the BWR Owners' Group program for compliance with the subject requirement. Requirement I.G.1, which is applicable to near-te.m operating licence (NT0L) facilities, has been reviewed against the present BWR Preoperational and Startup Test Program. A number of areas are identified where increased emphasis on operator training can be beneficial. Although we believe the-scope of the present test program is more than adequate, several new tests are identified that are responsive to the subject NRC requirements as discussed with your staff on September 5, 1980. The additional tests are in accordance with submitted safety analysis reports (SAR's); therefore no new analyses are required to support adding these tests. The result of the above review is the attached generic program developed by General Electric and the participating Owners listed in Appendix F of the attach-ment. The generic program will be used as a basis for individual submittals. Implementation details are plant dependent, based on the completion status of the preoperational test program, the scope of the present test and training program, and the plants administration procedures. The submittal of an Owners' Group position developed in response to an NRC require-ment does not indicate that the Owners' Group unanimously endorses that position; rather, it indicates that a substantial number of members believe the position is responsive to the NRC requirement and adequately satisfies the requirement. Each member must formally endorse a position so developed and submitted in order for the position to become the member's position.

't U. S. Nuclear Regulatory Comission Attn: D. G. Eisenhut, Director Subj: BWR Owners' Group Evaluation of NUREG-0737 Requirement I.G.1 Training Ouring Low Power Testing Janua'ry 4,1981 Page 2 Please contact R. H. Buchholz (GE), 408-925-5722 if you have any questions concerning the enclosed information. Yours very truly, cu.M' 8. nob D. B. Waters, Chairman BWR Owners' Group DBW:PWM:na Enclosure cc: BWR Owners' Group R. H. Buchholz GE) GE)) P. W. Marriott D. M. Verre111 NRC ---1 w, x -w ,,--,-,--~-ev-- e w. 5e- -,--eere -g --v-w y ,-r,r ,-yr-.- ,,-w-- v -.v -,-t-,- -e, w~~

BWR OWNERS' GR0dP PROGRAM FOR COMPLIANCE WITH NUREG-0737 ITEM I.G.1 TRAINING DURING LO!! POWER TESTING i t l l l l l l l l

TABLE OF CONTENTS SECTION TITLE PAGE INTRODUCTION 1 I PREOPERATIONAL TESTING 3 II COLD FUNCTIONAL TESTING 3 III HOT FUNCTIONAL TESTING 4 IV STARTUP TESTING 5 V ADDITIONAL TRAINING AND TESTING 6 CONCLUSIONS 6 APPENDIX A PREOPERATIONAL TESTING 7 APPENDIX B COLD FUNCTIONAL TESTING 8-10 APPENDIX C HOT FUNCTIONAL TESTING 11-14 APPENDIX D STARTUP TESTING 15-20 APPENDIX E ADDITICNAL TESTING AND TRAINING 21-25 FIGURE 1 STARTUP TESTING 26 FIGURE 2 STARTUP TESTING 27-28 APPENDIX F PARTICIPATING UTILITIES 29 l l I l l

INTRODUCTICN The NRC has identified new requirements for GE BWR plant testing and training. These requirements are applicable to near-term operating license (NTOL) facilities. The following quotes are from the NUREG documents addressing these require-ments: NUREG 0660 May, 1980 TASK I.G. PREOPERATIONAL AND LOW-POWER TESTING A. OBJECTIVE: Increase the capability of the shift crews to operate facilities in a safe and competent manner by assuring that training for plant evolu-tions and off-normal events is conducted. Near-term operating license facilities will be required to develop and implement intensified training exercises during low-power testing programs. This may involve the repetition of startup tests on different shifts for training purposes. Based on experiences from the near-term operating license facilities, requirements may be applied to other new facilities or incorporated into the plant drill requirement (Item I.A.2.5). Review comprehensiveness of test programs. NUREG 0694 June, 1980 I.G.1 TRAINING DURING LOW-POWER TESTING Define and commit to a special low-power testing program approved by NRC to be conducted at power levels no greater than 5 percent for the purposes of providing meaningful technical information beyond that obtained in the normal startup test program and to provide supplemental training. l The participating members of the GE BWR Owners' Group, Appen-dix F, and the General Electric Company have reviewed the present BWR Preoperational and Startup Test Programs against the above listed requirements. A number of areas have been identified where increased emphasis on operator training can be beneficial. Additionally, several new tests have been identified that are responsive to the NRC requirements discussed with the Omers Group subcommittee on September 5, 1980. As a result of this review, a generic program has been developed and is described herein. This generic program will be used as a basis for individual submittals. The test program has been divided into five sections for purposes of this report. They are: 1 l l

INTRODUCTION - (Cont'd) a I - Preoperational Testing ) II - Cold Functional Testing III - Hot Functional Testing IV - Startup Testing V - Additional Training and Testing The first four sections briefly discuss the present test program and changes made to improve the. training benefit. The last section contains new testing proposed to provide meaningful technical information and enhance training. i i l 2 ( i

I. PREOPERATIONAL TESTING Following completion of construction tests preoperational tests are performed. The purpose of the preoperational test program is to verify that the performance of plant systems meet design and operational requirements. System components are tested, logic checks are performed, and sensor.setpoints are verified. The system is then tested as a whole. The preoperational test program serves a two-fold purpose. Primarily, it controls and documents the preoperational test effort. A secondary benefit of the program is that during 4 the test phase, a detailed knowledge of the systems and their performance characteristics will be obtained by the plant operating group. Preoperational tests are performed on, as a minimum, any system whose operation is safety related. Plant operating personnel will obtain hands on experience for testing of these systems thereby helping to satisfy the training concerns of NUREGS 0660 and 0694. Many system tests will be conducted as part of these preoperational tests which readily lend themselves to operator training. - The Integrated ECCS with loss of AC and DC power test is one of the more significant tests performed during the preoperational test phase which significantly supports operator training. Appendi'x A describes this test. To enhance the training benefit of this test future Integrated ECCS testing will be scheduled so that each shift will participate in at least one of these tests to obtain training. 1 Operators obtain an appreciation and feel tor control room and plant conditions / limitations and will be required to resolve operational problems associated with the loss of emergency battery and diesel generators during a time when emergency equipment is required to operate. II. COLD FUNCTIONAL TESTING Cold Functional Tests are performed on a Plant for several reasons. Some of the more important reasons are as follows: A. Assure that plant systems are available to support fuel loading. B. Assure that shift personnel have operating experience with plant equipment. C. Assure that certain plant operating procedures and surveillance procedures have been tried and are usable. D. Assure that each shift has functioned together to operate the plant systems on an integrated basis. 3

E. Assure that specified plant equipment has been tested and the plant and personnel are ready for fuel loading. The Cold Functional Tests are performed using plant procedures and are controlled and documented by use of checklists. The checklist provides a signoff sheet to assure that each shift has received training and experience on specified systems. Typically, a designated shift supervisory person will be 4 responsible to ensure, by signing the checklist, that their shift has performed the operation specified. Typical systems to be included and an example of a typical checklist are found in Appendix B. Present testing plans will be reviewed and upgraded, as 4 necessary, to obtain documentation and testing scope for the operator training effort. III. HOT FUNCTIONAL TESTING Hot Functional Tests are performed to assure that insofar as possible the system, procedures, and personnel are ready for operation at various power levels. This verification is done by operating systems in an integrated fashion at operating temperatures and pressures at the earliest opportunity for meaningful checks. The Hot Functional Tests cover those areas of the Plant systems which are not tested by the Startup Test Procedures, but where it is felt that additional data over and above the Cold Functional Tests is beneficial. Typically, the Hot Functional Tests will begin after fuel is loaded when nuclear heat is available. The Startup provides three phases which offer Hot Functional Test opportunities. These phases are listed below: A. During heatup from ambient and 0 PSIG to rated tempera-ture and pressure. B. After increase from rated temperature and pressure to 30 percent power. C. Frcm 30 percent to 100 percent power. The Hot Functional Tests are not intendec to replace any of the startup test procedures, although there are portions which will be conducted simultaneously. Those systems whose environment does not change during ascension to rated temperature and pressure will not receive additional testing. 4

Typical examples of tests, checks, and signoff5 to be performed on systems are listed in Appendix C. During the performance of this testing an Operations Supervisor shall cause a review to be perforraed of the control Room copy of the procedures manual to ensure that changes are marked in the manual and with the required approvals as specified by the administrative procedures. He will addi-tionally verify that personnel on each shift have been familiarized with the changes to procedures through the use of information acknowledgements. Testing plans will be reviewed and upgraded, as necessary, to obtain sufficient documentation and testing scope for the operator training effort. IV. 3TARTUP TESTING A ti pical startup test program is composed of phases charac-terized by differences in plant and test conditions. Startup tests are comprised of four phases which include fuel loading and subsequent tests. 1. Open Vessel Testing 2. Initial Heatup 3. Power Tests 4. Warranty Tests Typical tests to be performed during open vessel, reactor heatup and power ascension are summarized in Figures 1 and 2. The actual testing sequence will be determined at each site. The recommended normal testing sequence can be obtained from Figure 1: Start from the left side of the page and move to the right, completing each column of tests before proceeding to the next column (example - all open vessel tests should be completed before heatup tests are started). The notable exception is that testing at natural circulation on the 100% load line (Test condition 4) will normally be done following pump trips from Test condition 6. The normal recommended sequence of tests in a column would be:

1) core performance analysis, 2) steady state testing, 3) control system tuning and 4) major trips.

The actual testing sequence can vary from recommended test sequence due to equipment problems and other considerations. Typical startup tests are described in the brief summaries of Appendix D. These tests were chosen from the tests listed in Figure 1 to provide insight into operator training obtained during this period. 5

s The significant training related, startup tests will ba / balanced so that each operating shift will: 1. See at least one reactor scram transient. 2. See at least one pressure regulator transient. 3. See at least one turbine trip transient or load rejection. 4. Operate the RCIC (and if applicable HPCI) system. S. See at least one water level setpoint transient. The other testing will be balanced as much as practicable to ensure even exposure to testing for all operating shifts. V. ADDITIONAL TRAINING AND TESTING Upgrading the training program for 4e presently defined test program will meet the training and testing intent of the NUREG sections quoted in the INTRODUCTION section of this report. However, in response to i'nformation obtained at the 9/5/80 meeting held with the NRC and because of our efforts to provide as comprehensive a test program as possible several new tests will be added to the test program. These tests will provide additional technical information to aid in. system and plant operational readiness evaluations. The tests will also provide some operator training. These tests will be performed once per plant and significant training information obtained will be transmitted to non-participating personnel via test critiques. Appendix E contains test descriptions defining the scope of the tests to be added to the test programs. Each facility will write Detailed procedures that will be prepared for individual plants within the scope of those descriptions. CONCLUSIONS As explained in this report, each phase of the testing program provides a building block for the next phase and provides the necessary overlap and depth to ensure that the facility's operating staff will obtain maximum meaningful inplant training to assure that crews will operate their facilities in a safe and competent manner and that all safety related systems are thoroughly tested. We are confident that, as delineated in this report, the increased emphasis on operator training and the addition of new testing, when coupled with the present testing and training programs, more than adequately satisfies the requirements of I.G.1 of NUREGs 0660 and 0694. 6

APPENDIX A EVENT: INTEGRATED ECCS WITH LOSS OF AC & DC POW"R TEST The Integrated ECCS Test is performed to demonstrate the follow-ing: a A. If applicable, the capability of the startup transformer with interconnected buses and the station battery systems with interconnected buses to start all the core standby cooling systems. B. The response of the diesel generators and interconnected equipment to a loss of off-site power (no loss of coolant). C. The capability of the diesel generators with the load shedding logic to auto start and assume all their respective emergency core cooling loads under a loss of offsite power, loss of coolant accident signal (LOCA). D. The capability of the above syst. ems to provide sufficient emergency core cooling equipment during LOCA conditions with "A" DC bus and associated emergency AC bus deenergized. ~ E. The capability of the above system to provide sufficient emergency core cooling equipment during LOCA conditions with "B" DC bus and associated AC bus deenergized. t F. The capability of the above systems to provide sufficient emergency core cooling equipment during LOCA conditions with each remaining individual emergency DC and associated emergency AC bus deenergized. G. These tests are run for a sufficiently long period of i time to verify proper separation between emergency power systems. Typically, the following tests are performed: 1. Simulated LOCA (with offsite power available). l 2. Loss of offsite power (LOSP) with simultaneous simulated LOCA. 3. LOSP with simultaneous simulated LCCA coincident with a loss of the "A" emergency DC battery system and associated emergency AC diesel generator. l 4. LOSP with simultaneous simulated LOCA coincident with a loss of the "B" emergency DC battery system and associated emergency AC diesel generator. 5. Test 4 is repeated substituting each remaining emergency DC and associated emergency AC diesel generator for the "B" system until all systems are tested. : _ _, _,.., _ _ -... ~. _,., _ - -

SHEET 1 of 3 APPENDIX B Typica? systems to be included as part of this program are: Main Steam Systems Main Steam Isolation Valves Main Steam Relief Valves Turbine Seal and Steam Air Ejectors Reactor Vessel & Auxilidry Systems Recirculation System Reactor Water Cleanup System Control Rod Drive System Reactor Vessel Level Instrumentation Standby Liquid Control Remote Shutdown System ECCS System LPCS RHR (including LPCI, Shutdown Cooling, Suppression Pool Cooling and Suppression Pool Spray Modes) HPCI, (if applicable) HPCS (if applicable) Emergency Electric =1 System Diesel Generator, and Emergency Buses Emergency Batteries Vital AC System Plant Support Systems Service Water Reactor Building Closed Cooling Water Turbine Bui1 ding Closed Cooling Water Radwaste Makeup Demineralizer Fuel Pool Cooling Demineralized Water Transfer and Storage

SHEET 2 of 3 I APPENDIX B Plant Supoort Systems (cont'd.) 1 Condensate Transfer and Storage Instrument and Service' Air Ventilation Emergency Service Water Circulating Water 1 1 s I l l f i s . o

APPEMDIX B SHEET 3 of 3 SYSTEM TRAINING - PROCEDURE AND EXPERIENCE CHECKS SYSTEM 1) SHIFT FOREMAN HAS CONDUCTED A REVIE4 OF THE NORMAL OPERATING PROCEDURE WITH THE SHIFT PERSONNEL PROCEDURE NO. 2) THE SHIFT PERSON!!EL HAVE OPERATED THE SYSTEM AS SPECIFIED BELOW: 3) THE SHIFT FOREMAN HAS CONDUCTED A REVIEW OF THE FOLLOWING EMERGENCY OPERATING PROCEDURES: PROCEDURE NO. PROCEDURE NO. PROCEDURE NO. PROCEDURE NO. ~ 4) TSE SHIFT FOREMAN HAS CONDUCTED ORAL EXAMINATION OF HIS SHIFT PERLONNEL CONCERNING THE SYSTEM AND, IN HIS JUDGEMENT, THE l PERSONNEL HAVE ADEQUATE KNOWLEDGE OF SYSTEM OPERATION. 5) SIGN OFF OF ITEMS 1, 2, 3, AND 4. DAY SHIFT SF DATE EVENING SHIFT SF DATE 1 MIDNIGHT SHIFT SF DATE l l l I v P 9

SHEET 1 of 4

• APPENDIX C DURING HEATUP FROM AMBIENT AND 0 PSIG TO RATED TEMPERATURE AND PRESSURE SYSTEM MODE OF OPERATION AND 30T FUNCTIONAL TESTS CRD System In continuous normal operatien, check each fully withdrawn CRD for coupling as it is withdrawn.

Observe tempera-turas are in limits. Observe for proper position indication. Record rod patterns. Drywell Leakage Detection Monitor sump pump integrators which System should be in continuous operation. Determine identified and unidentified leakage rates at 500 and 920 PSIG. Drywell Temp. and Drywell Both should be in continuous operation Cooling per procedure. Process Radiation Monitors In continuous operation. Check for response to increasing power levels. Ventilation System In continuous operation. Check that steam tunnel temperature is within temperature limits at rated temperature and pressure. Verify proper operation of leakage detection systems. Turbine EHC Pressure Start heatup with controlling regulator Controls set at 150 PSIG and by-pass opening jack at O. Nhen reactor pressure is greater than 150 PSIG check that regulator responds to setpoint changes. Rod Worth Minimizer In continuous operation. Verify proper operation as rods are withdrawn. Main Steam Relief Valves Record the discharge throat TC and pressure readings from recorder and determine that the valves do not have seat leakage. Condensate Demineralizer Verify performance of system to System adequately control water quality by observing that water quality stays within limits specified by plant chemist. Check (if applicable) demineralizer bypass valves not in auto...

SHEET 2 of 4 APPENDIk C SYSTEM MODE OF OPERATION AND HOT FUNCTIONAL TESTS TIP System Make trail traces if flux level permits. Verify leak tightness and air / nitrogen purge. Reactor Water Cleanup In continuous operation at System approximately 50 percent to 100 percent flow. Place cleanup recirculation pumps in operation at pressure and operate in all modes. Check that valves operate properly. Reject reactor water back to condenser and radwaste to check reject valve for proper operation. Reactor Recirculation In continuous operation per operating System procedure. Check that seal cavity, oil reservoir, winding temperatures, and MG set temperatures are within limits. Check that cavity pressures follows heatup pressure. Check that recirc. loop temperature recorder indicates the proper temperature increase. Condensate and Feedwater In continuous operation to maintain reactor level. Start standby feed pump turbine per procedure, place in service and remove replaced turbine ~ from service. SRM and IRM In continuous operation. Check for proper retract operation as they are withdrawn. Insert and check for proper operation / indication. Turbine Seal Place in continuous operation per operating procedure. Check that seal steam regulator controls seal pressure. Place backup regulator in service. Vacuum Pump Place in service per operating procedure. Steam Jet Air Ejectors Place in service per operating procedure. Place backup air ejectors in service. SHEET 3 of 4 APPENDIX C SYSTEM MODE OF OPERATION AND HOT FUNCTIONAL TESTS Reactor Vessel Temps and Should be in continuous service. Head Leak Detection Temperatures should be controlled such that vessel temperature differentials are within limits. Head seal leak detector should be valved per operating procedure and observed for seal leakage. Circulating Water. Continuous operation to maintain adequate condenser vacuum. Shift modes of system operation. I AFTER INCREASE FROM RATED TEMPERATURE AND PRESSURE TO 30% POWER A few significant system environmental changes occur between arrival at rated temperature and pressure and completion of 30 percent testing which requires the following additional hot functional checks. SYSTEM MODE OF OPERATION AND HOT FUNCTIONAL ~ CHECKS Turbine Generator During this period the turbine generator will be placed in operation 4 for the first time an;i the following checks should be perf'_.nad which are not part of the formal test program. Verify procedure for turbine warmup and roll to 1,800 RPM. Perform the turbine generator no-load tests. Check turbine vibration at critical speed and 1,800 RPM okay. Verify proper operation of stator cooling and generator seal oil systems. Verify operator familiarization with turbine generator instrumentation and controls both local and remote. Verify oil flow indication at each bearing inspection spout. Verify y that expansion (stretchout) is satisfactory. Perform over-speed checks.. - -..

SHEET 4 of 4 APPEbDIX C SYSTEM MODE OF OPERATION AND HOT FUNCTIONAL CHECKS Feedwater Heater Controls Put feedwater heaters in service, and establish level control. Feedwater temperature will rise. Inspect feedwater line and feedwater pump casings to assura thermal expansion has not opened flanges or affected mechanical seal operation. RBCCW System Check temperatures of cooled components. Readjust as necessary to maintain proper temperature in components as specified in the operating procedures. DURING OPERATION FROM 30 PERCENT TO 100 PERCENT POWER At this point, all safety-related equipment.and procedures have been checked out by the combination of cold functional tests, survei31ance tests, hot functional tests, and the startup tests, performed thus far. The startup test program adequately tests remair.ing plant performance and operating procedures associated with delivering greater than 30 percent power to network. The following is an example of the format for a Hot Functional test signoff: Shift Foreman Ope _r_ations Supervisor / INITIALS Control Rod Drive System 1. Checks required are complete. / 2. System performance adequate to proceed. / 3. Operating procedures modified if necessary. / 4. All shifts knowledgeable of system operation and procedure changes. / l _14_ L

SHEET 1 of 6 APPENDlX D RCIC System Purpose The purpose of this test is to verify the proper operation of the Reactor Core Isolation Cooling (RCIC) system over its expected operating oressure range. Description The RCIC system test consists of two parts: injection to the condensate storage tank and injection to the reactor vessel. The CST injections consist of controlled and quick ytarts at reactor pressures ranging from 150.psig (10.5 kg/cm ) to rated, with corresponding puy discharge pressures throttled between 100 psig (17.6 kg/cm 1 and 250~psig above rated pressure. During this part of the testing, proper operation of the system will be verified and adjustments made as required to meet this criteria. A cold quick start and two hours of continuous operation will be demonstrated. The cold quick start requires a minimum of three days with no RCIC operation. The reactor vessel injection will consist of a cold quick start of the system with all flow routed to the reactor vessel at 25% power. PRESSURE REGULATOR Purpose The purposes of this test are a) to determine the optimum settings-for the pressure control loop by analysis of the transients induced in the reactor pressure control system by means of the pressure regulators, b) to demonstrate the takeover capability of the backup pressure regulator via simulated failure of the controlling pressure regulator and to set the regulating pressure difference between the two regulators to an appropriate value c) to demonstrate smooth pressure control transition between the turbine control valves and bypass valves when the reactor steam generation exceeds the steam flow used by the turbine. -

SHEET 2 of 6 APPENDIX D PRESSURE REGULATOR Description The pressure setpoint will be decrgased and then increased rapidly by about 10 psi (0.7 J/cm ) and the response of the system will be measured in each case. It is desirable to accomplish the setpoint change in less than 1 second. At specified test condition.s the load limit setpoint will be set so that the transient is handled by control valves, bypass valves and both. The back-up regulator will be tested by simulating a failure of tne operating pressure regulator so that the back-up regulator takes over control. The response of the system will be measured and evaluated and regulator settings will be optimized. FEEDWATER SYSTEM Purpose The purposes of this test are a) to adjust the feedwater control system for acceptable reactor water level control, b) to demonstrate the capability of the automatic core flow runback feature to prevent low water level scram following the trip of one feedwater pump, c) to demonstrate adequate response to feedwater temperature loss, and d) to determine the maximum feedwater runout capability. Description Reactor water level setpoint changes of approximately 5 to 6 inches (12.5 to 15.3 cm) will be used to evaluate and adjust the feed-water control system settings for all power and feedwater pump modes. The level setpoint changes will also demonstrate core stability to subcooling changes. One of two operating feedwater pumps will then be tripped and the automatic flow runback circuit l will act to drop power to within the capacity of the remaining pump. The worst single failure case of feedwater temperature l loss will be performed and the resulting transients recorded between 80 and 90% power and near rated core flow rate. Data will ( be taken betwean 50 and 100% power to allow the determination of the maximum feedwater runout capability. l l l l l l l

SHEET 3 of 6 APPENDIX D MAIN STEAM ISOLATION */ALVES Purpose The purposes of this test are al to functionally check the main steam line isolation valves (MSIVs) for proper operation at selected power levels, b) to determine isolation valve closure times c) to determine maximum power at which full closures of a single valve can be performed without a scram and d) to determine the reactor transient behavior resulting from the simultaneous full closura of all MSIVs. Description At 5% and greater reactor power levels, individual fast closure of each MSIV will be performed to verify their functional performance and to determine closure times. The MSIV closure times will be determined from the MSL isolation data. To determine the maximum power level at which full individual closures can be parformed without a scram actuation will be performed between 50 and 65% power and used to extrapolate to the next test point between 70 and 85% power, and ultimately to the maximam power t. 4 condition with ample' margin to scram. A test of the simultaneous full closure of all MSIVs will be performed at.:>75% of rated thermal power. Correct performance of the BCIC and relief valves will be shown. Reactor process variables will be monitored to determine the transient behavior of the systea during and following the Main Steam Line (MSL) isolation. TURBINE TRIP AND GENERATOR LOAD REJECTION Purpose The purpose of this test is to demonstrate the response of the reactar and its control systems to protective trips in the turbine and the generator. i l _ ~

SHEET 4 of 6 APPENDIX D TURBINE TRIP AND GENERATOR LOAD REJECTION Description Turbine Trip (closure of the main turbine stop valves within approx. 0.1 second) and Generator Trip (closure of the main turbine control valves in about 0.1 to 0.2 seconds) will be performed at selected power levels during the Startup Test Program. At low power levels, reactor protection following the trip is provided by high neutron flux and vessel high pressure scrams. For the protective trips occurring at intermediate and higher power levels, reactor will scram by relays, actuated by stop/ control valve motion. A generator trip will be performed at low power level such that nuclear boiler steam generation is jus: within the bypass valve capacity to demonstrate scram avoidance. For the trips performed at intermediate power range, reactor scram is most important in controlling the transient peaks. Above about 40% power, the recirculation pump circuit breakers are both automatically tripped (RPT) and subsequent transient pressure rise will be limited by the opening of the bypass valves initially, and the safety relief valves, if necessary. For the turbine trip, the main generator breakers remain closed for a time so there is no rise in turbine generator speed, whereas, in the generator trip, the main generator breaker opens and the residual turbine steam will cause a momentary rise in the generator speed. SHUTDOWN FROM OUTSIDE THE CONTROL ROOM Purpose The purpose of this test is to demonstrate that the reactor can be brought from a normal initial steady-state power level to the point where cooldown is initiated and under control with reactor vessel pressure and water level controlled from outside the control room..-

SHEET 5 of 6 APPENDIX D SHUTDOWN FROM OUTSIDE THE CONTROL ROOM Pescription The test will simulate the reactor shutdown following a control room evacuation. The reactor will be scrammed from a normal steady-state condition, the vessel water level and pressure will be controlled from outside the control room. All other operator actions not directly related to vessel water level and pressure will be performed in the main control room. RECIRCULATION SYSTEM (for variable speed MG set plants) Purpose The purposes of this test are 1) to obtain recirculation system performance data under.different operational conditions, such as pump trip, flow coastdown, pump restart 2) to verify that no recirculation system cavitation will occur in the operable region of the power-flow map and 3) to verify that, during the trip of recirculation pumps, the feedwater control system can satisfactorily control water level without a resulting turbine trip / scram, and to record and verify acceptable performance of the recirculation pump circuit breaker trip system (RPT). Description Recirculation pump trips are performed to determine reactor water level transient characteristics. The reactor transient response during 'the trip and coastdown of one recirculation M-G set and its pump will be determined. All single-pump trips will be initiated by tripping either the M-G Set drive motor breaker or field breaker. Single pump trips of one M-G set drive motor will be used to determine the Feedwater Control System Transient performance. These transients will be extrapolated to field breaker trip of one pump. In case of higher power turbine or generator trips, there is an automatic opening of circuit breakers in the pump power supply. The result is a fast core flow coast-down that helps reduce peak neutron and heat flux in such events. The two pump circuit breaker trip at test condition 3 provides the best opportunity to observe the drive flow and core flow coastdowns while not being greatly affected by other transients, as in the midst of a T/G trip. 19-

SHEET 6 of 6 APPENDIX D LOSS OF TURBINE-GENERATOR AND OFFSITE POWER Purpose i This test determines. electrical equipment and reactor system transient performance during a loss of auxiliary power. Description I The Loss of Auxiliary Power Test will be performed at 20% to 30% of rated power. The proper response of the reactor plant equipment, automatic switching equipment and the proper sequencing of the diesel generator loads will be checked. Appropriate reactor parameters will be recorded during the resultant transient. I e i l l -

SHEET 1 of 5 APPENDIX E TEST: STARTUP OF THE RCIC SYSTEM AFTER LOSS OF AC POWER TO THE SYSTEM. PURPOSE: VERIFY THE DESIGN BASIS ABILITY OF THE SYSTEM TO START WITHOUT THE AID OF AC POWER WITH THE EXCEPTION OF THE RCIC DC/AC INVERTERS. INITIAL CONDITIONS: PREOPERATIONAI, TEST HAS BEEN PERFORMED ON RCIC SYSTEM.

• IF TEST IS PERFORMED PRIOR TO THE AVAILABILITY OF NUCLEAR STEAM, SUFFICIENT AUXILIARY BOILER CAPACITY AND PIPING TO RUN THE riCIC TURBINE / PUMP MUST BE AVAILABLE.

SYSTEM VALVES IN NORMAL STANDBY LINEUP (SUCTION FROM CST) NOTE: 1) IF THE AUXILIARY BOILER IS USED AS THE TURBINE STEAM C'IPPLY, TAG CLOSED THE DRYWELL STEAM SUPPLY IJM ATION VALVE. 2) FLOW CAN EITHER BE DIRECTED TO THE REACTOR PRESSURE VESSEL OR BACK TO THE CONDENSATE STORAGE TANK. POWER TO ALL RCIC COfiPONENTS FED BY SITE AC POWER SHALL BE SECURED. STATION EATTERIES SHALL BE FULLY CHARGED. ^ INSTRUtiENT AIR SHALL BE AVAILABLE FOR OPERATION AND CONTROL OF APPLICABLE VALVES. INSTRUliENTS SHALL BE CALIBRATED AND SETPOINTS, WHERE APPLICABLE, SHALL BE VERIFIED. TEST DE3CRI? TION: PERFORM A MANUAL INITIATION OF THE RCIC SYSTE!! UTILlZING THE liANUAL INITIATION SWITCH AND VERIFY THE PROPER OPERATION OF ALL COMPONENTS REQUIRED FOR THE RCIC STARTUP TRANSIENT TO RATED FLOW. NOTE: MANUAL MANIPULATION OF SOME W.JES WILL BE REQUIRED IF FLON IS RETURNED TO THE CST OR AUXILIARY BOILER STEAM IS USED. ACCEPTANCE CRITERIA: PROPER OPERATION OF ALL COMPONENTS FOR THE RCIC STARTUP TRANSIENT UNTIL RATED FLOW IS OBTAINED.. _

SHEET 2 of 5 APPENDIX E TEST: OPERATION OF THE RCIC SYSTEM WITH A SUSTAINED LOSS OF AC POWER TO THE SYSTEM PURPOSE: TO VERIFY THE OPERATION OF RCIC BEYOND ITS DESIGN BASIS TO EVALUATE THE LIMITS OF SYSTEM OPERATION WITH EXTENDED LOSS OF AC POWR TO IT AND SUPPORT SYSTEMS WITH THE EXCEPTION OF THE RCIC DC/AC INVERTERS. INITIAL CONDITIONS: o PREOPERATIONAL TEST HAS BEEN PERFORMED ON RCIC SYSTEM. o IF TEST IS PERFORMED PRIOR TO THE AVAILABILITY OF NUCLEAR STEAM, SUFFICIENT AUXILIARY / BOILER CAPACITY AND PIPING TO RUN THE RCIC TURBINE /FJMP MUST BE AVAILABLE. o SYSTEM VALVES IN NORMAL STANDBY LINEUP (SUCTION FROM CST). NOTE: 1) THE AUXILIARY BOILER IS USED AS THE TURBINE STEAM SUPPLY, TAG CLOSED THE DRYWELL STEAM SUPPLY ISOLATION VALVE. o POWER TO ALL RCIC COMPONENTS FED BY SITE AC POWER SHALL BE SECURED, INCLUDING RCIC AREA COOLERS AND BATTERY CHARGERS SUPPLYING THE STATION BATTERY FROM WHICH RCIC DC LOADS ARE POWERED. ~ o RCIC BIsTTERIES SHALL BE FULLY CHARGED. I l o INSTRUMENT AIR SHALL BE AVAILABLE FOR OPERATION AND CONTROL OF APPLICABLE VALVES. o INSTRUMENTS SHALL BE CALIBRATED AND SETPOINTS, WHERE APPLICABLE, SHALL BE VERIFIED. TEST DESCRIPTION: START AND OPERATE TK* RCIC SYSTEM WITH RETURN TO THE CST AND RUN FOR 2 HOURS OR UNTIL ANY SYSTEM LIMITING PARAMETER IS APPROACHED (E.G., HIGH RCIC AREA TEMP, LOW BATTERY VOLTAGE, OR HIGS SUPP. POOL i TEMP) TRIPPING AND RESTARTING THE RCIC SYSTEM TWO ADDITIONAL TIMES DURING THIS OPERATING PERIOD. ACCEPTANCE CRITERIA: NONE l i '

i SHEET 3 of 5 APPENDIX E TEST: RCIC OPERhTION TO PROVE DC SEPARATION. PURPOSE: VERIFY PROPER OPERATION OF THE RCIC DC COMPONENTS WHEN NON RCIC STATION BATTERIES ARE DISCONNECTED. INITIAL CONDITIONS: PREOPERATIONAL TEST HAS BEEN PERFORMED ON RCIC SYSTEM. TEST TO BE PERFORMED PRIOR TO FUEL LOAD. THIS TEST IS PERFORMED PRIOR TO THE AVAILABILITY OF NUCLEAR STEAM, SUFFICIENT AUXILIARY BOILER CAPACITY AND PIPING TO RUN THE RCIC TURBINE / PUMP MUST BE AVAILABLE. SYSTEM VALVES IN NORMAL STANDBY LINEUP (SUCTION FROM CST). DRYWELL STEAM SUPPLY ISOLATION VALVE TAGGED SHUT. STATION BATTERIES SHALL BE FULLY CHARGED. INSTRUMENT AIR SHALL BE AVAILABLE FOR OPERATION AND CONTROL OF APPLICABLE VALVES. INSTRUMENTS SHALL BE CALIBRATED AND SETPOINTS, WHERE APPLICABLE, SHALL BE VERIFIED. TEST DESCRIPTION: START AND OPERATE THE RCIC SYSTEM WITH RETURN TO THE CST. DURING SYSTEM OPERATION DISCONNECT, EACH NON-RCIC STATION BATTERY FROM ITS BUS AND VERIFY PROPER OPERATION OF EACH RCIC DC COMPONENT. ACCEPTANCE CRITERIA: PROPER OPERATION OF RCIC DC COMPONENTS WITH NON-RCIC STATION BATTERIES DISCONNECTED. 1,,. - _

SHEET 4 of 5 APPENDIX E TEST: INTEGRATED REACTOR PRESSURE VESSEL LEVEL FUNCTIONAL TEST. PURPOSE: VERIFY THAT INSTRUMENTS CONNECTED.TO THE RPV ARE TUBED PROPERLY, THAT THE TUBING IS NOT BLOCKED AND THAT INSTRUMENT TRACKING IS PROPER. INITIAL CONDITIONS: ALL INSTRUMENTS CONNECTED TO THE RPV HAVE BEEN CALIBRATED AND ARE OPERABLE. RPV HAS BEEN FLUSHED AND IS CLEAN.

• ALL RPV INSTRUMENT TUBING HAS BEEN FILLED, ALL INSTRUMENTS ARE VENTED, AND PROPER VALVE LINEUP VERIFIED.
• A SOURCE OF DEMINERALIZED WATER IS AVAILABLE TO FILL THE RPV.

FUEL HAS NOT BEEN LOADED INTO THE RPV. RPV HEAD REMOVED OR ADEQUATELY VENTED TO PREVENT PRESSURIZATION. TEST DESCRIPTION: RAISE AND LOWER.(OR LONER AND RAISE, WHICHEVER IS MOST CONVENIENT) THE RPV WATER LEVEL THROUGH THE RANGE OF RPV LEVELS NECESSARY TO VERIFY THE PROPER OPERATION AND TRACKING OF EACH RPV CONNECTED INSTRUMENT. NOTE: THE TEMPERATURE AND PRESSURE CONDITIONS AT WHICH THIS TEST WILL BE PERFORMED ARE NOT THE CONDITIONS FOR WHICH THE VARIOUS INSTRUMENTS ARE CALIBRATED. THERE WILL NOT BE A ONE-TO-ONE CORRESPONDENCE BETWEEN ACTUAL REACTOR VESSEL LEVEL CHANGE AND INDICATED LEVEL CHANGE. ACCEPTANCE CRITERIA: EACH AFFECTED RPV INSTRUMENTS OPERATION AND TRACKING IS SATISFACTORY.. -.

SHEET 5 of 5 APPENDIX E TEST:. INTEGRATED CONTAINMENT PRESSURE INSTRUMENTATION TEST (TEST TO BE PERFORMED IN CONJUNCTION WITH CONTAINMENT INTEGRATED LEAK RATE TESTING) PURPOSE: VERIFY'THE PROPER CONNECTION, AND TRACKING OF CONTAINMENT PRESSURE INSTRUMEh"IS AND THAT THE TUBING SUPPLYING THESE INSTRUMENTS IS NOT BLOCKED. J INITIAL. CONDITIONS: e ALL INITIAL CONDITIONS FOR CONTAINMENT INTEGRATED LEAK' RATE TESTING HAVE BEEN ESTABLISHED. o ALL CONTAINMENT PRE'SSURE INSTRUMENTS HAVE BEEN CALIBRATED AND ARE VALVED INTO SERVICE. TEST DESCRIPTION: AS CONTAINMENT PRF3SURE IS INCREASED, DURING THE CONTAINMENT INTEC3.ATED LEAK RATE TEST, VERIFY EROPER TRACKING ;/ ALL CONTAINMENT PRESSURE INSTRU-MENTS.. ACCEETANCE. CRITERIA: ACE. CONTAINMENT INSTRUMENTS TRACK PROPERLY AND ALL AEEECTED INSTRUMENT LINES.ARE CLEAR OF OBSTRUCTIONS. 1 m

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9 P SHEET 2 of 2 FIGURE 2 DEFINITION OF TESI CONDITION REGIONS Test Condition No. Power-Flow Man Region and Note,s, 1 Before main generator synchronization-between 5% and 20% thermal power-within 10% of M-G Set minimum opera-ting sp2ed line in Local Manual mode. 2 After main generator synchronization-between the 50% and 75% power rod lines-between M-G. Set minimum speeds for Local Manual and Master Manual modes the lower power corner must be less than Bypass Valve capacity. 3 Between the 50% and the 75% control rod lines, with core flow rated between 80% and 100% of its rated value. 4 On the natural circulation core flow line - within 5% of the intersection with the 100% power rod line. SM Within 5% of the 100% power rod line - within + 5% of the minimum M-G Set speed for Master Manual mode - Recirculation System engaged in Master Manual mode only. 5A Within 5% of the 100% power rod line - within + 5% of the core flow rate at the lower end of the Auto Flow Control region - Recirculation System Engaged in Auto Flow Control mode only. 6 Between 95% and 100% of rated power and between 95% and 100% of rated core flow rate. G y c n

I APPENDIX F NUREG-0737 ITEM I.G.1 This report applies to the following plants, whose Owners participated in the report's development. Detroit Edison Enrico Fenni 2 Long Island Lighting Shoreham Mississippi Power & Light Grand Gulf 1 & 2-Pennsylvania Power & Light Susquehanna 1 & 2

• M esp..-

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SNPS-1 FSAR II.B.1 Reactor Coolant System Vents NRC Position Each applicant and licensee shall install reactor coolant system (RCS) and reactor vessel head high point vents remotely operated trom the control room. Although the purpose of the system is to vent noncondensible gases from the RCS wnicn may inhibit core cooling during natural circulation, the vents must not lead to an unacceptable increase in the probability of a loss-ot-coolant accident (LOCA) or a challenge to containment integrity. Since these vents form a part of the reactor coolant pressure bou.mdary, the design of the events shall conform to the requirements of Appendix A to 10 CFR Part 50, " General Design Criteria." The vent system shall be designea with suf ficient redundancy that assures a low probability of inadvertent or irreversible actuation. Each licensee shall provide the following information concerning the design and operation of the high point vent system: a. Submit a description of the design, location, size, and power supply for the vent system along with results of analyses for loss-of-coolant accidents initiated by a break in the vent pipe. The results of the analyses should demonstrate compliance with the acceptance criteria of 10 CFR 50.46. b. Submit procedures and supporting analysis for operator use of the vents that also include the information available to the operator for initiating or terminating vent usage. The important safety f unction enhanced Dy this venting capability is core cooling. For events beyond the present design

basis, this venting capability will substantially increase the plant's ability to deal with large quantities or noncondensible gas wnich could interfere with core cooling.

Procef. ares addressing the use of the reactor coolant system vents should define the conditions under which the vents should ne used as well as the conditions under which the vents should not be-used. The procedures should be directed toward achieving a substantial increase in the plant being able to maintain core cooling witnout loss of containment integrity for events Deyond the design basis. Tne use of vents for accidents within tne normal design basis must not result in a violation or tne requirements of 10 CFR 50.44 or 10 CFR 50.4b. The r,ine of the reactor coolant vents is not a critical issue. The desired venting capability can De achieved with vents in a fairly broad spectrum of sizes. The criteria for sizing a vent-can be developed in several ways. One

approach, which may be considered, is to specify a volume of noncondensible gas to be II.B.1-1 l

A: .a i SNPS-1 FSAR vented and in a specific venting time. For-containments particularly vulnerable to f ailure from large hydrogen releases over a short period of time, the necessity and desirability for contained venting outside the containment must be consicered (e.g., into a decay gas collection and storage system). knere practical, the reactor coolant system vents should be kept smaller than the size corresponding to the detinition ot LOCA (10 CFR 50, Appendix A). This will minimize the challenges to the emergency core cooling system (ECCS) since the inadvertent opening of a vent smaller than the IDCA detinition would not require BCCS actuation, although it may result in leaxage beyond technical specification limits. On WRs, the use of new or existing lines whose smallest orifice is larger than the LOCA definition will require a valve in series with a vent valve that can be closed from the control room to terminate the LOCA that would result if an open vent valve could not be reclosed. A positive indicatlan of valve position should be provided in the control room. The reactor coolant vent system shall be oryerable from the-control room. Since the reactor coolant system vent will be part of the reactor coolant system pressure

boundary, all requirements for the reactor pressure boundary must be met, - and, in

addition, surricient redundancy should be incorporated into the design to minimize the probability of an inadvertent -actuation of the system.

Administrative procedures may be a viable option to meet the single-fallure criterion. For vents larger than the LOCA derinition, an analysis is required to demonstrate co.apliance with 10 CFR 50.46. The probability of a vent path f ailung to close, once opened, should be rainimized; this is a new requirement. Each vent must have its power supplied from an emergency bus. A single failure within the power and control aspects of the reactor coolant vent system should not prevent isolation of the entire vent syste.n when required. On BWRs, block valves are not required in lines with safety valves that are used for venting. Vent paths from the primary system to withus containment should go to those areas that provide good minng with containment air. The reactor coolant vent system (i.e., vent valves, block valves, position indication devices, cable terminations, and piping) shall be seiumically and environmen'. ally qualitied in accordance with IEEE 344-1975 as supplemented 9y Regulatory buide 1.100, 1.92, and SEP 3.92, 3.43, and 3.10. Environmental qualifications are in accordance with the May 23, 1980 Constission Order and Memorandum (CLI-80-21). II.B.1-2

SNPS-1 FSAR Provisions to test for operabili+.y of the reactor coolant vent system snould be a part of the desi gn. Testing snould be performed in accordance with subsection IWV of Section XI of tne ASME Code for Category B valves. It is important that the displays and controls added to the control room as a result of tnis requirement not increase the potential for operator error. A human-factor analysis should be performed taking into consideration: a. the use of this information by an operator during both normal and abnormal plant conditions, b. integration into emergency procedures, c. integration into operator training, and d. Other alarms during emergency and need ror prioritization of alarms. BWR Design Considerations Since the BWR owners' group has suggested that the present BWR designs have an inherent capability to vent, a question relating to the capability of existing systems arises. The anility or these systems to vent the RCS or noncondensible gas generated during an accident must be demonstrated. Because of ditf erences among the head vent systems for BWRs, eacn licensee or applicant should address the specitic design teatures of this plant and compare them with the generic venting capability proposed by the BWR owners' group. In addition, the ability of these systems to meet the same requirements as the PWR vent system must be documented. l In addition to RCS venting, eacn BWR licensee should address the ability to vent other systems, such as the isolation condenser which may be required to maintain adequate core cooling. If the l production of a large amount of noncondensible gas would cause the loss of tunction of such a system, remote venting or that system is required. The qualifications of such a venting system should be the same as that required for PWR venting systems. l PWR Vent Design Considerations Each PWR licensee should provide the capability to vent tne reactor vcssel head. The reactor vessel head vent should be capable of venting noncondensible gas Irom the reactor vessel hot legs (to che elevation of the top of the outlet nozzle) and cold legs (through head jets and other leakage paths). l Additional venting capability is required for those portions or each hot leg that cannot be vented through the reactor vessel } head vent or pressurizer. It le impractical to vent each or the many thousands of tubes in a U-tube steam generator; however, the II.B.1-3 1

SNPS-1 FSAR staff believes that a procedure can ne developed that assures sufficient liquid or steam can enter the U-tube region so that decay heat can be effectively removed trom the RCS. Such operating procedures should incorporate this consideration. Venting of the pressurizer is required to assure its availability for system pressure and volume control. These are important considerations, especially during natural circulation. ,LILCO Position LILCO endorses the BWR Owners' Group position. Presented below is a discussion of the features provided for

Shorenam, which provide protection against the accumulation ot noncondensables in the reactor pressure vessel.

1. Satety Relief Valves (SRV) The Shoreham facility is provided with eleven power operated SRV's, which can be manually operated from the control room to depressurize (vent) the reactor pressure vessel (RPV). Seven of the eleven SRV's comprise the automatic depressurization system (ADS) and are automatically actuated under certain conditions as described in Chapter 13. The SRV's are connected to the tour main steam lines which in turn are connected to the RPV above the tuel. Each SRV discharge is piped to a quencher discharge device located at the bottom of the suppression pool. Indication f or an-open or closed SRV is provided in the main control room as discussed in our response to Item II.D.3. The SRV's, steam line, and ADS are safety grade and conform with Appendix A to 10 CFR 50 General Design Criterla including the single failure criterion and the requirements of IEEE-279, as applicable. l 2. Reactor Core Isolation Cooling (RCIC) and High Pressure Core Injection (HPCI) Systems l l The RCIC and HPCI, installed at Shoreham, are provided witn l steam turbine driven pumps. The RCIC and HPCI turd 1nes are supplied with steam from the RPV through the main steam lines. The exhaust steam from these turbines is discharged to the suppression pool. Through operation of the RCIC and l l HPCI turbines the RPV is vented. The equipment required for initiation of the RCIC and HPCI are completely independent or auxillary ac power; they require de power, derived from the station battery. These systems are automatically started upon a RPV low water level signal. Controls are provided for [ remote manual operation from the main control room. II.B.1-4 l

SNPS-1 FSAR 3. Normally Open Reactor Head Vent Line A normally open reactor head vent line is provided in tne Shoreham design. This line discharges to one of the main steam lines which supplies the RCIC and HPCI systems and vents the portion of the RPV above the main steam nozzles. The head vent line is provided with a saf ety-related motor operated valve powered from an emergency bus and operable from the main control room. Indication is also provided in tne main control room. This line conforms to the same design requirements as those for the reactor coolant pressure boundary. We consider that the power operated SRVs, as described in one (1) above, fully satisfy the intent of the reactor coolant system venting requirement. The alternative path of venting tne RPV oescribed in two (2)

above, however, provides additionally installed protection against the accumulation of noncondensanle gasses in the reactor pressure vessel.

Botn of these metnods for venting the RPV can utilize the head vent line described in three (3) anove, to aid in the removal or noncondensable gases. Specific procedures addressing the use of reactor coolant vents are not required since the SRV*s (in the ADS mod e),

HPCI, and RCIC will function automatically in their designed modes to ensure adequate core cooling and provide continuous venting to the suppression pool.

Continuous

venting, as mentioned above, precludes the need for special analyses with regard to vent sizing.

In

addition, supplemental pipe break analysis is not required since a break of tne SRV discnarge line or other steam lines noted above is less severe tnan the design basis complete steam line break analyzea l

for Shorenam. The above discussion, as previously submitted in response to NUREG-0578, applies to venting the RPV. Post accident RPV cooling is supplied by the emergency core cooling systems (ECCS). Tne ECCS*s do not require venting, since the coolant is pumped either from the condensate storage tank or the suppression pool. Neither of these water sources is subject to the potentially nign noncondensable gas concentrations that could exist in tne reactor coolant pressure boundary following an accident. l l l 1 II.B.1-5 l L

SNPS-1 FSAR II.B.4 Training for Mitigating Core Damage NRC Position Prior to fuel loading develop a training program to instruct all operating personnel in the use of installed

systems, including systems that are not engineered safety

features, and instrumentation to monitor and control accidents in which the.

core may be severely damaged. Prior to issuance of a full power license complete the training of all operating personnel in the use of installed systems to monitor and control accidents in which the core may be severely damaged. LILCO Position It is LILCO's position that prior to fuel loading a training program for mitigating core damage will be developed. The training program will be completed p::ior to issuance of a full power license by all licensed operating personnel and STA's. The prograra will include the following: 3. Incore Instrumentation a. Use of fixed or moveable incore detectors to determine extent of core damage and geometry changes. 2. Vital Instrumentation a. Instrumentation response in an accident environment; failure sequence (time to

failure, method of failure); indication reliability (actual versus indicated level).

b. Alternative methods for measuring flows, pressures, levels, and temperatures of the primary system. 3. Primary Chemistry-a. Expected chemistry results with severe core damage; consequences of transferring small quantities of liquid outside containment; importance of using i leak-tight systems. b. Expected isotopic breakdown for core damage; for clad damage. l c. Corrosion effects of extended immersion in primary water; time to failure. i l l II.B.4-1

SNPS-1 FSAR 4. Radiation Mcnitoring a.

Response

of process and ~ area monitors to severe damage; behavior. of decectors when. saturated; method for detecting radiation readings by direct measurement at detector output-- (overranged detector!; expected accuracy of detectors at different locations; use of detectors to determine extent of core damage. b. Methods of determining dose rate inside containment from measurements taken outside containment. 5. Gas Generation a. Methods of hydrogen generation during an accident; other sources of gas (Xe, Kr); techniques for venting or disposal of noncondensibles. b. Hydrogen flammability and explosive limit; sources of oxygen in containment or reactor coolant system. 4 II.B.4-2 4 ,-r w .,4, ,.4--,, .,w-- --,,o -m-- p.---m-e y er, ,,~a.. a.-,y..~4 ,-,.,_,,,---y .,y--r-e-, ,-,e,-- --w

SNPS-1 FSAR II.D.1 Performance Testino of BWR and PWR Reliet and Safety valves Pressurized-water rauc+.or and boiling-water reactor licensees and applicants shall conduct testing to quality the reactor coolant system reller and satety valves under expected operating conditions for design-basis transients and accidents. Licensees and applicants shall determine the expected valve operating conditions through the use of analyses of accidents and anticipatea operational occurrences referenced in Regulatory Guide 1.70, Revision 2. The single failures applied to tnese analyses shall be chosen so that the dynar10 forces on the safety and relief valves are maxraized. Test pressures shall be the highest predicted by conventional safety analysis procedures. Reactor coolant system relief and safety valve qualification shall include qualification of associated control circuitry, piping, and supports, as well as tne valvea themselves. A. Performance Testing of Relief and Safety Valves--The following information must be provided in report form by October 1, 1981: (1) Evidence supported by test ot satety and relief valve functionability for expected operating and accident (non-ATWS) conditions must be provided to NRC. The testing snoula demonstrate that the valves w111 open and reclose under the expected flow conditions. (2) Since it is not planned to test all valves on all plants, each licensee must submit to Nhc a correlation or other evidence to substantiate tnat the valves tested in the EPRI (Electric Power Research Institute) or other generic test program demonstrate the functionanility of as-installed primary relief and safety valves. This correlation must show that the test conditions used are l equivalent to expected operating and accident cond.itions as prescribed in the final satety analysis report (FSAR). The etiect of as-built relief and satety valve discharge piping on valve operability must also De accounted for, if it is ditterent trom the generic test loop piping. (3) Test data including criteria for success and failure or valves tested must be provided for NRC staff review and evaluation. These test data should include data that would permit plant-specific evaluation 01 discharge piping and supports that are not directly tested. B. Qualification of PWR Block Valves--Although not specifically listed as a short-term lessons-learned requirement in NUREG-0578, qualification of PWR block valves is required by II.D.1-1 l l_. - - - - - - - - - - - - - - - ~ - -.

SNPS-1 FSAR the NRC Task Action Plan NUREG-0660 under task item II.D.1. It is the understanding of the NRC that testing of several commonly used block valve designs is already included in the . generic EPRI PWR satety and relief valve testing program to be completed by July 1, 1981. By means of this

letter, NRC is establishing July 1,1982 as the date for verification of block valve functionability.

By July 1, 1982, each PWR

licensee, for plants so equipped, should provide evidence supported by test that the block or isolation valves between the pressurizer and each power-operated relief valve can be

operated, closed, and opened for all 11uld ccnditions expected under operating and accident conditions.

C. ATHS Testing--Although ATWS testing need not De completed ny July 1,

1981, the test racility should be designed to accommodate ATWS conditions of approximately 3200 to 3500 (Service Level C pressure limit) pai and 700 E

with aufficient capacity to enable testing of rdlef and saiety valves of tne size and type used on operating pressurized-water reactors. LILCO Position LILCO is participating in the Safety Relief Valve (SRV) Performance Testing Program being conducted on a generic basis by the BWR Owners

• Group (BWROG).

A description 01 this test program was suomitted to NRC by the BWR Owners' Group on September 17, 1980. The results of this test program will coniirm the adequacy of numerous SRV types for the alternate shutdown cooling condition which is the only expected condition resulting in liquid or two phase discharge through the SRV's. The SRV*s utilized at Shoreham, the Target Rock 6K10 Two-Stage PilorM)perated SRV Model 7567F, are included in this test program. This has been previously documented in a letter from D. B. Waters (BWROG) to D. G. Eisenhut (14RC), "Respanses to NRC Questions on *.he BWR SRV Test Program" dated March 31, 1981. In addition, a Shoreham spec 111c low tiow SRV tesc program was completed for Shoreham and a report submitten to tne Nhc via SNRC-520, dated December 1, 1980. In contract with General Electric Co., Wyle Laboratories has fabricated a test facility in Huntsville, Alabama and has oeen conducting tests on the SRV*s and an associated discharge line test configuration this Spring. Testing is expected to be completed in May 1981. LILCO will ne transmitting the preliminary generic BNL SRV test program results which are applicable to Shoreham to the NRC by July 1, 1981. By October 1,

1981, LILCO will transmit a 11nal test report contirming the adequacy of Shoreham's specific SRV's.

II.D.1-2

SNPS-1 FSAR By January 1,

1982, LILCO will trannuait an evaluation of SRV discharge line piping and supports and their erfect upon valve operability based upon the test program final results.

II.D.1-3

SNPS-1 FSAR II.E.4.2 Containment Isolation Dependability NRC Position Containment isolation system designs shall comply with the recommendations of Standard Review Plan (SRP) Section 6.2.4 (i.e., that there be diversity in the parameters sensed for the initiation of containment isolation). The reference to SRP 6.2.4 is only to the diversity requirements set forth in that document. All plant personnel shall give careful consideration to the definition of essential and nonessential systems, identify each system determined to be essential, identify each system determined to be nonessential, describe the basis for selection of each essential

system, modify their containment isolation designs accordingly, and report the results of the reevaluation to the NRC.

For postaccident situations, each nonessential penetration (except instrument lines) is required to have two isolation barriers in series that meet the requirements of General Design Criteria 54, 55, 56, and 57, as clarified by Standard Review

Plan, Section 6.2.4.

Isolation must be performed automatically (i.e., no credit can be given for operator action). Manual valves must be sealed closed, as defined by Standard Review Plan, Section 6.2.4, to qualify as an isolation barrier. Each automatic isolation valve in a nonessential penetration must receive the diverse isolation signals. All nonessential systems shall be automatically isolated by the containment isolation signal. Revision 2 to Regulatory Guide 1.141 will contain guidance on the classification of essential versus nonessential systems and is due to be issued by June 1981. The design of control systems for automatic containment isolation valves shall be such that resetting the isolation signal will not result in the automatic reopening of containment isolation valves. Reopening of containment isolation valves shall require deliberate operator action. Administrative provisions to close all isolation valves manually before resetting the isolation signals is not an acceptable method of meeting this position. Ganged reopening of containment isolation valves is not acceptable. Reopening of isolation valves must be performed on a valve-by-valve

basis, or on a line-by-line basis, provided that electrical independence and other single-failure criteria continue to be satisfied.

The containment setpoint pressure that initiates containment isolation for nonessential penetrations must be reduced to the minimum compatible with normal operating conditions. II.E.4.2-1

i SNPS-1 FSAR The containment pressure history during normal operation should be used as a basis for arriving at an appropriate minimum pressure setpoint for intiating containment isolation. The pressure setpoint selected should be far enough above the maximum observed (or expected) pressure insido containment during normal operation so that inadvertent containment isolation does not occur during normal operation. from instrument drift or fluctuatione due to the accuracy of the pressure sensor. A margin of 1 psi above the maximum expected containment pressure should be adequate to account for instrument error. Any proposed values greater than 1 psi will require detailed justification. Applicants for an operating license and operating plant licensees that have operated less than one year should use pressure history data from similar plants that have operated more than one

year, if

possible, to arrive at a

minimum containment setpoint pressure. Containment purge valves that do not satisfy the operability criteria set forth in Branch Technical Position CSB 6-4 or the Staff Interim Position of October 23, 1979 (Attachment 1) must be sealed closed as defined in SRP 6.2.4, item II.3.f during operational conditions 1, 2, 3, and 4. Furthermore, these valves must be verified to be closed at least every 31 days. Sealed-closed purge isolation valves shall be under administrative control to assure that they cannot be inadvertently opened. Administrative control includes mechanical devices to seal or lock the valve closed, or to prevent power from being supplied to the valve operator. Checking the valve position light in the control room is an adequate method for verifying every 3] days that the purge valves are closed. Containment purge and vent isolation valves must close on a high radiation signal. II.E.4.2-2

SNPS-1 FSAR ATTACHMENT 1 OCTOBER 23, 1979* INTERIM POSITION FOR CONTAINMENT PURGE'AND VENT VALVE OPERATION PENDING RESOLUTION OF ISOLATION VALVE OPERABILITY Once the conditions listed below are met, restrictions on use of the containment purge and vent system isolation valves will be revised bared on our review of your responses to the November 1978 letter on this subject justifying your proposed operational mode. The November 1978 letters to all licensees identified certain events related to containment purging of concern to the NRC and requested commitments to either cease purging or justify purging operations. The revised restrivtions can be established separately for each system. (1) Whenever the containment integrity is required, emphasis should be placed on operating the containment in a passive mode as much as possible and on limiting all purging and venting times to as low as achievable. To justify venting or purging, there must be an established need to improve working conditions to perform a safety-related surveillance or safety-related maintenance procedure. (Examples of improved working conditions would include deinerting, reducing temperature,** humidity, and airborne activity sufficiently to permit efficient performance or to significantly reduce occupational radiation exposures.) (2) Maintain the containment purge and vent isolation valves closed whenever the reactor is not in the cold shutdown or refueling mode until such time ar you can show that: la) All isolation valves greater than 3-in nominal diameter used for containment purge and venting operations are operable under the most severe design-basis-accident (DBA) flow-condition loading and can close within the time limit stated in the j technical specifications, design

criteria, or l

operating procedures. The operability of butterfly l valves may, on an interim basis, be demonstrated by l limiting the valve to be no more than 30* to 50 open (90* being full open). The maximum opening shall be determined in consultation with the valve i supplier. The valve opening must be such that the critical valve parts will not be damaged by DBA-LOCA (loss-of-coolant accident) loads and that the valve will tend to close when the fluid dynamic forces are introduced, and

• Previously referred to as DOE Interim Position
  • Only when temperature and humidity controls are not in the present design.

II.E.4.2-3

SNPS-1 FSAR (b) Modifications, as necessary, have been made to segregate the containment ventilation isolation signals to ensure that, as a minimum, at least one of the automatic safety injection actuation signals is ur. inhibited and operable to initiate valve closure when any other isolation signal may be blocked, reset, or overridden. l l l l II.E.4.2-4 . ~. .. _ _.,. ~..,. _.

SNPS-1 FSAR LILCO Position The following summarizes our evaluation for each of the items stated above. 1. Diversity in Parameters Note 2 of Table II.E.4.2-1 " Containment Isolation Dependability" shows the different isolation signals and the parameters sensed to initiate each signal. Those primary containment isolation valves that receive two or more of-these signals satisfy the diversity requirement. 2. Essential and Nonessential Systems l The Shoreham containment isolation system is designed to prevent the release of radioactive material to the environs after an accident while ensuring that those systems important for post-accident mitigation are operational. The definition of essential and nonessential systems is discussed below. Table II.E.4.2-1 identifies which penetrations are associated with either essential or nonessential systems. a. Essential systems Essential systems, as defined for containment isolation purposes, are those systems that may be needed within 10 minutes of a loss-of-cooling

accident, a

normal reactor scram, or a scram system failure. Since these lines are necessary to mitigate the consequences of a accident, the basis for isolating them is related to the safety importance of the particular system. All other systems are defined as nonessential systems. The Shoreham containment isolation system design isolates essential systems as follows: 1. Certain lines are provided with two or more of the isolation signals, as listed in Note 2 of Table II. E.4.2-1, in addition to the remote manual isolation capability. ii. Certain lines are provided with check valves to prevent back flow out of the primary containment in addition to either an isolation valve with one or more of the isolation signals as listed in Note 2 of Table II.E.4.2-1. or in conjunction with [ remote manual isolation valves. iii. Certain lines that are provided with one of the isolation signals in addition to the remote manual capability. I II.E.4.2-5

SNPS-1 FSAR iv. Certain lines are provided with remote manual isolation capability. A number of remote manual valves on essential systems are neither locked closed nor provided with automatic isolation signals. Rather, these valves are controlled by remote manual actuation from the main control room, or by process signal, depending on their intended function. In all

cases, where isolation valves are not automatically closed, the system function requires that the valve remain open or be opened for accident mitigation and/or safe shutdown.

Subsequent isolation is achieved either by operator action or by process signal. b. Nonessential systems Since these lines are not immediately required to mitigate the consequences of an accident, the means for isolating these lines is described below: 1. Certain lines are provided with two or more of the isolation signals, as listed in Note 2 of Table II,E.4.2-1, in addition to the remote manual isolation capability. ii. Certain lines are provided with check valves to prevent back flow out of the primary containment in addition to one of the following: a) an isolation valve provided with one or more of the isolation signals, as listed in Note 2 of Table II.E.4.2-1, in addition to the remote manual isolation capability b. an isolation valve with remote manual isolation capabilit-- I c) a locked closed manual valve iii. Certain lines are provided with one of the isolation signals, as listed in Note 2 of Table II.E.4.2-1, in addition to the remote manual isolation capability. iv. Certain lines are provided with remote manual isolation capability only. v. Lines that are provided with check valves to prevent back flow out of the primary containment. As a result of our review, we are proceeding with the following modifications to the Shoreham primary l containment isolation system design: ( l II.E.4.2-6 l l t ____,_,_m

i i SNPS-1 FSAR 1. addition of a high drywell pressure isolation signal to the X-30 RPV sample line isolation valves and 2. addition of a solenoid valve on X-37A Nitrogen Purge for the Transversing In-core Probe System. The valve will be isolated by two of the isolation signals, as listed in Note 2 of Table II.E.4.2-1, in addition to the remote manual isolation capability. i 3. Isolation of Ngaessential Systems The means for isolating nonessential systems is described in Item 2.b above. The justification for those nonessential systems that are not automatically isolated by the containment isolation signal is provided in the note section of Table II.E.4.2-1. 4. Resetting of Containment Isolation Signals There are three cases where resetting of the containment isolation signals could permit system valves to return to their pretransient condition: a. X-30 Reactor Nater Sample Valves - These are 3/8 inch sample lines with normally open isolation valves that will open upon reset of the isolation signal if their control switches are in the open position. This line permits a continuous sample to be taken to monitor RPV conductivity. b. RHR Heat Exchanger Sample Valves - These are 3/8 inch sample lines with normally closed isolation valves that will open upon reset of the isolation signal if their control switches are in the open position. This line permits a grab sample to be taken to monitor RPV conductivity during shutdown conditions. l c. Feedwater Testable Check Valve This valve has a positive closing feature designed for remote testing during normal operation to assure mechanical operability of the valve disc. This remote testing capability will cause only a partial movement of the flow stream, with l only a minor effect on flow. Upon receipt of an l isolation

signal, the actuator will either cause a I

slight reduction in flow when feedwater flow is i available or cause the valve to close when the feedwater j flow is not available. Without the isolation signal the valve functions as a check valve in preventing back flow out of the primary containment. l 5. Drywell Pressure Setpoint i II.E.4.2-7 I

l SNPS-1 FSAR ksrlng nofmG\\ Cft The high drywell pressure cram trip settin is within 1 psi of the maximum expected drywell prescur Both previous operating experience and accident analysis have been used to determine the specific scram trip setting. This minimizes spurious trips without compromising safety. Accordingly, no further reduction in setpoint is warranted or desirable. 6. Purge Valves The Shoreham primary containment purge system, when operated in the purge

mode, is designed to replace the primary containment atmosphere with air prior to personnel entry during normal plant shutdown for maintenance.

The purge mode will only be used during operational conditions 4 and 5, i.e., cold shutdown and refueling. The Shoreham primary containment purge system, when operated in the vent mode, is designed to reduce pressure buildup, as

required, during operational conditions 1, 2, and 3, i.e.,

power operation,

startup, and hot shutdown.

During the venting process, the exhaust is always routed through a charcoal filter train by a 1,200 cfm exhaust fan. The primary containment isolation valves are isolated upon i initiation of the reactor building standby ventilation system (RBSVS) (see Note 3 of Table II.E.4.2-1). The vent process lines that penetrate the primary containment are 6 inches in diameter and have redundant fast acting air-operated isolation valves designed to Seismic Category I criteria. In addition to the isolation signal, these valves have remote manual isolation capability with position indication in the control room. The primary containment purge system will be verified closed every 31 days using the position indicating lights in the control. room. Prior to plant startup the SNPS-1-operator will be required to verify proper position of the purge system valves. The

valves, which satisfy the SRP Section 6.:2. 4 item II. 3. f sealed closed barrier definition (i.e.,

automatic valve which remains closed after a loss-of-coolant accident), are then positioned by existing Shoreham administrative and/or operational procedures. 7. High Radiation Isolation Signal The primary containment purge system, as discussed in our preceding response, isolate on FBSVS initiation. The RBSVS system initiation occurs when: a. RPV Low water level b. drywell high presstre c. refueling platform level high radiation d. reactor building high differential pressure 4 II.E.4.2-8

SNPS-1 FSAR RBSVS initiation isolates the secondary containment exhaust valves. Although there is no primary containment ihigh radiation isolation signal, there are radiation monitors on the secondary containment exhaust line. i. i j t l l [ i II.E.4.2-9

TABLE II.E.4.2-1 COffrAINMEfff ISOLATION DEPENDABILITY Penetration Number Description Valve Nwtbers Classificationt&D Isolation biona1sta> Remarks X-1A,B,C,D Main Steam Lines 1521 *AOV081A,B,C,D Essential b,C,D,E,P,R,T,RM 1B21*ADV082A,B,C,D W in Steam Drain Lines 1B21*MOV001 B,C,D,E,P,k,T,hM (Before sear. on outboard) 1321*MOV062 1821*MOV063 1B21*MOV064 Main Steam Leakage control 1E32*MOV021A,B,C,D RM X-2A,B Feedwater Simple check valve Essential Reverse Flow 1B21*AOV036A,B Reverse Flow /F,G,RM X-3 Maan Steam Drain Line 1821*MOV031 Nonessential B,C,D,1,P,R,T,RM 1B21*MOV032 X-4 Reactor Water Cleanup System 1G33*MOV033 13onessential B,J.Rt1 Note 10 from tne Reactor Vessel 1G33*MOV034 B,J,N,Y,RM X-5 Residual Heat Removal System - 1E11*MOV047 Nonessential A,U, kit aMte 10 Shutdown Cooling from 1E11*MOV048 A,U,Rit Reactor Vessel 1E11*RV103 N/A X-6A,B Residual Heat Removal System - 1E11*AOV081A,B Essential Reverse Flow Injection Line to Recirc 1811*MOV081A,B A,U,R11 System 1E11*MOV037A,b RM X-7A,B Residual Heat. Removal System - 1E11*MOV039A,B Nonessential F,G Rit Drywell Spray 1E11*MOV0 38A,B F,G,Rf1 X-8A,b Residual Heat Removal System - 1E11*MOV041A,B Nonessential F,G,Rit Suppression Cnamber Spray X-9A,B,C,D Residual Heat Removal System - 1E11*MOV031A,B,C,D Essential RM Pump Suction X-10A Residual Heat Removal Test 1E11*MOV040A Nonessential F,G,Rit Return to Suppression Pool IE11*MDV042A Nonessential F,G,R11 Suppression Pool Cleanup 1G41*MOV033A Nonessential B,F.R11 Return 1G41* TOV 033B Honessential B,F,Rta Residual Beat Removal System - 1E11* TOV 044A

• messential F,G,Rit Steam Cohdensing Discharge hesidual Heat kemoval System - 1E11*MOV045A Essential Rn Minimum Flow 1 ct V

i TABLE II.E.4.2-1 (CONT' D) Penetration i Number Description Valve Nin:tters Classitication(*3 Isolation stena1st a a Remarks Core Spray Test Line 1r21*NOV035A 13onessential F,G,E!! Core Spray Minimum Flow 1E21* TOV 034A Essential RM Suppression Pool Pump Back Simple Check Valve Nonessential Reverse Flow 1G11*MOV639 A.F.RF1 Post-Accident Sampling system Sluple Chect Valve Nonescential Reverse Flow Sample Return IE11*SOV-168 A,F,R11 2-10B Residual Beat Removal Test 1811*MOV040B Nonessential F,G,RM Returr. to Suppression Pool 1E11*MOV042B Nonessential F,G,RM Reactor Core Isolation 1851*MOV036 Essential RM Cooling - Minimum Flow High Pressure Coolant 1E41*foV036 Essential RM Injection - Minimum Flow Residual Heat Renoval System - 1E11*MOV0448 Nonessential F,G,R!t Steam Condensing Discharge Residual Heat Removal System - 1E11* tov 045B Essential RM Minimum Flow Core Spray Test Line 1221*MOV035b Nonessential F V1 Core Spray Minimun Floa 1821*eOV034b Essential RM Relief Valve Discharge - 1E11*RV155 Nonessential W/A Residual Heat Rernoval Supply to Reactor Core Injection Cooling Suction X-11 Residual Heat henoval System 1E11*MOV054 Nonessential A,b,RM Note 10 Head Spray Line to Reactor 1E11*MOV053 A,U,RM Vessel 1E11*dV164 h/A X-12 High Pressure Coolant 1E41*MOV047 Essential K,Rt1 Injection - Turbine Steam 1E41*MOV041 K,Rt1 Inlet Line 1E41*ts.N042 K,RM 1E41*MOV048 K,RM 1-13 High Pressure Coolant 1E41*MOV044 Essential RM Injection - Turbine Exhaust Simple Checx Valves Reverse Flow X-14 Spare Note 7 X-15 High Pressure Coolant 1E41*coV032 Essential K,RM Injection - Pump Suction X-16 Reactor Core Isolation 1E51* tov 047 Essential A,Rt1 Cooling - Turbine Steam Inlet 1E51* tov 041 K,Rf1 1E51* rov 042 K,hli 1E51*HOVO48 2 o1 9

TABLE II.E A 2-1 (00N18D) Penetration Number Description Valve Numbers Classification (18 Isolation Signalsta) Remarks X-17 Reactor Core Isolation 1E51*MOV045 Essential RM Cooling - Turbine Exhaust Simple Checx Valves Reverse Flow X-18 Reactor Core Isolation 1E51*MOV046 Essential Reverse Flow /kM J Cooling - Vacuum Pump Simple Check Valve Reverse Flow j Discharge X-19 keactor Core Isolation 1E51*MOV032 Essential RM Cooling - Pump Suction X-20A,B Core Spray Pump Discharge 1E21*ADV081A,B Essential Reverse Flow to keactor vessel 1E21*MOV081A,B RM 1E21*MOV033A,B RM j X-21A,B Core Spray Fur.p Suction 1E21*MuV031A,B issential RM X-22A,B Reactor Building Closed Loop 1P42*MOV035 Essential RM Cooling Water to Recirc 1P42*MDV047 Pump and Motor Coolers X-23A,B Reactor Building closed IA>op 1P42*t10VC36 Essential RM Cooling Water to hecirc 'IP42*MOV048 Pump and Motor Coolers X-24A to H Reactor Bulloing Closed Loop Simple Check Valves Nonessential Reverse Flow Cooling Water to Drywell 1P42*MOV232 F,G,3,RM Coolers 1P42*M0V233 F,G,1,RM 1P42*MOV234 F,G,3,RM 1P42* mV235 F,G,1,RM 1P42*MOV237 F,G,1,RM 1P42*MOV238 F,G,3,RM 1P42*MOV239 F,G,1,RM 1P42*MOV240 F,G,5,RM X-25A,B Reactor Building Closed Loop 1P42 *MOV147,148 Nonessential F,G,1,RM Cooling Water fran Drywell IP42*aV291A,B N/A Coolers 1P42*MOV231,236 F,G,1,RM X-26 Purge Air to Drywell 1T46*ADV03bA,B Nonessential L,RM Note 3 X-27 Purge Air frun Drywell 1T46*AOV039A,B Nonessential L,RM Note 3 X-28 Purge Air to Suppression 1T40*AOV038D,C Nonessential L,Rf! Note 3 Chamber Suppression Chamber Inerting 1T24*AOV004A,b Noressential L,htt hote 3 3 of 9

TABLE II.E.4.2-1 (CONT'D) lenetration Number _ Description Valve Numraers Classificationsa3 Isolation Sianalst a 3 Remarks X-29 Purge Air f rcun suppression 1T46*AOV039D,C Nonessential L,R!i Note 3 Chamber Vacuum Breaker Test Line - 1T46*ADV079A,b Nonessential L,RM Note 3 Suppression Chamber X-30 Sample Coolant from Reactor 1B31*ADV0d1 Nonessential B,C,F,RM Vessel 1831*AOV082 B,C,F,RM X-31 Equipment Drains fran Drywell 1G11*MOV248 teonessential B,F,Rif 1G11*MOV249 B,F,RM X-32 Floor Drains from Drywell 1G11*MOV246 Nonessential B,F,RM 1G11*NOV247 B,F,RM Note 7 X-33 Spard X-34 Spt.re Note 7 X-35 Spare Not.e 7 X-36 Standby Liquid Control System Simple Checx Valves Essential Revt.rse flow 1C41*EV010A,B RM X-37A Nitrogen Purge for Simple Chect Valve Nonessential Reverse Flow Transversing in-Core Probe 1C51* Solenoid Valve Nonessential F,G,Ri1 1 X-37B,C,D Transversing in-Core Probe 1C51*SOV801A,B,C,D Nonessential RM Note 4 i X-38 Drive Guide Tubes 1C51*EV801A,8,C,D RM X-39A,B Instrument Air to Suppression Simple check Valves Nonessential Reverse Flow Chamber 1P50*W)V104 F,G,RM 1P50*MOV100 F,G,Rf1 Note 7 X-40 Spare X-41 High Pressure Coolant 1E41*MOV0=9 Essential F and X,RM Injection Vacuum Breaker Reverte Flow X-42 Reactor Core Injection 1E51*MOV049 hasential F and X,RM Cooling Vacuum Breaker Reverse al;w 4 ct 9

TABLE II.E.4.2-1 (CONT'D) Penetration Number Description Valve tunat,ers Classiticatiu..ta3 Isolation Signalsca> Remarns X-43 High Pressue Coolant In3ection - Steam Line Drain Simple Check Valve Nonessential ReNerse Flow - Steam Supply to Residual 1E11*RV152A,B Nonessential N/A Heat nenoval Heat Exchanger Residual tieat Removal System - Heat Exchanger Relief IE11*RV157A,B Essential N/A - Heat Exchanger Vent 1E11*MOV055A,05bA Nonessential RM Note 5 1E11*NOV055B,0508 RM X-44 Primary Containment Atmosphere 1T48*MOV033A Nonessential RM Note b Control - Suppression ChamDer 1T48*MDV038A RM Supply Drywell Floor Seal 1T23*MOV031A Essential RM Pressurization X-4 5 Primary Containment Atmosphere 1Tes*MOV033B Nonessential RM Note b Control - Suppression Chamber 1T48*MOV038B RM Supply Drywell Floor Seal 1T23*f0V031B Essential RM Pressurization X-4 6 Primary Containment Atmosphere 1T48*MUV031A Nonessential RM Note b Control - Drywell Supply 1T48sMOV035A RM Drywell Inerting 1724*AUV001A,B Nonessential L,R&A Note 3 X-47 Primary Containment Atmosphere IT48*MOV031B Nonessent2al RM Note b Control - Drywell Supply 1T48*MDv035b RM XS-1 Spare Note 7 XS-2 Spare Note 7 XS-3 Spare Note 7 hote 7 XS-4 Spare XS-5 See X-43 XS-6 Suppression Pool cleanup / 1G41*MOV034A,8 Nonessential 8,F,RM Pumpdown XS-7 Primary Containment Atmosphere 1Te8*MOV034B Nonessential RM Note-6 Cor. trol - Suppres.91on Chamber 1T48*MOV0408 Return 5 or 9

TRbLE II.1,.4.2-1 (CONT 8D) 1 Penetration Number Dascription Valve Numbers Classification (a) Isolation Slanals(aD Ranarns XS-8 Primary containment Atmosphere 1T48+MOV034A Nonessential RM Note 6 Control - Suppression Chamber 1T48*eOV040A heturn Note 7 XS-9 Spare XS-10 Spare Note 7 XS-11 Spare Note 7 Note 7 XS-12 Spare XS-13 Spare Note 7 XS-14 Spare Note 7 XS-15 Spare Note 7 XS-16 Drywell Service Air Simple Chect Valve Nonessential Reverse Flow Note a Manual valve l XS-17 Spare Noter 7 XS-18 Spare Note 7 Note 7 XS-19 Spare XS-20 Prim.ary Containment Atnesphere 1748 *MOV032A Nones ..lal RM Note 6 Control - Drywell Return IT48*MOV037A XS-21 Primary Containment Atmosphere 1T48*MOV0323 Nonessential RM Note e Control - Drywell Return 1T48*MOV0378 XS-22 Vacuum Breaker Test Line - 1Te6*AOV078A,8 teonessential L,RM Note 3 Drywell 1 XS-23 Spare (Reserved fC! Reactor Note 7 Vessel Inspection) XS-24 Spare XS-25 Drywell Radiation Monitoring 1D11*MOV032A,B teonessential F,G,PJ1 Supply XS-26 Spare XS-27 Drywell Radiation Monitoring 1D11*NOV033A,B Nonessential F,G,RM Return XS-28 Post-Accident Sampling System Simple Check Valve Nonessential Reverse Flow Primary Containment Atmosphere 1T48*SOV131 A,F,RM Seple Return 6 of 9

TABLs II.E..#.2-1 tCO?rr'D1 Penetration Number Description Valve Numbers Classificationta3 Isolation $1onalst a 3 Remarks XS-29 Spare Note 7 XS-30 Spare Note 7 B-3 Post-Accident Sampling Systena 1Tes*SOV148A,B Nonessential A F.Rit Drywell Atmosphere Sample B-7 Instrument Air tn Drywell Simple Check Valves 2.asential Reverse Flow IP50*MOV103A RM C-2 Post-Accident Sampling System 1831*SOV313A,B Nonessential A, F,RM Reactor Sample D-5 Ir.strument Air to Drywell Simple Check Valveo Es wntial Reverse Flow 1P50*MOV103B RM F-10 hecirc Pump Seal Injee; ion Simple Check Walves Nonessential keverse Flow Mote 9 j l F-11 Recirc Pump Seal Injection Simp 3e Checx valves Nonessential Reverse Flow Mote 9 J-2 Post-Accident Sampling System Simplo Checx Valve Nonessential Reverse Flow d Atmosphere Sample Return 1T4d*SOV130 A,F,RM J-10 Eost-Accident sampling System 1T48*s0V12eA,B Nonessential A,F,R!i Drywell Atmosphere Sample Suppression Post-Accident Sanpling System 1Ted*SOV129A,b Nonessential A,F,RI! Onamber Suppression Chamber Atmosphere Gatch Sample (Azimuth 137 7*) Suppression Post-Accident Sampling System 1T48*SOV127A,B Nonessential A,F,RM Chamber Suppression Chamber Atmosphere Batch Sample (Azimuth 317 17*) Instrument Lines Essential Control Road Drive Insert and Essential withdraw Lines i I i 7 of 9

I l TABLE II.E.M.2-1 (t 2 T*D) TOTES 1. P.,ssential systems, as defined f or containment isolation purposes, are those systeses that may De raeeded within 1u minutes of a loss-of-coolant accident, a norisal reactor scram, or a scran systen railure. All other systems are defined as nonessential systems. 2. Containment Iselatien Sionals and Parameters sensed A - Reactor vessel low water level 3 B - Reactor vessel low water level 2 C - High radiation - main steam line P - Iow main steam line pressure D - Line breat - main steam line (tlow) at turbine (run mode only) E - Line Dreak - main steam line (temp. ) R - Low condenser vacuum F - High drywell pressure T - High temperature in turbine Du11 ding G - Reactor vessel low water leve).1 0 - High reactor vessel pressure J - Line break - reactor water W - High temperature at reactor water cleanup system cleanup nonregenerative heat exchanger K - Line breat - to/from high X - Low steam pressure preusure coolant injection / reactor Y - Standby liquid control system actuated core injec*lon cooling turbines 3 - Iow level in RDC144 heas tank L - Reactor building standby ventilation RM - Remote annual switch from main systen (See Note 3) control room 3. The containment purge / ventilation system is isolated upon: a) RPV low water level; b) drywell high pressure; c) refueling plattorm level high ratiation; d) reactor building higu ditterential pressure. 4. Transversing in-core probe (TIP) system The TIP drive guide tubes provide an essentially sealed path for the rlexible drive caDie of the TIP probes. The TIP tubing seals the TIP system from the reactor coolant and forms a leak signt boundary. When the TIP system caDie is inserted, the ball valve of the selected tube opens at..cmatically so that the proce and t cable may advance. A naximum of tour valves many De opened at an} time to conduct the calibration. It is expectett that a full core span will be done weekly. If isolation of the line is required during calibration, the caDie is automatically retracted asad the ball valve closes atter tne cable is completely withdrawn. To ensure isolation capability, it a TIP cable tails to withdraw or a ball valve tails to close, an explosive shear valve will be manually actuated to seal the guide tube. 5. These valves are primarily used in the steam condensing moce to vent the residual heat removal heat exchangera. Tney are normally closea valves and their position is controllea Dy the system operating procedure. Automatic isolation of these normally closed valves is not required. 6. Although ~_his system is classitied as a nonessential system (due to the 10 minute criteria), it is specifically designed to operate af ter an accident. The isolation valves are maintainea closed during normal operation. They.roula be opened as needed following an accident to control hydrogers buildup in tne primary conummt. The isolation valves woula be closea when the syctem train was no longer needed. 8 ct 9 l

TABLP II.E.#.2-1 f@ NT*D) 7. All unused penetrations (designated &s " spare") are capped and seal-welded on both sides or tne pr2 mary cor.tals.n.e nt. 8. This line is only needed duris.g maintenance. Service air supply as disconnected during plant operation and maintainea closed by acministrative procedures. 9. The evaluation of the recirculation pianp seal injection is provided in Seetion 6.2.4.3.2. W. The nigh drywell pressure signal was recently removed f ran the isolacion valves on penetrations X-4, X-5, and 1-11. Probleas which may result trom isolating the reactor water cleanup (hWCU) system on a high drywell pressure sispel include dropping the cleanup filter cake in the RWCU tilter demineralizer, adding radunste processing, and the loss of tr.e acility to remove water from the vessel atter the scram. Isolating the residual heat reasoval (RMR) shutdown cooling and reactor vessel head spray penetrations on hign drywell pressure (due to email steaum leans) would ird.2. nit time shutdown procedure. The use of this signal would have little, it any, effect on preveating coolant losses or reducing site boundary dose. Other than for shutdown cooling, these IdiR valves are always closed. i 4 h 1 p 9 of 9

SNPS-1 FSAR II.F.2 Identification of and Recovery From Conditions Leading to Inadequate Core Cooling NRC Position Licensees shall provide a description or any additional instrumentation or controls (primary or backup) proposed for the plant to supplement existing instrumentation (including primary coolant saturation monitors) in order to provide an unambiguous, l easy-to-interpret indication of inadequate core cooling (ICC). A description of the functional design requirements for the system shall also be included. A cescription of the procedures to be used with the proposed equipment, the analysis used in developing these procedures, and a schedule for installing the equipment shall be provided. Design of new instrumentation should provide an unazabiguous indication of ICC. This may require new measurements or a synthesis of existing measurements which meet design criteria (item 7). The evaluation is to include reactor-water-level indication. Licensees and applicants are required to provide the necessary desigi4 analysis to support tne proposed final instrumentation system for ICC and to evaluate the merits of various instruments to monitor water level and to monitor other parameters indicative of core-cooling conditions. l The indication of ICC must be uncabiguous in that it should have the tollowing properties: (a) It must indicate that the existence of ICC caused by various phenomena (i.e., high-void fraction purrped flow as well as stagnant boil mtf): and, (b) It must not erron'.ously indicate ICC because or the presence of an unrelated phenomenon. Tne indication must giva advanced warning of the approach or ICC. The indication must cover the full range trom normal operation to complete core uncovery. For example, water-level instrumentation may be chosen to provide advanced warning of two phase level drop to the top of the core and could be supp Lemented oy other indicators such as incore and core-exit thermocouples provided that the indicated temperatures can be correlated to provide Indication of the existence or ICC and to inter the extent of core uncovery. Alternatively, full-range level instrumentation to the bottom of the core may be employed in con 3 unction with other diverse indicators such as core-exit thermoccuples to preclude misinterpretation due to any inherent deliciencies or l Anaccuracles in the measurement system selected. I l I II.F.2-1

SNPS-1 PSAR All instrumentation in the 1Jnal ICC system must be evaluated for conformance to Appendix A, "Lesign and Qualitication Criteria for Accident Monitoring Instrumentation," as claritied or mod.iled by j the provisions that follow. This is a new requirement. If a computer is provided to process liquid-level signals for display, seismic qualification is not required for the computer and associated hardware beyond the isolator or input butter at a location accessible for maintenance following an accident. The single-fallure criteria of item 2, Appendix A 01 NURE4-0737, need not apply to the channel beyond the isolation device, if it is designed to provide 99 percent availability with respect to functional capability for 11guld-level displey. The oisplay and associated hardware beyond the isolation device need not De Class 1E, but should be energized from a high-reliability power source which ir battery bacxed. The quality assurance provisions cited in Appendix A, item 5, need not apply to this portion of the instrumentation system. This is a new requirement. incore thermocouples located at tne core exit or at discrete axial levels of the ICC monitoring system and whicn are part of the monitoring system should be evaluated f or contormity with, " Design and Qualification Criteria for Pwk Incore Thermocouples," which is a new requirement. The types and locations of displays and alarms snould be determined by performing a human-1 actors analysis taking into cons 1 aeration: (a) the use of this information by an operator during both normal and abnormal plant conditions, (b) integration into emergency procedures, (c) integration into operator training, and (d) other alarms auring emergency and need for prioritization of alarms. l l l I l II.F.2 -2

l SNPS-1 FSAR ATTACHMEbrF 1 Dd61GN AND QUALIFICATION CP.ITERIA FOR PRESSURIZED-WATER REACTOk INCORE THERMDCOUPLhS Thermocouples located at the core exit for each core quaarant, in i conjunction with core inlet temperature

data, shall be 31 surficient number to provide indication of radial distributic or the coolant enthalpy (temperature) rise across representative regions of the core.

Power distribution symmetry should De considered when determining the specific nwaber and location of theraccouples to De provided for diagnosis of local core problems. i There should be a prim ry operator display (or displays) having l the capabilities which follow: (a) A spatially oriented core map available on dam nd indicating the temperature or temperature ditterence across the core at each core exit thermocouple location. (b) A selective reading of core exit temperature, continuous on demand, which is consistent with parameters pert'sent to operator actions in connecting with plant-specific inadequate core cooling procedures. For example, tne action requirement and the displayed temperature might be either the highest of all operaole thermocouples or the average or I1ve

highest, thermocouples.

(c) Direct readout and hard-copy capability should be availabl e tor all thermocouple temperatures. Tne range shoulu extend from 200 F (or less) to 1800 F (or more). (d) Trend capability showing the temperature-time history or representation core exit temperature values should be availanie on demand. l (e) Appropriate alarm capability should De provided consistent with operator procedure regt.d.rements. (t) The operator-display device interrace shall De human-ractor designed to provide rapid access to requested displays. A backup display (or displays) should be provided with tne capability ror selective reading of a minimum 01 16 operable thermocouples, 4 Irom each core

quadrant, all within a time interval no greater than b minutes.

The range should extend trom 200 F (or Jess) to 2300 F (or more). The types and locations or displays and alarms should be determined by performing a human-factors analysis takino into consideration: II.F.2-3 _..__,_..-._..,-m. ,_w ,,.,,.,,...-,,.y_,,,7 mm.

j I SNPS-1 FSAR s 1 (a) the use of this information by an operator during both normal and abnormal plant conditions. (b) Integration into emergency procedures, (c) integration into operator training, and (d) other alarms during eneroency and need zor ptioritization of alarms. j ( The instrumentation must be evaluated for conformance to j Appendix B, " Design and Qualitication Criteria for Accident Monitoring Instrumentation," as modified by the provisions of items 6 through 9 which follow. 1 The prsmary and Dackup display channels should be electrically independent, energized from independent station Class IE power

sources, and pnysically separated in accordance with Regulatory Guide 1.75 up to and including any isolation device.

The primary display and associated hardware beyond the isolation device need not be Class IE, but should be energized from a high-reliability power source, cattery backed, where mossentary interruption is not tolerable. The backup display and associated hardware should be Class IE. The Instrumentation should be environmentally quallfled as described in Appendix B, item 1, except that seismic qualification is not required for the pr mary display and associated hardware beyond the isolator / input cutter at a location accessible for maintenance following an acciaent. The primary and backup display channels should be designsd to provide 99 percent availability for each channel wit 1 respect to functional capability to display a minimum of four thermocouples per core quadrant. '1h e availability shall De addressed in technical specarications. Tne quality assurance provisions cited in Appendix B, item 5, should be applied except for the primary display ano associaten hardware beyond the isolation device. II.F.2-4

SUPS-1 FSAR LILCO Position The BhR Owner's Group, of which LILCO is a member, has concloded that no additional instrumentation is required to monitor inadequate core cooling. The present water level instrumentation, described in the response to item II.A.3.27, "Cr== ann Reference Level" is fully adequate for predicting tne approach to inadequate core cooling and in allowing the plant operator to respond properly under all postulated reactor conditions. This has been evaluated and documented in the General P.lectric report NEDO-24708, " Additional Information Required for NRC Statf Generic Report on Bolling hater heactors". In

addition, essergency procedure guidelines have been surnaitted by the BWR Owners' Group for operators to recognize the approach to inadequate core cooling.

These are being incorporated into LILCO's emergency operating procedures. I LILCO believes the above procedures and analysis satisty the requirements of this NRC position relative to inadequate core cooling. 'Jt1112ation of incore thermocouples will be addressea conturgent upon the completion of our review of Regulatory Gr + 1.97, Rev. 2. With regard to human f actors, a preliminary design assessment was performed on the Shoreham Control Room. For more details, refer to Item I.D.1. l II.F.2-5 - ~ m

SMPS-1 FSAR II.K.3.30 Revised Small-Break LOCA Methods _ to Show Compliance with 10CFR50, Appendix K NRC Position The analysis methods used by NSSS vendors and/or fuel suppliers lor small break LOCA analysis for compliance with hppendix X to 10 CFR Part 50 should be revised, documented, and submitted for NRC approval. The revisions should account for comparisons with experimental

data, including data from the LOFT and Seuiscale facilities.

gackground As a result or the accident at TMI-2, the bulletins and Orders Task Force was formed within the Oftice of Nuclear Reactor Regulation. This task force was charged, in part, to review the analytical predictions of feedwater transients and small-oreax LOCAs ror the purpose of assuring the continued sate operation or all operating

reactors, including a

determination of acceptability or operator emergency guidelines. As a result of the Task Force reviews, a number of concerns were identitled regarding the adequacy of certain reatures 0t small-nreak LOCA models, in particular, the need to confira spec 121c model features (e.g., condensation heat transfer rates) against applicable experimental data. These concerns, as they applied to each LWR vendor's models, wero documented in tho Tasx Folce reports for each LWR vendor. In addition to the modeling concerns identified, the Task Force also concluded that, in light of the TMI-2

accident, additional syotems verirication or the small-Dreak LOCA model as required by II.4 or Appendix K to 10 CFR 50 was needed.

This included providing predictions of Semiscale Test S-07-108, LOFT Test L3-1, and providing ( experimental veritication or the various nodes or single phase and two-phase natural circulation preoicted to occur in each vendor's reactor during small-break LOCAs. Based on the cumulative staft requirements ror additional small-break LOCA model veritication, including both lutegral system and separate effects verification, we considered model revision the l appropriate metnod f or reflecting any potential upgrading or tne l analysis methods. The purpose of the verification was to provide the necessary assurance that tne small-oreaK LOCA models were acceptacle to calculate the benavior anc consequences of small primary system breaks. We believe that tnis assurance can alternatively be

proviced, as appropriate, by additional justirication or the acceptability of present small-breax LOCA models with regard to spec 1ric staff concerns and recent test data.

Such justification could supplement or supersede the need for model revision. As an

example, a

model that presently does not proper 2y account for norizontal countercurrent two phase flow in the not leg piping II.K.3.30-1 l l

SNPS-1 FSAR should either be revised to properly account for the pnenomena, or demonstrated to produce a conservative result for the entire spectrum or small breaks considered. The specific staff concerns regarding smell-break LvCA models are provided in the analysis sections or the B&O Task Force reports for each LWR vendor, (NUREG 's 0635, 0565, 0626, 0611, and Obi 3). These concerns should be reviewed in total by each holder of an approved ECCS model and addressed in the evaluation as appropriate. The recent tests include the entire Semiscale small-break test series and LOFT Test L3-1 and L3-2. The staff believes that the present small-break LOCA models can be both qualitatively and quantitatively assessed against these tests. Other separate effects tests, (e.g., ORNL core uncovery tests) nd future tests, as appropriate, should also be factored into this assessment. based on the above background and clarliacation, a detailed outline of your proposed program to address this issue snould be submitted. In particular, this submittal should identity (a) which areas ot your models, it any, you intend to

upgrace, (b) which areas you intend to address by further Juatification of acceptability, (c) test data to be used as part of the overall verification / upgrade effort, and (d) your estimated scheaule for perrorming the necessary work and submitting this inIormation for statt review and approval.

LILCO Position LILCO is a participant in the BWR Owners' Group wnich is l . reviewing the Appendix X Methodology. any model improvements, deemed appropriate, will ne utilized for plant spec 111e reanalyses, arter approval or models Dy the

NRC, if sucn reanalyses are required.

The Owners' Group response is presently scneduled to be available by the req uired date (January 1, 1982). 1 l II.K.3.30-2

SNPS-1 FSAR II.K.3.31 Plant-Specific Calculations to Show Compliance with 10 CFR 50.46 NRC Position Plant-specific calculatione using NRC-approved models for small-break LOCAs as described in II.K.3.30 to show compliance with 10 CFR 50.46 should be submitted for NRC approval by all licensees. See clarifying paragraphs of item II.K.3.30. LILCO Position LILCO has provided the results of Shoreham-specific small-break LOCA calculations in Section 6.3.3.7 and Tables 6.3.3-2 and 5. The references listed in Section 6.3 descr3"a the currently approved Appendix K methodology. This methodology is considered to be in compliance with 10 CFR 50.46. The specific NRC concerns described in Item II.K.3.30 are being addressed by the BWR Owners' Group, of which Lilco is a member. If it is determined that changes to the small-break LOCA models are required (after subsequent review by the NRC), a New Shoreham specific analysis will be prepared using the revised approved models and submitted for NRC review. l l II.K.3.31-1

SNPS-1 FSAR III.A.1.1 Upgrade Emergency Preparedness NRC Position The overall state or emergency preparedness for nuclear power plant accidents will be upgraded, including the integration of emergency preparedness onsite and orfsite, according to the NRC/ FEMA Memorandum of Understanding (item III.B.) Approval of the overall state of preparedness will be required (primarily subitem (1) below) prior to issuance of an operating license. The review and upgrading for operating reactors is under way. Six NRC teams were formed in September 1979 to amplement the " Action Plan for Promptly Improving Emergency Preparedness" (ShCY 79-450). That Action Plan ident2fies the elements requ2 red for promptly improving licensee emergency preparedness ana zor ensuring the capability of ottsite agencies to take appropriate emergency actioria. In the short term, the teams are snaking an integr ated assessment of licensee, local, and State capabilities and interfaces based on: (a) a review of existing plans and a meeting in the site area to ccmununicate upgraded criteria and to identity to licensees the areas requiring improvements. This includes an opportunity for expression of concerns by tne public through an open meeting. An objective of the taama la to help improve working relationships and commur.ications concerning emergency plan development among all parties. The criteria being used by the NRC teams reflect a number of the reconsnendations made as a result of the 2MI-2 accident by the President's Comunission and the NRC Special Inquiry Group; and (b) a review of upgraded licensee,

local, and State plans submitted by the licensee atter the site visit is summarized in a

sarety evaluation report. This includes an 2dentification of areas requiring improvement, a schedule for implementation or the improvements, and a specification of any required interim measures. The review of upgraded plans encompasses the points in SECY-79-450 and retlects any input from the Federal Regional Advisory Committees (RAC). Items in local or State plans requiring improvement to meet the upgradeo criteria or NUREG-0654 but which are adequate to meet the essential planning elements of "HkC Guide and Checklist," NUREG-75/111, and Supplement 1 thereto, are not belug required for issuance or licenses for low-power testing. The above actions are in progress and will be conq>1eted in FY 1980. In the longer term, beginning in FY 1981, an integrated assessment of the implementation or tne plans will be performed. This assessment will take into account cczuments and reviews by the RAC as a result of State plan concurrence ettorts, including critiques of emergency exercises. The results or the Office or inspection and Entorcement (IE) special team ettorts t.o evaluate 11censee health pnysics programs during 1980-81 will be factorea into the review. This longer term review of emergency preparedness will consist of three parts: (a) a review or implementing procedures, including inplant and orisite personnel III.A.1.1-1

S.4Pb-1 FSAR and equipment. The review of these procedures will be done ny the team. Subsequently, periodic reviews and 2nspections will be performed by IE; (b) observing and critiquing exercises involving

licensee, local, and State capabilities; and (c) observing and critiquing exercises involving licensee, local, State and Federal capah111 ties.

For new operating license applicants, this must be completed betore full-power licensing and within about five years for operating reactors. NRR has sent letters to operating reactors, operating license applicants, and holders ci construction permits requesting information legarding time estimates tor evacuation of areas around plants to determine the difficulty of implementing protective measures for tne public. LILCO Position The upgraded "Shoreham Nuclear Power Station Rrergency Plan, Section 13.3" addresses the NRC position for this item. Please refer to this document which was submitted to the NRC via letter SNRC-568, dated May 27, 1981. i III.A.1.1-2

SIIPS-1 FSAR III.A.1.2 Upgrade Lii:ensee Emergency Response Facilities NRC Position _ r,ach operating nuclear power plant shall maintain an onsite Technical Support Center (TSC) separate from and in close proximity to the control room that has the capability to display and transmit plant status to those individuals who are knowledgeable of and responsible for engineering and maamgement support of reactor operations in the event or an acclaent. The center shall ne habitable to the same degree as the control room for postulated accident conditions. The licensee anall revise his emergency plans as necessary to incorporate the role and location of the technical support center. Records that pertain to the asbuilt conditions and layout of structures, systems, and components snall be readily available to personnel in the TSC. An operational support center (USC) 6.411 be establisned separate from the control room and other emergency response tacilities as a place where operations support personnel can asseanie and report in an emergency situation to receive instructions trom the operating

1. tat t.

Consuunications shall be provided netween the OSC, TSC, EOF, and control room. An knergency Operations Facility (EOF) (Near-Site) will ne operated by the licensee Ior continued evaluation and coordination of all 1.icensee activities related to an emergency having or potentially having environmental consequences. The EOF shall be located wituin 20 miles of the TSC to permit periodic tace-to-tace communication between management personnel in tr.e TSC ano the EOF. The EOS structure shall be well engineered tor the design life of the plant. If the guF is locatea witnin 10 miles of the TSC lt shall have an isolatable ventilation system witn HEPA filters and a backup EOF shall De located within trona 10 to 20 miles of the TSC. It the EOF is locats! oetween 10 and 20 miles or the TSC, no isolatable ventilation system or DecKup sOF is required. The racility will have sutticient space to accommoaate repreeentatives trom

Federal, State, and loca).

governments as eppropriate. In addition, the major state and local response agencies may provide for data analysis Jointly with tne operator at this location. The imergency Operations Facility (sOF) will provide information needed by Federal, State, and local autnorities zor implementation or of fsite emergency plans in addition to a centralized meeting location ror Key representatives from the agencies. Recovery operations shall be managed from tnis facility. Press facilities also may be available at the Emergency Operations Facility. LILCO Position The attached document " Emergency

Response

Facilities Design Criteria and Description" is our response to the NRC Position above. III.A.1.2-1

11600-sr-3400a 05/27/81 52 J.O. No. 11600.02 EMERGENCY RESPONSE FACILITIES DESIGN CRITERIA AND DESCRIPTION I SHOREHAM NUCLEAR POWER STATION - UNIT 1 LONG ISLAND LIGHTING COMPANY l wvy--< ,,-.,,,,,4 ._,,,.,+,.,-,,..,,,,e..-w. ,-.....w- .,c-e,--..,...-, .-.....-e---

TABLE OF CONTENTS 1.0 GENERAL CRITERIA AND DESCRIPTION 1.1 General Criteria 1.2 General Description 2.0 TSC DESIGN CRITERIA AND DESCRIPTT.CN (PHASE I) 2. '. Location / Space 2.2 Structural / Architectural 2.3 Habitability 2.4 Heating, Ventilation, and Air Conditioning 2.5 Instrumentation 2.6 Electrical Power Supply -2.7 Communications 2.8 Records 3.0 SPDS DESIGN CRITERIA AND DESCRIPTION (PHASE I) 3.1 Location / Display 3.2 Display Availability 4.0 OSC DESIGN CRITERIA AND DESCRIPTION (PHASE I) 4.1 Location 4.2 Communications j 5.0 EOF DESIGN CRITERIA AND DESCRIPTION (PHASE I) 5.1 Location j 5.2 Communications 5.3 Instrumentation 6.0 PHASE II (PERMANENT) EMERGENCY RESPONSE FACILITIES ATTACHMENTS l 1. TSC X/Q Calculations Technique 2. TSC Integrated Dose Calculation 3. TSC Data Set Available From Process Computer 4. TSC Rad-Met Data Available From NMC Computers FIGURES 1. Site Arrangement Plan 2. Second Floor Plan - Existing Security Building 3. HVAC Schematic Diagram 4. EOF Location l l l l

1.0 GENERAL CRITERIA AND DESCRIPTION 1.1 General Criteria Emergency Response Facilities (ERF) shall be pro.'ided for use by plant management, technical and engineering support perscnnel, and representatives from Federal, State, and local regulatory and response agencies in an emergency. These racilities snail be used for assessment of plant status and potential orfsite impact in support of the control roan command and control tunction. In addition these facilities should also te used in conjunction with implementation of onsite and offsite emergency plans. As required Dy its intended function, each functional unit of the ERF should be provided with the as-built drawings 01 general plant arrangements and piping, instrumentation, and electrical systems. Photographs of as-built system layouts and locations are an acceptable method of ' satisfying some of these neeos. 1.2 General Description The ERF will consist of five iunctional units. a. Technical Support Center (TSC) l b. Emergency operations Facility (EOF) c. Satety Parameter Display System (SPDS) d. Operational Support Center (OSC) e. Nuclear Data Link (NDL) The ERF will be implemented in two phases. Phase I will be implemented prior to ruel load and will consist or: a. A temporary TSC, based on the existing plant process and radiological monitoring computers, which will ce located on the second floor of the security building. The second floor of the security building is being upgaaded to serve as the Phase I TSC Dy the addit'on of filtered ventilation and computer generated system and radiological parameter displays. The T6C staifing and activation criterla and interaction with the sOF will be specified in the Shoreham Nuclear Power Station - Unit 1 (SNPS-1) Emergency Plan. c. An

EOF, based on the plant radiological monitoring system computers will be located approximately 19 miles l

from the Shoreham Nuclear Power Station. An existing L1LCO training facility in Hauppauge, Long Island, N.Y. l l is neing moditled with the addition of computer l generated radiological parameter displays. TSC and SPLS l alsplays will not be available in the EOF during Phase I. 1.

c. A temporary nonseisanc SPDS, based on the plant process computer, will be located in the main control room. An existing CRT mounted on panel 1d11*PNL-603 will be utilized to display SPDS graphic representa tions of plant safety status based on the Phase I data set. The SPDS displays will not be available in the TSC or EUF during Phase I. d. An OSC will be established in a designated area of tne office and service building. The OSC will De provided with communications between the

USC, TSC, EOF, and control room.

e. The NDL will not be implemented during Phase I. Phase II of the ERF will be implemented arter fuel load and initial commercial operation. The Phase II ERP is being designeo to be in full compliance with NUREG-0696. 2.0 TSC DESIGN CRITERIA AND DESCRIPTION (PHASE I) 2.1 Location / Space 2.1.1 Criteria The Phase I TSC shall be located in proximity tof but separate from, the control room and within the plant security boundary. The facility shall be of suf ficient size to accommodate tnose operating due TSC and NRC and vendor representatives as we?.1 as the required equipment and technical data. 2.1.2 Description The existing security building is a separate structure located on the north side of the plant, as shown on the Site Arrangement

Plan, Figure 1.

The entire second floor of approximi.tely 4,000 sq tt consisting of lecture and classrooms, an

office, a

library, and toilets will be made available as the TSC on a Joint basis. Tnis location hac been determinea to De within a nominal two minute walx from the main control room to allow tor f ace-to-face meetings between operating and support personnel. The rirst l floor will continue as tne security tacility altnough it will ne within the protected (habitable) environment provided ror tne entire building due to tne TSC requirements. The existing floor plan is shown on Figure 2. It will provide anple space for 25 people. 2.2 S_tructural/ Architectural 4 2.2.1 Criteria Tne TSC need not be designed to seismic Category I requirements. The building should be well Duilt in accoroance with souno engineering

practice, with due consideration to tne etrects ut natural phenomena which may occur at the site.

2.

2.2.2 Description The existing security building is being moc1 fled as necessary to accommodate the functions of a TSC. 2.2.2.1 Existino Structure The security building supers tructure is or steel tramed construction supported on reinforced concrete spread footings. The energy efficient curtain wall design utilizes insulated cavity wall construction. The roof decx and intermediate Iloor slab are of reinforced concrete construction, with tne rooting material comprised of insulated, built-up asphalt and gravel. 2.2.2.2 Building Moditications The existing roof level HVAC penthouse will be expanded to acconspodate additional mechanical equ ipment. This penthouse expansion will be of a similar construction as the existing security building and vill complement the existing architectulal style. Additicnal building modifications will include the architectural sealing of the building to develop the ability to sustain tne positive internal pressure required for TSC occupation. This will be accomplished by providing existing doors and trames with appropriate weather stripping and gaskets. 2.3 Habitability 2.3.1 Criteria t l The TSC shall be designed to protect personnel Irom radiological hazards including airect radiation and airborne contaminants in accordance with General Design Criterion 19 and 6tandard Review Plan 6.4. Limits 01 5 rem wnole body, 30 rem thyrold, shall not he exceeded tor the duration of tne accident considering major sources of radiation. Monitoring shall be provided for both alrect radiation and i l airburne ladioactive contaminants. The monitors should provide l warning if the radiation levels in the support center ure reaching levels approaching the design lir.dt s. The licensee should designate action levels to define when protective measures should oe taken (such as using breathing apparatus and potassium lodine tablets, or evacuation to the ccatrol room). 2.3.2 Description The security building meets these criter2a, as tollows: 1. Credit is taken for mixed mode release; sec Attacnment 1 for justification, and 3. l l

2. The TSC atmosphere is filtered through a Charcoal-H4PA filter. See for a discussion or the analysis. This is achieved ny upgrading the security building HVAC system as discussed in Section 2.4 The 30 day integrated d9aes calculated basea on the above are: Total 30 Day Integrated Dose (Rem) Thyroid Gamma Beta Mixed Mode Release & 95 percent Halogen Filter 16 9. 3.7 A

portable, dedicated continuous airborne monitor, with ludine and particulate tilter cartridges, will be provided within the TSC to monitor airborne activity levels.

This monitor will include variable setpoints with audible and visual alarms to alert personnel to increasing airborne activity. This monitor will be sensitive to radioiodine concentrations as low as 10-7 p Ci/cc. In addition, two portable, dedicated area monitors will be provided within the TSC to provide measuring of direct radiation levels. These monitors will also include varlaLiv setpoints with audible and visual a la rms. Tne locations presently planned for these airborne and area monitors are shown on Figure 2. Procedures under development will provide for set-up ano operability verification of tnese monitors upon TSC l activation, check for proper settings of alarm setpoints, and i implementation of protective measures as required upon alarm activation. 2.4 Heating, Ventilation, and Air Conditioning 2.4.1 Criteria Permanent ventilation systems, including particulate and charcoal

tilters, shall te provided.

The TSC snall have tue same radiological habitability as the control room under accident conditions, and the TSC ventilation system shall function in a manner comparable to the control room ventilation system. The ventilation system need not be

seismic, Category I

qualltled, redundant, instrumented in the control room, or autoantically activated to fulfill itS role. Tne TSC ventilation system will consist of high-efficiency particulate air (hEPA) and cnarcoal filters as a minimum. 2.4.2 Description To pressurize tae security building atmospnere, 2,000 to 3,000 cim ot. filtered outside air will be suppilea to tne building. Provision has been made in the system design for 3,000 crm maximum outside air, with recirculation capability of up to 1,000 cfm. 4.

I A 3,000 cfm capacity Charcoal-HEPA filter train with booster fan will be installed on the root or the security building inside an extension of tne existing equipment room. This 111ter train will remove, with 95 percent efficiency, the gaseous

lodine, methyl

iodine, and any particulates from the outside air, reducing concentrations to within acceptable limits.

I In order to use the outside air of 2,000 to 3,000 ctm for pressurization only, exhaust f rom the second floor lecture

hall, toilets, and locker area will be eliminated by shutting down roof fans and securely closing dampers.

In addition, the main exhaust damper will be closed securely. Procedures will be provided to ensure all necessary actions are completed upon manning one TSC. Existing system controls are being nodirled to suit the new design requirements and to maintain positive pressure 10110 wing a l DBA. A central control center will be provideo for remote manual operation of the HVAC cystem during an accident. Tnis will include push buttons for all the manual-controlled, power operated dampers, startur of the filter booster fan, and Girect expansion air conditioning. A conceptual study sketch (Figure 3) showing a scuematic of the existing security building HVAC system and proposed nodifications is attached. Regulatory Guide 1.140 Revision 1, Design Testing and Maintenance Crateria f or Normal Ventilation Exhaust System hir Filtration and Adsorption Units ot Light-Water-Cooled Nuclear Power Plants, will be tollowed as required to meet the criteria as stated in Section 2.4.1. Spare parts will be readily available. 2.5 Instrumentation 2.5.1 Criteria The TSC shall have the capability to display plant patameters and equipment status to technical and management personnel responsible for engineering and support of reactor operations (control room activitics) tollowing an accident. The TSC capability to assess plant parameters snall be independent from actions in the control room. The TSC equipment lu not required to be satety grade or redundant. The data between the oeginning of the accident (t=0 detaned as initial event, e.g., reactor scram or turbine trip) and the time of activation or tne TSC shall not be lost and shall be available at the TSC. Tne instrumentation in the TSC shall not degrade plant installed saf ety grade instrumentation and equipment. 5.

2.5.2 Description The TSC data display will be entirely computer based, with inputs provided by the plant process computer

system, the emergency response facilities (ERF) data acquisition

system, and the digital radiation monitoring system.

The data will be processed and displayed by the plant process computer (normal inputs to process computer and ERF data acquisition system inputs) and the digital radiation monitoring computer system (meteorological and radiation monitoring data). Refer to FSAR Sections 7.5.1.6 and 7.5.2.7 on the process computer system and to sections 11.4 and 12.3.4 on the digital radiation monitoring system. The selection of parameters will be based on capabilities to: 1. Diagnose initial event / accident, 2. Evaluate performance of safety related systems, 3. Ensure that the plant is in a stable shutdown condition following an accident, 4. Monitor onsite radiological data, and 5. Monitor meteorological data. 2.5.2.1 In-plant System Parameters Presentation of in-plant system parameters will be provided at I the TSC by the process computer system. Data will be presented by a color graphics CRT display with keyboard access. Two high speed typers will be provided for hard copy recoro. One typer, a RSR (Input / Output)

type, will provide user demana request capabilities while the other tfper will be of the RO (Receive l

Only) type and will provide output of the process computer TSC l data log (Section 2.5. 2.3). The entire process computer system data base will thus be available, on demand, for TSC display. provides a listing or specific data points which will be availaole at tne l TSC as part 01 tne PCS TSC historical data file and log (Section 2.5.2.3). Class 1E and non-Class 18 signals which are being added to the plant process computer specirically to support the temporary Tbc will be accessed and isolated througn tne use of a Valldyne Model i RD 310 htgn speed data acquisition system. All components of l this syctem arc seismically qualified to support tne SPDS function of the emergency response facilities. All components of this system prior to the multiplexed, digi tal, fiber optic transmission path have been purchased as Class 1E qualitied equipment. Tne Validyne Model HD 310 will ne configured as a l remote multiplex system to

access, condition,

isolate, and l

multiplex signals for transmission to a master receiver unit, from whicn the data will be accessed by the plant process 6.

i computer. Thus, all Class 1E signals required at the TSC will be isolated via the fiber optic data linx prior to input to the process computer to ensure that these signals are not jeoparuized or degraded by the operation ot, or failure of, the process computer system. ERF multiplex system termination cabinets will be located in the relay room and vill be designed as the central gathering point for all required additional data priot to process computer system input. 2.5.2.2 Radiological and Meteorological Data Presentation of in plant radiological parameters and meteorological data will be provideo at the TSC by tne radiation monitoring computer system. Data will be presented by a color graphics CRT display with keyboard access. One high speed typer, a RO (receive only) type will be provided for hard copy records by way of user demand requests from the CRT neyDoard ano outputs from the RMS TSC data log an_ historical file (Section 2.5.2.3). The entire RMS computer system data base, including of f-site cose calcuations, will be available, on

demand, for TSC display.

provides a listing of specific data points which will be available at the TSC as part of the RMS TSC historical data rile and log (Section 2.5.2.3). 2.5.2.3 TSC Loos and Historical Data Files Two logs and nistorical data riles will be provided, one by way of the process computer system (PCS) and the other by way of the radiation monitoring system (RMS) computer. Pre-event historical data files and post-event logging ot data will provide TSC personnel with the capability to diagnose the initiating event and its radiological consequences, as well as provide an immediate evaluation of satety systems performance and plant status. 2.5.2.3.1 TSC Log /distorical File - In-plant System Parameters The process computer TSC historical data log will initiate upon receipt of an external event signal (t=0), a printout on a TSC

typer, of those in-plant system parameters assigned to this 1cg (selected from Attachment 3 - redundant parameters will not ne included in the log unless they are from redundant independent trains of safety systems).

The log will continue printing out data until manually terminated. A 2 hour pre-event data rile (i.e., history) of these selected TSC log parameters will be stored by the process

computer, at 1 minute intervals, to be recalled to the TbC, on demand, using the TSC KSh typer.

Post event data will be dumped on magnetic tape at 1 minute intervals up to 12 hours post event and at 5 minute intervals from 12 hours to up to 2 weeks post event using multiple, manually controlled tape reel dumps. This commitment is subject to the commercial availability of the hardware and software required to implement this nistorical data log. 7.

2.5.2.3.2 TSC Loc / Historical File - Radiological / Meteorological Parameters The RMS computer TSC historical data log will initiate upon receipt or an external event signal (t=0) a printout, on the RMS TSC

typer, of those radiological / meteorological parameters assigned to this log (selected irom Attachment 4).

The log will continue printing out data until manually terminated. 2.6 Electrical Power Supply 2.6.1 Criteria A power supply shall exist for the permanent ventilation system of the TSC. The power supply to the TSC instrumentation need not meet sarety grade requirements, but shall be reliable and of a quality compatible with the TSC instrumentation requirement =. The power supply for instrumentation shall be continuous once the TSC is activated. 2.6.2 Description The security building facilities are presently supplied from a 300 kVA 480-120/208 V transformer through an automatic transfer switch which receives power trom Duses 11C and 12C. This arrangement allows access to two sources of otisite power and l will carry all existing and added

HVAC, lighting and other necessary loads.

l The power requirements for the added computer points and the peripheral equipment in the TSC will be supplied from the existing computer inverter which is connected to the safety-related dieselc. The inverter serves as an isolation oevice so that the computer does not have to be tripped on a IDCA signal. Power tor power supplies associated with isolation devices fcr added instrumentation will be fed fran the appropriate satety related buses. 2.7 Communications A communications systesn will be provided as necessary to support the tunctions of the TSC. Details or this communications system are shown in the Shoreham Nuclear Power Station Emergency Plan. 2.8 Records 2.8.1 Criteria A complete set of as-built drawings and other records, as descriDed in ANSI N45.2.9-1974, shall be properly stored and filed at the site and accessible to the TSC uncer emergency conditions. These documents shall include, cut not be limited to, general arrangement

drawings, P& ids, paping system isometrics, electrical schematics, and photographs of components 8.

installed without layout specifications (e.g., tield-run piping and instrument tubing). 2.8.2 Description critical documents such as Emergency Procedur es, System Descriptions, and General Arrangement, Flow, Logic and Elementary Schematic Drawings will be available in the TSC and the balance will be available in the plant Records Center. 3.0 SPDS DESIGN CRITERIA AND DESCRIPTION (PHASE I) 3.1 Location / Display. 3.3.1 Criteria l The Phase I SPDS shall be located in the control room with additional SPDS displays provided in the TSC and EOF. The t SPDS may be physically separated from the normal control board; however, it shall be readily accessible and visible to the shift supervisor, control room senior operatur, shirt tecnnical advisor ( dnd at least one reactor Operator from the normal operating area. If the SPDS is part of the control boara, it shall be easily recognizable and readable. { 3.1.2 Description The Phase I SPDS will consist of an existing color CRT located on panel 1H11*PNL-603 in the control room. This CRT will display computer generated graphics representing the station safety status in the following five areas. 1 a. Reactivity control l b. Reactor core cooling and heat removal l c. Reactor coolant system integrity d. Radioactivity co7 trol e. Containment integrity These displays will be based on a sunset of the Phase I hkF data set available to the plant process computer. Tne Phase I bPDb will be non-seismic since it will be based on the existing plant process computer. The SPDS displays will be available on request on the CRT located in ene Phase I TSC on the second floor of the security building. SPDS displays u111 not be available in tne EOF during Phase I. 3.2 _ Display Availat !.ity The SPDS CRT will have access to the complete plant process computer data base. The operator will therefore ce able to call up the SPDS graphics, all additional Phase I BOP parameters and graphics, and all plant process computer parameters and graphics, 9.

This CRT will normally display the graphic snowing the safety status of the fita areas listed in Section 3.1.2. It the CRT is required to display plant operation parameters and grapnics on a temporary basis, the CRT will be returned to its SPDS tunction upon completion of the operation requiring alternative displays. 4.0 OSC DESIGN CRITERIA AND DESCRIPTION (PHASE I) 4.1 Location 4.1.1 Criteria The OSC shall provide a location where Licensee operation support personnel will assemble in an emergency. The OSC shall also provide a location where plant logistic support can be coordinated during an emergency and will restrict control room i access to those support personnel specitically requested by the shift supervisor. 4.1.2 Description l The general orfice area of the office and service building has been designated as the OSC for the Shoreham Nuclear Power Station. The office and service building is aa3acent to the control room building. Taking into account the time to clear any l access control security check points the transit time between the l control room and OSC is less than two minutes. 4.2 Communications A communications system will be provided as necessary to support the functions of the OSC. Details of this communications system are snown in the Shoreham Nuclear Power Station Emergency Plan. 5.0 dOF DESIGN CRITERIA AND DESCRIPTION (PHASE I) l 5.1 Location 1 5.1.1 Criteria l The location of the EOF shall be witnin 20 miles of the TSC and i shall be so located and/or projected to allow uninterrupted functioning during radiation releases for which it woulo De necessary to recommend protective actions for the pubile to offsite officials. 5.1.2 Description The EOF will be located approximately 19 miles from the Shoreham Nuclear Power Station TSC at an existing LILCO Training Center in Hauppauge, Long Island, N.Y. Figure 4 shows the locat.lon of the EOF lelative to the plant site. The building will be modified to provide additional security monitoring and to provide secure l storage for the EOF display and colanunications equipment. Working space will be provided for personnel assigned to the LOF 10. l

as well as representatives from

Federal, State, and Local Regulatory and Emergency Response Agencies.

Space will also be allocated for the storage of plant records and historical data. Portable radiation monitoring equipment will be provided to provide early warning to EOF personnel of adverse conditions that may affect habitability of the EOF. 5.2 Comunications 5.2.1 Criteria The EOF shall have reliable voice communications iacilities to the Tf+, control

room, NRC, and state and local emergency operations centers.

The normal communication path between the EOF and the control roan will be through the TSC. The EOF voice comunications facilities shall include reliable primary and backup means cf comunications. Facsimile transmission capatility between the

EOF, the

TSC, and the Nhc operations center shall be provided.

5.2.2 Description A communications system will be provided as necessary to support the functions of the EOF. Details of this communications system are shown in the Shoreham Nuclear Power Station Emergency Plan. 5.3 Instrumentation 5.3.1 Criteria Aquipment shall be provided to gather, store, and display data needed in the EOF to analyze and exchange information on plant conditions with the designated senior licensee manager in charge of the TSC. The EOF Data System Equipment shall perform these functions independently fran actions in the control room and witnout degrading or interfering with control room and plant functions. 5.3.2 Description The Phase I EOF will be connected to the plant radiation monitoring system computers via modems and leased telepnone lines. The complete radiation monitoring system data case will be available for display (CRT and hard copy) and analysis in the EOF. This data base includes plant meteorological data as well as radiological parameters. There will not ne any bvDS cisplays available in the Phase I EOF. t3. 0 PERMANENT (PHASE II) EMERGENCY RBSPONSE FACILITIES The Phase II ERF will be designed to De in full compliance with the requirements of NUP.EG-0696 and all otner applicable regulatory documents. As a minimum the data set will include those Type A, B, C, D, and E variables specified in Regulatory ( G2ide 1.97, Revision'2 which have been implemented in the plant i 11.

and the meteorological and radiological data in the radiation monitoring system computers. The total Phase Il data set list is being developed at this time and will be furnished later as a separate submittal. The remote multiplex system, which was purchased and contigured under Pnase I to access and input additional data into the plant process computer, will be reconfigured to input data to a new ERF computer system. The remote multiplex system will nave its applicable components qualified Class 1E and will be utilized to isolate Class 1E signals prior to input to either the

proces, computer system for Phase I or the new ERP computer system tor Phase II.

The new ERF computer

system, which will be purchased, will conceptually consist or a small mini or micro computer to tuilill the control room SPDS requirements and a larger mini computer to fulfill the TSC/ EOF /NDL requirements.

These two computers will be located in a new TSC computer room within the SBA/TSC ana will be linxed together via a high speed data linx. Tne remote multiplex system will teed data independently to each computer. The ERF computer system will provide pre anc post event historical logs in accordance with NUREG-0696. We will purchase the SPDS computer portion or the system as a seismically qualified machine to negate the need for a hardwired bacxup. Radiological and meteorological data will be red to the new ERP computer system via a direct data link to the plant rad / met computer which is a dual redundant Modcomp 7u35 sy7 tem.

However, any rad / met parameter which becomes defined as an SPDS parameter will be brought to the ERE computer system via tne remote multiplex system ano independent of the rad /mer, computers due to the SPDS seismic requirements.

i The Phase II TSC will be located as shown on Figure 1 In tne seismically designea annex to the office and service ouiluing which is now being constructed. Tnis new building will house Data Acquisition rquipment, the new TSC and SPDS (Seismic) computers, and the

displays, work

areas, and tilos which constitute the TSC.

The Service Building Annex / Technical Support tenter (SBA/TSC) will be a new four story structure (with provisions for a fifth floor) located due west of tne Orfice and Service Building. The TSC will be constructed or reintorced concrete eith exterior walls and roof slab a minimum of 18 inches thick. fae balance of the structure will be a craced steel trame. based on a mixed mode release concept tne raalation coses Ior une Phase II TSC will be within the acceptaole habitability criteria of General Design Criteria 19. The validity of the mixeo mode i concept will be verified by analysis ot a sight specatic study. 12.

l l The Phase II SPDS will consist of two seismically qualified color grapnic CRT's (suoject to commercial availability) mounted in a console located just behind the operators desk. The Phase II SPDs display format will te a 3 level graphical / alphanumeric display showing the saf ety status of the current operating mode of the plant. The OSC under Phase II will remain as is with no augmentation of wnat is provided for Phase I. The EOF under Phase II will be augmented with the addition 01 a dedicated terminal for SPDS displays and dedicated terminals for the accessing and display of any parameter or grapnic display in the TSC computer data base. Additional radiation monitoring inputs will be added to the TSC and/or the radiation monitoring system computers. These additional radiological parameters are required for compliance with Regulatory Guide 1.97, Revision 2. The Nuclear Data Link (NDL) will be defined when a more detailed definition of requirements is available in tne applicable regulatory documents. Both the Phase II TSC computer system and the Data Acquisition system have been configured to support the future addition of the NDL. Further details on the Phase II emergency response facilities will be provided in a future submittal. 13. .. ~

ATTACHMENT 1 SECURITY BUILDING 4 TSC X/O CALCULATIONAL TECHNIQUE Murphy and Campe identifies the technique that is to be utilized co evaluate X/Q values to be used in plant habitability calculations (see Standard Review Plan 6.4). The technique identified applies to a design basis accident (DBA) release emanating from some wall of the containment structure. Historically, DBA X/Q calculational techniques have been conservatively limited to ground level telease criteria except for releases from stacks 2 1/2 times the height of the nearest adjacent building (see Regulatory Guide (PG) 1.145). The postulated release from the Shoreham DBA is unique in that the reactor building standby ventilation vent fulfills all seismic criteria. Instead of the release leaking through portions of the primary and secondary containments, it is confined to exit through the vertical vent atop the secondary containment structure. This vent is higher than any adjacent building in the plant.

Thus, a more appropriate approach to consider X/Q calculation would be to utilize the mixed-mode release concept identified in RG 1.111, Revision 1, Position C2b.

To this end, the governing Murphy and Campe equation can be combined with the RG 1.111 Position C2b concept (which was developed from atmospheric tracer tests sponsored by the Atomic Industrial Forum at Millstone) to produce the following working equation: h T)Exp - f (hS) * ~ ET z X/Q = _ A u(wo a + K+2 -unc a z yz Where: entrainment coefficient E = T i E l f # w0/ S1 T l E = 2.58 - 1.58 (Vb/U) for 1 < Wo/U s 1.5 T i Al-1 l l l l l l l

0.3-0.05 (W, /U ) for 1.5 < W / E $ 5.0 E = T o E = 0~ for W /U> 5.0 T. o 0 wind speed at 10-m level (m/sec) = horizontal dispersion coefficient (m) a = y 1 's vertical dispersion coefficient (m) = containment building area (m ) A = K = 3 (S/d)2 ' where: source to receptor distance (m) S = containment diameter (m) d = h, effective stack height (m) = i where: h, hs+hpr - ht = height of vent release (m) h = 3 hpr = nonbuoyant plume rise (m) h = height of TSC roof above plant grade (m) t stack exit velocity (m/sec) W = o Al-2

It is conservatively assumed that the 10-m wind speed applies to the elevated portion of the release. RG 1.145 also identifies a fumigation condition as limiting for elevated (or partially elevated) releases during accident conditions. Seabreeze fumigation occurs only when the winds are blowing onshore. Examination of the relative locations of the shoreline, containment structure, and TSC, clearly shows the fumigation from the containment can only occur in the opposite direction from the TSC. Thus, this condition yields a zero X/Q at the TSC. The final consideration is to identify a 5 percent worut condition for this type of release. In order to introduce more conservatism ints the calculational technique, the meteorological condition producing the highest (worst) X/Q value (i.e. 0.01 percent) was assumed to occur for the first 8 hr of the accident (0-8 hr period). An additional conservatism, nonbuoyant plume

rise, due to the momentum of the release, was presumed to be zero, even though RG 1.111, Revision 1 recommends its consideration.

The X/Q's shown below were determined as being the highest (worst) values for the TSC. For the mixed-mode release, the O-8-hr X/Q value naximized during Pasquill stability Class D (neutral) with a wind speed of 10.73 m/sec. For the ground release

scenario, the 5 percent X/Q resulted from a Pasquill stability Class F (sta' ole) and a wind speed of 1 m/sec.

Security Building "3 0-8 Hr 8-24 Hr 1-4 Day 4-30 Day Mixed Mode Release X/Q (sec/m') 8.58x10 5 5.32x10 5 1.89x10 5 3.43x10 8 Ground Release X/Q (sec/m') 1.02x10 ' 6.32x10

• 2.24x10 6 4.08x10 5 e

i l Distance 107 m from source to receptor i I l l l Al-2

m ATTACHMENT 2 SECURITY BUILDING 4 TSC INTEGRATED DOSE CALCULATION Regulatory Guide 1.3 identifies the technique that is to be utilized to evaluate the integrated dose. The TSC integrated dose analysis was done based on a LOCA release from the primary containment at a rate of .5. percent volume per day, 10 gph ECCS leakage into th3 secondar y containment, and MSIV leakage corresponding to a Technical Specification value of 11.5 scfh per valve. All releases are discharged via the RBSVS. The thyroid doses are computed using the convarsion factors given in TID 14844 and a breathing rate of 3.47x10-4 m'/sec(1.25 m /hr). The gamma doses are computed based on a 8 finite cloud model in the TSC plus a semi-infinite cloud. surrounding the building which has a 4 inch concrete roof and equivalent 6 inch concrete walls. The beta doses are based on the semi-infinite cloud model suggested by the NRC, Regulatory Guide 1.3. The total 30-day integrated LOCA doses from the airborne activity in the TSC plus gamma penetrating the building are indicated below. The doses are calculated based on mixed-mode releases with atmospheric dispersion factors (X/Q's) as described in and providing a HEPA-charcoal HVAC system as i delineated in Section 2.4.2 of the ERF Design Criteria and Description. Total 30-Day Integrated Dose (Rem) Thyroid Gamma Beta i l Mixed-Mode Release 95% Halogen Filter 16, 9. 3.7 i No filter 319. 9. 3.8 l l i I A2-1 l ~

11600-sr-3400f 05/27/81 34 ATTACHMENT 3 TSC DATA SET AVAILABLE FROM PROCESS COMPUTER i PARAMF,TER INSTRUMENT 1. Reactor Pressure 1B21*PT004A 2. Reactor Pressure 1B21*PT004B 3. Reacror Wtr Lev (WR) 1B21* LIT 004A i 4. Reactor Wtr Lev (WR) 1D21*L1T004b 5. Reactor Wtr Lev (FZ) 1B21* LIT 007A 6. neactor Wtr Lev (FZ) 1B21* LIT 007B 7. ADS /SRV Ta11 pipe Press 1B21*PT153A 8. ADS /SRV Ta11 pipe Press 1B21*PT153B 9. ADS /SRV Tailpipe Press 1B21*PT153C 10. ADS /SRV Tailpipe Press 1B21*PT153D 11. ADS /SRV Tailpipe Press 1B21*PT153E 12. ADS /SRV Tailpipe Press 1B21*PT153F 13. ADS /SRV Tailpipe Press 1B21*PT153G 14. ADS /SRV Ta11 pipe Press 1B21*PT153H 15. ADS /SRV Teilpipe Press 1821*PT153J 16. ADS /SAV Ta11 pipe Press 1821*PT153K 17. ADS /SRV Ta11 pipe Press 1B21*PT153L 18. RCIC Pump Disch Flow 1E51*fT003 19. RHR Sys A Flow 1E11*FT001A 20. RHR Sys B Flow In11*FIO018 l 21. RHR HX A Outlet Temp 1E11*TE012A l 22. RHR HX B Outlet Temp 1E11*TE012B 23. RHR HX A Inlet Temp 1311*TE011A l 24. RHR HX B Inlet Temp 1E11*TE011B 25. HPCI Pump Disch Flow 1E41*FT003 26. Core Spray Sys A Flow 1621*FT002A 27. Core Spray Syo B Flow 1E21*FT002B 28. RHR HX A - SW Outlet Temp 1h11*TE013A 29. RHR HX B - SW Outlet Temp 1211*TE013B 30. RHR Svce Wtr A Flow 1h11*FT006A 31. RHR Svce Wtr B Flow 1E11*Pr00bB 32. Reactor Bldg. Flood Level 1G11*LTS645A 33. Reactor Bldg. Flood Level 1G11*LTS645B 34. Drywell Pressure 1Z93*PT003A 35. Drywell Pressure 1Z93*PT003B l 36. Suppression Chamber Press 1293*PT004A 37. Suppression Cham er Press 1293*PT004B n 38. Suppression Pool Wtr Temp (1 ft) 1Zw3*TE110Z 39. Suppression Pool Wtr Temp (1 f t) 1Z93*TE 111W 40. Suppression Pool Wtr Temp (1 f t) 1Z93*TE112Y 41. Suppressieu Pool htr Temp (1 ft) 1Z93*TE113x 42. Suppressic-Pool htr Temp (2 ft) 1Z93*TL132A 43. Suppression Pool Wtr Temp (2 ft) 1Z93*TE133B 44. Suppression Pool Wtr Temp (2 f t) 1Z93*TE134A 45. Suppression ?ool Wtr Temp (2 ft) 1Z93*T4135B f 46. Suppression Pool Wtr Level 1Z93*LT001A A3-1 ~

11600-sr-3400f 05/27/81 34 PARAMETER INSThUMENT 47. Suppression Pool Wtr Level 1Z93*LT001B 48. Drywell Hydrogen Conc. 1T48*H2?115A 49. Drywell Hydrogen Conc. 1T48*H2Z11SB 50. Suppression Chamber He Conc 1T48*h2Z116A 51. Suppression Chamber H, Conc 1T48*H2Z11bB 52. Drywell Oxygen Conc 1T48*02Z123A 53. Drywell Oxygen Conc 1T48*02Z123B 54. Suppression Chamber 0, Conc 1T48*02Z124A 55. Suppression Chamber 0, Conc 1T48*02Z124h 56. Reactor Blog. Press. 1T41-PDT011 57. ADS /SRV Air Hdr. A Press 1P50*PT116A 58. ADS /SRV Air Hdr. B Press 1P50*PT116B 59. Drywell Temperature (Later) 60. (11 RTDs) (Later) 61. (Later) 62. (Later) b3. (Later) 64. (Later) 65. (Later) o6. (Later) 67. (Later) 68. (Later) 69. (Later) 70. RBCLCW HX A Outlet Temp 1P42-TE001A 71. RBCLCW HX B Outlet Temp 1P42-TE001B 72. Circ Wtr Pmp A Disch Press 1N71-PT083A 73. Circ Ntr Pmp B Disch Press 1N71-PT083b 74. Circ Wtr Pmp C Disch Press 1N71-PT083C 75. Circ Wtr Pmp D Disch Press la71-PT083D 76. Main Condenser Pressure 1 Nil-PT005A 77. Main Condenser Pressure 1N21-PT005B 78. Condensate Storage Tk. Level 1F11-LT002 79. Feedwater Temperature 1821-TT001A 80. Feedwater Temperature 1B21-iT001b 81. Feedwater Temperature 1B21-iT001C 82. Feedwater Temperature 1B21-TT001D 83. Feedwater Flow 1C32-FT001A 84. Feedwater Flow 1C32-FT001H 85. Neutron Flux Level APRM A 86. Neutron Flux Level APRM B 87. Neutron Flux Level APRM C 88. Neutron Flux Level APRM D 89. Neutron Flux Level APRM E 90. Neutron Flux Level APRM F 91. Neutron Flux Level TIP A 92. Neutron Flux Level TIP b 93. Neutron Flux Level TIP C 94. Neutron Flux Level TIP D A3-2

11600-sr-30001 05/27/81 34 ) PARAMETER INSTRUMENT 95. Control Rod Position (Core Map Graphic Display) In addition 4 more parameters may be inputed to the process computer instead of the radiological computers: Drywell Hi Range Area Radiation A 1D21*RE-085A Drywell Hi Range Area Radiation B 1D21*Rh.-085D kBSVS H1 Range Area Radiation 1D11*RE-134 Station Vent H1 Range Radiation 1D11*RE-126 A3-3

ATTACHMENT 4 TSC RAD-MET DATA SET AVAILABLE FROM NMC COMPUTERS PARAMETER INSTRUMENT 1. Low Range Containment Atmosphere Particulate Rad (Drywell) 1D11*RE061 2. Low Range Containment Atmosphere Gas Rad (Drywell) 1Dll*RE062 3. RHR Service Wtr Disch. A Rad. 1Dll-RE023A ~ 4. RHR Service Wtr.Disch. B Rad. 1D11-RE023B 5. RBCLCW System Rad 1Dil-RE024 6. Control Room Vent Rad 1D11*RE025A 7. Control Room Vent Rad 1D11*RE025B. 8. -Control Room Vent Rad 1D11*RE026A 9. Control Room Vent Rad 1D11*RE026B 10. Control Room Atmosphere Particulate Rad 1D11*RE027 11. Control Room Atmosphere Gas Rad 1Dll*RE028 12. General Area Rad 1D21-REOO1 thru thru 41. 1D21-RE030 42. General Area Rad 1D21-RE032 thru thru 52. 1D21-RE042 53. Release Path Activity (Station Vent 1D11-RE042 Exhaust) Noble Oas 54. Release Path Activity (Station Vent 1D11*RE069 Exhaust) Gross 55. Release Path Activity (RBSVS) 1Dll*RE021A Noble Gas 56. Releese Path Activity (RBSVS) 1Dll*RE021B Noble Gas 57. Release Path Activity (RBSVS) 1Dll*RE022A Noble Gas 58. Release Path Activity (RBSVS) 1Dll*RE022B Noble Gas 59. Gaseous Effluent Flow Rates 1D11*FTO69 60. Gaseous Effluent Flow Rates 1D11*FTOO4B i 61. Gaseous Effluent Flow Rates 1T46*FTOO4B 62. Main Steam Line Rad 1D11*RE011A l 63. Main Steam Line Rad 1D11*RE011B 64. Main Steam Line Rad 1D11*RE011C 65. Main Steam Line Rad 1D11*REOllD METEOROLOGICAL PARAMETERS INSTRUMENT 66. Wind Direction at 33 Ft N/A 67. Wind Direction at 150 Ft N/A 68. Wind Upeed at 33 Ft N/A 69. Wind Speed at 150 Ft N/A 70. Temperature at 33 Ft N/A 71. Temperature AT Between 33 Ft & 150 Ft N/A A4-1

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l ~ SNPS-1 FSAR III.A.2 Improving Licensee Emergency Preparedness--Long-Term NRC Position Each nuclear tacility shall upgrade its emergency plans to provide reasonable assurance that adequate prot.ective measures can and will ne taken in the event or a radiological emergency. Specific criteria to meet this requirement is delineaten in NUREG-0654 (FEMA-R3P-1), " Criteria for Preparation and Evaluation of Radiological Emergency

Response

Plans anc Preparation in l Support of Nuclear Power Plants." In accordance with Task Action Plan item III.A.1.1, " Upgrade IJaergency Preparedness," each nuclear power facility was required to immediately upgrade its emergency plans with criteria provided October 10, 1979, as revised by NUREG-0654 (FEMA-REP-1, issued for interim use and

comment, January 1980).

hew plans were smanitted by January 1,

1980, using the October 10, 1979 criteria.

Reviews were started on the upgraden plans using NUREG-0654. Concomitant to these

actions, amendments were developed to 10 CFR Part 50 and Appendix 8 to 10 CFR Part 50, to provide the long-term implementation requirements.

Tnese new rules were issued in the Federal Register on August 19, 1980, with an effective date ot November 3, 1980. The revised rules delineate requirements for emergency preparedness at nuclear reactor racilities. NUREG-0654 (FEMA-REP-1), " Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Prepaledness in Support of huclear Power Plants," provides detailed items to De included in the upgraded energency plans and, along with the revised rules, provides the meteorological criteria, means for providing tor a prompt notification to the popalation, and the need for emcrgency response facilities (see Item III.A.1.2). Implementation of the new rules levied the requirement for the licensee to provide procedures implementing the upgraded emergency plans to the NRC tor review. Publication 01 Revision 1 l to NUREG-0654 (FEMA-REP-1) which incorporates the many pubile t consnents received is expected in October 1980. This is the j document that will be used by NRC and FEMA in their evaluation of emergency plans sub oitte', in accordance with the new NRC rules. NUREG-0654, Revision 1; NDREG-0696, " Functional Criteria for Emergency Response Facilities;" and the antendments to 10 CFR Part 50 and Appendix E to 10 CFR Part 50 regarding emergency preparedness e provide more detailed criteria lor emergency plans, design, and functional criteria for emergency response facilities and establishes firm dates for submission or upgraded emergency plans for installation of prompt notitication systems. These revised criteria and rules supersede previous Commission gulaance for the upgrading of emergency prepredness at nuclear power tacilities. III.A.2-1

SNPS-1 FSAR Revision 1 to NUREG-0654, " Criteria ror Preparation and Evaluation of Radiological Emergency

Response

Plans and Preparedness in Support of Nuclear Power Plants," provides meteorological criteria to fulfill, in part, the standard that " Adequate methods,

systems, and equipnent for assessing and monitoring actual or potential ofisite consequences of a

radiological emergency condition are in use" (see 10 CFR 50.47). The position in Appendix 2 to NUREG-0654 outlines tcur essential elements that can be categorized into three functions: measurements, assessment, and communications. Proposed Revision 1 to Regulatory Guide 1.23, " Meteorological Measuressents Programs in Support of Nuclear Power Plants," has been adopted to provide guidance criteria for the primary meteorological measurements program consisting of a primary system and secondary system (s) where necessary, and a nacxup system. Data collected from these systems are intenced for use in the assessment of the offsite consequences of a radiological emergency condition. Appendix 2 to NUREG-0654 delineates two classcs of assessment capabilities to provide input for the evaluation of offsite consequences 01 a radiological emergency condition. Both classes of capabilities provide input to decisions regarding emergency actions. The Class A capability should provide information to determine the necessity for notification, sheltering, evacuation, and, during the initial phase of a radiological emergency, maxing confirmatory radiological measurements. The Class B capability should provide information regarding the placement of supplemental meteorological monitoring equipment, and the need to make c.dditional confirmatory radiological m asurements. The Class B capability shall identify the areas 01 connai runted l proper.y and foodstuff requiring protective measures and may also provide information to determine the necessity for sheltering and evacuation. Proposed Revision 1 to Regulatory Guif.e 1.23 outlines the set of meteorological measurements that should be accessible from a system that can be interrogated; the meteorological data should be presented in the prescribed tormat. The results of the ( assessments should be acccasible from this system; this inrormation should incorporate human-factora engineering in its display to convey the essential information to the initial decision makers and subsequent management team. An integrated system should allow the eventual incorporation ot effluent monitoring and radiological monitoring information witn the environmental transport to provide direct dose consequence assessments. Requirements of the new emergency preparedness rules under paragraphs 50.47 and 5n.54 and the revised Appendix E to Part 50 taken together with NUREG-Ob54 kevision 1 and hDREG-069b, when dpproved for issuance, go beyOnd the previous requirements for l III.A.2-2 l

SNPS-1 FSAR meteorological programs. To provide a realistic time trame tor implementation, a staged schedule has been established with compensating actions provided for interim measures. LILCO Position The upgraded "Shorenam Nuclear Power Station t.nergency Plan, Section 13.3" addresses the NRC Position for this item. Please refer to this document which was submitted to the NRC via letter SNRC-568, dated May 27, 1981. l t I l III.A.2-3

SNPS-1 FSAR III.D.1.1 Primary Coolant Sources Outside the Containment Structure NRC Position Applicants shall implement a program to reduce leakage from systems outside containment that would or could contain highly radioactive fluids during a serious transient or accident to as-low-as-practical levels. This program shall include the following: Immediate leak reduction (a) Implement all practical leak reduction measures for all systems that could carry radioactive fluid outside of containment. (b) Measure actual leakage rates with system in operation and report them to the NRC. Continuing Leak Reduction -- Pstablish and implement a program of preventive maintenance to reduce leakage to as-low-as-practical levels. This program shall include periodic integrated leak tests at intervals not to exceed each refueling cycle. Applicants shall provide a summary description, together with initial leak-test results, of their program to reduce leakage from systems outside containment that would or could contain primary coolant or other highly radioactiva fluids or gases ~ during or following a serious transient or accident. Systems that should be leak tested are as follows (any other plant system which has similar functions or postaccident characteristice even though not specified

herein, should be included):

Residual heat removal (RHR) Containment spray recirculation High-pressure injection recirculation Containment and primary coolant sampling Reactor core isolation cooling Makeup and letdown (PWRs only) Waste gas (includes headers and cover gas system outside of containment in additon to decay or storage system) III.D.1.1-1

SNPS-1 FSAR Include a list of systems containing radioactive matt -ials which are excluded from program and provide justification for exclusion. Testing of gasenus systems should include helium leak detection or equivalent testing methods. Should consider program to reduce leakage potential release paths due to design and operator deficiencies as discusced in our letter to all operating nuclear power plants regarding North Anna and related incidents, dated October 17, 1979. LILCO Position A surveillance testing program, in accordance with 10CER50 Appendix J, " Reactor Containment Leakage Testing for Water Cooled Power Reactors", and the plant Technical Specifications, will be implemented at Shoreham. This testing program includes performance-of Type A tests to measure the overall integrated primary-containment leakage rates; Type B tests to detect and measure local leakage from certain containment penetrations and 3 components; and type C tests, to measure containment isolation i valve leakage rates. These tests will be performed during-preeperational testing and periodically at test intervals required by 10CFR50 Appi lix J. Periodic surveillance testing will be performed on items such an main steam isolation valves (MSIV) and air locks to maintain leakage within the allowable limits as specified in the plant's Technical Specifications. In addition, system hydrostatic tests, and inspections will be performed as required by ASME Section XI. During these

tests, appropriate corrective actions will be implemented as required.

Additional systems such as the MSIV leakage control system and the primary to secondary containment leakage detection and leakage return system have been incorporated in the plant design i in order to minimize and control leakage to the maximum extent possible. The MSIV leakage control system (MSIV-LCS) collets post LOCA leakage from the MSIV's to a maximum of 90 scfh for all main steam lines. This system may be manually actuated by the operator 20 min after an accident. The MSIV-LCS consists of physically separated redundant blowers which route any leakage from the closed MSIV's to areas served by the reactor building standby ventilation system (RBSVS). These blowers maintain the steam lines at a pressure slightly below atmospheric thus ( assuring that any leakage will be collected and processed by the [ RBSVS filters prior to release to the atmosphere. In order to further reduce the offsite dose contribution attributable to MSIV leakage, the collected effluent is discharged to the secondary containment which is used as a delay volume. Short-lived isotopes, such as I-133 and I-135, which constitute a significant fraction of the collected activity, are provided with additional III.D.l.1-2

i SNPS-1 FSAR time for decay prior to release. The effluent from ti s primary containment atmosphere control system is also dispersed within the secondary containment for the same reason. 4 The primary to secondary containment leakage detection and return system will assist in identifying and controlling post LOCA emergency core cooling systems (ECCS) leakage. Any abnormal leakage is detected by_a level switch in the el 8-0 floor drain sump which will actuate an alarm in the main control room at high sump level. In

addition, redundant safety related level detectors are provided on el 8-0, which will alarm in the control room when the floor water level (in the detector's area) exceeds approximately 1/2 in, corresponding to approximately 2,000 gal.

l The leakage return portion of the system consists of a self-priming leakage return pump with a capacity of 180 gpm which jacludes recirculation of 50 gpm. This pump will be manually started as required and will operate to return postulated ECCS leakage to the suppression pool. The pump will be powered from the emergency power supply and will be seismically qualified. The use of the leakage return system during post LOCA conditions will allow sufficient time for operator action to identify and isolate suspected leakage paths while continuing to maintain suppression pool water inventory and preventing excessive buildup of water on el 8-0 of the reactor building. Additional leakage detection measures to reduce and maintain leakage to as low as practical for systems outside primary containment that could contain highly radioactive fluids during a serious transient or accident are as follows: 1. The implementation of a periodic visual inspection program consisting of a combination of general inspections and detailed systen walkdown of liquid systems. These inspections shall be performed on accessible portions of applicable systems during system operational testing or by evaluation of leakage at lower j pressures during operation. ( 2. Systems containing gases are to be tested by use of tracer gases (helium, freon or DOP), by pressure decay j test eng or by_ metered makeup tests. 3. An aggressive maintenance program will be used to assign high priorities to leakage related Maintenance Work Requests (MWR's). l l 4. Preparation of systems

list, identifying specific I

methods used to test systems, the system

involved, and i

frequency of testing. 5. Records shall be maintained on the tests and inspections performed and leakage related MWR's. These records shall be used to identif1 chronic and generic leakage problems in order to implement modifications and/or III.D.l.1-3

b SNPS-1 FSAR corrective maintenance measures to keep leakage ac low as practical. l These measures will be implemented prior to full power operation. At that time, LILCO will submit to the NRC Stsff a report of all recorded leakage and all preventative maintenance performed as a direct result of the evaluation of this leakage. The report will also identify general leakage criteria to be applied during the first fuel cycle as the basis for instituting corrective action in the form of preventative maintenance. Prior to the start of the secord fuel cycle, LILCO will revise the general criteria-as necessary based on the experience gained during Shoreham's first fuel cycle. The revised criteria shall then be used as the basis for long term leakage monitoring activity at Shoreham, i J t i l III.D.l.1-4 4 ~ _}}