LR-N18-0053, Revision 30 to Updated Final Safety Analysis Report, Appendix a, TMI Lessons Learned

Revision 30 to Updated Final Safety Analysis Report, Appendix a, TMI Lessons Learned

ML18220A926
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Site:	Salem
Issue date:	05/11/2018
From:	Public Service Enterprise Group
To:	Office of Nuclear Reactor Regulation
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ML18220A885	List: LR-N18-0053, Revision 30 to Updated Final Safety Analysis Report, Appendix a, TMI Lessons Learned
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LR-N18-0053
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APPENDIX A TMI LESSONS LEARNED SGS-DFSAR Revision 6 February 15, 1987

APPENDIX A TMI LESSONS LEARNED TABLE OF CONTENTS Sectign/NVREG-0578 Item No.

INTRODUCTION A-iv 2.1.1 Pressurizer Power Sources A-1 2.1.2 Relief and Safety Valve Testing A-6 2.1.3.a Relief and Safety Valve Position Indication A-12 2.1.3.b Instrumentation for Inadequate Core cooling A-14 2.1.4 Containment Isolation A-20 2.1.S.a Dedicated Containment Penetrations A-25 2.1.s.c Hydrogen Recombiners A-26 2.1.6.a Leakage Outside Containment A-27 2.1.6.b Shielding Review A-32 2.1.7.a Auxiliary Feedwater Initiation A-44 2.1.7.b Auxiliary Feedwater Flow Indication A-47 2.1.8.a Post-Accident sampling A-49 2.1.8.b Increased Radiation Monitoring Range A-51 2.1.8.c In Plant Iodine Instrumentation A-56 2.1.9 Analysis of Accidents and A-58 Instrumentation to Follow Containment Conditions Reactor coolant System Vente 2.2.1.a Shift Supervisor's Responsibilities A-67 2.2.l.b Shift Technical Advisor A-69 2.2.1.c Shift Turnover Procedures A-70 2.2.2.a Control Room Access A-72 2.2.2.b Onsite Technical Support Center A-74 2.2.2.c Onsite Operational Support center A-80 A-i SGS-UFSAR Revision 6 February 15, 1987

LIST OF TABLES Table A-1 Deleted A-2 Deleted A-3 Deleted A-4 Dose Rates OUtside Containment Following a Design Basis LOCA in Salam Unit 1 A-5 Dose Rates OUtside Containment Following a Design Basis LOCA in salem Unit 2 A-ii SGS-UFSAR Revision 16 January 31, 1998

LIST OF FIGURES Figure A-1 Deleted A-2 Deleted A-3 Deleted A-4 Deleted A-5 Deleted A-6 Deleted A-iii SGS-UFSAR Revision 14 December 29, 1995

INTRODUCTION The information in Appendix A addresses lessons learned from the accident at Three Mile Island (TMI), Unit 2. The material is organized specifically in response to NUREG-0578, "TMI-2 Lessons Learned Task Force Status Report and Short-Term Recommendations." Two items (Instrumentation to monitor containment conditions and reactor coolant system vents) were not included in NUREG-0578, but were later incorporated as lessons learned by the Director of Nuclear Reactor Regulation.

Item numbering in this Appendix corresponds with that of NUREG-0578. For each item, the NRC recommendation is first stated, followed by the Public Service Electric & Gas (PSE&G} response.

A-iv SGS-UFSAR Revision 6 February 15, 1987

2.1.1 Pressurizer Power Sources Emergency Power Supply Requirements for the Pressurizer Heaters, Power-Operated Relief Valves and Block Valves, and Pressurizer Level Indicators in PWRs NRC Position Consistent with satisfying the requirements of General Design Criteria 10, 14, 15, 17, and 20 of Appendix A to 10CFR50 for the event of loss of offsite power, the following positions shall be implemented:

Pressurizer Heater Power Supply

1. The pressurizer heater power supply design shall provide the capability to supply, from either the offsi te power source or the emergency power source (when offsite power is not available), a predetermined number of pressurizer heaters and associated controls necessary to establish and maintain natural circulation at hot standby conditions. The required heaters and their controls shall be connected to the emergency buses in a manner that will provide redundant power supply capability.

2. Procedures and training shall be established to make the operator aware of when and how the required pressurizer heaters shall be connected to the emergency buses. If required, the procedures shall identify under what conditions selected emergency loads can be shed from the emergency power source to provide sufficient capacity for the connection of the pressurizer heaters.

3. The time required to accomplish the connection of the preselected pressurizer heater to the emergency buses shall be consistent with the timely initiation and maintenance of natural circulation condition.

A-1 SGS-UFSAR Revision 6 February 15, 1987

4. Pressurizer heater motive and control power interfaces with the emergency buses shall be accomplished through devices that have been qualified in accordance with safety grade requirements.

Response

The Salem design is such that it has the capability to manually connect approximately 800 kW of pressurizer heaters from two backup groups to the emergency power source. These connections are accomplished by an installed manually operated interlocked transfer scheme between the pressurizer heaters and the "A" diesel generator and the "C" diesel generator.

An analysis performed by Westinghouse indicates that 150 kW of pressurizer heaters is needed to assure maintenance of natural circulation. These backup heater groups will be manually set up such that only 150 kW can be supplied from each vital bus. Each redundant heater group has access to only one Class 1E division power supply. Motive and control interfaces with the vi tal buses will be through safety grade circuit breakers.

Emergency Operating Procedures address the transfer of the heaters to the vital I buses.

The diesel generators are capable of supplying the 150 kW of pressurizer heaters concurrent with the equipment loads required for a loss-of-coolant accident (LOCA) . The diesel loads during the injection phase (with the inclusion of the pressurizer heater load) would be slightly above the 2000-hour rating but well below the 30-minute rating. Under blackout conditions, the diesel generators have sufficient capacity to supply the required equipment loads including the pressurizer heaters and meet the continuous diesel rating.

The connection of the pressurizer heaters to a vital bus is through a normally open Class 1E circuit breaker. This circuit A-2 SGS-UFSAR Revision 16 January 31, 1998

breaker is mechanically key interlocked with the heaters' normal, non-vi tal power feed circuit breaker. A manually operated disconnect switch must also be closed to make the connection. In addition, the backup group heaters are set up to supply only 150 kW. Once the connection pathway is established manually, the final connection of the pressurizer heaters to the vi tal bus (open/ close the Class 1E circuit breaker) can be accomplished in the Control Room. The setup of the vital bus feed to the pressurizer heaters can be completed in a time frame consistent with maintenance of natural circulation.

The manual action of opening the non-vi tal pressurizer heater supply circuit breaker prior to closing the vital power supply circuit breaker by mechanical key interlocks is necessary to eliminate any possibility of feeding other non-vital loads from the vital power supply.

It is not necessary that certain equipment loads be shed in order to connect the pressurizer heaters to the vital buses. As a precaution, statements will be added to the operating procedures alerting the operator to remain within the appropriate diesel ratings.

The diesel generator ratings are included in the Emergency Operating Procedures. Connection of the pressurizer heaters to the vital buses does not require the reset of an SI signal.

The pressurizer heaters are not automatically tripped from the vital buses upon a safety injection actuation signal. An event where the pressurizer heaters are on the vital buses when a LOCA occurs is a highly improbable occurrence.

Normal operation of the heaters does not and will not require their supply from the vital buses. They will only be needed when normal power is lost (blackout). A LOCA would have to occur following a blackout during which time it became necessary to operate the heaters to maintain natural circulation.

A-3 SGS-UFSAR Revision 16 January 31, 1998

Power Supply for Pressurizer Relief and Block Valves and Pressurizer Level Indicators

1. Motive and control components of the power-operated relief valves

( PORVs) shall be capable of being supplied from either the offsi te power source or the emergency power source when the offsite power is not available.

2. Motive and control components associated with the PORV block valves shall be capable of being supplied from either the offsi te power source or the emergency power source when the offsi te power is not available.

3. Motive and control power connections to the emergency buses for the PORVs and their associated block valves shall be through devices that have been qualified in accordance with safety grade requirements.

4. The pressurizer level indication instrument channels shall be powered from the vital instrument buses. These buses shall have the capability of being supplied from either the offsite power source or the emergency power source when offsite power is not available.

Response

The pressurizer PORVs and their associated block valves are powered from the emergency power source. Motive and control power interfaces with the emergency power source satisfy safety grade requirements.

The design of the pressurizer relief and block valve arrangement for both Salem units was predicated on ensuring the ability to relieve. This concept resulted in providing two parallel relief paths which are completely independent and redundant. Such a design concept is necessary to provide protection for anticipated A-4 SGS-UFSAR Revision 6 February 15, 1987

transient without SCRAM (ATWS) conditions, for pressurizer water-solid conditions due to inadvertent operation of the safety injection system events, and low temperature overpressure transients.

Incorporation of complete independence between the relief valve and block valve would negate the system's ability to meet the single failure criterion for the events identified above. The existing design, however, does incorporate the use of diverse power supplies for the PORVs and their associated block valves.

The relief valves are supplied by Class 1E, 125 V de systems while the block valves use 230 V and 115 V vital ac.

Pressurizer level indication instrument channels are powered from the vi tal instrument buses.

A-5 SGS-UFSAR Revision 17 October 16, 1998

2.1.2 Relief and Safety Valve Testing Performance Testing for BWR and PWR Relief and Safety Valves NRC Position Pressurized water reactor (PWR) and boiling water reactor licensees and applicants shall conduct testing to qualify the Reactor Coolant System relief and safety valves under expected operating conditions for design basis transients and accidents. The licensees and applicants shall determine the expected valve operating conditions through the use of analyses of accidents and anticipated operational occurrences referenced in Regulatory Guide 1. 70, Revision 2. The single failures applied to these analyses shall be chosen so that the dynamic forces on the safety and relief valves are maximized. Test pressures shall be the highest predicted by conventional safety analysis procedures. Reactor Coolant System relief and safety valve qualification shall include qualification of associated control circuitry piping and supports as well as the valves themselves.

Response

1. Safety and Relief Valves Public Service Electric & Gas (PSE&G) is a participant in the Generic PWR Safety and Relief Valve Test Program implemented by the Electric Power Research Institute (EPRI) at the request of participating PWR utili ties in response to the USNRC recommendations for safety and relief valve testing.

The primary objective of the Test Program was to provide full scale test data confirming the functionability of primary system PORVs and safety valves for expected operating and accident conditions. The second objective of the program was to obtain sufficient piping thermal A-6 SGS-UFSAR Revision 6 February 15, 1987

hydraulic load data to perrni t confirmation of models which may be utilized for plant unique analysis of safety and relief valve discharge piping systems. Relief valve tests were completed in August 1981 and safety valve tests were completed in December 1981.

The reports prepared by EPRI documenting the Test Program results are as follows:

"Valve Selection/Justification Report" This report documents that the selected test valves represent all participating PWR plant safety and relief valves. Salem PORVs are 2-inch NPS Copes Vulcan valves with 17-4PH plug and cage. Three-inch Copes Vulcan valves similar to the Salem valves were tested in a configuration similar to that of the Salem Station. Salem safety valves are 6M6 Crosby valves which were tested in a configuration similar to that at the Salem Station.

"Test Condition Justification Report" and the "Westinghouse Plant Condition Justification Report" These reports document the basis and justification of the valve test conditions for all participating PWR plants. The PORV fluid conditions, safety valve fluid conditions and cold overpressurization conditions at Salem are enveloped by the test conditions.

"Safety and Relief Valve Test Report" This report provides evidence demonstrating the functionability of the selected test valves under the selected test conditions for all participating PWR plants. Tests conducted on the relief valve have confirmed that the valve opened and closed on demand and A-7 SGS-UFSAR Revision 6 February 15, 1987

that the valve suffered no damage that would preclude future operation. Requirements for the pressurizer power-operated relief valves are addressed in UFSAR Chapter 15.2.14, "Spurious Operation of the Safety Injection System at Power".

Although the tests indicated acceptable valve performance, test valve disassembly showed galling of the cage and plug guiding surfaces. In view of this, the internals of Salem Units 1 and 2 PORVs have been changed to 316 stellited plugs instead of 17-4PH. The Salem valves with this combination of internals have shown no indication of leakage or galling.

The safety valves were shown to open and close. The functionability of the valves to provide overpressure protection for the Final Safety Analysis Report (FSAR) events was found to be adequate (1). However, depending upon the test conditions (steam- transition- water), the valves were shown to flutter and/or chatter during loop seal discharge. The observed instability of the safety valves during loop seal discharge has been evaluated by Westinghouse and PSE&G and is not considered to be a safety concern.

Upstream piping and valve ring adjustments have been shown to have a substantial effect on valve performance. Performance of the Salem safety valves during steam discharge conditions has been judged stable through the use of a valve dynamic model developed by Continuum Dynamics, Inc. ( 2) . The model also predicted blowdown of less than 10 percent which is considered acceptable. Liquid discharge challenges to safety valves are predicted to occur significantly less frequently than a LOCA and the consequences of such liquid discharge are much less severe; liquid discharge from the Salem safety valves has been shown to be an unlikely event (3). Thus, safety valve liquid discharge is an insignificant safety concern when compared with FSAR transient events.

A-8 SGS-UFSAR Revision 17 October 16, 1998

"Application of Relap 5/MOD 1 for Calculations of Safety and Relief Valves Discharge Piping Hydrodynamic Loads" This report presents an analytical model benchmarked against test data that may be used for plant unique analysis of safety and relief valve discharge piping systems.

During a portion of the tests performed on safety valves, it was noted that the pressure upstream of the valve tended to oscillate, especially for loop seal configurations. These oscillations are thought to be related to valve instability which, in turn, is related to the valve and the inlet piping parameters. The tests that exhibited pressure oscillations are summarized in Volume 10, Section 4, of the EPRI Safety and Relief Valve Test Report.

For the test configuration that most nearly approximates the Salem configuration, it was determined that a maximum peak transient pressure of 6300 psi was experienced. An analysis of the expected behavior of the Salem 1 and 2 safety valve inlet piping assuming unstable valve behavior has been performed. The analysis indicates that the peak transient pressure for Salem 2 will be less than the test value (6300 psi) whereas the expected peak transient pressure for Salem 1 will be below 7100 psi. When compared with ASME Code allowables, it was determined that the pressure pulses are within acceptable limits. (The maximum permissible pressure for the inlet piping is calculated to be 7130 psi for Westinghouse.) Necessary inspection of the inlet piping subsequent to a safety valve discharge will be instituted to comply with the ASME requirement. Hence, the review of inlet pressure oscillations indicates no safety concern.

A-9 SGS-UFSAR Revision 6 February 15, 1987

EDS- Impell Corporation was retained by PSE&G to perform Salem plant specific analysis based on the EPRI test results. The thermal hydraulic analysis performed by Impell indicated that to make the pressurizer piping code compliant, the piping supports would have to be strengthened. To minimize the magnitude of discharge piping forces on a safety valve actuation, also required was encapsulation of the loop seals in insulation boxes so that loop seal water will be at a higher temperature.

The following modifications were completed at Salem to ensure the discharge piping integrity and in turn the safety valve operability.

At Salem 1, 18 new supports were added and 33 supports were modified.

At Salem 2, 42 new supports were added and 27 supports were modified.

Subsequently, further analysis was performed for both Salem Units 1 and 2 as a result of concerns raised by the NRC in their Safety Evaluation Report of PSE&G's response to NUREG-0737, Itemii.D.1, Sections 1. 2. 3 and 1. 2. 8. Engineering analysis of the Pressurizer Safety Valve piping and Power Operated Relief Valve piping for Salem Units 1 and 2 indicated that the Pressurizer Safety Valves (SVs) and the Power Operated Relief Valves (PORVs) discharge piping and welded attachments exceeded code allowable stress levels after actuation. The current PORV and SV inlet piping configuration allows steam from the pressurizer to fill the inlet piping and then condense to form a water seal. These water loop seals have been identified as a major contributor to exceeding the allowable stress levels.

A-10 SGS-UFSAR Revision 14 December 29, 1995

Analysis was performed for Salem Units 1 and 2 to verify that the discharge pipe stresses are within code allowable limits with no water loop seals present. This was accomplished by a modification to remove the water loop seals of the SVs and the PORVs, by continuously draining the condensation on the upstream side of the PORVs and SVs back to the pressurizer liquid space. This required the installation of drain lines from the upstream side of the PORVs connecting to the existing drain lines on the SVs loop seals. A new line was added to connect the drain lines to the Pressurizer liquid space.

As a result of eliminating the water loop seals for the PORVs and SVs, the valve internals are subjected to a saturated steam environment.

The safety valve internals were modified to ensure against leakage.

The PORV internals and materials were changed. Also, it is no longer required to maintain the SV loop seals in a heated condition, and therefore the heat boxes and associated temperature instrumentation were permanently removed.

In addition, the modification for Salem 2 includes the installation of 8 new supports on the drain line piping system, modification to 4 supports and modification to a pressurizer support column. Unit 1 modification includes the installation of 6 new supports on the drain line piping system, modification to 5 supports and modification to a pressurizer support column.

2. Block Valves Salem block valves are 3-inch Velan valves with SMB-00-15 motor operators which were tested by EPRI at the Marshall Facility. The Velan valve fully opened and closed on demand for each of the 21 test cycles (4). No operability concern has been identified.

3. ATWS Testing Results from the current program are likely to provide most of the information necessary to address ATWS events (i.e., relief capability at high pressures).

A-lOa SGS-UFSAR Revision 15 June 12, 1996

THIS PAGE INTENTIONALLY LEFT BLANK A-lOb SGS-UFSAR Revision 13 June 12, 1994

References for Section 2.1.2

1. "Review of Pressurizer Safety Valve Performance as Observed in the EPRI Safety and Relief Valve Test Program," Westinghouse Report WCAP-10105.

2. "Valve Dynamic Model Performance Simulation for the Salem PWR Plant Unit 1," Report No. 82-19 from Continuum Dynamics, Inc.

3. "Results of Probabilistic Evaluation of Liquid Discharge Challenges to Salem Units 1 and 2 Safety Valves," Report 1-231-01-052-00 from Science Applications, Inc.

4. "EPRI PWR Safety and Relief Valve Test Program - PORV Block Valve Information Package."

A-ll SGS-UFSAR Revision 7 July 22, 1987

2.1.3.a Relief and Safety Valve Position Indications Direct Indication of Power-Operated Relief Valve and Safety Valve Position for PWRs and BWRs NRC Position Reactor system relief and safety valves shall be provided with a positive indication in the control room derived from a reliable valve position detection device or a reliable indication of flow in the discharge pipe.

Response

Each PORV is equipped with a limit switch to provide an alarm in the Control Room if the PORV is not fully closed. These switches are seismically and environmentally qualified.

To provide positive indication of safety valve position, an environmentally qualified limit switch is mounted in each safety valve bonnet which will indicate open and closed position in the Control Room.

Both of the above schemes utilize a single switch on each valve powered from a vital bus. Several reliable backup methods are available to detect an open valve. These methods, which are addressed in Emergency Procedure EI 4. 24, "Malfunction of Pressurizer Relief Valve," are the following:

1. Pressurizer pressure

2. Valve discharge piping temperature

3. PRT level, pressure and temperature

4. PORV open/close indication in conjunction with PORV block valve open/close position indication A-12 SGS-UFSAR Revision 6 February 15, 1987

5. Control Room alarms for all of the above indicators A-13 SGS-UFSAR Revision 6 February 15, 1987

2.1.3.b Instrumentation for Inadequate Core Cooling Instrumentation for Detection of Inadequate Core Cooling in PWRs BWRs NRC Position

1. Licensees shall develop procedures to be used by the operator to recognize inadequate core cooling with currently available instrumentation. The licensee shall provide a description of the existing instrumentation for the operators to use to recognize these conditions. A detailed description of the analyses needed to form the basis for operator training and procedure development shall be provided pursuant to another short-term requirement, "Analysis of Off-Normal Conditions, Including Natural Circulation" (see Section 2.1.9).

In addition, each PWR shall install a primary coolant saturation meter to provide online indication of coolant saturation and condition.

Operator instruction as to the use of this meter shall include consideration that it is not to be used exclusive of other related plant parameters.

2. Licensees shall provide a description of any additional instrumentation or controls (primary or backup) proposed for the plant to supplement those devices cited in the preceding section giving an unambiguous,easy-to-interpret indication of inadequate core cooling. A description of the functional design requirements for the system shall also be included. A description of the procedures to be used with the proposed equipment, the analysis used in developing these procedures, and a schedule for installing the equipment shall be provided.

A-14 SGS-UFSAR Revision 6 February 15, 1987

Response

The existing instrumentation in the Control Room is sufficient to recognize inadequate core cooling. The indications available for verification of core heat removal are:

1. Reactor Coolant System (RCS) ~T less than full load ~T.

2. RCS or core exit thermocouple temperatures constant or decreasing.

3. Stearn generator pressure constant or decreasing at a rate equivalent to the rate of decrease of RCS temperatures while maintaining steam generator level with continuous auxiliary feedwater.

A further guide for recognition of inadequate core cooling is a computerized subcooling monitor. The margin to saturation calculation is performed in a micro-processor supplied by Combustion Engineering. RCS pressure and core exit temperatures are inputted and compared to a standard steam table to calculate the actual margin to saturation. The margin to saturation is then adjusted automatically by the subcooling margin monitor computer to compensate for instrument channel inaccuracies. This provides the operator with reasonable confidence that the RCS fluid will be subcooled at the core exit whenever a positive margin to saturation is indicated by the subcooling monitor.

Continuous digital and recorder displays of margin in °F are located in the main control room. Control room annunciators provide alarm at 10°F margin decreasing. Emergency Operating Procedures and Operations Procedures have been revised to address the use of this processor output.

Public Service Electric & Gas is a member of the Westinghouse Operating Plant Owners' Group. Westinghouse, under the direction of the Westinghouse Owners' Group, is performing further analyses to aid in selection of more direct indicators of inadequate core A-15 SGS-UFSAR Revision 16 January 31, 1998

cooling, and to serve as a basis for augmented emergency procedures.

A preliminary report on adequate core cooling was submitted to the NRC on October 30, 1979 by the Westinghouse Owners' Group. The Salem Emergency Procedures were revised on an interim basis to specify precautions and operator actions to recover from a condition in which the core has experienced inadequate cooling. The station procedures will be further updated after completion of the final Owners' Group report.

A device to indicate reactor vessel water level has been installed in Units 1 and 2. This device is similar to the proposed Westinghouse design for Virginia Power's North Anna plant.

The instrumentation for monitoring inadequate core cooling conforms to NUREG-0578, NUREG-0737 and the letter from H. R. Denton to all operating plant licensees, dated October 30, 1979. If the devices were to fail, backup parameters, such as, RCS pressure and temperature, steam generator level, and auxiliary feedwater flow are available to enable determination of adequate core cooling. The existing procedure and availability of alternate indications is sufficient to ensure proper determination of core cooling adequacy.

The following is an evaluation of conformance of the ICC Instrument System to NUREG-0737, Item II.F.2, Attachment 1 entitled, "Design and Qualification Criteria for Pressurized-Water Reactor In core Thermocouples." Paragraph numbering corresponds to that of Attachment 1:

1. There are 58 in-core thermocouples, with a minimum of ten in each quadrant and an additional seven A-16 SGS-UFSAR Revision 23 October 17, 2007

thermocouples shared with two adjoining quadrants to provide indication of radial distribution of temperature rise across representative regions of the core. See Section 7.

2. Primary Operator Displays The plant computer and SPDS are the primary displays. Additional description of SPDS is found in Section 7.10.

a. A core map for each quarter of the core is available to the operator on demand on the computer output CRT. The core map gives the temperature at each core exit thermocouple location in that quarter of the core.

b. The core map will give the location of the hottest in-core thermocouple. This hottest in-core thermocouple reading is the basis for the subcooling calculations and procedures.

c. There is direct readout and hard copy capability for all thermocouple temperatures. The range extends from 30°F to 2200°F.

d. Trend capability for the thermocouples is available on demand on the trend printer located on a vertical panel in the control room.

e. Alarm capability is provided consistent with operator procedure requirements: when reactor power <0. 25 percent, alarm at 1200°F; when reactor power >0.025 percent, alarm at 630°F.

f. The operator display device is human factor designed.

3. A backup display is available which meets the stated requirements as follows:

A-17 SGS-UFSAR Revision 23 October 17, 2007

All thermocouples may be read, but only one at a time. The range is The readout meter on the Core Exit Thermocouple Processing Cabinet is located in a room adjacent to the Control Room and will allow the operator to read 16 thermocouples within a time interval of less than 6 minutes. The backup display is referenced in the emergency procedures.

4. The primary display CRT is located on the control console. The hard copy and trend displays are located on the console or on a vertical panel in the control room.

5. The instrumentation meets the stated design and qualification criteria for accident monitoring instrumentation. See Items 6 through 9 below.

6. The primary display channel utilizes the station computer which is energized from an uninterruptible power supply. The primary CRT display and printers which supply direct digital readout and trend capability are also energized from the same power supply. The primary display channel and associated hardware are Class 1E.

The backup display is supplied from redundant station power sources.

The backup display and hardware are not Class 1E.

The reference junction heater power is derived from the same source as the backup display.

7. The in-core thermocouples are environmentally qualified as required in Appendix B (to NUREG-0737), Item 1. The computer and display have not been environmentally qualified or seismically qualified.

A-18 SGS-UFSAR Revision 23 October 17, 2007

8. The primary display channel uses a computer with an estimated reliability of 98 to 99 percent. The overall primary display channel reliability is 90 to 95 percent. The SPDS primary display and the backup display are designed to achieve 99% availability.

9. The in-core thermocouples are purchased to 10CFR50 Appendix B Quality Assurance requirements.

A-19 SGS-UFSAR Revision 23 October 17, 2007

2.1.4 Containment Isolation Containment Isolation Provisions for PWRs and BWRs NRC Position

1. All containment isolation system designs shall comply with the recommendations of Standard Review Plan ( SRP) 6. 2. 4; i.e., that there be diversity in the parameters sensed for the initiation of containment isolation.

2. All plants shall give careful reconsideration to the definition of essential and non-essential systems, shall identify each system determined to be essential, shall identify each system determined to be non-essential, shall describe the basis for selection of each essential system, shall modify their containment isolation designs accordingly, and shall report the results of there-evaluation to the NRC.

3. All non-essential systems shall be automatically isolated by the containment isolation signal.

4. The design of control systems for automatic containment isolation valves shall be such that resetting the isolation signal will not result in the automatic reopening of containment isolation valves.

Reopening of containment isolation valves shall require deliberate operator action.

Response

The containment isolation system complies with the requirement for initiation by diverse parameters as described in Section 6. 2. A number of isolation signals are provided for valve closure. Each signal is indicative of certain operating conditions and is A-20 SGS-UFSAR Revision 6 February 15, 1987

generated by diverse input parameters. The isolation signals and their input parameters are as follows:

Containment Isolation - Phase A

1. Manual actuation

2. High containment pressure

3. Low pressurizer pressure

4. High differential pressure between steam lines

5. High steam line flow coincident with low steam line pressure or Low-Low T

avg Containment Isolation - Phase B

1. Manual actuation

2. High-High containment pressure Containment Ventilation Isolation

1. Manual actuation

2. High containment pressure

3. Low pressurizer pressure

4. High differential pressure between steam lines

5. High steam line flow coincident with low steam line pressure or Low-Low T

avg

6. High containment radiation - particulate (Mode 6)

A-21 SGS-UFSAR Revision 13 June 12, 1994

7. High containment radiation- iodine

8. High containment radiation - gaseous Main Stearn Line Isolation

1. Manual actuation

2. High-High containment pressure

3. High steam line flow coincident with low steam line pressure or Low-Low T

avg Feedwater Isolation

1. Manual actuation

2. High containment pressure

3. Low pressurizer pressure

4. High differential pressure between steam lines

5. High steam line flow coincident with low steam line pressure or Low-Low T

avg

6. High-High steam generator water level

7. Reactor trip coincident with low T avg The Containment Isolation System isolates those systems which are not required for the mitigation of accidents specified in Section 15 of the FSAR. A review of Salem design has demonstrated conformance with these requirements.

The valves and systems isolated by the various isolation signals are indicated in Section 6.2. Isolation provision for all lines A-22 SGS-UFSAR Revision 6 February 15, 1987

penetrating the containment are described in Section 6. 2. All non-essential systems are either automatically isolated upon a containment isolation signal, or provided with non-return check valves, or closed during power operation and under adrninistrati ve control. Essential systems are not isolated since they are required to perform functions needed to maintain the plant in a safe condition following an accident. These essential systems are as follows:

1. Residual Heat Removal - Part of Safety Injection

2. Safety Injection

3. Containment Fan Coolers - Service Water

4. Stearn Supply to Auxiliary Feedwater Pump Turbine

5. Main Stearn Atmospheric Relief

6. Auxiliary Feedwater

7. Charging- Portion for Safety Injection The Westinghouse Owners' Group has prepared a report entitled "Classification of Lines Penetrating Containment and a Review of Containment Isolation Logic and Philosophy. " Salem conforms with the established essential/non-essential categories and recommended isolation provisions.

A review of the containment isolation valve Control Systems has been performed to verify that the valves remain closed upon resetting of the isolation signal until the operator takes deliberate action to reposition them.

Two instances, reactor coolant drain tank pump discharge line and pressurizer relief tank gas analyzer line, were discovered which A-23 SGS-UFSAR Revision 6 February 15, 1987

could result in inadvertent transfer of radioactive material from the containment.

The reactor coolant drain tank line is provided with two isolation valves, WL12 (inside containment) and WL13 (outside containment). Both of these valves are closed upon a containment phase "A" isolation signal. Upon a reset condition, WL13 will remain closed unless the operator takes action to change its position. Valve WL12 is provided with a number of automatic control signals which, if present, will cause the valve to reopen.

The pressurizer relief tank line is provided with two isolation valves, PR1 7 (inside containment) and PR18 (outside containment). Both of these valves are closed upon a containment phase "A" isolation signal. The valves can reopen following a protection system reset when in the auto-control mode. An open pathway would be established if both valves were in the auto-control mode.

Design changes have been implemented (for valves WL12, PR1 7, and PR18) revise the control circuitry to prevent these occurrences.

A-24 SGS-UFSAR Revision 14 December 29, 1995

2.1.5.a Dedicated Containment Penetrations Dedicated Penetrations for External Recombiners or Post-Accident Purge Systems NRC Position Plants using external recombiners or purge systems for post-accident combustible gas control of the containment atmosphere should provide Containment Isolation Systems for external recombiner or Purge Systems that are dedicated to that service only, that meet the redundancy and single failure requirements of General Design Criteria 54 and 56 of Appendix A to 10CFR50, and that are sized to satisfy the flow requirements of the recornbiner of Purge System.

Response

Each Salem unit incorporated two redundant, physically separated, permanently installed electric hydrogen recornbiners, located inside the reactor containment, as previously described in Section 6. 2. Each recornbiner was capable of maintaining post-accident hydrogen concentration in the containment below limit of flammability in air of 4 percent as previously noted in Section 6.2.

Requirements for the hydrogen recornbiners have been deleted based on Technical Specification Amendment numbers 281 and 264 to Facility Operating License numbers DPR-70 and DPR-75.

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2.1.5.c Hydrogen Recornbiners Capability to Install Hydrogen Recombiner at Each Light Water Nuclear Power Plant NRC Position

1. All licensees of light water reactor plants shall have the capability to obtain and install recornbiners in their plants within a few days following an accident if containment access is impaired and if such a system is needed for long-term post-accident combustible gas control.

2. The procedures and bases upon which the recornbiners would be used on all plants should be the subject of a review by the licensees in considering shielding requirements and personnel exposure limitations as demonstrated to be necessary in the case of TMI-2.

Response

Post-accident hydrogen control capability is described in the response to Item 2.1.5.a.

The procedure for use of the hydrogen recombiners, OI II- 15. 3. 1, "Hydrogen Recornbiner- Normal Operation," had been reviewed and revised as required.

Requirements for the hydrogen recornbiners have been deleted based on Technical Specification Amendment numbers 281 and 264 to Facility Operating License numbers DPR-70 and DPR-75.

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2.1.6.a Leakage Outside Containment Integrity of Systems Outside Containment Likely to Contain Radioactive Materials for PWRs and BWRs NRC Position Applicants and licensees shall immediately implement a program to reduce leakage from systems outside containment that would or could contain highly radioactive fluids during a serious transient or accident to as-low-as-practical levels. This program shall include the following:

1. Immediate Leak Reduction

a. Implement all practical leak reduction measures for all systems that could carry radioactive fluid outside of containment.

b. Measure actual leakage rates with system in operation and report them to the NRC.

2. Continuing Leak Reduction Establish and implement a program of preventive maintenance to reduce leakage to as-low-as-practical levels. This program shall include periodic integrated leak tests at a frequency not to exceed refueling cycle intervals.

Clarification Licensees shall, by January 1980, provide a summary description of their program to reduce leakage from systems outside containment that would or could contain highly radioactive fluids during a serious transient or accident.

Examples of such systems are given on Page A-26 of NUREG-0578. Other examples include the Reactor A-27 SGS-UFSAR Revision 6 February 15, 1987

Core Isolation Cooling and Reactor Cleanup (Letdown function) Systems for BWRs.

Include a list of systems which are excluded from this program. Testing of gaseous systems should include helium leak detection or equivalent testing.

Response

Public Service Electric & Gas has completed a comprehensive leak reduction program, which is intended to maintain the leakage rates as-low-as-practical for the following systems outside containment:

1. The Residual Heat Removal (RHR) System, in its entirety.

2. The Safety Injection System (SIS) - all those portions which have direct contact with the containment building.

3. Containment Spray System - only the portion which would have direct contact with the RHR System from the isolation valve to the containment building.

4. Chemical and Volume Control System (CVCS) - the operational portion of the system which includes the letdown heat exchanger lines, seal water heat exchangers, centrifugal charging pumps, and lines to and from the volume control tank.

5. Waste Gas System - the entirety of the system except for the lines to and from the nitrogen supply portion of the system.

6. Liquid Radwaste System - the waste evaporator and the waste holdup tanks.

7. Sampling System - all sample lines which have direct contact with the primary systems.

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The systems and portions of systems excluded from the program are: the boric acid recovery portion of the eves, because boric acid recovery will not be used during an accident; the primary water recovery portion of the eves, because it is not anticipated that this portion of the eves will be utilized during an accident; the Liquid Radwaste and Gaseous Radwaste Systems contain portions which will not be utilized during an accident. The entire Liquid Radwaste System except for the waste evaporator and the waste holdup tanks is excluded from the program. The Gas System nitrogen supply portion is excluded since this portion of the system will not be radioactive.

Most of the Containment Spray System will not be directly in contact with the radioactive fluid immediately after an accident. During an accident the Containment Spray System utilizes water from the refueling water storage tank.

Once this source is depleted the pumps are shut down and spray water is supplied from the RHR System. Thus, only the section of the system directly in contact with the RHR System will contain radioactive fluid (and be included in the program) .

The program consists of integrated leak tests of these systems. The baseline study and the actual leak rates with the systems in operation will be submitted as soon as practical, but no later than prior to entering Mode 4 following the next refueling on each unit.

At intervals not to exceed each refueling outage, an operating pressure leak test will be performed on portions of the SIS, RHR, CVCS, Reactor Coolant Sampling, Liquid Radwaste, Gaseous Radwaste, and Containment Spray Systems. The pressurized systems will be visually inspected for leakage into the building environment. Observed leakage will be corrected to the extent reasonably practical. Where feasible, leakage from liquid containing systems will be determined by counting the number of drops from each system. Where a system is not normally operating (such as the RHR and the SIS leakage will be determined by pressurizing applicable A-29 SGS-UFSAR Revision 6 February 15, 1987

portions of each system to operating pressure and conducting a walk-through of the system to determine the amount of leakage. Gaseous Radwaste System leakage will be determined by operating the waste gas compressors in the recirculation mode while maintaining the system pressure using a regulated nitrogen source.

The entire Gaseous Radwaste System, including the gas decay tanks and their relief valves, will be pressurized and leak tested. The system makeup rate will be determined with a gas flow meter at the supply regulator. All nonwelded connections in the system will be checked with a soap-and-water solution to locate any leaks, and appropriate corrective action will be taken.

The operating leak reduction program consists of a daily review of radioactive liquid waste processing, calculated containment leakage, and leakage observations. The daily leakage observations include those portions of the previously identified systems which are not shielded, enclosed, or otherwise controlled. Using this information, unidentified leakage baseline data is accumulated. Leakage quanti ties which exceed the baseline by a factor of two or more will be investigated to determine the source of leakage. Another feature of the program is the use of strategically located air monitors in the Auxiliary Building. These monitors have the capability to detect low leakage volumes of primary coolant at normal activity levels. Automatic monitoring is supplemented with smear surveys in controlled areas which contain major components of the listed systems.

Utilizing these monitoring programs, investigations and corrective actions will be implemented to reduce system leakage outside of the containment. When sources of leakage are identified, appropriate corrective measures to reduce the leakage will be initiated. Should correction of the leakage require reduction in operating mode, the correction will be made during the next scheduled shutdown.

Public Service Electric & Gas is taking other steps to eliminate unnecessary leakage into the Auxiliary Building. For example, A-30 SGS-UFSAR Revision 6 February 15, 1987

currently capped valve leakoff connections are being hardpiped to the Liquid Radwaste System.

A further review was performed in accordance with IE Circular 79-21, "Prevention of Unplanned Releases of Radioactivity." The results of this review indicate that the system designs are acceptable.

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2.1.6.b Shielding Review Design Review of Plant Shielding and Environmental Qualification of Equipment for Spaces/Systems Which May be Used in Post Accident Operations NRC Position With the assumption of a post accident release of radioactivity equivalent to that described in Regulatory Guides 1.3 and 1.4, each licensee shall perform a radiation and shielding design review of the spaces around systems that may, as a result of an accident, contain highly radioactive materials. The design review should identify the location of vital areas and equipment, such as the Control Room, radwaste control stations, emergency power supplies, motor control centers, and instrument areas, in which personnel occupancy may be unduly limited or safety equipment may be duly degraded by the radiation fields during post accident operations of these systems.

Each licensee shall provide for adequate access to vital areas and protection of safety equipment by design changes, increased permanent or temporary shielding, or post accident procedural controls. The design review shall determine which types of corrective actions are needed for vital areas throughout the facility.

Clarification Any area which will or may require occupancy to permit an operator to aid in the mitigation of or recovery from an accident is designated as a vital area.

In order to assure that personnel can perform necessary post accident operations in the vital areas, we are providing the following guidance to be used by licensees to evaluate the adequacy of radiation protection to the operators:

A-32 SGS-UFSAR Revision 6 February 15, 1987

1. Source Term The minimum radioactive source term should be equivalent to the source terms recommended in Regulatory Guides 1. 3, 1. 4, 1. 7 and SRP 15. 6. 5.

with appropriate decay times based on plant design.

a. Liquid Containing Systems: 100 percent of the core equilibrium noble gas inventory, 50 percent of the core equilibrium halogen inventory, and 1 percent of all others are assumed to be mixed in the reactor coolant and liquids injected by Safety Injection.

b. Gas Containing Systems: 100 percent of the core equilibrium noble gas inventory and 25 percent of the core equilibrium halogen activity are assumed to be mixed in the containment atmosphere. For gas containing lines connected to the primary system (e.g.,

BWR steam lines) the concentration ofradioacti vi ty shall be determined assuming the activity is contained in the gas space in the Primary Coolant System.

2. Dose Rate Criteria The dose rate for personnel in a vi tal area should be such that the guidelines of General Design Criterion (GDC) 19 should not be exceeded during the course of the accident. GDC 19 limits the dose to an operator to 5 rem whole body or its equivalent to any part of the body.

When determining the dose to an operator, care must be taken to determine the necessary occupancy time in a specific area. For example, areas requiring continuous occupancy will require much lower dose rates than areas where minimal occupancy is required. Therefore, allowable dose rates will be based upon A-33 SGS-UFSAR Revision 6 February 15, 1987

expected occupancy, as well as the radioactive source terms and shielding. However, in order to provide a general design objective, we are providing the following dose rate criteria with alternatives to be documented on a case-by-case basis. The recommended dose rates are average rates in the area. Local hot spots may exceed the dose rate guidelines provided occupancy is not required at the location of the hot spot. These doses are design objectives and are not to be used to limit access in the event of an accident.

a. Areas Requiring Continuous Occupancy:

<15mR/hr. These areas will require full time occupancy during the course of the accident. The Control Room and onsi te technical support center are areas where continuous occupancy will be required. The dose rate for these areas is based on the Control Room occupancy factors contained in SRP 6.4.

b. Area Requiring Infrequent Access:

GDC 19. These areas may require access on a regular basis, but not continuous occupancy. Shielding should be provided to allow access at a frequency and duration estimated by the licensee. The plant radiochemical/chemical analysis laboratory, radwaste panel, motor control center, instrumentation locations, and reactor coolant and containment gas sample stations are examples where occupancy may be needed often but not continuously.

Response

The Salem station radiation shielding design basis includes TID-14844 and Reg.

Guide 1.183 assumptions for certain areas of the plant.

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Considerable shielding is installed throughout the plant that would allow access to many other areas of the plant for shorter than normal periods of time after an accident even though the shielding in these areas was not designed specifically for post-LOCA sources.

The airborne source terms inside containment used for this review are based on a release of 100 percent of the noble gases and 40 percent of the iodine in the core to the containment atmosphere. Credit is taken for removal of iodine by plateout and by containment sprays. The recirculating sump water source terms used for this review are based on a release of 40 percent of the Halogens and 1 percent of all remaining fission products to a water volume equal to the sum of the primary coolant system, the RWST, the accumulators and the Boron Injection Tank. These release fractions are considered representative of Regulatory Guide 1.4 and 1.183. Calculations are performed at one hour, one day and seven days (one week) following the reactor shutdown caused by the accident to allow adjustment for radioactive decay.

Calculations are focused on areas in the Auxiliary Building and penetration areas. Dose rates in the containment were calculated for locations where necessary (post-LOCA) equipment and instruments are located.

The systems and areas reviewed include the following:

1. RHR System

2. Safety Injection

3. CVCS Demineralizer Area

4. Charging Pump Compartments

5. Reactor Coolant Filter

6. Seal Water Filter Area

7. Chemistry Lab

8. Primary Sample Lab

9. Fuel Handling Building A-35 SGS-UFSAR Revision 23 October 17, 2007

10. Spent Fuel Pool Heat Exchanger Area

11. Liquid Radwaste

12. Control Room

13. Technical Support Center

14. Diesel Generator Compartments

15. Diesel Oil Supply Tank Compartments

16. Electrical Relay and Switchgear Rooms

17. Gaseous Radwaste Valve Stations

18. Liquid Radwaste Valve Stations

19. Component Cooling Accessibility to systems and areas:

The effect of the design basis LOCA on the radiation environment in the plant was determined by:

1. Identifying the equipment expected to be handling recirculating sump water by reviewing ESF systems and associated P&ID's.

2. Locating this equipment in the plant by the use of mechanical drawings, and

3. Calculating the dose rates in each area of the plant affected by the equipment considering intervening shielding material.

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The areas of the plant affected by post LOCA sources are shown in Tables A-4 and A-5. These zones are identified by TRIS zone number and are assigned a radiation zone based on the following key:

Zone Dose Rate I < 15 mrem/hr II < 100 mrem/hr III < 1 rem/hr IV < 5 rem/hr v < 50 rem/hr VI < 500 rem/hr VII < 5000 rem/hr VIII > 5000 rem/hr Separate zone ratings are presented for one hour, one day and one week following the accident. The following is a discussion of the accessibility of specific areas of the plant.

Residual Heat Removal System - Elevation 45 Feet and 55 Feet Auxiliary Building

1. The RHR pump compartments on elevation 45 feet (Location Code #

01045002, 12045002, 01045006, 12045006) in the Auxiliary Building would be a zone VI I I during pump operation one hour after the accident and would not be accessible.

2. The dose rate in the adjacent RHR compartment will be zone III (See Note 5 on Tables A-4 and A-5). This compartment is accessible for limited periods of time while the other RHR system is operating.

3. The radiation zone on elevation 55 feet from the operating RHR System below (Location Code # 01055002, 12055002, 01055005, 12055005) is zone V at one hour post accident. This drops to zone III after 1 week of decay. Six inches of lead was installed to shield an exposed portion of RHR suction pipe.

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Safety Injection System I

1. The safety injection pump compartment (Location Code # 01084005, 12084005, 01084006, 12084006) is inaccessible while operating.

2. Radiation zones in adjacent areas, such as the spent fuel pool heat exchanger area (Location Code # 01084004, 12084004) and component cooling heat exchanger compartments (Location Code # 01084009, 12084009) are as high as zone V at contact with the pipe chase and pump compartment shield wall surfaces. This dose rate drops off substantially several feet from the walls. Limited access is afforded to these areas and no additional permanent shielding is planned.

Charging Pump Compartments

1. The radiation zone in the vicinity of these pumps (Location Code #

01084035, 12084035, 01084036, 12084036, 01084037, 12084037) may be as high as zone VIII, thus precluding access while the pumps are operating.

2. The dose rate through the wall separating the pump compartments produces a radiation zone V (Location Code # 01084041, 12084041).

3. The radiation zone outside the charging pump compartments is zone IV (e.g., Location Code # 01084025, 12084025); therefore, access to the components in the general area is available.

A-37 SGS-UFSAR Revision 18 April 26, 2000

Chemical and Volume Control - Demineralizer Area

1. Dose rates from the demineralizers would not have a significant effect on access.

2. The dose rates from piping and valves located behind valve aisle shield walls would be the major source of radiation and result in radiation zone IV in the operating aisles (Location Code # 01084024, 12084024).

This would be reduced by decay and will afford sufficient access to the area for limited valve operations.

Reactor Coolant and Seal Water Filters

1. The dose rates from these filters do not present a problem since the elements are replaced at predetermined radiation levels rather than high pressure drop. Post accident radiation levels in this area will not preclude access to this area. Each filter is located in an individual shielded compartment.

Primary Sample Lab

1. Use of the Primary Sample Lab may be required for post accident sample analyses. The Primary Sample Room may be required for post accident sampling of reactor coolant and containment sump (via RHR) .

A-38 SGS-UFSAR Revision 20 May 6, 2003

Counting Room

1. Direct dose rates in the Counting Room are not significantly affected by accident radiation source terms due to the location of the Counting Room. If high background dose rates preclude use of this area, alternate facilities are available.

Fuel Handling Building

1. Dose rates in the Fuel Handling Building due to direct radiation from the containment will not be significantly affected. The only exception to this is streaming from the elevation 130 feet containment personnel hatch and through the doorway into the Fuel Handling Building at elevation 130 feet.

2. The dose rates at the spent fuel pool heat exchanger and pump area in the Auxiliary Building (Location Code # 01084004, 12084004) produce a radiation zone V at one hour, thus affording limited access to this area.

Areas to Which Access May be Required Following an Accident The areas discussed below are considered vi tal areas, i.e., areas to which access may be required following an accident. Accessibility is based on direct radiation levels due to contained radiation sources.

Control Room The Control Room is located on elevation 122 feet and is sufficiently shielded from systems containing highly radioactive fluids. The radiation levels in the Control Room due to direct dose rates from the systems that may be required to operate after an accident are in the millirem per hour range.

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Technical Support Center The Technical Support Center is located in the Clean Facilities Building, and the doses due to the systems that will be operating in the Auxiliary Building are negligible. The doses to individuals in this building over the course of an accident are due to the cloud and airborne dose from plant releases. With installed shielding, the TEDE dose would be less than five rem. The Emergency Plan Implementing Procedures identify alternate facilities that are available if access to the TSC is limited.

Areas in the Auxiliary Building That do not Contain Highly Radioactive Sources of Radiation but May Require Access These areas include:

Diesel generator compartments Diesel oil supply tank compartments Electrical relay and switchgear rooms Analysis shows that sufficient shielding exists between these areas and adjacent compartments that contain radiation sources such that access to these areas is not precluded.

Access to Areas in the Auxiliary Building Which May Contain Highly Radioactive Sources The hydrogen purge controls and containment isolation valve reset controls are operated from the Control Room. Access to other areas of the Auxiliary Building related to this equipment is unnecessary.

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Chemistry Lab The Chemistry Lab (Location Code # 01100005) is located on elevation 100 ft in the Auxiliary Building. If there is a LOCA in Unit 1, there will be a localized high dose rate area (zone V at one hour) in the south end of the room. Otherwise it is sufficiently shielded such that the major contribution to the dose rate in the lab is due to streaming from the containment personnel hatch which produces a zone II. Alternate chemistry facilities are available if access to the Chemistry Lab is limited.

Gaseous Radwaste Control Center The valve operating station for the gas decay tanks is accessible.

Liquid Radwaste Control Station (Valve Areas)

Liquid radwaste is processed by the Portable Liquid Radwaste System located on elevation 103 ft of the Truck Bay of the Auxiliary Building. Before processing post accident radwaste, appropriate radiological controls will be put in place to reduce potential exposures. After processing, the liquid waste is stored and sampled in the Waste Hold-up Tanks or Waste Monitor Hold-up Tank. The valves used to divert flow are remotely operated at the 104 panel located on elevation 64 ft in the Auxiliary Building. Remaining manual valves are located on elevation 84 ft of the Auxiliary Building in accessible areas.

Component Cooling Pump and Auxiliary Feedwater Pump and Valve Areas These areas are located on elevation 84 feet (Location Code # 01084016, 12084016). The dose rates from shielded sources adjacent to this area produce a radiation zone III. This does not preclude access to this area.

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Boric Acid Evaporator Room These rooms (Location Code # 01100008, 12100008) are located on elevation 100 ft and contain the Post Accident Sample System (PASS) and Sampling System (SS) sample lines and PASS coolers (Unit 2 only). The post accident radiation zone in the east side of the room due to the safety injection pumps below is zone IV, which would allow limited access in the BAE room for the unit in which the LOCA occurs. The dose rate in the west part of the room near the door will be much lower (zone I). Once sampling is initiated, these areas become radiation zone VII due to the presence of the PASS and SS sample lines. If the LOCA is in Unit 1 and the PASS is used, both rooms will be affected by the PASS sample lines. If the SS is used, only the Unit 1 room is affected. For a LOCA in Unit 2, only the Unit 2 room is affected by the PASS sample lines. If the SS is used, both rooms are affected.

Electrical Penetration Areas The areas adjacent to the containment on elevation 78 (Location Code #

02078001, 02078012, 13078001, 13078012) contain electrical busses that may require access for long term recovery. The radiation zone in these areas is zone V at one hour after the accident due to activity in containment, which drops to zone III by one day. If PASS sampling is initiated, a localized high dose rate area will exist on the west end of the penetration in the vicinity of the PASS valves. The dose rate due to these valves also produces a zone V in one hour, which drops to a zone IV at one day.

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Equipment Qualification - Capability to Withstand Possible Radiation Doses Following an Accident Vi tal components in the RHR, High Pressure Safety Injection, Low Pressure Safety Injection, and CVCS Systems have been identified. Integrated doses after 120 days were calculated for the following pieces of equipment: RHR motor-driven pumps, safety injection motor-driven pumps and centrifugal charging motor-driven pumps. The direct dose to each of these pieces of 7

equipment is 2.31 x 10 rad, or less, after a period of 120 days. These doses were calculated using the TID source terms and reassessed consistent with Reg.

Guide 1.183 Source Terms over a 30-day elapsed period of time.

The capability of the electrical equipment to withstand the radiation exposures has been evaluated and documented in the Environmental Equipment Qualification (EQ) Program.

The containment spray pumps are also considered vi tal components, but these pumps are located in a mild environment and will not be exposed to any radioactive fluid. During the injection mode, the pumps take suction from the refueling water storage tank (RWST). During the recirculation mode, the RHR pumps supply the spray headers and the containment spray pumps are not run.

Radiation exposures for Class 1E electrical equipment in the EQ Program have been qualified to the guidelines of 10CFR50.49.

Other Considerations Local and Portable Shielding Small quantities of temporary shielding such as lead bricks, lead blankets, and lead sheet are available at the station to shield local hot spots.

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Source Terms The source terms used for this study were based on 1-hour decay. The calculated dose rates would be reduced by a factor of 10 at one day and approximately 50 at one week after the start of an accident.

The radiation source terms used for the shielding design review were obtained by using the ORIGEN code. Shielding and dose rate calculations were performed using point kernel transport methods, primarily consisting of fixed source/shield configurations. These methods were utilized because the source geometries for the analysis were primarily pipes and tanks.

Original requirements concerning environmental qualification for post accident operation were addressed in a letter dated November 26, 1980 to the Director of NRR. This has been superseded by the Environmental Design Criteria ( EDC) program.

A-43 SGS-UFSAR Revision 16 January 31, 1998

2.1.7.a Preliminary Feedwater Initiation Automatic Initiation of the Auxiliary Feedwater System for PWRs (Section NRC Position Consistent with satisfying the requirements of General Design Criterion 20 of Appendix A to 10CFR50 with respect to the timely initiation of the Auxiliary Feedwater System (AFWS), the following requirements shall be implemented in the short term:

1. The design shall provide for the automatic initiation of the AFWS.

2. The automatic initiation signals and circuits shall be designed so that a single failure will not result in the loss of AFWS function.

3. Testability of the initiating signals and circuits shall be a feature of the design.

4. The initiating signals and circuits shall be powered from the emergency buses.

5. Manual capability to initiate the AFWS from the Control Room shall be retained and shall be implemented so that a single failure in the manual circuits will not result in the loss-of-system function.

6. The ac motor-driven pumps and valves in the AFWS shall be included in the automatic actuation (simultaneous and/or sequential) of the loads to the emergency buses.

7. The automatic initiating signals and circuits shall be designed so that their failure will not result in the A-44 SGS-UFSAR Revision 6 February 15, 1987

loss of manual capability to initiate the AFWS from the Control Room.

In the long term, the automatic initiation signals and circuits shall be upgraded in accordance with safety grade requirements.

Responses The AFWS is described in Section 10.4. The system is designed to Class 1E criteria and is powered from the emergency power source.

Automatic initiation of the AFWS is provided by the following signals.

Motor-Driven Pumps

1. Loss of Offsite Power

2. Loss of Main Feed

3. Low-Low level in One Stearn Generator

4. Safeguards Sequence Signal Turbine-Driven Pump

1. Low-Low Level in Two Stearn Generators

2. 4 kV Bus Undervoltage Manual initiation of the systems may be accomplished either from the Control Room or locally at the pumps. The system and its components are designed for single failure considerations and are testable.

In a letter from R. L. Mittl to S. A. Vargo, dated December 31, 1980, PSE&G summarized the various detailed design data which has A-45 SGS-UFSAR Revision 6 February 15, 1987

been furnished during the Staff's review of the Auxiliary Feedwater System.

A-46 SGS-UFSAR Revision 6 February 15, 1987

2.1.7.b Auxiliary Feedwater Flow Indication Auxiliary Feedwater Flow Indication to Stearn Generators for PWRs NRC Position Consistent with satisfying the requirements set forth in GDC 13 to provide the capability in the Control Room to ascertain the actual performance of the AFWS when it is called to perform its intended function, the following requirement shall be implemented:

1. Safety grade indication of auxiliary feedwater flow to each steam generator shall be provided in the Control Room.

2. The auxiliary feedwater flow instrument channels shall be powered from the emergency buses consistent with satisfying the emergency power diversity requirements of the AFWS set forth in Auxiliary Systems BTP 10-1 of SRP Section 10.4.9.

Response

Safety grade indication of auxiliary feedwater flow to each steam generator is provided in the Control Room. These indicating channels are designed to the same criteria as the Protection System indicators. One testable flow instrument with an accuracy on the order of +/- 2 percent is provided for each steam generator. In addition, three level instruments are provided for each steam generator. The instruments are all powered from the vital buses and are seismically qualified, with environmental qualification for the level instruments which are located inside the containment.

Assurance of sufficient water being provided to the steam generators is of primary concern. This is accomplished by control valve demand with steam generator level indication. Present A-47 SGS-UFSAR Revision 6 February 15, 1987

indication of pump operation, valve demand/position, auxiliary feedwater flow (one/steam generator), auxiliary feedwater discharge pressure and steam generator level (three/steam generator) is adequate to meet the information requirements necessary to assure appropriate operator action. All of the above equipment is powered from vital buses, and is adequate to meet short- and long-term requirements.

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2.1.8.a Post-Accident Sampling Improved Post-Accident Sampling Capability NRC Position A design and operational review of the Reactor Coolant and Containment Atmosphere Sampling Systems shall be performed to determine the capability of personnel to promptly obtain (less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />) a sample under accident conditions without incurring a radiation exposure to any individual in excess of 3 and 18 3/4 rems to the whole body of extremities, respectively. Accident conditions should assume a Regulatory Guide 1.3 or 1.4 release of fission products. If the review indicates that personnel could not promptly and safely obtain the samples, additional design features or shielding should be provided to meet the criteria.

A design and operational review of the radiological spectrum analysis facilities shall be performed to determine the capability to promptly quantify (less than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />) certain radioisotopes that are indicators of the degree of core damage. Such radionuclides are noble gases (which indicate cladding failure), iodines and cesiums (which indicate high fuel temperatures), and non-volatile isotopes (which indicate fuel melting). The initial reactor coolant spectrum should correspond to a Regulatory Guide 1.3 or 1.4 release. The review should also consider the effects of direct radiation from piping and components in the Auxiliary Building, and possible contamination and direct radiation from airborne effluents. If the review indicates that the analyses required cannot be performed in a prompt manner with existing equipment, then design modifications or equipment procurement shall be undertaken to meet the criteria.

In addition to the radiological analyses, certain chemical analyses are necessary for monitoring reactor conditions. Procedures shall be provided to perform boron and chloride A-49 SGS-UFSAR Revision 6 February 15, 1987

chemical analyses assuming a highly radioactive initial sample (Regulatory Guide 1. 3 or 1. 4 source term) . Both analyses shall be capable of being completed promptly; i.e., the boron sample analysis within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and the chloride sample analysis within a shift.

Response

The Post-Accident Sampling System is described in Section 9.3. The PASS was removed from the licensing base as a result of License Amendments 254/235, dated November 5, 2002.

The eight PASS sample and return lines for Salem Units 1 and 2 have been cut and capped on both sides of the applicable containment penetration. The RCS sample lines were also cut and capped at the connection point to the sample system tubing.

A-50 SGS-UFSAR Revision 23 October 17, 2007

2.1.8.b Increased Radiation Monitoring Range Increased Range of Radiation Monitors NRC Position The requirements associated with this recommendation should be considered as advanced implementation of certain requirements to be included in a revision to Regulatory Guide 1. 97, 11 Instrumentation to Follow the Course of an Accident, 11 which has already been initiated, and in other Regulatory Guides, which will be promulgated in the near-term.

1. Noble gas effluent monitors shall be installed with an extended range designed to function during accident conditions as well as during normal operating conditions; multiple monitors are considered to be necessary to cover the ranges of interest.

5

a. Noble gas effluent monitors with an upper range of 10 ~Ci/cc (Xe-133) are considered to be practical and should be installed in all operating plants.

b. Noble gas effluent monitoring shall be provided for the total range

-7 of concentration extending from a minimum of 10 ~Ci/cc (Xe-133).

Multiple monitors are considered to be necessary to cover the ranges of interest. The range capacity of individual monitors shall overlap by a factor of ten.

2. Since iodine gaseous effluent monitors for the accident condition are not considered to be practical at this time, capability for effluent monitoring of radioiodines for the accident condition shall be provided with sampling conducted by adsorption on charcoal or other media, followed by onsite laboratory analysis.

8

3. In containment radiation level monitors with a maximum range of 10 rad per hour shall be installed. A minimum of two such monitors that are physically separated shall be provided. Monitors shall be designed and qualified to function in an accident environment.

A-51 SGS-UFSAR Revision 17 October 16, 1998

The NRC position in NUREG-0578 was subsequently modified to permit a maximum 7

range of 10 R per hour for gamma - only monitoring.

The NRC position (in NUREG-0578) was subsequently modified to require noble gas 5

effluent monitors with a range from as low as reasonably achievable to 10

!-LC/cc. In addition, the overlap requirement was deleted.

Response

1. Extended range noble gas monitors have been installed to meet this requirement. Post-accident samplers are located in enclosures outside of the Auxiliary Building to reduce radiation exposures to individuals obtaining post-accident plant vent samples. The detection range of extended range monitors is as follows:

Intermediate range monitors:

-4 2 Unit 1 - 1R41B, Unit 2 - 2R41B 1x10 to 1x10  !-LCi/cc High range monitors:

Unit 1 - 1R41C, Unit 2 - 2R41C 0.1 to 1x10 5 . !-LCl I cc Readings from these monitors are continuously available in the Control Room.

The existing R41A noble gas monitors provide for low detection ranges (1x10

-7 to 1x10

1. I .

!-LCl cc) durlng normal plant operations.

Channels R41B, C are assigned the Reg. Guide 1. 97 extended range noble gas monitoring functions.

High range monitors have also been installed to measure releases from the atmospheric steam relief and/or safety valves. A separate channel is installed for each of the four main steam lines of each unit. The range of these monitors is as follows:

3 Unit 1 - 1R46, A,B,C,D 0.1 to 2x10  !-LCi/cc Xe-133 3

Unit 2 - 2R46, A,B,C,D 0.1 to 2x10  !-LCi/cc Xe-133

2. The Salem R45 design provides for iodine sampling by absorption on charcoal or silver zeolite cartridges. Plant vent iodine grab samples can be obtained in the extended range monitoring enclosure to prevent personnel from receiving excessive radiation exposure.

A-52 SGS-UFSAR Revision 28 May 22, 2015

3. There are two high range containment monitors in Salem Units 1 and 2.

7 The R4 4A and R4 48 have a high range gamma radiation response of 10 R/hr. These monitors are in separate locations on different elevations.

A full description of these higher range containment monitors is provided in FSAR Section 11.4.

A-53 SGS-UFSAR Revision 15 June 12, 1996

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2.1.8.c In Plant Iodine Instrumentation Improved In Plant Iodine Instrumentation NRC Position Each licensee shall provide equipment and associated training and procedures for accurately determining the airborne iodine concentration throughout the plant under accident conditions.

Response

Sufficient instrumentation for iodine concentration monitoring throughout the plant under accident conditions is being provided.

The capability exists to accurately detect the presence of iodine in areas of the plant that may be occupied during an accident. This capability is provided by the equipment discussed below, which are part of the emergency equipment specified in the Emergency Plan. Operating procedures are available and training is conducted in accordance with the Emergency Plan.

Portable Air Samplers -A charcoal or silver zeolite cartridge sampler can be used on a portable air sampler which can be carried around and plugged into an electrical receptacle.

Continuous Air Monitors - These units are on carts with wheels and can be moved to sample different areas utilizing local electrical receptacles, can use charcoal or silver zeolite cartridge.

In the event that the count room facility cannot be used to analyze iodine samples, Emergency Plan procedures specify that the Hope Creek count room facility be used.

A-56 SGS-UFSAR Revision 16 January 31, 1998

Emergency Plan procedures contain instructions for performing a field analysis of iodine samples using portable radiation detection instrumentation.

The capability to purge a charcoal cartridge with clean air or nitrogen and to remove the cartridge to a low background area for further analysis will be established.

A-57 SGS-UFSAR Revision 16 January 31, 1998

2.1.9 Analysis of Accidents and Instrumentation to Follow Containment Conditions Analysis of Design and Off-Normal Transients and Accidents NRC Position Analysis, procedures, and training addressing the following are required:

1. Small break LOCAs,

2. Inadequate core cooling,

3. Transients and accidents.

Some analysis requirements for small breaks have already been specified by the Bulletins and Orders Task Force. These should be completed. In addition, pretest calculations of some of the Loss of Fluid Test (LOFT) small break tests (scheduled to start in September 1979) shall be performed as means to verify the analyses performed in support of the small break emergency procedures and in support of an eventual long-term verification of compliance with Appendix K of 10CFR50.

In the analysis of inadequate core cooling, the following conditions shall be analyzed using realistic (best-estimate) methods:

1. Low Reactor Coolant System inventory (two examples will be required -

LOCA with forced flow, LOCA without forced flow).

2. Loss of natural circulation (due to loss of heat sink).

These calculations shall include the period of time during which inadequate core cooling is approached as well as the period of A-58 SGS-UFSAR Revision 6 February 15, 1987

time during which inadequate core cooling exists. The calculations shall be carried out in real time far enough that all important phenomena and instrument indications are included. Each case should then be repeated taking credit for correct operator action. These additional cases will provide the basis for developing appropriate emergency procedures. These calculations should also provide the analytical basis for the design of any additional instrumentation needed to provide operators with an unambiguous indication of vessel water level and core cooling adequacy (see Section 2.1.3.b).

The analysis of transients and accidents shall include the design basis events specified in Section 15 of each FSAR. The analyses shall include a single active failure for each system called upon to function for a particular event.

Consequential failures shall also be considered. Failures of the operators to perform required control manipulations shall be given consideration for permutations of the analyses. Operator actions that could cause the complete loss of function of a safety system shall also be considered. At present, these analyses need not address passive failures or multiple system failures in the short term. In the recent analysis of small break LOCAs, complete loss of auxiliary feedwater was considered. The complete loss of auxiliary feedwater may be added to the failures being considered in the analysis of transients and accidents if it is concluded that more is needed in operator training beyond the short-term actions to upgrade AFWS reliability. Similarly, the long-term, multiple failures and passive failures may be considered depending in part on staff review of the results of the short-term analyses.

The transient and accident analyses shall include event tree analyses, which are supplemented by computer calculations for those cases in which the system response to operator actions is unclear or these calculations could be used to provide important quantitative information not available from an event tree.

For example, failure to initiate high-pressure injection could lead core uncovery for some transients, and a computer calculation A-59 SGS-UFSAR Revision 6 February 15, 1987

could provide information on the amount of time available for corrective action. Reactor simulators may provide some information in defining the event trees and would be useful in studying the information available to the operators. The transient and accident analyses are to be performed for the purpose of identifying appropriate and inappropriate operator actions relating to important safety considerations such as natural circulation, prevention of core uncovery, and prevention of more serious accidents.

The information derived from the preceding analyses shall be included in the plant emergency procedures and operator training. It is expected that analyses performed by the Nuclear Stearn Supply System (NSSS) vendors will be put in the form of emergency procedure guidelines and that the changes in the procedures will be implemented by each licensee or applicant.

In addition to the analyses performed by the reactor vendors, analyses of selected transients should be performed by the NRC Office of Research, using the best available computer codes to provide the basis for comparisons with the analytical methods being used by the reactor vendors. These comparisons together with comparisons to data, including LOFT small break test data, will constitute the short-term verification effort to assure the adequacy of the analytical methods being used to generate emergency procedures.

Response

Public Service Electric & Gas is a member of the Westinghouse Owners' Group and is actively supporting the generic analysis work described above. This analysis work will be completed on a schedule compatible with the industry effort. Emergency Procedures EI 4. 4, "LOCA", and EI 4.17, "Leakage Greater than Charging Flow," (in effect, inadequate core cooling) will incorporate the results of the analysis work performed. Operating personnel have been advised of small break LOCA procedural changes A-60 SGS-UFSAR Revision 6 February 15, 1987

and will receive the appropriate training for inadequate core cooling emergency procedures upon completion of the generic analysis work in early 1980.

Analyses of small break LOCA, symptoms of inadequate core cooling and required actions to restore core cooling, and analysis of transient and accident scenarios including operator actions not previously analyzed are being performed on a generic basis by the Westinghouse Owners' Group, of which PSE&G is a member. The small break analyses have been completed and were reported in WCAP-9600, which was submitted to the Bulletins and Orders Task Force by the Owners' Group on June 29, 1979. Incorporated in that report were guidelines that were developed as a result of small break analyses. These guidelines have been reviewed and approved by the Bulletins and Orders Task Force and have been presented to the Owners' Group utility representatives in a seminar held on October 16-19, 1979. Following this seminar, each utility has developed plant-specific procedures and trained their personnel on the new procedures. Revised procedures and training are in place in accordance with the requirement in to Mr. Eisenhut's letter of September 13, 1979, and Enclosure 2 to Mr. Denton's letter of October 30, 1979.

The work required to address the other two areas, inadequate core cooling and other transient and accident scenarios, was performed in conjunction with schedules and requirements established by the Bulletins and Orders Task Force.

Analysis related to the definition of inadequate core cooling and guidelines for recognizing the symptoms of inadequate core cooling based on existing plant instrumentation and for restoring core cooling following a small break LOCA were detailed analysis than was originally proposed, and will be followed up with a more extensive and detailed analysis which will be available during the first quarter of 1980. The Salem 2 Emergency Procedures have been revised on an interim basis as described in the response to Section 2.1.3.b.

A-61 SGS-UFSAR Revision 6 February 15, 1987

With respect to other transient accidents contained in the Salem FSAR, the Westinghouse Owners' Group has performed an evaluation of the actions which occur during an event by constructing a sequence of event trees for each of the non-LOCA and LOCA transients. From these event trees, a list of decision points for operator action has been prepared, along with a list of information available to the operator at each decision point. Following this, criteria have been set for credible misoperation, and time available for operator decisions have been qualitatively assessed. The information developed was then used to test Abnormal and Emergency Operating Procedures against the event sequences and determine if inadequacies exist in them.

The Owners' Group has also provided test predictions of the LOFT L3-1 nuclear small break experiment.

A-62 SGS-UFSAR Revision 6 February 15, 1987

Instrumentation to Monitor Containment Conditions During the Course of an Accident NRC Position Consistent with satisfying the requirements set forth in General Design Criterion 13 to provide the capability in the Control Room to ascertain containment conditions during the course of an accident, the following requirements shall be implemented:

1. A continuous indication of containment pressure shall be provided in the Control Room. Measurement and indication capability shall include three times the design pressure of the containment for concrete, four times the design pressure for steel, and minus five psig for all containments.

2. A continuous indication of hydrogen concentration in the containment atmosphere shall be provided in the Control Room. Measurement capability shall be provided over the range of 0 to 10 percent hydrogen concentration under both positive and negative ambient pressure.

3. A continuous indication of containment water level shall be provided in the Control Room for all plants. A narrow range instrument shall be provided for PWRs and cover the range from the bottom to the top of the containment sump. Also for PWRs, a wide range instrument shall be provided and cover the range from the bottom of the containment to the elevation equivalent to a 500, 000-gallon capacity. For boiling water reactors ( BWRs) , a wide range instrument shall be provided and cover the range from the bottom to 5 feet above the normal water level of the suppression pool.

The containment pressure, hydrogen concentration and wide range containment water level measurements shall meet the design and A-63 SGS-UFSAR Revision 6 February 15, 1987

qualification provisions of Regulatory Guide 1.97, including qualification, redundancy, and testability. The narrow range containment water level measurement instrumentation shall be qualified to meet the requirements of Regulatory Guide 1.89 and shall be capable of being periodically tested.

Response

Containment pressure instrumentation, containment water level instrumentation, and containment hydrogen instrumentation have been installed.

A-64 SGS-UFSAR Revision 6 February 15, 1987

Installation of Remotely-Operated High Point Vents in the Reactor Coolant System NRC Position Each applicant and licensee shall install Reactor Coolant System and reactor vessel head high point vents remotely operated from the Control Room. Since these vents form a part of the reactor coolant pressure boundary, the design of the vents shall conform to the requirements of Appendix A to 10CFR50, General Design Criteria. In particular, these vents shall be safety grade, and shall satisfy the single failure criterion and the requirements of IEEE Standard 279 to ensure a low probability of inadvertent actuation.

Each applicant and licensee shall provide the following information concerning the design and operation of these high point vents:

1. A description of the construction, location, size, and power supply for the vents along with results of analyses of LOCAs initiated by a break in the vent pipe. The results of the analyses should be demonstrated to be acceptable in accordance with the acceptance criteria of 10CFR50. 4 6.

2. Analyses demonstrating that the direct venting of non-condensable gases with perhaps high hydrogen concentrations does not result in violation of combustible gas concentration limits in containment as described in 10CFRS50.44, Regulatory Guide 1.7 (Rev. 1), and SRP, Section 6.2.5.

3. Procedural guidelines for the operators' use of the vents. The information available to the operator for initiating or terminating vent usage shall be discussed.

A-65 SGS-UFSAR Revision 6 February 15, 1987

Response

The Reactor Vessel Head Venting System is described in Section 5.1.

A-66 SGS-UFSAR Revision 6 February 15, 1987

2.2.1.a Shift Supervisor's Responsibilities Shift Supervisor's Responsibilities NRC Position

1. The highest level of corporate management of each licensee shall issue and periodically reissue a management directive that emphasizes the primary management responsibility of the shift supervisor for safe operation of the plant under all conditions on his shift and that clearly establishes his command duties.

2. Plant procedures shall be reviewed to assure that the duties, responsibilities, and authority of the shift supervisor and Control Room operators are properly defined to effect the establishment of a definite line of command and clear delineation of the command decision authority of the shift supervisor in the Control Room relative to other plant management personnel. Particular emphasis shall be placed on the following:

a. The responsibility and authority of the shift supervisor shall be to maintain the broadest perspective of operational conditions affecting the safety of the plant as a matter of highest priority at all times when on duty in the Control Room. The idea shall be reinforced that the shift supervisor should not become totally involved in any single operation in times of emergency when multiple operations are required in the Control Room.

b. The shift supervisor, until properly relieved, shall remain in the Control Room at all times during accident situations to direct the activities of Control Room operators. Persons authorized to relieve the shift supervisor shall be specified.

A-67 SGS-UFSAR Revision 6 February 15, 1987

c. If the shift supervisor is temporarily absent from the Control Room during routine operations, a lead Control Room operator shall be designated to assume the Control Room command function. These temporary duties, responsibilities, and authority shall be clearly specified.

3. Training programs for shift supervisors shall emphasize and reinforce the responsibility for safe operation and the management function the shift supervisor is to provide for assuring safety.

4. The administrative duties of the shift supervisor shall be reviewed by the senior officer of each utility responsible for plant operations.

Administrative functions that detract from or are subordinate to the management responsibility for assuring the safe operation of the plant shall be delegated to other operations personnel not on duty in the Control Room.

Response

A written directive describing and emphasizing the primary management responsibilities of shift supervisors and establishing their command duties was placed in effect September 12, 197 9. Using the guidance of this directive, Administrative Procedure AP-5 and the requalification program have been revised as necessary.

Shift administrative activities have been reviewed to determine which duties should be delegated to personnel who are not on duty in the Control Room.

Duties which were found to detract from the shift supervisor's responsibility for safe operation of the plant have been reassigned.

A-68 SGS-UFSAR Revision 6 February 15, 1987

2.2.l.b Shift Technical Advisor Shift Technical Advisor NRC Position Each licensee shall provide an on-shift technical advisor to the shift supervisor. The shift technical advisor may serve more than one unit at a multi-unit site if qualified to perform the advisor function for the various units.

The shift technical advisor shall have a bachelor's degree or equivalent in a scientific or engineering discipline and have received specific training in the response and analysis of the plant for transients and accidents. The shift technical advisor shall also receive training in plant design and layout, including the capabilities of instrumentation and controls in the Control Room.

The licensee shall assign normal duties to the shift technical advisors that pertain to the engineering aspects of assuring safe operations of the plant, including the review and evaluation of operating experience.

Response

See UFSAR Section 13 and Technical Specification Section 6.0 for Shift Technical Advisor staffing and qualification requirements.

A-69 SGS-UFSAR Revision 22 May 5, 2006

2.2.1.c Shift Turnover Procedures Shift and Relief Turnover Procedures NRC Position The licensees shall review and revise as necessary the plant procedure for shift and relief turnover to assure the following:

1. A checklist shall be provided for the oncoming and off going Control Room operators and the oncoming shift supervisor to complete and sign.

The following items, as a minimum, shall be included in the checklist:

a. Assurance that critical plant parameters are within allowable limits (parameters and allowable limits shall be listed on the checklist) .

b. Assurance of the availability and proper alignment of all systems essential to the prevention and mitigation of operational transients and accidents by a check of the control console (what to check and criteria for acceptable status shall be included on the checklist) .

c. Identification of systems and components that are in a degraded mode of operation permitted by the Technical Specifications. For such systems and components, the length of time in the degraded mode shall be compared with the Technical Specifications action statement (this shall be recorded as a separate entry on the checklist) .

2. Checklists or logs shall be provided for completion by the offgoing and oncoming auxiliary operators and technicians. Such checklists or logs shall include any equipment under maintenance of test that by themselves A-70 SGS-UFSAR Revision 6 February 15, 1987

could degrade a system critical to the prevention and mitigation of operational transients and accidents or initiate an operational transients (what to check and criteria for acceptable status shall be included on the checklist); and

3. A system shall be established to evaluate the effectiveness of the shift and relief turnover procedure (for example, periodic independent verification of system alignments).

Response

The Salem operating logs contain checklists which provide oncoming and offgoing shifts with a status of critical plant parameters. In order to provide for a more formalized shift turnover, a program has been established in Adrninistrati ve Procedure AP-5 and the Operating Department Manual to ensure that the oncoming shift log and plant status review has been properly accomplished. An adequate evaluation system, which provides for a frequent management review of shift supervision logs to determine the quality of shift operations is already in use at Salem. This inspection consists of verification of operator understanding of equipment status and plant alarms, and direct observation of the conduct of operations in the Control Room.

A-71 SGS-UFSAR Revision 7 July 22, 1987

2.2.2.a Control Room Access Control Room Access NRC Position The licensee shall make provisions for limiting access to the Control Room to those individuals responsible for the direct operation of the nuclear power plant (e.g., operations supervisor, shift supervisor, and control room operators), to technical advisors who may be requested or required to support the operation, and to pre-designated NRC personnel. Provisions shall include the following:

1. Develop and implement an administrative procedure that establishes the authority and responsibility of the person in charge of the Control Room to limit access.

2. Develop and implement procedures that establish a clear line of authority and responsibility in the Control Room in the event of an emergency. The line of succession for the person in charge of the Control Room shall be established and limited to persons possessing a current senior reactor operator's license. The plan shall clearly define the lines of communication and authority for plant management personnel not in direct command of operations, including those who report to stations outside of the Control Room.

Response

The Control Room access points are card key controlled.

Only those personnel who are required in the Control Room have unescorted access to the Control Room area.

A-72 SGS-UFSAR Revision 16 January 31, 1998

Administrative controls adequately restrict access to the Control Rooms to only those personnel who can demonstrate an actual need to be there.

Responsibilities and lines of authority in the Control Room are addressed in the response to Section 2.2.1.a.

A-73 SGS-UFSAR Revision 6 February 15, 1987

2.2.2.b Onsite Technical Support Center Onsite Technical Support Center NRC Position Each operating nuclear power plant shall maintain an onsite technical support center separate from and in close proximity to the Control Room that has the capability to display and transmit plant status to those individuals who are knowledgeable of and responsible for engineering and management support of reactor operations in the event of an accident. The center shall be habitable to the same degree as the control room for postulated accident conditions. The licensee shall revise his emergency plans as necessary to incorporate the role and location of the technical support center.

A complete set of as-built drawings and other records, as described in ANSI N45.2.9-1974, shall be properly stored and filed at the site and accessible to the technical support center under emergency conditions. These documents shall include, but not be limited to, general arrangement drawings, P&IDs, piping system isometrics, electrical schematics, and photographs of components installed without layout specifications (e.g., field-run piping and instrument tubing) .

Response

1. An onsite Technical Support Center (TSC) is provided in accordance with 10CFR50.47(b) and 10CFR50 Appendix E.IV.E.8 on the third floor of the Clean Facilities Building and meets the detailed criteria of NUREG-0737, Supplement 1 and NUREG-0696 as described in the Emergency Plan.

Additional descriptions and details of the TSC and support systems are confirmed in the Emergency Plan provided under separate submittal pursuant to 10CFR50.4 (b) (5).

The TSC is provided with plant parameters and derived variables representative of the safety status of the plant via the Safety Parameter Display System ( SPDS) in accordance with NUREG-07 37 supplement 1 and NUREG-0696. A description of SPDS is contained in Section 7.10.

A-74 SGS-UFSAR Revision 14 December 29, 1995

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2.2.2.c Onsite Operational Support Center Onsite Operational Support Center (Section 2.2.2.c)

NRC Position An area to be designated as the onsi te operational support center shall be established. It shall be separate from the Control Room and shall be the place to which the operations support personnel will report in an emergency situation. Communications with the Control Room shall be provided. The emergency plan shall be revised to reflect the existence of the center and to establish the methods and lines of communication and management.

Response

The Operational Control Center (OSC) is located on 127 foot elevation, Service Building. This area is separate from each Control Room and is the place to which operations support personnel report in an emergency situation.

Communications with each Control Room are provided at this location.

A-80 SGS-UFSAR Revision 27 November 25, 2013

TABLE A-1 THIS TABLE INTENTIONALLY DELETED

• SGS-UFSAR 1 of 1 Revision 14 December 29, 1995

TABLE A-2 THIS TABLE INTENTIONALLY DELETED

• SGS-UFSAR 1 of 1 Revision 14 December 29, 1995

TABLE A-3 THIS TABLE INTENTIONALLY DELETED

• SGS-UFSAR 1 of 1 Revision 14 December 29, 1995

Tabl.e A-4 Dose R{ltes Outside Containment Following a Design Basis LOCA in Salem Unit 1 (1)

Locati9n.Number Location Description Zone No.

1 Hour 1 Day 1 Week 01045001 11 RHR Rin VIII VII VII Shielded ( 2) v IV III 01045002 11 RHR Pmp Rm VIII VII VII 11 RHR Pmp Rm (3) III II I 01045003 11 RHR Hx Area VIII VII VI 01045004 11 Cont. Sump Valve Rm VIII VII VI 01045005 Instrument Rack 102 VIII VII VII Shielded (2) v IV III 01045006 12 RHR Pmp Rm VIII VII VII 12*RHR Ptnp Rrn {3) III II I 01045007 12 RHR Hx Area VIII VII vr*

01045008 12 Cont. Sump Valve Rm VIII VII VI 01055002 11 RHR Valve Rm v IV III 01055003 11 RHR Hx Rm VIII VII VI 01055004 11 RHR Valve Rm VIII VII VI 010550Q5 12 RHR Valve Rm v IV III 01055006 12 RHR Hx Rrn VIII VII VI 01055007 12 RHR Valve Rm VIII VII VI 01064001 4KV Vital Bus IV III II

& Battery Rm 01064003 Laundry & Chern Dr Pump Rm IV III II 01064004 11 Monitor Tk & Pump Rm IV III III 01064005 12 Monitor Tk & Pump Rm v IV III 010640QB Waste Holdup Tk Rm IV III II 01064009 Waste Holdup Tk Rm IV III II 01064011 Waste Monitor Holdup IV III II Tank Rm 01064014 11 Waste Gas IV III II Compressor Rm 01064017 12 Waste Gas IV III II Compressor Rm 01064020 Waste Gas Valve Area IV III II 010640~1 11 Gas Decay Tk IV III II 01064022 12 Gas Decay Tk IV III II 01064048 11 HUT Rm IV III II 01064029 12 HUT Rm IV III II 01064031 Pipeway VIII VII VII 01084002 460/230V Vital IV III III 01084003 Aisle Outside SFP Pump I I I 01084004 Spent *Fuel Pit Pump Rm v III III 01084005 11. Safety Inj Pmp Rm VIII VII VI 01084006 12 Safety Inj Pmp Rm VIII VII VI 01084007 Pipe Alley VIII VII VII West End of Pipeway VII VII VI 01084008* Corridor at CC Hx v III III 01084009 . 11 CC Pump Rm v III III

• SGS.,...UFSAR 1 of 3 Revision 21 December 6, 2004

Table A~4 (Cont.)

Location Number Location Description Zone No .

1 Hour 1 Day -1 Week 0108'4010 11 Comp Cooling VA Rm VII VI VI 01084012 12 CC Hx Rm III II II 01084016 13 Aux FW Pump III -II II 0108.4018 LTD Hx Valve Rm I I I 01084019 LTD Hx Rm IV III II 01084020 Seal Water Hx Valve .Rm I I I 01084021 Seal Water Hx Rm IV III II 01084022 Elec. Control Cente~ I I I 01084024 Vent Duct IV III II

& Equipment Hatch 01084025 Corridor at 11 Cbnt Spray IV III II 01084026 Rm Next to 11 Chrg Pmp VII VII* VI 01084027 Co2-Fire Equip Rm III II II 01084029 11 Diesel FOST Rm IV III II 01084034 Chrg Pmp Valve Alley (11) VII/III VII/N/A VI/N/A 01084035 11 Chrg Pmp Rm VIII VII VI 01084036 12 Chrg Pmp Rm VIII VII VI 01084037 13 Chrg Pmp Rm VII VII VI 01084038 Cont. Spray Area IV III II 01084041 No.1 Aisle (4) v IV III 01084046 Stairwell v III III 01100013 Waste Evap Rm v III III 01100005 Chemistry Lab (8) v IV III 01100006 Access Aisle v IV III 01100007 Corridor at BAE {5) III II I 01100008 Boric Acid Evap Rm (5) v IV III 0110p008 BAE Room Door I I I 01100009 S/G Slowdown Sample Rm v IV III 01100014 Ion Exchanger Rm v III III 0110b015 BA Transfer Pumps v IV III 01100019 Drum Storage Area v IV III 01113001 Primary Sampling Room (9) IV III II 02078001 At B, & C East Valves C.C v III II 02078002 Top of 12 Hx Rm VIII VII VII o2o7aoo3 BIT Rm Lower Level VII VII VI 02078004 BIT Rm Upper Level VIII VII VI 02078005 Mech. Pen. Area VII VII VI 02078006 - Stm Gen Blowdown Area VII VII VI 02078007 S.W. Piping Room III II II 02078008 Mech. Pen Area VII VII VI 02078009 $;W. Piping Rm III II II 02078011 S.W. Piping Rm III II II 02078012 Elec Pen/Cont Rad v III II Mon. Area (6) (7) 02100002 Main Steam Pen Area v IV III 02100003 Personnel Hatch v IV III 12100005 Counting Room {10) v IV III 2 of 3 SGS-UFSAR Revision 21 December 6, 2004

Table A-4 (Cont.)

Notes

1. Dose rates are due to post accident sources only and do not include normal operating dose rates. Any area not listed is Zone I.

2. This area is behind the partial wall separating this zone from the RHR pump room (Location Code # 01045002, 01045006) .

3. This dose rate is due to the adjacent RHR pump room {Location Code #

01045002 or 01045006) .

4. This area has the same shielding as the adjacent pump cubicles.

5. The designations shown correspond to conditions prior to initiation of SS.

6. Dose rates are due to shine through containment.

7. Containment atmosphere samples can be obtained approximately 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br /> after accident initiation without exceeding personnel exposure guidelines based on SS.

I

8. Containment sump boron analysis can be performed approximately 46 hours5.324074e-4 days <br />0.0128 hours <br />7.60582e-5 weeks <br />1.7503e-5 months <br /> after accident initiation without exceeding personnel exposure guidelines based on SS. I

9. Reactor coolant and containment sump samples can be obtained approximately I

19 hours after accident initiation without exceeding personnel exposure guidelines based on SS.

10. Bounding dose rates are those associated with a Design Basis LOCA in Salem Unit 2.

11. The second designation is for a LOCA in Salem Unit 2.

3 of 3 SGS-OFSAR Revision 23 October 17, 2007

Table A-5 Dose 'Rates Outside Containment Following a Design Basis LOCA in Salem Unit 2 { 1)

Locat*ion Number Location Description Zone No.

1 Hour 1 Day 1 Week 01100005 Chemistry Lab (10) v IV III 01113001 Primary Sampling Room {11) IV III II 12045001 21 RHR Rm VIII VII VII Shielded (2} v IV III 21 RHR'Pmp Rm VIII VII VII 21 RHR Pmp Rm (3) III II I 12045002 21 RHR .Pmp Rm .VIII VII VII 12045003 21 RHR Hx Area VIII VII VI 12045004 21 Cont. Sump Valve Rrn VIII VII VI 12045005 Instrument Radk 102 VIII VII VII 12045006 22 RHR Pmp Rm VIII VII VII 2 2 RHR Pmp Rm ( 3) III II I 12045,007 22 RHR Hx Area VIII VII VI 12045008 22 Cont. Sump Valve Rm VIII VII VI 12055902 21 RHR Valve Rm v IV III 12055003 21 RHR Hx Rm VIII VII VI 12055004 21 RHR Valve Rm VIII VIII VI 12055005 22 RHR Valve Rm v IV III 12055006 22 RHR Hx Rm VIII VII VI 12055007 22 RHR Valve Rm VIII VII VI 12064001 4KV Vital Bus & Battery Rm IV III II 12064003 Laundry & Chern Dr P-ump Rm IV III II 12064004 21 Monitor Tk & Pump Rm IV III III 12064005 22 Monitor Tk & Pump Rm v IV III 12064008 Waste Holdup Tk Rm IV III II 12064009 Waste Holdup Tk Rm IV III II 12064011 Waste Monitor Holdup IV III II Tank Rm 12 0 64 014 21 Waste Gas Compressor Rm IV III II 12064017 22 Waste Gas Compressor Rm IV III II 12064020 Waste Gas Valve Area IV III II 12064021I 21 Gas Decay Tk IV III II 12064022 22 Gas Decay Tk IV III II 12064028 21 HUT Rm IV III II 12064029 22 HUT Rm IV. III II 12064031 Pipeway VIII VII VII 12084002 460/230V Vital IV III III 12084003 Aisle Outside SFP Pump I I I 12084004 Spent Fuel Pit Pump Rm v III III 12084005 21 Safety Inj Prop Rm VIII VII VI 12084006 22 Safety Inj Prop Rm VIII VII VI 12084007 Pipe Alley. VIII VII VII We~t End of Pipeway VII VII VI 12084008 Corridor at CC Hx v III III 12084009 21 CG 'Pump .Rm v III III 12084010 21 Comp Cooling VA Rm VII VI VI 12084012 22 CC Hx Rm III II II 1 of 3 SGS-UFSAR Revision 21 December 6, 2004

Table A-5 (Cont.)

Looatton Number Location Description Zone No.

1 Hour 1 Day 1 Week 12084016 23 Aux FW Pump III II II 12084018 LTD Hx Valve RID I I I 12084019 LTD Hx Rrn IV III II 12084020 Seal Water Hx Valve Rm I I I 12084021 Seal Water Hx Rm IV III II 12084022 Elec. Control Center III 12084024 Vent Duct & Equipment Hatch IV III II 12084025 Corridor at 21 Cont Spray IV III II 12084026 Rm Next to 21 Chrg Pmp VII VII VI 12084027 C02 Fire Equip Rm III II II 12084029 21 Diesel FOST Rrn IV III II 12084034 Chrg Prop Valve Alley (12) VII/III VII/N/A VI/N/A 12084035 21 Chrg Pmp Rrn VIII VII VI 12084036 22 Chrg Pmp Rm VIII VII VI 12084037 23 Chrg Prop Rm VII VII VI 12084038 Cont. Spray Area IV III II 12084041 No.2 Aisle (4) V IV III 12084b46 Stairwell V III III 12100005 Counting Room ( 6) V IV III 12100006 Access Aisle V IV III 12100007 Corridor at BAE (5) III II I 12100008 Boric Acid Evap Rm (5) V IV III BAE Room Door I I I 12100009 PASS Room (8) V IV III 12100013 Waste Evap Rm V III III 12100014 Ion Exchanger Rm V III III 12100015 BA Transfer Pumps V IV III 12100019 Drum Storage Area V IV III 13078001 A, B, & ~ East Valves C.C V III II 13078002 Top of 22 Hx Rrn VIII VII VII 13078003 BIT Rm Lower Level VII VII VI 13078004 BIT Rm Upper Level VIII VII VI 13078005 Mech. -Pen. Area VII VII VI 13078006 Stm Gen Slowdown Area VII VII VI 13078007 S.W. Piping Room III II II 13078008 Mech. Pen Area VII VII VI 13078009 S.W. Piping Rrn III II II 13078011- S.W. Piping Rm III II II 13078012 Elec Pen/Cont Rad V III II Mon.- Area (7} (9}

13100002 Main Steam Pen Area v IV III 13100003 Personnel Hatch v IV III 2 of 3 SGS . . UFSAR Revision 21 December 6; 2004

Table A-5 (Cont.)

Notes

1. Dose rates are due to post accident sources only and do not include normal operating dose rates. Any area not listed is Zone I.

2. This area is behind the partial wall separating this zone from the RHR *pump room (Location Code # 12045002, 12045006) .

3. This dose rate is due to the adjacent RHR pump room (Location Code #

12045002 or 12045006).

4. This area has the same shielding as the adjacent pump cubicles.

5.

6.

The designations shown correspond to conditions prior to initiation of SS.

The dose rates apply only in the north end of the room. Other areas will I

be a zone I.

7. Dose rates are due to shine through containment.

I

8. Dose rates are due to external source~ and will allow limited access to obtain samples. Post accident sampling is addressed in the response to item 2.1.8.a.

9. Containment atmosphere samples can be obtained approximately 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br /> after accident initiation without exceeding personnel exposure guidelines based on SS.

10. Containment sump boron analysis can be performed approximately 46 hours5.324074e-4 days <br />0.0128 hours <br />7.60582e-5 weeks <br />1.7503e-5 months <br /> after accident initiation without exceeding personnel exposure guidelines based on ss. I

11. Reactor coolant and containment sump samples can be obtained approximately 19 hours2.199074e-4 days <br />0.00528 hours <br />3.141534e-5 weeks <br />7.2295e-6 months <br /> after accident initiation without exceeding personnel exposure guidelines based on SS.

12. The second designation is for a LOCA in Salem Unit 1.

3 of 3 SGS-UFSAR Revision 23 October 17, 2007

FIGURE A-1 intentionally deleted.

Refer to Figure 5.1-11 REVISION6 FEBRUARY15, 1987

FIGURE A-2 intentionally deleted.

Refer to Figure 5.1-10 REVISION6 FEBRUARY15,1987

FIGURE A-3 intentionally deleted.

Refer to Figure 3.6-26.

REVISION6 FEBRUARY15, 1987

FIGURE A-4 intentionally deleted.

Refer to Figure 3.6-27 REVISION6 FEBRUARY15, 1987

THIS FIGURE HAS BEEN DELETED. *,

REVISION14 DECEMBER29, 1995 PUBLICSERVICEELECTRICAND GAS COMPANY SALEMNUCLEARGENERATING STATION Updated FSAR FigureA.S

THIS FIGURE HAS BEEN DELETED.

REVISION14 DECEMBER29,1995 PUBLICSERVICEELECTRICANDGASCOMPANY SALEMNUCLEARGENERATING STATlON Updated FSAR FigureA-6