ML20050D519

Forwards Notes from 820323-26 Review Meetings at United Engineers Ofc in Philadelphia,Pa,To Assist in SER Preparation

ML20050D519
Person / Time
Site:	Seabrook
Issue date:	04/01/1982
From:	Devincentis J PUBLIC SERVICE CO. OF NEW HAMPSHIRE, YANKEE ATOMIC ELECTRIC CO.
To:	Stevens R Office of Nuclear Reactor Regulation
References
SBN-247, NUDOCS 8204120281
Download: ML20050D519 (100)

Text

{{#Wiki_filter:/ ~ .b SWROOK STATION Lj pusuC SEAVICE Engineering Office: Companyof NewHampshre 1671 Worcester Road Framinaham. Massachusetts 01701 (617) - 872 - 8100 April 1, 1982 Q O) SBN-247 ( Q T.F. B 7.1.2 gECEIyGO 9 9 ,ApRg United States Nuclear Regulatory Commission 9' A 12 Washington, D. C. 20555 9 / At t ent io n : Mr. Robert Stevens Instrumentation and Controls Systems Branch Division of En8 neering 1

References:

(a) Const ruction Permits CPPR-135 and CPPR-136, Docket Mas. 50-44 3 and 50-4 44 (b) USNRC Let ter, da ted Februa ry 16, 1982, " Request for Add i tiona l In f o rma t i o n, " F. J. Miraglia to W. C. Tallman Su bjec t : Meeting Notes; Inst rumenta t ion and Cont rols Systems Branch (ICSB)

Dear Sir:

We have attached notes from the March 23-26, 1982 ICSB review meetings conducted at the office of United Engineers (Philadelphia, PA). This meeting was based on the ICSB Requests for Additional Information which were forwarded i n Re f e re nce (b). These notes are provided to assist you in the preparation of the Safety Evaluation Report, as they highlight open issues, resolved issues, and commitment s which have been tendered. Future meet ings with ICSB will be conducted, as necessary, unt ti their review has been sat i s f ac torily completed. Ve ry t ruly yours, YANKEE ATOMIC, ELECTRIC COMPANY p r 1 9\\ ohn DeVincentis Project Manager cc-Mr. Lou i s Whee l e r, Project Manager Mr. Ralph Marback Licensing Branch No. 3 Argonne National Labs, Bldg. 301 Division of Licensin8 9700 S. Cass Argonne, IL 60439 0204120291 820401 PDR ADOCK 05000443 E PDR

420.5 As called for in Section 7.1 of the Standard Review Plan, provide (7.1) Information as to how your design conforms with the following TMI Action Plan Items as described in NUREG-0737: (a) II.D.3 - Relief and safety valve position indication, (b) II.E.1.2 - Auxiliary feedwater system automatic initiation flow indication, (c) II.E.4.2 - Containment isolation dependability (positions 4, 5 and 7), (d) II.F.1 - Accident monitoring instrumentation (positions 4, 5 and 6), (e) II.F.3 - Instrumentation for monitoring accident conditions (Regulatory Guide 1.97, Revision 2), (f) II.F.3 - Final recommendations .9 - PID controller .12 - Anticipatory reactor trip.

RESPONSE

(a) II.D.3 The single acoustic device to minitor all safety valves is not redundant but is safety grade. Limit switches for each PORV are not redundant but position indication is safety grade. Position indication system is seismically and environmentally qualified. There will be control room alarm for acoustical device and for either PORV not closed. There is backup temperature indication downstream of each safety valve and one temperature indication for both PORVs, all are alarmed in the control room. The FSAR will be revised. (b) II.E.1.2 Auxiliary feedwater system automatic initiation is safety grade. Flow indication meets Item 2a and b of II.E.1.2.5, NUREG-0737. (c) & (d) II.E.4.2 and II.F.1 will be handled by containment systems l branch. (e) II.F.3 will be covered by Regulatory Guide 1.97, Response 420.51. l (f) II.K.3.9 and.12, provided response in letter SBN-212, dated 2/12/82. Reviewed by staf f and found acceptable. 420.6 Provide an overview of the plant electrical distribution system, (7.1) with emphasis on vital buses and separation divisions, as background for addressing various Chapter 7 concerns. RES PONSE: Discussed at meeting, no further response required. 420.7 Describe features of the Seabrook environment control system which (7.1) insure that instrumentation sensing and sampling lines for systems important to safety are protected from freezing during extremely cold weather. Discuss the use of environmental monitoring and -

alarm systems to prevent loss of, or damage to systems important to safety upon f ailure of the environmental control system. Discuss electrical independence of the environmental control system circuits.

RESPONSE

Written response reviewed by the NRC and attached to meeting notes. We reviewed the freeze protection for the refueling water storage tank (RWST) after the meeting. It was determined that the instruments and sensing lines are in the building that encloses the RWST and is maintained above 320F by the heated RWST. Additional freeze protection is not required. RAI 440.112 is related. This item is under review by the staf f. RANDOUT: To ensure that instruments, including sensing and sampling lines, are protected from freezing during cold weather, electrical heat tracing is provided. Heat tracing on safety-related piping is protected by redundant, non-safety-related, heat tracing. On the boron injection line only, the primary heat tracing circuit is train A associated. The backup heat tracing circuit is train B associated. This backup circuit is normally de-energized. On the remaining lines, the redundant heat tracing circuit is energized from the same train as the primary circuit. Integrity of each circuit is continuously monitored. Low and high temperature alarms are available at the heat tracing system control cabinet. Additionally, failures as detailed below are indicated at the heat tracing control cabinet: a) Loss of voltage, b) Ground fault trip for each heating element circuit, c) Overload trip of branch circuit breakers, Trouble alarms are provided in the main control room. 420.8 Provide and describe the following for NSSS and BOP safety-related (7.1) setpoints: (a) Provide a reference for the methodology used. Discuss any dif ferences between the referenced methodology and the methodology used for Seabrook, (b) Verify that environmental error allowances are based on the highest value determined in qualification testing, (c) Document the environmental error allowance that is used for each reactor trip and engineered safeguards netpoint, i (d) Identify any time limits on environmental qualification of instruments used for trip, post-accident monitoring or engineered safety features actuation. Where instruments are qualified for only a limited time, specify the time and basis for the limited time.

RESPONSE

Seabrook uses the same methodology as W used for DC Cook, North Anna and Summer, there are no differences. DC Cook and North Anna were submitted and approved. This is applicable for both NSSS and BOP safety-related setpoints. WCAP 8587 and 8687 describe the determination of environmental error allowances. 420.9 There is an inconsistency between the discussions in FSAR l (7.1.2.5) Section 1.8 and FSAR Section 7.1.2.5 pertaining to the compliance with Regulatory Guide 1.22. FSAR Section 1.8 states that the main reactor coolant pump breakers are not tested at full power. FSAR Section 7.1.2.5 does not include these breakers in the list of equipment which cannot be tested at full power. Please provide a discussion as to whether the operation of the reactor coolant pump breakers is required for plant safety. If not, then please justify. Also, please correct the inconsistency described above and, as a minimum, provide a discussion per the recommendations of Regulatory Position D.4 of Regulatory Guide 1.22. RES PONSE: Revised 1.8 provided to staff and attached to meeting notes, reactor does not trip on opening of reactor coolant pump breakers. 420.10 Using detailed plant design drawings (schematics), discuss the (1.8) Seabrook design pertaining to bypassed and inoperable status (7.1.2.6) indication. As a minimum, provide information to describe: (7.5) 1. Compliance with the recommendations of Regulatory Guide 1.47, 2. The design philosophy used in the selection of equipment / systems to be monitored, 3. How the design of the bypass and inoperable status indication systems comply with Positions Bl through B6 of ICSB Branch Technical Position No. 21, and 4. The list of system automatic and manual bypasses within the BOP and NSSS scope of supply as it pertains to the recommendations of Regulatory Guide 1.47. The design philosophy should describe, as a minimum, the criteria to be employed in the display of inter-relationships and dependencies on equipment / systems and should insure that bypassing or deliberately induced inoperability of any auxiliary or support system will automatically indicate all safety systems affected.

RESPONSE

Handout given to staff. Overview of systems covered and description of operation given including automatic and manual modes, and interaction between systems. Handout as ammended during meeting will be attached to the meeting minutes. System description of computer and video alarm system (VAS) i presented during meeting and will be followed up by written l description to staff as response to RAI 420.49. A meeting will be held with the staf f in Washington at a later date to review all aspects of plant computer operation..

Staff presented concern that some guarantee must be considered as to percent of time computer will be operating and that plant will not continue to operate for any length of time, without appropriate corrective action, when and if computer should be out of service. A possible solution would be to refer operating and repair times to safety review committee although it is agreed that the computer is not a safety-related system. Staff asked for additional information concerning level of validation and verification of sof tware. HANDOUT: 1. Systems are designed to meet the recommendations of Regulatory Guide 1.47. 2. Design philosophy is discussed in FSAR Section 7.1.2.6. The selection of equipment is given in Item 4. 3. System design meets the recommendation of ICSB-21 as follows: B1 - Refer to FSAR Section 7.1.2.6(a). B2 - System design meets the requirements. Refer to logic diagrams listed in FSAR Section 7.1.2.6(f). B3 - Erroneous bypassed / inoperable alarm indications could be provided by any of the following: - dirty relay contacts - dirty limit switch contacts. B4 - The bypass indication system does not perform functions essential to safety. (Refer to FSAR Section 7.1.2.6) - A system design is supplemented by administrative procedures. The operator will not rely solely on the indication system. B5 - The indication system does not perform any safety-related functions and has no effect on plant safety systems. The indication system is located at the MCB separately for each train on system level basis. B6 - All bypass indicators and plant video annunciator systems are capable of being tested during normal system operation. 4. The list of the equipments for which bypass / inoperable alarms are provided. l Al - Service Water System (SW) I Service Equipment Logic Diagram Schematic Service Water Pumps SW-P-41A/41B M-503968 M-301107 Sh. AG3,AR3 -41C/41D M-503969 M-301107 Sh. AG4,AR4 Cooling Tower Pumps SW-P-110A M-503966 M-301107 Sh. AU2 -110B M-503967 M-301107 Sh. AU6 Cooling Tower Fans SW-FN-51A M-503951 M-301107 Sh. AV4 -51B M-503452 M-301107 Sh. AW4 Cooling Tower / Service M-503973 M-310951 EH9/EHO Water Bypass /Inop. A2 - Primary Component Cooling Water System (CC) Service Equipment Logic Diagram Schematic Primary Cooling Water Pumps CC-P-11A M-503270 M-310895 Sh. A58/A78 llB/ llc /11D A59,A79 PCCW Bypass Inop. M-503277 M-310951 EH9/EHO A3 - Containment Building Spray (CSB) Service Equipment Logic Diagram Schematic Containment Spray Pumps CBS-P-9A/9B M-503257 M-310900 Sh. A61,A81 Containment Sump Iso. V1v. CBS-V8/V14 M-503252 M-310900 Sh. B84,D40 Cont. Spray Add. Iso. Viv. CBS-V39/V44 M-503259 M-310900 Sh. 4b Cont. Spray Nozzle Iso. Vlv. CBS-V13/Vl9 M-503259 M-310900 Sh. 4b Service Equipment Logic Diagram Schematic Primary Comp. Cooling Water to Containment HX CC-V131/V260 M-503259 M-310895 Sh. 4a Prima ry Comp. Cooling Water M-503259 A4 - Residual Heat Removal (RH) Service Equipment Logic Diagram Schematic RH Cold Leg Inj. Iso. Vlv. RH-V14/26 M-503768/503769 M-310887 Sh. B57,B65 RH Hot Leg Inj. Iso. Vlv. RH-V32/70 M-503768/503769 M-310887 Sh. B58,D90 Chg. Pump Suc. Iso. V1v. RH-V35 M-503768/503763 M-310887 Sh. B59,B66 SI Pump Suc. Iso. Vlv. RH-36 M-503768/503763 M-310887 Cont. Sump Iso. Viv. CBS-V8/V14 M-503252 M-310900 Sh. B84,D40 Prim. Comp. Cooling Water to HX CC-V133/V258 M-503768 M-310895 Sh. 4A Residual Ht. Removal Pumps RH-P-BA/8B M-503761 M-310877 sh. A57,A77 _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

A5 - Safety Injection System (SI) Se rvice Equipment Logic Diagram Schematic SI Pumps SI-P-6A/ 6B M-503900 M-310890 Sh. A56/A76 Cont. Sump Iso. Valve CBS-V8/V14 M-503918 SI Cold Leg Iso. Valve SI-V114 M-503918 M-310890 Sh. B49 SI-P-CA-6B to Hot Legs Isolation Valve SI-V102/V77 SI-P-6A/6B to RWST Isolation Valve SI-V89/V90 M-503918 M-310890 Sh. B41/B42 SI-Pump Cross Connect SI-V111/V112 M-503918 M-310890 Sh. B47/B48 Prim. Comp. Cooling Wtr. M-503918 M-310895 Sh. EH9/3 EA A6 - Chemical and Volume Control System (CS) Service Equipment Logic Diagram Schematic Charging Pump CS-P-2A/ 2B M-503372,M-503330 M-310891 Sh. A62,A82 Prim. Comp. Cooling Wtr. M-503372 A7 - Feedwater (FW) Se rvice Equipment Logic Diagram Schematic Emer. Feedwater Pump FW-P-37B M-503586 M-310844 Sh. A80 Emer. FW Pump 37A/37B FW-V71/ 73 M-503599 M-310844 Sh. 4 Discharge and Bypass V1vs. FW-V65/65 M-503599 M-310844 Sh. 4 A8 - Diesel Generator (DG) Function Logic Diagram Schematic DG Containment Power Lost M-503495 M-310102 DG Breaker Containment Power Lost M-503495 M-310102 EPS Ctl. Power Lost M-503495 M-310102 A8 - Diesel Generator (DG) (Continued) Function Logic Diagram Schematic Prot. Relay Not Reset M-503495 M-310102 Barring Devices Engaged M-503495 M-310102 Starting Air Press. Lo-Lo M-503495 M-310102 Containment SW Pull to lock M-503495 M-310102 Control SW Maintenance M-503495 M-310102 B - Interrelationship Between Auxiliary Systems and Safety Systems Auxiliary systems such as service water system (SW) and primary component cooling water system (CC) have interrelationships and dependencies on the following safety systems. SI - Safety Injection j \\

RH - Residual Heat Removal System CBS - Containment Spray System CS - Chemical and Volume Control System Bypassed or inoperability of these auxiliary systems (SW, CC) would automatically indicate, both on the VAS and the system inoperative status monitoring lights, all safety systems which are affected. Reference logic drawings: M-503277 - M-503973 M-503259 - M-503768 M-503918 - M-503372 420.11 Summarize the status of those instrumentation and control items (7.1) discussed in the Safety Evaluation Report (and supplements) issued for the construction permit which required resolution during the operating license review.

RESPONSE

There are no unresolved items relating to Chapter 7 of the SAR identified in the construction permit SER (Supplements 1 to 4). 420.12 Various instrumentation and control system circuits in the plant (7.1.2.2) (including the reactor protection system, engineered safety features actuation system, instrument power supply distribution System) rely on certain devices to provide electrical isolation capability in order to maintain the independence between redundant safety circuits and between safety circuits and non-safety circuits. 1. Identify the type of isolation devices which are used as boundaries to isolate non-safety grade circuits from the safety grade circuite or to isolate redundant safety grade ci rcui t s. 2. Describe the acceptance criteria and tests performed for each isolation device which is identified in response to Part 1 above. This information should address results of analyses or tests performed to demonstrate proper isolation and should assure that the design does not compromise the required protective system function.

RESPONSE

1. BOP uses the same type W 7300 system, with the same qualifications, as is used by NSSS (NSSS equipment for Seabrook is identical to that for SNUPPS). 2. Radiation data management system will require submittal of further documentation of isolation devices used. 3. Power supply distribution isolation is covered under RAI 430.40A. 420.13 The discussion in Section 7.1.2.2 states that Westinghouse tests (7.1.2.2) on the Series 7300 PCS system covered in WCAP-8892 are considered (7.5.3.3) applicable to Seabrook. As a result of these tests, Westinghouse (7.7.2.1) has stated that the isolator output cables will be allowed to be routed with cables carrying voltages not exceeding 580 volts ac or 250 volts dc. The discussion of isolation devices in Section 7.5.3.3 of the FSAR, however, considered the maximum credible fault accidents of 118 volts ac or 140 volts de only. Also, the statement in Section 7.7.2.1 implies that the isolation devices were tested with 118 volts ac and 140 volts de only. In order to clarify the apparent inconsistency, provide the following: (a) Specify the type of isolation devices used for Seabrook process instrumentation system. If they are not the same as the Series 7300 PCS tested by Westinghouse, specify the f ault voltages for which they are rated and provide the supporting test results. (b) Provide information requested in (a) above for the isolation devices of the nuclear instrumentation system. As implied in WCAP-8892, the tests on Series 7300 PCS did not include the nuclear instrumentation system. (c) Describe what steps are taken to insure that the maximum credible fault voltages which could be postulated in Seabrook, as a result of BOP cable routing design, will not exceed those for which the isolation devices are qualified.

RESPONSE

The isolation devices used are as described in 420.12. Isolation device design is identical and has been qualified the same as for SNUPPS. The routing of cables leaving the cabinets is consistent with the interface criteria in WCAP 8892A. 420.14 The FSAR information provided describing the separation criteria (7.1.2.2) for instrument cabinets and the main control board is insufficient. Please discuss the separation criteria as it pertains to the design criteria of IEEE Standard 384-1977, Sections 5.6 and 5.7. Detailed drawings should be used to aid in verifying compliance with the separation criteria.

RESPONSE

Handout submitted to staff. Overview of main control board was presented using drawings and pictures. FSAR Sections 7.1.2.2 and 1.8 will be revised to be applicable to both balance of plant and NSSS control panels. The design criteria of IEEE Standard 384-1977, Sections 5.6 and 5.7 for the main control board and instrument cabinets has been met. HANDOUT: 1. Instrument Cabinets Section 5.7 of IEEE-384-1977 is met by having independent cabinets for redundant Class IE instruments, examples of this separation may be found on instrument cabinets MM-CP-152A and MM-CP-152B, both located in the main control room, control building Elevation 75'-0"..

2. Main Control Board (MCB) Sections 5.6.1 through 5.6.6 of IEEE-384-1977 are met as follows, and as described in UE&C Specification 9763-006-170-1, Revision 5: (a) Section 5.6.1 - The main control board, seismically qualified by analysis and testing per UE&C Specifications 9763-006-170-1 Revision 5, and 9763-SD-170-1, Revision 0, is located in the main control room of the Seabrook station control building (Elevation 75'-0") which is a Seismic Category I structure. (b) Sections 5.6.2 through 5.6.6 - MCB Zone "B" (front contains the low pressure safety injection; rear contains miscellaneous systems like steam generator blowdown, heat removal, spent fuel) will be used to describe compliance with above referenced sections of IEEE-384-1977. UE&C drawings 9763-F-510102 Revision 6, 9763-F-510115 Revision 4 and 9763-F-510116 Revision 4 could be used to ascertain the compliance with the standard. b.1 Internal Separation (5.6.2) - the front section of Zone B is divided into Class 1E train "A" (and it's associated non-Class 1E circuits train "AA") on the left-hand side, separated from the Class lE train "B" (and it's associated non-Class lE circuits train "RA") by a full size top-to-bottom steel barrier. However, due to process requirements there are instruments of the opposite

train, "B",

on the train "A" side; they are separated by a steel enclosure fully surrounding the instrument or open at the rear af ter a depth 6" deeper than the instrument itself. The rear section of Zone B is all Class lE train "A" or it's associated non-Class 1E circuit train "AA". Again, as in the f ront section due to ] process requirements, there are instruments of the opposite train which are separted by a steel enclosure in the same fashion as in the front section. Refer to next Item, b.2, for wiring separation. b.2 Internal Wiring Identification (5.6.3) - All j wiring within each section is identified by different jacket colors, as follows: Class lE train "A" - red 0 Class 1E train "B" - white Non-Class 1E train "AA" - black with red stripe Non Class 1E train "BA" - black with white stripe Each wire / cable insulation is qualified to be flame retardant per either IPCEA-S-19-81 (NEMA WC3) paragraph 6.13.2 or UL-44 Section 85 or IEEE Standard-383 Section 2.5. In addition, all wiring within each section is run in covered wireways formed from solid or punched sheet steel. Minimum wire bundles were allowed where it was physically impossible to install wireways or where it would have been hazardous to the operator / maintenance personnel. Class IE and Non-Class 1E wiring of the same train are run in the same wireway. The wireways were further identified with red "A" or white "B" to depict the train assignment of the wire being run within the particular wireway. b.3 Common Terminations (5.6.4) - No common terminations were allowed in the MCB. b.4 Non-Class IE Wiring (5.6.5) - Class 1E and Non-Class 1E associated circuits wiring of the same train are run together in the same metallic wireway but are separated by specific identifying jacket colors as described above (b.2). b.5 Cable Entrance (5.6.6) - Field cables to be terminated on the MCB terminal blocks are routed in train assigned raceways through the cable spreading room which is located directly under the main control room (refer to UE&C Drawing 9763-F-500091, Revision 6). The raceways run all the way up to the floor slots of the same assigned train located in the floor right underneath the MCB. (The floor slots location and train assignment are shown on UE&C Drawings 9763-F-500100 Revision 6, 9763-F-101347 Revision 5 and 9763-F-310432 Revision 8). 420.15 Identify all plant safety-related systems, or portions thereof, (7.1) for which the design is incomplete at this time.

RESPONSE

The design of all safety-related systems has been completed. The design details associated with procurement and installation are on going in accordance with the project schedule. 420.16 Identify where microprocessors, multiplexers, or computer systems (7.1) are used in or interf ace with safety-related systems. RES PONSE: NSSS does not use microprocessors, multiplexers or computers in or to interface with safety-related systems (multiplexors are used for information transmission). The radiation data management uses microprocessors and computers. Detailed descriptions on how the system works will be submitted later. 420.17 The FSAR information which discusses conformance to Regulatory (7.1) Guide 1.118 and IEEE-338 is insufficient. Further discussion is (7.2) required. As a minimum, provide the following information: (7.3) (1.8) 1. Confirm that the Technical Specifications will provide detailed requirements for the operator which insure that blocking of a selected protection function actuator circuit is returned to normal operation after testing. 2. Discuss response time testing of BOP and NSSS protection systems using the design criteria described in Position C.12 or Regulatory Guide 1.118 and Section 6.3.4 of IEEE 338. Confirm that the response time testing will be provided in the Technical Specifications. 3. The FSAR states that, " Temporary jumper wires, temporary test instrumentation, the removal of fuses and other equipment not hard-wired into the protection system will be used where applicable". Identify where procedures require such operation. Provide further discussion to describe how the Seabrook test procedures for the protection systems conform to Regulatory Guide 1.118 (Revision 1) Position C.14 guidelines. Identify and justify any exceptions. 4. Confirm that the Technical Specifications will include the RPS and ESFAS response times for reactor trip functions. 5. Confirm that the Technical Specifications will include response time testing of all protection system components, from the sensor to operation of the final actuation device. 6. Provide an example and description of a typical response time test.

RESPONSE

Handout was distributed and found acceptable with changes discussed during meeting. The revised handout is included in the meeting minutes. HANDOUT: 1. Technical Specification Tables 3.3-1 reactor trip system, 3.3-3 engineered safety features actuation, and 3.3-5 reactor trip /ESF actuation system interlocks, provide the operator with the minimum operable channel criteria and the appropriate action statement. 2. BOP and NSSS protection system time response tests will be conducted in accordance with Regulatory Guide 1.118 Revision 1, IEEE-338-1975, ISA dS67-06, and draf t Regulatory Guide Task IC 121-5, January,1982, with the following exceptions and positions: (a) Task IC 121-5 Regulatory Position Cl states that the term " nuclear safety-related instrument channels in nuclear power plants" should be understood to mean instrument channels in protection systems. (b) Response time testing will be performed only on those channels having a limiting response time established and credited in the safety analysis. (c) The revised discussion of Regulatory Guide 1.118 in FSAR Section 1.8 (copy attached). Response time testing is specified in Tables 3.3-2 and 3.3-4. 3. It is not anticipated that any Seabrook test procedures performed on protection systems will require the use of temporary jumpers, lif ted wires or pulled fuses. All procedures will, in fact, utilize the hard-wired test points within the system and therefore, comply with Regulatory Guide 1.118, Revision 1, Position C14. If during plant operation, conditions or test requirements show that deviation from this guide is the only practical method of obtaining the desired test results, then all affected testing will be performed and documented under the control of a special test procedure. We will inform ICSB, prior to licensing, of any temporary modifications identified during preparation of the surveillance procedures. 4. Response times are specified in Tables 3.3-2 and 3.3-4. 5. Compliance with Regulatory Guide 1.118, Revision 1 IEEE-338-1975, and ISA dS67-06 ensures that the complete channel is tested with the exception noted on Table 3.3-2 of Seabrook Technical Specifications. 6. Response time tests have not yet been prepared. Test methods to be employed are outlined below: Pressure Sensors The process variable will be substituted by a hydraulic ramp, the ramp rate to be selected based on the transient for which the sensor is required to respond. In the event that the sensor is required to respond to more than one transient, the ramp rates will be selected to represent the fastest and slowest transients. Temperature Sensors Will be tested in place using the loop current step response (LCSR) method. See NUREG-0809. Impulse Lines Tests will be conducted during the startup testing phase to establish the relationship between response time and impulse line flow, subsequent tests will be limited to flow testing. Electronic Channel The signal conditioning and logic section of the instrument channel will be tested by inputting a step change at the input of the process racks, and measuring the time required until the final device in the channel actuates. 420.18 It is stated in FSAR Section 7.1.2.11 that, "A periodic (7.1.2.11) verification test program for sensors within the Westinghouse scope for determining any deterioration of installed sensor's response time, is being sought". NUREG-0809, " Review of Resistance Temperature Detector Time Response Characteristics", and draf t Standard ISA-dS67.06, " Response Time Testing of Nuclear Safety-Related Instrument Channels in Nuclear Power Plants", are documents which propose acceptable methods for response time testing nuclear safety-related instrument channels. Please provide further discussion on this matter to unequivocally indicate the test methods to be used for Seabrook.

RESPONSE

See our Response to 420.17 for a discussion of the proposed response time testing program. The referenced portion of 7.1.2.11 will be deleted (see attached copy). 420.19 FSAR Section 7.1.1 does not provide suf ficient information to (7.1.1.1) distinguish between those systems designed and built by the nuclear steam system supplier and those designed or built by others. Please provide more detailed information.

RESPONSE

Draft revision of FSAR 7.1.1 provided to staff and found acceptable and is attached to the meeting notes. 420.20 Section 7.1.2.7 of the FSAR discusses conformance to Regulatory (7.1.2.7) Guide 1.53 and IEEE Standard 379-1972. The information provided addresses only Westinghouse provided equipment and associated topical reports. Provide a conformance discussion that addresses the BOP portions of the plant safety systems and auxiliary systems required for support of safety systems.

RESPONSE

FSAR has been revised to cover single failure criteria for BOP and NSSS and is attached to the meeting minutes. 420.21 The information in Section 7.2.1.1.b.6, " Reactor Trip on Turbine (7.2.1.1) Trip", is insufficient. Please provide further design bases discussion on this subject per BTP ICSB 26 requirements. As a minimum you should: 1. Using detailed drawings, describe the routing and separation for this trip circuitry from the sensor in the turbine building to the final actuation in the reactor trip system (RTS).,

2. Discuss how the routing within the non-seismic Category I turbine building is such that the effects of credible faults or failures in this area on these circuits will not challenge the reactor trip system and thus degrade the RTS perf ormance. This should include a discussion of isolation devices. 3. Describe the power supply arrangement for the reactor trip on turbine trip circuitry. 4. Provide discussion on your proposal to use permissive P-9 (50% power). 5. Discuss the testing planned for the reactor trip on turbine trip circuitry. Identify any other sensors or circuits used to provide input signals to the protection system or perform a function required for safety which are located or routed through non-seismically qualified structures. This should include sensors or circuits providing input for reactor trip, emergency safeguards equipment such as auxiliary feedwater system and safety grade inerlocks. Verification should be provided to show that such sensors and circuits meet IEEE-279 and are scismically and environmentally qualified. Identif y the testing or analyses performed which insures that failures of non-seismic structures, mountings, etc. will not cause failures which could interfere with the operation of any other portion of the protection system.

RESPONSE

Add to the SNUPPS response to " Reactor Trip on Turbine Trip" that circuits and sensors used in a non-seismic structure are Class 1E and are run in separate conduits meeting Regulatory Guide 1.75 with the exception of seismic qualification. Hydraulic pressure and limit switches on the turbine stop valves are two examples. the response will be attached to the meeting minutes. Permissive P-9 has an adjustable setpoint between 10 - 50%. Reactor trip on turbine trip circuitry is testable at power. The turbine impulse chamber pressure transmitters are Class 1E and routed as Class lE, with the seismic exception. There are no other safety-grade sensors routed through non-seismic The only safety-related outputs in non-seismic areas are areas. signals to close the feedwater control valves, close the condenser dump valves and trip the turbine generator. These circuits are designed as described above. MANDOUT: Revised SNUPPS Submittal Evaluations indicate that the functional perf ormance of the protection system would not be degraded by credible electrical faults such as opens and shorts in the circuits associated with -

reactor trip or the generation of the P-7 interlock. The contacts of redundant sensors on the steam stop valves and the trip fluid pressure system are connected through the grounded side of the ac ) supply circuits in the solid state protection system. A ground fault would therefore produce no fault current. Loss of signal caused by open circuits would produce either a partial or a full reactor trip. Faults on the first stage turbine pressure circuits would result in upscale, conservative, output for open circuits and a sustained current, limited by circuit resistance, for short circuit s. Multiple failures imposed on these redundant circuits could potentially disable the P-13 interlock. In this event, the nuclear instrumentation power range signals would provide the P-7 j safety interlock. Refer to Functional Diagram, Sheet 4 of Figure 7.2-1. The sensing devices conform to the requirements applying to turbine mounted equipment cennected to the protection system. The electrical and physical independence of connection cabling conforms to the requirements of FSAR Appendix 8A. 420.22 FSAR Section 7.2.1.1.b.8 states that, "The manual trip consists of (7.2.1.1) two switches with two outputs on each switch. One output is used to actuate the train A reactor trip breaker, the other output actuates the train B reactor trip breaker." Please describe how this design satisfies the single failure criterion and separation requirements for redundant trains.

RESPONSE

Manual trip design is identical to SNUPPS, Watts Bar, Byron-Braidwood. Drawing was reviewed and found acceptable. 420.23 Describe how the effects of high temperatures in reference legs of (7.2) steam generator and pressurizer water level measuring instruments subsequent to high energy breaks are evaluated and compensated for in determining setpoints. Identify and describe any modifications planned or taken in response to IEB 79-21. Also, describe the level measurement errors due to environmental temperature effects on other level instruments using reference legs. RES PONSE : The steam generator level transmitter reference legs will be insulated to prevent excessive heating under accident conditions. Setpoints will include errors for high energy line breaks with the insulation. For the pressurizer level, we will review SNUPPS report and determine applicablity to Seabrook. 420.24 State whether all of the systems discussed in Sections 7.2, 7.3, (7.2) 7.4 and 7.6 of the FSAR conform to the recommendations of (7.3) Regulatory Guide 1.62 concerning manual initiation. Identify (7.4) any exceptions and discuss how they do not conform to the (7.6) recommendations. Provide justification for nonconformance areas. ( RES PONSE : Systems discussed in Sections 7.2, 7.3, 7.4 and 7.6 of the FSAR conform to the recommendations of Regulatory Guide 1.62 concerning manual initiation. There are no exceptions taken. 420.25 The information provided in Section 7.2.2.2.c.10.(b) on testing (7.2.2.2) of the power range channels of the nuclear instrumentation system, covers only the testing of the high neutron flux trips. Testing of the high neutron flux rate trips is not included. Provide a description of how the flux rate circuitry is tested periodically to verify its performance capability.

RESPONSE

The power range nuclear instrumentation system and all associated bistables including the rate trips are testable at power. 420.26 Identif y where instrument sensors or transmitters supplying (7.2) information to more than one protection channel are located in a (7.3) common instrument line or connected to a common instrument tap. The intent of this item is to verify that a single failure in a common instrument line or tap (such as break or blockage) cannot defeat required protection system redundancy.

RESPONSE

Identical to SNUPPS except we do not share taps for pressurizer pressure. There are no shared taps for redundant BOP safety instruments. 420.27 If safety equipment does not remain in its emergency mode upon (7.3) reset of an engineered safeguards actuation signal, system modification, design change or other corrective action should be planned to assure that protective action of the affected equipment is not compromised once the associated actuation signal is reset. This issue is addressed by I6E Bulletin 80-06. Please provide a discussion addressing the concerns of the above bulletin. This discussion should assure that you have reviewed the Seabrook design per each of the I&E Bulletin 80-06 concerns. Results of your review should be given.

RESPONSE

We have reviewed the electrical schematics for engineered safety feature (ESF) reset controls. In the Seabrook design, all systems serving safety-related functions remain in the emergency mode upon removal of the actuating signal and/or manual resetting of ESF actuation signals. The required testing (per 80-06) will be performed as part of the start-up test program described in Chapter 14. 420.28 The description of the emergency safety feature systems which is (7.3.1.1) provided in the FSAR Section 7.3.1.1 is incomplete in that it does not provide all of the information which is requested in Section 7.3.1 of the standard format for those safety-related systems, interfaces and components which are supplied by the applicant and mate with the systems which are within the Westinghouse scope of supply. Provide all of the descriptive and design basis information which is requested in the standard format for these systems. In addition, provide the results of an analysis, as is requested in Section 7.3.2 of the standard format, which demonstrates how the requirements of the general design criteria and IEEE Standard 279-1971 are satisfied and the extent to which the recommendations of the applicable Regulatory Guide are satisfied. Identify and justify any exceptions.

RESPONSE

Tables supplied in response to 420.32 and the additional information to be supplied when answering 420.29 will satisfy the requirementa of this question. 420.29 Confirm that the FMEA referenced in FSAR Section 7.3.2.1: (1) is (7.3.2.1) applicable to all engineered safety features equipment within the BOP and NSSS scope of supply, and (2) is applicable to design changes subsequent to the design analyzed in the referenced WCAP.

RESPONSE

Discussion of this item was deferred to the next meeting. 420.30 Section 7.3.2.2 of the FSAR indicates that conformance to (7.3) Regulatory Guide 1.22 is discussed in Section 7.1.2.8.

However, Section 7.1.2.8 addresses Regulatory Guide 1.63.

Correct this discrepancy.

RESPONSE

The reference to Section 7.1.2.8 will be changed in Amendment 45 to Section 7.1.2.5 where Regulatory Guide 1.22 is addressed. 420.31 Using detailed drawings, discuss the automatic and manual operation (7.3.2.2) of the containment spray system including control of the chemical additive system. Discuss how testing of the containment spray system conforms to the recommendations of Regulatory Guide 1.22 and the requirements of BTB ICSB 22. Include in your discussion the tests to be performed for the final actuation devices.

RESPONSE

Draft of response submitted to staff. Overview of containment spray system was presented using drawings. System description and operation were reviewed. Staff questioned redundancy of temperature system. Tank temperature is monitored by a temperature indicating switch that actuates a VAS alarm and by an independent temperature indicating controller that controls auxiliary steam to the tank. Fluid systems are totally separable into trains "A" and "B". The electrical systems are also completely separable into trains "A" and "B" as per the piping systems. Provisions are available for on-line testing of CBS system as described in FSAR 7.3.2.2. The assignment of components to slave relays for on-line testing is indicated in the ESF table in the response to 420.32. 420.32 Please provide a table (s) listing the components actuated by the (7.3) engineered safety features actuation system. As a minimum, th< table should include: 1. Action required, 2. Component description, 3. Identification number, 4. Actuation signal and channel.

RESPONSE

Tables supplied at the meeting are attached. 420.33 Section 7.3.2.2.e.12 discusses testing during shutdown. De scribe (7.3.2.2) provisions for insuring that the " isolation valves" discussed here are returned to their normal operating positions af ter test.

RESPONSE

Administrative controls to ensure that equipment and systems are restored to normal af ter testing will be addressed in equipment contrcl procedures that follow the guidance of ANS 18.7, 1976. The system inoperative status monitoring panel will be manually actuated when a system is made inoperative. 420.34 Portions of paragraph 7.3.1.2.f, appear not to apply to ESFAS (7.3) response times. In particular, the discussion on reactor trip breakers, latching mechanisms, etc., should be replaced by a discussion of ESF equipment time responses. The applicant should provide a revised discussion for ESFAS (a) defining specific beginning and end points for which the quoted times apply, and (b) relating these times to the total delay for all equipment and to the accident analysis requirements.

RESPONSE

FSAR 7.3.1.2.f will be revised as indicated on the attached markup. 420.35 Using detailed drawings, describe the ventilation systems used to (7.2 & 7.4) support engineered safety features areas including areas containing systems required for safety shutdown. Discuss the design bases for these systems including redundancy, testability, etc.

RESPONSE

Overview given at meeting on HVAC system for control room. Equipment for system is redundant and safety grade. The HVAC instrumentation and control required for safety-related equipment is Class lE and trains "A" and "B" oriented. Radiation detectors f or intake air are redundant and safety related. Other systems in the control building are redundant and safety related. Control of safety-related HVAC systems are operated from the control room and those systems required for remote safe shutdown also have local control. The control room outside air intake lines are shared between Units 1 and 2. Each unit has its own controls and isolation valves. 420.36 Using detailed system schematics, describe how the Seabrook (7.3.2.3) auxiliary feedwater system meets the requirements of NUREG-0737, TMI Action Plan Item II.E.1.2 (See question 420.01). Be sure to include the following information in the discussion: a) the effects of all switch positions on system operation. b) the effects of single power supply failures including the effect of a power supply failure on auxiliary feedwater control af ter automatic initiation circuits have been reset in a post-accident sequence. c) any bypasses within the system including the means by which it is insured that the bypasses are removed. i 1 d) initiation and annunciation of any interlocks or automatic isolations that could degrade system capability. e) the safety classification and design criteria for any air systems required by the auxiliary feedwater system. This should include the design bases for the capacity of air reservoirs required for system operation. t l f) design features provided to terminate auxiliary feedwater flow to a steam generator affected by either a steam line or feed line break. g) system features associated with shutdown from outside the control room.

RESPONSE

Overview of emergency feedwater system was presented to staff using drawings for description of system operation. Emergency feedwater system was discussed with staf f and it is considered an open item. Significant concerns identified: a) Lack of safety-grade air system. b) Single failure in pneumatic control valve. c) Loss of one train of power while operating from remote safe shutdown panel. d) On-off control of the EFW control valves. 420.37 Using detailed system schematics, describe the sequence for (7.3) periodic testing of the: a) main steam line isolation valves b) main feedwater control valves c) main feedwater isolation valves d) auxiliary feedwater system e) steam generator relief valves f) pressurizer PORV The discussion should include features used to insure the availability of the safety function during test and measures taken to insure that equipment cannot be lef t in a bypassed condition af ter test completion.

RESPONSE

Periodic testing was discussed using detailed drawings. Significant discussion items are: a) To be presented at next meeting. _

b) Standard Westinghouse testing system used. c) When testing main feedwater control and main feedwater isolation valves using train "A", the system for train "B" remains completely operable. d) During testing of emergency feedwater pumps the discharge valve is closed and recirculation valve opened. The system inoperable indication is in accordance with Regulatory Guide 1.47. During testing, the capability exists to test the entire ESFAS as including actuation of the EFW pump. e) Discussed with no comments. f) Discussed with no comments. 420.38 The information supplied in FSAR Section 7.4.1 does not adequately (7.4.1) describe the systems required for safe shutdown as required by Section 7.4.1 of the standard format. Therefore, provide all the descriptive and design basis information which is requested by Section 7.4.1 of the standard format. Also, provide the results of an analysis, as requested by Section 7.4.2 of the standard format, which demonstrates how the requirements of the general design criteria and IEEE Std. 279-1971 are satisfied and the extent to which the recommendations of the applicable regulatory guides are satisfied. Identify and justify any exceptions.

RESPONSE

Staff to review handouts presented at this meeting and come back with any further questions. Update list for 420.39 and submit with minutes. YAEC given written position on safe shutdown, to be forwarded formally. Rewritten FSAR 7.4 is attached. 420.39 The information supplied for remote shutdown from outside the control room is insufficient. Therefore, provide further discussion to describe the capability of achieving hot or cold shutdown from outside the control room. As a minimum, provide the following information: a. Provide a table listing the controls and display instrumentation required for hot and cold shutdown from outside the control room. Identify the safety classification and train assignments for the safety-related equipment. b. Design basis for selection of instrumentation and control equipment on the hot shutdown panel. c. Location of transfer switches and remote control station (include layout drawings, etc.). d. Design criteria for the remote control station equipment including transfer switches. e. Description of distinct control features to both restrict and to assure access, when necessary, to the displays and controls located outside the control room. i f. Discuss the testing to be performed during plant operation to verify the capability of maintaining the plant in a safe shutdown condition from outside the control room. g. Description of isolation, separation and transfer / override provisions. This should include the design basis for preventing electrical interaction between the control room and remote shutdown equipment. h. Description of any communication systems required to coordinate operator actions, including redundancy and separation. 1. Description of control room annunciation of remote control or overridden status of devices under local control. j. Means for ensuring that cold shutdown can be accomplished. k. Explain the footnote in FSAR Section 7.4.1.4 which states that, " Instrumentation and controls for these systems may require some modification in order that their functions may be performed from outside the control room". Discuss the modifications required on the instrumentation and controls of the pressurizer pressure control including opening control for pressurizer relief valves, heaters and spray and the nuclear instrumentation that are necessary to shutdown the plant from outside the control room. Also discuss the means of defeating the safety injection signal trip circuit and closing the accumulator isolation valves when achieving cold shutdown.

RESPONSE

See 420.38. HANDOUT: a) Table is attached. b) See response to Item 440.13 (attached). c) Transfer switches are at the same location as the controls. d) Controls are the same safety classification as the controls in the control room. Instrumentation is not safety-related. e) The controls are located in areas that are controlled by the security system. The transfer switches are key-locked. f) Verification of the capability of maintaining the plant in a safe shutdown condition from outside control room will be in accordance with commitment in Chapter 14, Table 14.2-5, Item 33. Reactor coolant pumps will not be tripped for this test. Verification of natural circulation will be in accordance with commitment in Chapter 14, Table 14.2-5, Item 22. g) Isolation is discussed in FSAR 7.4.11. _ __

h) See response to 430.67 (attached). 1) Any switch that is in the local position is alarmed by the VAS. j) See Items a and b. k) The footnote has been deleted. See rewritten 7.4 submitted in 420.38. 420.40 Concerning safe shutdown from outside the control room, discuss the likelihood that the auxiliary feedwater system will be automatically initiated on low-low steam generator level following a manual reactor trip and describe the capability of resetting the initiating logic from outside the control room. Describe the method of controlling auxiliary feedwater from outside the control room.

RESPONSE

Even though the emergency feedwater system may be automatically initiated as the main control room is evacuated, the emergency feedwater system can be controlled from the remote safe shutdown panel. Additional information required by staff is furnished in the response to 420.38 and 420.39. 420.41 Subsection 7.4.2 states that, "The results of the analysis which (7.4.2) determined the applicability to the Nuclear Steam Supply System safe shutdown systems of the NRC General Design Criteria, IEEE S tanda rd 279-1971, applicable NRC Regulatory Guides and other industry standards are presented in Table 7.1-1". This statement does not address the balance of plant (BOP) safe shutdown systems. Also, sufficient information giving results of the analysis perf ormed for safe shutdown systems cannot be found f rom Table 7.1-1. Therefore, provide the results and a detailed discussion of how the BOP and NSSS systems required for safe shutdown meet GDCs 13, 19, 34, 35, and 38; IEEE Standard 279 requirements; Regulatory Guides 1. 2 2, 1. 4 7, 1. 5 3, 1. 6 8, a nd 1. 7 5. Be sure that you include a discussion of how the remote shutdown station complies with the above design criteria. RES PONSE: Closely related to Items 38 and 39. Staff will review to see if more response is required. 420.42 FSAR Section 7.4.2 states that, "It is shown by these analyses, (7.4.2) that safety is not adversely affected by these incidents, with the associated assumptions being that the instrumentation and controls indicated in Subsections 7.4.1.1 and 7.4.1.2 are available to control and/or monitor shutdown". Please provide a discussion pertaining to the phrase " associated assumptions". Your discussion should address loss of offsite power associated with plant load rejection or turbine trip. RESPONSE : Covered in the response to 420.38. 420.43 Please discuss how a single failure within the station service (7.4.2) water system and/or the primary component cooling water system affects safe shutdown.

RESPONSE

Each of the independent and redundant flow trains of the station service water system and the primary component cooling water system is capable of performing their safety functions necessary to effect a safe shutdown assuming a single failure. See Sections 9.2.1, 9.2.2 and 9.2.5 for further details. 420.44 Using detailed electrical schematics and logic diagrams, discuss (9.2.5.5) the tower actuation (TA) signal which is generated to isolate the normal service water system and initiate the cooling tower system. Be sure to include in your discussion the possibilities of inadvertent switchover (loss of offsite power, etc.) and the affects this would have.

RESPONSE

The tower actuation circuit is being revised. The revised drawings will be submitted for review. 420.45 FSAR Section 7.4.2 states that, " Loss of plant air systems will not (7.4.2) inhibit ability to reach safe shutdown from outside the control room". Using detailed drawings, please provide further discussion on this matter. Clearly indicate any function required to reach safe shutdown from outside the control room which is dependent on air and the means by which the air is provided.

RESPONSE

Instrument air system is redundant, piping is safety grade and seismically supported but appropriate safety grade compressor has not been located. Critical to define how long system can operate from accumulator tanks. Staff questioned atmospheric relief valve as to safety classification - valve itself is safety grade but control system is not. This item is still open. 420.46 Describe the procedures to borate the primary coolant from outside (7.4) the control room when the main control room is inaccessible. How much time is there to do this?

RESPONSE

Handout given to NRC. Staff questioned if MOV's and controls mentioned are safety grade. Items are safety grade. If problem exists during review, it will be covered under overall discussion of shutdown. " Adequate time" mentioned in response is minimum of f our hours. HANDOUT: Boration of the primary coolant will require an alignment of the suction of charging pumps from the refueling water storage tank (RWST) to the boric acid storage tank (BAST). This will be required once the plant starts its cooldown. The gravity feed from the BAST to the suction of the charging pumps contains manual isolation valves located in the primary auxiliary building. The RWST suction valves contain motor-operated valves (MOV) that can be controlled from the motor control center in the switchgear. If need be, the MOV's can be operated locally. There is adequate time for an operator to follow the procedure since the plant is in a safe hot shutdown condition. 420.47 Using detailed drawings (schematics, P&lDs'), describe the (7.4) automatic and manual operation and control of the atmospheric._ _

relief valves. Describe how the design complies with the requirements of IEEE-279 (i.e., testability, single failure, redundancy, indication of operability, direct valve position, indication in control room, etc.).

RESPONSE

Operation of these valves from a remote location is not considered a safety-related function; therefore, they are not designed to meet IEEE-279. Overview of operation given at meeting. Item still under review by staff and considered open. 420.48 Using detailed electrical schematics and piping diagrams, please (7.4.2) discuss the automatic and manual operation and control of the (7.3) station service water system and the component cooling water system. Be sure to discuss interlocks, automatic switchover, testability, single f ailure, channel independence, indication of operability, isolation functions, etc.

RESPONSE

Reviewed system design and operation from drawings and schematics. Staff will review isolation of non-seismic portion of service water system during earthquake without another accident. 420.49 The information supplied in FSAR Section 7.5 concentrates on the (7.5) post accident monitoring instrumentation and does not provide sufficient information to describe safety related display instrumentation needed for all operating conditions. Therefore, please expand the FSAR to provide as a minimum additional information on the following: 1. ESF Systems Monitoring 2. ESF Support Systems Monitoring 3. Reactor Protective System Monitoring 4. Rod Position Indication System 5. Plant Process Display Instrumentation 6. Control Boards and Annunciators 7. Bypass and Inoperable Status Indication 8. Control Room Habitability Instrumentation 9. Residual Heat Removal Instrumentation Please use drawings as necessary during your discussion.

RESPONSE

All except Item 6 will be covered in response to Regulatory Guide 1.97. Summary of VAS and annunciator system will be provided. 420.50 If reactor controls and vital instruments derive power f rom common (7.5) electrical distribution systems, the failure of such electrical distribution systems may result in an event requiring operator action concurrent with f ailure of important instrumentation upon which these operator actions should be based. IE Bulletin 79-27 addresses several concerns related to the above subject. You are requested to provide inf ormation and a discussion based on each IE Bulletin 79-27 concern. Also, you are to: 1. Confirm that all a.c. and d.c. instrument buses that could affect the ability to achieve a cold shutdown condition were reviewed. Identify these buses. 2. Confirm that all instrumentation and controls required by emergency shutdown procedures were considered in the review. Identify these instruments and controls at the system level of detail. 3. Confirm that clear, simple, unambiguous annunciation of loss of power is provided in the control room for each bus addressed in item 1 above. Identify any exceptions. 4. Confirm that the effect of loss of power to each load on each bus identified in item 1 above, including ebility to reach cold shutdown, was considered in the review. 5. Confirm that the re-review of IE Circular No. 79-02 which is required by Action Item 3 of Bulletin 79-27 was extended to include both Class 1E and Non-Class lE inverter supplied instrument or control buses. Identify these buses or confirm that they are included in the listing required by Item 1 above.

RESPONSE

Refer to the attached response to IE Bulletin 79-27 and two attached responses to IE Circular 79-02. 1. All ac and de instrument buses were reviewed, without regard to their importance for shutdown. Refer to the listing of buses reviewed in the attached response to Bulletin 79-27. 2. A list of instrumentation and controls required by emergency shutdown procedures (Remote Safe Shutdown) will be included in the report "10 CFR 50, Appendix R; Fire Protection of Safe Shutdown Capability". No separate review of instrumentation and controls normally used for a control room shutdown has been planned. 3. Annunciation of loss of power is provided in the main control room through Seabrook video alarm system. The wording of all alarms is subject to review by the station operating staff to insure clarity. 4. The effect of loss of power to each load (instrument or control system) required for remote safe shutdown will be considered in the review of the fire protection of safe shutdown capability. 5. Refer to the two attached responses to Circular 79-02. The buses are listed in the response to Bulletin 79-27..

420.51 Table 7.1-1 indicates that conformance to R.G. 1.97 is discussed (7.5) in Section 7.5.3.2. However, Section 7.5.3.2 is a section of definitions only. We find partial discussion on conformance in Section 7.5.3.1. Correct Table 7.1-1. Also, FSAR Section 1.8 states that Regulatory Guide 1.97, Revision 2, is presently being reviewed and the extent of compliance will be addressed at a later date. Discuss the plans and schedule for complying with R.C. 1.97, Revision 2.

RESPONSE

Applicant is working on response to Regulatory Guide 1.97, Revision 2. Schedule will be supplied at a later date. 420.52 Provide a discussion (using detailed drawings) on the residual (7.6.2) heat removal (RHR) system as it pertains to Branch Technical Position ICSB 3 and RSB 5-1 requirements. Specifically address the following as a minimum: l. Testing of the RHR isolation valves as required by branch position E of BTP RSB 5-1. 2. Capability of operating the RHR from the control room with either onsite or only offsite power available as required by Position A.3 of BTP RSB 5-1. This should include a discussion of how the RHR system can perform its function assuming a single f ailure. 3. Describe any operator action required outside the control room after a single failure has occurred and justify. In addition, identify all other points of interface between the Reactor Coolant System (RCS) and other systems whose design pressure is less than that of the RCS. For each such interface, discuss the degree of conformance to the requirements of Branch Technical Position ICSB No. 3. Also, discuss how the associated interlock circuitry conforms to the requirements of IEEE Standard 279. The discussion should include illustrations from applicable drawings.

RESPONSE

The RHR isolation valves can be tested while on RHR by operating only one RRR pump, removing power from one valve associated with i the operating pump, simulating high pressure in the isolation channel for the valve that has power removed and verifying that the associated valve in the non-operating loop closes. The system is restored, the sequence repeated for the other isolation channel, cooling shif ted to the other loop and the test sequence repeated. NRC will review reply to RAI 440.23 and 440.24 that address power sou rc e s. There is no other system interfacing with the reactor coolant system (RCS) whose design pressure is less than that of the RCS. 420.53 FSAR Section 7.6.4, Accumulator Motor-Operated Valves, states that, (7.6.4) "During plant operation, these valves are normally open, and the --

motor control center supplying power to the operators is deenergized". Describe how power is removed and how the system complies to Positions B.2, B.3 and B.4 of BTP ICSB 18 (PSB). Also, identify any other such areas of design and state your conformance to the positions of BTP ICSB 18.

RESPONSE

Covered in response to 420.59. 420.54 FSAR Section 7.3.1.1 states that, "The transfer from the injection (7.3.1.1) to the recirculation phase is initiated automatically and completed (7.6.5) manually by operator action from the main control board". Describe automatic and manual design features permitting switchover from injection to recirculation mode for emergency core cooling including protection logic, component bypasses and overrides, parameters monitored and controlled and test capabilities. Discuss design features which insure that a single failure will neither cause premature switchover nor prevent switchover when required. Discuss the reset of Safety Injection actuation prior to automatic switchover fom injection to recirculation and the potential for defeat of the automatic switchover function. Confirm whether the low-low level refueling water storage tank alarms which determine the time at which the containment spray is switched to recirculation mode are safety grade.

RESPONSE

Will be discussed later. 420.55 FSAR Section 5.2.5.8 states that calibration and functional testing (5.2.5.8) of the leakage detection systems will be performed prior to initial (7.6) plant startup. Please provide justification since Position C.8 of Regulatory Guide 1.45 states that, " leakage detection systems should be equipped with provisions to readily permit testing for operability and calibration during plant operation".

RESPONSE

The electronics can be tested with plant at power. There are readouts that can be checked during plant operation. Radiation sensors can be tested at power because they have check source in them. Level sensors will be channel calibrated in accordance with Technical Specifications. 420.56 As shown on drawing 9763-M-310882 SH-B54a, two circuit breakers in (7.6) series are employed in the power and control circuits for the residual heat removal inlet isolation valves. Tripping of either breaker will remove power from the position indicating lights and valve position indication will be lost. Discuss how this arrangement complies with Branch Technical Position ICSB No. 3 which calls for suitable valve position indication to the control room.

RESPONSE

Handout submitted to staff. Valve position indicator lights will be powered from different source so that true valve position will always be indicated when power is removed from valve motor by racking out breaker. This applies to RHR interface valves..-

HANDOUT: Two circuit breakers in series are employed in the circuits of motor-operated valves inside containment. This is part of the containment penetration protection provided in response to Regulatory Guide 1.63. Refer to FSAR Section 8.3.1.1.c.7a. Valve position indication is provided on both RCS-RHR interface valves which are in series. As with any circuit, when power is removed because of a fault, indication will also be lost. We believe that our design meets the intent of ICSB 3 position B4. In addition to the normal valve position indication lights, the valve full closed position is also monitored by the station computer to alarm whenever the valve is not fully closed and the reactor coolant system is above the pressure rating of the RHR syatem. 420.57 Section 7.6.2.1 indicates that the interlock circuits of the (7.6) residual heat removal isolation valves, RC-V22 and RC-V87, have a transmitter that is diverse from the transmitter associated with valves RC-V23 and RC-V88. Discuss the method (s) used to achieve this diversity.

RESPONSE

Different manufacturers for pressure transmitters are used to achieve the diversity. 420.58 Discuss conformance of the accumulator motor-operated valves to (7.6) the recommendations of Branch Technical Positions ICSB No. 4. RESPOUSE: Handout submitted to staff. Change response to indicate valve position is monitored through video alarm system (VAS). Details of VAS vill be in the response to 420.49. Staf f will review adequacy of alarm. RANDOUT: The design of the accumulator motor-operated valves conforms to the recommendations of ICSB No. 4. Refer to FSAR Section 7.6.4 for a response to Branch Technical Positions B1 and B2. Branch Technical Position B3: Valve position is monitored and alarmed by the video alarm system. Branch Technical Position B4: The automatic safety injection signal bypasses all main control board switch functions which may have closed the SI accumulator valve. The safety injection signal will not automatically return power to the de-energized motor control center. 420.59 Section 7.6.9 of the FSAR lists the motor-operated valves which (7.6) will be protected from spurious actuation by removal of motor and control power by de-energizing their motor control centers (MCC _

522 and MCC 622). The FSAR also states that control of the breakers supplying power to these MCCs is provided in the main control room. Provide the following information: (a) The control the the MCC breaker from the Main Control Board for a typical Safety Injection System accumulator isolation valve is not shown on schematic diagram 9763-M-310890 Sh. B35a. Identify the drawing where this is shown. (b) The residual heat removal inlet isolation valves are not included in the list of valves protected against spurious operation. State whether protection against spurious action of these isolation valves is planned and if so, provide information on how it is accomplished. If not, then justify.

RESPONSE

(a) Refer to FSAR Section 8.3.3. Alarm is provided in the control room when the breaker is closed. (b) Reply given in response to RAI 440.23 and will be reviewed by the staff. 420.60 The following apparent errors have been noted in the schematic (7.6) diagrams. (a) Drawing M-310980, Sh. B35d, Rev. O contacts 5-SC on LOCAL REMOTE SWITCH SS-2403 appear incorrectly developed. An X indicating contacts closed should appear under the REMOTE column for contact 5 to allow remote closing of the accumulator valves. (b) Drawing 9763-M-310900, Sh. B52a, Rev. 1 Motor starter 42 open coil is mislabeled 42/C instead of 42/0. RES PONSE: We agree with your observation of drawing errors on the two schematic sheets mentioned and this will be corrected in the next revision of these drawings. 420.61 FSAR Section 7.6.6 discusses interlocks for RCS pressure control (7.6.6) during low temperature operation. Using detailed schematics, discuss how this interlock system complies with Positions B.2, B.3, B.4 and B.7 of BTP RSB 5-2. Be sure to discuss the degree of redundancy in the logic for the low temperature interlock for the RCS pressure control. Also, include a discussion on block valve control.

RESPONSE

Reply for the low temperature operation of the RCS pressure control will be under RAI 440.11. The block valves and manual controls are Class lE, train oriented, with controls being on the main control board. 420.62 If control systems are exposed to the environment resulting from (7.7) the rupture of reactor coolant lines, steam lines or feedwater lines, the control systems may malfunction in a manner which would cause consequences to be more severe than assumed in safety analyses. I&E Information Notice 79-22 discusses certain non-safety grade or control equipment, which if subjected to the adverse environment of a high energy line break, could impact the safety analyses and the adequacy of the protection functions perf ormed by the safety grade systems. The staf f is concerned that a similar potential may exist at light water facilities now under construction. You are, therefore, requested to perform a review per the I&E Information Notice 79-22 concern to determine what, if any, design changes or operator actions would be necessary to assure that high energy line breaks will not cause control system failures to complicate the event beyond the FSAR analysis. Provide the results of your review including all identified problems and the manner in which you have resolved them. The specific " scenarios" discussed in the above referenced Information Notice are to be considered as examples of the kinds of interactions which might occur. Your review should include those scenarios, where applicable, but should not necessarily be limited to them.

RESPONSE

We will identify key control systems that effect plant safety and analyze for effects of high energy line break. Review will be completed and formal response to I&E Inf ormation Notice 79-22 submitted. 420.63 If two or more control systems receive power or sensor information (7.7) from common power sources or common sensors (including common headers or impulse lines), failures of these power sources or sensors or rupture / plugging of a common header or impulse line could result in transients or accidents more severe than considered in plant safety analyses. A number of concerns have been expressed regarding the adequacy of safety systems in mitigation of the kinds of control system failures that could actually occur at nuclear plants, as opposed to those analyzed in FSAR Chapter 15 safety analyses. Although the Chapter 15 analyses are based on conservative assumptions regarding failures of single control systems, systematic reviews have not been reported to demonstrate that multiple control system failures beyond the Chapter 15 analyses could not occur because of single events. Among the types of events that could initiate such multiple failures, the most significant are, in our judgment, those resulting f rom f ailure or malfunction of power supplies or sensors common to two or more control systems. To provide assurance that the design basis event analyses adequately bound multiple control system failures, you are requested to provide the following information: (1) Identify those control systems whose failure or malfunction could seriously impact plant safety. (2) Indicate which, if any, of the control systems identified in (1) receive power from common power sources. The power sources considered should include all power sources whose failure or malfunction could lead to failure or malfunction of more than one control system and should extend to the effects of cascading power losses due to the failure of higher level distribution panels and load centers. (3) Indicate which, if any, of the control systems identified in Item 1 receive input signals from common sensors. The sensors considered should include, but should not necessarily be limited to, common hydraulic headers or impulse lines feeding pressure, temperature, level or other signals to two or more control systems. (4) Provide justification that any simultaneous malfunctions of the control systems identified in (2) and (3) resulting from isilures or malfunctions of the applicable common power source or sensor are bounded by the analyses in Chapter 15 and would not require action or response beyond the capability of operators or safety systems. RES PONSE: We will submit formal response similar to that submitted on other Westinghouse plants. 420.64 FSAR Section 7.7.1 discusses steam generator water level control. (7.7.1) Discuss, using detailed drawings, the operation of this control system. Include information on what consequences (i.e., overfilling the steam generator and causing water flow into the steam piping, etc.) might result from a steam generator level control channel failure. Be sure to discuss the high-high steam generator level logic used for main feedwater isolation. NOTE: The following RAI is from the draf t letter received 3/22/82. 420.67 The present Seabrook design shows that three steam generator level (7.2) channels are to be used in a two-out-of-three logic for isolation (7.3) of feedwater on high steam generator level and that one of the three level channels is used for control. This design for actuation of feedwater isolation does not meet Paragraph 4.7 of IEEE-279 on " Control and Protection System Interaction". For example, the failure of the level channel used for control in the low direction could defeat the redundancy requirements (i.e., a single failure of one of the remaining channels defeats the two-out-of-three requirement s). Therefore it is the staff's position that the system be modified (i.e., addition of a fourth protection channel) to meet the redundancy requirements.

RESPONSE

High-high steam generator level trip will be changed to two out of four logic. 420.65 Recent review of a plant (Waterford) revealed a situation where (7.2) heaters are to be used to control temperature and humidity within (7.3) insulated cabinets housing electrical transmitters that provide input signals to the reactor protection system. These cabinet heaters were found to be unqualified and a concern was raised since possible failure of the heaters could potentially degrade the transmitters, etc. Please address the above design as it pertains to Seabrook. If cabinet heaters are used, then describe as a minimum the design criteria used for the heaters.

RESPONSE

Class 1E electronic transmitters are not mounted in an insulated cabinet with heaters for temperature and humidity control. The subject design, therefore, does not pertain to Seabrook. NRC MEMO DATED MARCH 22, 1982 (Attached): Discussion: Submit justification for using this type of circuit. Use circuit as shown and define analysis that guarantees parallel contacts will not open under load conditions. Submit test results if any. Include number of systems used as safety-related. Address periodic testing. _

Fs Art ik:ck u p 53 1 & 2 TSAR C a....w ... rescus ...e by dipping sne maThTuv1.- m,, .A-- e r r n Generation of a reactor trip by tripping the turbine. g, [ Generation of a reactor trip by use,of the manual trip switch. g [ Generation of a reactor trip by manually actuating the safety injection ' system. h Generation of safety injection signal by use of the manual safety injection switch. [. Generation of containment spray signal by use of the manual spray actuation switch. [ 7all closure of main steam isolation valves. Tull. closure of feedvater isolation valves, f T,ull closure of feedvater control valves. qJ Main feedvater pump trip. [O Closure of reactor coolant pump component cooling water isolation ,~ valves. // Closure of reactor coolant pucp seal' vater return valves. Tor the above cases, it has been determined that: 1. "There is no practicable system design that vould per=it operation of the equipment without adversely affecting the safety or operability of the plant."

• The present position is that it is not a " practicable syste=

de sign" to provide equi =ent to bypass a device such as.e w p ?m=- ~= = 4ec ar a =ain steam line isolation valve solely c to test the device. In the case of testing the =anual initiation switches, the design for test capability would require that switches be provided on a train or sequential basis. This increases the operator action required to manually actuate the function. 2. "The probability that the protection system vill fail to initiate the operation of the equipment is, and can be =aintained, acceptably lov vithout testing the equipment during reactor operation." k 1.8-8

JAH.27 'So 22 43 cril Stnzuuun menesun - pa ss SB 1 le 2 Amendment 44 February 1982 FSAR KGA may iw //;20 M such as motor-opera-limit switches. Qualification of valve appurtenances, tors, solenoid valves and limit switches, is in accordance with this Regula-Refer to section 3.11 (B) for further discussion on this subject. tory cuide., For NSSS safety-related motor-operated valves located inside co' tainment, n environssental qualification is perfonsed in accordance with IEEE Standards The qualification program for valve related equipment 382-1972 and 323-1974. will be described in the NRC-approved version of Reference (9). Regulatory Guide 1.74 Quality Assurance Terms and Definitions (Rev. O, 2/74) f Endorses ANSI N45.2.10-1973 a-The guidance of this standard has been utilised to provide consistent terms and definitions in the description of the quality assurance program with the The definitions following exception, regarding Section 2.0 of the standard: of " Certificate of Conformance" and " Certificate of Compliance" shall be interchanged to comply with ANSI N45.2.13 (Section 10.2) and the ASME B&PV For further clarification during the Operational Phase, see Section Code. 17.2. 44 R_exulatory Guide 1.75 Physical Independence of Electric \\ (Rev. 2, 9/78) Systems The BOP design is consistent with the criteria for physical independence of electrical systems established in " Attachment C" of AEC letter dated 14,1973 (see FSAR Appendix 8A) and is in general conformance with December Regulatory Guide 1.75, Rev. 2, except as follows: Isolation Device - the Seabrook design conforms to the recomunenda-a. tions of IEEE 384-1977, Section 6, regarding specific electrical isolation criteria. Battery Room Ventilation - four Class 1E batteries are located in b. four seismic Category I structures, and are served by two cross-Each* room can be connected safety-related ventilation systems. isolated by fire dampers. The subject of this regulatory guide is further diteussed in Subsections l 8.3.1.3, 8.3.2.3 and 8.3.3. 8.1.5.3, 8.3.1.2,P u am4 do The NSSS(bfurnished systema comply with the recoannendations of Regulatory Guide 1.75, Rev. 2, as discussed in subsection 7.1.2.2. \\, 1.8-29 l

ann.ar me aos., ani >sasaww...a.... 551&2 FSAR

h. l Credible events shall include, but not be limited to, the effects of short

. circuits, pipe rupture, missiles, fire, etc. and are considered in the basic plant design. Control board details are given in Subsection 7.1.2.2b. In the control boar.d, separation of redundant circuits is maintained as described in Subsection 7.1.2.2a. a. Ceneral 1. Independence of Redundant Instrument Sensing Lines _ The independence of instruments and their' sensing lines required for a system safety function is maintained through redundancy, physical separation and/or diversity in accordance with IEEE Btandard 279-1971. Sensing lines penetrating the primary contaimeent satisfy the requirements of Ragulatory Guide 1.11. 2. Design Criteria and Bases for the Installation of Electrical Cable f or. 8afety-Related Systems The design criteria and bases for the installation of cables for preserving the independence of tedundant reactor protection systems and engineered safety features systems with respect to cable derating, cable raceway fill, cable routing, sharing of raceways by safety related cables with non-safety related cables, and cable tray markings are the same as that presented g~ in Subsection 8.3.1.4. 3. Spacing of Wiring and Components in Control Boards, Panels and Relay Racks Criteria for spacing of wiring and c6mponents in control boards, panels and relay racks are described in Subsection 7.1.2.2.b. 4. Physical Separation Criteria The physical separation criteria for redundant sa fe ty-rela ted system sensors, sensing lines, wireways, cables and components on racks within Westinghouse NSSSascope meet reconsnendations contained in Eagulatory cuide 1.75 with the following counsentet G W 60P i (a) The Westinghouse design of the protection system relies on the provisions of IEEE Standard 384-1974 relative to overcurrent devices to prevent malfunctions in one circuit from causing unacceptable influences on the functioning of the protection system. 1he protec tion system uses redundant instrumentation channels and actuation trains and incorporates physical and electrical separation to prevent faults in one channel from' degrading any other protection channel. 7.1-13

SB 1 & 3 Amendmcnt 44 FSAR February 1982 4'20,/7 / 3 greater than the required 10-3 For further discussion, refer to Subsection 3.5.1.3. Regulatory Guide 1.116 Qutslity Assurance Requirements for Installa- _(Rev. 0-R, 6/76, 5/77) tion, Inspection and Testing of Me,chanical Equipment and Systems Endorses ANSI N45.2.8-1975 44 The guidance of this Regulatory Guide has been used in the installation, For further inspection and testing of mechanical equipment and systems. discussion, refer to Sections 17.1.2 and 17.2. Regulatory Guide 1.117 Tornado Design Classification (Rev. 1, 4/78) The plant design complies with Regulatory Guide 1.117, Rev. 1. Although the condensate storage tank is not designed for missiles or a pressure drop, the system will function if the tank fails because the shield wall is designed for missiles and is waterproofed to contain water from the tank. [ The ultimate heat sink cooling tower is not designed for tornado missiles in the fill area. The primary source for water is the Atlantic Ocean through the underground tunnels, which will function during a tornado event. For further discussion on this subject, refer to Section 3.5. Regulatory Guide 1.118 Periodic Testing of Electric Power (Rev. 2, 5 "S) and Protection Systems 0 s //?7) The 9ee electric power and safety system testing will comply with this l regulatory guide. However, IEEE-338-!?75 r_il.c th... 1000-330 1^77 =e W by b;;. LOT oud n65S. &#E 7W5dTEj) A in IEEE-338-1975 as {ue N000 upplicemH-l-treat 11 "shoulf'y' recommendationstobefollowedonlyat-+++patements -discretion. Detailed positions on the regulatory positions are presented below: Regulatory Post 'on C.1 e NSSS supplier wil rovide a means to

• 1itate response time tes from the sensor i t at the protection k to and includin he input to the ac tion device. Examp of actuation s

devices are protection system lay or bistable. I i l 1.8-41 l 1

SB 1 6 2 Amendment 44 FSAR February 1982 ] 6t-Regulatory Position C.2 g7. ppg 74 " Protective Action Systems"A o mean t -The !!C00 ouyyl.c. .u w. y. a: the electric, instrumentation and controls portions of those protection systems and equipment actuated and controlled by.the protection system. \\, Regulatory Position C.6 Equipment performing control functions, but actuated from protection system sensors, is not part of the safety system and will not be tested for time response. d, Regulatory Position C.10 Testing, although not tied to accident conditions, will be tied to the range of the parameter that is varied. This range is determined by expected design basis event conditions and anticipated operational occurrences, therefe:c--tH : gu A yu.i.Iea I: r:n;ider A b h yt e NGCC auyy1ac; :: '_-t. d. Regulatory Position C.ll Status, annunciating, display, and monitoring functions, except for those related to the Post Accident Monitoring System (PAMS), [ are considered by the M99? : pp1'er to be control functions. Reasonability checks, i.e., comparison between or among similar such display functions, will be made. Otherwise, the clarification note in Item l above, pertaining to Position C.6, is observed. C. b Regulatory Positions C.12 and C.13 Response time testing for control functions operated from protection system sensors will not be performed. Nucicar Instrumentation System detectors will not be tested for time response. (See Table 3.3-2 of the Technical Specifications). Ttc ":xp:::co :n;.e.-uul angmechanic1configrationof he actual stallation ' will not be a plicated or the esting of nsors whic must be r oved to accom lish resp nse time testing un ss it cau e shown th t the duplic ion is p ctical nd that the uplicated actors signific tly influ nce th sensor time esponse. Th NSSS sup ier scope rotectio system does not precl% e the resp se time sting'of ocess sen es by the removal normal shutdos The s dard NS supplier ope protec 'on system oes not inct e design ovision ich permi insitu tes 'ng of proc ss or Nucicar strument 'on Syst sensors. i 4 1.8-42 'l 1

SB 1 & 2 Amendment 44 FSAR February 1982 9,2W73 z g. egulatory P ition C.14 Te orary jumper 'res, tempor test ins umentation, he removal of f s and other uipment not rd-wired t o the prote on system

• 1 be used wh e applicabl Regulatory Guide 1.119 Surveillance Program for New Fuel Assembly (Rev. O, 6/76)

Designs This regulatory guide was withdrawn by the NRC on June 23, 1977. Regulatory Guide 1.120 Fire Protection Guidelines for Nuclear (Rev. 1, 11/77) Power Plants Regulatory Guide 1.120 has been issued to provide information to applicants regarding the NRC staff's plans for using this regulatory guide and to solicit public comment. Branch Technical Position APCSB 9.5-1, which is part of the Standard Review Plan (NUREC-75/087), formed the basis for the regulatory guide and continues to be used in the evaluation of fire protection provisions of applicants currently under review for operating licenses for plants under construction. The plant design complies with the Branch Technical Position APCSB 9.5-1 with the exceptions as depicted in " Fire Protection System Evaluation and Ccmparison to Branch Technical Position APCSB 9.5-1, Appendix A", submitted f. to the USNRC on August 30, 1977. Regulatory Guide 1.121 Bases for Plugging Degraded PWR Steam (Rev. O, 8/76) Cenerator Tubes The bases for plugging degraded steam generator tubes conform to Regulatory Guide 1.121. For further discussion refer to Subsection 5.4.2.2. Development of Floor Response Spectra for Regulatory Guide 1.122 (Rev. 1, 2/78) Seismic Design of Floor Supported Equipment or Components The plant design conforms to Regulatory Guide 1.122, Rev. 1, with the following exception: Regulatory Guide 1.122 requires peaks associated with structural frequencies be broadened by +0.15 f. Seabrook PSAR Subsection 3.7.2.6 i states that "to account for variations in structural parameters the peaks on the floor response spectra will be widened by +10%." The justification for this exception is that Regulatory Guide 1.122 was published after the PSAR was submitted. The " implementation" section of Regulatory Guide 1.122 states that it is presently being used "in \\. 1.8-43

fjd /[ / SB 1 & 2 FSAR ( 7.1.2.7 Con formance to Regulatory Guide 1.53 and IEEE Standard 379-1972 The principles described in IEEE Standard 379-1972 were used in t,he design of the Westinghouse Protection System. The system complies with the intent of this standard and the additional guidance of Regulatory Guide 1.53 although the formal analyses have not been documented exactly as outlined. Westinghouse has gone beyond the required analyses and has performed a fault tree analysis, Reference (1). The referenced topical report provide details of the analyses of the protection systems previously made to show conformance with single failure criterion set forth in paragraph 4.2 of IEEE Standard 279-1971. The interpretation of single failure criterion provided by IEEE Standard 379-1972 does not indicate substantial dif ferences with the Westinghouse interpretation of the criterion except in the methods used to confirm design reliability. Established design criteria in conjunction with sound engineering practices form the bases for the Westinghouse protection systems. The Reactor Trip and Engineered Safety Features Actuation Systems are each redundant sa fe ty sy s te ms. The required periodic testing of these systems will disclose any failures or loss of redundancy which could have occurred in the interval between tests, thus ensuring the availability of these systems. 7.1.2.8 Conformance to Regulatory Guide 1.63 Conformance to Regulatory Guide 1.63 is discussed in Section 8.1 and Subsection 8.3.1.2. 7.1.2.9 Conformance to IEEE Standard 317-1972 Conformance to this IEEE standard is discussed in Section 8.1. 7.1.2.10 Conformance to IEEE Standard 336-1971 The installation and pre-operational testing of Class IE systems and related Class IE electrical power, instrumentation and control equipment conform or will conform to the requirements of IEEE Standard 336-1971. The quality assurance program for design, procurement and installation is described in Chapter 17 and the pre-operational test procedures for each system are described in Chapter 14. 7.1.2.11 Conformance to IEEE Standard 338-1975 The periodic testing of the Reactor Trip System and the Engineered Safety Features Actuation System conforms to the requirements of IEEE Standard 338-1975, with the following coments: The surveillance requirements of the technical specifications a. for the protection system ensure that the system func tional operability is maintained comparable to the original design standards. Periodic k' tests at frequent intervals demonstrate this capability,4ee-the systeg aveluM ng_4enekee. 7.l-25

FSAR t Overall protection systems response times shall be demonstrated by test. Sensors - ;hi.- th; ";;; oh.... :::;:_will be demonstrated ~ adequate for this design by vendor testing, sn-sitA ests in operating ably typb/p-4/7g plants with appropriately similar design, or y testing. The Nuclear Instrumentation System detectors are excluded since they exhibit response time characteristics such that-delays attributable to them are negligible in the overall channel response time required for safety. A eriodic ver ' fication at program r sensors ithin he Wes inghouse se e for det ining any terioratt of 1 talled sens 's response time, is b ing sought. The metho ogy an accept le test pr.edure has ot yet evol d. This t ue is industry eneric and ill be re Ived by Wes nghouse on hat sis. When final ed, technt I specift tions will quire pert ic verification esting on least I month interva Each test shall include at least one logic train such that both logic trains are tested at least once per 36 months and one channel per function such that all channels are tested at least once every (N times 18 months), where N is the total number of redundant channels in a specific protective function. The measurement of response time at the specified time intervals provides assurance that the protective and Engineered Safety Features action function associated with each channel is completed within the time limit assumed in the accident analyses. b. The reliability goals specified in paragraph 4.2 of IEEE Standard 338-1975, and are being developed, and adequacy of time intervals will be demonstrated at a later date, The periodic time interval _ discussed in paragraph 4.3 of IEEE c. Standard 338-1975, and specified in the plant technical specifi-cations, is conservatively selected to assure that equipment associated with protection func tions has not drif ted beyond its minimum performance requirements. If any protection channel appears to be marginal or requires more frequent adjustments due to plant condition changes, the time interval will be decreased to accom-modate the situation until the marginal performance is resolved. d. The test interval discussed in paragraph 5.2 of IEEE Standard 338-1975 is developed primarily on past operating experience and modified if necessary to assure that system'and subsystem protection is reliably provided. Analytic methods for determining reliability are not used to determine test interval. Based on the scope definition given in IEEE Standard 338-1975, no othpr ( systems described in Chapter 7 are required to comply with this standard. i 1 l

h&kg b [2 Y k'#'O' E s SB 1 & 2 FSAR q. Control Accuracy - This definition includes channel accuracy, accuracy of readout devices (isolator, controller), and rack environ-mental effec ts. Were an isolator separates control and protection signals, the isolator accuracy is added to the channel accuracy to determine control accuracy, but credit is taken for tuning beyond this point; i.e., the accuracy of these modules (excluding controllers) is included in the origiaal channel accuracy. It is simply defined as the accuracy of the control signal in percent of the span of that signal. This will then include gain changes where the control span is different from the span of the measured variable. Were controllers are involved, the control span is the input span of the controller. No error is included for the time in which the system is in a nonsteady state condition. 7.1.1 Identification of Safety Related Systems 7.1.1.1 Safety-Related Systems The Nuclear Steam Supply System (NSSS) and the Balance of Plant (BOP) instru-mentation discussed in Chapter 7 are those required to function to achieve ~ the system responses assumed in the safety evaluations, and those needed to shutdown the plant safely, and are identified in this section. -%e+e A.. *f ;f. .vyp11:w with the assa are .v y - -- :h:: .m a. Reactor Trip System (gegeGA NO Vi M,4 d *$ The Reactor Trip System is a functionally defined system described in Section 7.2. The equipment which provides the trip unctions is identified and discussed in Section 7.1. Design bases for the Reactor Trip System are given in Subsection 7.1.2.1. Figure 7.1-1 includes a single line diagram of this system. T b. Engineered Safety Features Actuation System N8'C24 (E.f fh 0 fyovlde/ 63 The Engineered Safety Features Actuation System (is a functionally defined sys Q described in Section 7.3. The equipment which O iff Abd '. l provides the actuation functions is identified and discussed in . Section 7.3. Design bases for the Engineered Safety Features i Actuation System are given in Subsection 7.1.2.1. h.gi r.c e i c el. C A i'% i~e5e C&EM C. Tite 2.ngineered Aafety feature Ayste=s W ^ ' : .2.;:---" g ; pp,*, .I w yv.m.6s that perform protective actions after tr- # Hg * -. w.4 f._u y. m or the operator are listed as , 'f' Sp$c~--a wcyl- -L. E c. Cf ave. R e ? PW " iM Scld a ll s l. Containment Spray System (Subsection 6.2.2) 2. Containment Isolation System (Subsection 6.2.4) 3. Combustible Gas Control System (Subsection 6.2.5) 7.1-4

A thach M to aAI 4D M g, [g213-SB 1 & 2 FSAR T 7 / 4. Emergency Core Cooling System (Section 6.3) 5. Habitability Systems (Section 6.4) 6. Fission Product Removal & Control Systems (Section 6.5) 7. Daergency'Feedwater System (Section 6.8) d / Instrtssentation and Control Power Sunely System g,p Design bases for the Instrumentation and Centrol' Power Supply System are7 given in Subsection 7.1.2.1. Further description of f e v' d e_M. this system is provided in Section-8.3. g g Other Auxiliary Supporting Systems Auxiliary Supporting Systems are those systems that, upon receipt of actuation signals, must function to support and enable the operation of protection systems. ' Actuation signals for these g,y[- systems are provided from the Engineered Safety Features Actuation . ? [c a 8 , System. A The auxiliary systems are: !b il *7 4 c) r -*' y J. J p t\\'1. Fuel Storage and Handling Systems (Section 9.1)

1. 1. L +f g, G 2.

Service Water System (Subsection 9.2.1) f,/cef 3. Cooling System for Reactor Auxiliaries (Subsection 9.2.2) Ultimate Heat Sink (subsection 9.2.5) 4 5. Reactor Makeup Water System (Subs'ection 9.2.7) 6. Chemical and volume Control System (Subsection 9.3.4) l 7. Air Conditioning, Beating, Cooling and Ventilation Systems (Section 9.4) 8. Normal and emergency electrical power systems (Section 8.3) 9. Diesel Generator Mechanical Systems (Section 9.5) y other Systems for Safety These are systems which operate to reduce the probability of occurrence of specific accidents, maintain the plant within the envelope of operating conditions postulated in the accident analyses, or are required to assure full protection capability. These systems are: I N 9 Me- 0? STY ' $ g- ' ; [ w I, i, 7 > f [ 4 f 'E A > ' f 3 '4. w( ( a, c_ ptCS. [ de-o .c c ^' pa kt psrs and tq C ,)ds) a f" 2- [- 7.1-5 i i

hDS E D YES df 20, l9 NOV 0 6 BSD SB 1 & 2 FSAR Si*1 1 1. Safety-related display instrumentation (Section 7.5) 2. Accumulater isolation valve controls (Section 7.6) 3. Reactor coolant system pressure control during low temperature operation,(Section 7.61 4. Residual heat removal system isolation (Section 7.6) 5. Protection against spurious valve actuation (Section 7.6) 6. Switchover from injection to re-circulation (Section 7.6) 7. Isolation of non-essential components jgBB0 in PCCW system (Section 7.6) 8. Bypass and inoperable status indication system (Section 7.1) 9. Area radiation and airborne radioactivity monitoring instru- ,4, mentation (Section 12.3.4). T 7.1.1.2 Safety Related Display Instrumentation Display instrumentation (Section 7.5, Table 7.5-1) provides the operator with information to enable him to moni' tor the results of Engineered Safety Features actions following a Condition III or IV event. Section 7.5, Tables 7.5-1 and 7.5-2, represent instrumentation and controls provided to maintain the plant in a hot shutdown condition, or to proceed to cold shutdown under normal operating conditions, and following Condition III and IV events. The safety-related display instrumentation for the safety-related systems includes position indicating lights and indicators for the vit,a1 parameters in the systems listed in Subsection 7.1.1.1. 7.1.1.3 Instrumentation and Control System Designs All systems discussed in Chapter 7 have definitive functional requirements developed on the basis of the Westinghouse NSSS design. Figure 7.2-1 defines scope interface. Regardless of the, supplier, the functional requirements necessary to assure plant safety and proper control are clearly delineated. 7.1.1.4 Plant Comparison System functions for all systems discussed in Chapter 7 are similar to those discussed in the comparison tables provided in Section 1.3. i 7.1.2 Identification of Safety Criteria Subsection 7.1.2.1 presents design bases for the systems given in Subsection 7.1.1.1. Design bases for non-safety related systems are provided in the sections which describe the systems. Conservative considerations for instrument errors are included in the accident analyses presented in Chapter 15. Functional 7.1-6

Q fauw ys h'JCAIMO /M IEZEEN-S2 //WM W s w gppmpM. saim:; op Amauroy dwpg 4 5.3 yMg y.sto /s TNA 05S N A W.f S s f i c74/c /J. y N020 ( Sy&'Ea3 RA ms y 7.1.2.7 Conformance to Regulatory Guide 1.53 and IEEE Standard 379-1972 f The principles described in IEEE Standard 379-1972 were used in the design of the Westinghouse Protection System. The system complies with the intent of this standard and the additional guidance of Regulatory Guide 1.53 although { the formal analyses have not been documented exactly as outlined. Westinghouse has gone beyond the required analyses and has performed a fault tree analysis, Reference (1). The referenced topical report provide details of the analyses of the protection systems previously made to show conformance with: single failure criterion set forth in paragraph 4.2 of IEEE Stand.ntd 279-1971v -The--interpretation of single failure criterion provided by IEEE Standard 379-1972 does not 1 indicate substantial dif ferences with the Westinghouse interpretation of I the criterion except in the methods used to confira design reliability. Established design criteria in conjunction with sound engineering practices form the bases for the Westinghouse protection systems. The Reactor Trip and Engineered Safety Features Actuation Systems are each redundant safety sy s te ms. The required periodic testing of ~ these systems will: disclose any failures.or loss of redundancy which could have occurred in th'e interval between testo, thus ensuring the availability of these systems'. W..,. 99....,. Conformance to Regulatory Guide l.63..- s-7 1.2.8 s. U Co'nformance t'o Re'gulatory Guide 1.63 is discussed in Section 8L1 and Subsection 8.3.1.2. 7.1.2.9 Conformance to IEEE Standard 317-1972 g .Conformance to this IEEE standard is discussed in Section 8.1. I , 7.1.2.10 Conformance to IEEE Standard 336-1971 ft,. he. ins tallat,io.n, and, pre-operati'onal. test.ing of.: Clas s 1E.' systems and related ' 1 Clas.s,1E elec tri, cal. power, instrumentationland control' eqiiipment conform'or 'e 4 ' will confohn to the requirements of IEEE,. Standard 336-197l'. Theiquality i ' assurance program for. design, procurement.and, installationnis; ' described ' in Chapter 17 and.the pre--operational testPp/hftp.- rocedures.forreach.: system are described in, Chapter 14.

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gys;~.'....:4,r..g.j 4,g. g..g;..sy.py 4. +.y.g.....,,.... . < g.. g s ..n ..o ~ .i .. :.,,.. s. -.u iH 3 ec 27 c-64A L4ch SIM u u o - - ~ ~ - ~ " TRAIN A & B . COMPONENT SYSTEM COMPOffNTNO DESCRIPTION RNCTION ~A el-P-+A scpeJ IAld. AEcdRc PP SI S Td P ~ te e. B sI P-4 S a A SI V-f 73 Bi TK-6 m sug4rsq etagg w at n -174 et B ' A 14$ ST_-P-4A,5 ouft.27 iso N ar . B ' A 06h-FH l6h EMpK4dif.AN 0F fit rFAN C t>A START i et B n -It,8 _n A B u -CP-2st c nouxo pargar/ed EDS TRIP a .,.. n m.s. A ,+.. B @ =CP-1.S + 4ROUND PdifCT/0N KDG 7 819 A i L 6 MCC br+ DISTR PNL KH3 ED TRIP ' s4A Luh SMa, u o ." u TRAIN A & B COMPONENT SYSTEM -~ (XWONENT NO DESCRIPTION FUNCTION A. S1 s A snFGTY InJ. Pump s1 STA R.T B ~s r-P - G B u u A cAn.ru-te crttr*wT* sruuG CLCs _FAA CAH al.ocMsinRT -ta_ se n B u -r* ee u A n B -IA = -IF n A .- I D es 88 V i 8 5.T sr,927 A sr-e - 6 A SArtTY M PpMP- __ ' i' ei 8 sz - P - G er _ e8 ~ A B Eor-us-e Sus.G_t(,8 Tie Be<m, (u o) EDE TOP A )~ ~B Mcc. t,\\\\ o s N o M I E A V m i k.t /E S 6D6 iner i A ) .B m e c e.6 4, a w, t...,sa ser T4.P SWA utP

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u. SED /NYARNRt.L Y B IVa - Y - l *)

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.I B Mo _ __ _ n _i A_,c w = w FA te-R/t@ Loop i n R c_ a n ' B % 4 FV-18'I4 A-00P / OSC ~ = a n A cs-V~l49 LTON LINE IRC -tso Cs Blace ctost B RC = FV*1M'i LOOP 3 150 SAMPLE RC CLOSR A co-V 143 E-9A FCC W ORC I30 _g.Q BLOCe CleSK B Re N %nt PR'tR./NBO SAMPL2 RC Clost A CG-V-145 E-9A PCCW ORO 1s_o ' CC n B 62= V-I ') 1

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'T P.'h1 ~ j'{hf.e.'ee'Teig ent gr.siooY star.no.4,9fis- ,. c. y.9..9..y3..L., 48.f. :. . + <.: : -. '.... 9.....,.. :.: .u. ;. q. d.,4&.~--dW#_ ~c_'.5.f);,$. ':bl;b."h*f' k..c. ;. .:.'.$$h-f9hi..l ' ,h '*.., YNk.' f'$.'-).., ! _ l. c.. ': ~.~ ..%.,. +... ~;..". :. ~ ~.- M. :,.,.%. '...

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stocx close B

s -26& E-168 se u = .-ian E. /Q ~ ' so -- as orsn A = 8 e -264 E-/68 se e a A

• Itt PCCW Leof A CCHMT RET a

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B A c B S-V - JI c0NTMr $fMY VLV CBs BLOCK CLD32 B

-_ t 7 a _ _o orga n -ss srsnv noomva ptsen.viv LA B -42 ~38 ~ Stock clau~ l A = .-43 a n B a FA - < : ; ~v. . w... i g ~. :.,. n.. . :.. ~~ . -.n. A B A cas-V-It coHTMr sPxnY YLV CA$ C Pf.N d = m - t'r ~ . _ ~ 3 COf%cahtYEITt SPR.Ay ACT. "C5" TRAIN A & B COMPONENT SYSTEM L... I CX)NF0 BENT NO DESCRIPTION _ FUNCTION l A ces -V. 31 TEST REconc YLV CBS CLess i a n o B = -ss -32 .a n a i A a B A MM uA sR2 I4 An_4 u ti ATOR MM ALARM 5 5 8 A B 'A B A cas.P-9A coHrMr SPRAY PUMP CBS STMAY 95 o B -94 i' p A . -9s n a a 8 _A 1 1 B

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..n .: --.... -..... T3o F 2./ 5F# Cortoinmut Vent.ho&bn o ! TRAIN A &~ B COMPONENT 5YSTEM ~ COMPONENTNQ DESCRIPTION FUNCTION A CAP-V-f 4-4 c6HTMY AIM OUYBD 150 __ C A P Clog & ~ B CAP-V-gg-s u u n-A CAP-FN-9 FRE-ENYKY PURG6 fBN n STEP _ _. -5 LA cop-v-[- CONTMTPUMqd Is__0 _ cop CloSE B. CO P - V - t ~ n n A COP-FM-73 coprmr runge rnN srop B A COP-V- A cewrMr/vn45 ors &xH C0P Ct.asE I B CCP-V - 3 CaNrMf?uR45 /N6 EXH n n AlcAr.fM-st. Rarost ronos sup!LY CAP '5709 .. <. >. a'h....... :,, a. ..w )' /

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} s y; I.4 e p 2.9 ~ '.h. ... -.... ~,;. : , ir. m h... -v +. -v. +. ....v... N O N. TRAIN A & B COMPONENT SYSTEM ..s COMPObENTNG DESCRIPT10N FUNCTION A cs-LCV-lits cs-TK-/ OVrLKr_/SO CS CtNSE B = -Itto = n OPEN -- ~A _a . _-It t o Rwsr re CNs Ptwr tso e .gggs n u u g A B A ' B ~-A B A B A B A B VCT W t.O LnVEL TRAIN A & B COMPONEAi $YSTEM ' ^ ~ ~ CONFOrENT NO DESCRIPTION FUNCTION h CS-LCV-IttB CS-TK-f 0pYLdr tsc c5 _c L o SE ~ -Ittc n = B a -toto RW57 Tb CNG PUMP /$o o cPEN A .-tutn a ~

• 1 B

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P.821 'JgH.14 e3 20:47 GMT Str.8200K S.TATION - 9763 ~ '}:..,~ 'f2 0,3 . 4 *.. ' ; r,f. * ?g", *

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,,,y. 5y.3.gg g. ..,g.. .,..,. n.m u. s -.. ..-,,..::? Erhergocu RedRiMPft.0L.o steo] Ge.n.14vd [2/d TRAN A & B CO'MPONENT SYSTEM i COMPCMNTNO DESCRIPTION FUNCTION l A b-i AAff l e M.W R.h ,._V M *1 SB .X.L o sf_ l 9 B fW.P.M1B K M 1 R G. M_ _ 6 o. P_t,( M P FW 3TAAY A Ms _- V. - s.t 7.. s.r.M.. sum.y...r.o. !WW.97A MS. _ e PEN OPRN se '* M5_ B Ms -V-ISB_ _ A .B FN-P-STS ARMER G, ffED PUMP FW .6TRAT 7. n..,.... e t i I I!. S

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..ff'O,3 ^ ~ 0$)..j..l.~.. ~ ~ '.. ^ .-=~~ -l..,.,.. n : y c .. ',....in... q .. ix.,.. .+ .......s =- x:e:.-:.:+:, :- '-.'. _ s.a L7_sE.A7-SMAM DOMP CCNDEF=ER. VLV INTLX._ 1 TRAN A &.8 COMPONENT SYSTEM ( ~ COMPOtENTNO . DESCRIPTION RNCTION ~ B A Ms-V-9012 nTERM puNi! YnivE h MS BLDCKcMM B -30s2, n a a _A w -S oop n a a B a -5007 a w a A a -3 010 u u .n ~B n -3 0_/o a u p A ee -Both n n n B n' -Both n a n A = -3c/3 o n n -3073 B w o a n ~ A -u -30/4 n p u ) B b -301_4 n .e n / - A a -3020 o n n 8 a 3020 u u sicam 3: cap cowwwsera vtv irct.i "^ TRAIN A & 8 CRTMPONENT SYSTEM ~ CONFOffNT NO DESCRIPTION FUNCTION A B A Ms_-Y-3o17_ _ G TERN 1 DuM7F YAL VE MS BLEck opst B u - 3017 n e. n A v -3018 n n B us -3_o18 n n n A_ _ ~ B i B I A I B ) A i 1 B l \\ Y \\ l

- JKH.14se 20 M MT T N.~Bh00K STATION - 9763 'f,~jh Y *'I ' *"? ' ~,- . ~ _, _ _ }Z.... ) SH 18 6 F A7 bGCLtT) hKP CCCLla0M COND61VS6R. hl V INTLK TRAIN A & B COMPONENT GYSTEM FUNCTION CONPOENT NO DESCRIPTION B A Ms-V-SOll STM QUMP /NN/Bir SV MS Block ettx B a -Soft a s -So/t A a B se - 3 015 es a n n u A a. -30!p _= et n -B OI9 'n n B c '~ -~ e g D* e et ) >d

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• rssr a

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a bM hE6f5002. 6ttoder 4hSn UrkACcV. %I tl , TRAIN A.. ..B.__' COMPONENT-SYSTEM CONTAGT' t NO DESCRIPTION FUNCTION ~ sr-Ti<-9A eso VLV S.Z opw A SI-V-~S In .ps i B i A - 3 2. = -9c es n 9 - 4 7- - -90 a w. e e I 6 h / ..,e.

I $ }Q, ] f / SB 1 6 8 TSAR /a c. Spatially Dependent Variables he only variable sensed by the Engineered Safety Features Actuation System which has spatial dependence is reactor coolant temperature. De ef feet on the measurement is negated by taking multiple samples from the reactor coolant hot leg and averaging these samples by mixing in the resistance temperature detector bypass loop. d. 1.inits, Margins and Setooints Prudent operational limits, available margins and setpoints before onset of unsafe conditions requiring protective action are discussed in Chapters 15 and 16. e. Abnormal Events I he malfunctions, accidents, or other unusual' events which could physically damage protection system components or co'uld cause environmental changes are as follows: 1. Loss of coolant accident (see Section 15.6) 2. Steam line breaks (see Section 15.1) 3. Earthquakes (see Sections 2.5 and 3.7) 4 Fire (see Subsection 9.5.1) = 5. Explosion (hydrogen buildup inside containment) (see Section 15.6) \\' 6. Missiles (see Section 3.5) 7. Flood (see Sections 2.4 and 3.4) f. Minimum Performance Requirements Minimue performance requirements are as follows: 1. System Response Times f<he Engineered Safety Features Actuation System response time is defined as the interval required for the Engineered Safety Features sequence to be initiated subsequent to the point in

1. time that the appropriate variable (s) exceed setpoints. De

response time includes sensor / process (analog) and logic (digital) delay, plus the time delay associated with trip-ping open the reactor trip breakers and control and latching h ph [ ' snechanisms, although the Engineered Sa fety Features actuation 2

i signal occurs before or simultaneously with Engineered Safety Features sequence initiation (see Figure 7.2-1, Sheet 8). A6R 7.3-8

SB 1 & 2 FSAR d,V. o f ", 7 4./ hO f The values listed herein are maximum allowable times consis 3 i J /' f. ' g, tent with the safety analyses and are systematienilv verified j I durine elant pre-operational start-up tests.s These maximEm elay time s tnus Anc tuoe ali compensaiava ano therefore require that any such network be aligned and operating during verifi-cation testing. The Engineered Safeguards Actuation System is always capable of having response time tests performed using the same methods as those tests performed during the preoperational test program or following significant component changes. Typical maximum allowable time delays in generating the actua-tion signal for loss of coolant are: (a) Pressurizer pressure 2.0 seconds Typical maximum allowable time delays in generating the actua-tion signal for steamline break protection are: (a) Steam line pressure rate 2.0 seconds (b) Steam line pressure 2.0 seconds (c) Reactor Coolant System T,yg (as measured) at the resistance temp-erature detector sensor output, including 2 seconds for resistance temperature detector bypass delay e (assume other signals present) 6.0 seconds (d) High containment pressure for closing main steamline stop valves 1.5 secends (e) Actustion signals for auxiliary feed pumps 2.0 seconds (f) Refueling water storage tank levels for recirculation actuation (later) ( 2. System Accuracie's l Typical accuracies required in generating the required actua-i I tion signals for loss of coolant protection are: (a) Pressurizer pressure l (uncompensated) 314 psi I L Typical accuracies required in generating the required actua-( tion signals for steam line break protection are: l h 7.3-9

Insert T. Seabrook P7.3-8 and 9 of FSAR to Resolve Agenda Item 420.34 J ~7 The ESFAS response time is defined as the interval required for the ESF sequence to be initiated subsequent to the time that the appropriate variable (s) exceed this setpoint(s).. The ESF sequence is initiated by the output of the ESFAS which is hy the operation of the dry contacts of the slave relays (600 and 700 series relays) in the output cabinets of the solid state protection system. The response times listed below include the interval of time which will elapse between the time the parameter as sensed by the sensor exceeds the safety setpoint and the time the solid state protection system slave relay dry contacts are operated. These values (as listed below) are maximum allowable values consistent with the safety analyses and the Technical Specifications and ~ are systematically verified during plant preoperational startup tests. For the overall ESF response time; refer ton the Technical Specifications. In a similar manner for the overall reactor trip system instrumentation response time; refer to h the Technical Specifications. e e e e e 19030

92c2 37 /dI / / 7.4 SYSTEMS REQUIRED FOR SAFE SHUTDOWN The functions necessary for initiation of safe shutdown are available from instrumentation channels that are associated with the major systems in both These the primary and secondary portions of the Nuclear Steam Supply System. channels are normally aligned to serve a variety of operational functions, l There are no including startup and shutdown as well as protective functions. However, prescribed procedures identifiable saf e shutdown systems, per se. for securing and maintaining the plant in a safe condition can be instituted by appropriate alignment of selected systems in the Nuclear Steam Supply The discussion of these systems, together with the applicable codes, System. In addition, criteria and guidelines are found in other sections of the FSAR. the alignment of shutdown functions associated with the Engineered Safety Features which are invoked under postulated limiting f ault situations is discussed in Chapter 6 and Section 7.3. The instrumentation and control functions which are required to be aligned for maintaining safe shutdown of the reactor that are discussed in this section These functions will are the minimum number under non-accident conditions. pe rmi t the necessary operations that will: Prevent the reactor from achieving criticality in violation of the a. Technical Specifications, and b. Provide an adequate heat sink such that design and safety limits are not exceeded. 7.4.1 Description The designation of systems that can be used for safe shutdown depends on identifying those systems which provide the following capabilities for maintaining a safe shutdown: a. Decay Heat Removal Reactor Coolant Inventory and Pressure Control b. Negative Reactivity Addition Control c. d. Electrical Power Supply c. Plant Cooling System f. Remote Saf e Shutdown Monitoring g. HVAC These systems are identified in the following lists together with the The identification of the associated instrumentation and controls provisions. monitoring indicators (Subsection 7.4.1.2) and controls (Subsection 7.4.1.3) shutdown. The equipment and are those necessary for maintaining a hot services available for a cold shutdown are identified in Subsection 7.4.1.4.

920.3S O 7.4.1.1 Control Room Evacuation The main control room is the primary station for safe shutdown control of the Controls required for plant and is designed to be available at all times.to hot or cold shutdown and for bringing the plant In the extremely unlikely conditions are located in the main control room. event that the main control room becomes uninhabitable, the plant may be brought to and maintained in a safe hot shutdown condition using alternate It is noted that the control provisions outside the main control room. instrumentation and controls listed in Subsections 7.4.1.2 and 7.4.1.3, which are used to achieve and maintain a safe shutdown, are available in the event These controls and an evacuation of the control room is required. listed in Subsection instrumentation channels, together with the equipment 7.4.1.4, identify the potential capability for cold shutdown of the reactor subsequent to a control room evacuation through the use of suitable procedure s. In the worst conditions, should the main control room become uninhabitable, physical and electrical circuit separation of controlthe Rem abnormal conditions. channels within the control room from those at location and electrical disabling of equipment ensures that the saf e shutdown systems are operational. The preferred method of obtaining indication is by separate independentprac instrument loops. However, when this is not proper independent operability, isolation (guillotine) and transfer capability is utilized. 7.4.1.2 Monitoring Indicators The characteristics of these indicators, which are provided outside as well as The necessary inside the control room, are described in Section 7.5 indicators are as follows: Uater level indicator for each steam generator a. Pressure indicator for each steam generator b. Pressurizer water Icvel indicator c. d. Pressurizer pressure indicator j, Reactor coolant loops 1 and 4 hot and cold leg temperature indicators c. Intermediate range neutron flux detectors f. Primary component cooling water loops A and B tecperatures j g. b Emergency feedwater flow h. 7.4.1.3 Controls Generr.1 Consid erations a. ] 1. The turbine is tripped (note that this can be accomplished at the turbine as well as in the control room). l.

qu,.7S .7 to this can be accomplish at The reactor is tripped (note that the reactor trip switchgear as well as in the control room). 2. Main steam isolation valves will be tripped in the control room 3. (prior to evacuation of control room). 4. All four reactor coolant pumps are tripped (prior to evacuation of control room). For selected equipment having dual independent motor controls outside the control room (which duplicate the manual functions 5. inside the control room), the controls are provided with a key locked mode selector switch which transf ers (guillotine) control f rom the control room to a local station (s). of the equipment Placing the local selector switch in the local operating position will give an annunciator alarm in the control room, and will turn off the motor control position lights on the control Selection of the " local" position defeats all room panel. automatic trip functions except equipment protective trips and undervoltage load shedding. b. Pumps and Fans 1. Emergency Feedwater Pumps The operation of these pumps is explained in Section 6.8. Start /stop controls are located inside the control room for both of these pumps, and also in the switchgear room for the the remote saf e shutdown panels for motor-driven pump, and at Handuheel control for the valves is the turbine-d riven pump. also provided (see Dwgs. 9763-M-503585 and 9763-M-503586). 2. Charging Pumps The operation of the pumps is explained in Section 9 3 4. Start /stop motor controls for these pumps are located outside, Controls are provided for as well as inside the control room. The controls and the two centrifugal charging pumps. remote / local selector switch for the charging pumps are located in the switchgear rooms, as well as in the control room (see Dwgs 9763-M-503388 and 9763-H-503336). 3. Service Water Pumps The function of these pumps is explained in Section 9.2.1. Start /stop motor controls and the remote / local selector switch are located in the switchgear rooms, as well as in the control room (see Dwg. 9763-M-503969). 4. Primary Component Cooling Water Pumps The operation of these pumps is explained in Section 9.2.2. Start /stop controls and the remote / local selector switch are as well as in the control rooms located in the switchgear rooms, (see Dwg. 9763-M-503270).

420.79 fjf /0 5 Containment-Cooling Units The equipment f unction is explained in Subsection 9.4.5. Controls are provided both in the control room and at the remote The remote / local shutdown panels (see Dwg. 9763-H-503205). the remote shutdown panels. selector switch is provided at 6. HVAC Emergency Switchgear Area Supply and Return Fans a) b) Battery Room Exhaust Fans c) Diesel Cenerator Room Supply and Exhaust Fans d) Containment Enclosure Cooling Fans e) Emergency Feedpump House Fans Primary Auxiliary Building PCC Pump Area Supply Fans f) g) Service Water Pump House Supply Fans 9.4.3, 9.4.6, The equipment functions are explained in Sections Scare /stop motor 9 4.8, 9.4.10, 9. 4.11, 9.4.13 and 9.4.14. controls are provided in both the control room and switchgear rooms with a remote / local selector switch in the switchgear rooms. Diesel Generators c. These function is explained in Sections 8.3 and 9 5 The equipment units start automatically following a loss of of f-site ac power or on However, manual controls f or diesel a safety injection (SI) signal. the diesel generators as well as in startup are provided locally at the control room (see Dwg. 9763-M-503493). The diesel generator system is provided with a LOCAL-REMOTE-Under remote safe shutdown (RSS) I MAINTENANCE selector switch. conditions, if a loss of of f-site power occurs and if the selector l switch is in " LOCAL" position, the diesel engine will automatically the operator must manually close the diesel generator l start, but the A safety injection (SI) signal will not start circuit breaker. diesel engine automatically when the selector is in " LOCAL" functions are defeated when the l All the automatic start position. Automatic closure of the selector is in the " MAINTENANCE" position. breaker is defeated when " LOCAL" or diesel generator circuit l " MAINTENANCE" positions are selected. i

0. 5 j(~

/62 d. Valves and Heaters 1. Emergency Feedwater Control Valves Controls for these valves are located in the control room and remote shutdown panels (see Dwg. 9763-N-504152) with a remocc/ local selector switch at the remote shutdown panels. 2. Main Steam Atmospheric Relief Valves The main steam. atmospheric relief valves are automatically Manual control is provided at the remote shutdown controlled. panels as well as in the control room (see Dwg. 9763-M-503670) the remote shutdown with a remote / local selector switch at panels. 3 Pressurizer Heater Control On/of f control with selector switches is provided for two backup The heater groups are connected to separate heater groups. buses, such that each can be connected to separate diesels in The controls are located at the event of loss of outside power. remote shutdown panels and duplicate functions available in the control room (see Dwg. 9763-M-503749). Remote / local selector switches are located at the remote shutdown panel. Main Steam Isolation Valves (MSIV) and Bypass Valves 4. If uninhabitable, Control will be from the control room. operator will trip valves before leaving control room (see Dwgs. 9763-F-503668 and M-405669). 5. Pressurizer Relief Valves Remote manual controls with selector switches are provided at the remote shutdown panel. The controls duplicate functions available in the control room (see Dwg. 9763-M-503746). the remote Remote / local selector switches are located at shutdown panel. 6. Reactor Coolant Pump Seal Return Valves Remote manual controls with selector switches are provided at the remote shutdown panel. The controls duplicate functions availabic in the control room (see Dwg. 9763-M-503333). the remote Remote / local selector switches are located at shutdown panel. 7. Reactor Coolant Pump Seal Injection Valves Remote manual control and the remote / local selector switches are provided at the MCC in Switchgear Room A. The controls duplicate functions available in the control room (see Dwg. 9763-M-503391).

h $a di fl1 Pressurizer Relief Block Valves 8. Remote manual control with remote / local selector switches is Control is also provided at the NCC's in each switchgear room. provided in the control room. Accumulator Tank Isolation Valves 9. If the control room is Control is provided in the control room. inaccessible, manual operation will be required locally. Charging Pump Mini-Flow Isolation Valves 10. If (ne control room is Control is provided in the control room. inaccessible, manual operation will be required locally. RWST Gravity Feed to Charging. Suction Valves 11. These valves are manual valves requiring local operation. 12. Service Water System Valves a) Cooling Tower Discharge Valves Diesel Generator Heat Exchanger Discharge Valves b) Primary Component Cooling Heat Exchanger Discharge Valves c) Service Water Transfer to Cooling Towers Valves d) Service Water Pump Discharge Valves c) Service Water Intake Isolation Valves f) Service Water to Circulating Water Discharge Valves g) i Service Water to SCC Isolation Valves h) If the control room is Control is provided in the control room. inaccessible, the valves will be disabled by opening the breakers (to prevent reposition) in the switchgear rooms except The diesel generator heat exchanger for items b) and h). discharge valves will be disabled to their failure position their 125V AC local power distribution panel (open) also at The Service Water to SCC localled in the switchgear rooms. Isolation Valves will also have controls on the MCC's in each switchgear room. SW Intake / Discharge Tunnel Valves 13 Remote manual control with a remote / local selector switch is these valves the remote shutdown panel to prevent available at from changing position (see Dwg. 9763-M-503961).

ty2AJf it? 14. PCCU Temperature Control Valves Remote manual controls with remote / local selector switches are provided at the remote shutdown panels. These controls duplicate functions available in the control room (see. Dwg. 9763-M-503276). 15. Containment structure Cooling Valves Remote manual controls with remote / local selector switches are provided at the remote shutdown panels. These controls duplicate functions available in the control room (see Dwg. 9763-H-503280). 16. Sample Valves Isolation Valves Control is provided in the control room. If the control room is inaccessible, manual operation will be required locally. 17. Volume Control Tank Discharge Isolation Valve Remote manual control with remote / local selector switches is provided at the MCC's in each switchgear room. Control is also provided in the control room. 18. Charging Pump Suction to RWST Remote manual control with remote / local selector switches is provided at the MCC's in each switchgear room. Control is also provided in the control room. e. HVAC Dampers 1. Mechanical Room Intake, Recirculation and Exhaust Dampers 2. Diesel Generator Room Supply and Exhaust Dampers 3. Emergency Feedpump House Dampers l Primary Auxiliary Building PCC Pump Supply and Exhaust Dampers 4 l Controls are provided locally with the associated f ans. 7.4.1.4 Equipment Available for Cold Shutdown In addition to equipment used for hot shutdown listed in Section 7.4.1.3, the following equipment is available for cold shutdown. I Residual Heat Removal Pumps a. The operation of these pumps is explained in Section 5.4.7. i Start /stop motor controls and the local / remote selector switches are located inside the switchgear rooms, and also normal control from the control room. l t l

f)0. 33 d "' ! b. Residual Heat Removal. Heat Exchanger and Bypass Valves Local control is provided at the top of the RHR and CS vaults as well as control in the control room. c. RHR Sample Valves These valves are manual valves requiring local operation. Residual Heat Removal Discharge Temperature and Flow d. Indication is both in the control room and remote shutdown panels . located in the switchgear room. the effects of a safety injection signal trip circuit actuation In addition, be defeated in the switchgear rooms (if the and cooling tower actuation must control room has been evacuated) and the SI accumulator isolation valves closed locally if the control room has been evacuated. 7.4.2 Analysis Hot shutdown is a stable plant condition, automatically reached following a The hot shutdown condition can be maintained safely for an plant shutdown. In the unlikely event that access to the control extended period of time. room is restricted, the plant can be safely kept at a hot shutdown, or brought to a cold shutdown, by the use of the monitoring indicators and the controls listed in Subsections 7.4.1.2 and 7.4.1.3. These indicators and controls are provided outside as well as inside the control room. Alternate control provisions outside the main control room consist of selector switches for interrupting certain logic interlocks and for enabling the manual Failure of a single control controls integral with motor starting equipment. in the remote safe shutdown facility will not or indicating loop or component prevent safe shutdown from either the control room or from outside the control room. Controls are provided at the remote shutdown locations for all air-operated devices or motor-operated devices whose positioning is required to achieve and maintain a safe shutdown condition. Portions of the instrument air system are The compressed required for air-operated valves necessary for saf e shutdown. This system has been designed air system is described in FSAR Section 9.3.1. for maximum operating reliability and is available following loss of off-site is connected to the emergency diesel generator buses. Also, a power since it backup emergency saf e shutdown air supply will be used in the unlikely event of total loss of normal air. This will supply air to the required air-operated equipment and will be separated and seismically qualified. Remote shutdown controls and indications include provisions for testing and calibration during refueling outage. Communications between the various control locations are provided to assist in coordination of proper monitoring of the plant parameters during the remote shutdown procedures.

42d. 7S }7 /V? The safety evaluation of the maintenance of a shutdown with these systems and associated instrumentation and controls has included consideration of the The accident consequences that might jeopardize safe shutdown conditions. accident consequences that are germane are those that would tend to degrade the capabilities f or boration, adequate supply for emergency feedwater, and residual heat removal. Of these, The results of the accident analysis are presented in Chapter 15. the f ollowing events will produce the most severe consequences that are pertinent: Uncontrolled Boron Dilution (see Subsection 15.4.6). a. Loss of Normal Feedwater (see Subsection 15.2.7). b. Loss of External Electrical Load and/or Turbine Trip (see Subsections c.

15. 2.2 and 15.2.3).

Loss of Nonemergency AC Power to the Station Auxiliaries (Loss of d. Off-Site Power) (see Subsection 15.2.6). It is shown by these analyses, that safety is not adversely affected by these incidents, using the instrumentation and controls indicated in Subsections 7.4.1.2 and 7.4.1.3 are available in the control room to control and/or These available systems will allow a maintenance of hot monitor shutdown. shutdown even under the accident conditions listed above which would tend toward a return to criticality or a loss of heat sink. In the unlikely event that the control room is uninhabitable, alternate Safety is not control provisions are provided outside the control room. adversely affected by Event a., Uncontrolled Boron Dilution (see Section Events b., c., and d. are not adversely af f ected since the remote 15.4.6). is powered by emergency power and a plant trip safe shutdown equipment initiated by control room evacuation will put the plant in a safe condition. The safety The station Service Water system is explained in Section 9.2.1. evaluation is presented in Subsection 9.2.1.3. The Primary Component Cooling Water system is explained in Section 9.2.2 and the safety evaluation is presented in Subsection 9.2.2.3 in detail. The results of the analysis which determined the applicability to the Nuclear Steam Supply System safe shutdown systems of the NRC Ceneral Design Criteria, IEEE Standard 279-1971, applicable NRC Regulatory Guides and other industry The functions considered and listed standards are presented in Table 7.1-1. below include both safety-related and non-saf ety-related equipment. Reactor Trip System a. b. Engineered Safety Features Actuation System Saf ety-Related Display Instrumentation for Post-Accident Honitoring c. d. Main Control Board

920 M /'d7 /l2 Remote Safe Shutdown Stations e. f. Residual Heat Removal g. Instrument Power Supply h. Control Systems For the discussions addressing how these requirements are satisfied, the column of Table 7.1-1, entitled "Conformance Discussed in Section " provides the appropriate reference. I i I

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a. Safety Classification Train Control Description Device Mechanical Electrical Assignment Location Emergency Feedwater Pump FW-P-37A 3 lE A&B CP-108A FW-P-37B 3 IE B 4 kV Bus E6 SG A Emergency Feedwater Control Valve FW-FV-4214 3 IE A CP-108A FW-FV-4224 3 IE B CP-108B B FW-FV-4234 3 lE A CP-108A C FW-FV-4244 3 lE B CP-108B D SG A Emergency Feedwater Flow FW-FT-4214 3 Non IE AA CP-108A FW-FT-4224 3 Non IE BA CP-108B B FW-FT-4234 3 Non IE AA CP-108A C FW-FT-4244 3 Non IE BA CP-108B D RC Loop 1 Hot Leg Temperature RC-TE-9406 1 Non IE A CP-108A 4 RC-TE-9407 1 Non IE B CP-108B RC Loop 1 Cold Leg Temperature RC-TE-9410 1 Non IE A CP-108A 4 RC-TE-9411 1 Non IE B CP-108B SG A Atmos. Relief Valve MS-PV-3001 2 Non IE AA CP-108A MS-PV-3002 2 Non IE BA CP-108B B MS-PV-3003 2 Non IE AA CP-108A C MS-PV-3004 2 Non IE BA CP-108B D SG A Wide Range Level FW-LT-4310 2 Non IE A CP-108A FW-LT-4320 2 Non IE B CP-108B B FW-LT-4330 2 Non IE A CP-108A C FW-LT-4340 2 Non IE B CP-108B g w D MS-PT-3173 2 Non IE A CP-108A .Sh SG A Pressure MS-PT-3174 2 Non IE B CP-108B () ,s B MS-PT-3178 2 Non IE A CP-108A (4 MS-PT-3179 2 Non IE B CP-108B %{( C D

,m _ Safety Classification Train Control Description Device Mechanical Electrical Assignment Location SG Blowdown Isolation Valve SB-V-9 2 1E B PP-ll2B SB-V-10 2 lE B PP-ll2B S B-V-11 2 lE B PP-il2B SB-V-12 2 1E B PP-ll2B Pressurizer Heaters Group A Non IE AA CP-108A Non IE BA CP-1088 Croup B Charging Pump CS-P-2A 2 lE A 4 kV Bus ES Cubicle CS-P-2B 2 lE B 4 kV Bus E6 Cubicle Pressurizer Relief Valve RC-PCV-456A 1 lE A CP-108A 1 RC-PCV-456B 1 1E B CP-108B Pressurizer Relief Block Valve RC-V-122 1 lE A MCC E531 RC-V-124 1 1E B MCC E631 Pressurizer Pressure RC-PT-7336 2 Non IE AA CP-108A RC-PT-7335 2 Non IE BA CP-108B RCP Seal Return RCP-1A Valve CS-V-10 2 Non IE AA CP-108A RCP-1B CS-V-28 2 Non IE AA CP-108A RCP-1C CS-V-44 2 Non IE AA CP-108A RCP-lD CS-V-59 2 Non IE AA CP-108A RCP Seal Injection RCP-1A Valve CS-V-166 2 lE A MCC E512 RCP-1B CS-V-162 2 lE A MCC E512 RCP-1C CS-V-158 2 lE A MCC E512 RCP-lD CS-V-154 2 lE A MCC E512 SI Accum. Tank 9A Isolation Valve SI-V-3 1 lE A MCC E522 9B SI-V-17 1 lE B MCC E622 (g 9C SI-V-32 1 lE A MCC E522 9D SI-V-47 1 lE B MCC E622 4 h Charging Pump Mini-Flow Isol. Valve CS-V-196 2 lE A MCC E512 y x CS-V-197 2 IE B MCC E612 4 t

Safety Classification Train Control Description Device Mechanical Electrical Assignment Location Intermediate Range Neutron Monitors NI-NI-6690 Non IE A CP-108A Non IE B CP-108B NI-NI-6691 Service Water Pump SW-P-41A 3 IE A 4 kV Bus E5 Cubicle 7 SW-P-41B 3 lE B 4 kV Bus E6 Cubicle 7 SW-P-41C 3 lE A 4 kV Bus E5 Cubicle 2 SW-P-41D 3 IE B 4 kV Bus E6 Cubicle 2 SW C1g. Twr. P-110A Discharge Valve SW-V-54 3 1E A CP-108A P-110B SW-V-25 3 IE B CP-108B DG Heat Exchanger Discharge Valve SW-V-16 3 IE A CP-248 EDE-PP-112A SW-V-18 3 IE B CP-249 EDE-PP-112B CCW HX Discharge Valve SW-V-15 3 lE A MCC E512 SW-V-17 3 IE B MCC E612 SW Transfer to Cooling Twr. SW-V-23 3 lE B MCC E612 SW-V-34 3 lE A MCC E512 SW Pump Discharge Valve SW-V-2 3 lE A MCC E514 SW-V-22 3 lE A MCC E514 SW-V-29 3 1E B MCC E614 SW-V-31 3 lE B MCC E614 SW Intake Isolation Valve SW-V-20 3 IE A MCC E512 SW-V-19 3 IE B MCC E612 N ub SW Discharge to Cire. Water Discharge SW-V-75 NNS Non IE AA MCC 261 SW Intake / Discharge Tunnel Valves SW-V-44 NNS Non IE AA CP-108A q SW-V-64 NNS Non IE AA CP-108A SW-V-63 NNS Non IE AA CP-108A SW-V-46 NNS Non IE AA CP-108A CC-P-llA 3 IE A 4 kV Bus E5 Cubicle 12 PCCW Pump CC-P-llB 3 lE B 4 kV Bus E6 Cubicle 13 CC-P-11C 3 IE A 4 kV Bus E5 Cubicle 14 CC-P-llD 3 lE B 4 kV Bus E6 Cubicle 15

o s Safety Classification Train Control Description Device Mechanical Electrical Assignment Location PCCW Loop A Temperature Control Valve CC-TV-2171-1 3 Non IE AA CP-108A CC-TV-2171-2 3 Non IE AA CP-108A PCCW Loop B Temperature Control valve CC-TV-2271-1 3 Non IE BA CP-108B ~ CC-TV-2271-2 3 Non IE BA CP-108B PCCW SF-E-15A Supply CC-V-32 3 lE A CP-108A SF-E-15B CC-V-445 3 lE B CP-108B PCCW Loop A Temperature CC-TE-2197 3 Non IE AA CP-108A B CC-TE-2297 3 Non IE BA CP-108B Cont. Structure CC Loop A Supply CC-V-168 2 IE A CP-108A B CC-V-175 2 lE B CP-108B Cont. Structure CC Loop A Inbd. Supply CC-V-57 2 IE B CP-108B B CC-V-176 2 lE A CP-108A Cont. Structure CC Loop A Inbd. Return CC-V-121 2 lE B CP-108B B CC-V-256 2 lE A CP-108A Cont. Structure CC Loop A Otbd. Return CC-V-122 2 lE A CP-108A B CC-V-257 2 1E B CP-108B Containment Cooling Unit lA CAH-FN-1A NNS Non IE BA CP-108B IB CAH-FN-1B NNS Non IE BA CP-108B IC CAH-FN-lC NNS Non IE AA CP-108A ID CAH-FN-lD NNS Non IE BA CP-108B IE CAH-FN-lE NNS Non IE AA CP-108A 1F CAH-FN-lF NNS Non lE AA CP-108A Emergency Switchgear Area CBA-FN-19 3 1E A MCC E521 'd} CBA-FN-32 3 lE B MCC E621 I Supply Fan %R 4 CBA-FN-20 3 IE A MCC E521 '\\k io Emergency Switchgear Area CBA-FN-33 3 'E B MCC E621 's (a V4 sq Return Fan

Safety Classification Train Control Description Device Mechanical Electrical Assignment Location Battery Room A Exhaust Fan CBA-FN-21A 3 IE A MCC ES21 B CBA-FN-21B 3 IE B MCC E621 Mechanical Room Intake Damper CBA-DP-24A 3 Non IE Recirculation Damper CBA-DP-24B 3 Non IE LATER LATER Exhaust Damper CBA-DP-24C 3 Non IE Diesel Generator Room Supply Far; DAH-FN-25A 3 lE A MCC ES21 DAH-FN-25B 3 IE B MCC E621 Diesel Generator Room Exhaust Fan DAH-FN-26A 3 IE A MCC E521 DAH-FN-26B 3 lE B MCC E621 Diesel Generator Room Supply Damper DAH-DP-15A 3 IE A MCC ES21 DAH-DP-15B 3 lE B MCC E621 Diesel Generator Room Exhaust Damper DAH-DP-16A 3 lE A MCC E521 DAH-DP-16B 3 lE B MCC E621 Containment Enclosure Cooling Fan EAH-FN-5A 3 IE A 480 V Bus ES2 EAH-FN-5B 3 IE B 480 V Bus E62 Containment Enclosure Fan EAH-FN-31A 3 lE A MCC E512 EAH-FN-31B 3 IE B MCC E612 Emergency Feedpump House Fan EPA-FN-47A NNS 1E A MCC E512 EPA-FN-47B NNS lE B MCC E612 Emergency Feedpump House Dampers EPA-DP-54A NNS lE A MCC E512 EPA-DP-54B NNS lE B MCC E612 EPA-DP-61A NNS lE A MCC E512 EPA-DP-61B NNS lE B MCC E612 g bb h PAB PCC Pump Area Supply Fan PAH-FN-42A 3 IE A MCC E512 g PAH-FN-42B 3 lE B MCC E612 g g4 w PAB PCC Pump Area Supply Damper PAH-DP-43A 3 lE A MCC E512 PAH-DP-43B 3 lE B MCC E612

Safety Classification Train Control Description Device Mechanical Electrical Assignment Location PAB PCC Pump Area Exhaust Dampers PAH-DP-44A 3 1E A MCC E512 PAH-DP-44B 3 lE B MCC E612 Service Water Pump House Supply Fan SHA-FN-40A 3 1E A MCC E514 SWA-FN-40B 3 1E B MCC E614 Residual Heat Removal Pumps RH-P-8A 2 1E A 4 kV Bus 5 Cubicle 10 RH-P-8B 2 1E B 4 kV Bus 6 Cubicle 11 RHR Suction Isolation Valve RC-V-87 1 1E B MCC Bus E621 RC-V-88 1 lE A HCC Bus E521 RC-V-22 1 1E B MCC Bus E621 1 RC-V-23 1 1E A MCC Bus E521 RH-FCV-618 2 Non IE AA Local Controls RHR HX Bypass Valve RH-FCV-619 2 Non IE BA and Instruments To Be Designed RH-HCV-606 2 lE A Local Controls RHR HX Valve RH-HCV-607 2 1E B and Instruments To Be Designed Local Controls RH-TI-608 2 RHR HX Discharge Temperature RH-TI-609 2 and Instruments To Be Designed RH-FT-618 2 Non IE AA CP-6 RHR Flow RH-FT-619 2 Non IE BA CP-8 lE A DG-CP-75A Diesel Generator A lE B DC-CP-76A B b () s VCT Discharge Isolation Valve CS-LCV-112B 2 lE A MCC E512 b CS-LCV-ll2C 2 lE B MCC E612 N CS-LCV-ll2D 2 1E A MCC E512 s. Charging Pump Suction from RWST CS-LCV-112E 2 lE B MCC E612 \\4 CS-V-65 2 1E A MCC E512 Charging Pump Discharge to BIT Valves CS-V-66 2 lE B MCC E612

E 0, Provide a discussion of the procedures and plant systems used to 2 /_7 440.13 f rom normal operating conditions to cold shutdown take the plantThis discussion should include heat removal, c ond i t i ons. depressurization, flow circulation, and reactivity control. A. Functicnal Requirements The system (s) which can be used to take the reactor from normal s operating conditions to cold shutdown shall satisfy the functional requirements listed below: The design shall be such that the reactor can be taken from 1. normal operating conditions to cold shutdown using only These systems shall satisfy General safety-grade systems. Design Criteria 1 through 5 The system (s) shall have suitable redundancy in components 2. and features, and suitable interconnections, leak detection, f or on-site and isolation capabilities to assure that electrical power system operation (assuming of f-site power is not available) and for off-site electrical power system operation (assuming on-site power is not available) the system function can be accomplished assuming a single failure. The system (s) shall be capable of being operated from the 3. control room with either only on-site or only off-site power In demonstrating that the system can perform its available. function assuming a single failure, limited operator action outside of the control room would be considered acceptable if suitably justified. The system (s) shall be capable of bringing the reactor to a 4. cold shutdown condition, with only of f-site or on-site power available, within a reasonable period of time following shutdown, assuming the most limiting single failure. the main steam isolation The operator will trip the reactor,

RESPONSE

valves and the reactor coolant pumps, thus establishing a hot shutdown condition. A decay heat removal path will be established using the emergency fee'dvater system and steam generator Cooldown vill then be started and atmospheric relief valves. proceed to the RHR vindow so the RHR system can be aligned as the ultimate heat removal system. Decay Heat Removal Decay heat removal is accomplished by the use of portions of the the Main Steam system and the Steam Cenerator Feedvater system, Reactor Coolant system temperature is controlled Blowdown system. The steam by the steam generator atmospheric relief valves. generator water inventory is controlled by operating the emergency I feedvater pumps and associated emergency feedvater control Inventory for the emergency feedvater is f rom the valves. condensate storage tanks. To assure feedvater system integrity, To the outboard steam generator blowdown valves are closed. assure Main i

l l t b f ~ Steam system integrity, the HSIV's and HSIV bypass valves are ffa[s#L7 / transf er is made possible by maintained closed. Decay hea t natural circulation flow in th'e Reactor Coolant system. i 1 Reactor Coolant (RC) Pressure Control The RC system pressure is controlled by use of the pressurizer heaters to increase pressure and by the pressurizer power operated 1 relief valves to depressurize. Reactor Coolant Inventory Control To compensate for RC system leakage through RC pump seals and for cooldown volume shrink, portions of the Chemical and The injection path for this supply i~s water supply, are used. through the RC pump seals. Reactivity Control Reactivity conditions required for cold shutdown are controlled by operation of a portion of the Chemical and Volume Control system uhich includes a centrifugal charging pump taking a gravityThe injectio suction from a boric acid tank. RC pump seals. ) Process Monitoring _ instrumentation is provided for monitoring the following process variables: Steam generator emergency f eedwater flow Reactor coolant loop hot and cold leg temperatures a. b. Steam generator vide-range level c. d. Steam generator pressure Pressurizer level Intermediate-range neutron monitoring (excore) e. f. Primary component cooling water temperature =- g. Sampling A manual RHR local sample valve will be utilized to verify boron An RC content of RHR system before alignment for cold shutdown. system sample will be utilized to verify boron content before and This system is not safety grade, but is during the cooldown. redundant and single failure proof. Cold Shutdown The Residual Heat Removal (RHR) system will be utilized for the The valves will be long-term heat sink for fuel decay heat. manually aligned as required and an RHR pump operated. ) i. 1

f k 01 b Service Water (SW)_ The Service Water system will supply cooling water to the Primary Cooling Water system and to the diesel generators. Component Service Water supply will be f rom either the Servic,e Water pumps The SW system includes the SW pumps, or from the cooling covers. SW valves, cooling cover pumps, cooling tower f ans, and cooling t tower valves. Cooling Water (PCCW) Primary Component 1 The PCCW system is utilized to maintain cooling water to the charging pumps, RHR pumps, RHR heat exchangers, containment structure cooling units and containment enclosure cooling units. l The PCCW pumps, temperature control valves, and inboard and outboard containment isolation valves are necessary for system operation. Containment Building Air Handling (CAH) The CAM system is utilized to maintain habitability of containment for manual valve actuations, if required, including accumulator The_CAH system isolation valves and RHR isolation valves. This system is includes six coolers and their associated f ans.However, the system is ~ non-safety grade. failure proof. Control Building Air Handling (CBA) The CBA system is utilized to maintain long-tern habitability of the switchgear rooms and equipment cooling in the battery roomsThe CB and mechanical equipment rooms. and dampers necessary for air handling in these areas. (DAH) Diesel Generator Building Air Handling The DAH system is utilized to maintain long-term habitability and The DAH s'ystem equipment cooling for the diesel generator rooms. includes t Enclosure Air Handling (EAH) Co'ntainment The EAH system is utilized to maintain long-term habitability of the RHR vaults and the pipe tunnel area, and provide equipment The EAR system cooling in the charging pump rooms and RHR vaults. incl in these areas. Emergency Feedvater Pumphouse Air Handling (EPA) The EPA system is utilized to maintain long-term habitability and The equipment cooling in the emergency feedwater pump building. EPA system includes the f ans and dampers required for air handling [ The system is Seismic Category 1, Safety Class NNS, ) The system is redundant and single l in this area. and the motors are Class IE. f failure proof.

92 0,7 % ~ ) (PAB) Ai r lland ling (Pall)_ Primary Auxiliary Building 'N Portions of the PAH system are utilized to maintain long-term habitability and equipment cooling in the PCCW area of the PAB. The PAH system includes the fans and dampers required for air handling in this area. SW&CT Air Handling (SWA) t The SWA system is utilized for equipment cooling in the SW pumphouse switchgear rooms and in the cooling tower s rooms. air handling in these areas. Emergency Electrical Distribution (EDE)_ Portions of th EDE system are required to power the various pumps, Included in the fans, valves, etc., required for saf e shutdown.EDE syst i emergency motor control centers, uninterruptible power suppl es, 120 volt vital distribution panels,125 volt de batteries, battery chargers and 125 vole de distribution panels. Diesel Cenerators (DC) l The diesel generators provide power to the emergency electrical The DC system distribution system upon loss of of /-site power. includes machine auxiliaries and fuel oil transfer pumps. Instrument Air (IA) Portions of the IA system are required f or air-operated valves, h The compressed air system 1,s necessary for safe shutdown. These system has been designed described in FSAR Section 9.3.1 for maximum operating reliability and is available following loss of off-site power since it is connected to the emergency diesel generator buses.,Also, a backup emergency saf e shutdown air supply is being developed to be used in the unlikely event ofT total loss of normal ' air. lly air-operated equipment and will be separated and seismica qualified. The reminding systems used to take the plant f rom normel operating conditions to cold shutdown conditions are safety grade with i hd suitable redundancy so that system function can be accomplis e. The systems are capable of bringing the reactor Limited operator action outside the control room vill be required (RHR suction isolation to energize equipment normally locked out valves), isolate the SI accumulator isolation valves by containment entry, and RCS/RI!R sampling. I / I

920,Whx a 430.67 (c) For those evants which requira Control Rocm evacuatien, va have identified the following arcs 3.as requiring manning to achieve ~ N and maintain cold shutdown. (, Switchgea r Rooms A and B RHR Vaults A and B Diesel Generator Control Panels A and B In addition, there are many other areas where one time actions (i.e., valve opera tion) may be necessa ry. The station design provides for bringing the plant to cold shutdown f rom the Control Room. Therefora, if the Control Room is available, there is no need to man remote locations to mitigate the consequences of an event or to attain a safe cold ( plant shutdown. (b) The maximum sound levels are as follows: Switchgear Room A - B-RHR taults A-B- Diesel Cenerator Control Panels A - ,B-(c) The remote shutdown locations identified in a) and b) share a dedicated sound powered telephone channel. Each location, with the exception of the RHB vaults, also have access to a dedicated paging station. Because of the close proximity to each other, the RHR vaults share a single paging station. There is also an extension f rom the station telephone system near each location.

f h he lt /2 0 in addition to those communication systems identified above, the station radio system (FSAR Section 9.5.2.2.a.4) is designed { to provide communications betweeen all areas of the station (except the Containment Building) via hand-held portable ra d io s. The radio system would provide communication to those areas noted in a) as requiring one time actions. (d) The maximum background noise level that could exist at each manned location identified in a) is listed in b). 1. The page party system is designed to provide effective communications at maximum background noise level. 2. Headphones will be provided as necessary to assure k) ef fective communication via the dedicated sound powered Sound absorbent booths will be employed as system. necessary to assure audible communications via the plant telephone system. Individual volume control on the' hand-held portable radios assures that this system will provide effective communication under the maximum expected noise levels. (e) Functional tests will be conducted under conditions that simulate the maximum plant noise levels being generated during the variour operating conditions and accident conditions, to demonstrate system capabilities. i

920,39 A The telephona system is p:wsr d f rom a Unit 1, Tra in " A" bus. (f) Back-up power is provided by a. dedicated engine generator unit. - 3 The Public Address (PA) system for Unit 1 is powered from a Unit 1, Tra i n " A" U PS bu s. The PA system f or Unit 2 is powered i f rom a Unit 2, Train " A" UPS bus. The station radio system is powered from Train A busses, and each repeater is backed up by a dedicated battery rated for Portable units are powered by rechargable 8-hour use. ba t t e rie s. The sound powered telephone system requires no external power supply to maintain its function. The f ollowing protective measures have been taken to assure a (- (g) functionally operable on-site communication system. Power supplies for the various communication systems are discussed in (f). The telephone system has redundant Central Processing Units (CPU). Two multi pair telephone cables following diverse routes connect the station telephone system to off-site public telephone system. Upon loss of all power to the telephone system, preselected phones are automatically connected to the of f-site telephone system. and each unit's PA system control The telephona PBX, cabinets, are housed in dif f erent locations. Cables for

Nh. 50 MEMORANDUM r a conswuotors hr-OrricE8 Philadelphia Joe No. 9763.006 DATE: February 23, 1982 Derv. Power / Engineering C.,L Asgarval Cores To E. H. Kats G. it. Morris ~ ~ ~ ~ ' D. A Rhoads 48MN N' R. P. Neustadter Sus;EcT: Public Service Co. of New Rangshire Seabrook Station - Unita 1 & 2 Response *a IE Bulletin No. 79-27, " Loss of Non-Clasa-1-E Instrumentation and Control Power System Bus During Operation" The following information is submitted in response to II Bull. 79-27: "Raview the Class 1-E and Non-Class 1-E buses supplying power to Iters 1_ safety and non-safety related instrumentation and control systems which could affect the ability to achiava a cold shutdown condition using axisting procedures or procedures developed under Item 2 below. For each buss" ( i and control The Class 1-E and Non-Class 1-E instrumentation

Response

systems are fed by the following buses Class 1-_E B_uses 125 volt de Bus 11A 125 volt de Bus 113 125 vole de Bus 11C 125 volt de Bus 11D 120 volt ac Vitsi Bus 1A 120 volt ac Vital Bus 1B 120 volt ac Vital Bus 1C 120 volt ac vital Bus 1D' 120 volt ac vital Bus 1E 120 volt ac Vital Bus IF Non-Class 1_5 Buses 125 volt de Bus 12A l 125 volt de Bus 123 120 volt ac Bus 2A 120 voit ac Bus 25 120 volt ac Bus AA 120 volt ac Bus 43 120 volt ac Bus 5 l l i e I l l

snn.os 'ee 23:49 Gnf SEAB100K STATION - 9743 P.804 2 D $~C %qe z oR6 Page 2 H. H. Katz Item 1(a): " Identify and review the alarm and/or indication provided in the control room to alert the operator to the loss of power to the bus." Response: The buses listed above are provided with the following alarms in the main control room: Cisss 1-E Buses 125 vol_t_ de vital Bus 11A, 11B, 11C, & 11D Bus Voltage Low (Separate alarms for 125 V de Bus 11A,11B,11C & 11D). 'Separata alarms for Aav cc mus lia, AAm, liG = AAu). - L::e ef 100 vwAt ac to matracy Char; re (? 7: rete z f:: Ch. ps- _ _1 ', !!, 10- E IS) _ 120_ volt ac Vital Bus 1A, IB, 1C, 1D, 1E & 1F Bua Voltage Lost (Separate alarma for 120 V ac vital Bus 1A,1B,1C, 1D, 1E & 1F) ( R". r round-d (Cepe ;t: 212._ fus 120 i au vAsaA cus AA, Aa, IC ~ a. u c. Non-Class 1-E Buses 1_2_5 voit de Instrument Bus 12A, 12B i Bus Voltage Low (Separate alarms for 125 V de Bus 12A,125) Bus Voltage Lo-Lo n n n n u n u n n gu _ c_ _..., g -Lors sf '*C " sit ;; t: 3etterj Cb=eg=-- (' ;:::t; cler,::s-TUY chargars % t. C)_ 120 volt ac Instrument Bus 2A; 25, 4A, 43, 5 ~ Bos %lfa c Lost (Sepevok obms b-ZA,2E,4^*46*I ~ Inverter (sed fcum L. i t. c, (C^~-er A1=r- #^ % a o _ 3eparass sv - u .a

1. 3 }

-21:= fer 3" _95 W > r'1ws Ma s m (Cvww Ma s fer Eu; 2A $ LA C'T 8 "- t hw G r-- d e rG Jor-Bas-2 B-t-4)- -UP3tarjor1Liarm-{dw-u Alarm-for-Rua c cr alasw ?A A AA c (Tmr*re-r trio) ate eau _4,,_ge, 3 ;_ g) Vacione Inv.. i.. Tscubic-Alerme--(he-5)-- Item 1(b): " Identify the Instrument and Control System Loads connected to tna bus and evaluate the effects of loss of power to these loads including tha ability to achieve a cold shutdown condition." ( Responset Review of the abova question is addressed in the following two sections: 1 I 1

92o. So 3ofO jC Page 3 H. H. Ka ta Class 1-E 125 VDC & __120 VAC (Vital) Busea A description and one line diagram of the 125 VDC vital system and the 120 VAC vital system is contained in FSAR Section 8.3 and Figures A list of I&C loads dedicated 8.3-2, 8. 3-3, 8.3 'f,@ basis) is attachad. to usfe shutdown (on a system Because of the redundancy of information and controls available to the operator, f ailure of any single bus vill not af fect the ability to achieve a cold shutdown condition. Non-Class 1-E 125 VDC and 120 VAC Instrument Buses A description and one line diagram of the 125 VDC system and the 120 VAC system is contained in FSAR Section 8.3 and Figures 8.3-2, These buses are not required 8.3-38,

• rid d wgt 765-F.3n oo S 4.

for safe shutdown. " Describe any proposed design modifications resulting from these reviews and evaluations and your proposed se hedule for imple-Item 1(c): mancating those modificationa". Response s Class 1-E 125 VDC and 120 VAC Class 1-E (Vital) Buses. Due to the redundancy noted in the response to Item 1(b), no design modifications are required. Non-Class 1-E 120 VAC Instrument Buses the safe shutdown No design modifications are required to ensure capability. "Prepara emergency proceduras or review existing ones that will be used by control room operators, including procedures required to Item 2: achieve a cold shutdown condition, upon loss of power to each 1-E and Non-Class 1-E bus supplying power to safety and Class The emergency non-saf ety related instrument and control syntama. procedures should include: The diagnostics / alarms / indicators /symptoma resulting from the review and evaluation conducted per item 1 above. a. The use of alternate indication and/or control circuits which may be povered from other Non-Class 1-E or Class b. 1-E instru=entation and control buses. l. 4 H011U15 )s00 sew 35 two writt es. CO*NWT ' ~ ~ 09/A

42C.fC 7%e 4 eS 6 [ Page 4

8. H. Kate Methods for restoring power to the bus.

c. Describe any proposed design modification or administrative controls to be implemented resulting from these procedures. and your proposed ochedule for larplementing the changes." Review of the above question is addressed in the following two Fasponse: sections: 1-E 125 VDC and 120_VAC Vital Buses _ Class Due to the redundancy noted in reply to Item No.1(b) for all instrumant and control systems on Class 1-E Buses, and due to 1(a), alarms provided on these buses as described in reply to Ite'n No. no modifications to design or procedures are deemed necessary to these systems to ensure the capability to bring the plant to a required cold shutdown condition. Power may be restored to the vital 120 volt ac bua, in the event of loss of supply due to (loss of AC inverter input and, loss of DC inverter input) E nverter failure, by manually tranafarring the bus supply to the (non-vital) maintenance supply (transf er is nada at the i i switchgear). f loss Power may be restored to the vital 125 Volt do bus, in the event o f DC of supply due to loss of AC supply to the rectifier and_ loss o 3 supply to the bus, by (example, bus 11A loss of Power) manually trans-(bua 11A) supply to the normal supply for (bus 11C) ferring the (transf er is made at the de switchgear). Non-_ Class 1-E 125,VDC and 120 VAC Instrument Bus 5 Due to the alarms provided on these buses as desc These bdses are not_, requited 'for safer shutdown'. necessary. Power may be restored co' the n'on-vitsi 120' Volt f the inverter) and_ and_ f ailure of the de inverter input) g f ailure o f ailure of the static transfer evitch, by manually bypassier the static switch, thereby transferring bus supply to the alternate v. iource, (transfer is mada at the switchgear). (4A or 4B) in Power may be restored to the non-vital 120 volt oc bus (2A or 2B) by manually the event of loss of supply from the feeder bus feeder bus transferring the bus (4A or 4B) supply to the alternataShedding of certain (2A or 2B) (transfer de made at the switchgear). ( non-vital loads nay be required to accomodate this transfer. g N. 1946 - M0!!W15 200uSW35 LW9 Ctsit se. Ca*HW

42Gro Mage I chb Page 5 H. H. Katz ) using the Power may be restored to the non-vital 120 Volt ac bus (5 i bus (2A or 23). same procedure as for the non-vital 120 volt ac (12A or 12B) Power will be supplied to tha'.aonwitel.125 Volt de bus. f the AC source in the event of loss of normal supply due to failure oWhen main control o_r_ the battery charger, by the backup batteries.the bus is being fed fr room indication is received that batteries, provisions may be made to connect a portable charger to the bus, l power bus during the time period required to restors the norma supply (connection is made at the switchgear). "Re-review IE Circular No. 79-02, Pailure of 120 Volt Vital AC l

11. 1979, to include both C ass I_cen 3:

Power Supplies, deced January 1-E and Non-class 1-E saf ety related power supply invarters. i of Based on a review of operating experience and i l f the or administrative controls to be implemented as a resu t o re-review." ddress both Our response to IE Circu1=r 79-02 has been modified to a

Response

vital and non-vital inverters. hr ~ ~~ R. P. Neustadter' Supervising I&C Engineer RPN/JRL/ars l l l l - 84011W15 30088w35 iWO 9ZelZ se, GO'NUf l C946

420.SO %C b o? O . REMOTE SWTDOWN I & C LOADS F0WERED BY 120 6 125 V INSTRUVihT BUSES I esa FIGURE i l .EL3 C...] Team! Ed_S _2AliE.t_ Cki 1HUTDovh4.L OAD..I I l CP 108 A M. ..!b . 2...l.h.. b M6.. PisREL___ _ _......... l ' CP l O B B ' B.,li..) F i itF '2. R c,S_ N.e t_ .__3 3 RC sysTerA A l... \\ l A. _ ' u.2. A..l.. i ?S.S.r.kis_. _ _ _. O. u. i CC SYSTEM O..LA. _n A u2 /h._..t..L....Rss..ckas.. MS SYSTEM

A

.t.t A. LuzA.13 .RSS Ckts. ._...h..O i MS SYSTEM i i _._Mo _A !tiA LLL2 ALiM i aes.cxu i Rt SYSTEM i 1.J31 i B_ ! 11 B ' \\ \\2.B.'..\\ Ras tvas I cc sys,em . E.2 'R.,il..B__i112B...ll RS.S__. CKt s....... _. Ms Sysrem i .H 2_ _. B ;!. i l B....; t i2-B l l 4 I Rss Ckts l l I t .i 1, t l i i 1 i i i l i L_ l c (~. RSS = Remote 6m Sau tzw C946 - M0!!W15 20059W35 twe it e tt 88. Ce*NWT ~~~~~

A2o.so7%;e 7 ef 8\\ CF Cole 06UO J Casoleri 0609 VR Morrison 14U7 DH Rhoads 06UO DD Boyle 06U9 MP Hanson Field AW Col. 06U0 NE Flora /JK Shaw 06U9 JF Vought Field 06U0 CH Aggarwel/A5 Calahan 05U7 Field DCC Field LS Nascimento 06U4 RA Mabry/LL Tipton 05U9 RJ Phelps Field < WE Kaug f AJ Huishiser/WH Reading 06U4 DE Mc Caig 02UO JR Whitaker Field S Kasturi/G Trautman 06U5 ER Case, II 02U1 P Howard-Johnson Boston in NH Kats 06U5 JR Diaytryk 12U4 Serial File 06U1 $ JJ Parisano 06U6 WC Stevenson/CC Cipra 12U6 DA Fertig 06U1 NB Pauling/WJ Breslin 06U7 5 Tiannaraju 14U4 Decembe r 7, 1979 SBU-32335 Ref. SB-7219 No Response Required Aewh..a 2. +, MM#86$ A Mr. John Devincentis, Project Manager Yankee Atomic Electric Company Seabrook Station 20 Turnpike Road Westborough, Massachusetts 01581 Dear Mr. DeVincentist Public Service Company of New Hampshire Seabrook Station Units 1 and 2 NRC CIRCUIAR 79-02 We have reviewed the subject NRC circular and offer the following response to questions raised in the'NRC circular, ,w The W units trip only the 480V AC input lines on high DC voltage at the in-1. The DC supply from the battery will still be available to the inverter. verter. The fuse which we Transformer tap settings will be set before startup. 2. believe corresponds to the one that blew in one of the Arkansas Nucisar one units (inverter fuse) is rated at 250 amps in the W unit which we feel is adequate. An alternate source is provided at Seabrook for a maintenance bypass 3. around the inverter. No. auto transfer is provided. 4. Administrative controls are to be set up by YAEC. If you have any questions on the above please contact us. Very truly yours, 'G. F. Cole Project Manager GMA/G'nH:amk Messrs. J. DeVincentis - YAEC 4L cc: B. B. Backley - PSNK 3L (.'*- J. D. Haseltine-PSNK IL ' ~ J. H. Herrin - PSNR/YAEC Field Office IL (

k20.50 3C b Obb MEMORANDUM l a consmco* M / O m cc: Philadelphia c No. 9763.006 DaTEi March 2, 1982 O cer. Power / Engineering CoricS D. H. Rhoads To; J. R. Lindquist H. H. ht: File 9.1.3 At +a-seb" *" No Response Required R. P* Neustadter FROM: Public Service Coc:pany of New Ha=pshire SusJect: Seabrook Station - Units 1 & 2 Response to IE Circular 79-02 Applicability to Non-Vital Inverters The Seabrook design for non-vital inverters is acceptable in light of the Circular 79-02 concerns, because: No time delay circuitry is used in the DC undervoltage trip circuit 1. of the Exide inverters. Transformer tap settings are fixed and,have been optimized for 2. the UPS systam by the vendor and will be verified during system startup. I The non-vital inverter system incorporates a static switch for \\ The static 3. uninterrupted transfer of load to the bypass source. switch control senses the UPS condition and determines acceptability of restarting the inverter af ter a bypass transf er. The proper administrative controls are to be established by TAEC. 4. ) i JJ R 6? StWA ~k. P. Ne'6stadter Supervising I&C Engineer RPN/JRL/ars l l I C8*NWf E946 - HollW15 20058W35 IW9 6EstE OS. ~}}