ML18285A595

Revision 19 to Updated Final Safety Analysis Report, Chapter 1, Introduction and General Description of Plant

ML18285A595
Person / Time
Site:	Limerick
Issue date:	09/19/2018
From:	Exelon Generation Co
To:	Office of Nuclear Reactor Regulation
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LGS UFSAR CHAPTER 1 - INTRODUCTION AND GENERAL DESCRIPTION OF PLANT TABLE OF CONTENTS

1.1 INTRODUCTION

1.2 GENERAL PLANT DESCRIPTION 1.2.1 Site Characteristics 1.2.1.1 Location 1.2.1.2 Site Environs and Access 1.2.1.3 Geology 1.2.1.4 Seismology 1.2.1.5 Hydrology 1.2.1.6 Meteorology 1.2.2 Principal Design Criteria 1.2.2.1 General Design Criteria 1.2.2.2 System Design Criteria 1.2.2.2.1 Nuclear System Criteria 1.2.2.2.2 Safety-Related Systems Criteria 1.2.2.2.3 Process Control Systems Criteria 1.2.2.2.4 Power Conversion Systems Criteria 1.2.2.2.5 Electrical Power Systems Criteria 1.2.2.2.6 Auxiliary Systems Criteria 1.2.2.2.7 Radioactive Waste Management Systems Criteria 1.2.2.2.8 Shielding and Access Control Criteria 1.2.2.2.9 Fuel Handling and Storage Facilities 1.2.3 General Arrangement of Structures and Equipment 1.2.4 System Description 1.2.4.1 Nuclear System 1.2.4.1.1 Reactor Core and Control Rods 1.2.4.1.2 Reactor Vessel and Internals 1.2.4.1.3 Reactor Recirculation System 1.2.4.1.4 Residual Heat Removal System 1.2.4.1.5 Reactor Water Cleanup System 1.2.4.1.6 Nuclear Leak Detection System 1.2.4.2 Safety-Related Systems 1.2.4.2.1 Reactor Protection System 1.2.4.2.2 Neutron Monitoring System 1.2.4.2.3 Control Rod Drive System 1.2.4.2.4 Control Rod Velocity Limiter 1.2.4.2.5 Control Rod Drive Housing Supports 1.2.4.2.6 Nuclear System Pressure Relief System 1.2.4.2.7 Reactor Core Isolation Cooling System 1.2.4.2.8 Primary Containment CHAPTER 01 1-i REV. 16, SEPTEMBER 2012

LGS UFSAR TABLE OF CONTENTS (cont'd) 1.2.4.2.9 Primary Containment and Reactor Vessel Isolation Control System 1.2.4.2.10 Secondary Containment 1.2.4.2.11 Main Steam Isolation Valves 1.2.4.2.12 Main Steam Line Flow Restrictors 1.2.4.2.13 Emergency Core Cooling Systems 1.2.4.2.14 Residual Heat Removal System (Containment Cooling) 1.2.4.2.15 Control Room Heating, Ventilating and Air Conditioning System 1.2.4.2.16 Reactor Enclosure Recirculation System and Standby Gas Treatment System 1.2.4.2.17 Standby AC Power Supply 1.2.4.2.18 DC Power Supply 1.2.4.2.19 Residual Heat Removal Service Water System 1.2.4.2.20 Emergency Service Water System 1.2.4.2.21 Main Steam Line Radiation Monitoring System 1.2.4.2.22 Reactor Enclosure and Refueling Area Ventilation Radiation Monitoring System 1.2.4.2.23 Remote Shutdown System 1.2.4.2.24 Standby Liquid Control System 1.2.4.2.25 Information in Section Deleted 1.2.4.2.26 Redundant Reactivity Control System 1.2.4.3 Instrumentation and Control Systems 1.2.4.3.1 Nuclear System Process Control and Instrumentation 1.2.4.3.2 Power Conversion Systems Process Control and Instrumentation 1.2.4.4 Electrical Systems 1.2.4.4.1 Transmission and Generation Systems 1.2.4.4.2 Electric Power Distribution Systems 1.2.4.5 Fuel Handling and Storage Systems 1.2.4.5.1 New and Spent Fuel Storage 1.2.4.5.2 Fuel Pool Cooling and Cleanup System 1.2.4.5.3 Fuel Handling Equipment 1.2.4.6 Cooling Water and Auxiliary Systems 1.2.4.6.1 Service Water System 1.2.4.6.2 Reactor Enclosure Cooling Water System 1.2.4.6.3 Turbine Enclosure Cooling Water System 1.2.4.6.4 Fire Protection System 1.2.4.6.5 Plant Heating, Ventilating, and Air Conditioning Systems 1.2.4.6.6 Instrument Air System 1.2.4.6.7 Clarified Water System 1.2.4.6.8 Demineralized Water Makeup System 1.2.4.6.9 Plant Equipment and Floor Drainage System 1.2.4.6.10 Process Sampling System 1.2.4.6.11 Plant Communication System 1.2.4.7 Power Conversion Systems 1.2.4.7.1 Turbine-Generator 1.2.4.7.2 Main Steam System 1.2.4.7.3 Main Condenser 1.2.4.7.4 Main Condenser Evacuation System 1.2.4.7.5 Steam Seal System 1.2.4.7.6 Turbine Bypass and Pressure Control System 1.2.4.7.7 Circulating Water System CHAPTER 01 1-ii REV. 16, SEPTEMBER 2012

LGS UFSAR TABLE OF CONTENTS (cont'd) 1.2.4.7.8 Condensate Cleanup System 1.2.4.7.9 Condensate and Feedwater Systems 1.2.4.7.10 Condensate and Refueling Water Storage Facilities 1.2.4.8 Radioactive Waste Systems 1.2.4.8.1 Liquid Radwaste System 1.2.4.8.2 Solid Radwaste System 1.2.4.8.3 Gaseous Radwaste System 1.2.4.9 Radiation Monitoring and Control 1.2.4.9.1 Process Radiation Monitoring 1.2.4.9.2 Area Radiation Monitors 1.2.4.9.3 Site Environs Radiation Monitors 1.2.4.10 Shielding 1.2.5 Control of Unit 2 Construction Activities During Unit 1 Operation 1.3 COMPARISON TABLES 1.3.1 Comparisons with Similar Facility Designs 1.3.2 Comparison of Final and Preliminary Information 1.4 IDENTIFICATION OF AGENTS AND CONTRACTORS 1.4.1 Applicant 1.4.2 Architect-Engineer and Constructor 1.4.3 Nuclear Steam Supply System Supplier 1.4.4 Turbine-Generator Supplier 1.4.5 Consultants 1.5 REQUIREMENTS FOR FURTHER TECHNICAL INFORMATION 1.5.1 Current Development Programs 1.5.1.1 Instrumentation for Vibration of Reactor Intervals 1.5.1.2 Core Spray Distribution 1.5.1.3 Core Spray and Core Flooding Heat Transfer Effectiveness 1.5.1.4 Verification of Pressure-Suppression Design 1.5.1.5 Critical Heat Flux Testing 1.5.1.6 Fuel Assembly Structural Testing 1.5.2 References 1.6 MATERIAL INCORPORATED BY REFERENCE/GENERAL REFERENCE 1.7 DRAWINGS AND OTHER DETAILED INFORMATION 1.8 CONFORMANCE TO NRC REGULATORY GUIDES 1.9 STANDARD DESIGNS 1.10 SYMBOLS AND TERMS CHAPTER 01 1-iii REV. 16, SEPTEMBER 2012

LGS UFSAR TABLE OF CONTENTS (cont'd) 1.10.1 Text Acronyms 1.10.2 Logic Symbols 1.10.3 Piping Identification 1.10.4 Valve Identification 1.10.5 Equipment Numbering and Location 1.10.6 Electrical Component Identification 1.10.6.1 Equipment Location Numbers 1.10.6.2 Scheme Cable Numbers 1.10.6.3 Raceway Numbers 1.11 RRRC CATEGORY 1, 2, 3, AND 4 MATTERS 1.11.1 Discussion of Categories 1.11.2 References 1.12 UNRESOLVED SAFETY ISSUES 1.12.1 Introduction 1.12.2 Applicability to LGS 1.12.3 Discussions of Tasks as They Relate to LGS 1.12.4 References 1.13 TMI-2 RELATED REQUIREMENTS FOR NEW OPERATING LICENSES 1.13.1 NUREG-0737, Clarification of the TMI Action Plan Requirements 1.13.2 TMI Action Plan Requirements for Applicants for an Operating License (Enclosure 2 to NUREG-0737) 1.13.3 References CHAPTER 01 1-iv REV. 16, SEPTEMBER 2012

LGS UFSAR CHAPTER 1 - INTRODUCTION AND GENERAL DESCRIPTION OF PLANT LIST OF TABLES TABLE TITLE 1.3-1 Comparison of Nuclear Steam Supply System Design Characteristics 1.3-2 Comparison of Engineered Safety Features and Auxiliary Systems Design Characteristics 1.3-3 Comparison of Power Conversion System Design Characteristics 1.3-4 Comparison of Containment Design Characteristics 1.3-5 Comparison of Structural Design Characteristics 1.3-6 Radioactive Waste Management Systems Design Characteristics 1.3-7 Comparison of Electrical Power Systems Design Characteristics 1.3-8 Significant Design Changes from PSAR to FSAR 1.6-1 Referenced Reports 1.7-1 Electrical Drawings 1.7-2 Figure Index for Plant Systems 1.7-3 Control and Instrumentation Drawings 1.7-4 Figure Index for Miscellaneous Drawings 1.8-1 Component Identification for Code Case N242 1.10-1 Acronyms Used in UFSAR 1.10-2 Piping and Valve Class Identification 1.11-1 Correlation of LGS UFSAR Sections with Category 2, 3, and 4 Matters 1.13-1 Vital Area Radiation Doses 1.13-2 Radiation Doses for Vital Area Access Paths 1.13-3 Solutions to Potential Vital Area Access Problems CHAPTER 01 1-v REV. 16, SEPTEMBER 2012

LGS UFSAR LIST OF TABLES (cont'd)

TABLE TITLE 1.13-4 Potential Unplanned Release Paths 1.13-5 Access Path Identification 1.13-6 Radiation Qualification of Safety-Related Equipment 1.13-7 X/Q Values for Vital Areas 1.13-8 High-Range Noble Gas Effluent Monitors (Table II.F.1-1) 1.13-9.1 Interim Procedures for Quantifying High-Level Accidental Radioactivity Releases (Table II.F.1-2) 1.13-10 Sampling and Analysis or Measurement of High-Range Radioiodine and Particulate Effluents in Gaseous Effluent Streams (Table II.F.1-3) 1.13-11 Containment High-Range Radiation Monitor (Table II.F.1-4) 1.13-12 Information Required for Control Room Habitability Evaluation (Table III.D.3.4-1)

CHAPTER 01 1-vi REV. 16, SEPTEMBER 2012

LGS UFSAR CHAPTER 1 - INTRODUCTION AND GENERAL DESCRIPTION OF PLANT LIST OF FIGURES FIGURE TITLE 1.2-1 Deleted 1.2-2 Deleted 1.2-3 Deleted 1.2-4 Deleted 1.2-5 Deleted 1.2-6 Deleted 1.2-7 Deleted 1.2-8 Deleted 1.2-9 Deleted 1.2-10 Deleted 1.2-11 Deleted 1.2-12 Deleted 1.2-13 Deleted 1.2-14 Deleted 1.2-15 Deleted 1.2-16 Deleted 1.2-17 Deleted 1.2-18 Deleted 1.2-19 Deleted 1.2-20 Deleted 1.2-21 Deleted 1.2-22 Deleted CHAPTER 01 1-vii REV. 16, SEPTEMBER 2012

LGS UFSAR LIST OF FIGURES (cont'd)

FIGURE TITLE 1.2-23 Deleted 1.2-24 Deleted 1.2-25 Deleted 1.2-26 Deleted 1.2-27 Deleted 1.2-28 Deleted 1.2-29 Deleted 1.2-30 Deleted 1.2-31 Deleted 1.2-32 Deleted 1.2-33 Deleted 1.2-34 Deleted 1.2-35 Deleted 1.2-36 Deleted 1.2-37 Deleted 1.2-38 Deleted 1.2-39 Deleted 1.2-40 Deleted 1.2-41 Deleted 1.2-42 Deleted 1.2-43 Deleted 1.2-44 Deleted 1.2-45 Deleted CHAPTER 01 1-viii REV. 16, SEPTEMBER 2012

LGS UFSAR LIST OF FIGURES (cont'd)

FIGURE TITLE 1.2-46 Deleted 1.2-47 Deleted 1.2-48 Deleted 1.2-49 Deleted 1.2-50 Deleted 1.2-51 Deleted 1.2-52 Deleted 1.2-53 Deleted 1.2-54 Deleted 1.2-55 Deleted 1.2-56 Deleted 1.2-57 Deleted 1.2-58 Deleted 1.2-59 Deleted 1.2-60 Deleted 1.2-61 Deleted 1.2-62 Deleted 1.2-63 Deleted 1.2-64 Deleted 1.2-65 Deleted 1.2-66 Deleted 1.2-67 Deleted 1.2-68 Deleted CHAPTER 01 1-ix REV. 16, SEPTEMBER 2012

LGS UFSAR LIST OF FIGURES (cont'd)

FIGURE TITLE 1.2-69 Deleted 1.2-70 Deleted 1.2-71 Deleted 1.2-72 Deleted 1.2-73 Deleted 1.2-74 Deleted 1.2-75 Deleted 1.2-76 Deleted 1.2-77 Deleted 1.2-78 Deleted 1.2-79 Deleted 1.2-80 Deleted 1.2-81 Deleted 1.2-82 Deleted 1.2-83 RHR and Core Spray Strainer General Arrangement Plan, Reactor Building Units 1 and 2, Areas 13, 14, 17, and 18, el 181 - 11 1.2-84 Reactor System Heat Balance 1.10-1 Deleted 1.10-2 Logic Symbols 1.13-1 Dose Rate Reduction Factors for ECCS/RHR Piping (0 to 24 hr) 1.13-2 Dose Rate Reduction Factors for ECCS/RHR Piping (24 to 720 hr)

CHAPTER 01 1-x REV. 16, SEPTEMBER 2012

LGS UFSAR CHAPTER 1 - INTRODUCTION AND GENERAL DESCRIPTION OF PLANT

1.1 INTRODUCTION

This UFSAR is submitted to fulfill the requirements of 10CFR50.71(e) for Exelons nuclear power station designated as the Limerick Generating Station, Units 1 and 2. These units hold full power utilization facility (Class 103) licenses, NPF-39 and NPF-85. These licenses were issued in August 1985 and August 1989 respectively.

LGS is located on the east bank of the Schuylkill River in Limerick Township of Montgomery County, Pennsylvania, approximately 4 river miles downriver from Pottstown, 35 river miles upriver from Philadelphia, and 49 river miles above the confluence of the Schuylkill with the Delaware River. The site contains 595 acres (423 acres in Montgomery County and 172 in Chester County).

Each of the LGS units employs a GE BWR originally designed and licensed to operate at a rated core thermal power of 3293 MWt (100% steam flow) with a corresponding gross electrical output of 1092 MWe. Approximately 37 MWe are used for auxiliary power. Subsequent to issuing the original operating licenses, LGS Units 1 and 2 were reevaluated with regard to rerating power to 3458 MWt (Rerate Power). The acceptability of the rerate evaluations stems from the fact that LGS Units 1 and 2 were originally designated for steam flow capabilities at least 5% above its original rating. In addition, improvements in the analytical techniques based on more realistic assumptions, plant performance feedback, and the latest fuel designs resulted in a significant increase in the calculated operational margins related to safety analyses. Subsequently, the core thermal power was uprated from 3458 MWt to 3515 MWt as part of the measurement uncertainty recapture power uprate (MUR PU). The existing analyses assume a 2% uncertainty in feedwater flow, which is reduced to 0.3% using leading edge ultrasonic flow meters. This is acceptable because the analyzed conditions and margins of the safety analyses are not affected by this change in FW flow measurement.

The reactor design power level used in various analyses is discussed in Section 6.3 and Chapter 15.

The containment system, designed by Bechtel Power Corporation, limits the release of radioactive materials to the environs subsequent to the occurrence of a postulated LOCA so that the offsite doses are below the values stated in 10CFR50.67. The design employs the drywell/pressure-suppression features of the BWR/Mark II containment concept. The containment consists of a dual barrier: the primary containment, and the secondary containment. The primary containment is a steel-lined reinforced concrete pressure-suppression system of the over-and-under configuration. The secondary containment is the enclosure that encloses the reactor, and its primary containment, and fuel storage areas.

Condenser cooling is provided by water circulated through natural draft cooling towers.

The LGS PSAR was submitted on February 26, 1970 (AEC Dockets 50-352 and 50-353). The construction permits, CPPR-106 and CPPR-107, were originally issued on June 19, 1974.

Environmental impact is discussed in the Applicant's Environmental Report - Construction Permit Stage (Revised) dated May 1972. The Atomic Energy Commission (now Nuclear Regulatory Commission) issued the LGS Final Environmental Statement Construction Stage in November 1973.

CHAPTER 01 1.1-1 REV. 16, SEPTEMBER 2012

LGS UFSAR The LGS FSAR was originally submitted on March 17, 1981 and docketed on July 27, 1981. The NRC issued its SER in August 1983 and nine supplements to NUREG-0991 through August 1989.

A discussion of environmental impact was also submitted as the EROL, and the NRC issued its LGS Final Environmental Statement Operating License Stage, NUREG-0974, in April 1984.

The LGS Unit 1 low power (5%) operating license (NPF-27) was issued on October 26, 1984 and the full power operating license (NPF-39) was issued on August 8, 1985. The LGS Unit 1 entered commercial operation on February 1, 1986.

The LGS Unit 2 was issued an operating license (NPF-83) to load fuel and conduct testing up to, but not including, initial criticality on June 22, 1989. The low power (5%) operating license (NPF-

84) was issued July 10, 1989 and the full power operating license (NPF-85) was issued August 25, 1989. The LGS Unit 2 entered commercial operation on January 8, 1990. The licensee received a license amendment for a 5% increase in rated power to 3458 MWt for LGS Unit 2 on February 16, 1995 and for Unit 1 on January 24, 1996. The licensee received license amendments for an additional 1.65% increase in rated power to 3515 MWt for Unit 1 and Unit 2 on April 8, 2011.

The FSAR was prepared and submitted in accordance with 10CFR50.34(b). Its format and content are in accordance with Regulatory Guide 1.70 (Rev 3), "Standard Format and Content of Safety Analysis Reports for Nuclear Power Plants", November, 1978. Following its initial update, the UFSAR will be updated in accordance with 10CFR50.71.

The relationships of other various reports submitted by the licensee are discussed below.

As discussed in Appendix 9A, the Fire Protection Evaluation Report was prepared and submitted in response to a September 30, 1976 NRC request. Since it contains the information suggested by Regulatory Guide 1.70 to be provided in Section 9.5.1.3, the FPER, in its entirety, was incorporated into the UFSAR as Appendix 9A in accordance with 10CFR50.32. The FPER will be updated in accordance with 10CFR50.71.

As discussed in Appendix 3A, the Design Assessment Report was prepared and submitted in response to a generic industry concern of thermohydrodynamic loads resulting from SRV operations and/or discharges during a LOCA. The DAR contains considerable design information and will be updated in accordance with 10CFR50.71. Proprietary DAR information is discussed in Appendix 3B.

The Quality Assurance Program was prepared and submitted in accordance with 10CFR50.34(b).

Its format and content were prepared in accordance with Regulatory Guide 1.70 (Rev 3). The Quality Assurance Program is incorporated into the UFSAR as Section 17.2 and will be updated in accordance with 10CFR50.54(a)(3) and 10CFR50.71.

In accordance with 10CFR50.34(b)(6)(v) and Regulatory Guide 1.70, the Emergency Plan, while a separate report, is referenced in Section 13.3 of the UFSAR. The Emergency Plan will be updated in accordance with 10CFR50.54(q) and 10CFR50, Appendix E.

The Security Plan was prepared and submitted in accordance with 10CFR50.34(c). It is identified as a separate report withheld from public disclosure in UFSAR Section 13.6, in accordance with Regulatory Guide 1.70 (Rev 3). The Security Plan will be updated in accordance with 10CFR50.54(p).

CHAPTER 01 1.1-2 REV. 16, SEPTEMBER 2012

LGS UFSAR The Safeguards Contingency Plan was prepared and submitted in accordance with 10CFR50.34(c), and withheld from public disclosure pursuant to 10CFR2.790(d). No discussion of this report is provided in the UFSAR, consistent with Regulatory Guide 1.70 (Rev 3). The Safeguards Contingency Plan will be updated in accordance with 10CFR50.54(p).

As discussed in Section 1.0 of the Environmental Qualification Report, the EQR was prepared and submitted in response to a May 1980 Commission Memorandum and Order (CLI 80-21). It has been revised to fulfill the requirements of 10CFR50.49. The EQR is referenced in Section 3.11 of the UFSAR but is considered to be a licensee working document and update submittals are not planned.

The EROL was prepared and submitted in accordance with 10CFR51.21. Its format and content are in accordance with Regulatory Guide 4.2 (Rev 2), "Preparation of Environmental Reports for Nuclear Power Plants", July 1976. Regulatory Guide 4.2, section 7.1, "Station Accidents Involving Radioactivity" was later superseded by the Commission's Interim Position on Accident Consideration Under NEPA (45FR40101).

As discussed in section 1.1 of the Probabilistic Risk Assessment (PRA) and the Severe Accident Risk Assessment (SARA), the PRA and SARA were prepared and submitted in response to an initial May 6, 1980 NRC request. Because they contain the information required by the NRC's Interim Position on Accident Considerations under NEPA (45FR40101), the PRA and SARA were used in the analysis performed for EROL Section 7.1, in accordance with 10CFR50.32. At the request of the NRC Limerick Project Manager, the PRA is acknowledged in UFSAR Section 15.11; it is not referenced therein. The PRA and SARA are considered to be licensee working documents and update submittals are not planned.

CHAPTER 01 1.1-3 REV. 16, SEPTEMBER 2012

LGS UFSAR 1.2 GENERAL PLANT DESCRIPTION 1.2.1 SITE CHARACTERISTICS A summary of the site characteristics for LGS is provided below. Detailed discussions on the site characteristics are provided in Chapter 2 of the UFSAR.

1.2.1.1 Location LGS is located in southeastern Pennsylvania on the Schuylkill River about 1.7 miles southeast of the limits of the Borough of Pottstown and about 20.7 miles northwest of the Philadelphia city limits. The Schuylkill River passes through the site and separates the western portion, which is located in East Coventry Township, Chester County, from the eastern portion, which is partly in Limerick Township and partly in Lower Pottsgrove Township, both in Montgomery County, Pennsylvania. All of the major plant structures are located in Limerick Township. The site location map is shown in Figure 2.1-1.

1.2.1.2 Site Environs and Access The site is located in gently rolling countryside, traversed by numerous valleys containing small creeks or streams that empty into the Schuylkill River. Two parallel streams, Possum Hollow Run and Brooke Evans Creek, cut through the site in wooded valleys, running southwest into the Schuylkill River.

The area surrounding the site can be generally classified as rural and open. A large portion of the land is used for agricultural purposes with the remainder of the area being either vacant or woodland with scattered residences.

The main access to the plant is from U.S. Highway 422 which runs east and west about one mile north of the site. Access to the site and all activities thereon are under the control of the licensee.

1.2.1.3 Geology The site is situated in the Triassic Lowland section of the Piedmont Physiographic Province. This section is characterized by a gently rolling land surface formed on an eroded low plateau.

The rocks in the region surrounding the site include Precambrian and Lower Paleozoic crystalline rocks and folded sedimentary strata, and essentially unfolded Triassic sedimentary rocks and igneous intrusions. The Triassic rocks belong to the Newark Group which is divided into the basal Stockton Formation and the Brunswick, Lockatong, and Hammer Creek Lithofacies.

Bedrock at the site underlies a thin cover of residual soil. The Brunswick red siltstone, sandstone, and shale is the predominant bedrock formation. Gray shale and argillite of the Lockatong Lithofacies, light gray sandstones and conglomerates of the Hammer Creek Lithofacies, and intruded diabase and associated hornfels are also found in the area. The strata exhibit gentle homoclinal dips to the north and northwest. The thickness of the Newark Group overlying the Paleozoic and Precambrian basement rocks at the site is on the order of 8000 feet.

The dominant structural feature of the region is the Regional Appalachian Orogenic Belt. This belt is marked by the northeast- southwest orientation of the axes and lineation of most of the structural features and stratigraphic contacts.

CHAPTER 01 1.2-1 REV. 19, SEPTEMBER 2018

LGS UFSAR 1.2.1.4 Seismology The seismicity of the site was evaluated on the basis of historical earthquakes, damage resulting from these shocks, and the regional and local geologic structure. The site lies in a region that has experienced a moderate amount of earthquake activity. Most of the reported earthquakes have occurred in the Piedmont province. Some minor shocks have occurred in a northeast-southwest trend along the Fall Zone, the physiographic boundary between the Piedmont and the Coastal Plain to the southeast. Some scattered activity has occurred in the Coastal Plain. No recent faulting has been mapped in the area of the site.

Based on the seismic history and the geologic structure of the region, no significant earthquake ground motion is expected at the site during the life of the proposed facility. Despite this demonstrative evidence to the contrary, the remote possibility that the geologic structure in the epicentral areas of the significant regional earthquakes could exist in the site area is considered.

Thus, a design basis earthquake is hypothesized equivalent to the 1871 Wilmington, Delaware earthquake (Intensity VII) near the site. Such an event is highly improbable and this hypothesis is very conservative.

The plant has the capability for safe shutdown if subjected to a peak horizontal ground acceleration at foundation level of 0.15 g. Seismic Category I structures are founded on the competent siltstone and sandstone bedrock of the Brunswick Lithofacies. Design spectra consistent with the safe shutdown earthquake are used for the dynamic analysis of the seismic Category I structures and equipment.

1.2.1.5 Hydrology In the site area, Triassic-age siltstone, sandstone, and shale are found at shallow depths beneath a thin cover of residual soils. The residual soils are relatively impermeable. Most groundwater in the area is found in joints, fractures, and other secondary openings in the rock. The groundwater table is found at relatively shallow depths, except in the vicinity of pumping wells. Because of the limited quantities of available groundwater, surface water is the primary source of supply in the region. Groundwater accounts for only about 3% of the total industrial and commercial use in the region. However, numerous domestic wells extract small quantities of water from the Triassic strata.

A number of wells are located in the general site area. However, the geologic, hydrologic, and topographic conditions are such that the possibility of any adverse effect on these wells by operation of LGS is extremely remote.

The flows of the Schuylkill vary widely at different points along the river. This is mainly due to the varying topography and climatological and geohydrologic conditions along its course. The extreme and average daily flows as recorded at Pottstown gauging station (about 5.5 river miles upstream from the site) are:

Flow (cfs) Date Minimum 87 August 13, 1930 (instantaneous)

Average 1793 October 1926-September 1969 (daily)

Maximum 95,900 June 1972 (instantaneous)

CHAPTER 01 1.2-2 REV. 19, SEPTEMBER 2018

LGS UFSAR The probable maximum flood peak and stage at the plant site are estimated to be 500,000 cfs and el 174' (MSL), respectively.

The principal uses of the Schuylkill River are for municipal and industrial water supply. The river is also used for recreational fishing and boating.

1.2.1.6 Meteorology The general climate of the site is best described as humid continental. The region is dominated by continental air masses in winter, and by alternating continental and maritime tropical air masses in the summer. The site is near the track of most eastwardly moving low pressure systems that are brought from the interior of the U.S. by the prevailing westerlies. Annual average wind speeds in the region are between 9 and 10 mph and temperatures rarely exceed 100?F or drop below 0?F. The region receives a moderate amount of precipitation which is well distributed over the year.

Five years of meteorological data collected on the site have verified that the general regional conditions do exist at the site and that no unusual meteorological conditions prevail.

1.2.2 PRINCIPAL DESIGN CRITERIA The principal criteria for design, construction, and testing of LGS are summarized below. Specific criteria, codes, and standards are addressed in Sections 3.1 and 3.2.

1.2.2.1 General Design Criteria The LGS design conforms to the requirements given in 10CFR50, Appendix A, "General Design Criteria for Nuclear Power Plants." Specific compliance is discussed in Section 3.1.

a. The plant is designed, fabricated, erected, and operated to produce electrical power in a safe and reliable manner.

b. The plant is designed, fabricated, erected, and operated in such a way that the release of radioactive materials to the environment does not exceed the limits and guideline values of applicable government regulations pertaining to the release of radioactive materials for normal operations, and for abnormal transients and accidents. Safety-related systems are designed to permit safe plant operation and to accommodate postulated accidents without endangering the health and safety of the public.

1.2.2.2 System Design Criteria 1.2.2.2.1 Nuclear System Criteria

a. The fuel cladding is designed to retain integrity, so that any failures are within acceptable limits, as a radioactive material barrier for the design power range and for any abnormal transient.

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LGS UFSAR

b. Those portions of the nuclear system that form part of the nuclear system process barrier are designed to retain integrity as a radioactive material barrier during normal operation and following abnormal operational transients and accidents.

c. Heat removal systems are provided to remove heat generated in the reactor core for the full range of normal operational conditions from shutdown to design power, and for any abnormal operational transient. Heat removal systems are provided to remove decay heat generated in the core under remote circumstances where the normal operational heat removal systems become inoperative. The capacity of such systems is adequate to prevent fuel cladding damage.

d. The reactor core and reactivity control systems are designed so that control rod action is capable of bringing the core subcritical and maintaining it so, even with the rod of highest reactivity worth fully withdrawn and unavailable for insertion.

e. Backup reactor shutdown capability is provided independent of normal reactivity control provisions. This backup system has the capability to shut down the reactor from any operating condition, and subsequently to maintain the shutdown condition.

f. The nuclear system is designed so there is no tendency for divergent oscillation of any operating characteristics through hardware and administrative controls, considering the interaction of the nuclear system with other appropriate plant systems.

g. The reactor core is designed so that its nuclear characteristics do not contribute to a divergent power transient through hardware and administrative controls .

1.2.2.2.2 Safety-Related Systems Criteria 1.2.2.2.2.1 General

a. Safety systems act in response to abnormal operational transients so that fuel cladding retains its integrity as a radioactive material barrier to keep any failures within acceptable limits.

b. Safety systems and ESF act to ensure that no damage to the nuclear system process barrier results from internal pressures caused by abnormal operational transients or accidents.

c. Where positive, precise actions are immediately required in response to accidents, these actions are automatic and require no decision or manipulation of controls by operations personnel.

d. Essential safety actions are carried out by equipment of sufficient redundancy and independence so that no single failure of active components prevents the required actions. For systems or components to which IEEE 279 and/or IEEE 308 are applicable, single failures of passive electrical components are considered as well as single failures of active components in recognition of the higher anticipated failure rates of passive electrical components relative to passive mechanical components.

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LGS UFSAR

e. Features of the station that are essential to the mitigation of accident consequences are designed, fabricated, and erected to quality standards that reflect the importance of the safety function to be performed.

f. The design of safety systems and ESF includes allowances for environmental phenomena at the site.

g. Provision is made for control of active components of nuclear safety systems and ESF from the control room.

h. Safety systems and ESF are designed to permit demonstration of their functional performance requirements.

1.2.2.2.2.2 Containment and Isolation Criteria

a. A primary containment is provided to completely enclose the reactor vessel. It is designed to act as a radioactive material barrier during accidents that release radioactive material into the primary containment. It is possible to test the primary containment integrity and leak-tightness at periodic intervals.

b. A secondary containment that completely encloses both the primary containment and fuel storage areas is provided and designed to act as a radioactive material barrier.

c. The primary and secondary containments, in conjunction with other ESF, act to prevent radioactive material released from the containment volumes from exceeding the guideline values of applicable regulations.

d. Provisions are made for the removal of energy from within the primary containment as necessary to maintain the integrity of the containment system following accidents that release energy to the primary containment.

e. Piping that both penetrates the primary containment structure and could serve as a path for the uncontrolled release of radioactive material to the environs is automatically isolated whenever such uncontrolled radioactive material release is threatened. Such isolation is effected in time to prevent radiological effects from exceeding the guideline values of applicable regulations.

1.2.2.2.2.3 Emergency Core Cooling Systems Criteria

a. The ECCS is provided to prevent excessive fuel clad temperature as a result of a LOCA.

b. The ECCS provides for continuity of core cooling over the complete range of postulated break sizes in the nuclear system process barrier.

c. The ECCS is diverse, reliable, and redundant.

d. Operation of the ECCS is initiated automatically when required, regardless of the availability of offsite power supplies and the normal generating system of the plant.

1.2.2.2.3 Process Control Systems Criteria CHAPTER 01 1.2-5 REV. 19, SEPTEMBER 2018

LGS UFSAR 1.2.2.2.3.1 Nuclear System Process Control Criteria

a. Control equipment is provided for recirculation flow control to allow the operator to respond manually to load changes.

b. It is possible to manually control the reactor power level.

c. Control of the nuclear system is possible from a single location.

d. Nuclear system process controls are arranged to allow the operator to rapidly assess the condition of the nuclear system and to locate process system malfunctions.

e. Interlocks or other automatic equipment are provided as a backup to procedural controls to avoid conditions requiring the actuation of nuclear safety systems or ESF.

f. If the control room is inaccessible, it is possible to bring the reactor from power range operation to a cold shutdown condition by manipulation of controls and equipment that are available outside of the control room.

1.2.2.2.3.2 Power Conversion Systems Process Control and Instrumentation Criteria

a. Controls are provided to maintain temperature and pressure to below design limitations. These systems result in a stable operation and response for all allowable variations.

b. Controls and instrumentation are designed to provide equipment protection, indication, and alarm in the event of power conversion system trouble.

c. Control of the power conversion system is possible from locations accessible during normal operation.

d. Controls are provided to ensure adequate cooling of power conversion system equipment.

e. Controls are provided to ensure adequate condensate purity.

f. Controls are provided to regulate the supply of water so that adequate reactor vessel water level is maintained.

1.2.2.2.3.3 Electrical Power Systems Process Control Criteria

a. Controls are provided to ensure that sufficient electrical power is provided for startup, normal operation, and to attain prompt shutdown and continued maintenance of the station in a safe condition.

b. Control of the electrical power system is possible from locations accessible during normal operation.

1.2.2.2.4 Power Conversion Systems Criteria CHAPTER 01 1.2-6 REV. 19, SEPTEMBER 2018

LGS UFSAR

a. The power conversion system components are designed to produce electrical power from the steam coming from the reactor, condense the steam into water, and return the water to the reactor as heated feedwater, with a major portion of its gases and particulate impurities removed.

b. The power conversion system components are designed to ensure that fission products or radioactivity associated with the steam and condensate are safely contained inside the system or are released under controlled conditions in accordance with waste disposal procedures and the plant Technical Specifications.

1.2.2.2.5 Electrical Power Systems Criteria

a. The station electrical power systems are designed to efficiently deliver the electrical power generated.

b. Sufficient normal and standby auxiliary sources of electrical power are provided to attain prompt shutdown and continued maintenance of the station in a safe condition. The capacity of the power sources is adequate to accomplish all required ESF under postulated DBA conditions.

1.2.2.2.6 Auxiliary Systems Criteria

a. Fuel handling and storage facilities are designed to prevent criticality and to maintain adequate shielding and cooling for spent fuel.

b. Multiple independent station auxiliary systems are provided for the purpose of cooling and servicing the station, the reactor, and the station containment systems under various normal and abnormal conditions.

c. Auxiliary systems that are not required to effect safe shutdown of the reactor or maintain it in a safe condition are designed so that a failure of these systems does not prevent the essential systems from performing their design functions.

1.2.2.2.7 Radioactive Waste Management Systems Criteria

a. Gaseous, liquid, and solid waste management facilities are designed so that the discharge of radioactive effluents and offsite shipment of radioactive materials are made in accordance with applicable regulations.

b. The waste management systems, design includes means of informing station operations personnel whenever operational limits on the release of radioactive material are exceeded.

1.2.2.2.8 Shielding and Access Control Criteria

a. Radiation shielding is provided, and access control patterns are established, to allow the operating staff to control radiation doses within the limits of applicable regulations in any mode of normal station operation.

b. The control room is shielded against radiation and has suitable environmental control so that occupancy under DBA conditions is possible.

CHAPTER 01 1.2-7 REV. 19, SEPTEMBER 2018

LGS UFSAR 1.2.2.2.9 Fuel Handling and Storage Facilities Fuel handling and storage facilities are located in the refueling area (Zone III) of the secondary containment and are designed to preclude criticality and to maintain adequate shielding and cooling for spent fuel.

1.2.3 GENERAL ARRANGEMENT OF STRUCTURES AND EQUIPMENT The principal structures are listed below:

a. Main power block comprised of the following:

1. Two reactor enclosures with common refueling area

2. Two turbine enclosures with common operating floor

3. One control structure with common control room

4. Two diesel generator enclosures

5. One radwaste enclosure

6. One chemistry laboratory expansion

7. One administration building

8. One auxiliary boiler enclosure

9. One warehouse and shop

b. One circulating water pump structure

c. Two cooling towers with two acid/chlorine enclosures and a common valve and meter pit

d. One spray pond and spray pond pump structure

e. One Schuylkill pump structure

f. One Perkiomen pump structure

g. One water treatment enclosure

h. One fuel oil pump structure

i. One sewage treatment plant The arrangement of structures on the site is shown in drawing C-2. The general arrangements for the major power block structures and the spray pond pump structure are shown in drawings M-110, M-111, M-112, M-113, M-114, M-115, M-116, M-117, M-118, M-119, M-120, M-121,M-122, M-123, M-124, M-125, M-126, M-127, M-128, M-129, M-130, M-131, M-132, M-133, M-134, M-135, M-136, M-137, M-138, M-140, M-141, M-142, M-143, M-144, M-145, M-146, M-388, M-389, and M-390. The layout of piping and equipment within the reactor enclosure and primary containment is shown in drawings M-206, M-207, M-208, M-209, M-210, M-211, M-213, M-215, M-217, M-218, M-219, M-220, M-221, M-222, M-223, M-225, M-226, M-227, M-228, M-229, M-230, M-231, M-232, M-234, M-235, M-236, M-237, M-238, M-239, M-240, M-241, M-242, M-246, M-288, M-289, M-290, M-291, M-292, M-293, M-295, M-296, M-297, M-298, M-299, M-CHAPTER 01 1.2-8 REV. 19, SEPTEMBER 2018

LGS UFSAR 300, M-301, M-302, M-303, M-305, M-306, M-307, M-308, M-309, M-310, M-311, M-312, M-313, M-316, M-317, M-318, M-319, M-320, M-321, M-322, M-323, and M-326.

1.2.4 SYSTEM DESCRIPTION A summary of the systems provided for LGS is provided below.

1.2.4.1 Nuclear System The nuclear system includes a single-cycle, forced circulation, GE BWR producing steam for direct use in the steam turbine. A heat balance showing the major parameters of the nuclear system for the rated power condition is shown in Figure 1.2-84.

1.2.4.1.1 Reactor Core and Control Rods The fuel for the reactor core consists of slightly enriched uranium dioxide pellets contained in sealed Zircaloy-2 fuel rods. These fuel rods are assembled into individual fuel assemblies. Gross control of the core is achieved by movable, bottom-entry control rods. The control rods are of cruciform shape and are dispersed throughout the lattice of fuel assemblies. The rods are controlled by individual hydraulic systems.

1.2.4.1.2 Reactor Vessel and Internals The reactor vessel contains the core and supporting structure; the steam separators and dryers; the jet pumps; the control rod guide tubes; distribution lines for the feedwater, and core spray; the incore instrumentation; and other components. The main connections to the vessel include the steam lines, the coolant recirculation lines, the feedwater lines, the CRD and nuclear instrumentation housings, and the ECCS lines.

The reactor vessel is designed and fabricated in accordance with applicable codes for a pressure of 1250 psig. The nominal operating pressure is 1060 psia in the steam space above the separators. The vessel is fabricated of carbon steel and is clad internally with stainless steel (except for the top head which is not clad).

The reactor core is cooled by demineralized feedwater that enters the lower portion of the core and is heated as it flows upward around the fuel rods. The steam leaving the core is dried by steam separators and dryers located in the upper portion of the reactor vessel. The steam is then directed to the turbine through four main steam lines. Each steam line is provided with two isolation valves in series, one on each side of the primary containment barrier.

1.2.4.1.3 Reactor Recirculation System The reactor recirculation system consists of two recirculation pump loops external to the reactor vessel. These loops provide the piping path for the driving flow of water to the reactor vessel jet pumps that provide a continuous internal circulation path for the major portion of the core coolant flow. Each loop has one motor-driven recirculation pump. Recirculation pump speed can be varied to allow some control of reactor power level through the effects of coolant flow rate on moderator void content.

1.2.4.1.4 Residual Heat Removal System CHAPTER 01 1.2-9 REV. 19, SEPTEMBER 2018

LGS UFSAR The RHR system consists of pumps, heat exchangers, and piping that fulfill the following functions:

a. Removal of decay and sensible heat during and after plant shutdown

b. Injection of water into the reactor vessel following a LOCA, to reflood the core independent of other core cooling systems. This is discussed Section 1.2.4.2.13.

c. Removal of heat from the primary containment following a LOCA to limit the increase in primary containment pressure. This is accomplished by cooling and recirculating the suppression pool water (containment cooling) and by spraying the drywell and suppression pool air spaces (containment spray) with suppression pool water.

1.2.4.1.5 Reactor Water Cleanup System A RWCU system is provided to clean up the reactor cooling water, to reduce the amounts of activated corrosion products in the water, and to remove excess reactor coolant from the nuclear system under controlled conditions.

1.2.4.1.6 Nuclear Leak Detection System The nuclear leak detection and monitoring system consists of temperature, pressure, flow, and fission product sensors with associated instrumentation and alarms. This system detects and annunciates leakage in the following systems:

a. Main steam lines

b. RWCU system

c. RHR system

d. RCIC system

e. Feedwater system

f. ECCS systems

g. Miscellaneous systems Small leaks generally are detected by monitoring the temperature, radiation levels, and drain sump fill-up and pump-out rates. Large leaks are also detected by changes in reactor water level and changes in flow rates in process lines.

1.2.4.2 Safety-Related Systems Safety-related systems provide actions necessary to assure safe shutdown, to protect the integrity of radioactive material barriers, and/or to prevent the release of radioactive material in excess of allowable dose limits. These systems can be components, groups of components, systems, or CHAPTER 01 1.2-10 REV. 19, SEPTEMBER 2018

LGS UFSAR groups of systems. ESF systems are included in this category. ESF systems function to mitigate the consequences of DBAs.

1.2.4.2.1 Reactor Protection System The RPS initiates a rapid, automatic shutdown (scram) of the reactor. This action is taken in time to prevent excessive fuel cladding temperatures and any nuclear system process barrier damage following abnormal operational transients. The RPS overrides all operator actions and process controls.

1.2.4.2.2 Neutron Monitoring System Those portions of the NMS that are part of the RPS are safety-related. The IRM and APRM monitor neutron flux via incore detectors and provide scram logic inputs to the RPS to initiate a scram in time to prevent excessive fuel clad damage as a result of overpower transients (Upscale neutron flux), upscale simulated thermal power, and OPRM upscale are conditions that provide scram logic signals.

1.2.4.2.3 Control Rod Drive System When a scram is initiated by the RPS, the CRD system inserts the negative reactivity necessary to shut down the reactor. Each control rod is controlled individually by a hydraulic control unit.

When a scram signal is received, high pressure water from an accumulator for each rod forces each control rod rapidly into the core.

1.2.4.2.4 Control Rod Velocity Limiter A control rod velocity limiter is a part of each control rod and limits the velocity at which a control rod can fall out of the core should it become detached from its CRD. The rate of reactivity insertion resulting from a rod-drop accident is limited by this feature. The limiters contain no moving parts.

1.2.4.2.5 Control Rod Drive Housing Supports CRD housing supports are located underneath the reactor vessel near the control rod housings.

The supports limit the travel of a control rod in the event that a control rod housing is ruptured.

The supports prevent a nuclear excursion as a result of a housing failure, thus protecting the fuel barrier.

1.2.4.2.6 Nuclear System Pressure Relief System A pressure relief system, consisting of SRVs mounted on the main steam lines, prevents excessive pressure inside the nuclear system during operational transients or accidents.

1.2.4.2.7 Reactor Core Isolation Cooling System The RCIC system provides makeup water to the reactor vessel whenever the vessel is isolated from the main condenser and feedwater system. The RCIC system uses a steam-driven turbine-pump unit and operates automatically in time, and with sufficient coolant flow, to maintain adequate reactor vessel water level for events defined in Section 5.4.6.1.

CHAPTER 01 1.2-11 REV. 19, SEPTEMBER 2018

LGS UFSAR 1.2.4.2.8 Primary Containment A pressure-suppression primary containment houses the reactor vessel, the reactor coolant recirculation loops, and other branch connections of the reactor primary system. The pressure-suppression system consists of a drywell, a pressure-suppression chamber storing a large volume of water, a connecting vent system between the drywell and the water pool, isolation valves, containment cooling systems, and other service equipment. In the event of a process system piping failure within the drywell, reactor water and steam would be released into the drywell air space. The resulting increased drywell pressure would then force a mixture of air, steam, and water through the vents into the pool of water stored in the suppression chamber. The steam would condense rapidly in the suppression pool, resulting in a rapid pressure reduction in the drywell. Air transferred from the drywell to the suppression chamber pressurizes the suppression chamber and is subsequently vented to the drywell to equalize the pressure between the two chambers. Cooling systems remove heat from the reactor core, the drywell, and from the water in the suppression chamber, thus providing continuous cooling of the primary containment under accident conditions. Appropriate isolation valves are actuated during this period to ensure containment of radioactive materials within the primary containment.

1.2.4.2.9 Primary Containment and Reactor Vessel Isolation Control System The primary containment and reactor vessel isolation control system automatically initiates closure of isolation valves to close off all process lines that are potential leakage paths for radioactive material to the environs. This action is taken upon indication of a potential breach in the nuclear system process barrier.

1.2.4.2.10 Secondary Containment Any leakage from the primary containment system is contained within the secondary containment system. This system includes the SGTS and the RERS. The secondary containment system is designed to minimize the release of airborne radioactive materials, and to provide for the controlled, filtered release of the reactor enclosure atmosphere under accident conditions.

1.2.4.2.11 Main Steam Isolation Valves Although process lines that penetrate the primary containment, and offer a potential release path for radioactive material, are provided with redundant isolation capabilities, the main steam lines, because of their large size and large mass flow rates, are given special isolation consideration.

Two automatic isolation valves, each powered by both pneumatic pressure and spring force, are provided in each main steam line. These valves fulfill the following objectives:

a. To prevent excessive damage to the fuel barrier by limiting the loss of reactor coolant from the reactor vessel resulting either from a major leak from the steam piping outside the primary containment, or from a malfunction of the pressure control system, resulting in excessive steam flow from the reactor vessel

b. To limit the release of radioactive materials, by closing the nuclear system process barrier, in case of a gross release of radioactive materials from the fuel to the reactor coolant and steam CHAPTER 01 1.2-12 REV. 19, SEPTEMBER 2018

LGS UFSAR

c. To limit the release of radioactive materials by closing the primary containment barrier, in case of a major leak from the nuclear system inside the primary containment.

1.2.4.2.12 Main Steam Line Flow Restrictors A venturi-type flow restrictor is installed in each steam line. These devices limit the loss of coolant from the reactor vessel and prevent uncovering of the core before the MSIVs are closed in case of a main steam line break.

1.2.4.2.13 Emergency Core Cooling Systems Four independent core standby cooling systems are provided to maintain fuel clad temperatures below the limits of 10CFR50.46 in the event of a breach in the RCPB that results in a loss of reactor coolant. The four core standby cooling systems are as follows:

a. High Pressure Coolant Injection System The HPCI system provides and maintains an adequate coolant inventory inside the reactor vessel to limit fuel clad temperatures as a result of postulated small breaks in the RCPB. A high pressure system is needed for such breaks because the reactor vessel depressurizes slowly, preventing low pressure systems from injecting coolant. The HPCI system includes a turbine-driven pump powered by reactor steam. The system is designed to accomplish its function on a short-term basis without reliance on plant auxiliary power supplies other than the dc power supply.

b. Automatic Depressurization System The ADS acts to rapidly reduce reactor vessel pressure in a LOCA situation in which the HPCI system fails to maintain reactor vessel water level. The depressurization provided enables the low pressure ECCS to deliver cooling water to the reactor vessel. The ADS uses some of the relief valves that are part of the nuclear system pressure relief system. The automatic relief valves are arranged to open on conditions indicating that both a break in the nuclear system process barrier has occurred and the HPCI system is not delivering sufficient cooling water to the reactor vessel to maintain the water level above a preselected value. The ADS will not be activated unless either the core spray or the LPCI system is operating.

c. Core Spray System The CS system consists of two independent pump loops that deliver cooling water to spray spargers over the core. The system is actuated by conditions indicating that a breach exists in the RCPB, but water is delivered to the core only after reactor vessel pressure is reduced. This system provides the capability to cool the fuel by spraying water on the core. Either loop functioning in conjunction with the ADS or HPCI can provide sufficient fuel cladding cooling following a LOCA.

d. Low Pressure Coolant Injection CHAPTER 01 1.2-13 REV. 19, SEPTEMBER 2018

LGS UFSAR LPCI is an operating mode of the RHR system. LPCI uses the pump loops of the RHR system to inject cooling water into the reactor system. LPCI is actuated by conditions indicating a breach in the RCPB, but water is delivered to the core only after reactor vessel pressure is reduced. LPCI operation provides the capability of core reflooding following a LOCA in time to maintain the fuel cladding below prescribed temperature limits.

1.2.4.2.14 Residual Heat Removal System (Containment Cooling)

The RHR system for containment cooling is placed in operation to limit the temperature of the water in the suppression pool and of the atmospheres in the drywell and suppression chamber following a design basis LOCA, to control the pool temperature during normal operation and to reduce the pool temperature following an isolation transient. In the containment cooling mode of operation, the RHR system pumps take suction from the suppression pool and deliver the water through the RHR system heat exchangers, where cooling takes place by transferring heat to the RHR service water system. The fluid is then discharged back to the suppression pool, the drywell or suppression chamber spray headers, or to the RPV.

1.2.4.2.15 Control Room Heating, Ventilating and Air Conditioning System The control room HVAC system provides ventilation, cooling, and control of environmental conditions in the control room areas for the safety and comfort of operating personnel during normal operations and during postulated accident conditions. The system includes air filter units used to remove contaminants that are potentially present in the air following a postulated accident before introducing the air into the control room HVAC system.

1.2.4.2.16 Reactor Enclosure Recirculation System and Standby Gas Treatment System Both the RERS and the SGTS service the secondary containment. The recirculation system has the capability of recirculating the reactor enclosure air volume prior to its discharge via the SGTS, following a LOCA. The SGTS has the capability of maintaining a negative pressure within the reactor enclosures and the refueling area zones of the secondary containment with respect to the outside atmosphere. The air moving through the SGTS is filtered and discharged through the north exhaust stack.

1.2.4.2.17 Standby AC Power Supply The standby ac power supply system consists of four diesel generator sets per unit. The diesel generators are sized so that any three diesels can supply all the necessary power requirements for one unit in the DBA condition. The diesel generators are designed to start and be able to accept load within 10 seconds. Four independent 4 kV ESF switchgear assemblies are provided for each reactor unit. Each diesel generator feeds an independent 4 kV bus for each reactor unit.

Each diesel generator starts automatically upon LOOP or detection of a LOCA. The necessary safety-related loads are applied in a preset time sequence. Each generator operates independently and without paralleling during a LOOP or LOCA signal.

1.2.4.2.18 DC Power Supply CHAPTER 01 1.2-14 REV. 19, SEPTEMBER 2018

LGS UFSAR Each unit is provided with two independent Class 1E 125/250V, two independent Class 1E 125V, one non-Class 1E 125/250V, and one non-Class 1E 250V DC systems. The systems are provided to supply station DC control power, DC power to diesel generators, their associated switchgear, ESF systems, and DC motor driven pumps and valves.

The Class 1E DC systems are designed to supply power adequate to satisfy the safety-related load requirements of the unit with the postulated LOOP and any concurrent signal failure in the DC system.

1.2.4.2.19 Residual Heat Removal Service Water System The purpose of the RHRSW system is to provide a reliable supply of cooling water for heat removal from the RHR system during normal shutdown operations and under postaccident conditions. It can also supply a source of water if postaccident flooding of the primary containment is required.

The system consists of two independent loops, each of 100% capacity, supplying one RHR heat exchanger in each unit. During postaccident conditions the system uses the common spray pond as the heat sink. Interconnections are provided to allow use of a cooling tower as a heat sink during normal operations and, if conditions permit, during postaccident operation.

1.2.4.2.20 Emergency Service Water System The purpose of the ESW system is to provide a reliable supply of cooling water to emergency equipment during LOOP and postaccident conditions.

The system consists of two independent loops. Each loop supplies corresponding safety-related equipment in each unit. The safety- related cooling loads consist of equipment room coolers, control room chillers, and the RHR pump coolers.

ESW for the diesel generators is supplied by either loop. The ESW system uses the common spray pond as a heat sink. Interconnections are provided to allow use of a cooling tower as a heat sink if conditions permit.

1.2.4.2.21 Main Steam Line Radiation Monitoring System The MSL-RMS consists of four gamma radiation monitors located external to the main steam lines just outside of the primary containment. The monitors are designed to detect a gross release of fission products from the fuel. Upon detection of high radiation, an alarm signal is initiated by the monitors.

1.2.4.2.22 Reactor Enclosure and Refueling Area Ventilation Radiation Monitoring System The REVE-RMS and RAVE-RMS consists of a number of radiation monitors arranged to monitor the activity level of the ventilation exhaust from the reactor enclosure and refueling area. Upon detection of high radiation, the affected area is automatically isolated and the SGTS and RERS (for reactor enclosure only) are started.

1.2.4.2.23 Remote Shutdown System CHAPTER 01 1.2-15 REV. 19, SEPTEMBER 2018

LGS UFSAR A remote shutdown panel and associated procedures are provided for each unit so that the plant can be maintained in a safe shutdown condition in the event that the control room becomes uninhabitable.

1.2.4.2.24 Standby Liquid Control System Although not intended to provide rapid reactor shutdown, the SLCS provides a redundant, independent, and alternate way to bring the reactor subcritical and to maintain it subcritical as the reactor cools. The system makes possible an orderly and safe shutdown in the event that not enough control rods can be inserted into the reactor core to accomplish normal shutdown. The system is sized to counteract the positive reactivity effect from rated power to the cold shutdown condition. The SLCS also provides pH control for the primary containment water inventory following a LOCA.

1.2.4.2.25 Deleted.

1.2.4.2.26 Redundant Reactivity Control System The RRCS is designed to provide a redundant and diverse method of shutting down the reactor, in the unlikely event that the RPS does not scram the reactor as a result of an anticipated operating transient. The RRCS logic is initiated when either the high reactor pressure or low reactor water level setpoints are reached. A signal is then sent to open the ARI valves that vent the CRD scram air header to insert the control rods into the reactor. A signal is also transmitted to the RPT breakers to trip the reactor recirculation pumps to reduce the reactor power. An initiation of the RRCS logic by high reactor pressure will cause the feedwater pumps to automatically runback. If reactor power has not decreased to a predetermined level, within a specified period of time, the RRCS logic will initiate a feedwater runback and the injection of a neutron poison solution into the reactor, via the SLCS, and shut down the reactor.

The system consists of control panels, their associated ATWS detection and actuation logic, and the necessary interface logic to the recirculation system, the feedwater system, the SLCS, the RWCU system and the ARI components of the CRD system required to perform specific functions in response to an ATWS event.

1.2.4.3 Instrumentation and Control Systems 1.2.4.3.1 Nuclear System Process Control and Instrumentation 1.2.4.3.1.1 Reactor Manual Control System The reactor manual control system provides the means by which control rods are positioned from the control room for power control. The system operates valves in the CRD hydraulic system to control rod position. Only one control rod can be manipulated at a time. The reactor manual control system includes the logic that restricts control rod movement (rod block) under certain conditions as a backup to procedural controls.

1.2.4.3.1.2 Recirculation Flow Control System The recirculation flow control system controls the speed of the reactor recirculation pumps.

Adjusting the pump speed changes the coolant flow rate through the core. This effects changes CHAPTER 01 1.2-16 REV. 19, SEPTEMBER 2018

LGS UFSAR in core power level. The system is operated manually to match reactor power output to the load demand by adjusting the frequency of the electrical power supply for the reactor recirculation pumps.

1.2.4.3.1.3 Neutron Monitoring System The NMS is a system of incore neutron detectors and electronic monitoring equipment. The system provides indication of neutron flux that can be correlated to thermal power level for the entire range of flux conditions that may exist in the core. The SRM and IRM provide flux level indications during reactor startup and low power operation. The LPRM and APRM allow assessment of local and overall flux conditions during power range operation. The TIP system provides a means to calibrate the individual LPRMs utilizing a gamma-measuring probe. The NMS provides inputs to the reactor manual control system to initiate rod blocks if preset alarm flux limits are exceeded, and inputs to the RPS to initiate a scram if trip limits are exceeded.

1.2.4.3.1.4 Refueling Interlocks A system of interlocks, restricting the movements of refueling equipment and control rods when the reactor is in the refueling and startup modes, is provided to prevent an inadvertent criticality during refueling operations. The interlocks back up procedural controls that have the same objective. The interlocks affect the refueling platform, the refueling platform hoists, the fuel grapple, and control rods.

1.2.4.3.1.5 Reactor Vessel Instrumentation In addition to instrumentation provided for the nuclear safety systems and ESF, instrumentation is provided to monitor and transmit information that can be used to assess conditions existing inside the reactor vessel and the physical condition of the vessel itself. The instrumentation provided monitors reactor vessel pressure, water level, temperature, internal differential pressures and coolant flow rates, and top head flange leakage.

1.2.4.3.1.6 Deleted 1.2.4.3.1.7 Plant Monitoring System The PMS is a centralized, integrated system which performs the process monitoring and calculation that are necessary for the effective evaluation of normal and emergency power plant operation. The PMS acquires and records process data (e.g., temperatures, pressures, flows, status indicators) to produce displays, logs, and plots of current or historical plant performance which are presented to plant personnel in the plant main control room.

1.2.4.3.1.8 Rod Worth Minimizer The RWM monitors and enforces adherence to established low power level rod insert and withdraw sequences. This function prevents the operator from establishing control rod patterns that are not consistent with the prescribed sequence by initiating the appropriate rod insert and withdraw block. When RWM is inoperable both insert and withdraw blocks are enforced unless the RWM is bypassed. The RWM enforces control rod sequences designed to limit individual control rod worths to acceptable levels as determined by the rod-drop accident design basis.

CHAPTER 01 1.2-17 REV. 19, SEPTEMBER 2018

LGS UFSAR 1.2.4.3.2 Power Conversion Systems Process Control and Instrumentation 1.2.4.3.2.1 Pressure Regulator and Turbine-Generator Control The pressure regulator controls the turbine control and turbine bypass valves to maintain the nuclear system pressure essentially constant.

The turbine-generator speed-load control is set above the desired load and grid generator frequency. Load changes are made by the operator by adjusting the reactor recirculation flow control system and control rods.

The turbine-generator speed-load controls initiate rapid closure of the turbine control valves (rapid opening of the turbine bypass valves) to prevent turbine overspeed on loss of the generator electric load.

1.2.4.3.2.2 Feedwater System Control A three-element control system regulates the feedwater system so that proper water level is maintained in the reactor vessel. Signals used by the control system are main steam flow rate, reactor vessel water level, and feedwater flow rate. The feedwater control signal is used to control the speed of the steam turbine-driven feedwater pumps.

1.2.4.3.2.3 Electrical Power System Control Controls for the electrical power system are located in the control room to permit safe startup, operation, and shutdown of the plant.

1.2.4.4 Electrical Systems 1.2.4.4.1 Transmission and Generation Systems Redundant sources of offsite power are provided to each unit by separate transmission lines to ensure that no single failure of any active component can prevent a safe and orderly shutdown.

Each unit is provided with an independent substation, which is 220 kV for Unit 1 and 500 kV for Unit 2. The substations are connected by an autotransformer and ultimately feed into the PJM interconnection through the 220 kV and 500 kV transmission systems. Two independent offsite sources provide auxiliary power for startup and for operating the safety-related systems.

The main generator for each unit is an 1800 rpm, 3 phase, 60 Hz synchronous unit rated at 1264.97 MVA. Each generator is connected directly to the turbine shaft and is equipped with an excitation system coupled directly to the generator shaft. Power from the generators is stepped up from 22-220 kV on Unit 1 from 22-500 kV on Unit 2 by the unit main transformers and supplied by overhead lines to the 220 kV and 500 kV switchyards, respectively.

1.2.4.4.2 Electric Power Distribution Systems The electric power distribution system includes Class 1E and non- Class 1E ac and dc power systems. The Class 1E power system supplies all safety-related equipment, while the non-Class 1E system supplies the balance of plant equipment.

CHAPTER 01 1.2-18 REV. 19, SEPTEMBER 2018

LGS UFSAR The Class 1E ac system for each unit consists of four independent load groups. Two independent offsite power systems provide the normal electric power to these groups. Each load group includes a 4 kV switchgear, a 440 V load center, 440 V MCCs, and 120 V control and instrument power panels. The vital ac instrumentation and control power supply systems include battery systems and static inverters.

There are four independent diesel generator sets for each unit. Each diesel generator is provided as a standby source of power for one of the four Class 1E ac load groups in each unit. Assuming the total LOOP and failure of one diesel generator, the remaining diesel generators have sufficient capacity to operate all the equipment necessary to prevent undue risk to public health and safety in the event of a DBA on one unit and an emergency shutdown of the second unit.

The non-Class 1E ac system includes 13.2 kV switchgear, 2.3 kV switchgear, 440 V load centers, MCCs, and 120 V control and instrument power panels.

Two independent Class 1E 125 V dc batteries and two independent Class 1E 125/250 V dc batteries and associated battery chargers provide direct current power for the Class 1E dc loads of each unit. Power for non-Class 1E dc loads is supplied from 125/250 V and 250 V non-Class 1E batteries and associated battery chargers.

1.2.4.5 Fuel Handling and Storage Systems 1.2.4.5.1 New and Spent Fuel Storage The fuel storage racks are designed to prevent load buckling and inadvertent criticality under dry and flooded conditions. Sufficient coolant and shielding are maintained to prevent overheating and excessive personnel exposure, respectively. New and spent fuel will be stored in the spent fuel pool in addition to spent fuel stored in the Independent Spent Fuel Storage Installation.

1.2.4.5.2 Fuel Pool Cooling and Cleanup System The FPCC system is provided to remove decay heat from spent fuel stored in the fuel pool and to maintain specified water temperature, purity, clarity, and level.

1.2.4.5.3 Fuel Handling Equipment The major fuel servicing and handling equipment includes the reactor enclosure cranes, refueling service platform, fuel and control rod servicing tools, fuel sipping and inspection devices, and other auxiliary servicing tools.

1.2.4.6 Cooling Water and Auxiliary Systems 1.2.4.6.1 Service Water System The service water system supplies cooling water to equipment required for normal plant operation.

The system consists of three 50% capacity pumps with associated piping and valves. The cooling water supply to the pumps is taken from the cooling tower basin, while the water being returned from the system is discharged into the cooling tower.

1.2.4.6.2 Reactor Enclosure Cooling Water System CHAPTER 01 1.2-19 REV. 19, SEPTEMBER 2018

LGS UFSAR The RECW system is a closed-loop cooling water system that provides cooling water for miscellaneous reactor auxiliary plant equipment. The RECW system consists of two 100%

capacity pumps, two 100% capacity heat exchangers, a head tank, chemical addition tank, associated piping, valves, and controls. One RECW pump is normally in service and the other pump is on automatic standby. During normal plant operation, heat is transferred from the RECW system to the service water system.

1.2.4.6.3 Turbine Enclosure Cooling Water System The TECW system is a closed-loop cooling system that provides cooling water to the auxiliary plant equipment associated with the nuclear and power conversion systems in the turbine enclosure. The TECW system consists of two 100% capacity pumps, two 100% capacity heat exchangers, a head tank, chemical addition tank, and associated piping and valves. During normal plant operation, the TECW heat exchanger transfers heat from the TECW system to the service water system. One TECW pump is normally in service and the other pump is on automatic standby.

1.2.4.6.4 Fire Protection System A fire protection system supplies fire fighting water to points throughout the plant. An automatic carbon dioxide protection system, in addition to portable fire extinguishers, is provided. An automatic halon fire protection system provides protection in the auxiliary electrical equipment room.

1.2.4.6.5 Plant Heating, Ventilating, and Air Conditioning Systems The HVAC systems supply and circulate filtered fresh air for personnel comfort and equipment cooling.

1.2.4.6.6 Instrument Air System The instrument air system supplies compressed air of suitable quality and pressure for power plant operation.

1.2.4.6.7 Clarified and Domestic Water Systems The clarified and domestic water systems provide filtered, clarified water for plant and personnel use.

1.2.4.6.8 Demineralized Water Makeup System A demineralized water makeup system is provided to furnish a supply of treated water suitable for use as makeup for the plant.

1.2.4.6.9 Plant Equipment and Floor Drainage System The plant equipment and floor drainage system handles both radioactive and nonradioactive drains. Drains that can contain radioactive materials are pumped to the radwaste system for cleanup, reuse, or discharge. Nonradioactive drains are processed to remove oil and chemicals and then discharged to the environs.

CHAPTER 01 1.2-20 REV. 19, SEPTEMBER 2018

LGS UFSAR 1.2.4.6.10 Process Sampling System The process sampling system is provided to monitor the operation of plant equipment and to provide information needed to make operational decisions.

1.2.4.6.11 Plant Communication System The plant communication system provides communication between various plant structures and locations.

1.2.4.7 Power Conversion Systems 1.2.4.7.1 Turbine-Generator The turbine-generator consists of the turbine, generator, exciter, controls, and required subsystems designed for a nominally rated MWe 1231.1.

The turbine is an 1800 rpm, tandem-compound, nonreheat steam turbine and an EHC system.

The main turbine comprises one double-flow high pressure turbine and three double-flow low pressure turbines. Exhaust steam from the high pressure turbine passes through moisture separators before entering the three low pressure turbines.

The generator is a direct-driven, 3 phase, 60 Hz, 22,000 V, 1800 rpm, synchronous generator rated at 1265 MVA on the basis of guaranteed best turbine efficiency MW rating at an expected 0.973 power factor at 75 psig hydrogen pressure. The generator-exciter system is shaft-driven, complete with static-type voltage regulator and associated switchgear (Unit 2 only). The generator-exciter system is shaft-driven, complete with digital voltage regulator and associated switchgear (Unit 1 only).

1.2.4.7.2 Main Steam System The main steam system delivers steam from the nuclear boiler system via four 26 inch OD steam lines to the turbine-generator. This system also supplies steam to the SJAE, the RFPT, the main condenser hotwell at startup and low loads, and the steam seal evaporator.

1.2.4.7.3 Main Condenser The main condenser system condenses and deaerates the exhaust steam from the main turbine and RFPT, and provides a heat sink for the turbine bypass system. The main condenser is a triple-pass, triple-pressure, deaerating-type with a reheating-deaerating hotwell and divided water boxes. The condenser consists of three sections with each section located below one of three low pressure turbines.

1.2.4.7.4 Main Condenser Evacuation System The main condenser evacuation system removes the noncondensable gases from the main condenser. Two redundant SJAE are provided for air removal during normal operation, and one motor-driven vacuum pump is provided for air removal during startup.

CHAPTER 01 1.2-21 REV. 19, SEPTEMBER 2018

LGS UFSAR 1.2.4.7.5 Steam Seal System The steam seal system provides clean, nonradioactive steam to the seals of the turbine valve packings and the turbine shaft packings. The sealing steam is supplied by the steam seal evaporator. The auxiliary boiler provides an auxiliary steam supply for startup and can be used as a backup to the steam seal evaporator, when available, during power operation.

1.2.4.7.6 Turbine Bypass and Pressure Control System The turbine bypass and pressure control system provides control of the reactor pressure for the following operating modes:

a. During reactor heatup to rated pressure

b. While the turbine is being brought up to speed and synchronized

c. During normal power operation and transient power operation when the reactor steam generation exceeds the turbine steam requirements

d. When shutting down the reactor 1.2.4.7.7 Circulating Water System The circulating water system is a closed-loop system designed to circulate the flow of water required to remove the heat load from the main condenser and auxiliary heat exchanger equipment and discharge it to the atmosphere through natural draft cooling towers.

1.2.4.7.8 Condensate Cleanup System The function of the condensate cleanup system is to maintain the required purity of the feedwater to the reactor. The system consists of full flow condensate filter/demineralizers and deep bed condensate demineralizers. The condensate filter/demineralizers remove suspended solids from the condensate and feedwater streams. Downstream of and in series with the condensate filter/demineralizers, the deep bed condensate demineralizers use ion exchange resins that remove dissolved impurities from the feedwater. A bypass exists around one of the condensate filter/demineralizers to provide a means to control the iron/transition metal concentration in the reactor recirculation system. The deep bed condensate demineralizers also remove some of the radioactive material produced by corrosion as well as fission product carryover from the reactor.

1.2.4.7.9 Condensate and Feedwater Systems The condensate and feedwater systems are designed to deliver the required feedwater flow to the reactor vessel during stable and transient operating conditions throughout the entire operating range from startup to full load to shutdown. The system operates using three condensate pumps to pump deaerated condensate from the hotwell of the main condenser through the SJAE condenser, the gland steam packing exhauster condenser, and then to the condensate cleanup system. The demineralized feedwater then flows through three parallel strings of low pressure feedwater heaters to the suction of three reactor feed pumps that deliver the feedwater through one set of three parallel high pressure heaters to the reactor.

1.2.4.7.10 Condensate and Refueling Water Storage Facilities CHAPTER 01 1.2-22 REV. 19, SEPTEMBER 2018

LGS UFSAR The condensate and refueling water storage facilities provide storage of condensate water for use in normal plant operations and refueling operations.

1.2.4.8 Radioactive Waste Systems The radioactive waste systems are designed to confine the release of plant-produced radioactive material to well within the limits specified in 10CFR20 and 10CFR50, Appendix I. Various methods are used to achieve this end (e.g., collection, filtration, holdup for decay, dilution, and concentration). The pre-1994 10CFR20, Appendix B limits were used for the original licensing basis of the plant. Current liquid effluent releases are limited to ten-times the Effluent Concentration Limit (ECL) for each isotope specified in post-1994 10CFR20, Appendix B, Table 2, Column 2. Current gaseous and liquid effluent releases are controlled by the Radioactive Effluent Controls Program defined by the Technical Specifications.

1.2.4.8.1 Liquid Radwaste System The liquid radwaste system collects, treats, stores, and disposes of radioactive liquid wastes.

These wastes are collected in sumps and drain tanks at various locations throughout the plant and then transferred to the appropriate collection tanks in the radwaste enclosure prior to treatment, storage, and disposal. Processed liquid wastes are returned to the condensate system, packaged for offsite shipment, or discharged from the plant.

Equipment is selected, arranged, and shielded to permit operation, inspection, and maintenance within radiation allowances for personnel exposure. For example, tanks and processing equipment that will contain significant radiation sources are shielded and sumps, pumps, instruments, and valves are located in controlled access rooms or spaces. Processing equipment is selected and designed to require a minimum of maintenance.

Valving redundancy, instrumentation for detection, alarms of abnormal conditions, and procedural controls protect against the accidental discharge of liquid radioactive waste.

1.2.4.8.2 Solid Radwaste System Solid wastes originating from nuclear system equipment are stored for radioactive decay in the fuel storage pool and prepared for reprocessing or offsite storage in approved shipping containers. Examples of these wastes are spent control rods, and incore ion chambers.

Process solid wastes are collected, dewatered, packaged, and stored in shielded compartments prior to offsite shipment. Examples of these solid wastes are filter residue, spent resins, paper, air filters, rags, and used clothing.

1.2.4.8.3 Gaseous Radwaste System Radioactive gaseous wastes are discharged to the turbine enclosure vent via the gaseous radwaste system. This system provides hydrogen-oxygen recombination, filtration, and holdup of the offgases to ensure a low rate of release from the turbine enclosure vent.

The offgases from the main condenser are the greatest source of gaseous radioactive waste.

The treatment of these gases reduces the released activity to well below permissible levels even with some defective fuel elements.

CHAPTER 01 1.2-23 REV. 19, SEPTEMBER 2018

LGS UFSAR 1.2.4.9 Radiation Monitoring and Control 1.2.4.9.1 Process Radiation Monitoring Radiation monitors are provided on various lines to monitor and control radioactivity in process and effluent streams and to activate appropriate alarms and controls.

1.2.4.9.2 Area Radiation Monitors Radiation monitors are provided to monitor for abnormal radiation at various locations in the plant.

These monitors activate alarms when abnormal radiation levels are detected.

1.2.4.9.3 Site Environs Radiation Monitors Radiation monitors are provided outside the plant structures to monitor radiation levels. These data are used for determining the contribution of plant operations to onsite and offsite radiation levels.

1.2.4.10 Shielding Shielding is provided throughout the plant, as required, to reduce radiation levels to operating personnel and to the general public within the applicable limits set forth in 10CFR20, 10CFR50, and 10CFR50.67. It is also designed to protect certain plant components from radiation exposure resulting in unacceptable alterations of material properties or activation.

1.2.5 Control Of Unit 2 Construction Activities During Unit 1 Operation To meet the requirements of 10CFR50.34(b)(6)(vii), an evaluation was performed which verified that safety-related structures, systems, and components of Unit 1 were protected from potential hazards resulting from construction activities on Unit 2. This evaluation also identified the plant administrative and managerial controls required to provide assurance that technical specification limiting conditions for operation were not exceeded. Administrative and managerial controls existed in the form of design controls, procedures and training during the construction of Unit 2.

The plant Technical Specifications were taken into consideration throughout the development of these controls. The Plant Operations Review Committee was not required to review the Unit 2 construction activity controls or the revisions thereto.

LGS utilizes a unitized design for safety-related structures and systems with only the following common structures and systems as exceptions: the control enclosure and supporting systems, spray pond, spray pond pumphouse and supporting systems, ESW system, RHRSW system, and SGTS. All portions of the Unit 1 systems and those common systems required for the safe operation and shutdown of Unit 1 were completed prior to Unit 1 fuel load. Unit 2 systems and structures required to assure that Unit 1 limiting conditions for operation were not exceeded had also been completed. A PAB that was maintained in accordance with an established separation program served to define the Unit 1 and common operations area. The PAB considered personnel access for both security and ALARA radiation exposure. The LGS security plan covered all aspects of Unit 1 and common security.

Administrative and managerial controls governed the activities associated with Unit 2 construction to prevent the safe operation of Unit 1 from being affected. Design controls, procedures, safety programs, or training sessions existed to ensure that the following areas were addressed during Unit 2 construction:

CHAPTER 01 1.2-24 REV. 19, SEPTEMBER 2018

LGS UFSAR

- Separation of Unit 1 and common safety-related systems and equipment (including those Unit 2 systems, structures, and equipment required for operation of Unit 1) from Unit 2 construction activities.

- Yard activities, such as excavation, blasting, grading, use of heavy equipment, and erection of structures, such that consideration is given to site drainage, protection of underground utilities, and Unit 1 operation.

- Maintenance of construction personnel radiation exposures as low as reasonably achievable.

- Minimizing the probability of the LOOP to Unit 1 due to Unit 2 construction activities.

- The control of the use of hazardous and toxic chemicals which may have been used during Unit 2 construction.

- The control of the use and storage of compressed gas cylinders which may have been used during Unit 2 construction such that Unit 1 was not jeopardized.

- Construction cranes were prevented from damaging Unit 1 and common structures and systems important to safety by governing placement and operation.

- Rigging and the movement of equipment was governed to ensure potential heavy load drops did not affect Unit 1 or common safe shutdown equipment.

- The safe operation of Unit 1 was maintained by considering the fire barrier, missile protection, radiation protection, pressure boundary, flood control, and security aspects of walls, ceilings and floors when construction openings were made.

- Use of safe onsite transportation and traffic practices.

- Fire protection programs were enforced and not affected by construction activities associated with Unit 2.

CHAPTER 01 1.2-25 REV. 19, SEPTEMBER 2018

LGS UFSAR 1.3 COMPARISON TABLES 1.3.1 COMPARISONS WITH SIMILAR FACILITY DESIGNS This section highlights the principal design features of the plant and compares the major features with those of other BWR facilities. The design of this facility is based on proven technology attained during the development, design, construction, and operation of BWRs of similar types.

The data, performance, characteristics, and other information presented here represent the original design, and licensed operating conditions.

The following tables summarize the plant design characteristics for LGS, PBAPS, SSES, and Zimmer Unit 1:

Table No. System 1.3-1 Nuclear Steam Supply System 1.3-2 Engineered Safety Features and Auxiliary Systems 1.3-3 Power Conversion Systems 1.3-4 Containment 1.3-5 Structural Design 1.3-6 Radioactive Waste Management Systems 1.3-7 Electrical Power Systems 1.3.2 COMPARISON OF FINAL AND PRELIMINARY INFORMATION Significant changes made in the facility design between the PSAR stage and the FSAR stage are listed in Table 1.3-8. Design changes are only those that have occurred since the last PSAR amendment. Notice of all other design changes has been given through amendments to the PSAR. Each item in Table 1.3-8 is cross-referenced to the appropriate section of the UFSAR which describes the present design.

CHAPTER 01 1.3-1 REV. 13, SEPTEMBER 2006

LGS UFSAR Table 1.3-1 COMPARISON OF NUCLEAR STEAM SUPPLY SYSTEM DESIGN CHARACTERISTICS LGS* SSES ZIMMER 1 PBAPS THERMAL AND HYDRAULIC DESIGN (Section 4.4)

Rated power, MWt 3293 3293 2436 3293 Design power, MWt 3435 3439 2550 3440 Steam flow rate, lb/hr 14.159x106 13.48x106 10.477x106 13.381x106 Core coolant flow rate, lb/hr 100x106 100.5x106 100.5x106 102.5x106 Feedwater flow rate, lb/hr 14.127x106 13.44x106 10.447x106 10.447x106 Feedwater temperature, F 420 383 420 376.1 System pressure, nominal in steam dome, psia 1020 1020 1020 1020 Average power density, kW/liter 48.7 48.7 50.51 50.8 Maximum linear heat generation rate, kW/ft 13.4 13.4 13.4 18.35 Average linear heat generation rate, kW/ft 5.3 5.3 5.4 7.049 Maximum heat flux, Btu/hr-ft2 361,600 361,600 354,255 425,060 Average heat flux, Btu/hr-ft2 144,100 143,700 144,032 163,230 Maximum uranium dioxide (U02) temperature, F 3435 3435 3435 4430 Average volumetric fuel temperature, F 2130 2130 2130 2780 Average fuel rod surface temperature, F 566 566 566 560 Minimum critical power ratio (MCPR) 1.22 1.25 1.24 -

Coolant enthalpy at core inlet, Btu/lb 526.1 521.8 527.4 521.2 Core maximum exit voids within assemblies, % 77.1 76.6 75 79 Core average exit quality, % steam 14.1 13.2 13.2 13.2 Design power peaking factor(1)

Maximum relative assembly power 1.4 1.4 1.4 1.4 Design power peaking factor(1)

Maximum relative assembly power 1.4 1.4 1.4 1.4 Axial peaking factor 1.4 1.4 1.4 1.5 NUCLEAR DESIGN (FIRST CORE)

(Section 4.3)

Water/UO2 volume ratio (cold, beginning of cycle 2.74 2.80 2.55 2.43

[BOC])

Reactivity with strongest control rod out, keff <0.99 <0.99 <0.99 <0.99 CHAPTER 01 1.3-2 REV. 13, SEPTEMBER 2006

LGS UFSAR Table 1.3-1 (Contd)

COMPARISON OF NUCLEAR STEAM SUPPLY SYSTEM DESIGN CHARACTERISTICS LGS* SSES ZIMMER 1 PBAPS Dynamic void coefficient (end of cycle 1 [EOC-1])

(2)

a. At core average voids, % 39.7 39.7 40.54 (2)

b. At rated output, ¢/% -7.48 -7.48 -8.57 Fuel temperature doppler coefficient (BOC) at -1.85x10-5 -1.85x10-5 -1.94x10-5 (2) rated output (1/k) (dk/dt) (1/C)

Initial average U-235 enrichment wt, % 1.88 1.88 1.90 2.19 (2)

Initial cycle exposure, Mwd/short ton 9600 9600 9200 CORE MECHANICAL DESIGN (Sections 4.2 and 4.6)

Fuel assembly Number of fuel assemblies 764 764 560 764 Fuel rod array 8x8 8x8 8x8 7x7 Overall length, in 176 176 176 176 Weight of UO2 per assembly, lb 456 458 466 490 (pellet type)

Weight of fuel assembly, lb 680 665 698 676 Fuel rods Number per fuel assembly 62 62 63 63 Outside diameter, in 0.483 0.483 0.493 0.563 Cladding thickness, in 0.032 0.032 0.034 0.032 Diametral gap, pellet to cladding, in 0.009 0.009 0.009 0.011 Length of gas plenum, in 9.48 10 14 16 Cladding material Zircaloy-2 Zircaloy-2 Zircaloy-2 Zircaloy-2 Cladding process Freestanding Freestanding Freestanding Freestanding loaded tubes loaded tubes loaded tubes loaded tubes Fuel pellets Material UO2 UO2 UO2 UO2 Density, % of theoretical 94 95 95 95 Diameter, in 0.410 0.410 0.416 0.487 Length, in 0.410 0.410 0.420 0.5 Fuel channel Overall length, in 166.9 166.9 166.9 166.9 CHAPTER 01 1.3-3 REV. 13, SEPTEMBER 2006

LGS UFSAR Table 1.3-1 (Contd)

COMPARISON OF NUCLEAR STEAM SUPPLY SYSTEM DESIGN CHARACTERISTICS LGS* SSES ZIMMER 1 PBAPS Thickness, in 0.100,0.080(3) 0.080 0.100 0.080 Cross section dimensions, in 5.48x5.48 5.48x5.48 5.48x5.48 5.44x5.44 Material Zircaloy-4 Zircaloy-4 Zircaloy-4 Zircaloy-4 Core assembly Fuel weight as UO2, lb 348,939 349,912 260,551 369,790 Core diameter (equivalent), in 187.1 187.1 160.2 187.1 Core height (active fuel), in 150 150 146 144 Reactor control system Movable control Movable control Movable control Movable control rods and variable rods and variable rods and variable rods and variable Method of variation of reactor power forced coolant forced coolant forced coolant forced coolant flow flow flow flow Number of movable control rods 185 185 137 185 Shape of movable control rods Cruciform Cruciform Cruciform Cruciform Pitch of movable control rods, in 12.0 12.0 12.0 12.0 Control material in movable rods Boron Carbide B4C granules B4C granules B4C granules (B4C) granules compacted in compacted in compacted in compacted in stainless steel stainless steel stainless steel stainless steel tubes tubes tubes tubes Type of control rod drives Bottom entry Bottom entry Bottom entry Bottom entry locking piston locking piston locking piston locking piston Type of temporary reactivity control Burnable poison; Burnable poison; Burnable poison; Burnable poison; gadolinia-urania gadolinia-urania gadolinia-urania gadolinia-urania fuel rods fuel rods fuel rods fuel rods Incore neutron instrumentation Total number of LPRM detectors 172 172 124 172 Number of incore LPRM penetrations 43 43 31 43 Number of LPRM detectors per penetration 4 4 4 4 Number of SRM penetrations 4 4 4 4 Number of IRM penetrations 8 8 8 8 Total nuclear instrument penetrations 55 55 43 55 CHAPTER 01 1.3-4 REV. 13, SEPTEMBER 2006

LGS UFSAR Table 1.3-1 (Contd)

COMPARISON OF NUCLEAR STEAM SUPPLY SYSTEM DESIGN CHARACTERISTICS LGS* SSES ZIMMER 1 PBAPS Range (and number) of detectors:

a. SRM Shutdown Shutdown Shutdown Shutdown through through through through criticality(4) criticality(4) criticality(4) criticality(4)

Prior to criticality Prior to criticality Prior to criticality Prior to criticality

b. IRM to low power (8) to low power (8) to low power (8) to low power (8)

Power range monitors 1% to 125% 5% to 125% 1% to 125% 1% to 125%

power power power power

- LPRM 172 172 124 172

- APRM 6 6 6 6 Number and type of incore neutron sources 7; Sb-Be 7; Sb-Be 5; Sb-Be 7; Sb-Be REACTOR VESSEL DESIGN (Section 5.3)

Material Carbon steel/ Carbon steel/ Carbon steel/ Carbon steel/

stainless clad stainless clad stainless clad stainless clad Design pressure, psig 1250 1250 1250 1250 Design temperature, F 575 575 575 575 Inside diameter, ft-in 20-11 20-11 18-2 20-11 Inside height, ft-in 72-1 72-11 69-10 72-11 Minimum base metal thickness (cylindrical 6.187 6.19 5.375 6.3125 section), in Minimum cladding thickness, in 1/8 1/8 1/8 1/8 REACTOR COOLANT RECIRCULATION SYSTEM DESIGN (Section 5.4)

Number of recirculation loops 2 2 2 2 Design pressure

a. Inlet leg, psig 1250 1250 1250 1148

b. Outlet leg, psig 1500 1500 1575 1326 Design temperature, F 575 575 575 562 Pipe diameter, in 28 28 20 28 Pipe material, ANSI 316 304/316 304/316 304/316 CHAPTER 01 1.3-5 REV. 13, SEPTEMBER 2006

LGS UFSAR Table 1.3-1 (Contd)

COMPARISON OF NUCLEAR STEAM SUPPLY SYSTEM DESIGN CHARACTERISTICS LGS* SSES ZIMMER 1 PBAPS Recirculation pump flow rate, gpm 45,200 45,200 32,500 45,200 Number of jet pumps in reactor 20 20 20 20 MAIN STEAM LINES (Section 10.3)

Number of steam lines 4 4 4 4 Design pressure, psig 1115 1250 1250 1115 Design temperature, F 582 575 575 583 Pipe diameter, in 26 26 24 26 Pipe material Carbon steel Carbon steel Carbon steel Carbon steel (1)

Local and total peaking factors are not used as input to the thermal/hydraulic codes and are therefore not included here.

(2)

Available values for PBAPS first core were developed on a different basis and are not directly comparable to LGS, SSES, or Zimmer 1.

(3)

LGS Unit 1 will use 80 mil thick fuel channels beginning with refueling cycle 2.

LGS Unit 2 will use 80 mil thick fuel channels beginning with the initial core.

• Based on the original licensed operating conditions.

CHAPTER 01 1.3-6 REV. 13, SEPTEMBER 2006

LGS UFSAR Table 1.3-2 COMPARISON OF ENGINEERED SAFETY FEATURES AND AUXILIARY SYSTEMS DESIGN CHARACTERISTICS LGS* SSES ZIMMER 1 PBAPS EMERGENCY CORE COOLING SYSTEMS (Systems sized on design power)

(See UFSAR Section 6.3)

Core spray system Number of loops 2 2 1 2 Flow rate, gpm, per pump 6350 at 105 psid 6350 at 105 psid 4725 at 119 psid 6250 at 122 psid High pressure coolant injection system Number of loops 1 1 1 1 Flow rate, gpm 5600 minimum 5000 at 1172-165 1330 at 1110 psid, 5000 at 1120-150 psia, 4625 at 200 psid psid Automatic depressurization system Number of relief valves 5 6 6 5 Low pressure coolant injection Number of loops 4 2 3 2 Number of pumps 4 4 3 4 Flow rate, gpm/pump 10,000 at 20 psid 10,650 at 20 psid 5050 at 20 psid 10,000 at 20 psid AUXILIARY SYSTEMS (See UFSAR Sections 5.4 and 9.2)

Residual heat removal system Reactor shutdown cooling mode:

Number of pumps 2 2 3 4 Flow rate, gpm/pump 10,000 10,000 5050 10,000 Duty, Btu/hr/heat exchanger 41.6x106 44x106 30.8x106 70.0x106 Number of heat exchangers 2 2 3 4 Primary containment cooling mode:

Flow rate, gpm/heat exchanger 10,000 10,000 5050 10,000 Service water system Flow rate, gpm/heat exchanger 12,000 9000 5000 14,000 Number of pumps 3 2 4 3 Reactor core isolation cooling system Flow rate, gpm 600 at 1120 psid 600 at 1172-165 psia 400 at 1120 psid 616 at1120 psid Fuel pool cooling and cleanup system Capacity, Btu/hr 11.25x106 13.2x106 6.9x106 11.25x106

• Based on the original licensed operating conditions.

CHAPTER 01 1.3-7 REV. 13, SEPTEMBER 2006

LGS UFSAR Table 1.3-3 COMPARISON OF POWER CONVERSION SYSTEM DESIGN CHARACTERISTICS LGS* SSES ZIMMER 1 PBAPS TURBINE-GENERATOR (See UFSAR Section 10.2)

Design power, MWe (gross) 1092 1085 830 1098 Generator speed, rpm 1800 1800 1800 1800 Design steam flow, lb/hr (maximum 14.14x106 13.46x106 11.00x106 13.36x106 guaranteed)

Inlet pressure, psig 965 965 950 965 STEAM BYPASS SYSTEM (See UFSAR section 10.4.4)

Capacity, % design steam flow 25 25 25 25 MAIN CONDENSER (See UFSAR Section 10.4.1)

Heat removal capacity, Btu/hr 7725x106 7890x106 7053x106 7600x106 CIRCULATING WATER SYSTEM (See UFSAR Section 10.4.5)

Number of pumps 4 4 3 3 Flow rate, gpm/pump 113,000 112,000 150,000 250,000 CONDENSATE AND FEEDWATER SYSTEMS (See UFSAR Section 10.4.7)

Design flow rate, lb/hr 14.12x106 13.44x106 10.971x106 13.33x106 Number of condensate pumps 3 4 3 3 Number of condensate booster pumps - - 3 -

Number of feedwater pumps 3 3 2 3 Condensate pump drive AC power AC power AC power AC power Booster pump drive - - AC power -

Feedwater pump drive Turbine Turbine Turbine Turbine

• Based on the original licensed operating conditions.

CHAPTER 01 1.3-8 REV. 16, SEPTEMBER 2012

LGS UFSAR Table 1.3-4 COMPARISON OF CONTAINMENT DESIGN CHARACTERISTICS LGS* SSES ZIMMER 1 PBAPS PRIMARY CONTAINMENT (See UFSAR Sections 3.8 and 6.2)

Type Pressure- Suppression Pressure-suppression Pressure-suppression Pressure-suppression Construction Concrete with steel liner Concrete with steel liner Concrete with steel liner Free-Standing Steel Drywell Frustum of cone upper Frustum of cone upper Frustum of cone upper Light bulb shape, steel portion portion portion vessel Suppression chamber Cylindrical lower portion Cylindrical lower portion Cylindrical lower portion Torus, steel vessel Suppression chamber internal design 55 53 45 56 pressure, psig Suppression chamber external design 5 5 2 2 pressure, psi Drywell internal design pressure, psig 55 53 45 56 Drywell external design pressure, psi 5 5 2 2 Drywell free volume, ft3 (low water) 243,580 239,600 180,000 159,000 Suppression chamber free air volume, ft3 147,670 148,590 93,000 19,000 (high water) (high water) 159,540 159,130 (low water) (low water)

Suppression pool water volume, ft3 134,600(max) 131,550(max) 95,762 135,000 122,120(min) 122,410(min)

Submergence of downcomers below 121/4 11 10 4 suppression pool surface, ft (high water) 10 (low water)

CHAPTER 01 1.3-9 REV. 13, SEPTEMBER 2006

LGS UFSAR Table 1.3-4 (Cont'd)

LGS* SSES ZIMMER 1 PBAPS Design temperature of drywell, F 340 340 340 281 Design temperature of suppression 220 220 275 281 chamber, F Downcomer vent pressure loss factor 2.23 2.5 2.17 6.21 Break area/total vent area 0.0159 0.016 0.008 0.019 Calculated maximum pressure after 44.0 44 40.4 40 blowdown to drywell, psig Calculated maximum suppression 30.6 29 35.6 25 chamber pressure after LOCA blowdown, psig Initial suppression pool temperature rise 43 40 35 32 during LOCA blowdown, F Leakage rate, % free volume/day 0.5 0.5 0.635 at 45 psig and 0.5 340F SECONDARY CONTAINMENT (See UFSAR Section 3.8)

Type Controlled leakage, roof Controlled leakage, Controlled leakage, Controlled leakage, level release elevated release elevated release elevated release Construction Lower levels Reinforced concrete Reinforced concrete Reinforced concrete Reinforced concrete Upper levels Reinforced concrete Steel super-structure and Steel super-structure and Steel super-structure and super-structure and siding siding siding siding Roof Reinforced concrete Steel decking Steel decking Steel decking

• Based on the original licensed operating conditions.

CHAPTER 01 1.3-10 REV. 13, SEPTEMBER 2006

LGS UFSAR Table 1.3-4 (Cont'd)

LGS* SSES ZIMMER 1 PBAPS Internal design pressure, psig below 0.25 0.25 0.25 0.25 atmosphere Design inleakage rate % free 200 100 100 100 volume/day at 0.25 in wg. Reactor enclosure Refueling area 50 100 100 100

• Based on the original licensed operating conditions.

CHAPTER 01 1.3-11 REV. 13, SEPTEMBER 2006

LGS UFSAR Table 1.3-5 COMPARISON OF STRUCTURAL DESIGN CHARACTERISTICS LGS SSES ZIMMER 1 PBAPS SEISMIC DESIGN (See UFSAR Section 3.7)

Operating basis earthquake

- horizontal(g) 0.075 0.05 0.10 0.05

- vertical(g) 0.05 0.033 0.07 0.033 Safe shutdown earthquake

- horizontal(g) 0.15 0.10 0.20 0.12

- vertical(g) 0.10 0.067 0.14 0.08 WIND DESIGN (See UFSAR Section 3.3)

Maximum sustained wind speed (mph) 90 80 90 87 TORNADO DESIGN (See UFSAR Section 3.3)

Translational speed (mph) 60 60 60 -

Rotational speed (mph) 300 300 300 300 CHAPTER 01 1.3-12 REV. 13, SEPTEMBER 2006

LGS UFSAR Table 1.3-6 RADIOACTIVE WASTE MANAGEMENT SYSTEMS DESIGN CHARACTERISTICS LGS SSES ZIMMER 1 PBAPS GASEOUS RADWASTE (See UFSAR Section 11.3 Design bases, noble gases, Ci/sec 100, 000 at 30 min 100, 000 at 30 min 100, 000 at 30 min 100, 000 at 30 min Process treatment Recombiner and ambient Recombiner and Chilled charcoal Recombiner charcoal delay ambient charcoal delay Design condenser inleakage, cfm 75 30 12.5 54 Release point-height above ground, ft 197 201 172 500 LIQUID RADWASTE (See UFSAR Section 11.2)

Treatment of:

Floor drains F, D, R F, D, R F, E, R F, O Equipment drains F, D, R F, D, R F, D, R F, D, R Chemical drains F, D, R E, D concentrates to E, D concentrates to Neutralized radwaste, F, O solid radwaste, distillate solid radwaste, distillate R R Laundry drains F, O Diluted and sent to Reverse osmosis F, O circulating water discharge discharge (1) Legend:

D = demineralized F = filtered E = evaporator/concentrator R = recycled, i.e., returned to condensate storage O = discharged CHAPTER 01 1.3-13 REV. 13, SEPTEMBER 2006

LGS UFSAR Table 1.3-7 COMPARISON OF ELECTRICAL POWER SYSTEMS DESIGN CHARACTERISTICS LGS SSES ZIMMER 1 PBAPS TRANSMISSION SYSTEM (See UFSAR Section 8.2)

Outgoing lines, number-rating 3-500 kV 1-230 kV 3-345 kV 4.500 kV 2-230 kV (Unit 1) 1-500 kV (Unit 2)

NORMAL AUXILIARY AC POWER (See UFSAR Sections 8.2 and 8.3)

Incoming lines, number-rating 3-500 kV 2.230 kV 1-69 kV 1-230 kV 2-230 kV (common to both units) 1-345 kV 13.8 kV Auxiliary transformers, number 2 1 per unit 1(unit auxiliary) 2 Startup transformers, numbers 2 2 (common to both units) 2 2 Safeguard transformers, numbers 2 + 1 spare - - 2 STANDBY AC POWER SUPPLY (See UFSAR Section 8.3)

Number of diesel generators 8 4 (common to both units) 3 4 Number of 4160 V shutdown buses 8 4 per unit 3 8 Number of 480 V shutdown buses 8 4 load centers and 8 8 8 MCCS per unit; 8 MCCs common to both units CHAPTER 01 1.3-14 REV. 13, SEPTEMBER 2006

LGS UFSAR Table 1.3-7 (Cont'd)

LGS* SSES ZIMMER 1 PBAPS DC POWER SUPPLY (See UFSAR Section 8.3)

Number of 125 V or 250 V batteries 4-125 V 4-125 V 3-125 V 4-125/250 V per unit 6-125/250 V 2-250 V 1-250 V 2-250 V 2-250 V per unit Number of 125 V buses 33 4 per unit 3 8 Number of 250 V buses 8 buses and 8 MCCs 2 load centers and 3 1 8 MCCs per unit CHAPTER 01 1.3-15 REV. 13, SEPTEMBER 2006

LGS UFSAR Table 1.3-8 SIGNIFICANT DESIGN CHANGES FROM PSAR TO FSAR UFSAR SECTION IN WHICH ITEM CHANGE REASON FOR CHANGE SUBJECT IS DISCUSSED Nuclear fuel The arrangement of fuel rods in This change improves fuel 4.2 each fuel bundle was changed performance by increasing safety from 7x7 to 8x8. margins.

Nuclear pressure relief system The two safety valves were This change improves the 5.2.2 deleted and the number of relief pressure suppression capability of valves was increased from 11 to the nuclear relief system.

14.

Feedwater sparger The design of the thermal This change eliminated the 5.3 sleeve connecting the sparger to possibility of vibration and leakage.

the reactor vessel has been changed.

Reactor recirculation system The 4 inch bypass line around This changed improves the 5.4 the recirculation pump discharge integrity and reliability of the valve has been deleted. recirculation loop.

Process sensors The monitoring devices of This change improves testability. 7.2, 7.3 process parameters have been changed (e.g., pressure, level, and flow) for the RPS and the ESF systems from process switches to transmitters and trip units.

Main condenser low vacuum The MSIV and main steam drain This eliminates reliance on the 7.2, 7.3 line isolation valves, rather than turbine control system for isolation the turbine stop valves and of the main condenser from the turbine bypass valves, are main steam supply.

automatically closed if there is loss of vacuum in the main condenser.

CHAPTER 01 1.3-16 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.3-8 (Cont'd)

UFSAR SECTION IN WHICH ITEM CHANGE REASON FOR CHANGE SUBJECT IS DISCUSSED Standby ac power system Bypassing of the following diesel To conform with BTP ICSB 17.

generator trip signals, if there is a LOCA, has been added:

a. Phase overcurrent

b. Ground neutral overcurrent

c. Ant-motoring

d. Jacket coolant high temperature/low pressure

e. Lube oil high temperature/low pressure Control room HVAC system The capability for total isolation For conformance with Regulatory 6.4, 9.4.1 and recirculation of control room Guides 1.78 and 1.95.

atmosphere on toxic chemical detection signal has been added.

Reactor enclosure HVAC The requirement for complete The reactor enclosure normal 9.4.2 isolation closure of the isolation valves in exhaust system serves those the reactor enclosure normal areas of the reactor enclosure exhaust duct before any which have a low release potential.

contaminated air is released Releases of radioactivity during after its detection has been the short time period required for deleted. Isolation valves will trip isolation valve closure would be a in normal time on detection of very small fraction of 10CFR50.67 airborne contamination. guidelines.

Drywell unit coolers Changed from two-speed to This change was made to obtain 9.4.5 single fan motors of sufficient motors qualified for 340oF horsepower for LOCA operation operation.

and ILRT operation.

CHAPTER 01 1.3-17 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.3-8 (Cont'd)

UFSAR SECTION IN WHICH ITEM CHANGE REASON FOR CHANGE SUBJECT IS DISCUSSED Reactor enclosure and control Added steam flooding isolation This prevents damage to 9.4.2 structure HVAC systems dampers safeguard equipment and protects personnel from pipe breaks outside containment.

Drywell HVAC duct-work Added pressure relief valves This prevents damage to ducts 9.4.5 during LOCA pressure surge in drywell.

Mechanical vacuum pump The pump exhaust was rerouted The charcoal filters will capture the 9.4.4 to the turbine equipment iodine discharged from the compartment exhaust duct vacuum pumps, as identified by leading to the charcoal filters EPRI Report NP-495.

and vent stack.

Mechanical vacuum pump The room air exhaust was The charcoal filters will capture 9.444 compartment changed from nonfiltered to iodine released to the room per filtered exhaust. EPRI Report NP-495.

Liquid Waste Management The radwaste evaporator Effective processing of chemical 11.2 System system and associated waste can be provided by the floor equipment was not completely drain subsystem, thereby installed for plant operation. eliminating operational problems associated with evaporative processing.

Gaseous waste management Change the offgas treatment The charcoal adsorption method 11.3 system system from cryogenic provides advantages in reliability distillation type to charcoal and maintainability, while limiting adsorption type. offsite doses to levels as low as or lower than can be achieved with the cryogenic distillation method.

CHAPTER 01 1.3-18 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.3-8 (Cont'd)

UFSAR SECTION IN WHICH ITEM CHANGE REASON FOR CHANGE SUBJECT IS DISCUSSED Solid radwaste management Because the evaporator was not Due to the previously described system completely installed for plant change in the liquid waste operation, a system for solidification management system, the evaporator of evaporator concentrates was also concentrates will not be produced.

not installed. Dewatered resin wastes will be packaged in approved high integrity containers consistent with the requirements established by the South Carolina Department of Health and Environmental Control and will meet the intent of BTP ESTB 11-3.

The vibrating hoppers were eliminated from system design because of anticipated operational problems and because they are not required for effective functioning of the solid radwaste system.

Primary containment instrument A seismic Category I backup gas To allow for long-term operation of 9.3.1, 5.4.7, 1.13 gas system supply for operation of ADS valves ADS valves to provide an alternate has been added. shutdown cooling path for conformance with Regulatory Guide 1.139. Also satisfies NUREG-0694 item.

Bypass leakage barrier design Added vent lines to potential bypass To minimize leakage in order to 6.2.3 leakage paths to vent to the minimize offsite doses in the event of secondary containment and added a a LOCA.

feedwater fill system to maintain a wate seal on the feedwater lines.

Residual heat removal system Addes intertie piping and valves 'A' To allow use of RHR pumps 'B' and 'D' 5.4 and 'B' and between RHR 'C' and 'D' in conjunction with the RHR heat discharge loops. exchanger in the shutdown cooling mode for greater system flexibility during maintenance.

CHAPTER 01 1.3-19 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.3-8 (Cont'd)

UFSAR SECTION IN WHICH ITEM CHANGE REASON FOR CHANGE SUBJECT IS DISCUSSED Ultimate heat sink Added soil-bentonite lining to the To minimize construction delays in 2.5, 9.2.6 spray pond bottom and soil event that the potential for greater slopes. than expected seepage rates was found.

Safeguard piping fill system Provided a redundant safety- To provide increased assurance 6.3 grade piping fill system. that water hammer events will not occur during ECCS system startup.

Spent fuel pool Added makeup water To provide Seismic Category I, 9.1 connections from the ESW safety-grade makeup water supply System. to the spent fuel pools to provide cooling in the event of loss of the spent fuel pool cooling system in conformance with Regulatory Guide 1.13.

Reactor recirculation system Deleted recirculation loops To improve the integrity and 5.4 equalizing line. reliability of the recirculation loops.

Reactor coolant pressure Changed portions of the RHR To minimize potential for IGSCC. 5.2.3 boundary piping LPCI, head spray, and shutdown cooling piping to type 316L stainless steel with less than 0.02% carbon. Changed recirculation loop piping to type 316K stainless steel.

Battery System Added a non-Class IE battery to To provide separation of Class 1E 8.3 power non-Class IE dc loads. and non-Class 1E loads in conformance with Regulatory Guide 1.75 CHAPTER 01 1.3-20 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.3-8 (Cont'd)

UFSAR SECTION IN WHICH ITEM CHANGE REASON FOR CHANGE SUBJECT IS DISCUSSED Reactor enclosure recirculation RERS no longer recirculates air Separation prevents the 9.4.2.1 system from the refueling area which is temperature and humidity of the permanently separated from the refueling area from affecting the reactor enclosure at el 352'. reactor enclosure below through Refueling area now exhausts RERS mixing, reduces the time for directly to the SGTS upon drawdown of the reactor enclosure isolation. by eliminating the possibility of mixing airborne activity through reactor enclosure 1, the refueling area, and reactor enclosure 2 following a LOCA.

Redundant Reactivity Control Added RRCS To reduce the possibility of an 7.6.1.8 & 7.6.2.8 System ATWS event and the automatically mitigate the consequences of an ATWS event by independently monitoring the RPV dome pressure and water level and automatically initiating the ARI, RPT, SLCS flow and feedwater runback.

Alternate rod insertion Added ARI solenoid valves to To provide independent solenoid 4.6.1.2.5.4 the scram valve pilot air header. valves to bleed air from the scram valve pilot air header on low water level or high dome pressure in the RPV when detected by the RRCS to increase the reliability of control rod insertion.

Recirculation Pump Trip Added redundant trip breakers To trip the reactor recirculation 7.1 & 7.6 to the power supply to each pump motors in the event of high reactor recirculation pump dome pressure or low water level motor. in the RPV, and thereby reduce the reactor power level in the event of an ATWS.

CHAPTER 01 1.3-21 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.3-8 (Cont'd)

UFSAR SECTION IN WHICH ITEM CHANGE REASON FOR CHANGE SUBJECT IS DISCUSSED HPCI Flow Split Added a cross connection so To ensure adequate mixing of 6.3.2.2.1 that HPCI flow is injected to the SLCS flow injected into the RPV.

RPV through both the core spray and feedwater spargers.

Standby Liquid Control System Added a third SLCS pump & To permit increased SLCS 9.3.5 explosive valve. maintenance flexibility.

Reactor Building Recirculation Added REPS Vent. This vent is needed to allow System simultaneous SGTS operation to the reactor enclosure and refueling area. The SGTS duct is seal welded to ensure RERS prefiltration after the RERS fan starts.

Standby Gas Treatment System SGTS filters have 8 inch deep The 8 inch deep SGTS charcoal 6.5.1.1.2 charcoal adsorber with and adsorber provides a residence assigned efficiency of 99.0% for time 0.68 seconds after drawdown.

removal of inorganic iodines. This is sufficient to meet the filtering efficiency specified in table 2 of Regulatory Guide 1.52 (Rev 2).

Reactor Recirculation Pump Both of the Unit 1 The ASD is more reliable and Table 1.3-8, 1.10-1, Table 3.2-1, Motor Power Supply Recirculation Pump Motors efficient than the MG Set for Sect. 3.8.4.1.8, Sect. 4.4.3.3.2, Power Supplies have been controlling Reactor Recirculation 4.4.3.5, Table 5.2-3, Sect. 5.4.1.3, changed from a Motor- Pump speed. Table 5.4-1, Sect. 7.1.1.2, Generator (MG) Set to an Table 7.1-1, Sect. 7.7.1.3.1.1, Adjustable Speed Drive (ASD). 7.7.1.3.2, 7.7.1.3.3.2.1, 7.7.1.3.3.3, 7.7.1.3.3.4, 7.7.1.3.3.4.3, 7.7.1.3.3.4.4, 7.7.1.3.3.4.5, 7.7.1.3.3.4.6, 7.7.1.3.3.4.7, 7.7.1.3.3.4.8, 7.7.1.3.3.5, 7.7.1.3.5.1, 7.7.1.3.5.2, 7.7.2.3.1, 7.7.2.3.3, Fig. 7.7-7, Sect. 8.1.6.1.12, Fig. 8.1-4, Table 8.3-28, Table 8.3-29, CHAPTER 01 1.3-22 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.3-8 (Cont'd)

UFSAR SECTION IN WHICH ITEM CHANGE REASON FOR CHANGE SUBJECT IS DISCUSSED Sect. 9.4.4.1, 9.4.4.2.4, 9.5.1.2.3.2, 9.5.1.2.9, 9.5.1.2.12, Sect. 9A.2.3, 9A.2.12, 9A.5.8.12, Table 9A-1, Fig. 9A-8, Sect. 15.3.1.1.1, 15.3.2.1.1, 15.3.2.2.3, 15.3.2.3.3, 15.4.5.1.1, 15.4.5.2.1, 15.4.5.3.2, 15.9.6.3.3 Reactor Recirculation Pump Recirculation Pump Motor The ASD is more reliable and Table 1.3-8, 1.10-1, Table 3.2-1, Motor Power Supply Power Supply has been efficient to improve system Sect. 3.8.4.1.8, Sect. 4.4.3.3.2, changed from a Motor- response to perturbations and 4.4.3.5, Sect. 5.4.1.3, Table 5.4-1, Generator (MG) Set to an transients. In addition, the Sect. 7.1.1.2, Table 7.1-1, Adjustable Speed Drive (ASD) ASD units are designed to be Sect. 7.7.1.3.1.1, 7.7.1.3.2.1, for Unit 2. The Unit 1 MG sets tolerant to single failures 7.7.1.3.2.2, 7.7.1.3.3.2.1, replacement was performed 7.7.1.3.3.3.1, 7.7.1.3.3.3.2, previously. 7.7.1.3.3.4.1, 7.7.1.3.3.4.2, 7.7.1.3.3.4.3, 7.7.1.3.3.4.4, 7.7.1.3.3.4.5, 7.7.1.3.3.4.6, 7.7.1.3.3.4.7, 7.7.1.3.3.4.8, 7.7.1.3.3.5, 7.7.1.3.5.1, 7.7.1.3.5.2, 7.7.2.3.1, 7.7.2.3.3, Fig. 7.7-7.1. Fig. 7.7-2.2, Sect. 8.1.6.1.12, Fig. 8.1-4, Table 8.3-28, Table 8.3-29, Sect. 9.4.4.1, 9.4.4.2.4, 9.5.1.2.3.2, 9.5.1.2.9, 9.5.1.2.12, Sect. 9A.2.3, 9A.2.12, 9A.5.8.25, Table 9A-1 Fig. 9A-8, Sect. 15.3.1.1.1, 15.3.2.1.1, 15.3.2.2.3, 15.3.2.3.3, 15.4.5.1.1, 15.4.5.2.1, 15.4.5.3.2, 15.9.6.3.3 CHAPTER 01 1.3-23 REV. 17, SEPTEMBER 2014

LGS UFSAR 1.4 IDENTIFICATION OF AGENTS AND CONTRACTORS 1.4.1 APPLICANT Exelon Generation Company, LLC (EGC) is the sole applicant for the utilization facility licenses and will operate the plant upon completion. Prime contractors and principal consultants are identified in Sections 1.4.2, through 1.4.5.

The Applicant has been responsible for the design and construction of, and currently operates, eight multi-unit fossil fuel power plants and one 2-unit nuclear power plant. Additionally, two large multi-unit hydroelectric generating plants, one of which is a pumped-storage plant, and several diesel engine and combustion turbine-driven generator installations have also been designed, constructed, and are currently being operated by the Applicant.

The Applicant also has an ownership interest in two operating fossil fuel plants and one operating nuclear power plant. These plants provide capacity and energy to the Applicant's system but are not operated by the Applicant.

These facilities, which had a net capacity of 8,197,600 KWe at the end of 1977, constitute the Applicant's electric generating system.

The Applicant has been active in the development of atomic energy for electric generation for many years. In 1952 it became a charter member of the Dow Chemical-Detroit Edison Nuclear Power Development Project, which subsequently became Atomic Power Development Associates, Inc. This organization designed and developed a fast breeder power reactor for the Atomic Energy Commission's Power Demonstration Program. The Applicant also took part in the formation of Power Reactor Development Company, which was organized to finance, construct, own, and operate the fast breeder reactor designed by Atomic Power Development Associates, Inc., for the Enrico Fermi Atomic Power Station.

The Applicant's engineers have had experience in many phases of nuclear projects including:

assignments to Atomic Power Development Associates, Inc. for design and development of core and fuel elements, shielding design, coordination of research at various levels on the metallurgical and chemical aspects of fuel elements; shift supervisor duties and preoperational duties, including preparation of plant operation manuals, at the Enrico Fermi Atomic Power Station; assignment to Power Reactor Development Company for coordination of control instrumentation and electrical features; assignment to the Nautilus nuclear submarine project for field engineering and mechanical operations during startup and initial operation; assignment to the nuclear reactor at Shippingport, Pennsylvania, for training and operational duties; assignment to the Knolls Atomic Power Laboratory for participation in prototype design of a sodium boiler for a submarine reactor; construction, startup, operation, and decommissioning of PBAPS Unit 1, a 40,000 KWe capacity unit employing an HTGR; and construction, startup, operation, and maintenance of PBAPS Units 2 and 3, each unit consisting of a BWR having an original rated core thermal power of 3293 KWt and producing a corresponding net electrical output of 1065 MWe.

1.4.2 ARCHITECT-ENGINEER AND CONSTRUCTOR The Applicant has retained Bechtel Power Corporation and Bechtel Construction, Inc. to provide architectural, engineering, construction, and startup services for LGS. In addition, Bechtel is CHAPTER 01 1.4-1 REV. 16, SEPTEMBER 2012

LGS UFSAR responsible for procurement of equipment other than the NSSS, turbine-generators, and certain other major components that have been purchased by the Applicant. Bechtel has been continuously engaged in engineering and construction activities since 1898. A review of recent tabulations of nuclear units in the continental United States that are planned, under construction, or in operation, indicates that Bechtel is responsible for the engineering design of approximately 60 of these units and, in addition, is charged with responsibility for construction of over 40 units.

Bechtel is, therefore, eminently qualified to provide the required services for station design, equipment procurement, construction, and startup.

1.4.3 NUCLEAR STEAM SUPPLY SYSTEM SUPPLIER GE has the contract to design, fabricate, and deliver the boiling water-type NSSS and nuclear fuel for LGS, as well as to provide technical direction for installation and startup of these systems. GE has been engaged in the development, design, construction, and operation of boiling water reactors since 1955. A review of recent tabulations of nuclear units in the United States that are planned, under construction, or in operation, reveals that approximately 65 of these units employ GE BWRs. Thus, GE has substantial experience, knowledge, and capability to design, manufacture, and furnish technical assistance for the installation and startup of the LGS NSSS.

1.4.4 TURBINE-GENERATOR SUPPLIER GE was the original contractor to design, fabricate, and deliver the turbine-generators for LGS, as well as to provide technical assistance for installation and startup of this equipment. GE has a long history in the application of turbine-generators to nuclear power stations dating back to 1955.

Over 100 of the nuclear units planned, under construction, or in operation in the United States employ GE turbine-generators. GE is, therefore, well qualified to design, fabricate, and deliver the turbine-generators for LGS, and to provide technical assistance for the installation and startup of this equipment. Siemens Power Corporation has the contract to design, fabricate and install the retrofit high pressure and low pressure turbines. Like GE, Siemens is well qualified to perform this work.

1.4.5 CONSULTANTS The licensee has engaged consultants to provide information and recommendations in a number of specialized fields. Principal consultants include:

a. Gilbert Associates: siting

b. Dames & Moore: geology, seismology, groundwater hydrology

c. Meteorological Evaluation Services, Inc.: meteorology

d. Buchart-Horn: archeology

e. MPR Associates, Inc.: quality assurance

f. C. L. Hosler: cooling tower studies

g. Radiation Management Corporation: aquatic and terrestrial biology, and radioactive releases and their effects

h. Nuclear Associates International Corp: core analysis CHAPTER 01 1.4-2 REV. 16, SEPTEMBER 2012

LGS UFSAR

i. Kibbe & Associates: nuclear fuel supply

j. Nuclear Energy Services: inservice inspection

k. J. E. Edinger: limnology

l. Hydrocon: Schuylkill River hydrology, radioactive release dispersion analysis

m. Betz-Converse-Murdoch, Inc.: sewage treatment

n. Sanders & Thomas: Schuylkill River soundings, road relocation

o. E. H. Bourquard Associates, Inc: water supply

p. Tippetts-Abbett-McCarthy-Stratton: water supply, hydrology CHAPTER 01 1.4-3 REV. 16, SEPTEMBER 2012

LGS UFSAR 1.5 REQUIREMENTS FOR FURTHER TECHNICAL INFORMATION 1.5.1 CURRENT DEVELOPMENT PROGRAMS 1.5.1.1 Instrumentation for Vibration of Reactor Intervals Vibration testing for reactor internals has been performed on virtually all GE BWR plants. At the time of issue of Regulatory Guide 1.20, test programs for compliance were instituted. The first BWR/4 plant of this size, Browns Ferry 1, is considered a prototype design and was instrumented and subjected to both cold and hot, two-phase flow testing to demonstrate that flow-induced vibrations similar to those expected during operation do not cause damage. Subsequent plants that have internals similar to those of the prototypes are tested in compliance with the requirements of Regulatory Guide 1.20 to confirm the adequacy of the design with respect to vibration. Combined with the system for monitoring of vibration within the reactor vessel and its immediate piping, additional equipment is provided to monitor selected rotating machines within the plant in order to provide early warning of excessive machine vibration.

1.5.1.2 Core Spray Distribution GE has a program underway to study BWR/6 core spray distributions using a combination of single nozzle steam and air tests, single and multiple nozzle analytical models, and full-scale air tests. This methodology was confirmed by a full-scale 30° sector steam test conducted during 1979 and reported in Reference 1.5-1. The NRC has agreed "that the overall empirical/engineering method outlined by GE ... is an acceptable method for verification of the currently assumed core spray distributions which are used to justify conservatisms of the spray cooling heat transfer coefficients in ECCS-LOCA licensing calculations."

For other BWR plants, the NRC believes that "there is a sufficient technical basis to permit continued plant operation and licensing in the interim period while these additional tests and information are being developed. This interim conclusion is based on:

a. The existence of a considerable safety margin between available and required spray flow indicated by preliminary analyses and measurements provided for each size BWR/1 through BWR/5;

b. The relative ease with which ECCS re-analyses could be performed to establish an acceptable power limit in the unlikely event that test results do not support the spray flows currently assumed;

c. The possibility that plants under construction could modify their spray nozzles or aiming pattern to provide a better spray distribution, if future test results indicate the desirability of such changes (particularly applicable to the BWR/6, where the type of preliminary measurements referenced in a. above are not yet available);

d. The existence of counter-current-flow-limiting phenomena in many plants would provide a steam/water layer on top of the core which should force a more even distribution of the core spray; CHAPTER 01 1.5-1 REV. 13, SEPTEMBER 2006

LGS UFSAR

e. The aforementioned empirical/engineering method is expected to provide timely confirmation of the spray flow margin presently believed to exist."

1.5.1.3 Core Spray and Core Flooding Heat Transfer Effectiveness Due to the incorporation of an 8x8 fuel rod array with unheated "water rods," tests have been conducted to demonstrate the effectiveness of the ECCS in the new geometry.

These tests are regarded as confirmatory only, since the geometry change is very slight and the "water rods" provide an additional heat sink in the inside of the bundle that improves heat transfer effectiveness.

There are two distinct programs involving the core spray. Testing of the core spray distribution has been accomplished and submitted (Reference 1.5-2). The other program concerns the testing of core spray and core flooding heat transfer effectiveness. The results of testing with stainless steel cladding are reported in Reference 1.5-3. The results of testing using Zircaloy cladding are reported in Reference 1.5-4.

1.5.1.4 Verification of Pressure-Suppression Design The Mark II pressure-suppression test program was initiated in the fall of 1975 to investigate suppression pool dynamic phenomena. Phase I blowdown tests were completed late in 1975.

These tests utilized a single 24 inch diameter (590 mm ID) downcomer that vented into a 7 foot (2.13 meters) inside diameter tank, representative of a single downcomer/pool cell in a typical Mark II suppression pool. The objective of this phase of testing was to quantify pool dynamics phenomena, particularly the effect of wetwell pressurization on pool swell, and the load associated with the low mass flux steam condensation, or chugging. Primary variables were simulated break size, initial vent submergence, and wetwell air space configuration, i.e., vented or closed wetwell.

The Phase II tests were generally similar to the Phase I tests, except a 20 inch diameter (489 mm ID) downcomer was used. The Phase I and II tests thus bound the range of vent-to-pool area ratios of all Mark II containments. Although the test objectives were similar during Phases I and II, some changes were made in the Phase II test matrix after review of the Phase I data. For example, since the Phase I test had shown that wetwell configuration was the variable that had the most pronounced effect on pool dynamics, the decision was made to concentrate the testing effort on the closed wetwell configuration, which is characteristic of the Mark II containment.

In place of the open wetwell tests, additional blowdowns were included in the Phase II test matrix in order to investigate the effect of saturated liquid versus saturated steam breaks and the effect of downcomer bracing configuration.

As was the case for the Phase I tests, the primary Phase II variables were simulated break size and initial vent submergence. The Phase III tests investigated the pool temperature sensitivity of pool swell and of the load associated with the chugging phenomenon. Only a single break size and vent submergence were tested, with pool temperature alone being a variable. A significant number of blowdowns were performed to yield a statistically significant data set.

CHAPTER 01 1.5-2 REV. 13, SEPTEMBER 2006

LGS UFSAR 1.5.1.5 Critical Heat Flux Testing A program for critical heat flux testing was established and was to be similar to that described in Reference 1.5-5. Since that time, however, a new analysis has been performed and the General Electric BWR Thermal Analysis Basis (GETAB) program initiated. The results of that analysis and related testing is described in Reference 1.5-6.

1.5.1.6 Fuel Assembly Structural Testing Although tests are being conducted to determine the effects of vibration on fuel assembly spacers and to determine the forces to which the assemblies are subjected during shipment, there is no special program at present concentrating on structural testing, and no topical report is anticipated.

1.

5.2 REFERENCES

1.5-1 "Core Spray Design Methodology Confirmation Test," NEDO-24712, (August 1979).

1.5-2 "BWR Core Spray Distribution," Licensing Topical Report NEDO-10846, (April 1973).

1.5-3 "Modeling the BWR/6 Loss-of-Coolant Accident: Core Spray and Bottom Flooding Heat Transfer Effectiveness," Licensing Topical Report NEDO-10801, (March 1973).

1.5-4 "Emergency Core Cooling Test of an Internally Pressurized, Zircaloy Clad, 8x8 Simulated BWR Fuel Bundle," Licensing Topical Report NEDO-20231, (December 1973).

1.5-5 "Design Basis for Critical Heat Flux Conditions in Boiling Water Reactors," APED-5286, (September 1966).

1.5-6 "General Electric BWR Thermal Analysis Basis (GETAB): Data, Correlation and Design Application," Licensing Topical Report NEDO-10958-A, (January 1977).

CHAPTER 01 1.5-3 REV. 13, SEPTEMBER 2006

LGS UFSAR 1.6 MATERIAL INCORPORATED BY REFERENCE/GENERAL REFERENCE Table 1.6-1 provides a tabulation of topical reports and other documents incorporated by reference in this UFSAR.

Note: For clarification of the terms Incorporation by Reference and General Reference, refer to Reg. Guide 1.181, Content Of The Updated Final Safety Analysis In Accordance With 10 CFR 50.71(e), September, 1999 (endorsement of NEI 98-01, Revision 1, June, 1999).

CHAPTER 01 1.6-1 REV. 13, SEPTEMBER 2006

LGS UFSAR Table 1.6-1 REFERENCED REPORTS Report Referenced in Number UFSAR Section A. General Electric Company Reports APED-4827 Maximum Two-Phase Vessel 6.2 Blowdown from Pipes (1965)

APED-5286 Design Basis for Criteria Heat 1.5 Flux Condition in BWRs (Sept 1966)

APED-5458 Effectiveness of Core Standby 5.4 Cooling Systems for General Electric Boiling Water Reactors (March 1968)

APED-5460 Design and Performance of General 3.9 Electric BWR Jet Pumps (July 1968)

APED-5555 Impact Testing on Collet 4.6 Assembly for Control Rod Drive Mechanism (7RDB144A) (Nov 1967)

APED-5652 Stability and Dynamic Performance 4.1 of the General Electric Boiling Reactor APED-5706 In-Core Neutron Monitoring System 7.2 For General Electric Boiling Water Reactors (Nov 1968, Revised April 1969)

APED-5750 Design and Performance of General 3.9, 5.4 Electric Boiling Water Reactor Main Steam Line Isolation Valves (March 1969)

APED-5756 Analytical Methods for Evaluating 15.4, 15.7 the Radiological Aspects of the General Electric Boiling Water Reactor (March 1969)

GEAP-5620 Failure Behavior in ASTM A 106B 5.2 Pipes Containing Axial Through-Wall Flows (April 1968)

GE-NE-L12- GE14 Fuel Design Cycle-Independent 9.1.6 00884-00-01P Analyses for Limerick Generating Station, Units 1 and 2, March 2001 J11-03898-01 GE14 Spent Fuel Storage Rack 9.1.6

-SFP Criticality Analysis for Limerick Generating Station, Unit 2, March, 2001 J11-03932-00 GE14 Spent Fuel Storage Rack 9.1.6

-SFP Criticality Analysis for the Limerick Generating Station, Unit 1, May, 2001 NEDC-32601P-A Methodology and Uncertainties for 4.1 Safety Limit MCPR Evaluations (latest approved revision)

NEDC-32868-P GE14 Compliance with Amendment 22 9.1.6 of NEDE-24011-P-A (GESTAR II)

(latest approved revision)

CHAPTER 01 1.6-2 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.6-1 (Cont'd)

Report Referenced in Number UFSAR Section NEDE-10813 PDA-Pipe Dynamic Analysis Program 3.6 for Pipe Rupture Movement (Proprietary Filing)

NEDE-10958 General Electric BWR Thermal 15.0 Analysis Basis (GETAB):

Data, Correlation, and Design Application (November 1973)

NEDE-20371-02 User Guide and Engineering 4.1 Description of HEATER Computer Program (March 1974)

NEDE-20566 Analytical Model for Loss-of 3.9, 6.3 Coolant Accident (LOCA) in Accordance with 10CFR50, Appendix K (Nov. 1975)

NEDE-20944-P BWR/4 and BWR/5 Fuel Design 1.8, 4.2 (October 1976) Amendment 1 4.3 (January 1977)

NEDE-21175-3-P BWR Fuel Assembly Evaluation 3.9 of Combined Safe Shutdown Earthquake (SSE) and Loss-of-Coolant Accident (LOCA)

Loadings (July 1982)

NEDE-21354-P BWR Fuel Channel Mechanical 3.9 Design and Deflection (September 1976)

NEDE-21821 Boiling Water Reactor 3.9 Feedwater Nozzle/Sparger Final Report (March 1978)

NEDE-24011-P-A General Electric Standard 4.1, 4.2 NEDE-24011-P- Application for Reactor Fuel, A-US including the United States Supplement (latest approved revision)

CHAPTER 01 1.6-3 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.6-1 (Cont'd)

Report Referenced in Number UFSAR Section NEDE-24057-P Assessment of Reactor 3.9 Internal Vibration in BWR/4 and BWR/5 Plants (November 1977)

NEDE-24222 Assessment of BWR Mitigation of 15.8 ATWS (NUREG-0460 Alternate 3)

(Volume 1 May 1979, Volume 2 December 1979)

NEDO-10173 Current State of Knowledge of 11.1 High Performance BWR Zircaloy-Clad UO2 Fuel (May 1970)

NEDO-10320 The General Electric Pressure 6.2 Suppression Containment Analytical Model (April 1971) Supplement 1 (May 1971)

NEDO-10466 Power Generation Control Complex 7.7, 8.1 Design Criteria and Safety Evaluation (Revision 2, March 1978)

NEDO-10505 Experience with BWR Fuel 11.1 Through September 1971 (May 1972)

NEDO-10527 Rod-Drop Accident Analysis for 15.4A Large Boiling Water Reactors (March 1972) Supplement 1 (July 1972) Supplement 2 (January 1973)

NEDO-10585 Behavior of Iodine in Reactor 5.2, 15.6 Water During Plant Shutdown and Startup (August 1972)

NEDO-10602 Testing of Improved Jet Pumps 3.9 for BWR/6 Nuclear System (June 1972)

NEDO-10739 Methods for Calculating Safe 6.3 Test Intervals and Allowable Repair Times for Engineered Safeguard Systems (January 1973)

CHAPTER 01 1.6-4 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.6-1 (Cont'd)

Report Referenced in Number UFSAR Section NEDO-10801 Modeling the BWR/6 Loss-of- 1.5 Coolant Accident: Core Spray and Bottom Flooding Heat Transfer Effectiveness (March 1973)

NEDO-10802 Analytical methods of Plant 5.2, 15.0, Transient Evaluations for 15.1 General Electric Boiling Water Reactor (April 1973)

NEDO-10846 BWR Core Spray Distribution 1.5 (April 1973)

NEDO-10871 Technical Derivation of BWR 11.1 1971 Design Basis Radioactive Source Terms (March 1975)

NEDO-10899 Chloride Control in BWR Coolants 5.2 (June 1973)

NEDO-10958-A General Electric BWR Thermal 1.5 Analysis Basis (GETAB): Data, Correlation, and Design Application (January 1977)

NEDO-10959 General Electric BWR Thermal 15.0 Analysis Basis (GETAB): Data, Correlation, and Design Application (November 1973)

NEDO-11209- Nuclear Energy Business Group 1.8 04A Boiling Water Reactor Quality Assurance Program (February 1980)

NEDO-12037 Summary of X-Ray and Gamma Ray 12.3 Energy and Intensity Data (January 1970)

NEDO-20231 Emergency Core Cooling Tests 1.5 of an Internally Pressurized, Zircaloy-Clad, 8x8 Simulated BWR Fuel Bundle (December 1973)

NEDO-20533 The General Electric Mark III 6A Pressure-Suppression Containment System Analytical Model (June 1974) Supplement 1 (September 1975)

CHAPTER 01 1.6-5 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.6-1 (Cont'd)

Report Referenced in Number UFSAR Section NEDO-20566 General Electric Company Model 3.9, 6.3 for Loss-of-Coolant Accident Analysis in Accordance with 10CFR50, Appendix K (January 1976)

NEDO-20922 Experience with BWR Fuel 11.1 Through September 1974 (June 1975)

NEDO-20944-1 BWR/4 and BWR/5 Fuel Design 4.2, 4.3 (October 1976) Amendment 1 (January 1977)

NEDO-20953 Three-Dimensional Boiling 15.4 Water Reactor Core Simulator (May 1976)

NEDO-21061 Mark II Containment Dynamic 3.8, 6.2 Forcing Function Information Report NEDO-21142 Realistic Accident Analysis 15.4, 15.6 The RELAC Code (October 1977)

NEDO-21143 Conservative Radiological 15.4 Accident Evaluation - The CONAC01 Code (March 1976)

NEDO-21159 Airborne Release from BWR's for 11.1 Environmental Impact Evaluation (March 1976)

NEDO-21231 Banked Position Withdrawal 15.4 Sequence (January 1977)

NEDO-21617A Analog Transmitter/Trip Unit 7.0, 7.2 System for Engineered Safe-Guard Sensor Inputs NEDO-21660 Experience with BWR Fuel 11.1 through December 1976 (July 1977)

CHAPTER 01 1.6-6 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.6-1 (Cont'd)

Report Referenced in Number UFSAR Section NEDO-21708 Radiation Effects in BWR 5.3 NEDO-21778-A Transient Pressure Rises 5.3 Affecting Fracture Toughness Requirements for BWRs (December 1978)

NEDO-23538 Users Manual for CRPLS01 4.1 Program (December 1976)

NEDO-24057 Assessment of Reactor Internals 3.9 Vibration in BWR/4 and BWR/5 Plants (November 1977)

NEDO-24154 Qualification of the One- 5.2, 15.0 Dimensional Core Transient Model for BWRs (October 1978)

NEDO-24708A Additional Information Required 1.13, 6.3 for NRC Staff Generic Report on BWRs, Rev. 1 (Dec. 1980)

NEDO-24712 Core Spray Design Methodology 1.5 Confirmation Tests (August 1979)

NEDO-24951 BWR Owners' Group NUREG-0737 1.13 Implementation: Analyses and Positions Submitted to the NRC (June 1981)

NEDO-31897 GE Nuclear Energy, "Generic 6.2, 15.0 NEDC-31897P-A Guidelines For GE Boiling Water Reactor Power Uprate,"

Class I (Non-proprietary),

February 1992; and Class III (Proprietary), May 1992.

NEDO-33484 GE Hitachi Nuclear Energy, "Safety 1.1, 1.2, 1.3, 1.4, NEDC-33484P Analysis Report for Limerick Generating 1.10, 3.6, 3.8, 3.9, Station Units 1 and 2 Thermal Power 4.3, 4.4, 5.2, 5.3, Optimization," Class I (Non-proprietary), 7.2, 7.7, 8.2, 9.1, March 2010; and Class III (Proprietary), 9.2, 10.1, 10.2, March 2010. 10.4, 15.0, 15.2, 15.6 NEDC-31585P BWROG Report for increasing MSIV 6.7, 15.6 Leakage Rate Limits and Elimination of Leakage Control Systems NEDM-10320 The GE Pressure Suppression 6.2 Containment Analytical Model,"

March 1971 CHAPTER 01 1.6-7 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.6-1 (Cont'd)

Report Referenced in Number UFSAR Section NEDO-20533 The General Electric Mark III 6.2 Pressure Suppression Containment System Analytical Model," June 1974.

NEDO-20566A General Electric Company 6.2 Analytical Model for Loss-of-Coolant Analysis in Accordance with 10CFR50 Appendix K -

Volume II, January 1976 NUREG-0800 U.S. Nuclear Regulatory 6.2 Commission Standard Review Plan, Section 6.2.1.1.C, "Pressure -

Suppression Type BWT Containments,"

Revision 6, August 1984 NRC Letter Letter from Ashok Thadani, 6.2 Director Division of Systems Safety and Analysis, Office of Nuclear Reactor Regulation, U.S.

Nuclear Regulatory Commission, to Gary L. Sozzi, Manager Technical Services, General Electric Nuclear Energy, "Use of SHEX Computer Program and ANSI/ANS 5.1-1979 Decay Heat Source Term For Containment Long-Term Pressure and Temperature Analysis,"

July 13, 1993.

NEDO-21061 Mark II Containment Dynamic 3.8, 6.2 Forcing Functions Information Report, Rev. 4, November 1981 NUREG-0487 U.S. Nuclear Regulatory 6.2 Commission "Mark II Containment Lead Plant Program Load Evaluation and Acceptance Criteria," October 1978 NUREG-0808 U.S. Nuclear Regulatory 6.2 Commission, "Mark II Containment Program Load Evaluation and Acceptance Criteria," August 1981 CHAPTER 01 1.6-8 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.6-1 (Cont'd)

Report Referenced in Number UFSAR Section U.S. Nuclear Regulatory 6.2 Commission, "Safety Evaluation Report Related to the Operation of Limerick Generating Station, Units 1 and 2," NUREG-0991, August 1983, and Supplements (Docket Nos.

50-352 and 50-353).

NEDO-30832 Elimination of Limit On Local 6.2 Suppression Pool Temperature For SRV Discharge With Quenchers, Class I, December 1984 GE Nuclear Energy, "Generic 6.2 Evaluations of General Boiling Water Reactor Power Uprate,"

Licensing Topical Report NEDC-31984P, Class III (Proprietary),

July 1991; NEDO-31984, Class I (Non-proprietary), March 1992; and Supplements 1 & 2.

D. Gobel, "Thermo-Hydraulic 6.2 Quencher Design of the Safety Relief System," Revision 1, R14-25/1978, Kraftwerk Union, April 1978 NEDC-32170P Limerick Generating Station 6.2 Units 1 and 2, SAFER/GESTR-LOCA Loss-of-Coolant Accident Analysis, Class III (Proprietary), Revision 1, June 1993 NEDC-32225P Power Rerate Safety Analysis 6.2 Report for Limerick Generating Station Units 1 & 2 (September 1993)

HI-2104779 Criticality Safety Evaluation for GNF2 9.1 Fuel in the SFP at Limerick, Revision 1 NEDC-33270P GNF2 Advantage Generic Compliance 9.1 with NEDE 24011-P-A (GESTAR II)

(latest approved revision)

NEDC-33627P GNF2 Fuel Design Cycle Independent 15.7 Analyses for Limerick Generating Station Units 1 and 2, Global Nuclear Fuels Document, (latest approved revision)

B. Other Reference Reports AI-75-2 Thermal Hydrogen Recombiner 6.2 System for Water-Cooled Reactors, Rockwell International (Rev.2(P),

July 1975)

CHAPTER 01 1.6-9 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.6-1 (Cont'd)

Report Referenced in Number UFSAR Section AI-77-55 Thermal Hydrogen Recombiner 6.2 System for Mark I and II Boiling Water Reactors, Rockwell International (Sept 1977)

BHR/DER 70-1 Radiological Surveillance 11.1 Studies at a Boiling Water Nuclear Power Reactor (March 1970)

OCF-1 Nuclear Containment Isolation 6.2 System, Owens-Corning Fiberglass Corporation (Jan 1979)

TID-4500 Relap 3 - A Computer Program 3.6 for Reactor Blowdown Analysis IN-1321 (June 1970)

C. Bechtel Power Corporation Reports BC-TOP-1 Containment Building Liner 3.8 Plant Design (Rev. 1 Dec 1972)

BC-TOP-4-A Seismic Analyses of Structures 3.7 and Equipment for Nuclear Power Plants (Rev. 3, November 1974)

BC-TOP-9A Design of Structures for Missile 3.3, 3.5 Impact (Rev. 2, Sept 1974)

BN-TOP-2 Design for Pipe Rupture Effects 3.6 (Rev. 2, May 1974)

BN-TOP-4 Subcompartment Pressure Analysis 3.6, 6A (Nov 1972) Rev. 1 (July 1976)

D. Exelon Reports Limerick Environmental Qualification Report 1.13, 3.11, 7.1, 8.1 Limerick Probabilistic Risk Assessment 15.11 Limerick Severe Accident Risk Assessment Limerick Environment Report - Operating 5.2, 2.3.2 License Stage CHAPTER 01 1.6-10 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.6-1 (Cont'd)

Report Referenced in Number UFSAR Section E. Siemens Reports ER 9605 Missile Probability 3.5, 10.2 Methodology for Limerick Generating Station, Units 1 and 2, with Siemens Retrofit Turbines Siemens Power Corporation Engineering Report, Revision 2, June 18, 1997 - SIEMENS PROPIETARY CT-27496 "Missile Analysis Report" 3.5, 10.2 Limerick Units 1 and 2, March 1, 2013 (Includes ER-9605, Rev. 2 as Appendix A)

CHAPTER 01 1.6-11 REV. 17, SEPTEMBER 2014

LGS UFSAR 1.7 DRAWINGS AND OTHER DETAILED INFORMATION Table 1.7-1 provides a listing of electrical drawings used in the plant design.

Table 1.7-2 provides a listing of P&ID drawings, with a reference to their former UFSAR figure number where applicable.

Table 1.7-3 provides a listing of control and instrumentation drawings used in the plant design.

Table 1.7-4 provides a listing of miscellaneous drawings, with a reference to their former UFSAR figure number where applicable.

Note: Refer to the corresponding Limerick design drawings and their associated open change documentation for up to date plant design information.

CHAPTER 01 1.7-1 REV. 15, SEPTEMBER 2010

LGS UFSAR Table 1.7-1 ELECTRICAL DRAWINGS Drawing Number Title Former UFSAR Figure Number E-1 Sh.1 Single Line Diagram - Station 8.1-1 Sh.1 E-2 Sh.1 Schematic Diagram - Phasing, 220KV, 22KV, 13.2KV, 23KV & 440V Systems Unit 1 and Comm -

E-3 Sh.1 Schematic Diagram - Phasing, 500KV, 22KV, 13.2KV, 440V Systems Unit 2 -

E-4 Sh.1 Schematic Diagram - Phasing 4 kV & 440 V Safeguard Systems - Unit 1 -

E-5 Sh.1 Schematic Diagram - Phasing 4 kV & 440 V Safeguard Systems - Unit 2 -

E-6 Sh.1 Single Line Diagram - Synchronizing - Unit 1 -

E-7 Sh.1 Single Line Diagram - Synchronizing - Unit 2 -

E-8 Sh.1 Single Line Diagram - Site Services Substation -

SINGLE LINE METER & RELAY DIAGRAMS -

E-10 Sh.1 Single Line Meter & Relay Diagram - 1 Generator, 1 Transformer & 11 Auxiliary Transformer - Unit 1 -

E-11 Sh.1 Single Line Meter & Relay Diagram - 2 Generator, 2 Transformer &211 Auxiliary Transformer - Unit 2 -

E-12 Sh.1 Single Line Meter & Relay Diagram - 13.2KV Unit Auxiliary Power System - Unit 1 -

E-12 Sh.1 Single Line Meter & Relay Diagram - 13.2KV Unit Auxiliary Power System - Unit 1 -

E-13 Sh.1 Single Line Meter & Relay Diagram - 13.2KV Unit Auxiliary Power System - Unit 2 -

E-13 Sh.2 Single Line Meter & Relay Diagram - 13.2KV Unit Auxiliary Power System - Unit 2 -

E-14 Sh.1 Single Line Meter & Relay Diagram -

E-14 Sh.2 Single Line Meter & Relay Diagram -

E-15 Sh.1 Single Line Meter & Relay Diagram - 4 kV Safeguard Power System - Unit 1 8.3-1 Sh.1 E-16 Sh.1 Single Line Meter & Relay Diagram - 4 kV Safeguard Power System - Unit 2 8.3-1 Sh.2 E-17 Sh.1 Single Line Meter & Relay Diagram - 114A & 124A Generator Area L.C. & 114B and 124B Reactor Area L.C., 440V-Unit 1 -

E-18 Sh.1 Single Line Meter & Relay Diagram - 114C & 124C Turbine Area L.C., 440V - Unit 1 -

E-19 Sh.1 Single Line Meter & Relay Diagram - 2.3 KV Plant Services Power System - Comm -

E-20 Sh.1 Single Line Meter & Relay Diagram - Diesel Generator - Units 1 & 2 -

E-21 Sh.1 Single Line Meter & Relay Diagram - 214A & 224A Generator Area L.C. and 214B and 224B Reactor Area L.C. - 440V - Unit 2 -

E-22 Sh.1 Single Line Meter & Relay Diagram - 214C & 224C Turbine Area L.C. - 440V - Unit 2 -

E-23 Sh.1 Single Line Meter & Relay Diagram - Load Center Load tab, Non-Safeguard Load Center - Unit 1 only E-23 Sh.2 Single Line Meter & Relay Diagram - Load Center Load tab, Non-Safeguard Load Center - Unit 2 only -

E-23 Sh.3 Single Line Meter & Relay Diagram - Load Center Load tab, Non-Safeguard Load Center - Comm only -

E-24 Sh.1 Safeguard LC Load tab - Units 1 & 2 -

E-25 Sh.1 Single Line Meter & Relay Diagram - 114D, 124D, 134D, 214D, 224D & 234D Plant Serv. & Admin. Complex L.C.-440-Comm -

E-25 Sh.2 Single Line Meter & Relay Diagram - 134D, 234D, 144D, 244D Admin. Building & Technical Supp. Center L.C.-440-Comm -

E-26 Sh.1 Single Line Diagram - 120 V ac Power Supply HVAC Safeguard Motor-Operated Valves & Dampers - Units 1 & 2 & Comm -

E-26 Sh.2 Single Line Diagram - 120 V ac Power Supply HVAC Safeguard Motor-Operated Valves & Dampers - Units 1 & 2 & Comm -

Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-2 REV. 16, SEPTEMBER 2012

LGS UFSAR Table 1.7-1 (Contd)

ELECTRICAL DRAWINGS Drawing Number Title Former UFSAR Figure Number E-27 Sh.1 Single Line Meter & Relay Diagram MCC Load Tab - D214-R-G1 & D224-R-G1 - Reactor Area Safeguard MCC 440 V - Unit 2 -

E-28 Sh.1 Single Line Meter & Relay Diagram - D114, D124, D134, D144 Safeguard Load Centers, 440 V - Unit 1 8.3-2 Sh.1 E-29 Sh.1 Single Line Meter & Relay Diagram - D214, D224, D234, D244 Safeguard Load Centers, 440 V - Unit 2 8.3-2 Sh.2 E-30 Sh.1 Single Line Diagram - Instrumentation ac System - Unit 1 -

E-30 Sh.2 Single Line Diagram - Instrumentation ac System - Unit 1 -

E-30 Sh.3 Single Line Diagram - Instrumentation ac System - Unit 1 -

E-31 Sh.1 Single Line Diagram - Instrumentation ac System - Unit 2 -

E-31 Sh.2 Single Line Diagram - Instrumentation ac System - Unit 2 -

E-31 Sh.3 Single Line Diagram - Instrumentation ac System - Unit 2 -

E-32 Sh.1 Single Line Meter & Relay Diagram - Uninterruptible ac System - RPS, UPS and Computer Systems - Units 1 & 2 7.2-16 Sh.1 E-32 Sh.2 Single Line Meter & Relay Diagram - Uninterruptible ac System - RPS, UPS and Computer Systems - Units 1 & 2 -

E-33 Sh.1 Single Line Meter & Relay Diagram - 125/250 V dc System - Unit 1 8.3-3 Sh.1 E-33 Sh.2 Single Line Meter & Relay Diagram - 125/250 V dc System - Unit 1 8.3-3 Sh.2 E-33 Sh.3 Single Line Meter & Relay Diagram - 125/250 V dc System - Unit 1 8.3-3 Sh.3 E-34 Sh.1 Single Line Meter & Relay Diagram - 125/250 V dc System - Unit 2 8.3-3 Sh.4 E-34 Sh.2 Single Line Meter & Relay Diagram - 125/250 V dc System - Unit 2 8.3-3 Sh.5 E-34 Sh.3 Single Line Meter & Relay Diagram - 125/250 V dc System - Unit 2 8.3-3 Sh.6 E-35 Sh.1 Single Line Meter & Relay Diagram MCC Load Tab - D114-R-G1 & D124-R-G1 - Reactor Area Safeguard MCC 440 V - Unit 1 -

E-36 Sh.1 Single Line Diagram - Totalizing Demand Metering - Units 1 & 2 -

E-37 Sh.1 Single Line Meter & Relay Diagram MCC Load Tab - D114-S-L, D124-S-L, D234-S-L & D244-S-L- Spray Pond Area -

Safeguard MCC 440 V - Comm E-37 Sh.2 Single Line Meter & Relay Diagram MCC Load Tab - D114-S-L, D124-S-L, D234-S-L & D244-S-L - Spray Pond Area -

Safeguard MCC 440 V - Comm E-39 Sh.1 Single Line Meter & Relay Diagram - MCC Load tab - D114-G-D & D124-G-D, Generator Area, 440V, Unit 1 -

E-40 Sh.1 Single Line Meter & Relay Diagram - MCC Load tab - 114A-G-F & 124A-G-F, Generator Area MCC, 440V, Unit 1 -

E-40 Sh.2 Single Line Meter & Relay Diagram - MCC Load tab - 114A-G-F & 124A-G-F, Generator Area MCC, 440V, Unit 1 -

E-41 Sh.1 Single Line Meter & Relay Diagram - MCC Load tab - 114A-G-D & 124A-G-D, Generator Area MCC, 440V, Unit 1 -

E-41 Sh.2 Single Line Meter & Relay Diagram - MCC Load tab - 114A-G-D & 124A-G-D, Generator Area MCC, 440V, Unit 1 -

E-42 Sh.1 Single Line Meter & Relay Diagram - MCC Load tab - 114B-G-B & 124B-G-B, Generator Area MCC and 124B-R-C -

Reactor Area MCC, Unit 1 E-42 Sh.2 Single Line Meter & Relay Diagram - MCC Load tab - 114B-G-B & 124B-G-B, Generator Area MCC and 124B-R-C -

Reactor Area MCC, Unit 2 Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-3 REV. 16, SEPTEMBER 2012

LGS UFSAR Table 1.7-1 (Contd)

ELECTRICAL DRAWINGS Drawing Number Title Former UFSAR Figure Number E-43 Sh.1 Single Line Meter & Relay Diagram - MCC Load tab - 114C-T-F & 124C-T-F, Turbine Area MCC, 440V, Unit 1 -

E-43 Sh.2 Single Line Meter & Relay Diagram - MCC Load tab - 114C-T-F & 124C-T-F, Turbine Area MCC, 440V, Unit 2 -

E-44 Sh.1 Single Line Meter & Relay Diagram - MCC Load tab - 114C-T-G & 124C-T-G, Turbine Area MCC, 440V, Unit 1 -

E-44 Sh.2 Single Line Meter & Relay Diagram - MCC Load tab - 114C-T-G & 124C-T-G, Turbine Area MCC, 440V, Unit 1 -

E-44A Sh.1 Single Line Meter & Relay Diagram - MCC Load tab - 104C-T-G, Turbine Area MCC, 440V, Unit 1 -

E-45 Sh.1 Single Line Meter & Relay Diagram - MCC Load tab - 114C-R-A & 124C-R-A, Reactor Area MCC, 440V, Unit 1 -

E-46 Sh.1 Single Line Meter & Relay Diagram - MCC Load tab - 114D-T-B & 214D-T-B, Turbine Area MCC & 114D-V-G & -

214D-V-G Water Treatment Enclosure MCC Comm E-47 Sh.1 Single Line Meter & Relay Diagram - MCC Load tab - 134D-M-F, 234D-M-F & 234D-M-F2 Machine Shop Area MCC -

440V - Comm E-47 Sh.2 Single Line Meter & Relay Diagram - MCC Load tab - 134D-M-F, 234D-M-F Mach. Shop Area MCC 440V - Comm -

E-47 Sh.3 Single Line Meter & Relay Diagram - MCC Load tab - 134D-M-F, 234D-M-F1 & 234D-M-F2 Machine Shop Area MCC -

440V - Comm -

E-48 Sh.1 Single Line Meter & Relay Diagram - MCC Load tab - 114D-P-G, 214D-P-G Pump House MCC 440V - Comm -

E-48 Sh.2 Single Line Meter & Relay Diagram - MCC Load tab - 114D-P-G, 214D-P-G Pump House MCC 440V - Comm -

E-49 Sh.1 Single Line Meter & Relay Diagram - MCC Load tab - 114B-F-G, 214B-F-G Boiler House Area MCC 440V - Comm -

E-50 Sh.1 Single Line Meter & Relay Diagram - MCC Load tab - 114D-T-G, 214D-T-G Turb Area MCC & 124D-W-E & -

Sh.1 224D-W-E Radwaste Enclosure 440V - Comm E-51 Sh.1 Single Line Meter & Relay Diagram - MCC Load tab - 124D-W-K, 224D-W-K Radwaste Area MCC 440V - Comm -

E-52 Sh.1 Single Line Meter & Relay Diagram - MCC Load tab - 124D-W-J, 224D-W-J Radwaste Enclosure -

Sh.1 MCC 440V - Comm E-53 Sh.1 Single Line Meter & Relay Diagram - MCC Load tab - 124D-X-M Sewage Treatment Facility MCC, 124D-Y-N & -

Sh.1 224D-Y-N Schukill River Facility MCC 440V - Comm E-54 Sh.1 Single Line Meter & Relay Diagram MCC Load tab - D134-C-B & D144-C-B Control Enclosure Safeguard MCC - 440 V -

Sh.1 Comm E-55 Sh.1 Single Line Meter & Relay Diagram MCC Load tab - D114-R-G & D124-R-G - Reactor Area Safeguard MCC 440 V - Unit 1 -

E-55 Sh.2 Single Line Meter & Relay Diagram MCC Load tab - D114-R-G & D124-R-G - Reactor Area Safeguard MCC 440 V - Unit 1 -

E-56 Sh.1 Single Line Meter & Relay Diagram MCC Load tab - D114-D-G, D124-D-G, D134-D-G & D144-D-G - Diesel Generator Area -

Sh.1 Safeguard MCC 440 V - Unit 1 E-56 Sh.2 Single Line Meter & Relay Diagram MCC Load tab - D114-D-G, D124-D-G, D134-D-G & D144-D-G - -

Diesel Generator Area Safeguard MCC 440 V - Unit 1 E-57 Sh.1 Single Line Meter & Relay Diagram MCC Load Tab - D134-R-H & D144-R-H - Reactor Area Safeguard MCC 440 V - Unit 1 -

E-57 Sh.2 Single Line Meter & Relay Diagram MCC Load Tab - D134-R-H & D144-R-H - Reactor Area Safeguard MCC 440 V - Unit 1 -

Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-4 REV. 16, SEPTEMBER 2012

LGS UFSAR Table 1.7-1 (Contd)

ELECTRICAL DRAWINGS Drawing Number Title Former UFSAR Figure Number E-58 Sh.1 Single Line Meter & Relay Diagram MCC Load Tab - D114-R-C, D124-R-C, D134-R-E & D144-R-E - Reactor Area Safeguard -

MCC 440 V - Unit 1 E-58 Sh.2 Single Line Meter & Relay Diagram MCC Load Tab - D114-R-C, D124-R-C, D134-R-E & D144-R-E - Reactor Area Safeguard -

MCC 440 V - Unit 1 E-58 Sh.3 Single Line Meter & Relay Diagram MCC Load Tab - D114-R-C, D124-R-C, D134-R-E & D144-R-E - Reactor Area Safeguard -

MCC 440 V - Unit 1 E-58 Sh.4 Single Line Meter & Relay Diagram MCC Load tab - D114-R-C, D124-R-C, D134-R-E & D144-R-E - Reactor Area Safeguard -

MCC 440 V - Unit 1 E-59 Sh.1 Single Line Meter & Relay Diagram MCC Load tab - D214-D-G, D224-D-G, D234-D-G & D244-D-G - Diesel Generator Area -

Safeguard MCC 440 V - Unit 2 E-59 Sh.2 Single Line Meter & Relay Diagram MCC Load tab - D214-D-G, D224-D-G, D234-D-G & D244-D-G - Diesel Generator Area -

Safeguard MCC 440 V - Unit 2 E-60 Sh.1 Single Line Meter & Relay Diagram - MCC Load tab - 214A-G-F & 224A-G-F Generator Area MCC 440V - Unit 2 -

E-60 Sh.2 Single Line Meter & Relay Diagram - MCC Load tab - 214A-G-F & 224A-G-F Generator Area MCC 440V - Unit 2 -

E-61 Sh.1 Single Line Meter & Relay Diagram - MCC Load tab - 214A-G-D & 224A-G-D Generator Area MCC 440V - Unit 2 -

E-61 Sh.2 Single Line Meter & Relay Diagram - MCC Load tab - 214A-G-D & 224A-G-D Generator Area MCC 440V - Unit 2 -

E-62 Sh.1 Single Line Meter & Relay Diagram - MCC Load tab - 214B-G-B & 224B-G-B Generator Area MCC & 214B-R-C and -

224B-R-C Reactor Area MCC -440V - Unit 2 E-62 Sh.2 Single Line Meter & Relay Diagram - MCC Load tab - 214B-G-B & 224B-G-B Generator Area MCC & 214B-R-C and -

224B-R-C Reactor Area MCC -440V - Unit 2 E-63 Sh.1 Single Line Meter & Relay Diagram - MCC Load Tab - 214C-T-F & 224C-T-F Turbine Area MCC - 440V - Unit 2 -

E-63 Sh.2 Single Line Meter & Relay Diagram - MCC Load Tab - 214C-T-F & 224C-T-F Turbine Area MCC - 440V - Unit 2 -

E-64 Sh.1 Single Line Meter & Relay Diagram - MCC Load Tab - 214C-T-G & 224C-T-G Turbine Area MCC - 440V - Unit 2 -

E-64 Sh.2 Single Line Meter & Relay Diagram - MCC Load Tab - 214C-T-G & 224C-T-G Turbine Area MCC - 440V - Unit 2 -

E-64A Sh.1 Single Line Meter & Relay Diagram - MCC Load Tab - 204C-T-G Turbine Area MCC - 440V - Unit 2 -

E-65 Sh.1 Single Line Meter & Relay Diagram - MCC Load Tab - 214C-R-A & 224C-R-A Reactor Area MCC - 440V - Unit 2 -

E-66 Sh.1 Single Line Meter & Relay Diagram - MCC Load Tab - D214-G-D & D224-G-D Generator Area MCC - 440V - Unit 2 -

E-67 Sh.1 Single Line Meter & Relay Diagram MCC Load Tab - D214-R-G & D224-R-G - Reactor Area Safeguard MCC 440 V - Unit 2 -

E-67 Sh.2 Single Line Meter & Relay Diagram MCC Load Tab - D214-R-G & D224-R-G - Reactor Area Safeguard MCC 440 V - Unit 2 -

E-68 Sh.1 Single Line Meter & Relay Diagram MCC Load Tab - D214-R-A, D224-R-A, D234-R-E & D244-R-E - Reactor Area Safeguard -

MCC 440 V - Unit 2 E-68 Sh.2 Single Line Meter & Relay Diagram MCC Load Tab - D214-R-A, D224-R-A, D234-R-E & D244-R-E - Reactor Area Safeguard -

MCC 440 V - Unit 2 Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-5 REV. 16, SEPTEMBER 2012

LGS UFSAR Table 1.7-1 (Contd)

ELECTRICAL DRAWINGS Drawing Number Title Former UFSAR Figure Number E-69 Sh.1 Single Line Meter & Relay Diagram MCC Load Tab - D234-R-H & D244-R-H - Reactor Area Safeguard MCC 440 V - Unit 2 -

E-69 Sh.2 Single Line Meter & Relay Diagram MCC Load Tab - D234-R-H & D244-R-H - Reactor Area Safeguard MCC 440 V - Unit 2 -

E-70 Sh.1 Schematic Meter & Relay Diagram - 1 Generator, 11 Unit Auxiliary Transformer - Unit 1 -

E-70 Sh.2 Schematic Meter & Relay Diagram - 1 Generator, 11 Unit Auxiliary Transformer - Unit 1 -

E-72 Sh.1 Schematic Meter & Relay Diagram - 2 Generator, 21 Unit Auxiliary Transformer - Unit 2 -

E-72 Sh.2 Schematic Meter & Relay Diagram - 2 Generator, 21 Unit Auxiliary Transformer - Unit 2 -

E-74 Sh.1 Schematic Meter & Relay Diagram - 13.2KV Unit Auxiliary Power System - Unit 1 -

E-75 Sh.1 Schematic Meter & Relay Diagram - 13.2KV Unit Auxiliary Power System - Unit 2 -

E-76 Sh.1 Schematic Meter & Relay Diagram - 13.2KV Station Auxiliary Power System - Unit 1 -

E-77 Sh.1 Schematic Meter & Relay Diagram - 13.2KV Station Auxiliary Power System - Unit 2 -

E-78 Sh.1 Schematic Meter & Relay Diagram - 1 Transformer - Unit 1 -

E-79 Sh.1 Schematic Meter & Relay Diagram - 2 Transformer - Unit 2 -

E-80 Sh.1 Schematic Meter & Relay Diagram - D11 & D12 Safeguard Buses, 4 kV - Unit 1 -

E-81 Sh.1 Schematic Meter & Relay Diagram - D13 & D14 Safeguard Buses, 4 kV - Unit 1 -

E-82 Sh.1 Schematic Meter & Relay Diagram - D21 & D22 Safeguard Buses, 4 kV - Unit 2 -

E-83 Sh.1 Schematic Meter & Relay Diagram - D23 & D24 Safeguard Buses, 4 kV - Unit 2 -

E-84 Sh.1 Schematic Meter & Relay Diagram - 114A, 114B, 114C, 114D, 124A, 124B, 124C, 124D, 214D, 224D, 134D, 234D -

E-85 Sh.1 Schematic Meter & Relay Diagram - Diesel Generators, 4 kV - Units 1 & 2 -

E-85 Sh.2 Schematic Meter & Relay Diagram - Diesel Generators, 4 kV - Units 1 & 2 -

E-87 Sh.1 Schematic Meter & Relay Diagram - 214A, 214B, 214C, 224A, 224B & 224C Load Centers 440 V - Unit 2 -

E-88 Sh.1 Schematic Meter & Relay Diagram - D114, D214, D314, D414 Safeguard Load Centers 440 V - Unit 1 -

E-89 Sh.1 Schematic Meter & Relay Diagram - D124, D224, D324, D424 Safeguard Load Centers 440 V - Unit 2 -

E-92 Sh.1 Schematic Meter & Relay Diagram - 125/250 V dc System - Units 1 & 2 -

E-92 Sh.2 Schematic Meter & Relay Diagram - 125/250 V dc System - Units 1 & 2 -

E-92 Sh.3 Schematic Meter & Relay Diagram - 125/250 V dc System - Units 1 & 2 -

E-92 Sh.4 Schematic Meter & Relay Diagram - 125V/250V DC System Units 1 & 2 -

E-97 Sh.1 Schematic Meter & Relay Diagram - 2.3 KV Plant Services Power System - Comm -

SCHEMATIC BLOCK DIAGRAM - REACTOR SYSTEM E-100 Sh.1 Schematic Block Diagram - Steam Leak Detection System - Units 1 & 2 -

E-101 Sh.1 Schematic Block Diagram - Nuclear Steam Supply Shutoff System - Units 1 & 2 -

E-101 Sh.2 Schematic Block Diagram - Nuclear Steam Supply Shutoff System - Units 1 & 2 -

E-101 Sh.3 Schematic Block Diagram - Nuclear Steam Supply Shutoff System - Units 1 & 2 -

E-102 Sh.1 Schematic Block Diagram - RHR System - Units 1 & 2 -

Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-6 REV. 16, SEPTEMBER 2012

LGS UFSAR Table 1.7-1 (Contd)

ELECTRICAL DRAWINGS Drawing Number Title Former UFSAR Figure Number E-102 Sh.2 Schematic Block Diagram - RHR System - Units 1 & 2 -

E-102 Sh.3 Schematic Block Diagram - RHR System - Units 1 & 2 -

E-103 Sh.1 Schematic Block Diagram - Core Spray System - Units 1 & 2 -

E-104 Sh.1 Schematic Block Diagram - HPCI System - Units 1 & 2 -

E-104 Sh.2 Schematic Block Diagram - HPCI System - Units 1 & 2 -

E-105 Sh.1 Schematic Block Diagram - RCIC System - Units 1 & 2 -

E-105 Sh.2 Schematic Block Diagram - RCIC System - Units 1 & 2 -

E-106 Sh.1 Schematic Block Diagram - Process Radiation Monitor System - Units 1 & 2 & Comm -

E-107 Sh.1 Schematic Block Diagram - Reactor Water Cleanup System - Units 1 & 2 -

E-109 Sh.1 Schematic Block Diagram - Nuclear Boiler Process Instrumentation System - Units 1 & 2 -

E-110 Sh.1 Schematic Block Diagram - Auto-depressurization and Standby Liquid Control Systems - Units 1 & 2 -

E-113 Sh.1 Schematic Block Diagram - MSIV Leakage Control System - Units 1 & 2 -

E-120 Sh.1 Schematic Block Diagram - Power Range Neutron Monitoring System - Units 1 & 2 -

E-120 Sh.2 Schematic Block Diagram - Power Range Neutron Monitoring System - Units 1 & 2 -

E-126 Sh.1 Schematic Block Diagram - Startup Range Neutron Monitoring System - Units 1 & 2 -

E-129 Sh.1 Schematic Block Diagram - Reactor Protection System - Units 1 & 2 -

E-129 Sh.2 Schematic Block Diagram - Reactor Protection System - Units 1 & 2 -

E-129 Sh.3 Schematic Block Diagram - Reactor Protection System - Units 1 & 2 -

SCHEMATIC DIAGRAMS - AUXILIARY ELECTRICAL SYSTEM -

E-156 Sh.1 Schematic Diagram - 10 & 20 Auxiliary Buses - 101 & 201 Safeguard Transformer Breakers, 13.2 kV - Units 1 & 2 -

E-159 Sh.1 Schematic Diagram - Load Center Swgr-MCC Feeder Breakers 440 V - 1 and 2 Units -

E-159 Sh.2 Schematic Diagram - Load Center Swgr-MCC Feeder Breakers 440 V - 1 and 2 Units -

E-159 Sh.3 Schematic Diagram - Load Center Swgr-MCC Feeder Breakers 440 V - 1 and 2 Units -

E-160 Sh.1 Schematic Diagram - Safeguard Buses - 101 & 201 Safeguard Bus Feeder Breakers 4 kV - Units 1 & 2 -

E-160 Sh.2 Schematic Diagram - Safeguard Buses - 101 & 201 Safeguard Bus Feeder Breakers 4 kV - Units 1 & 2 -

E-160 Sh.3 Schematic Diagram - Safeguard Buses - 101 & 201 Safeguard Bus Feeder Breakers 4 kV - Units 1 & 2 -

E-160 Sh.4 Schematic Diagram - Safeguard Buses - 101 & 201 Safeguard Bus Feeder Breakers 4 kV - Units 1 & 2 -

E-162 Sh.1 Schematic Diagram - Safeguard Buses - D144 & D244 Safeguard Load Control Transformer Breakers, 4 kV - Units 1 & 2 -

E-163 Sh.1 Schematic Diagram - Safeguard Buses - D114, D124, D134, D214, D224 & D234 Safeguard Load Control -

Transformer Bkrs, 4kV Units 1 & 2 E-164 Sh.1 Schematic Diagram - Safeguard Buses - D11, D12, D13, D14, D21, D22, D23 & D24 Generator Bkrs 4 kV - Units 1 & 2 -

E-164 Sh.2 Schematic Diagram - Safeguard Buses - D11, D12, D13, D14, D21, D22, D23 & D24 Generator Bkrs 4 kV - Units 1 & 2 -

E-164 Sh.3 Schematic Diagram - Safeguard Buses - D11, D12, D13, D14, D21, D22, D23 & D24 Generator Bkrs 4 kV - Units 1 & 2 -

Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-7 REV. 16, SEPTEMBER 2012

LGS UFSAR Table 1.7-1 (Contd)

ELECTRICAL DRAWINGS Drawing Number Title Former UFSAR Figure Number E-164 Sh.4 Schematic Diagram - Safeguard Buses - D11, D12, D13, D14, D21, D22, D23 & D24 Generator Bkrs 4 kV - Units 1 & 2 -

E-168 Sh.1 Schematic Diagram - Safeguard Buses - D11, D12, D13, D14, D21, D22, D23, D24 Protective Relaying 4 kV - Units 1 & 2 -

E-169 Sh.1 Schematic Diagram - Diesel Generator Protective Relaying - 4 kV - Units 1 & 2 -

E-171 Sh.1 Schematic Diagram - 101 & 201 Safeguard Transformer Protective Relaying - Units 1 & 2 -

E-185 Sh.1 Schematic Diagram - MCC Breaker Shunt Trip Coil Circuits & Auxiliary Control - Units 1 & 2 & Comm -

E-185 Sh.2 Schematic Diagram - MCC Breaker Shunt Trip Coil Circuits & Auxiliary Control - Units 1 & 2 & Comm -

E-277 Sh.1 Schematic Diagram - Main Steam to RFPT & Radwaste Recombiner Free Heater to Hotwell Steam Spargers & to Steam -

Seal Evaporators Shutoff MOVs - Units 1 & 2 E-321 Sh.1 Schematic Diagram - Emergency Service Water Pumps - Comm -

E-321 Sh.2 Schematic Diagram - Emergency Service Water Pumps - Comm -

E-321 Sh.3 Schematic Diagram - Emergency Service Water Pumps - Comm -

E-321 Sh.4 Schematic Diagram - Emergency Service Water Pumps - Comm -

E-321 Sh.5 Schematic Diagram - Emergency Service Water Pumps - Comm -

E-321 Sh.6 Schematic Diagram - Emergency Service Water Pumps - Comm -

E-322 Sh.1 Schematic Diagram - Diesel Generator ESW Inlet and Outlet MOVs - Units 1 & 2 -

E-322 Sh.2 Schematic Diagram - Diesel Generator ESW Inlet and Outlet MOVs - Units 1 & 2 -

E-323 Sh.1 Schematic Diagram - Turbine Enclosure Cooling Water Heat Exchanger ESW MOVs - Units 1 & 2 -

E-324 Sh.1 Schematic Diagram - ESW Discharge to RHRSW MOVs - Comm -

E-324 Sh.2 Schematic Diagram - ESW Discharge to RHRSW MOVs - Comm -

E-324 Sh.3 Schematic Diagram - ESW Discharge to RHRSW MOVs - Comm -

E-325 Sh.1 Schematic Diagram - Cooling Water Shutoff Valves to Service Water & ESW - Units 1 & 2 -

E-325 Sh.2 Schematic Diagram - Cooling Water Shutoff Valves to Service Water & ESW - Units 1 & 2 -

E-325 Sh.3 Schematic Diagram - Cooling Water Shutoff Valves to Service Water & ESW - Units 1 & 2 -

E-325 Sh.4 Schematic Diagram - Cooling Water Shutoff Valves to Service Water & ESW - Units 1 & 2 -

E-326 Sh.1 Schematic Diagram - ESW Shutoff Valves to Reactor Enclosure Cooling Water Heat Exchangers - Units 1 & 2 -

E-327 Sh.1 Schematic Diagram - Control Room Chiller Cooling Water Shutoff Valves & ESW Valves Auxiliary Ckt - Comm -

E-327 Sh.2 Schematic Diagram - Control Room Chiller Cooling Water Shutoff Valves & ESW Valves Auxiliary Ckt - Comm -

E-327 Sh.3 Schematic Diagram - Control Room Chiller Cooling Water Shutoff Valves & ESW Valves Auxiliary Ckt - Comm -

E-328 Sh.1 Schematic Diagram - Reactor Enclosure Cooling Water Heat Exchangers Shutoff Valves to ESW - Units 1 & 2 -

E-343 Sh.1 Schematic Diagram - Containment Isolation Signal Bypass Permissive - Units 1 & 2 -

E-343 Sh.2 Schematic Diagram - Containment Isolation Signal Bypass Permissive - Units 1 & 2 -

E-350 Sh.1 Schematic Diagram - Core Spray Pumps - Units 1 & 2 -

E-350 Sh.2 Schematic Diagram - Core Spray Pumps - Units 1 & 2 -

Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-8 REV. 16, SEPTEMBER 2012

LGS UFSAR Table 1.7-1 (Contd)

ELECTRICAL DRAWINGS Drawing Number Title Former UFSAR Figure Number E-351 Sh.1 Schematic Diagram - Suppression Pool Water Filter Pump Isolation MOVs - Units 1 & 2 -

E-352 Sh.1 Schematic Diagram - Control Rod Drive Water Pumps 1 & 2 Units -

E-352 Sh.2 Schematic Diagram - Control Rod Drive Water Pumps 1 & 2 Units -

E-353 Sh.1 Schematic Diagram - RHR Vacuum Breaker to Suppression Pool Isolation MOVs - Units 1 & 2 -

E-354 Sh.1 Schematic Diagram - Drywell & Suppression Pool Instrument Line Shutoff Valve - Units 1 & 2 -

E-354 Sh.2 Schematic Diagram - Drywell & Suppression Pool Instrument Line Shutoff Valves - Units 1 & 2 -

E-354 Sh.3 Schematic Diagram - Drywell & Suppression Pool Instrument Line Shutoff Valves - Units 1 & 2 -

E-354 Sh.4 Schematic Diagram - Drywell & Suppression Pool Instrument Line Shutoff Valves - Units 1 & 2 -

E-355 Sh.1 Schematic Diagram - BOP Main Steam Line Leak Detection - Units 1 & 2 -

E-357 Sh.1 Schematic Diagram - Instrument Gas Compressor Suction Line Inboard Isolation MOV - Units 1 & 2 -

E-358 Sh.1 Schematic Diagram - Reactor FW Startup Flushing & ECCS Pumps Suct from Cond Storage Tank MOVs - Units 1 & 2 -

E-358 Sh.2 Schematic Diagram - Reactor FW Startup Flushing & ECCS Pumps Suct from Cond Storage Tank MOVs - Units 1 & 2 -

E-359 Sh.1 Schematic Diagram - Spray Pond Makeup Line MOV - Comm -

E-360 Sh.1 Schematic Diagram - RHR Pumps - Units 1 & 2 -

E-360 Sh.2 Schematic Diagram - RHR Pumps - Units 1 & 2 -

E-360 Sh.3 Schematic Diagram - RHR Pumps - Units 1 & 2 -

E-361 Sh.1 Schematic Diagram - RHR Service Water Pumps - Comm -

E-361 Sh.2 Schematic Diagram - RHR Service Water Pumps - Comm -

E-361 Sh.3 Schematic Diagram - RHR Service Water Pumps - Comm -

E-362 Sh.1 Schematic Diagram - Spray Pond Header Cross-tie & Cooling Water Return Cross-tie MOVs - Comm -

E-362 Sh.2 Schematic Diagram - Spray Pond Header Cross-tie & Cooling Water Return Cross-tie MOVs - Comm -

E-363 Sh.1 Schematic Diagram - TBCW Htx Cooling Water Return to RHR Service Water MOVs - 1 & 2 Units -

E-364 Sh.1 Schematic Diagram - RHR Drain to Radwaste Inboard Isolation Valve - Units 1 & 2 -

E-365 Sh.1 Schematic Diagram - Primary Containment Instrumentation Gas Outboard Isolation Valves - Units 1 & 2 -

E-366 Sh.1 Schematic Diagram - RHR Full Flow Test Line Shutoff & Min Flow Bypass MOVs -

E-366 Sh.2 Schematic Diagram - RHR Full Flow Test Line Shutoff & Min Flow Bypass MOVs -

E-371 Sh.1 Schematic Diagram - RHR Heat Exchanger Tube Side Inlet MOVs - Units 1 & 2 -

E-371 Sh.2 Schematic Diagram - RHR Heat Exchanger Tube Side Inlet MOVs - Units 1 & 2 -

E-372 Sh.1 Schematic Diagram - RHR Heat Exchanger Tube Side Outlet MOVs - Units 1 & 2 -

E-372 Sh.2 Schematic Diagram - RHR Heat Exchanger Tube Side Outlet MOVs - Units 1 & 2 -

E-373 Sh.1 Schematic Diagram - RHR SW/ESW to Cooling Tower Shutoff MOVs - Units 1 & 2 -

E-373 Sh.2 Schematic Diagram - RHR SW/ESW to Cooling Tower Shutoff MOVs - Units 1 & 2 -

E-374 Sh.1 Schematic Diagram - Cooling Tower Return to Spray Pond Shutoff MOVs - Units 1 & 2 -

E-374 Sh.2 Schematic Diagram - Cooling Tower Return to Spray Pond Shutoff MOVs - Units 1 & 2 -

Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-9 REV. 16, SEPTEMBER 2012

LGS UFSAR Table 1.7-1 (Contd)

ELECTRICAL DRAWINGS Drawing Number Title Former UFSAR Figure Number E-375 Sh.1 Schematic Diagram - Spray Pond Spray Nozzle Inlet MOVs - Comm -

E-375 Sh.2 Schematic Diagram - Spray Pond Spray Nozzle Inlet MOVs - Comm -

E-375 Sh.3 Schematic Diagram - Spray Pond Spray Nozzle Inlet MOVs - Comm -

E-376 Sh.1 Schematic Diagram - Spray Pond Spray Nozzle Bypass MOVs - Comm -

E-376 Sh.2 Schematic Diagram - Spray Pond Spray Nozzle Bypass MOVs - Comm -

E-377 Sh.1 Schematic Diagram - Spray Pond Wetwell Inlet Motor-Operated Gates - Comm -

E-377 Sh.2 Schematic Diagram - Spray Pond Wetwell Inlet Motor-Operated Gates - Comm -

E-378 Sh.1 Schematic Diagram - Spray Pond Wetwell Cross-tie Motor-Operated Gate - Comm -

E-380 Sh.1 Schematic Diagram - HPCI Steam to RHR Heat Exchanger Shutoff Valves Bypass MOVs - Units 1 & 2 -

E-380 Sh.2 Schematic Diagram - HPCI Steam to RHR Heat Exchanger Shutoff Valves Bypass MOVs - Units 1 & 2 -

E-382 Sh.1 Schematic Diagram - Drywell and Suppression Pool Purge Line Outboard Isolation Valves - Units 1 & 2 -

E-382 Sh.2 Schematic Diagram - Drywell and Suppression Pool Purge Line Outboard Isolation Valves - Units 1 & 2 -

E-383 Sh.1 Schematic Diagram - Drywell Nitrogen Makeup Line Isolation Valve - Units 1 & 2 -

E-384 Sh.1 Schematic Diagram - Drywell Nitrogen Purge Line Control Valve and Isolation Valves - Units 1 & 2 -

E-384 Sh.2 Schematic Diagram - Drywell Nitrogen Purge Line Control Valve and Isolation Valves - Units 1 & 2 -

E-385 Sh.1 Schematic Diagram - Containment Atmosphere Sampling System Isolation Valves - Units 1 & 2 -

E-385 Sh.2 Schematic Diagram - Containment Atmosphere Sampling System Isolation Valves - Units 1 & 2 -

E-385 Sh.3 Schematic Diagram - Containment Atmosphere Sampling System Isolation Valves - Units 1 & 2 -

E-386 Sh.1 Schematic Diagram - Hydrogen-Oxygen Analyzer Package Pumps & Sample Select Valves - Units 1 & 2 -

E-386 Sh.2 Schematic Diagram - Hydrogen-Oxygen Analyzer Package Pumps & Sample Select Valves - Units 1 & 2 -

E-388 Sh.1 Schematic Diagram - Drywell & Supp Pool Lines to Containment Hydrogen Recombiner Outboard Isolation Valves - Units 1 & 2 -

E-406 Sh.1 Schematic Diagram - Drywell Floor Drain Sump & Drywell Equipment Drain Sump Drain Isolation Valves - Units 1 & 2 -

SCHEMATIC DIAGRAMS - HEATING & VENTILATION SYSTEM E-453 Sh.1 Schematic Diagram - Turbine Enclosure Equipment Compartment Exhaust Fans - Units 1 & 2 -

E-453 Sh.2 Schematic Diagram - Turbine Enclosure Equipment Compartment Exhaust Fans - Units 1 & 2 -

E-462 Sh.1 Schematic Diagram - Control Room Chilled Water Circulation Pump - Comm -

E-463 Sh.1 Schematic Diagram - Control Room Chillers, Oil Pumps & Pumpout Compressor - Comm -

E-463 Sh.2 Schematic Diagram - Control Room Chillers, Oil Pumps & Pumpout Compressor - Comm -

E-463 Sh.3 Schematic Diagram - Control Room Chillers, Oil Pumps & Pumpout Compressor - Comm -

E-463 Sh.4 Schematic Diagram - Control Room Chillers, Oil Pumps & Pumpout Compressor - Comm -

E-464 Sh.1 Schematic Diagram - Drywell Chillers, Oil Pumps & Pumpout Compressors - Units 1 & 2 -

E-464 Sh.2 Schematic Diagram - Drywell Chillers, Oil Pumps & Pumpout Compressors - Units 1 & 2 -

E-464 Sh.3 Schematic Diagram - Drywell Chillers, Oil Pumps & Pumpout Compressors - Units 1 & 2 -

Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-10 REV. 16, SEPTEMBER 2012

LGS UFSAR Table 1.7-1 (Contd)

ELECTRICAL DRAWINGS Drawing Number Title Former UFSAR Figure Number E-465 Sh.1 Schematic Diagram - Drywell Chilled Cooling Water Supply & Return MOVs - Units 1 & 2 -

E-465 Sh.2 Schematic Diagram - Drywell Chilled Cooling Water Supply & Return MOVs - Units 1 & 2 -

E-466 Sh.1 Schematic Diagram - Drywell Cooling Water Supply & Return Isolation MOVs - Units 1 & 2 -

E-466 Sh.2 Schematic Diagram - Drywell Cooling Water Supply & Return Isolation MOVs - Units 1 & 2 -

E-470 Sh.1 Schematic Diagram - Reactor Enclosure Air Recirculation Fan & Auxiliary Control - Units 1 & 2 -

E-470 Sh.2 Schematic Diagram - Reactor Enclosure Air Recirculation Fan & Auxiliary Control - Units 1 & 2 -

E-470 Sh.3 Schematic Diagram - Reactor Enclosure Air Recirculation Fan & Auxiliary Control - Units 1 & 2 -

E-470 Sh.4 Schematic Diagram - Reactor Enclosure Air Recirculation Fan & Auxiliary Control - Units 1 & 2 -

E-471 Sh.1 Schematic Diagram - RCIC, HPCI, RHR and Core Spray Room Unit Coolers - Units 1 & 2 -

E-474 Sh.1 Schematic Diagram - Reactor Enclosure & Refueling Floor Isolation System - Units 1 & 2 -

E-474 Sh.2 Schematic Diagram - Reactor Enclosure & Refueling Floor Isolation System - Units 1 & 2 -

E-476 Sh.1 Schematic Diagram - Drywell Area Unit Coolers - Units 1 & 2 -

E-476 Sh.2 Schematic Diagram - Drywell Area Unit Coolers - Units 1 & 2 -

E-482 Sh.1 Schematic Diagram - Standby Gas Treatment System Charcoal Filter Valves - Comm -

E-482 Sh.2 Schematic Diagram - Standby Gas Treatment System Charcoal Filter Valves - Comm -

E-482 Sh.3 Schematic Diagram - Standby Gas Treatment System Charcoal Filter Valves - Comm -

E-483 Sh.1 Schematic Diagram - Standby Gas Treatment System Exhaust Fans - Comm -

E-483 Sh.2 Schematic Diagram - Standby Gas Treatment System Exhaust Fans - Comm -

E-484 Sh.1 Schematic Diagram - Heater - Comm -

E-485 Sh.1 Schematic Diagram - Standby Gas Treatment System Room Unit Coolers - Comm -

E-485 Sh.2 Schematic Diagram - Standby Gas Treatment System Room Unit Coolers - Comm -

E-486 Sh.1 Schematic Diagram - Drywell Purge Exhaust Fans Isolation Valves - Comm -

E-488 Sh.1 Schematic Diagram - Auxiliary Equipment Room Supply Air Fans, Humidifiers & Cooling Coil Valves - Comm -

E-488 Sh.2 Schematic Diagram - Auxiliary Equipment Room Supply Air Fans, Humidifiers & Cooling Coil Valves - Comm -

E-488 Sh.3 Schematic Diagram - Auxiliary Equipment Room Supply Air Fans, Humidifiers & Cooling Coil Valves - Comm -

E-488 Sh.4 Schematic Diagram - Auxiliary Equipment Room Supply Air Fans, Humidifiers & Cooling Coil Valves - Comm -

E-489 Sh.1 Schematic Diagram - Control Room & Auxiliary Equipment Room Return Air Fans & Dampers - Units 1 & 2 -

E-489 Sh.2 Schematic Diagram - Control Room & Auxiliary Equipment Room Return Air Fans & Dampers - Units 1 & 2 -

E-489 Sh.3 Schematic Diagram - Control Room & Auxiliary Equipment Room Return Air Fans & Dampers - Units 1 & 2 -

E-490 Sh.1 Schematic Diagram - Diesel Generator Ventilation Air Exhaust Fans & Air Control - Units 1 & 2 -

E-490 Sh.2 Schematic Diagram - Diesel Generator Ventilation Air Exhaust Fans & Air Control - Units 1 & 2 -

E-491 Sh.1 Schematic Diagram - Spray Pond Pump Structure Fan Heater and Auxiliary Control - Comm -

E-491 Sh.2 Schematic Diagram - Spray Pond Pump Structure Fan Heater and Auxiliary Control - Comm -

E-491 Sh.3 Schematic Diagram - Spray Pond Pump Structure Fan Heater and Auxiliary Control - Comm -

Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-11 REV. 16, SEPTEMBER 2012

LGS UFSAR Table 1.7-1 (Contd)

ELECTRICAL DRAWINGS Drawing Number Title Former UFSAR Figure Number E-495 Sh.1 Schematic Diagram - Control Room Emergency Fresh Air Supply Fans and Intake Heaters - Comm -

E-495 Sh.2 Schematic Diagram - Control Room Emergency Fresh Air Supply Fans and Intake Heaters - Comm -

E-495 Sh.3 Schematic Diagram - Control Room Emergency Fresh Air Supply Fans and Intake Heaters - Comm -

E-496 Sh.1 Schematic Diagram - Control Room Isolation System & Valves - Comm -

E-496 Sh.2 Schematic Diagram - Control Room Isolation System & Valves - Comm -

E-496 Sh.3 Schematic Diagram - Control Room Isolation System & Valves - Comm -

E-498 Sh.1 Schematic Diagram - Control Enclosure Purge System - Comm -

E-508 Sh.1 Schematic Diagram - Reactor Enclosure Steam Flooding Dampers - Units 1 & 2 -

E-508 Sh.2 Schematic Diagram - Reactor Enclosure Steam Flooding Dampers - Units 1 & 2 -

E-508 Sh.3 Schematic Diagram - Reactor Enclosure Steam Flooding Dampers - Units 1 & 2 -

E-509 Sh.1 Schematic Diagram - Control Structure Steam Flooding Dampers - Units 1 & 2 -

E-509 Sh.2 Schematic Diagram - Control Structure Steam Flooding Dampers - Units 1 & 2 -

E-509 Sh.3 Schematic Diagram - Control Structure Steam Flooding Dampers - Units 1 & 2 -

E-509 Sh.4 Schematic Diagram - Control Structure Steam Flooding Dampers - Units 1 & 2 -

E-509 Sh.5 Schematic Diagram - Control Structure Steam Flooding Dampers - 1 7 2 Units -

E-521 Sh.1 Schematic Diagram - Control Enclosure Emergency Swgr & Battery Rooms Supply Air Fans & Dampers - Comm -

E-521 Sh.2 Schematic Diagram - Control Enclosure Emergency Swgr & Battery Rooms Supply Air Fans & Dampers - Comm -

E-522 Sh.1 Schematic Diagram - Control Enclosure - Battery Room Exhaust & Recirculation Dampers - Comm -

SCHEMATIC DIAGRAMS MISCELLANEOUS SYSTEMS E-560 Sh.1 Schematic Diagram - Diesel Generator Diesel Oil Transfer Pumps - Units 1 & 2 -

E-565 Sh.1 Schematic Diagram - Turbine Enclosure & Reactor Enclosure Cooling Water Pumps - Units 1 & 2 -

E-585 Sh.1 Schematic Diagram - Containment Hydrogen Recombiner System -

E-585 Sh.2 Schematic Diagram - Containment Hydrogen Recombiner System -

E-585 Sh.3 Schematic Diagram - Containment Hydrogen Recombiner System -

E-591 Sh.1 Schematic Diagram - Diesel Generator Control & Auxiliaries - Units 1 & 2 -

E-591 Sh.2 Schematic Diagram - Diesel Generator Control & Auxiliaries - Units 1 & 2 -

E-591 Sh.3 Schematic Diagram - Diesel Generator Control & Auxiliaries - Units 1 & 2 -

E-591 Sh.4 Schematic Diagram - Diesel Generator Control & Auxiliaries - Units 1 & 2 -

E-591 Sh.5 Schematic Diagram - Diesel Generator Control & Auxiliaries - Units 1 & 2 -

E-591 Sh.6 Schematic Diagram - Diesel Generator Control & Auxiliaries - Units 1 & 2 -

E-591 Sh.7 Schematic Diagram - Diesel Generator Control & Auxiliaries - Units 1 & 2 -

Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-12 REV. 16, SEPTEMBER 2012

LGS UFSAR Table 1.7-1 (Contd)

ELECTRICAL DRAWINGS Drawing Number Title Former UFSAR Figure Number E-648 Sh.1 Schematic Diagram - Safety System Bypass/Inop Status Indication Circuits - Units 1 & 2 -

E-648 Sh.2 Schematic Diagram - Safety System Bypass/Inop Status Indication Circuits - Units 1 & 2 -

E-648 Sh.3 Schematic Diagram - Safety System Bypass/Inop Status Indication Circuits - Units 1 & 2 -

E-649 Sh.1 Schematic Diagram - Safety System Annunciator Auxiliary Relay Circuits - Units 1 & 2 -

E-649 Sh.2 Schematic Diagram - Safety System Annunciator Auxiliary Relay Circuits - Units 1 & 2 -

E-649 Sh.3 Schematic Diagram - Safety System Annunciator Auxiliary Relay Circuits - Units 1 & 2 -

E-649 Sh.4 Schematic Diagram - Safety System Annunciator Auxiliary Relay Circuits - Units 1 & 2 -

E-649 Sh.5 Schematic Diagram - Safety System Annunciator Auxiliary Relay Circuits - Units 1 & 2 -

E-649 Sh.6 Schematic Diagram - Safety System Annunciator Auxiliary Relay Circuits - Units 1 & 2 -

E-649 Sh.7 Schematic Diagram - Safety System Annunciator Auxiliary Relay Circuits - Units 1 & 2 -

E-649 Sh.8 Schematic Diagram - Safety System Annunciator Auxiliary Relay Circuits - Units 1 & 2 -

E-649 Sh.9 Schematic Diagram - Safety System Annunciator Auxiliary Relay Circuits - Units 1 & 2 -

E-649 Sh.10 Schematic Diagram - Safety System Annunciator Auxiliary Relay Circuits - Units 1 & 2 -

E-686 Sh.1 Schematic Diagram - HVAC Miscellaneous Safeguard Instrumentation - Units 1 & 2 & Comm -

E-686 Sh.2 Schematic Diagram - HVAC Miscellaneous Safeguard Instrumentation - Units 1 & 2 & Comm -

E-686 Sh.3 Schematic Diagram - HVAC Miscellaneous Safeguard Instrumentation - Units 1 & 2 & Comm -

E-686 Sh.4 Schematic Diagram - HVAC Miscellaneous Safeguard Instrumentation - Units 1 & 2 & Comm -

E-686 Sh.5 Schematic Diagram - HVAC Miscellaneous Safeguard Instrumentation - Units 1 & 2 & Comm -

E-686 Sh.6 Schematic Diagram - HVAC Miscellaneous Safeguard Instrumentation - Units 1 & 2 & Comm -

E-686 Sh.7 Schematic Diagram - HVAC Miscellaneous Safeguard Instrumentation - Units 1 & 2 & Comm -

E-686 Sh.8 Schematic Diagram - HVAC Miscellaneous Safeguard Instrumentation - Units 1 & 2 & Comm -

E-686 Sh.9 Schematic Diagram - HVAC Miscellaneous Safeguard Instrumentation - Units 1 & 2 & Comm -

E-686 Sh.10 Schematic Diagram - HVAC Miscellaneous Safeguard Instrumentation - Units 1 & 2 & Comm -

E-686 Sh.11 Schematic Diagram - HVAC Miscellaneous Safeguard Instrumentation - Units 1 & 2 & Comm -

E-686 Sh.12 Schematic Diagram - HVAC Miscellaneous Safeguard Instrumentation - Units 1 & 2 & Comm -

E-686 Sh.13 Schematic Diagram - HVAC Miscellaneous Safeguard Instrumentation - Units 1 & 2 & Comm -

E-686 Sh.14 Schematic Diagram - HVAC Miscellaneous Safeguard Instrumentation - Units 1 & 2 & Comm -

E-686 Sh.15 Schematic Diagram - HVAC Miscellaneous Safeguard Instrumentation - Units 1 & 2 & Comm -

E-688 Sh.1 Schematic Diagram - Miscellaneous Systems Instrumentation - Units 1 & 2 -

E-688 Sh.2 Schematic Diagram - Miscellaneous Systems Instrumentation - Units 1 & 2 -

ELECTRICAL LAYOUT DRAWINGS E-1001 Sh.1 Electric Duct Layout - Site Plan -

E-1002 Sh.1 Electrical Duct Layout Profiles, Sections & Details - North Area -

Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-13 REV. 16, SEPTEMBER 2012

LGS UFSAR Table 1.7-1 (Contd)

ELECTRICAL DRAWINGS Drawing Number Title Former UFSAR Figure Number E-1003 Sh.1 Electrical Duct Layout Profiles, Sections & Details - East Area -

E-1004 Sh.1 Electrical Duct Layout Profiles, Sections & Details - Southeast Area -

E-1005 Sh.1 Electrical Duct Layout Profiles, Sections & Details - Southwest Area -

E-1006 Sh.1 Electrical Duct Layout Profiles, Sections & Details - West Area Control System -

E-1007 Sh.1 Electrical Duct Layout Profiles, Sections & Details - West Area Startup & Pump Structural Ducts -

E-1008 Sh.1 Electrical Duct Layout - Spray Pond Area - Plan -

E-1009 Sh.1 Electrical Duct Layout Profiles, Sections & Details - Spray Pond Area -

E-1010 Sh.1 Embedded Conduit - Turbine Enclosure Unit 1 - Below el 217'-0" -

E-1011 Sh.1 Embedded Conduit - Turbine Enclosure Unit 2 - Below el 217'-0" -

E-1013 Sh.1 Embedded Conduit - Reactor Enclosure Unit 1 - Below el 177'-0" -

E-1014 Sh.1 Embedded Conduit - Reactor Enclosure Unit 2 - Below el 177'-0" -

E-1015 Sh.1 Embedded Conduit - Reactor Enclosure Unit 1 - Below el 217'-0" -

E-1016 Sh.1 Embedded Conduit - Reactor Enclosure Unit 2 - Below el 217'-0" -

E-1034 Sh.1 Raceway Layout - Spray Pond Pump Structure -

E-1036 Sh.1 Electrical Details - Spray Pond Pump Structure -

E-1055 Sh.1 Lighting - Cable Spreading Room - Units 1 & 2 Above el 254'-0" -

E-1056 Sh.1 Lighting - Cable Spreading Room - Units 1 & 2 Above el 254'-0" -

E-1056 Sh.2 Lighting - Cable Spreading Room - Units 1 & 2 Above el 254'-0" -

E-1060 Sh.1 Lighting - Reactor Enclosure - Unit 1 Above el 177'-0" -

E-1061 Sh.1 Lighting - Reactor Enclosure - Unit 1 Above el 201'-0" -

E-1062 Sh.1 Lighting - Reactor Enclosure - Unit 1 Above el 217'-0" -

E-1063 Sh.1 Lighting - Reactor Enclosure - Unit 1 Above el 253'-0" -

E-1064 Sh.1 Lighting - Reactor Enclosure - Unit 1 Above el 283'-0" -

E-1065 Sh.1 Lighting - Reactor Enclosure - Unit 1 Above el 313'-0" -

E-1066 Sh.1 Lighting - Reactor Enclosure - Unit 1 Above el 352'-0" -

E-1066 Sh.2 Lighting - Reactor Enclosure - Unit 1 Above el 411'-9" -

E-1067 Sh.1 Lighting - Diesel Generator Enclosure - Unit 1 Above el 217'-0" -

E-1075 Sh.1 Lighting - Control Room - Above el 269'-0" -

E-1076 Sh.1 Lighting - Auxiliary Equipment Room - Above el 289'-0" -

E-1080 Sh.1 Lighting - Reactor Enclosure - Unit 2 Above el 177'-0" -

E-1081 Sh.1 Lighting - Reactor Enclosure - Unit 2 Above el 201'-0" -

E-1082 Sh.1 Lighting - Reactor Enclosure - Unit 2 Above el 217'-0" -

E-1083 Sh.1 Lighting - Reactor Enclosure - Unit 2 Above el 253'-0" -

E-1084 Sh.1 Lighting - Reactor Enclosure - Unit 2 Above el 283'-0" -

Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-14 REV. 16, SEPTEMBER 2012

LGS UFSAR Table 1.7-1 (Contd)

ELECTRICAL DRAWINGS Drawing Number Title Former UFSAR Figure Number E-1085 Sh.1 Lighting - Reactor Enclosure - Unit 2 Above el 313'-0" & 331'-0" -

E-1086 Sh.1 Lighting - Reactor Enclosure - Unit 2 Above el 352'-0" -

E-1087 Sh.1 Lighting - Diesel Generator Enclosure - Unit 2 Above el 217'-0" -

E-1112 Sh.1 Raceway Layout - Turbine Enclosure - Unit 1 Columns R-N & 5-12 (Area 1) el 239'-0" 7.2-10 Sh.1 E-1121 Sh.1 Raceway Layout - Turbine Enclosure - Unit 1 Columns R-N & 5-12 (Area 1) el 269'-0" -

E-1124 Sh.1 Raceway Layout - Turbine Enclosure - Unit 1 Columns N-J & 5-12 (Area 6) el 269'-0" -

E-1125 Sh.1 Raceway Layout - Turbine Enclosure - Unit 1 Columns N-J & 12-19.2 (Area 7) el 269'-0" -

E-1141 Sh.1 Raceway Layout - Unit 1 J Wall Elevation Looking North Columns 9-3-23. el 162'-0" to 217'-0" -

E-1141 Sh.2 Raceway Layout - Unit 1 J Wall Elevation Looking North Columns 9-3-23. el 162'-0" to 217'-0" -

E-1142 Sh.1 Tray Layout - Turbine Enclosure - Units 1 & 2 Columns N-J & 19.2-26 (Area 8) Auxiliary Equipment Room Sections -

E-1143 Sh.1 Tray Layout - Turbine Enclosure - Units 1 & 2 Columns N-J & 24.5-26.6 (Area 8) Auxiliary Equipment Room Sections -

E-1144 Sh.1 Raceway Layout - Turbine Enclosure - Units 1 & 2 Mh Wall Elevation Looking North Columns 19.2-25.5 el 217'-0" to 318'-0" -

E-1145 Sh.1 Raceway Layout Turbine Enclosure Elevation Mh Wall Looking South Columns 19.2 to 26.8 el 217'-0" to 304'-0" -

E-1146 Sh.1 Raceway Layout - Turbine Enclosure - Unit 1 Sections and Details -

E-1147 Sh.1 Raceway Layout Turbine Enclosure - Units 1 & 2 Plans of Mh Wall from el 217'-0" to 300'-0" -

E-1148 Sh.1 Raceway Layout Turbine Enclosure Sections and Details of Mh Wall -

E-1149 Sh.1 Raceway Layout - Turbine Enclosure - Unit 1 Section and Plans of 19.4 Wall -

E-1149 Sh.2 Raceway Layout - Turbine Enclosure - Unit 1 Section and Plans of 19.4 Wall -

E-1150 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 Columns J-G & 14.1-18.5 (Area 11) Plan el 177'-0" Slab & Above -

E-1151 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 Columns J-G & 18.5-23 (Area 12) Plan el 177'-0" Slab & Above -

E-1152 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 Columns G.D. & 14.1-18.5 (Area 15) Plan el 177'-0" Slab & Above -

E-1152 Sh.2 Raceway Layout - Reactor Enclosure - Unit 1 Columns G.D. & 14.1-18.5 (Area 15) Plan el 177'-0" Slab & Above E-1153 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 Columns G.D. & 18.5-23 (Area 16) Plan el 177'-0" Slab & Above -

E-1154 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 Columns J-G & 14.1-18.5 (Area 11) Plan el 201'-0" Slab & Above -

E-1155 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 Columns J-G & 18.5-23 (Area 12) Plan el 201'-0" Slab & Above -

E-1156 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 Columns G-D & 14.1-18.5 (Area 15) Plan el 201'-0" Slab & Above -

E-1157 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 Columns G-D & 18.5-23 (Area 16) Plan el 201'-0" Slab & Above -

E-1158 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 Columns J-G & 14.1-18.5 (Area 11) Plan el 217'-0" Slab & Above -

E-1158 Sh.2 Raceway Layout - Reactor Enclosure - Unit 1 Columns J-G & 14.1-18.5 (Area 11) Plan el 217'-0" Slab & Above -

E-1159 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 Columns J-G & 18.5-23 (Area 12) Plan el 217'-0" Slab & Above -

E-1159 Sh.2 Raceway Layout - Reactor Enclosure - Unit 1 Columns J-G & 18.5-23 (Area 12) Plan el 217'-0" Slab & Above -

E-1160 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 Columns G-D & 14.1-18.5 (Area 15) Plan el 217'-0" Slab & Above -

E-1160 Sh.2 Raceway Layout - Reactor Enclosure - Unit 1 Columns G-D & 14.1-18.5 (Area 15) Plan el 217'-0" Slab & Above -

E-1160 Sh.3 Raceway Layout - Reactor Enclosure - Unit 1 Columns G-D & 14.1-18.5 (Area 15) Plan el 217'-0" Slab & Above -

Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-15 REV. 16, SEPTEMBER 2012

LGS UFSAR Table 1.7-1 (Contd)

ELECTRICAL DRAWINGS Drawing Number Title Former UFSAR Figure Number E-1161 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 Columns G-D & 18.5-23 (Area 16) Plan el 217'-0" Slab & Above -

E-1161 Sh.2 Raceway Layout - Reactor Enclosure - Unit 1 Columns G-D & 18.5-23 (Area 16) Plan el 217'-0" Slab & Above -

E-1162 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 Columns J-G & 14.1-18.5 (Area 11) Plan el 253'-0" Slab & Above -

E-1162 Sh.2 Raceway Layout - Reactor Enclosure - Unit 1 Columns J-G & 14.1-18.5 (Area 11) Plan el 253'-0" Slab & Above -

E-1163 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 Columns J-G & 18.5-23 (Area 12) Plan el 253'-0" Slab & Above -

E-1163 Sh.2 Raceway Layout - Reactor Enclosure - Unit 1 Columns J-G & 18.5-23 (Area 12) Plan el 253'-0" Slab & Above -

E-1163 Sh.3 Raceway Layout - Reactor Enclosure - Unit 1 Columns J-G & 18.5-23 (Area 12) Plan el 253'-0" Slab & Above -

E-1164 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 Columns G-D & 14.1-18.5 (Area 15) Plan el 253'-0" Slab & Above 7.2-14 Sh.1 E-1164 Sh.2 Raceway Layout - Reactor Enclosure - Unit 1 Hydraulic Control Unit Raceway Plan el 253'-0" Slab & Above 7.2-14 Sh.2 E-1165 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 Columns G-D & 18.5-23 (Area 16) Plan el 253'-0" Slab & Above 7.2-15 Sh.1 E-1166 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 Columns J-G & 14.1-18.5 (Area 11) Plan el 283'-0" Slab & Above -

E-1166 Sh.2 Raceway Layout - Reactor Enclosure - Unit 1 Columns J-G & 14.1-18.5 (Area 11) Plan el 283'-0" Slab & Above -

E-1166 Sh.3 Raceway Layout - Reactor Enclosure - Unit 1 Columns J-G & 14.1-18.5 (Area 11) Plan el 283'-0" Slab & Above -

E-1167 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 Columns J-G & 18.5-23 (Area 12) Plan el 283'-0" Slab & Above -

E-1167 Sh.2 Raceway Layout - Reactor Enclosure - Unit 1 Columns J-G & 18.5-23 (Area 12) Plan el 283'-0" Slab & Above -

E-1167 Sh.3 Raceway Layout - Reactor Enclosure - Unit 1 Columns J-G & 18.5-23 (Area 12) Plan el 283'-0" Slab & Above -

E-1168 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 Columns G-D & 14.1-18.5 (Area 15) Plan el 283'-0" Slab & Above -

E-1169 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 Columns G-D & 18.5-23 (Area 16) Plan el 283'-0" Slab & Above -

E-1169 Sh.2 Raceway Layout - Reactor Enclosure - Unit 1 Columns G-D & 18.5-23 (Area 16) Plan el 283'-0" Slab & Above -

E-1170 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 Columns J-G & 14.1-18.5 (Area 11) Plan el 313'-0" Slab & Above -

E-1171 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 Columns J-G & 18.5-23 (Area 12) Plan el 313'-0" Slab & Above -

E-1172 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 Columns G-D & 14.1-18.5 (Area 15) Plan el 313'-0" Slab & Above -

E-1173 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 Columns D-G & 18.5-23 (Area 16) Plan el 313'-0" Slab & Above -

E-1174 Sh.1 Conduit and Gutter Layout - Turbine Enclosure - Unit 1 Columns N-J & 19.2-23 (Area 8) Cable Spreading Room - Plan el -

254'-0" Slab & Above E-1174 Sh.2 Conduit Layout - Turbine Enclosure - Unit 1 Columns N-J & 19.2-23 (Area 8) Cable Spreading Room Plan el 254'-0" Slab & -

Above E-1175 Sh.1 Conduit and Gutter Layout - Turbine Enclosure - Unit 2 Columns N-J & 23-26.6 (Area 8) Cable Spreading Room Plan -

El. 234'-0" Slab & Above E-1175 Sh.2 Conduit Layout - Turbine Encl - Unit 2 Columns N-J & 23-26.6 (Area 8) Cable Spring Room - Plan el 254'-0" Slab & Above -

E-1176 Sh.1 Raceway Layout - Reactor Encl - Unit 1 Columns G-D & 14.1-18.5 (Area 15) Plan el 331'-0" Slab & Above -

E-1177 Sh.1 Raceway Layout - Reactor Encl - Unit 1 Columns G-D & 18.5-23 (Area 16) Plan el 331'-0" Slab & Above -

E-1178 Sh.1 Raceway Layout - Reactor Encl - Unit 1 Columns J-G & 14.1-18.5 (Area 11) Plan el 352'-0" Slab & Above -

Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-16 REV. 16, SEPTEMBER 2012

LGS UFSAR Table 1.7-1 (Contd)

ELECTRICAL DRAWINGS Drawing Number Title Former UFSAR Figure Number E-1179 Sh.1 Raceway Layout - Reactor Encl - Unit 1 Columns J-G & 18.5-23 (Area 12) Plan el 352'-0" Slab & Above -

E-1179 Sh.2 Raceway Layout - Reactor Encl - Unit 1 Columns J-G & 18.5-23 (Area 12) Plan el 352'-0" Slab & Above -

E-1180 Sh.1 Raceway Layout - Reactor Encl - Unit 1 Columns G-D & 14.1-18.5 (Area 15) Plan el 352'-0" Slab & Above -

E-1181 Sh.1 Raceway Layout - Reactor Encl - Unit 1 Columns G-D & 18.5-23 (Area 16) Plan el 352'-0" Slab & Above -

E-1182 Sh.1 Panels & Floor Penetration Identification - Turbine Encl - Units 1 & 2 Columns N-J 19.2-26.8 (Area 8) Control Room -

Plan el 269'-0" Slab & Above E-1183 Sh.1 Conduit and Gutter Layout - Turbine Encl - Units 1 & 2 Columns N-J & 19.2-26.6 (Area 8) Plan el 289'-0" Slab & Above -

E-1183 Sh.2 Conduit and Gutter Layout - Turbine Encl - Units 1 & 2 Columns N-J & 19.2-26.6 (Area 8) Plan el 289'-0" Slab & Above -

E-1184 Sh.1 Raceway Layout - Unit 1 D Wall Elevation Looking North Columns 15.5-21.5 el 217'-0" to 313'-0" -

E-1185 Sh.2 Raceway Layout - Reactor Encl - Units 1 & 2 J Wall Elevation - Looking North Columns 19.4-26.6 el 217'-0" to 332'-0" -

E-1186 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 Drywell Section AZ-0 to AZ-90 -

E-1186 Sh.2 Raceway Layout - Reactor Enclosure - Unit 1 Drywell Section AZ-0 to AZ-90 -

E-1186 Sh.3 Raceway Layout - Reactor Enclosure - Unit 1 Drywell Section AZ-0 to AZ-90 -

E-1186 Sh.4 Raceway Layout - Reactor Enclosure - Unit 1 Drywell Section AZ-0 to AZ-90 -

E-1187 Sh.1 Drywell - Units 1 & 2 Electrical Raceway Supports el 243'-0" -

E-1187 Sh.2 Drywell - Units 1 & 2 Electrical Raceway Supports el 243'-0" -

E-1187 Sh.3 Drywell - Units 1 & 2 Electrical Raceway Supports el 243'-0" -

E-1187 Sh.4 Drywell - Units 1 & 2 Electrical Raceway Supports el 243'-0" to 322'-0" & 6 -

E-1188 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 Drywell RPV Instrumentation -

E-1189 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 Drywell Plan Above el 217'-0" -

E-1190 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 Drywell Unit 1 Raceway Supported from Steel at el 253'-0" -

E-1191 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 CRD & LPRM Inside RPV Pedestal -

E-1192 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 Drywell Miscellaneous Plans & Details -

E-1193 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 Drywell Raceway Supported from Steel at el 272'-9" -

E-1194 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 Drywell Raceway Supported from Steel at el 277'-6" -

E-1195 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 Drywell Raceway Supported from Steel at el 286'-1" -

E-1196 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 Drywell Raceway Supported from Steel at el 295'-11" -

E-1198 Sh.1 Raceway Layout -

E-1199 Sh.1 Raceway Layout - Reactor Enclosure - Unit 1 Drywell Tray Section & Details -

E-1209 Sh.1 Raceway Layout - Turbine Enclosure - Unit 2, Area 5, el 239'-0" 7.2-10 Sh.2 E-1209 Sh.2 Raceway Layout - Turbine Enclosure - Unit 2, Area 5 el 239'-0" 7.2-10 Sh.3 E-1233 Sh.1 Raceway Layout - Turbine Enclosure - Units 1 & 2 Mh Wall Elevation Looking North Columns 19.4-26.6, el 217'-0" to 304'-0" -

E-1234 Sh.1 Raceway Layout - Turbine Enclosure - Units 1 & 2 J Line Wall Elevation Looking South Columns 19.4-26.6 & el 200'-0" to -

289'-0" Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-17 REV. 16, SEPTEMBER 2012

LGS UFSAR Table 1.7-1 (Contd)

ELECTRICAL DRAWINGS Drawing Number Title Former UFSAR Figure Number E-1235 Sh.1 Class I Bus Duct Supports -

E-1241 Sh.1 Raceway Layout - Unit 2 J Line Wall Elevation Looking North Columns 23-31.9 el 177'-0" to 217'-0" -

E-1241 Sh.2 Raceway Layout - Unit 2 J Line Wall Elevation Looking North Columns 23-31.9 el 177'-0" to 217'-0" -

E-1244 Sh.1 Raceway Layout - Turbine Enclosure - Wall Elevation Columns 19.4 and 26.6 J to N el 217'-0" to 332'-0" -

E-1250 Sh.1 Raceway Layout - Reactor Enclosure - Unit 2 Columns G-J & 23-27.5 (Area 13) Plan el 177'-0" Slab & Above -

E-1250 Sh.2 Raceway Layout - Reactor Enclosure - Unit 2 Columns G-J & 23-27.5 (Area 13) Plan el 177'-0" Slab & Above -

E-1251 Sh.1 Raceway Layout - Reactor Enclosure - Unit 2 Columns G-J & 27.5-31.9 (Area 14) Plan el 177'-0" Slab & Above -

E-1252 Sh.1 Raceway Layout - Reactor Enclosure - Unit 2 Columns D-G & 23-27.5 (Area 17) Plan el 177'-0" Slab & Above -

E-1252 Sh.2 Raceway Layout - Reactor Enclosure - Unit 2 Columns D-G & 23-27.5 (Area 17) Plan el 177'-0" Slab & Above -

E-1253 Sh.1 Raceway Layout - Reactor Enclosure - Unit 2 Columns D-G & 27.5-31.9 (Area 18) Plan el 177'-0" Slab & Above -

E-1253 Sh.2 Raceway Layout - Reactor Enclosure - Unit 2 Columns D-G & 27.5-31.9 (Area 18) Plan el 177'-0" Slab & Above -

E-1254 Sh.1 Raceway Layout - Reactor Enclosure - Unit 2 Columns J-G & 23-27.5 (Area 13) Plan el 201'-0" Slab & Above -

E-1254 Sh.2 Raceway Layout - Reactor Enclosure - Unit 2 Columns J-G & 23-27.5 (Area 13) Plan el 201'-0" Slab & Above -

E-1256 Sh.1 Raceway Layout - Reactor Enclosure - Unit 2 Columns D-G & 23-27.5 (Area 17) Plan el 201'-0" Slab & Above -

E-1256 Sh.2 Raceway Layout - Reactor Enclosure - Unit 2 Columns D-G & 23-27.5 (Area 17) Plan el 201'-0" Slab & Above -

E-1257 Sh.1 Raceway Layout - Reactor Enclosure - Unit 2 Columns D-G & 27.5-31.9 (Area 18) Plan el 201'-0" Slab & Above -

E-1257 Sh.2 Raceway Layout - Reactor Enclosure - Unit 2 Columns D-G & 27.5-31.9 (Area 18) Plan el 201'-0" Slab & Above -

E-1258 Sh.1 Raceway Layout - Reactor Enclosure - Unit 2 Columns G-J & 23-27.5 (Area 13) Plan el 217'-0" Slab & Above -

E-1258 Sh.2 Raceway Layout - Reactor Enclosure - Unit 2 Columns G-J & 23-27.5 (Area 13) Plan el 217'-0" Slab & Above -

E-1259 Sh.1 Raceway Layout - Reactor Enclosure - Unit 2 Columns G-J & 27.5-31.9 (Area 14) Plan el 217'-0" Slab & Above -

E-1260 Sh.1 Raceway Layout - Reactor Enclosure - Unit 2 Columns D-G & 23-27.5 (Area 17) Plan el 217'-0" Slab & Above -

E-1260 Sh.2 Raceway Layout - Reactor Enclosure - Unit 2 Columns D-G & 23-27.5 (Area 17) Plan el 217'-0" Slab & Above -

E-1260 Sh.3 Raceway Layout - Reactor Enclosure - Unit 2 Columns D-G & 23-27.5 (Area 17) Plan el 217'-0" Slab & Above -

E-1261 Sh.1 Raceway Layout - Reactor Enclosure - Unit 2 Columns D-G & 27.5-31.9 (Area 18) Plan el 217'-0" Slab & Above -

E-1261 Sh.2 Raceway Layout - Reactor Enclosure - Unit 2 Columns D-G & 27.5-31.9 (Area 18) Plan el 217'-0" Slab & Above -

E-1261 Sh.3 Raceway Layout - Reactor Enclosure - Unit 2 Columns D-G & 27.5-31.9 (Area 18) Plan el 217'-0" Slab & Above -

E-1262 Sh.1 Raceway Layout - Reactor Enclosure - Unit 2 Columns G-J & 23-27.5 (Area 13) Plan el 253'-0" Slab & Above -

E-1262 Sh.2 Raceway Layout - Reactor Enclosure - Unit 2 Columns G-J & 23-27.5 (Area 13) Plan el 253'-0" Slab & Above -

E-1262 Sh.3 Raceway Layout - Reactor Enclosure - Unit 2 Columns G-J & 23-27.5 (Area 13) Plan el 253'-0" Slab & Above -

E-1263 Sh.1 Raceway Layout - Reactor Enclosure - Unit 2 Columns G-K & 27.5-31.9 (Area 14) Plan el 253'-0" Slab & Above -

E-1263 Sh.2 Raceway Layout - Reactor Enclosure - Unit 2 Columns G-K & 27.5-31.9 (Area 14) Plan el 253'-0" Slab & Above -

E-1264 Sh.1 Raceway Layout - Reactor Enclosure - Unit 2 Columns D-G & 23-27.5 (Area 17) Plan el 253'-0" Slab & Above 7.2-14 Sh.3 E-1264 Sh.2 Raceway Layout - Reactor Enclosure - Unit 2 Columns D-G & 23-27.5 (Area 17) Plan el 253'-0" Slab & Above 7.2-14 Sh.4 E-1264 Sh.3 Raceway Layout - Reactor Enclosure - Unit 2, Area 18 el 253'-0" 7.2-14 Sh.5 Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-18 REV. 16, SEPTEMBER 2012

LGS UFSAR Table 1.7-1 (Contd)

ELECTRICAL DRAWINGS Drawing Number Title Former UFSAR Figure Number E-1264 Sh.4 Raceway Layout - Reactor Enclosure - Unit 2, Area 18 el 253'-0" 7.2-14 Sh.6 E-1265 Sh.1 Raceway Layout - Reactor Enclosure - Unit 2 Columns D-G & 27.5-31.9 (Area 18) Plan el 253'-0" Slab & Above 7.2-15 Sh.2 E-1265 Sh.2 Raceway Layout - Reactor Enclosure - Unit 2 Columns D-G & 27.5-31.9 (Area 18) Plan el 253'-0" Slab & Above 7.2-15 Sh.3 E-1265 Sh.3 Raceway Layout - Reactor Enclosure - Unit 2, Area 18 el 253'-0" 7.2-15 Sh.4 E-1266 Sh.1 Raceway Layout - Reactor Enclosure - Unit 2 Columns G-J & 23-27.5 (Area 13) Plan el 283'-0" Slab & Above -

E-1266 Sh.2 Raceway Layout - Reactor Enclosure - Unit 2 Columns G-J & 23-27.5 (Area 13) Plan el 283'-0" Slab & Above -

E-1267 Sh.1 Raceway Layout - Reactor Enclosure - Unit 2 Columns G-J & 27.5-31.9 (Area 14) Plan el 283'-0" Slab & Above -

E-1267 Sh.2 Raceway Layout - Reactor Enclosure - Unit 2 Columns G-J & 27.5-31.9 (Area 14) Plan el 283'-0" Slab & Above -

E-1268 Sh.1 Raceway Layout - Reactor Enclosure - Unit 2 Columns D-G & 23-27.5 (Area 17) Plan el 283'-0" Slab & Above -

E-1268 Sh.2 Raceway Layout - Reactor Enclosure - Unit 2 Columns D-G & 23-27.5 (Area 17) Plan el 283'-0" Slab & Above -

E-1269 Sh.1 Raceway Layout - Reactor Enclosure - Unit 2 Columns D-G & 27.5-31.9 (Area 18) Plan el 283'-0" Slab & Above -

E-1269 Sh.2 Raceway Layout - Reactor Enclosure - Unit 2 Columns E-H & 14.1-18.5 (Area 14, 17, & 18) Plan el 300'-3" Slab -

E-1270 Sh.1 Raceway Layout - Reactor Enclosure - Unit 2 Columns G-J & 23-27.5 (Area 13) Plan el 313'-0" Slab & Above -

E-1271 Sh.1 Raceway Layout - Reactor Enclosure - Unit 2 Columns G-J & 27.5-31.9 (Area 14) Plan el 313'-0" Slab & Above -

E-1272 Sh.1 Raceway Layout - Reactor Enclosure - Unit 2 Columns D-G & 23-27.5 (Area 17) Plan el 313'-0" Slab & Above -

E-1273 Sh.1 Raceway Layout - Reactor Enclosure - Unit 2 Columns D-G & 27.5-31.9 (Area 18) Plan el 313'-0" Slab & Above -

E-1276 Sh.1 Raceway Layout - Reactor Enclosure - Unit 2 (Area 17) Plan Above el 331'-0" -

E-1277 Sh.1 Raceway Layout - Reactor Enclosure - Unit 2 (Area 18) Plan Above el 331'-0" -

E-1278 Sh.1 Raceway Layout - Reactor Enclosure - Unit 2 (Area 13) Plan Above el 352'-0" -

E-1279 Sh.1 Raceway Layout - Reactor Enclosure - Unit 2 (Area 14) Plan Above el 352'-0" -

E-1280 Sh.1 Raceway Layout - Reactor Enclosure - Unit 2 (Area 17) Plan Above el 352'-0" -

E-1281 Sh.1 Raceway Layout - Reactor Enclosure - Unit 2 (Area 18) Plan Above el 352'-0" -

E-1284 Sh.1 Raceway Layout - Unit 2 D Wall Elevation Looking North Columns 24.5-30.5 el 217'-0" to 313'-0" -

E-1288 Sh.1 Raceway Layout - Reactor Enclosure - Unit 2 Drywell RPV Instrumentation -

E-1289 Sh.1 Raceway Layout - Reactor Enclosure - Unit 2 Drywell Plan Above el 217'-0" -

E-1291 Sh.1 Raceway Layout - Reactor Enclosure - Unit 2 CRD & LPRM Inside RPV Pedestal -

E-1292 Sh.1 Raceway Layout - Reactor Enclosure - Unit 2 Drywell Misc. Plans & Details -

E-1297 Sh.1 Raceway Layout - Reactor Enclosure - Unit 2 Drywell Raceway Sections - Sheet 1 -

E-1298 Sh.1 Raceway Layout - Containment - Unit 2 Drywell Tray Layout -

E-1299 Sh.1 Raceway Layout - Containment - Unit 2 Drywell Tray Sections -

E-1300 Sh.1 Raceway Layout - Radwaste Enclosure Area 20 Plan el 162'-0" Slab & Above -

E-1301 Sh.1 Raceway Layout - Radwaste Enclosure Area 22 Plan el 162'-0" Slab & Above -

E-1302 Sh.1 Raceway Layout - Radwaste Enclosure Area 23 Plan el 162'-0" Slab & Above -

Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-19 REV. 16, SEPTEMBER 2012

LGS UFSAR Table 1.7-1 (Contd)

ELECTRICAL DRAWINGS Drawing Number Title Former UFSAR Figure Number E-1303 Sh.1 Raceway Layout - Radwaste Enclosure Area 20 Plan el 191'-0" Slab & Above -

E-1304 Sh.1 Raceway Layout - Radwaste Enclosure Area 22 Plan el 191'-0" Slab & Above -

E-1305 Sh.1 Raceway Layout - Radwaste Enclosure Area 23 Plan el 191'-0" Slab & Above -

E-1306 Sh.1 Raceway Layout - Radwaste Enclosure Area 20 Plan el 217'-0" Slab & Above -

E-1307 Sh.1 Raceway Layout - Radwaste Enclosure Area 22 Plan el 217'-0" Slab & Above -

E-1308 Sh.1 Raceway Layout - Radwaste Enclosure Area 20 Plan el 237'-0" Slab & Above -

E-1309 Sh.1 Raceway Layout - Radwaste Enclosure Area 22 Plan el 237'-0" Slab & Above -

E-1310 Sh.1 Raceway Layout - Radwaste Enclosure Area 20 Plan el 257'-0" Slab & Above -

E-1311 Sh.1 Raceway Layout - Radwaste Enclosure Area 22 Plan Above el 257'-0" -

E-1314 Sh.1 Raceway Layout - Radwaste Enclosure Area 19 Plan el 195'-0" Slab & Above -

E-1315 Sh.1 Raceway Layout - Radwaste Enclosure Area 21 Plan el 195'-0" Slab & Above -

E-1316 Sh.1 Raceway Layout - Radwaste Enclosure Misc. Plans, Details & Sections -

E-1317 Sh.1 Raceway Layout - Radwaste Enclosure Misc. Plans, Details & Sections -

E-1318 Sh.1 Raceway Layout - Radwaste Enclosure Area 20 - Partial Plan Below Radwaste Control Room -

E-1319 Sh.1 Raceway Layout - Radwaste Enclosure Area 20 Sections Below Radwaste Control Room -

E-1328 Sh.1 Raceway Layout - Lube Oil Storage Enclosure -

E-1332 Sh.1 Embedded Conduit Layout - Diesel Generator Enclosure - Unit 1 -

E-1335 Sh.1 Embedded Conduit Layout - Diesel Generator Enclosure - Unit 2 -

E-1348 Sh.1 Raceway Layout - Diesel Generator Enclosure - Unit 1 Plan el 217'-0" -

E-1349 Sh.1 Raceway Layout - Diesel Generator Enclosure - Unit 2 Plan el 217'-0" -

E-1360 Sh.1 Riser Diagram - Fire Alarm System - Unit 1 -

E-1360 Sh.2 Riser Diagram - Fire Alarm System - Unit 1 -

E-1361 Sh.1 Riser Diagram - Fire Alarm System - Unit 2 -

E-1362 Sh.1 Riser Diagram - Fire Alarm System (FA) Remote Enclosure - Comm -

E-1364 Sh.1 Wiring/Connection Diagram - Evacuation Alarm & River Warning Systems -

E-1367 Sh.1 Riser Diagram - Public Address System (PA) Unit 2 9.5-3 Sh.1 E-1368 Sh.1 Riser Diagram - Public Address System (PA) Remote Enclosure - Comm 9.5-4 Sh.1 E-1369 Sh.1 Riser Diagram - Telephone System (PABX) Unit 1 9.5-5 Sh.1 E-1370 Sh.1 Riser Diagram - Telephone System (PABX) Unit 2 9.5-6 Sh.1 E-1366 Sh.1 Riser Diagram - Public Address System (PA) Unit 1 9.5-2 Sh.1 E-1371 Sh.1 Riser Diagram - Telephone System (PABX) Remote Enclosure - Comm 9.5-7 Sh.1 E-1373 Sh.1 Riser Diagram - Lighting, Power & Fire Alarm Panel boards Unit 1 Turbine & Reactor Enclosure -

E-1374 Sh.1 Riser Diagram - Lighting, Power, and Fire Alarm Panel boards Unit 2 - Turbine & Reactor Enclosures -

Note: See note in Section 1.7 for drawing considerations CHAPTER 01 1.7-20 REV. 16, SEPTEMBER 2012

LGS UFSAR Table 1.7-1 (Contd)

ELECTRICAL DRAWINGS Drawing Number Title Former UFSAR Figure Number E-1375 Sh.1 Riser Diagram - Lighting, Power, and Fire Alarm Panel boards Remote Enclosure - Comm -

E-1405 Sh.1 Lighting - Notes, Symbols & Details -

E-1406 Sh.1 Conduit & Cable Tray Notes, Symbols & Details -

E-1407 Sh.1 Communication Notes, Symbols & Details -

E-1408 Sh.1 Fire Alarm System Notes, Symbols & Details -

E-1412 Sh.1 Wire & Cable - Notes & Details -

E-1425 Sh.1 Lighting, Power & Fire Alarm Panel Schedules -

E-1460 Sh.1 Communication and Fire Alarm Layout - Reactor Enclosure - Unit 1 Plan Above el 177'-0" -

E-1461 Sh.1 Communication & Fire Alarm Layout - Reactor Enclosure - Unit 1 Plan Above el 201'-0" -

E-1462 Sh.1 Communication & Fire Alarm Layout - Reactor Enclosure - Unit 1 Above el 217'-0" -

E-1463 Sh.1 Communication & Fire Alarm Layout - Reactor Enclosure - Unit 1 Above el 253'-0" -

E-1464 Sh.1 Communication & Fire Alarm Layout - Reactor Enclosure - Unit 1 Above el 283'-0" -

E-1465 Sh.1 Communication & Fire Alarm Layout - Reactor Enclosure - Unit 1 Above el 313'-0" -

E-1466 Sh.1 Communication & Fire Alarm Layout - Reactor Enclosure - Unit 1 Above el 352'-0" -

E-1467 Sh.1 Communication & Fire Alarm Layout - Diesel Generator Bids - Unit 1 -

E-1480 Sh.1 Communication & Fire Alarm Layout - Reactor Enclosure - Unit 2 Above el 177'-0" -

E-1495 Sh.1 Communication & Fire Alarm Layout - Spray Pond Pumphouse Above el 251'-0" & 268'-0" -

E-1500 Sh.1 Raceway Schedule - Engineered Safeguard System - Unit 1 -

E-1501 Sh.1 Raceway Schedule - Reactor Protection System - Unit 1 -

E-1506 Sh.1 Circuit Schedule - Engineered Safeguard System - Unit 1 & Comm -

E-1507 Sh.1 Circuit Schedule - Reactor Protection System - Unit 1 & Comm -

E-1515 Sh.1 Raceway Schedule - Engineered Safeguard Systems - Unit 2 -

E-1516 Sh.1 Raceway Schedule - Reactor Protection System - Unit 2 -

E-1521 Sh.1 Circuit Schedule - Engineered Safeguard System - Unit 2 & Comm -

E-1522 Sh.1 Circuit Schedule - Reactor Protection System - Unit 2 & Comm -

E-1675 Sh.1 Communication & Fire Alarm Layout - Main Control Room - Above el 269'-0" -

E-1676 Sh.1 Communication & Fire Alarm Layout - Auxiliary Equipment Room Above el 289'-0" -

E-1681 Sh.1 Communication & Fire Alarm Layout - Reactor Enclosure - Unit 2 Above el 201'-0" -

E-1682 Sh.1 Communication & Fire Alarm Layout - Reactor Enclosure - Unit 2 Above el 217'-0" -

E-1683 Sh.1 Communication & Fire Alarm Layout - Reactor Enclosure - Unit 2 Above el 253'-0" -

E-1684 Sh.1 Communication & Fire Alarm Layout - Reactor Enclosure - Unit 2 Above el 283'-0" -

E-1685 Sh.1 Communication & Fire Alarm Layout - Reactor Enclosure - Unit 2 Plan Above el 313'-0" -

E-1686 Sh.1 Communication & Fire Alarm Layout - Reactor Enclosure - Unit 2 Plan Above el 352'-0" -

E-1687 Sh.1 Communication & Fire Alarm Layout - Diesel Generator Enclosure - Unit 2 Above el 217'-0" -

Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-21 REV. 16, SEPTEMBER 2012

LGS UFSAR Table 1.7-2 FIGURE INDEX FOR PLANT SYSTEMS P&ID Number System Former UFSAR Figure Number M-00 Sh. 1 Legend 1.10-1 Sh.1 M-00 Sh. 2 Legend 1.10-1 Sh.2 M-01 Sh. 1 Main Steam 10.3-1 Sh. 1 M-01 Sh. 2 Main Steam 10.3-1 Sh. 2 M-01 Sh. 3 Main Steam 10.3-1 Sh. 3 M-01 Sh. 4 Main Steam 10.3-1 Sh. 4 M-02 Sh. 1 Extraction Steam 10.2-1 Sh. 1 M-02 Sh. 2 Extraction Steam 10.2-1 Sh. 2 M-02 Sh. 3 Extraction Steam 10.2-1 Sh. 3 M-02 Sh. 4 Extraction Steam 10.2-1 Sh. 4 M-03 Sh. 1 Vents and Drains, Heaters 1 & 2 Drain Cooler 1 10.4-7 Sh.1 M-03 Sh. 2 Vents and Drains, Heaters 1 & 2 Drain Cooler 1 10.4-7 Sh.2 M-04 Sh. 1 Vents and Drains, Heaters 3,4,5 & 6 10.4-8 Sh. 1 M-04 Sh. 2 Vents and Drains, Heaters 3,4,5 & 6 10.4-8 Sh. 2 M-04 Sh. 3 Vents and Drains, Heaters 3,4,5 & 6 10.4-8 Sh. 3 M-04 Sh. 4 Vents and Drains, Heaters 3,4,5 & 6 10.4-8 Sh. 4 M-04 Sh. 5 Vents and Drains, Heaters 3,4,5 & 6 10.4-8 Sh. 5 M-04 Sh. 6 Vents and Drains, Heaters 3,4,5 & 6 10.4-8 Sh. 6 M-05 Sh. 1 Condensate 10.4-4 Sh. 1 M-05 Sh. 2 Condensate 10.4-4 Sh. 2 M-05 Sh. 3 Condensate 10.4-4 Sh. 3 M-05 Sh. 4 Condensate 10.4-4 Sh. 4 M-06 Sh. 1 Feedwater 10.4-5 Sh. 1 M-06 Sh. 2 Feedwater 10.4-5 Sh. 2 M-06 Sh. 3 Feedwater 10.4-5 Sh. 3 M-06 Sh. 4 Feedwater 10.4-5 Sh. 4 M-06 Sh. 5 Feedwater 10.4-5 Sh. 5 Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-22 REV. 18, SEPTEMBER 2016

LGS UFSAR Table 1.7-2 (Contd)

FIGURE INDEX FOR PLANT SYSTEMS P&ID Number System Former UFSAR Figure Number M-06 Sh. 6 Feedwater 10.4-5 Sh. 6 M-06 Sh. 7 Feedwater 10.4-5 Sh. 7 M-06 Sh. 8 Feedwater 10.4-5 Sh. 8 M-06 Sh. 9 Feedwater 10.4-5 Sh. 9 M-06 Sh.10 Feedwater 10.4-5 Sh.10 M-06 Sh.11 Feedwater 10.4-5 Sh.11 M-07 Sh. 1 Air Removal & Sealing Steam 10.4-1 Sh. 1 M-07 Sh. 2 Air Removal & Sealing Steam 10.4-1 Sh. 2 M-07 Sh. 3 Air Removal & Sealing Steam 10.4-1 Sh. 3 M-07 Sh. 4 Air Removal & Sealing Steam 10.4-1 Sh. 4 M-08 Sh. 1 Condensate and Refueling Water Storage 9.2-24 Sh. 1 M-08 Sh. 2 Condensate and Refueling Water Storage 9.2-24 Sh. 2 M-08 Sh. 3 Condensate and Refueling Water Storage 9.2-24 Sh. 3 M-09 Sh. 1 Circulating Water 10.4-2 Sh. 1 M-09 Sh. 2 Circulating Water 10.4-2 Sh. 2 M-09 Sh. 3 Circulating Water 10.4-2 Sh. 3 M-09 Sh. 4 Circulating Water 10.4-2 Sh. 4 M-09 Sh. 5 Circulating Water 10.4-2 Sh. 5 M-09 Sh. 6 Circulating Water 10.4-2 Sh. 6 M-09 Sh. 7 Circulating Water 10.4-2 Sh. 7 M-09 Sh. 8 Circulating Water 10.4-2 Sh. 8 M-09 Sh. 9 Circulating Water 10.4-2 Sh. 9 M-09 Sh. 10 Circulating Water -

M-09 Sh. 11 Circulating Water -

M-09 Sh. 12 Circulating Water -

M-09 Sh. 13 Circulating Water -

M-09 Sh. 14 Circulating Water -

M-10 Sh. 1 Service Water 9.2-1 Sh. 1 M-10 Sh. 2 Service Water 9.2-1 Sh. 2 Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-23 REV. 18, SEPTEMBER 2016

LGS UFSAR Table 1.7-2 (Contd)

FIGURE INDEX FOR PLANT SYSTEMS P&ID Number System Former UFSAR Figure Number M-10 Sh. 3 Service Water 9.2-1 Sh. 3 M-10 Sh. 4 Service Water 9.2-1 Sh. 4 M-10 Sh. 5 Service Water 9.2-1 Sh. 5 M-10 Sh. 6 Service Water 9.2-1 Sh. 6 M-10 Sh. 7 Service Water 9.2-1 Sh. 7 M-10 Sh. 8 Service Water 9.2-1 Sh. 8 M-10 Sh. 9 Service Water 9.2-1 Sh. 9 M-10 Sh.10 Service Water 9.2-1 Sh.10 M-11 Sh. 1 Emergency Service Water 9.2-2 Sh. 1 M-11 Sh. 2 Emergency Service Water 9.2-2 Sh. 2 M-11 Sh. 3 Emergency Service Water 9.2-2 Sh. 3 M-11 Sh. 4 Emergency Service Water 9.2-2 Sh. 4 M-11 Sh. 5 Emergency Service Water 9.2-2 Sh. 5 M-12 Sh. 1 RHR Service Water 9.2-3 Sh. 1 M-12 Sh. 2 RHR Service Water 9.2-3 Sh. 2 M-13 Sh. 1 Reactor Enclosure Cooling Water 9.2-25 Sh. 1 M-13 Sh. 2 Reactor Enclosure Cooling Water 9.2-25 Sh. 2 M-14 Sh. 1 Turbine Enclosure Cooling Water 9.2-26 Sh. 1 M-14 Sh. 2 Turbine Enclosure Cooling Water 9.2-26 Sh. 2 M-15 Sh. 1 Compressed Air 9.3-1 Sh. 1 M-15 Sh. 2 Compressed Air 9.3-1 Sh. 2 M-15 Sh. 3 Compressed Air 9.3-1 Sh. 3 M-15 Sh. 4 Compressed Air 9.3-1 Sh. 4 M-15 Sh. 5 Compressed Air 9.3-1 Sh. 5 M-15 Sh. 6 Compressed Air 9.3-1 Sh. 6 M-15 Sh. 7 Compressed Air 9.3-1 Sh. 7 M-15 Sh. 8 Compressed Air 9.3-1 Sh. 8 M-15 Sh. 9 Compressed Air 9.3-1 Sh. 9 Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-24 REV. 18, SEPTEMBER 2016

LGS UFSAR Table 1.7-2 (Contd)

FIGURE INDEX FOR PLANT SYSTEMS P&ID Number System Former UFSAR Figure Number M-15 Sh. 10 Compressed Air 9.3-1 Sh. 10 M-15 Sh. 11 Compressed Air 9.3-1 Sh. 11 M-15 Sh. 12 Compressed Air 9.3-1 Sh. 12 M-15 Sh. 13 Compressed Air 9.3-1 Sh. 13 M-15 Sh. 14 Compressed Air 9.3-1 Sh. 14 M-15 Sh. 15 Compressed Air 9.3-1 Sh. 15 M-15 Sh. 16 Compressed Air 9.3-1 Sh. 16 M-15 Sh. 17 Compressed Air 9.3-1 Sh. 17 M-15 Sh. 18 Compressed Air 9.3-1 Sh. 18 M-15 Sh. 19 Compressed Air 9.3-1 Sh. 19 M-15 Sh. 20 Compressed Air 9.3-1 Sh. 20 M-15 Sh. 21 Compressed Air 9.3-1 Sh. 21 M-15 Sh. 22 Compressed Air 9.3-1 Sh. 22 M-15 Sh. 23 Compressed Air 9.3-1 Sh. 23 M-15 Sh. 24 Compressed Air 9.3-1 Sh. 24 M-15 Sh..25 Compressed Air 9.3-1 Sh..25 M-15 Sh..26 Compressed Air 9.3-1 Sh..26 M-15 Sh. 27 Compressed Air 9.3-1 Sh. 27 M-15 Sh. 28 Compressed Air 9.3-1 Sh. 28 M-15 Sh. 29 Compressed Air 9.3-1 Sh. 29 M-15 Sh. 30 Compressed Air 9.3-1 Sh. 30 M-15 Sh. 31 Compressed Air 9.3-1 Sh. 31 M-15 Sh. 32 Compressed Air 9.3-1 Sh. 32 M-15 Sh. 33 Compressed Air 9.3-1 Sh. 33 M-15 Sh. 34 Compressed Air 9.3-1 Sh. 34 M-15 Sh. 35 Compressed Air 9.3-1 Sh. 35 M-15 Sh. 36 Compressed Air 9.3-1 Sh. 36 M-15 Sh. 37 Compressed Air 9.3-1 Sh. 37 M-15 Sh. 38 Compressed Air 9.3-1 Sh. 38 M-15 Sh. 39 Compressed Air 9.3-1 Sh. 39 M-15 Sh. 40 Compressed Air 9.3-1 Sh. 40 M-15 Sh. 41 Compressed Air 9.3-1 Sh. 41 M-15 Sh. 42 Compressed Air 9.3-1 Sh. 42 M-15 Sh. 43 Compressed Air 9.3-1 Sh. 43 Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-25 REV. 18, SEPTEMBER 2016

LGS UFSAR Table 1.7-2 (Contd)

FIGURE INDEX FOR PLANT SYSTEMS P&ID Number System Former UFSAR Figure Number M-15 Sh. 44 Compressed Air 9.3-1 Sh. 44 M-15 Sh. 45 Compressed Air 9.3-1 Sh. 45 M-16 Sh. 1 Condensate Filter/Demineralizers 10.4-3 Sh. 1 M-16 Sh. 2 Condensate Filter/Demineralizers 10.4-3 Sh. 2 M-16 Sh. 3 Condensate Filter/Demineralizers 10.4-3 Sh. 3 M-16 Sh. 4 Condensate Filter/Demineralizers 10.4-3 Sh. 4 M-16 Sh. 5 Condensate Filter/Demineralizers 10.4-3 Sh. 5 M-16 Sh. 6 Condensate Filter/Demineralizers 10.4-3 Sh. 6 M-17 Sh. 1 Clarified Water 9.2-4 Sh. 1 M-17 Sh. 2 Clarified Water 9.2-4 Sh. 2 M-18 Sh. 1 Makeup Demineralizer 9.2-5 Sh. 1 M-18 Sh. 2 Makeup Demineralizer 9.2-5 Sh. 2 M-18 Sh. 3 Makeup Demineralizer 9.2-5 Sh. 3 M-19 Sh. 1 Lube Oil -

M-19 Sh. 2 Lube Oil -

M-19 Sh. 3 Lube Oil -

M-19 Sh. 4 Lube Oil -

M-19 Sh. 5 Lube Oil -

M-19 Sh. 6 Lube Oil -

M-19 Sh. 7 Lube Oil -

M-19 Sh. 8 Lube Oil -

M-19 Sh. 9 Lube Oil -

M-19 Sh.10 Lube Oil -

M-20 Sh. 1 Fuel & Diesel Oil Storage & Transfer -

M-20 Sh. 2 Fuel & Diesel Oil Storage & Transfer -

M-20 Sh. 3 Fuel & Diesel Oil Storage & Transfer (Fuel oil & Transfer System Unit 1 9.5-8 Sh.1 M-20 Sh. 4 Fuel & Diesel Oil Storage & Transfer (Cooling Water System Unit 1) 9.5-9 Sh.1 M-20 Sh. 5 Fuel & Diesel Oil Storage & Transfer (Cooling Water System Unit 1) 9.5-9 Sh.3 M-20 Sh. 6 Fuel & Diesel Oil Storage & Transfer (Starting Air System Unit 1) 9.5-10 Sh.1 Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-26 REV. 18, SEPTEMBER 2016

LGS UFSAR Table 1.7-2 (Contd)

FIGURE INDEX FOR PLANT SYSTEMS P&ID Number System Former UFSAR Figure Number M-20 Sh. 7 Fuel & Diesel Oil Storage & Transfer (Lube Oil System Unit 1) 9.5-11 Sh.1 M-20 Sh. 8 Fuel & Diesel Oil Storage & Transfer (Combustion air intake & Exhaust Unit 1) 9.5-12 Sh.1 M-20 Sh. 9 Fuel & Diesel Oil Storage & Transfer (Fuel Oil & Transfer System Unit 2) 9.5-8 Sh.2 M-20 Sh. 10 Fuel & Diesel Oil Storage & Transfer (Cooling Water System Unit 2) 9.5.9 Sh.2 M-20 Sh. 11 Fuel & Diesel Oil Storage & Transfer (Cooling Water System Unit 2) 9.5-9 Sh.4 M-20 Sh. 12 Fuel & Diesel Oil Storage & Transfer (Starting Air System Unit 2) 9.5-10 Sh.2 M-20 Sh. 13 Fuel & Diesel Oil Storage & Transfer (Lube Oil System Unit 2) 9.5-11 Sh.2 M-20 Sh. 14 Fuel & Diesel Oil Storage & Transfer (Combustion air intake & Exhaust Unit 2) 9.5-12 Sh.2 M-21 Sh. 1 Auxiliary Steam 10.4-6 Sh. 1 M-21 Sh. 2 Auxiliary Steam 10.4-6 Sh. 2 M-21 Sh. 3 Auxiliary Steam 10.4-6 Sh. 3 M-21 Sh. 4 Auxiliary Steam -

M-22 Sh. 1 Fire Protection 9.5-1 Sh. 1 M-22 Sh. 2 Fire Protection 9.5-1 Sh. 2 M-22 Sh. 3 Fire Protection 9.5-1 Sh. 3 M-22 Sh. 4 Fire Protection 9.5-1 Sh. 4 M-22 Sh. 5 Fire Protection 9.5-1 Sh. 5 M-22 Sh. 6 Fire Protection 9.5-1 Sh. 6 M-22 Sh. 7 Fire Protection 9.5-1 Sh. 7 M-22 Sh. 8 Fire Protection 9.5-1 Sh. 8 M-22 Sh. 9 Fire Protection 9.5-1 Sh. 9 M-22 Sh. 10 Fire Protection -

M-23 Sh. 1 Process Sampling 9.3-3 Sh. 1 M-23 Sh. 2 Process Sampling 9.3-3 Sh. 2 M-23 Sh. 3 Process Sampling 9.3-3 Sh. 3 M-23 Sh. 4 Process Sampling 9.3-3 Sh. 4 M-23 Sh. 5 Process Sampling 9.3-3 Sh. 5 M-23 Sh. 6 Process Sampling 9.3-3 Sh. 6 M-23 Sh. 7 Process Sampling 9.3-3 Sh. 7 M-23 Sh. 8 Process Sampling 9.3-3 Sh. 8 M-23 Sh. 9 Process Sampling 9.3-3 Sh. 9 Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-27 REV. 18, SEPTEMBER 2016

LGS UFSAR Table 1.7-2 (Contd)

FIGURE INDEX FOR PLANT SYSTEMS P&ID Number System Former UFSAR Figure Number M-23 Sh. 10 Process Sampling 9.3-3 Sh. 10 M-23 Sh. 11 Process Sampling 9.3-3 Sh. 11 M-24 Sh. 1 Chlorination -

M-24 Sh. 2 Chlorination -

M-25 Sh. 1 Plant Leak Detection 5.2-11 Sh. 1 M-25 Sh. 2 Plant Leak Detection 5.2-11 Sh. 2 M-25 Sh. 3 Plant Leak Detection 5.2-11 Sh. 3 M-25 Sh. 4 Plant Leak Detection 5.2-11 Sh. 4 M-26 Sh. 1 Plant Process Radiation Monitoring 11.5-1 Sh. 1 M-26 Sh. 2 Plant Process Radiation Monitoring 11.5-1 Sh. 2 M-26 Sh. 3 Plant Process Radiation Monitoring 11.5-1 Sh. 3 M-26 Sh. 4 Plant Process Radiation Monitoring 11.5-1 Sh. 4 M-26 Sh. 5 Plant Process Radiation Monitoring 11.5-1 Sh. 5 M-26 Sh. 6 Plant Process Radiation Monitoring 11.5-1 Sh. 6 M-26 Sh. 7 Plant Process Radiation Monitoring 11.5-1 Sh. 7 M-26 Sh. 8 Plant Process Radiation Monitoring 11.5-1 Sh. 8 M-26 Sh. 9 Plant Process Radiation Monitoring 11.5-1 Sh.1 M-28 Sh. 1 Generator H2 Cooling and C02 Purge 10.2-2 Sh.1 M-28 Sh. 2 Generator H2 Cooling and C02 Purge 10.2-2 Sh. 2 M-28 Sh. 3 Generator H2 Cooling and C02 Purge -

M-28 Sh. 4 Generator H2 Cooling and C02 Purge -

M-30 Sh. 1 Postaccident Sample 11.5-2 Sh.1 M-30 Sh. 2 Postaccident Sample 11.5-2 Sh. 2 M-31 Sh. 1 Main Turbine EHC -

M-31 Sh. 2 Main Turbine EHC -

M-31 Sh. 3 Main Turbine EHC -

M-31 Sh. 4 Main Turbine EHC -

M-31 Sh. 5 Main Turbine EHC -

M-31 Sh. 6 Main Turbine EHC -

M-31 Sh. 7 Main Turbine EHC -

M-31 Sh. 8 Main Turbine EHC Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-28 REV. 18, SEPTEMBER 2016

LGS UFSAR Table 1.7-2 (Contd)

FIGURE INDEX FOR PLANT SYSTEMS P&ID Number System Former UFSAR Figure Number M-33 Sh. 1 Stator Cooling -

M-33 Sh. 2 Stator Cooling -

M-41 Sh. 1 Nuclear Boiler 5.1-3 Sh. 1 M-41 Sh. 2 Nuclear Boiler 5.1-3 Sh. 2 M-41 Sh. 3 Nuclear Boiler 5.1-3 Sh. 3 M-41 Sh. 4 Nuclear Boiler 5.1-3 Sh. 4 M-41 Sh. 5 Nuclear Boiler 5.1-3 Sh. 5 M-41 Sh. 6 Nuclear Boiler 5.1-3 Sh. 6 M-42 Sh. 1 Nuclear Boiler Vessel Instrumentation 5.1-4 Sh. 1 M-42 Sh. 2 Nuclear Boiler Vessel Instrumentation 5.1-4 Sh. 2 M-42 Sh. 3 Nuclear Boiler Vessel Instrumentation 5.1-4 Sh. 3 M-42 Sh. 4 Nuclear Boiler Vessel Instrumentation 5.1-4 Sh. 4 M-42 Sh. 5 Nuclear Boiler Vessel Instrumentation -

M-42 Sh. 6 Nuclear Boiler Vessel Instrumentation -

M-43 Sh. 1 Reactor Recirculation Pump 5.4-2 Sh. 1 M-43 Sh. 2 Reactor Recirculation Pump 5.4-2 Sh. 2 M-43 Sh. 3 Reactor Recirculation Pump 5.4-2 Sh. 3 M-43 Sh. 4 Reactor Recirculation Pump 5.4-2 Sh. 4 M-44 Sh. 1 Reactor Water Cleanup 5.4-16 Sh. 1 M-44 Sh. 2 Reactor Water Cleanup 5.4-16 Sh. 2 M-44 Sh. 3 Reactor Water Cleanup 5.4-16 Sh. 3 M-44 Sh. 4 Reactor Water Cleanup 5.4-16 Sh. 4 M-45 Sh. 1 Cleanup Filter/Demineralizer 5.4-18 Sh.1 M-45 Sh. 2 Cleanup Filter/Demineralizer 5.4-18 Sh. 2 M-46 Sh. 1 Control Rod Drive Hydraulics Part A 4.6-5 Sh.1 M-46 Sh. 2 Control Rod Drive Hydraulics Part A 4.6-5 Sh. 2 M-47 Sh. 1 Control Rod Drive Hydraulics Part B 4.6-6 Sh.1 M-47 Sh 2 Control Rod Drive Hydraulics Part B 4.6-6 Sh. 2 Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-29 REV. 18, SEPTEMBER 2016

LGS UFSAR Table 1.7-2 (Contd)

FIGURE INDEX FOR PLANT SYSTEMS P&ID Number System Former UFSAR Figure Number M-48 Sh. 1 Standby Liquid Control 9.3-5 Sh.1 M-48 Sh. 2 Standby Liquid Control 9.3-5 Sh. 2 M-49 Sh. 1 Reactor Core Isolation Cooling 5.4-8 Sh.1 M-49 Sh. 2 Reactor Core Isolation Cooling 5.4-8 Sh. 2 M-50 Sh. 1 RCIC Pump-Turbine 5.4-9 Sh. 1 M-50 Sh. 2 RCIC Pump-Turbine 5.4-9 Sh. 2 M-50 Sh. 3 RCIC Pump-Turbine 5.4-9 Sh. 3 M-50 Sh. 4 RCIC Pump-Turbine 5.4-9 Sh. 4 M-51 Sh. 1 Residual Heat Removal 5.4-13 Sh. 1 M-51 Sh. 2 Residual Heat Removal 5.4-13 Sh. 2 M-51 Sh. 3 Residual Heat Removal 5.4-13 Sh. 3 M-51 Sh. 4 Residual Heat Removal 5.4-13 Sh. 4 M-51 Sh. 5 Residual Heat Removal 5.4-13 Sh. 5 M-51 Sh. 6 Residual Heat Removal 5.4-13 Sh. 6 M-51 Sh. 7 Residual Heat Removal 5.4-13 Sh. 7 M-51 Sh. 8 Residual Heat Removal 5.4-13 Sh. 8 M-52 Sh. 1 Core Spray 6.3-9 Sh. 1 M-52 Sh. 2 Core Spray 6.3-9 Sh. 2 M-52 Sh. 3 Core Spray 6.3-9 Sh. 3 M-52 Sh. 4 Core Spray 6.3-9 Sh. 4 M-53 Sh. 1 Fuel Pool Cooling 9.1-3 Sh. 1 M-53 Sh. 2 Fuel Pool Cooling 9.1-3 Sh. 2 M-53 Sh. 3 Fuel Pool Cooling 9.1-3 Sh. 3 M-53 Sh. 4 Fuel Pool Cooling 9.1-3 Sh. 4 M-54 Sh. 1 Fuel Pool Filter/Demineralizer 9.1-4 Sh. 1 M-54 Sh. 2 Fuel Pool Filter/Demineralizer 9.1-4 Sh. 2 M-55 Sh. 1 High Pressure Coolant Injection 6.3-7 Sh. 1 M-55 Sh. 2 High Pressure Coolant Injection 6.3-7 Sh. 2 Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-30 REV. 18, SEPTEMBER 2016

LGS UFSAR Table 1.7-2 (Contd)

FIGURE INDEX FOR PLANT SYSTEMS P&ID Number System Former UFSAR Figure Number M-56 Sh. 1 HPCI Pump-Turbine 6.3-8 Sh. 1 M-56 Sh. 2 HPCI Pump-Turbine 6.3-8 Sh. 2 M-56 Sh. 3 HPCI Pump-Turbine 6.3-8 Sh. 3 M-56 Sh. 4 HPCI Pump-Turbine 6.3-8 Sh. 4 M-57 Sh. 1 Containment Atmospheric Control 9.4-5 Sh. 1 M-57 Sh. 2 Containment Atmospheric Control 9.4-5 Sh. 2 M-57 Sh. 3 Containment Atmospheric Control 9.4-5 Sh. 3 M-57 Sh. 4 Containment Atmospheric Control 9.4-5 Sh. 4 M-57 Sh. 5 Containment Atmospheric Control 9.4-5 Sh. 5 M-57 Sh. 6 Containment Atmospheric Control 9.4-5 Sh. 6 M-57 Sh. 7 Containment Atmospheric Control 9.4-5 Sh. 7 M-57 Sh. 8 Containment Atmospheric Control -

M-57 Sh. 9 Containment Atmospheric Control -

M-57 Sh.10 Containment Atmospheric Control -

M-57 Sh.11 Containment Atmospheric Control -

M-58 Sh. 1 Containment Hydrogen Recombiner "A" 6.2-37 Sh. 1 M-58 Sh. 2 Containment Hydrogen Recombiner "B" 6.2-37 Sh. 2 M-58 Sh. 3 Containment Hydrogen Recombiner "A" 6.2-37 Sh. 3 M-58 Sh. 4 Containment Hydrogen Recombiner "B" 6.2-37 Sh. 4 M-59 Sh. 1 Primary Containment Instrument Gas 9.3-2 Sh. 1 M-59 Sh. 2 Primary Containment Instrument Gas 9.3-2 Sh. 2 M-59 Sh. 3 Primary Containment Instrument Gas 9.3-2 Sh. 3 M-59 Sh. 4 Primary Containment Instrument Gas 9.3-2 Sh. 4 M-60 Sh. 1 Primary Containment Leak Testing 6.2-47 Sh. 1 M-60 Sh. 2 Primary Containment Leak Testing 6.2-47 Sh. 2 M-61 Sh. 1 Liquid Radwaste Collection 9.3-4 Sh. 1 M-61 Sh. 2 Liquid Radwaste Collection 9.3-4 Sh. 2 M-61 Sh. 3 Liquid Radwaste Collection 9.3-4 Sh. 3 M-61 Sh. 4 Liquid Radwaste Collection 9.3-4 Sh. 4 M-61 Sh. 5 Liquid Radwaste Collection 9.3-4 Sh. 5 Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-31 REV. 18, SEPTEMBER 2016

LGS UFSAR Table 1.7-2 (Contd)

FIGURE INDEX FOR PLANT SYSTEMS P&ID Number System Former UFSAR Figure Number M-62 Sh. 1 Liquid Waste Equipment Drain Processing 11.2-1 Sh. 1 M-62 Sh. 2 Liquid Waste Equipment Drain Processing 11.2-1 Sh. 2 M-63 Sh. 1 Liquid Radwaste Floor Drain Processing 11.2-2 Sh. 1 M-63 Sh. 2 Liquid Radwaste Floor Drain Processing 11.2-2 Sh. 2 M-64 Sh. 1 Liquid Radwaste Chemical and Laundry Processing 11.2-3 Sh. 1 M-64 Sh. 2 Liquid Radwaste Chemical and Laundry Processing 11.2-3 Sh. 2 M-66 Sh. 1 Solid Radwaste Collection 11.4-1 Sh. 1 M-66 Sh. 2 Solid Radwaste Collection 11.4-1 Sh. 2 M-67 Sh. 1 Solid Radwaste Collection and Processing 11.4-2 Sh. 1 M-67 Sh. 2 Solid Radwaste Collection and Processing 11.4-2 Sh. 2 M-67 Sh. 3 Solid Radwaste Collection and Processing 11.4-2 Sh. 3 M-67 Sh. 4 Solid Radwaste Collection and Processing 11.4-2 Sh. 4 M-67 Sh. 5 Solid Radwaste Collection and Processing 11.4-2 Sh. 5 M-68 Sh. 1 Plant Waste Water Effluent -

M-68 Sh. 2 Plant Waste Water Effluent -

M-69 Sh 1 Gaseous Radwaste - Recombination 11.3-2 Sh 1 M-69 Sh. 2 Gaseous Radwaste - Recombination 11.3-2 Sh. 2 M-69 Sh. 3 Gaseous Radwaste - Recombination 11.3-2 Sh. 3 M-69 Sh. 4 Gaseous Radwaste - Recombination 11.3-2 Sh. 4 M-70 Sh. 1 Gaseous Radwaste - Ambient Charcoal Treatment 11.3-3 Sh. 1 M-70 Sh. 2 Gaseous Radwaste - Ambient Charcoal Treatment 11.3-3 Sh. 2 M-70 Sh. 3 Gaseous Radwaste - Ambient Charcoal Treatment 11.3-3 Sh. 3 M-70 Sh. 4 Gaseous Radwaste - Ambient Charcoal Treatment 11.3-3 Sh. 4 M-75 Sh. 1 Turbine Enclosure HVAC 9.4-4 Sh. 1 M-75 Sh. 2 Turbine Enclosure HVAC 9.4-4 Sh. 2 M-75 Sh. 3 Turbine Enclosure HVAC 9.4-4 Sh. 3 Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-32 REV. 18, SEPTEMBER 2016

LGS UFSAR Table 1.7-2 (Contd)

FIGURE INDEX FOR PLANT SYSTEMS P&ID Number System Former UFSAR Figure Number M-75 Sh. 4 Turbine Enclosure HVAC 9.4-4 Sh. 4 M-75 Sh. 5 Turbine Enclosure HVAC 9.4-4 Sh. 5 M-75 Sh. 6 Turbine Enclosure HVAC 9.4-4 Sh. 6 M-75 Sh. 7 Turbine Enclosure HVAC 9.4-4 Sh. 7 M-75 Sh. 8 Turbine Enclosure HVAC 9.4-4 Sh. 8 M-76 Sh. 1 Reactor Enclosure HVAC 9.4-2 Sh. 1 M-76 Sh. 2 Reactor Enclosure HVAC 9.4-2 Sh. 2 M-76 Sh. 3 Reactor Enclosure HVAC 9.4-2 Sh. 3 M-76 Sh. 4 Reactor Enclosure HVAC 9.4-2 Sh. 4 M-76 Sh. 5 Reactor Enclosure HVAC 9.4-2 Sh. 5 M-76 Sh. 6 Reactor Enclosure HVAC 9.4-2 Sh. 6 M-76 Sh. 7 Reactor Enclosure HVAC 9.4-2 Sh. 7 M-76 Sh. 8 Reactor Enclosure HVAC 9.4-2 Sh. 8 M-76 Sh. 9 Reactor Enclosure HVAC 9.4-2 Sh. 9 M-76 Sh.10 Reactor Enclosure HVAC 9.4-2 Sh.10 M-77 Sh. 1 Drywell Air Cooling 9.4-7 Sh.1 M-77 Sh. 2 Drywell Air Cooling 9.4-7 Sh. 2 M-78 Sh. 1 Control Structure HVAC 9.4-1 Sh. 1 M-78 Sh. 2 Control Structure HVAC 9.4-1 Sh. 2 M-78 Sh. 3 Control Structure HVAC 9.4-1 Sh. 3 M-78 Sh. 4 Control Structure HVAC 9.4-1 Sh. 4 M-79 Sh. 1 Radwaste Enclosure HVAC 9.4-3 Sh. 1 M-79 Sh. 2 Radwaste Enclosure HVAC 9.4-3 Sh. 2 M-79 Sh. 3 Radwaste Enclosure HVAC 9.4-3 Sh. 3 M-80 Sh. 1 Administration Complex, Offices-Shops-HVAC 9.4-11 Sh. 1 M-80 Sh. 2 Administration Complex, Offices-Shops-HVAC 9.4-11 Sh. 2 M-80 Sh. 3 Administration Complex, Offices-Shops-HVAC 9.4-11 Sh. 3 M-80 Sh. 4 Administration Complex, Offices-Shops-HVAC 9.4-11 Sh. 4 Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-33 REV. 18, SEPTEMBER 2016

LGS UFSAR Table 1.7-2 (Contd)

FIGURE INDEX FOR PLANT SYSTEMS P&ID Number System Former UFSAR Figure Number M-81 Sh. 1 Miscellaneous Structures HVAC 9.4-10 Sh. 1 M-81 Sh. 2 Miscellaneous Structures HVAC 9.4-10 Sh. 2 M-81 Sh. 3 Miscellaneous Structures HVAC 9.4-10 Sh. 3 M-82 Sh. 1 Hot Maintenance Shop HVAC 9.4-9 Sh.1 M-82 Sh. 2 Hot Maintenance Shop HVAC 9.4-9 Sh. 2 M-83 Sh. 1 Administration Complex Guard Station HVAC -

M-87 Sh. 1 Drywell Chilled Water 9.2-27 Sh. 1 M-87 Sh. 2 Drywell Chilled Water 9.2-27 Sh. 2 M-87 Sh. 3 Drywell Chilled Water 9.2-27 Sh. 3 M-87 Sh. 4 Drywell Chilled Water 9.2-27 Sh. 4 M-87 Sh. 5 Drywell Chilled Water 9.2-27 Sh. 5 M-87 Sh. 6 Drywell Chilled Water 9.2-27 Sh. 6 M-87 Sh. 7 Drywell Chilled Water 9.2-27 Sh. 7 M-87 Sh. 8 Drywell Chilled Water 9.2-27 Sh. 8 M-87 Sh. 9 Drywell Chilled Water 9.2-27 Sh. 9 M-87 Sh. 10 Drywell Chilled Water 9.2-27 Sh. 10 M-90 Sh. 1 Control Structure Chilled Water 9.2-28 Sh. 1 M-90 Sh. 2 Control Structure Chilled Water 9.2-28 Sh. 2 M-96 Sh. 1 Plant Heating System -

M-96 Sh. 2 Plant Heating System -

M-96 Sh. 3 Plant Heating System -

M-96 Sh. 4 Plant Heating System -

M-96 Sh. 5 Plant Heating System -

M-96 Sh. 6 Plant Heating System -

Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-34 REV. 18, SEPTEMBER 2016

LGS UFSAR Table 1.7-3 CONTROL AND INSTRUMENTATION DRAWINGS Drawing Number Title Former UFSAR Figure Number M-01FD Sh.1 Main Steam -

M-02FD Sh.1 Extraction Steam -

M-02FD Sh.2 Extraction Steam -

M-03FD Sh.1 Vents and Drains Heaters 1 & 2 Drain Cooler 1 -

M-04FD Sh.1 Vents and Drains Heaters 3, 4, 5 & 6 -

M-05FD Sh.1 Condensate System -

M-05FD Sh.2 Condensate System -

M-06FD Sh.1 Feedwater System -

M-06FD Sh.2 Feedwater System -

M-06FD Sh.3 Feedwater System -

M-07FD Sh.1 Air Removal and Sealing Steam -

M-07FD Sh.2 Air Removal and Sealing Steam -

M-07FD Sh.3 Air Removal and Sealing Steam -

M-08FD Sh.1 Condensate and Refueling Water Storage -

M-08FD Sh.2 Condensate and Refueling Water Storage -

M-09FD Sh.1 Circulating Water -

M-09FD Sh.2 Circulating Water -

M-09FD Sh.3 Circulating Water -

M-09FD Sh.4 Circulating Water -

M-09FD Sh.5 Circulating Water -

M-10FD Sh.1 Service Water -

M-10FD Sh.2 Service Water -

M-10FD Sh.3 Service Water -

M-11FD Sh.1 Emergency Service Water 7.3-21 Sh.1 M-11FD Sh.2 Emergency Service Water 7.3-21 Sh.2 M-11FD Sh.3 Emergency Service Water 7.3-21 Sh.3 M-11FD Sh.4 Emergency Service Water 7.3-21 Sh.4 M-12FD Sh.1 RHR Service Water 7.3-22 Sh.1 M-12FD Sh.2 RHR Service Water 7.3-22 Sh.2 M-12FD Sh.3 RHR Service Water 7.3-22 Sh.3 Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-35 REV. 16, SEPTEMBER 2012

LGS UFSAR Table 1.7-3 (Contd)

CONTROL AND INSTRUMENTATION DRAWINGS Drawing Number Title Former UFSAR Figure Number M-12FD Sh.4 RHR Service Water 7.3-22 Sh.4 M-12FD Sh.5 RHR Service Water 7.3-22 Sh.5 M-12FD Sh.6 RHR Service Water 7.3-22 Sh.6 M-13FD Sh.1 Reactor Building Cooling Water 7.3-17 Sh.1 M-14FD Sh.1 Turbine Building Cooling Water -

M-15FD Sh.1 Compressed Air -

M-16FD Sh.1 Condensate Filter/Demineralizers -

M-17FD Sh.1 Clarified Water -

M-18FD Sh.1 Make-Up Demineralizer -

M-19FD Sh.1 Lube Oil -

M-20FD Sh.1 Fuel and Diesel Oil Storage and Transfer -

M-21FD Sh.1 Auxiliary Steam -

M-26FD Sh.1 Radiation Monitoring -

M-41FD Sh.1 Nuclear Boiler -

M-41FD Sh.2 Nuclear Boiler -

M-42FD Sh.1 Nuclear Boiler Vessel Instrumentation -

M-45FD Sh.1 Clean-Up Filter Demineralizer -

M-46FD Sh.1 Control Rod Drive Hydraulic Part "A" -

M-49FD Sh.1 Reactor Core Isolation Cooling -

M-50FD Sh.1 Reactor Core Isolation Cooling -

M-51FD Sh.1 Residual Heat Removal 7.3-16 Sh.1 M-51FD Sh.2 Residual Heat Removal 7.3-16 Sh.2 M-51FD Sh.3 Residual Heat Removal 7.3-16 Sh.3 M-51FD Sh.4 Residual Heat Removal 7.3-16 Sh.4 M-52FD Sh.1 Core Spray 7.3-15 Sh.1 M-53FD Sh.1 Fuel Pooling Cooling and Cleanup -

M-54FD Sh.1 Fuel Pool Filter Demineralizer -

M-55FD Sh.1 High Pressure Coolant Injection 7.3-14 Sh.1 M-57FD Sh.1 Containment Atmospheric Control 7.3-18 Sh.1 M-57FD Sh.2 Containment Atmospheric Control 7.3-18 Sh.2 Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-36 REV. 16, SEPTEMBER 2012

LGS UFSAR Table 1.7-3 (Contd)

CONTROL AND INSTRUMENTATION DRAWINGS Drawing Number Title Former UFSAR Figure Number M-57FD Sh.3 Containment Atmospheric Control 7.3-18 Sh.3 M-57FD Sh.4 Containment Atmospheric Control 7.3-18 Sh.4 M-57FD Sh.5 Containment Atmospheric Control 7.3-18 Sh.5 M-59FD Sh.1 Primary Containment Instrument Gas 7.3-19 Sh.1 M-59FD Sh.2 Primary Containment Instrument Gas 7.3-19 Sh.2 M-60FD Sh.1 Primary Containment Leak Testing -

M-61FD Sh.1 Liquid Radwaste Collection 7.3-20 Sh.1 M-61FD Sh.2 Radwaste Collection 7.3-20 Sh.2 M-62FD Sh.1 Liquid Radwaste Equipment Drain Processing -

M-62FD Sh.2 Liquid Radwaste Equipment Drain Processing -

M-63FD Sh.1 Liquid Radwaste Floor Drain Processing -

M-63FD Sh.2 Liquid Radwaste Floor Drain Processing -

M-64FD Sh.1 Liquid Radwaste Chemical and Laundry Processing -

M-64FD Sh.2 Liquid Radwaste Chemical and Laundry Processing -

M-66FD Sh.1 Solid Radwaste Collection -

M-66FD Sh.2 Solid Radwaste Collection -

M-67FD Sh.1 Solid Radwaste Collection and Processing -

M-67FD Sh.2 Solid Radwaste Collection and Processing -

M-67FD Sh.3 Solid Radwaste Collection and Processing -

M-68FD Sh.1 Plant Waste Water Treatment -

M-68FD Sh.2 Plant Waste Water Treatment -

M-69FD Sh.1 Gaseous Radwaste Recombination -

M-70FD Sh.1 Gaseous Radwaste, Ambient Charcoal Treatment -

M-75FD Sh.1 Turbine Enclosure - HVAC -

M-75FD Sh.2 Turbine Enclosure - HVAC -

M-75FD Sh.3 Turbine Enclosure - HVAC -

M-75FD Sh.4 Turbine Enclosure - HVAC -

M-76FD Sh.1 Reactor Enclosure - HVAC 7.3-23 Sh.1 M-76FD Sh.2 Reactor Enclosure - HVAC 7.3-23 Sh.2 M-76FD Sh.3 Reactor Enclosure - HVAC 7.3-23 Sh.3 Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-37 REV. 16, SEPTEMBER 2012

LGS UFSAR Table 1.7-3 (Contd)

CONTROL AND INSTRUMENTATION DRAWINGS Drawing Number Title Former UFSAR Figure Number M-76FD Sh.4 Reactor Enclosure - HVAC 7.3-23 Sh.4 M-76FD Sh.5 Reactor Enclosure - HVAC 7.3-23 Sh.5 M-76FD Sh.6 Reactor Enclosure - HVAC 7.3-23 Sh.6 M-76FD Sh.7 Reactor Enclosure - HVAC 7.3-23 Sh.7 M-76FD Sh.8 Reactor Enclosure - HVAC 7.3-23 Sh.8 M-76FD Sh.9 Reactor Enclosure - HVAC 7.3-23 Sh.9 M-76FD Sh.10 Reactor Enclosure - HVAC 7.3-23 Sh.10 M-76FD Sh.11 Reactor Enclosure - HVAC 7.3-23 Sh.11 M-76FD Sh.12 Reactor Enclosure - HVAC 7.3-23 Sh.12 M-76FD Sh.13 Reactor Enclosure - HVAC 7.3-23 Sh.13 M-76FD Sh.14 Reactor Enclosure - HVAC 7.3-23 Sh.14 M-76FD Sh.15 Reactor Enclosure - HVAC 7.3-23 Sh.15 M-76FD Sh.16 Reactor Enclosure - HVAC 7.3-23 Sh.16 M-77FD Sh.1 Drywell - HVAC 7.3-13 Sh.1 M-77FD Sh.2 Drywell - HVAC 7.3-13 Sh.2 M-78FD Sh.1 Control Enclosure - HVAC 7.3-24 Sh.1 M-78FD Sh.2 Control Enclosure - HVAC 7.3-24 Sh.2 M-78FD Sh.3 Control Enclosure - HVAC 7.3-24 Sh.3 M-78FD Sh.4 Control Enclosure - HVAC 7.3-24 Sh.4 M-78FD Sh.5 Control Enclosure - HVAC 7.3-24 Sh.5 M-78FD Sh.6 Control Enclosure - HVAC 7.3-24 Sh.6 M-78FD Sh.7 Control Enclosure - HVAC 7.3-24 Sh.7 M-78FD Sh.8 Control Enclosure - HVAC 7.3-24 Sh.8 M-79FD Sh.1 Radwaste Enclosure - HVAC -

M-79FD Sh.2 Radwaste Enclosure - HVAC -

M-79FD Sh.3 Radwaste Enclosure - HVAC -

M-80FD Sh.1 Administration Complex, Offices and Shop-HVAC -

M-80FD Sh.2 Administration Complex, Offices and Shop-HVAC -

M-80FD Sh.3 Administration Complex, Offices and Shop-HVAC -

M-80FD Sh.4 Administration Complex, Offices and Shop-HVAC -

Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-38 REV. 16, SEPTEMBER 2012

LGS UFSAR Table 1.7-3 (Contd)

CONTROL AND INSTRUMENTATION DRAWINGS Drawing Number Title Former UFSAR Figure Number M-80FD Sh.5 Administration Complex, Offices and Shop-HVAC -

M-80FD Sh.6 Administration Complex, Offices and Shop-HVAC -

M-80FD Sh.7 Administration Complex, Offices and Shop-HVAC -

M-80FD Sh.8 Administration Complex, Offices and Shop-HVAC -

M-80FD Sh.9 Administration Complex, Offices and Shop-HVAC -

M-80FD Sh.10 Administration Complex, Offices and Shop-HVAC -

M-80FD Sh.11 Administration Complex, Offices and Shop-HVAC -

M-80FD Sh.12 Administration Complex, Offices and Shop-HVAC -

M-81FD Sh.1 Miscellaneous Structures-HVAC 7.3-12 Sh.1 M-81FD Sh.2 Miscellaneous Structures-HVAC 7.3-12 Sh.2 M-81FD Sh.3 Miscellaneous Structures-HVAC 7.3-12 Sh.3 M-81FD Sh.4 Miscellaneous Structures-HVAC 7.3-12 Sh.4 M-82FD Sh.1 Administration Complex, Hot Maintenance Shop -

M-82FD Sh.2 Administration Complex, Hot Maintenance Shop -

M-82FD Sh.3 Administration Complex, Hot Maintenance Shop -

M-82FD Sh.4 Administration Complex, Hot Maintenance Shop -

M-82FD Sh.5 Administration Complex, Hot Maintenance Shop -

M-82FD Sh.6 Administration Complex, Hot Maintenance Shop -

M-82FD Sh.7 Administration Complex, Hot Maintenance Shop -

M-82FD Sh.8 Administration Complex, Hot Maintenance Shop -

M-83FD Sh.1 Administration Complex, Guard Station -

M-83FD Sh.2 Administration Complex, Guard Station -

M-83FD Sh.3 Administration Complex, Guard Station -

M-83FD Sh.4 Administration Complex, Guard Station -

M-83FD Sh.5 Administration Complex, Guard Station -

M-83FD Sh.6 Administration Complex, Guard Station -

M-83FD Sh.7 Administration Complex, Guard Station -

M-87FD Sh.1 Drywell Chilled Water -

M-87FD Sh.2 Drywell Chilled Water -

M-87FD Sh.3 Drywell Chilled Water -

Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-39 REV. 16, SEPTEMBER 2012

LGS UFSAR Table 1.7-3 (Contd)

CONTROL AND INSTRUMENTATION DRAWINGS Drawing Number Title Former UFSAR Figure Number M-90FD Sh.1 Control Structure Chilled Water 7.3-25 Sh.1 M-96FD Sh.1 Plant Heating Steam -

M-602 Sh.1 Control Room Arrangement - El. 269' 7.5-1 Sh.1 M-602 Sh.2 Control Room Arrangement - El. 269' 7.5-1 Sh.2 M-603 Sh.1 Auxiliary Equipment Room Arrangement el 289'-0" 7.5-2 Sh.1 M-603 Sh.2 Auxiliary Equipment Room Arrangement el 289'-0" 7.5-2 Sh.2 M-675 Sh.1 Unit 1 - Turbine Building Instrument Location Plan el 217'-0" Area 1 -

M-676 Sh.1 Unit 1 - Turbine Building Instrument Location Plan el 239'-0" Area 1 -

M-677 Sh.1 Unit 1 - Turbine Building Instrument Location Plan el 255'-0" Area 1 7.2-11 Sh.1 M-678 Sh.1 Unit 1 - Turbine Building Instrument Location Plan el 269'-0" Area 1 -

M-679 Sh.1 Unit 1 - Turbine Building Instrument Location Plan el 189'-0" Area 2 -

M-680 Sh.1 Unit 1 - Turbine Building Instrument Location Plan el 217'-0" Area 2 -

M-681 Sh.1 Unit 1 - Turbine Building Instrument Location Plan el 239'-0" Area 2 -

M-682 Sh.1 Unit 1 - Turbine Building Instrument Location Plan el 255'-0" Area 2 -

M-683 Sh.1 Unit 1 - Turbine Building Instrument Location Plan el 269'-0" Area 2 -

M-685 Sh.1 Unit 1 - Turbine Building Instrument Location Plan el 189'-0" Area 3 -

M-686 Sh.1 Unit 1 - Turbine Building Instrument Location Plan el 217'-0" Area 3 -

M-687 Sh.1 Unit 1 - Turbine Building Instrument Location Plan el 239'-0" Area 3 -

M-688 Sh.1 Unit 1 - Turbine Building Instrument Location Plan el 269'-0" Area 3 -

M-689 Sh.1 Unit 1 - Turbine Building Instrument Location Plan el 200'-0" Area 6 -

M-690 Sh.1 Unit 1 - Turbine Building Instrument Location Plan el 217'-0" Area 6 -

M-691 Sh.1 Unit 1 - Turbine Building Instrument Location Plan el 239'-0" Area 6 -

M-693 Sh.1 Unit 1 - Turbine Building Instrument Location Plan el 269'-0" Area 6 -

M-695 Sh.1 Unit 1 - Turbine Building Instrument Location Plan el 200'-0" Area 7 -

M-696 Sh.1 Unit 1 - Turbine Building Instrument Location Plan el 217'-0" Area 7 -

M-697 Sh.1 Unit 1 - Turbine Building Instrument Location Plan el 239'-0" Area 7 -

M-699 Sh.1 Unit 1 - Turbine Building Instrument Location Plan el 269'-0" Area 7 -

Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-40 REV. 16, SEPTEMBER 2012

LGS UFSAR Table 1.7-3 (Contd)

CONTROL AND INSTRUMENTATION DRAWINGS Drawing Number Title Former UFSAR Figure Number M-700 Sh.1 Unit 1 - Turbine Building Instrument Location Plan el 285'-0" Area 7 -

M-701 Sh.1 Unit 1 - Turbine Building Instrument Location Plan el 180'-0" Area 8 -

M-701 Sh.2 Unit 1 - Turbine Building Instrument Location Plan el 180'-0" Area 8 -

M-702 Sh.1 Unit 1 - Turbine Building Instrument Location Plan el 180'-0" Area 8 -

M-703 Sh.1 Unit 1 - Turbine Building Instrument Location Plan el 180'-0" Area 8 -

M-704 Sh.1 Unit 1 - Turbine Building Instrument Location Plan el 200'-0" Area 8 -

M-704 Sh.2 Unit 1 - Turbine Building Instrument Location Plan el 200'-0" Area 8 -

M-705 Sh.1 Unit 1 - Reactor Building Instrument Location Plan el 177'-0" Area 11 -

M-706 Sh.1 Unit 1 - Reactor Building Instrument Location Plan el 201'-0" Area 11 -

M-707 Sh.1 Unit 1 - Reactor Building Instrument Location Plan el 217'-0" Area 11 -

M-708 Sh.1 Unit 1 - Reactor Building Instrument Location Plan el 253'-0" Area 11 -

M-709 Sh.1 Unit 1 - Reactor Building Instrument Location Plan el 283'-0" Area 11 -

M-710 Sh.1 Unit 1 - Reactor Building Instrument Location Plan el 313'-0" Area 11 -

M-711 Sh.1 Unit 1 - Reactor Building Instrument Location Plan el 177'-0" Area 12 -

M-712 Sh.1 Unit 1 - Reactor Building Instrument Location Plan el 201'-0" Area 12 -

M-713 Sh.1 Unit 1 - Reactor Building Instrument Location Plan el 217'-0" Area 12 -

M-714 Sh.1 Unit 1 - Reactor Building Instrument Location Plan el 253'-0" Area 12 -

M-715 Sh.1 Unit 1 - Reactor Building Instrument Location Plan el 283'-0" Area 12 -

M-716 Sh.1 Unit 1 - Reactor Building Instrument Location Plan el 313'-0" Area 12 -

M-717 Sh.1 Unit 1 - Reactor Building Instrument Location Plan el 177'-0" Area 15 -

M-718 Sh.1 Unit 1 - Reactor Building Instrument Location Plan el 201'-0" Area 15 -

M-719 Sh.1 Unit 1 - Reactor Building Instrument Location Plan el 217'-0" Area 15 -

M-720 Sh.1 Unit 1 - Reactor Building Instrument Location Plan el 253'-0" Area 15 -

M-721 Sh.1 Unit 1 - Reactor Building Instrument Location Plan el 283'-0" Area 15 -

M-722 Sh.1 Unit 1 - Reactor Building Instrument Location Plan el 313'-0" Area 15 -

M-723 Sh.1 Unit 1 - Reactor Building Instrument Location Plan el 177'-0" Area 16 -

M-724 Sh.1 Unit 1 - Reactor Building Instrument Location Plan el 201'-0" Area 16 -

M-725 Sh.1 Unit 1 - Reactor Building Instrument Location Plan el 217'-0" Area 16 -

M-726 Sh.1 Unit 1 - Reactor Building Instrument Location Plan el 253'-0" Area 16 -

Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-41 REV. 16, SEPTEMBER 2012

LGS UFSAR Table 1.7-3 (Contd)

CONTROL AND INSTRUMENTATION DRAWINGS Drawing Number Title Former UFSAR Figure Number M-727 Sh.1 Unit 1 - Reactor Building Instrument Location Plan el 283'-0" Area 16 -

M-728 Sh.1 Unit 1 - Reactor Building Instrument Location Plan el 313'-0" Area 16 -

M-729 Sh.1 Unit 1 - Radwaste Piping Tunnel -

M-730 Sh.1 Unit 1 - Radwaste Piping Tunnel -

M-731 Sh.1 Unit 1 - Reactor Building Plan el 352'-0" Area 11 -

M-732 Sh.1 Unit 1 - Reactor Building Plan el 352'-0" Area 12 -

M-733 Sh.1 Unit 1 - Reactor Building Plan el 352'-0" Area 15 -

M-734 Sh.1 Unit 1 - Reactor Building Plan el 352'-0" Area 16 -

M-735 Sh.1 Unit 2 - Radwaste Building Instrument Location Plan el 195'-0" Area 19 -

M-736 Sh.1 Unit 2 - Radwaste Building Instrument Location Plan el 162'-0" Area 20 -

M-737 Sh.1 Unit 2 - Radwaste Building Instrument Location Plan el 191'-0" Area 20 -

M-738 Sh.1 Unit 2 - Radwaste Building Instrument Location Plan el 217'-0" Area 20 -

M-740 Sh.1 Unit 2 - Radwaste Building Instrument Location Plan el 195'-0" Area 21 -

M-741 Sh.1 Unit 2 - Radwaste Building Instrument Location Plan el 162'-0" Area 22 -

M-742 Sh.1 Unit 2 - Radwaste Building Instrument Location Plan el 191'-0" Area 22 -

M-743 Sh.1 Unit 2 - Radwaste Building Instrument Location Plan el 217'-0" Area 22 -

M-744 Sh.1 Unit 2 - Radwaste Building Instrument Location Plan el 257'-0" Area 22 -

M-745 Sh.1 Unit 2 - Radwaste Building Instrument Location Plan el 162'-0" Area 23 -

M-746 Sh.1 Unit 2 - Radwaste Building Instrument Location Plan el 191'-0" Area 23 -

M-747 Sh.1 Unit 2 - Radwaste Building Instrument Location Plan el 237'-0" Area 20 -

M-748 Sh.1 Unit 2 - Radwaste Building Instrument Location Plan el 257'-0" Area 20 -

M-749 Sh.1 Unit 1 - Reactor Building Tunnel el 198'-0" Areas 15 and 16 -

M-750 Sh.1 Unit 1 - Turbine Building el 302'-0" Area 6 -

M-751 Sh.1 Unit 1 - Turbine Building el 302'-0" Area 7 -

M-752 Sh.1 Control Area el 304'-0" Area 8 -

M-753 Sh.1 Control Area el 332'-0" Area 8 -

M-754 Sh.1 Control Area el 350'-0" Area 8 -

M-755 Sh.1 Instrument Location Drawing Radwaste Building Plan el 217'-0" Area 19 -

M-756 Sh.1 Instrument Location Condensate & Refueling Water -

M-757 Sh.1 Auxiliary Boiler el 217'-0" and 230'-9" Storage Tank, Piping Plan & Section -

Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-42 REV. 16, SEPTEMBER 2012

LGS UFSAR Table 1.7-3 (Contd)

CONTROL AND INSTRUMENTATION DRAWINGS Drawing Number Title Former UFSAR Figure Number M-758 Sh.1 Fuel Oil Tank, Condensation Storage Tank Number 2 and Pump House -

M-759 Sh.1 Unit 1 - Instrument Location Plan Circulating Water Pump House -

M-760 Sh.1 Unit 1 - Instrument Location Plan Service Water Pump -

M-761 Sh.1 Unit 2 - Instrument Location Plan Circulating Water Pump House -

M-762 Sh.1 Instrument Installation Detail Circulating Water Pumps -

M-763 Sh.1 Instrument Location Circulating Water, Chlorination and H2SO4 FD System -

M-764 Sh.1 Instrument Location Water Treatment Building -

M-765 Sh.1 Instrument Installation Detail Water Treatment Building -

Sh.2 Instrument Installation Detail Water Treatment Building M-765 Sh.1 Instrument Installation Detail Water Treatment Building -

M-766 Sh.1 Instrument Location Drawing Unit 1 - Reactor Building el 331'-0" Area 16 -

M-767 Sh.1 Instrument Location Drawing Spray Pond Pumphouse -

M-768 Sh.1 Instrument Location Drawing Hydrogen Generating Facility -

M-769 Sh.1 Yard Work - Partial Area H and J Valve and Meter Pit -

M-838 Sh.1 Supports for Condenser Water Box Instrument Lines Units 1 and 2 -

M-840 Sh.1 Drywell Plan el 253'-0" Areas 11, 12, 15 and 16 -

M-841 Sh.1 Administration Building, Shop and Warehouse el 217'-0" -

M-842 Sh.1 Administration Building, Shop and Warehouse el 203'-0", 230'-0" and 269'-0" -

M-843 Sh.1 Units 1 and 2 Control Area 8 el 269'-0" -

M-844 Sh.1 Units 1 and 2 Control Area 8 el 289'-0" -

M-845 Sh.1 Instrument Location Drawing - Yard Work -

M-846 Sh.1 Instrument Location Drawing - Diesel Oil Storage and Yard el 217'-0" -

M-847 Sh.1 Unit 1 - Instrument Location Drawing Diesel Generator Enclosure el 217'-0" -

M-848 Sh.1 Instrument Location Drawing Reactor Roof Units 1 and 2 Plan at el 411'-9" -

M-849 Sh.1 Instrument Location Radwaste Building Plan at el 237'-0" Area 22 -

M-850 Sh.1 Instrument Location Drawing Suppression Pool Platforms -

M-883 Sh.1 Containment Leak Detection Radiation Monitor Seismic Modifications -

M-969 Sh.1 Process Diagram Gaseous Radwaste - Recombiners -

M-970 Sh.1 Process Diagram Off Gas Charcoal Absorber System -

Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-43 REV. 16, SEPTEMBER 2012

LGS UFSAR Table 1.7-3 (Contd)

CONTROL AND INSTRUMENTATION DRAWINGS Drawing Number Title Former UFSAR Figure Number M-1500 Sh.1 Unit 2 - Turbine Building Instrument Location Plan el 189'-0" Area 4 -

M-1501 Sh.1 Unit 2 - Turbine Building Instrument Location Plan el 217'-0" Area 4 -

M-1502 Sh.1 Unit 2 - Turbine Building Instrument Location Plan el 239'-0" Area 4 -

M-1503 Sh.1 Unit 2 - Turbine Building Instrument Location Plan el 255'-0" Area 4 -

M-1504 Sh.1 Unit 2 - Turbine Building Instrument Location Plan el 269'-0" Area 4 -

M-1507 Sh.1 Unit 2 - Turbine Building Instrument Location Plan el 217'-0" Area 5 -

M-1508 Sh.1 Unit 2 - Turbine Building Instrument Location Plan el 239'-0" Area 5 -

M-1509 Sh.1 Unit 2 - Turbine Building Instrument Location Plan el 255'-0" Area 5 -

M-1510 Sh.1 Unit 2 - Turbine Building Instrument Location Plan el 269'-0" Area 5 -

M-1511 Sh.1 Unit 2 - Turbine Building Instrument Location Plan el 200'-0" Area 9 -

M-1512 Sh.1 Unit 2 - Turbine Building Instrument Location Plan el 217'-0" Area 9 -

M-1513 Sh.1 Unit 2 - Turbine Building Instrument Location Plan el 239'-0" Area 9 -

M-1515 Sh.1 Unit 2 - Turbine Building Instrument Location Plan el 269'-0" Area 9 -

M-1516 Sh.1 Unit 2 - Turbine Building Instrument Location Plan el 285'-0" Area 9 -

M-1517 Sh.1 Unit 2 - Turbine Building Instrument Location Plan el 302'-0" Area 9 -

M-1520 Sh.1 Unit 2 - Turbine Building Instrument Location Plan el 200'-0" Area 10 -

M-1521 Sh.1 Unit 2 - Turbine Building Instrument Location Plan el 217'-0" Area 10 -

M-1522 Sh.1 Unit 2 - Turbine Building Instrument Location Plan el 236'-0" Area 10 -

M-1524 Sh.1 Unit 2 - Turbine Building Instrument Location Plan el 269'-0" Area 10 -

M-1526 Sh.1 Unit 2 - Turbine Building Instrument Location Plan el 302'-0" Area 10 -

M-1527 Sh.1 Unit 2 - Turbine Building Instrument Location Plan el 180'-0" Area 8 -

M-1529 Sh.1 Unit 2 - Diesel Generator Instrument Location Plan el 217'-0" -

M-1530 Sh.1 Unit 2 - Reactor Building Instrument Location Plan el 177'-0" Area 13 -

M-1531 Sh.1 Unit 2 - Reactor Building Instrument Location Plan el 201'-0" Area 13 -

M-1532 Sh.1 Unit 2 - Reactor Building Instrument Location Plan el 217'-0" Area 13 -

M-1533 Sh.1 Unit 2 - Reactor Building Instrument Location Plan el 253'-0" Area 13 -

M-1534 Sh.1 Unit 2 - Reactor Building Instrument Location Plan el 283'-0" Area 13 -

M-1535 Sh.1 Unit 2 - Reactor Building Instrument Location Plan el 313'-0" Area 13 -

M-1536 Sh.1 Unit 2 - Reactor Building Instrument Location Plan el 177'-0" Area 14 -

M-1537 Sh.1 Unit 2 - Reactor Building Instrument Location Plan el 201'-0" Area 14 -

M-1538 Sh.1 Unit 2 - Reactor Building Instrument Location Plan el 217'-0" Area 14 -

Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-44 REV. 16, SEPTEMBER 2012

LGS UFSAR Table 1.7-3 (Contd)

CONTROL AND INSTRUMENTATION DRAWINGS Drawing Number Title Former UFSAR Figure Number M-1539 Sh.1 Unit 2 - Reactor Building Instrument Location Plan el 253'-0" Area 14 -

M-1540 Sh.1 Unit 2 - Reactor Building Instrument Location Plan el 283'-0" Area 14 -

M-1541 Sh.1 Unit 2 - Reactor Building Instrument Location Plan el 313'-0" Area 14 -

M-1542 Sh.1 Unit 2 - Reactor Building Instrument Location Plan el 177'-0" Area 17 -

M-1543 Sh.1 Unit 2 - Reactor Building Instrument Location Plan el 201'-0" Area 17 -

M-1544 Sh.1 Unit 2 - Reactor Building Instrument Location Plan el 217'-0" Area 17 -

M-1545 Sh.1 Unit 2 - Reactor Building Instrument Location Plan el 253'-0" Area 17 -

M-1546 Sh.1 Unit 2 - Reactor Building Instrument Location Plan el 283'-0" Area 17 -

M-1547 Sh.1 Unit 2 - Reactor Building Instrument Location Plan el 313'-0" Area 1 -

M-1548 Sh.1 Unit 2 - Reactor Building Piping Tunnel Areas 17 and 18 -

M-1550 Sh.1 Unit 2 - Reactor Building Instrument Location Plan el 177'-0" Area 18 -

M-1551 Sh.1 Unit 2 - Reactor Building Instrument Location Plan el 201'-0" Area 18 -

M-1552 Sh.1 Unit 2 - Reactor Building Instrument Location Plan el 217'-0" Area 18 -

M-1553 Sh.1 Unit 2 - Reactor Building Instrument Location Plan el 253'-0" Area 18 -

M-1554 Sh.1 Unit 2 - Reactor Building Instrument Location Plan el 283'-0" Area 18 -

M-1555 Sh.1 Unit 2 - Reactor Building Instrument Location Plan el 313'-0" Area 18 -

M-1556 Sh.1 Unit 2 - Reactor Building el 352'-0" Area 13 -

M-1557 Sh.1 Unit 2 - Reactor Building el 352'-0" Area 14 -

M-1558 Sh.1 Unit 2 - Reactor Building el 352'-0" Area 17 -

M-1559 Sh.1 Unit 2 - Reactor Building el 352'-0" Area 18 -

M-1560 Sh.1 Unit 2 - Radwaste Tunnel Piping -

M-1561 Sh.1 Unit 2 - Radwaste Tunnel Piping -

M-1562 Sh.1 Unit 2 - Radwaste Tunnel Piping -

M-1563 Sh.1 Unit 2 - Instrument Location Plan Circulating Water and H2SO4 -

M-1564 Sh.1 Reactor Units 1 and 2 Instrument Location Plan (North Stack) el 364'-0" to 410'-0" -

M-1565 Sh.1 Reactor Units 1 and 2 Instrument Location Plan (South Stack) el 352'-0" to 398'-7" -

M-1566 Sh.1 Drywell Plan el 253'-0" Areas 13, 14, 17 and 18 -

Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-45 REV. 16, SEPTEMBER 2012

LGS UFSAR Table 1.7-4 FIGURE INDEX FOR MISC. DRAWINGS Drawing Number Title Former UFSAR Figure Number B21-1030-F-001 GE FCD - Nuclear Boiler System 7.3-8 Sh.1 B21-1030-F-002 GE FCD - Nuclear Boiler System 7.3-8 Sh.2 B21-1030-F-002 Sh.2 GE FCD - Nuclear Boiler System 7.3-8 Sh.3 B21-1030-F-003 GE FCD - Nuclear Boiler System 7.3-8 Sh.4 B21-1030-F-004 GE FCD - Nuclear Boiler System 7.3-8 Sh.5 B21-1030-F-005 GE FCD - Nuclear Boiler System 7.3-8 Sh.6 B32-1020-F-002 GE FCD - Reactor Recirculation System 7.7-6 Sh.1 B32-1020-F-003 GE FCD - Reactor Recirculation System 7.7-6 Sh.2 B32-1020-F-004 GE FCD - Reactor Recirculation System 7.7-6 Sh.3 B32-1020-F-005 GE FCD - Reactor Recirculation System 7.7-6 Sh.4 B32-1020-F-006 GE FCD - Reactor Recirculation System 7.7-6 Sh.5 C11-1020-G-004 GE Process Diagram - Control Rod Drive System 4.6-7 Sh.1 C11-1020-G-005 GE Process Diagram - Control Rod Drive System 4.6-7 Sh.2 C11-1020-G-006 GE Process Diagram - Control Rod Drive System 4.6-7 Sh.3 C11-1020-G-007 GE Process Diagram - Control Rod Drive System 4.6-7 Sh.4 C11-1030-F-008 GE FCD - Reactor Recirculation System 7.7-2 Sh.1 C11-1030-F-009 GE FCD - Reactor Recirculation System 7.7-2 Sh.2 C11-1030-F-010 GE FCD - Reactor Recirculation System 7.7-2 Sh.3 C11-1030-F-011 GE FCD - Reactor Recirculation System 7.7-2 Sh.4 C11-1030-F-012 GE FCD - Reactor Recirculation System 7.7-2 Sh.5 C11-1030-F-013 GE FCD - Reactor Recirculation System 7.7-2 Sh.6 C11-1030-F-014 GE FCD - Control Rod Drive System 7.7-2 Sh.7 C32-1010-F-001 GE IED - Feedwater Control System - Turbine Feedpump 7.7-8 Sh.1 C41-1030-F-002 GE FCD - Standby Liquid Control System 7.4-2 Sh.1 C41-1030-F-003 GE FCD - Standby Liquid Control System 7.4-2 Sh.2 C41-1030-F-004 GE FCD - Standby Liquid Control System 7.4-2 Sh.3 C51-1010-F-002 GE FCD - Neutron Monitoring System 7.6-1 Sh.1 C51-1010-F-003 GE FCD - Neutron Monitoring System 7.6-1 Sh.2 C51-1010-F-004 Sh.1 GE FCD - Neutron Monitoring System 7.6-1 Sh.3 C51-1010-F-004 Sh.2 GE FCD - Neutron Monitoring System 7.6-1 Sh.4 C51-1020-F-009 GE FCD - Neutron Monitoring System 7.6-4 Sh.1 C51-1020-F-010 GE FCD - Neutron Monitoring System 7.6-4 Sh.2 C51-1020-F-011 GE FCD - Neutron Monitoring System 7.6-4 Sh.3 C51-1020-F-012 GE FCD - Neutron Monitoring System 7.6-4 Sh.4 Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-46 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.7-4 (Contd)

FIGURE INDEX FOR MISC. DRAWINGS Drawing Number Title Former UFSAR Figure Number C51-1020-F-013 GE FCD - Neutron Monitoring System 7.6-4 Sh.5 C51-1020-F-014 GE FCD - Neutron Monitoring System 7.6-4 Sh.6 C51-1020-F-015 GE FCD - Neutron Monitoring System 7.6-4 Sh.7 C51-1020-F-016 Sh.1 GE FCD - Neutron Monitoring System 7.6-4 Sh.8 C51-1020-F-016 Sh.2 GE FCD - Neutron Monitoring System 7.6-4 Sh.9 C51-1020-F-016 Sh.3 GE FCD - Neutron Monitoring System 7.6-4 Sh.10 C51-1020-F-016 Sh.4 GE FCD - Neutron Monitoring System 7.6-4 Sh.11 C51-1020-F-016 Sh.5 GE FCD - Neutron Monitoring System 7.6-4 Sh.12 C51-1020-F-016 Sh.6 GE FCD - Neutron Monitoring System 7.6-4 Sh.13 C51-1020-F-016 Sh.7 GE FCD - Neutron Monitoring System 7.6-4 Sh.14 C71-1010-F-002 GE IED - Reactor Protection System 7.2-1 Sh.1 C71-1010-F-003 GE IED - Reactor Protection System 7.2-1 Sh.2 C71-1010-F-004 GE IED - Reactor Protection System 7.2-1 Sh.3 C71-1010-F-005 GE IED - Reactor Protection System 7.2-1 Sh.4 DBA-110-E0001 Sh.1 RPV Head Vent Piping Isometric - Unit 1 3.6-30 Sh.1 DBA-110-J0001 Sh.1 RPV Head Vent Piping Isometric - Unit 1 3.6-30 Sh.1 E11-1020-G002 Sh.1 GE Process Diagram - Residual Heat Removal System 6.3-3 Sh.1 E11-1020-G002 Sh.2 GE Process Diagram - Residual Heat Removal System 6.3-3 Sh.2 E11-1020-G002 Sh.3 GE Process Diagram - Residual Heat Removal System 6.3-3 Sh.3 E11-1030-F-001 GE FCD - Residual Heat Removal System 7.3-10 Sh.1 E11-1030-F-001 Sh.1A GE FCD - Residual Heat Removal System 7.3-10 Sh.1 E11-1030-F-002 GE FCD - Residual Heat Removal System 7.3-10 Sh.1 E11-1030-F-003 GE FCD - Residual Heat Removal System 7.7-10 Sh.3 E11-1030-F-003 Sh.1A GE FCD - Residual Heat Removal System 7.3-10 Sh.3 E21-1020-G-001 GE Process Diagram - Core Spray System 6.3-2 Sh.1 E21-1030-F-004 GE FCD - Core Spray System 7.3-9 Sh.1 E21-1030-F-005 GE FCD - Core Spray System 7.3-9 Sh.2 E41-1020-G-002 GE Process Diagram - High Pressure Coolant Injection System 6.3-1 Sh.1 E41-1030-F-004 GE FCD - High Pressure Coolant Injection System 7.3-7 Sh.1 Sh.2 GE FCD - High Pressure Coolant Injection System 7.3-7 Sh.2 E41-1030-F-005 GE FCD - High Pressure Coolant Injection System 7.3-7 Sh.3 Sh.2 GE FCD - High Pressure Coolant Injection System 7.3-7 Sh.4 E41-1030-F-006 GE FCD - High Pressure Coolant Injection System 7.3-7 Sh.5 E41-1030-F-007 GE FCD - High Pressure Coolant Injection System 7.3-7 Sh.6 Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-47 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.7-4 (Contd)

FIGURE INDEX FOR MISC. DRAWINGS Drawing Number Title Former UFSAR Figure Number E41-1030-F-008 GE FCD - High Pressure Coolant Injection System 7.3-7 Sh.7 E41-1030-F-009 GE FCD - High Pressure Coolant Injection System 7.3-7 Sh.8 E51-1020-G-002 GE Process Diagram - Reactor Core Isolation Cooling System 5.4-10 Sh.1 E51-1030-F-004 GE FCD - Reactor Core Isolation Cooling System 7.4-1 Sh.1 E51-1030-F-004 Sh.2 GE FCD - Reactor Core Isolation Cooling System 7.4-1 Sh.2 E51-1030-F-005 GE FCD - Reactor Core Isolation Cooling System 7.4-1 Sh.3 E51-1030-F-006 GE FCD - Reactor Core Isolation Cooling System 7.4-1 Sh.4 E51-1030-F-007 GE FCD - Reactor Core Isolation Cooling System 7.4-1 Sh.5 E51-1030-F-008 GE FCD - Reactor Core Isolation Cooling System 7.4-1 Sh.6 E51-1030-F-009 GE FCD - Reactor Core Isolation Cooling System 7.4-1 Sh.7 G31-1020-F-001 GE FCD - Reactor Water Cleanup System 7.7.11 Sh.1 G31-1030-G-001 GE Process Diagram - Reactor Water Cleanup System 5.4.17 Sh.1 N-00E-246-00193 Sh.1 Heat Balance Diagram-100% 10.1-1 Sh.1 C-2 Sh.1 Yardwork - Plot Plan 1.2-1 Sh.1 C-11 Sh.1 Yardwork - Fire Sytem 9A-3 Sh.1 C-12 Sh.1 Yardwork - Domestic Water System 9.2-29 Sh.1 M-110 Sh.1 Equipment Location - Turbine Enclosure - Unit 1 - Plan at El 200' 1.2-17 Sh.1 M-111 Sh.1 Equipment Location - Turbine Enclosure - Unit 1 - Plan at El 217' 1.2-19 Sh.1 M-112 Sh.1 Equipment Location - Turbine Enclosure - Unit 1 and Control Structure - Plan at El 239' 1.2-21 Sh.1 M-113 Sh.1 Equipment Location - Turbine Enclosure - Unit 1 - Plan at El 269' 1.2-23 Sh.1 M-114 Sh.1 Equipment Location - Turbine Enclosure - Unit 1 - Section A-A 1.2-28 Sh.1 M-115 Sh.1 Equipment Location - Turbine Enclosure - Unit 1 and Control Structure - Plan at El 302' & 304' 1.2-25 Sh.1 M-116 Sh.1 Equipment Location - Reactor Enclosure - Unit 1 - Plan at El 177' 1.2-2 Sh.1 M-117 Sh.1 Equipment Location - Reactor Enclosure - Unit 1 - Plan at El 201' 1.2-4 Sh.1 M-118 Sh.1 Equipment Location - Reactor Enclosure - Unit 1 - Plan at El 217' 1.2-6 Sh.1 M-119 Sh.1 Equipment Location - Reactor Enclosure - Unit 1 - Plan at El 253' 1.2-8 Sh.1 M-120 Sh.1 Equipment Location - Reactor Enclosure - Unit 1 & 2 - Plan at El 283' 1.2-10 Sh.1 M-121 Sh.1 Equipment Location - Reactor Enclosure - Unit 1 - Plan at El 313' 1.2-12 Sh.1 M-122 Sh.1 Equipment Location - Reactor Enclosure Refueling Area - Unit 1 - Plan at El 352' 1.2-14 Sh.1 Sh.1 9.1-17A Sh.1 M-123 Sh.1 Equipment Location - Reactor Enclosure - Unit 1 - Section A-A 1.2-16 Sh.1 Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-48 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.7-4 (Contd)

FIGURE INDEX FOR MISC. DRAWINGS Drawing Number Title Former UFSAR Figure Number M-124 Sh.1 Equipment Location - Control Structure - Plan at El 321', 332', and 350' 1.2-27 Sh.1 M-125 Sh.1 Equipment Location - Turbine Enclosure - Unit 2 - Plan at El 200' 1.2-18 Sh.1 M-126 Sh.1 Equipment Location - Turbine Enclosure - Unit 2 - Plan at El 217' 1.2-20 Sh.1 M-127 Sh.1 Equipment Location - Turbine Enclosure - Unit 2 and Control Structure - Plan at El 239' 1.2-22 Sh.1 M-128 Sh.1 Equipment Location - Turbine Enclosure - Unit 2 - Plan at El 269' 1.2-24 Sh.1 M-129 Sh.1 Equipment Location - Turbine Enclosure - Unit 2 - Section A-A 1.2-29 Sh.1 M-130 Sh.1 Equipment Location - Turbine Enclosure - Unit 2 and Control Structure - Plan at El 302' & 304' 1.2-26 Sh.1 M-131 Sh.1 Equipment Location - Reactor Enclosure - Unit 2 - Plan at El 177' 1.2-3 Sh.1 M-132 Sh.1 Equipment Location - Reactor Enclosure - Unit 2 - Plan at El 201' 1.2-5 Sh.1 M-133 Sh.1 Equipment Location - Turbine Enclosure - Unit 2 - Plan at El 217' 1.2-7 Sh.1 M-134 Sh.1 Equipment Location - Reactor Enclosure - Unit 2 - Plan at El 253' 1.2-9 Sh.1 M-135 Sh.1 Equipment Location - Reactor Enclosure - Unit 2 - Plan at El 283' 1.2-11 Sh.1 M-136 Sh.1 Equipment Location - Reactor Enclosure - Unit 2 - Plan at El 313' 1.2-13 Sh.1 M-137 Sh.1 Equipment Location - Reactor Enclosure Refueling Area - Unit 2 - Plan at El 352' 1.2-15 Sh.1 Sh.1 9.1-17B Sh.1 M-138 Sh.1 Equipment Location - Reactor Enclosure - Unit 2 - Section A-A 1.2-16 Sh.2 M-140 Sh.1 Equipment Location - Radwaste Enclosure - Plan at El 162' 1.2-30 Sh.1 M-141 Sh.1 Equipment Location - Radwaste Enclosure - Plan at El 191' 1.2-31 Sh.1 M-142 Sh.1 Equipment Location - Radwaste Enclosure - Plan at El 217' 1.2-32 Sh.1 M-143 Sh.1 Equipment Location - Radwaste Enclosure - Plan at El 237' & 257' 1.2-33 Sh.1 M-144 Sh.1 Equipment Location - Radwaste Enclosure - Sections 1.2-34 Sh.1 M-145 Sh.1 Equipment Location - Diesel Generator Enclosure - Units 1 & 2 - Plan at El 217' 1.2-35 Sh.1 M-146 Sh.1 Equipment Location - Diesel Generator Enclosure - Units 1 & 2 - Sections 1.2-36 Sh.1 M-191 Sh.1 Piping and Mechanical - Turbine Building - Units 1 & 2 - El 180' - Area 8 1.2-75 Sh.1 M-192 Sh.1 Piping and Mechanical - Turbine Building - Units 1 & 2 - El 180' - Area 8 1.2-74 Sh.1 M-195 Sh.1 Piping and Mechanical - Turbine Building - Units 1 & 2 - El 200' - Area 8 1.2-76 Sh.1 M-196 Sh.1 Piping and Mechanical - Turbine Building - Units 1 & 2 - El 217' - Area 8 1.2-77 Sh.1 M-197 Sh.1 Piping and Mechanical - Turbine Building - Units 1 & 2 - El 239' - Area 8 1.2-78 Sh.1 M-198 Sh.1 Piping and Mechanical - Turbine Building - Units 1 & 2 - El 254' - Area 8 1.2-79 Sh.1 M-200 Sh.1 Piping and Mechanical - Turbine Building - Units 1 & 2 - El 269' - Area 8 1.2-80 Sh.1 M-201 Sh.1 Piping and Mechanical - Turbine Building - Units 1 & 2 - El 289' - Area 8 1.2-81 Sh.1 M-202 Sh.1 Piping and Mechanical - Turbine Building - Units 1 & 2 - El 304' - Area 8 1.2-82 Sh.1 M-206 Sh.1 Piping and Equipment Layout - Reactor Enclosure - Unit 1 - Plan at El.177' - Area 11 1.2-40 Sh.1 M-207 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 1 - Plan at El.201'- Area 11 1.2-45 Sh.1 Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-49 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.7-4 (Contd)

FIGURE INDEX FOR MISC. DRAWINGS Drawing Number Title Former UFSAR Figure Number M-208 Sh.1 Piping and Mechanical - Reactor Enclosure - Unit 1 - Plan at El.217' - Area 11 1.2-49 Sh.1 M-209 Sh.1 Piping and Equipment Layout - Reactor Enclosure - Unit 1 - Plan at El.253' - Area 11 1.2-53 Sh.1 M-210 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 1 - Plan at El.283" - Area 11 1.2-57 Sh.1 M-211 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 1 - Plan at El.313' - Area 11 1.2-61 Sh.1 M-213 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 1 - Drywell Plan at El.238' - Area 11, 12, 15, & 16 1.2-65 Sh.1 M-215 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 1 - Section B-B - Areas 11, 12, & 16 1.2-71 Sh.1 M-217 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 1 - Section D-D - Areas 12, & 16 1.2-72 Sh.1 M-218 Sh.1 Piping and Equipment Layout - Reactor Enclosure - Unit 1 - Plan at El.177' - Area 12 1.2-41 Sh.1 M-219 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 1 - Plan at El.201' - Area 12 1.2-46 Sh.1 M-220 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 1 - Plan at El.217' - Area 12 1.2-50 Sh.1 M-221 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 1 - Plan at El.253' - Area 12 1.2-54 Sh.1 M-222 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 1 - Plan at El.283' - Area 12 1.2-58 Sh.1 M-223 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 1 - Plan at El.313' - Area 12 1.2-62 Sh.1 M-225 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 1 - Drywell Plan at El.253' - Area 11, 12, 15, & 16 1.2-66 Sh.1 M-226 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 1 - Drywell Plan at El.272'-9" - Area 11, 12, 15, & 16 1.2-67 Sh.1 M-227 Sh.1 Piping and Equipment Layout - Reactor Enclosure - Unit 1 - Plan at El.177' - Area 15 1.2-42 Sh.1 M-228 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 1 - Plan at El.210' - Area 15 1.2-47 Sh.1 M-229 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 1 - Plan at El.217' - Area 15 1.2-51 Sh.1 M-230 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 1 - Plan at El.253' - Area 15 1.2-55 Sh.1 M-231 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 1 - Plan at El.283' - Area 15 1.2-59 Sh.1 M-232 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 1 - Plan at El.313' - Area 15 1.2-63 Sh.1 M-234 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 1 - Drywell Plan at El.286' - Area 11, 12, 15, & 16 1.2-68 Sh.1 M-235 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 1 - Drywell Plan at El.295' - Area 11, 12, 15, & 16 1.2-69 Sh.1 M-236 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 1 - Drywell Plan at El.310' - Area 11, 12, 15, & 16 1.2-70 Sh.1 M-237 Sh.1 Piping and Equipment Layout - Reactor Enclosure - Unit 1 - Plan at El.177' Area 16 1.2-43 Sh.1 M-238 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 1 - Plan at El.210' - Area 16 1.2-48 Sh.1 M-239 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 1 - Plan at El.217' - Area 16 1.2-52 Sh.1 M-240 Sh.1 Piping and Mechanical - Reactor Enclosure - Unit 1 - Plan at El.253' - Area 16 1.2-56 Sh.1 M-241 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 1 - Plan at El.283' - Area 16 1.2-60 Sh.1 M-242 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 1 - Plan at El.313' - Area 16 1.2-64 Sh.1 M-246 Sh.1 Piping and Equipment Layout - Reactor Enclosure - Unit 1 - Plan at El.191' Area 15 & 16 1.2-44 Sh.1 M-312 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 2 - Plan at El.283' - Area 17 1.2-60 Sh.2 M-313 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 2 - Plan at El.313' - Area 17 1.2-64 Sh.2 M-316 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 2 - Section B-B - Areas 13, & 14 1.2-71 Sh.2 Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-50 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.7-4 (Contd)

FIGURE INDEX FOR MISC. DRAWINGS Drawing Number Title Former UFSAR Figure Number M-317 Sh.1 Piping and Equipment Layout - Reactor Enclosure - Unit 2 - Plan at El.191' Area 17 & 18 1.2-44 Sh.2 M-318 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 2 - Plan at El 177' - Area 18 1.2-42 Sh.2 M-319 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 2 - Plan at El 201' - Area 18 1.2-47 Sh.2 M-320 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 2 - Plan at El 217' - Area 18 1.2-51 Sh.2 M-321 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 2 - Plan at El 253' - Area 18 1.2-55 Sh.2 M-322 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 2 - Plan at El 283' - Area 18 1.2-59 Sh.2 M-323 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 2 - Plan at El 313' - Area 18 1.2-63 Sh.2 M-326 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 2 - Section D-D - Areas 13, & 17 1.2-72 Sh.2 M-384 Sh.1 Piping Assembly for Spray Network A B C & D 9.2-7 Sh.1 M-388 Sh.1 Equipment Location - Spray Pond Pump Structure -Plans at El 268 and 251 1.2-37 Sh.1 M-389 Sh.1 Piping and Mechanical - Spray Pond Pump Structure, Sections 1.2-39 Sh.1 M-390 Sh.1 Piping and Mechanical - Spray Pond Pump Structure - Plan at El 237' 1.2-38 Sh.1 M-677 Sh.1 Instrument Location - Turbine Bldg - Unit 1 - Plan at El. 255 - Area 1 7.2-11 Sh.1 M-6389 Sh.1 Sewage Treatment Facility - Equipment, Instrumentation & Piping Diagram 9.3-9 Sh.1 M-8320 Sh.1 RHR & Core Spray Strainer Gen. Arrgt.-Plan-Reactor Enclosure Areas 11,12,15 1.2-83 Sh.1 N-110 Sh.1 Shielding and Radiation Zoning Drawing - Turbine Enclosure - Unit 1 - Plan at El. 200' 12.3-8 Sh.1 N-111 Sh.1 Shielding and Radiation Zoning Drawing - Turbine Enclosure - Unit 1 - Plan at El. 217' 12.3-9 Sh.1 N-112 Sh.1 Shielding and Radiation Zoning Drawing - Turbine Enclosure - Unit 1 - Plan at El. 239' 12.3-10 Sh.1 N-113 Sh.1 Shielding and Radiation Zoning Drawing - Turbine Enclosure - Unit 1 - Plan at El. 269' 12.3-11 Sh.1 N-115 Sh.1 Shielding and Radiation Zoning Drawing - Turbine Enclosure - Unit 1 - Plan at El. 302' & 304' 12.3-12 Sh.1 N-116 Sh.1 Shielding and Radiation Zoning Drawing - Reactor Enclosure - Unit 1 - Plan at El. 177' 12.3-13 Sh.1 N-117 Sh.1 Shielding and Radiation Zoning Drawing - Reactor Enclosure - Unit 1 - Plan at El. 201' 12.3-14 Sh.1 N-118 Sh.1 Shielding and Radiation Zoning Drawing - Reactor Enclosure - Unit 1 - Plan at El. 217' 12.3-15 Sh.1 N-119 Sh.1 Shielding and Radiation Zoning Drawing - Reactor Enclosure - Unit 1 - Plan at El. 253' 12.3-16 Sh.1 N-120 Sh.1 Shielding and Radiation Zoning Drawing - Reactor Enclosure - Unit 1 - Plan at El. 283' 12.3-17 Sh.1 N-121 Sh.1 Shielding and Radiation Zoning Drawing - Reactor Enclosure - Unit 1 - Plan at El. 313' 12.3-18 Sh.1 N-122 Sh.1 Shielding and Radiation Zoning Drawing - Reactor Enclosure - Unit 1 - Plan at El. 352' 12.3-19 Sh.1 N-124 Sh.1 Shielding and Radiation Zoning Drawing - Cont Structure - Plans at El. 321', 332', 350', & Sect. 12.3-24 Sh.1 N-125 Sh.1 Shielding and Radiation Zoning Drawing - Turbine Enclosure - Unit 2 - Plan at El. 200' 12.3-8 Sh.2 N-126 Sh.1 Shielding and Radiation Zoning Drawing - Turbine Enclosure - Unit 2 - Plan at El. 217' 12.3-9 Sh.2 N-127 Sh.1 Shielding and Radiation Zoning Drawing - Turbine Enclosure - Unit 2 - Plan at El. 239' 12.3-10 Sh.2 N-128 Sh.1 Shielding and Radiation Zoning Drawing - Turbine Enclosure - Unit 2 - Plan at El. 269' 12.3-11 Sh.2 N-130 Sh.1 Shielding and Radiation Zoning Drawing - Turbine Enclosure - Unit 2 - Plan at El. 302' & 304' 12.3-12 Sh.2 N-131 Sh.1 Shielding and Radiation Zoning Drawing - Reactor Enclosure - Unit 2 - Plan at El. 177' 12.3-13 Sh.2 Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-51 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.7-4 (Contd)

FIGURE INDEX FOR MISC. DRAWINGS Drawing Number Title Former UFSAR Figure Number M-288 Sh.1 Piping and Equipment Layout - Reactor Enclosure - Unit 2 - Plan at El.177' Area 13 1.2-41 Sh.2 M-289 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 2 - Plan at El.201' - Area 13 1.2-46 Sh.2 M-290 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 2 - Plan at El.217' - Area 13 1.2-50 Sh.2 M-291 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 2 - Plan at El.253' - Area 13 1.2-54 Sh.2 M-292 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 2 - Plan at El.283' - Area 13 1.2-58 Sh.2 M-293 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 2 - Plan at El.313' - Area 13 1.2-62 Sh.2 M-295 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 2 - Drywell Plan at El.238' - Area 13, 14, 17, & 18 1.2-65 Sh.2 M-296 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 2 - Drywell Plan at El.253' - Area 13, 14, 17, & 18 1.2-66 Sh.2 M-297 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 2 - Drywell Plan at El.272'-9" - Area 13, 14, 17, & 18 1.2-67 Sh.2 M-298 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 2 - Plan at El.177' - Area 14 1.2-40 Sh.2 M-299 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 2 - Plan at El.201' - Area 14 1.2-45 Sh.2 M-300 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 2 - Plan at El.217' - Area 14 1.2-49 Sh.2 M-301 Sh.1 Piping and Equipment Layout - Reactor Enclosure - Unit 2 - Plan at El.253' Area 14 1.2-53 Sh.2 M-302 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 2 - Plan at El.283' - Area 14 1.2-57 Sh.2 M-303 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 2 - Plan at El.313' - Area 14 1.2-61 Sh.2 M-305 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 2 - Drywell Plan at El.286' - Area 13, 14, 17, & 18 1.2-68 Sh.2 M-306 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 2 - Drywell Plan at El.295' - Area 13, 14, 17, & 18 1.2-69 Sh.2 M-307 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 2 - Drywell Plan at El.310' - Area 13, 14, 17, & 18 1.2-70 Sh.2 M-308 Sh.1 Piping and Equipment Layout - Reactor Enclosure - Unit 2 - Plan at El.177' Area 17 1.2-43 Sh.2 M-309 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 2 - Plan at El.201' - Area 17 1.2-48 Sh.2 M-310 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 2 - Plan at El.217' - Area 17 1.2-52 Sh.2 M-311 Sh.1 Piping and Mechanical - Reactor Bldg - Unit 2 - Plan at El.253' - Area 17 1.2-56 Sh.2 N-132 Sh.1 Shielding and Radiation Zoning Drawing - Reactor Enclosure - Unit 2 - Plan at El. 201' 12.3-14 Sh.2 N-133 Sh.1 Shielding and Radiation Zoning Drawing - Reactor Enclosure - Unit 2 - Plan at El. 217' 12.3-15 Sh.2 N-134 Sh.1 Shielding and Radiation Zoning Drawing - Reactor Enclosure - Unit 2 - Plan at El. 253' 12.3-16 Sh.2 N-135 Sh.1 Shielding and Radiation Zoning Drawing - Reactor Enclosure - Unit 2 - Plan at El. 283' 12.3-17 Sh.2 N-136 Sh.1 Shielding and Radiation Zoning Drawing - Reactor Enclosure - Unit 2 - Plan at El. 313' 12.3-18 Sh.2 N-137 Sh.1 Shielding and Radiation Zoning Drawing - Reactor Enclosure - Unit 2 - Plan at El. 352' 12.3-19 Sh.2 N-139 Sh.1 Shielding and Radiation Zoning Drawing - Roof Areas of Rx.Enc., RW Encl., & Control Encl. 12.3-25 Sh.1 N-140 Sh.1 Shielding and Radiation Zoning Drawing - RW & Offgas Enclosures - Plan at El. 162' & 187'-6" 12.3-20 Sh.1 N-141 Sh.1 Shielding and Radiation Zoning Drawing - RW & Offgas Enclosures - Plan at El. 191' & 195' 12.3-21 Sh.1 N-142 Sh.1 Shielding and Radiation Zoning Drawing - RW & Offgas Enclosures - Plan at El. 217' 12.3-22 Sh.1 N-143 Sh.1 Shielding and Radiation Zoning Drawing - RW Enclosure - Plan at El. 237' & 257' 12.3-23 Sh.1 Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-52 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.7-4 (Contd)

FIGURE INDEX FOR MISC. DRAWINGS Drawing Number Title Former UFSAR Figure Number 105D5584 Sh.1 GE Process Diagram - Control Rod Drive System 4.6-7 Sh.1 Sh.2 GE Process Diagram - Control Rod Drive System 4.6-7 Sh.2 Sh.3 GE Process Diagram - Control Rod Drive System 4.6-7 Sh.3 Sh.4 GE Process Diagram - Control Rod Drive System 4.6-7 Sh.4 731E769AD Sh.1 GE Process Diagram - Reactor Core Isolation Cooling System 5.4-10 Sh.1 761E292AD Sh.1 GE Process Diagram - Residual Heat Removal System 5.4-14 Sh.1 Sh.2 GE Process Diagram - Residual Heat Removal System 5.4-14 Sh.2 Sh.3 GE Process Diagram - Residual Heat Removal System 5.4-14 Sh.3 761E270AD Sh.1 GE Process Diagram - High Pressure Coolant Injection System 6.3-1 Sh.1 761E280A Sh.1 GE Process Diagram - Core Spray System 6.3-2 Sh.1 729E613AD Sh.1 GE FCD - Core Spray System 7.3-9 Sh.1 Sh.2 GE FCD - Core Spray System 7.3-9 Sh.2 919D694AD Sh.1 GE FCD - Standby Liquid Control System 7.4-2 Sh.1 Sh.2 GE FCD - Standby Liquid Control System 7.4-2 Sh.2 Sh.3 GE FCD - Standby Liquid Control System 7.4-2 Sh.3 729E618AD Sh.1 GE FCD - Reactor Recirculation System 7.7-2 Sh.1 Sh.4 GE FCD - Reactor Recirculation System 7.7-2 Sh.4 Sh.5 GE FCD - Reactor Recirculation System 7.7-2 Sh.5 Sh.6 GE FCD - Reactor Recirculation System 7.7-2 Sh.6 729E630AD Sh.1 GE FCD - Residual Heat Removal System 7.3-10 Sh.1 Sh.2 GE FCD - Residual Heat Removal System 7.3-10 Sh.2 761E477 Sh.3 GE FCD - Reactor Recirculation System 7.7-6 Sh.3 Sh.4 GE FCD - Reactor Recirculation System 7.7-6 Sh.4 Sh.5 GE FCD - Reactor Recirculation System 7.7-6 Sh.5 Note: See note in Section 1.7 for drawing considerations.

CHAPTER 01 1.7-53 REV. 17, SEPTEMBER 2014

LGS UFSAR 1.8 CONFORMANCE TO NRC REGULATORY GUIDES This section provides a brief description of LGS conformance with the guidelines presented in the regulatory guides and provides reference to the UFSAR sections where the LGS design and details of conformance or alternate approaches are discussed.

The conformance information below applies only to the particular guide being addressed and not necessarily to other guides that may be referenced in that guide.

This section also identifies those guides classified as Category 1,2,3 or 4 per Reference 1.11-2, as discussed in Section 1.11.

REGULATORY GUIDE 1.1 Net Positive Suction Head for Emergency Core Cooling and Containment Heat Removal System Pumps (Safety Guide 1)

Rev 0, November 2 1970 LGS is in conformance with this guide as discussed in Sections 5.4.7 and 6.3.2.

(Category 1)

REGULATORY GUIDE 1.2 Thermal Shock to Reactor Pressure Vessels (Safety Guide 2)

Rev 0, November 2 1970 Although not used as a design basis, LGS is evaluated as being in conformance with this guide.

Reactor vessel integrity is discussed in Section 5.3.

(Category 1)

REGULATORY GUIDE 1.3 Assumptions Used for Evaluating the Potential Radiological Consequences of a Loss-of-Coolant Accident for Boiling Water Reactors Rev 2, June 1974___________________________________________________

Regulatory Guide 1.3 was used for the original plant design. Regulatory Guide 1.3 is used for the determination of in-plant doses, shielding design and equipment unless such evaluations are re-performed using Alternate Source Terms. The requirements of Regulatory Guide 1.3, as they apply to the determination of control room and off-site radiological consequences for LOCA, are superseded by the requirements of Regulatory Guide 1.183 (Category 1)

REGULATORY GUIDE 1.4 Assumptions Used for Evaluating the Potential Radiological Consequences of a Loss-of-Coolant Accident for Pressurized Water Reactors Rev 2, June 1974 This guide is for pressurized water reactors and therefore is not applicable to LGS.

REGULATORY GUIDE 1.5 Assumptions Used for Evaluating the Potential Radiological Consequences of a Steam Line Break Accident for Boiling Water Reactors (Safety Guide 5)

Rev 0, March 10 1971 CHAPTER 01 1.8-1 REV. 19, SEPTEMBER 2018

LGS UFSAR Regulatory Guide 1.5 was used for the original design of LGS. Regulatory Guide 1.5 is used for the determination of in-plant doses, shielding design and equipment unless such evaluations are re-performed using Alternate Source Terms. Regulatory Guide 1.5 steam cloud dispersion methodology is used for the MSLB does assessment for Alternate Source Terms. The requirements of Regulatory Guide 1.5, as they apply to the determination of control room and off-site radiological consequences for a Main Steam Line Break, are superseded by the requirements of Regulatory Guide 1.183.

(Category 1)

REGULATORY GUIDE 1.6 Independence Between Redundant Standby (Onsite) Power Sources and Between Their Distribution Systems (Safety Guide 6)

Rev 0, March 10 1971 LGS is in conformance with this guide as discussed in Sections 7.1.2.5, 7.6.2.8.2.1.1 and 8.1.6.1.

(Category 1)

REGULATORY GUIDE 1.7 Control of Combustible Gas Concentrations in Containment Following a Loss-of-Coolant Accident Rev 2, November 1978 LGS is in conformance with this guide. There is a clarification of quality group requirements of paragraph C.3 for the gas analyzer packages, as discussed in Section 6.2.5.4.

(Category 1)

REGULATORY GUIDE 1.8 Personnel Selection and Training Rev 1-R, May 1977 LGS is in conformance with this guide to the extent discussed in Section 12.5.3.5.2, 13.1 and 13.2.

(Category 1)

REGULATORY GUIDE 1.9 Selection of Diesel Generator Set Capacity for Standby Power Supplies (Safety Guide 9)

Rev 2, December 1979 LGS is in conformance with Revision 0 (3/10/71) of this guide as discussed in Section 8.1.6.1.

Revision 1 of this guide was for comment only, and Revision 2 is not applicable to LGS (being for plants whose construction permit applications are docketed after December, 1979).

(Category 1)

REGULATORY GUIDE 1.10 Mechanical (Cadweld) Splices in Reinforcing Bars of Category I Concrete Structures Rev 1, January 2 1973 CHAPTER 01 1.8-2 REV. 19, SEPTEMBER 2018

LGS UFSAR LGS is in conformance with this guide except that there are alternate approaches to paragraphs C.4.a, C.4.b, C.5.a, and C.5.b in that some testing procedures differ but are interpreted to be equally or more stringent than those recommended in the regulatory guide. Details are discussed in Section 3.8.6.

(Category 1)

REGULATORY GUIDE 1.11 Instrument Lines Penetrating Primary Reactor Containment (Safety Guide 11)

Rev 0, March 10, 1971 LGS is in conformance with this guide except that position indication of excess flow check valves is provided locally, rather than in the control room as suggested in Paragraph C.1.c. of the guide.

Details are discussed in Sections 6.2.4 and 6.2.6. LGS is in conformance with this guide for the TIP system lines to the extent discussed in Section 6.2.4.

(Category 1)

REGULATORY GUIDE 1.12 Instrumentation for Earthquakes Rev 2, March 1997 The LGS design is in conformance with this guide as discussed in Section 3.7.4.1.

REGULATORY GUIDE 1.13 Spent Fuel Storage Facility Design Basis Rev 1, December 1975 This guide applies to LGS on a case-by-case basis. LGS is in conformance with this guide as discussed in Sections 9.1.2 and 9.1.4.

(Category 4)

REGULATORY GUIDE 1.14 Reactor Coolant Pump Flywheel Integrity Rev 1, August 1975 The subject matter does not apply to LGS as reactor coolant recirculation pumps do not have inertia flywheels.

CHAPTER 01 1.8-3 REV. 19, SEPTEMBER 2018

LGS UFSAR REGULATORY GUIDE 1.15 Testing of Reinforcing Bars for Category 1 Concrete Structures Rev 1, December 28, 1972 LGS is in conformance with this guide as discussed in Section 3.8.6.2.

(Category 1)

REGULATORY GUIDE 1.16 Reporting of Operating Information - Appendix A Technical Specifications Rev 4, August 1975 LGS reporting requirements are established in Chapter 16, Technical Specifications, which were based on NUREG-0123, Revision 2, "Standard Technical Specifications for GE Boiling Water Reactors."

REGULATORY GUIDE 1.17 Protection of Nuclear Power Plants Against Industrial Sabotage Rev 1, June 1973 LGS is in conformance with this guide to the extent discussed in Section 13.6.

(Category 1)

REGULATORY GUIDE 1.18 Structural Acceptance Test for Concrete Primary Reactor Containments Rev 1, December 28, 1972 LGS is in conformance with paragraphs C.4 through C.8 & C.13. Alternate approaches are employed for portions of paragraphs C.1, C.2, and C.3 regarding pressure tests, measurement locations, and deflection measurement. The test environment of paragraph C.9 is not considered applicable, and LGS has not utilized the test pressure drop procedures of paragraph C.10. Details are discussed in Section 3.8.1.7.

(Category 1)

REGULATORY GUIDE 1.19 Nondestructive Examination of Primary Containment Liner Welds (Safety Guide 19)

Rev 1, August 11 1972 LGS is in conformance with this guide except that alternate approaches are employed for paragraphs C.1.a (radiographic examination increments) and C.7.a and C.7.b (acceptance standards). Conformance to paragraph C.4 (personnel qualification) is subject to an interpretation.

Details are discussed in Sections 3.8.1 and 3.8.2.

(Category 1)

CHAPTER 01 1.8-4 REV. 19, SEPTEMBER 2018

LGS UFSAR REGULATORY GUIDE 1.20 Comprehensive Vibration Assessment Program for Reactor Internals During Preoperational and Initial Startup Testing Rev 2, May 1976 LGS's program is evaluated as being in conformance with this guide and is discussed in Section 3.9.2.4 and 14.2.

(Category 1)

REGULATORY GUIDE 1.21 Measuring, Evaluating, and Reporting Radioactivity in Solid Wastes and Releases of Radioactive Materials in Liquid and Gaseous Effluents from Light-Water-Cooled Nuclear Power Plants Rev 1, June 1974 The LGS process and effluent radiological monitoring and sampling systems are designed to allow conformance to this guide, as discussed in Section 7.7, 11.5 and 12.3. Evaluation and reporting procedures during operation will conform to this guide.

(Category 1)

REGULATORY GUIDE 1.22 Periodic Testing of Protection System Actuation Functions (Safety Guide 22)

Rev 0, February 17 1972 The LGS design is in conformance with this guide as discussed in Sections 7.1.2.5 and 8.1.6.1.

(Category 1)

REGULATORY GUIDE 1.23 Onsite Meteorological Programs (Safety Guide 23)

Rev 0, February 17 1972 The LGS onsite meteorological instrumentation systems met NRC requirements at the time of installation, prior to the issuance of this guide. LGS conforms to the guidelines of Regulatory Guide 1.23, except as discussed in detail in Sections 2.3.2 and 2.3.3.

(Category 1)

REGULATORY GUIDE 1.24 Assumptions Used for Evaluating the Potential Radiological Consequences of a Pressurized Water Reactor Radioactive Gas Storage Tank Failure (Safety Guide 24)

Rev 0, March 23 1972 This guide is for PWRs and therefore does not apply to LGS.

REGULATORY GUIDE 1.25 Assumptions Used for Evaluating the Potential Radiological Consequences of a Fuel Handling Accident in the Fuel Handling and Storage Facility for Boiling and Pressurized Water Reactors (Safety Guide 25)

Rev 0, March 23 1972 CHAPTER 01 1.8-5 REV. 19, SEPTEMBER 2018

LGS UFSAR Regulatory Guide 1.25 was used for the original design. Regulatory Guide 1.25 is used for the determination of in-plant doses, shielding design and equipment unless such evaluations are re-performed using Alternate Source Terms. The requirements of Regulatory Guide 1.25, as they apply to the determination of control room and off-site radiological consequences for a Fuel Handling Accident, are superseded by the requirements of Regulatory Guide 1.183.

(Category 1)

REGULATORY GUIDE 1.26 Quality Group Classifications and Standards for Water-,

Steam-, and Radioactive-Waste-Containing Components of Nuclear Power Plants Rev 3, February 1976 LGS is in conformance with this guide except that alternate approaches are used for the CRD hydraulic control units, isolation of certain steam lines, parts of the fuel pool cooling system, diesel generator cooling system, and control structure chilled water system, instrument tubing for "passive" instrumentation, the SLCS storage tanks and accumulator vessels, and the HPCI globe stop-check valves. Details are discussed in Section 3.2.2.

(Category 1)

REGULATORY GUIDE 1.27 Ultimate Heat Sink for Nuclear Power Plants Rev 2, January 1976 LGS is in conformance with this guide except that alternate approaches were used to paragraphs C.1, C.1.a, C.1.b, and C.1.c regarding thermal analysis methods and selection of meteorology. The design meteorology is in conformance with Revision 1 of the guide. Details for both Revision 1 and Revision 2 are discussed in Section 9.2.6.6.

(Category 2)

REGULATORY GUIDE 1.28 Quality Assurance Program Requirements (Design and Construction)

Rev 3, August 1985 At the time of initial licensing, this guide, which endorsed/modified ANSI N45.2 (1977), was not applicable to LGS (being for plants whose construction permit applications are docketed after October 1979); Quality assurance during construction is discussed in the document "LGS Generating Station Units 1 and 2; Summary Description of the Quality Assurance Program for Design and Construction." The LGS QA program during operation will be in conformance with this guide, as discussed in the QATR.

Further, as discussed in a letter of approval from the NRC to Exelon, dated December 24, 2002, Regulatory Guide 1.28, Rev 3 endorses NQA-1-1983. The NRC letter approves Exelon's proposal to update its commitment to quality standards by adopting the guidance of NQA-1-1994.

Therefore, N45.2.13-1976, superseded by NQA-1-1983 has been superseded by NQA-1-1994.

(Category 1)

REGULATORY GUIDE 1.29 Seismic Design Classification Rev 3, September 1978 CHAPTER 01 1.8-6 REV. 19, SEPTEMBER 2018

LGS UFSAR LGS is in conformance with this guide except that alternate approaches have been taken for the fuel pool cooling system and isolation of certain steam lines. There are clarifications for certain reactor internals and reactivity control systems. Details are discussed in Section 3.2.1.

(Category 1)

REGULATORY GUIDE 1.30 Quality Assurance Requirements for the Installation, Inspection, and Testing of Instrumentation and Electric Equipment (Safety Guide 30)

Rev 0, August 11 1972 LGS is constructed in accordance with this guide, which endorses/ modifies ANSI N45.2.4 (1972)/IEEE 336 (1971), although the standard is not specifically a part of construction quality assurance procedures as discussed in Section 8.1.6.1.

The commitments to this Regulatory Guide and ANSI N45.2.4 were deleted since they were superseded by Exelons commitment to ASME NQA-1 1994 subpart 2.4.

(Category 1)

REGULATORY GUIDE 1.31 Control of Ferrite Content in Stainless Steel Weld Metal Rev 3, April 1978 Revision 3 of this guide is not applicable to LGS (being for plants whose construction permit applications are docketed after October 1, 1978). For the GE scope of supply, Revision 1 of the guide is used as a design basis for LGS, with certain alternate approaches considered to meet the intent of the guide. Details are discussed in Section 5.2.3.4, along with a comparison of Bechtel procedures with Revision 3 of the guide.

REGULATORY GUIDE 1.32 Criteria for Safety-Related Electric Power Systems for Nuclear Power Plants Rev 2, February 1977 This guide, which endorses/modifies IEEE 308 (1974), is not applicable to LGS (for plants whose construction permit applications are docketed after April 14, 1977). The LGS design is in conformance as discussed in Section 8.1.6.1.

(Category 1)

REGULATORY GUIDE 1.33 Quality Assurance Program Requirements (Operation)

Rev 2, February 1978 LGS is in conformance with this guide, which endorses/modifies ANSI N18.7 (1976), except for certain alternate approaches to the guide and the ANSI standard, as discussed in the QATR.

(Category 1)

REGULATORY GUIDE 1.34 Control of Electroslag Weld Properties Rev 0, December 28 1972 Electroslag welding was not used on LGS and therefore this guide is not applicable.

CHAPTER 01 1.8-7 REV. 19, SEPTEMBER 2018

LGS UFSAR REGULATORY GUIDE 1.35 Inservice Inspection of Ungrouted Tendons in Prestressed Concrete Containment Structures Rev 2, January 1976 LGS does not have a prestressed concrete containment and therefore this guide does not apply.

REGULATORY GUIDE 1.36 Nonmetallic Thermal Insulation for Austenitic Stainless Steel Rev 0, February 23 1973 LGS is in conformance with this guide as discussed in Section 5.2.3.2.

(Category 1)

REGULATORY GUIDE 1.37 Quality Assurance Requirements for Cleaning of Fluid Systems and Associated Components of Water-Cooled Nuclear Power Plants Rev 0, March 16 1973 This guide endorses/modifies ANSI N45.2.1 (1973). While this standard is not specifically applied in Bechtel's scope of work, the procedures in use satisfy the intent of the guide as discussed in Section 5.2.3.4. The GE scope of supply is in conformance with this guide as discussed in Sections 4.5.

The commitments to this Regulatory Guide and ANSI N45.2.1 were deleted since they were superseded by Exelons commitment to ASME NQA-1 1994 subpart 2.1.

(Category 1)

REGULATORY GUIDE 1.38 Quality Assurance Requirements for Packaging, Shipping, Receiving, Storage, and Handling of Items for Water-Cooled Nuclear Power Plants Rev 2, May 1977 This guide endorses/modifies ANSI N45.2.2 (1972). The guide/ standard is not specifically utilized during construction, although procedures in use for LGS conform with the intent of the guide.

Quality assurance during construction is discussed in the document "LGS Generating Station Units 1 and 2; Summary Description of the Quality Assurance Program for Design and Construction."

The GE scope of supply is in conformance with this guide as discussed in NEDO-11209-04A, "Nuclear Energy Business Group Boiling Water Reactor Quality Assurance Program" February, 1980.

The commitments to this Regulatory Guide and ANSI N45.2.2 were deleted since they were superseded by Exelons commitment to ASME NQA-1 1994 subpart 2.2.

(Category 1)

REGULATORY GUIDE 1.39 Housekeeping Requirements for Water-Cooled Nuclear Power Plants Rev 2, September 1977 CHAPTER 01 1.8-8 REV. 19, SEPTEMBER 2018

LGS UFSAR LGS is in general conformance with this guide, which endorses/ modifies ANSI N45.2.3 (1973),

although the ANSI Standard is not specifically a part of construction quality assurance procedures.

Quality assurance during construction is discussed in the document "LGS Generating Station Units 1 and 2; Summary Description of the Quality Assurance Program for Design and Construction."

The commitments to this Regulatory Guide and ANSI N45.2.3 were deleted since they were superseded by Exelons commitment to ASME NQA-1 1994 subpart 2.3.

(Category 1)

REGULATORY GUIDE 1.40 Qualification Tests of Continuous-Duty Motors Installed Inside the Containment of Water-Cooled Nuclear Power Plants Rev 0, March 16, 1973 Limerick is in conformance with the intent of this guide, which endorses/modifies trial use standard IEEE 334-1971, as discussed in Section 8.1.6.1. The Standard was revised on October 29, 1974, and the method of qualification testing was modified from the trial use version. The in-containment motors at LGS were qualified by testing performed in accordance with the enhanced methods stated in the 1974 version of IEEE Standard 334.

(Category 1)

REGULATORY GUIDE 1.41 Preoperational Testing of Redundant Onsite Electric Power Systems to Verify Proper Load Group Assignments Rev 0, March 16 1973 LGS is in conformance with this guide as discussed in Sections 8.1.6.1, 8.3.2.2, and 14.2.7.2.

(Category 1)

REGULATORY GUIDE 1.42 Interim Licensing Policy on as Low as Practicable for Gaseous Radioiodine Releases Withdrawn by the NRC March 22, 1976.

REGULATORY GUIDE 1.43 Control of Stainless Steel Weld Cladding of Low-Alloy Steel Components Rev 0, May 1973 This guide applies to welding of cladding to low-alloy steels made to coarse grain practice. LGS vessel plate and nozzle forgings are made to fine grain practice and a low heat input process is used. Other components are not clad. Therefore, the guide is not applicable.

(Category 1)

REGULATORY GUIDE 1.44 Control of the Use of Sensitized Stainless Steel Rev 0, May 1973 CHAPTER 01 1.8-9 REV. 19, SEPTEMBER 2018

LGS UFSAR For GE scope of supply, this guide is not used as a design basis for LGS and in some instances alternate approaches are used which, however, conform to the intent of this guide. For the Bechtel scope of supply, there is conformance with the guide except for alternate approaches taken for nonsensitization and intergranular corrosion testing. Details are discussed in Section 5.2.3.3.

REGULATORY GUIDE 1.45 Reactor Coolant Pressure Boundary Leakage Detection Systems Rev 0, May 1973 The LGS design complies with the intent of this regulatory guide. Three diverse methods of detection have been provided. The design bases, limitations, and operation of these systems are discussed in Sections 5.2.5.2.1.3 through 5.2.5.2.1.5. These provisions meet or exceed the recommendations of ANSI/ISA S67.03. Each of the three systems provided for leak detection has readouts and alarms in the main control room in accordance with Regulatory Guide 1.45.

(Category 1)

REGULATORY GUIDE 1.46 Protection Against Pipe Whip Inside Containment Rev 0, May 1973 For the recirculation system, pipe break locations are selected by alternate criteria which are in accordance with the intent of this guide. For all other systems, the criteria of BTP MEB 3-1 (dated 11/24/75) are used in lieu of the criteria of the regulatory guide. Protection against the effects of postulated pipe ruptures, both inside and outside the primary containment, is discussed in Section 3.6.2.

(Category 1)

REGULATORY GUIDE 1.47 Bypassed and Inoperable Status Indication for Nuclear Power Plant Safety Systems Rev 0, May 1973 LGS is in conformance with this guide as discussed in Sections 7.1.2.5 and 8.1.6.1.

(Category 1)

REGULATORY GUIDE 1.48 Design Limits and Loading Combinations for Seismic Category I Fluid System Components Rev 0, May 1973 The design limits and loading combinations for non-NSSS seismic Category I fluid systems is in accordance with this guide, as shown in Section 3.9. The NSSS systems were designed prior to the issuance of this guide and therefore the guide was not a design basis requirement, however, there is general agreement with the guide. A comparison between Regulatory Guide 1.48 and the NSSS design is provided in Section 3.9.3.

(Category 1)

CHAPTER 01 1.8-10 REV. 19, SEPTEMBER 2018

LGS UFSAR REGULATORY GUIDE 1.49 Power Levels of Nuclear Power Plants Rev 1, December 1973 LGS is in conformance with this guide as discussed in Section 15.0.4.

(Category 1)

REGULATORY GUIDE 1.50 Control of Preheat Temperature for Welding of Low-Alloy Steel Rev 0, May 1973 For GE scope of supply, the guide was not used as a design basis for LGS and in some cases alternate approaches are employed that satisfy the intent of the guide. For Bechtel scope of supply, alternate approaches are employed for portions of the procedure qualifications and maintenance of preheat temperature beyond completion of welding. Details are discussed in Section 5.2.3.3.

(Category 1)

REGULATORY GUIDE 1.51 Inservice Inspection of ASME Code Class 2 and 3 Nuclear Power Plant Components Withdrawn by the NRC July 15, 1975.

REGULATORY GUIDE 1.52 Design, Testing, and Maintenance Criteria for Post Accident Engineered Safety Feature Atmosphere Cleanup System Air Filtration and Adsorption Units of Light-Water-Cooled Nuclear Power Plants Rev 2, March 1978 The LGS system was designed prior to the original issuance of this guide in 1973, and therefore the guide was not specifically considered in the design. While there is substantial conformance, there are various exceptions and alternate approaches. These, however, are not considered significantly different from the intent of the guide. Details are discussed in Section 6.5.1 and Table 6.5-2. The initial test program will be in conformance except as may be modified by the general statement on regulatory guides in Section 14.2. Testing during operation is discussed in Chapter 16.

(Category 2 for Revision 1)

REGULATORY GUIDE 1.53 Application of the Single Failure Criterion to Nuclear Power Plant Protection Systems Rev 0, June 1973 LGS is in conformance with this guide, which endorses/modifies trial use standard IEEE 379 (1972), as discussed in Sections 7.1.2.5 and 8.1.6.1.

(Category 1)

CHAPTER 01 1.8-11 REV. 19, SEPTEMBER 2018

LGS UFSAR REGULATORY GUIDE 1.54 Quality Assurance Requirements for Protective Coatings Applied to Water-Cooled Nuclear Power Plants Rev 0, June 1973 This guide endorses/modifies ANSI N101.4 (1972). Non-NSSS practice is in conformance with the guide except that, since there are no Class I Service Level coatings in LGS, a quality assurance program was not applied. Most NSSS equipment for LGS was ordered prior to the issuance of the guide and ANSI N101.4 was not used as a design basis. GE procedures are considered to satisfy the intent of the guide. Details are discussed in Section 6.1.2. During operation, LGS will be in conformance with ASTM D3843-93 with an additional clarification, exception, and requirement as discussed in the QATR.

(Category 1)

REGULATORY GUIDE 1.55 Concrete Placement in Category I Structures Rev 0, June 1973 LGS is in conformance with this guide except that an alternate approach used for paragraphs C.2 and C.3 regarding the division of responsibilities of "designer" and "constructor" within Bechtel.

Details are discussed in Section 3.8.6.2. Also, this guide references ACI 301-72 and ACI 305-72 and LGS is in conformance with ACI 301-66 and ACI 605-59.

(Category 1)

REGULATORY GUIDE 1.56 Maintenance of Water Purity in Boiling Water Reactors Rev 1, July 1978 The LGS design is in conformance with this guide except for alternate approaches to measurement of deep bed condensate demineralizer flow and methods of determining resin exhaustion for the condensate cleanup system. The condensate cleanup system is discussed in Section 10.4.6. The RWCU system is discussed in Section 5.4.8.

Water purity limits are presented in Chapter 16.

(Category 3)

REGULATORY GUIDE 1.57 Design Limits and Loading Combinations for Metal Primary Reactor Containment System Components Rev 0, June 1973 LGS is in conformance with this guide, which applies to hatches and other metal components on LGS, with the clarification that the Code Addenda in effect at the time of design were used, rather than the later one cited by the guide. Details are discussed in Section 3.8.2.5.

(Category 1)

REGULATORY GUIDE 1.58 Qualification of Nuclear Power Plant Inspection, Examination, and Testing Personnel Rev 1, September 1980 CHAPTER 01 1.8-12 REV. 19, SEPTEMBER 2018

LGS UFSAR This guide endorses/modifies ANSI N45.2.6. QA during construction is discussed in the document "LGS Generating Station Units 1 and 2; Summary Description of the Quality Assurance Program for Design and Construction."

During operation, for NDE personnel, the Company and contractor personnel performing NDE are trained, tested, qualified, or certified in accordance with a company procedure that meets applicable requirements of 10 CFR 50.55a and ASME Section XI with specific exceptions and clarifications as discussed in the QATR.

(Category 1)

REGULATORY GUIDE 1.59 Design Basis Floods for Nuclear Power Plants Rev 2, August 1977 Although this guide does not apply to LGS (being for construction permit applications docketed after the guide's issuance), LGS is in conformance as discussed in Section 2.4.2.2.

(Category 2)

REGULATORY GUIDE 1.60 Design Response Spectra for Seismic Design of Nuclear Power Plants Rev 1, December 1973 A letter from J.M. Hendrie (NRC) to R.M. Collins (Bechtel) dated Dec. 21, 1973 stated that this guide is applicable only to plants docketed for construction permit review after April 1, 1973. LGS was docketed prior to this date, and therefore the guide is not applicable. The design response spectra were determined prior to the issuance of this guide and LGS has employed alternate approaches. Details are discussed in Section 3.7.1.1.

REGULATORY GUIDE 1.61 Damping Values for Seismic Design of Nuclear Power Plants Rev 0, October 1973 A letter from J.M. Hendrie (NRC) to R.M. Collins (Bechtel) dated Dec. 21, 1973 stated that this guide is applicable only to plants docketed for construction permit review after April 1, 1973.

LGS was docketed prior to this date and therefore the guide is not applicable. The damping values for both the NSSS and non-NSSS scope were determined prior to the issuance of this guide. For the NSSS design, an alternate approach has been employed that is more conservative than the recommendations of the guide. The non-NSSS design uses values equal to or more conservative than the guides except for the SSE value for welded steel structures.

Details are discussed in Section 3.7.1.

(Category 1)

REGULATORY GUIDE 1.62 Manual Initiation of Protective Actions Rev 0, October 1973 LGS is in conformance with this guide as discussed in Sections 7.1.2.5 and 8.1.6.1.

(Category 1)

CHAPTER 01 1.8-13 REV. 19, SEPTEMBER 2018

LGS UFSAR REGULATORY GUIDE 1.63 Electric Penetration Assemblies in Containment Structures for Light-Water- Cooled Nuclear Power Plants Rev 2, July 1978 The LGS electric penetration assemblies were purchased when Revision 0 (10/73) of this guide, which endorses/modifies IEEE 317 (1972), was in effect. The LGS assemblies are in full conformance with this revision of the guide. Revision 2 of the guide, which endorses/modifies IEEE 317 (1976), is not applicable to LGS per its implementation section (being for plants whose construction permit applications are docketed after August 31, 1978). There are several exceptions and clarifications to this revision of the guide as discussed in Section 8.1.6.1.

(Category 2)

REGULATORY GUIDE 1.64 Quality Assurance Requirements for the Design of Nuclear Power Plants Rev 2, June 1976 This guide, which endorses/modifies ANSI N45.2.11, does not apply to LGS (being for construction permits docketed after July 15, 1976). Quality assurance during construction is discussed in the document "LGS Generating Station Units 1 and 2; Summary Description of the Quality Assurance Program for Design and Construction." LGS will conform during operation, except for certain alternate approaches to paragraph C.2 of the guide regarding design verification, as discussed in the QATR.

(Category 1)

REGULATORY GUIDE 1.65 Materials and Inspections for Reactor Vessel Closure Studs Rev 0, October 1973 The reactor vessel closure studs were ordered prior to the issuance of this guide and therefore the guide was not used as a design basis for LGS. The LGS design, is in conformance except that alternate approaches were used for Charpy V impact testing of paragraph C.1.B.(2) of the guide and ultrasonic examination procedures of paragraph C.2.b. Material details and use are discussed in Section 5.3.1.11. The cleanliness recommendations of the guide will be followed during operation.

(Category 1)

REGULATORY GUIDE 1.66 Nondestructive Examination of Tubular Products Withdrawn by NRC September 1977. Discussion of activities prior to that time is provided in Section 5.2.3.3.

REGULATORY GUIDE 1.67 Installation of Overpressure Protection Devices Rev 0, October 1973 There are no ASME Section III, Class 1, 2 or 3 relief valves employed in the LGS design, to which Code Case 1569 applies, therefore, the subject matter of this guide is not applicable to LGS.

CHAPTER 01 1.8-14 REV. 19, SEPTEMBER 2018

LGS UFSAR REGULATORY GUIDE 1.68 Initial Test Program for Water-Cooled Reactor Power Plants Rev 2, August 1978 LGS will be in conformance with this guide as discussed in Section 14.2.7.2.

(Category 1)

REGULATORY GUIDE 1.68.1 Preoperational and Initial Startup Testing of Feedwater and Condensate Systems for Boiling Water Reactor Power Plants Rev 1, January 1977 LGS will be in conformance with the guide as discussed in Section 14.2.7.2.

(Category 1)

REGULATORY GUIDE 1.68.2 Initial Startup Test Program to Demonstrate Remote Shutdown Capability for Water-Cooled Nuclear Power Plants Rev 1, July 1978 LGS will be in conformance with the guide.

(Category 3)

REGULATORY GUIDE 1.68.3 Preoperational Testing of Instrument and Control Air Systems Rev 0, April 1982 LGS will be in conformance with the applicable portions of this guide.

REGULATORY GUIDE 1.69 Concrete Radiation Shields for Nuclear Power Plants Rev 0, December 1973 LGS did not directly apply this guide, which endorses/modifies ANSI N101.6 (1972). Certain provisions of the guide, including those pertaining to structural aspects of radiation shield design are met by LGS via conformance to concrete standards. LGS concrete standards are discussed in Section 3.8.

(Category 1)

REGULATORY GUIDE 1.70 Standard Format and Content of Safety Analysis Reports for Nuclear Power Plants Rev 3, November 1978 The LGS FSAR is in conformance with the format and content requirements of this guide.

(Category 1)

REGULATORY GUIDE 1.71 Welder Qualification for Areas of Limited Accessibility CHAPTER 01 1.8-15 REV. 19, SEPTEMBER 2018

LGS UFSAR Rev 0, December 1973 GE does not employ this guide as a design basis for LGS and in some cases employs alternate approaches that are evaluated as satisfying the intent of the guide. Details are discussed in Section 5.2.3.4. Bechtel employs alternate approaches to portions of this guide as in Section 5.2.3.4.

(Category 1)

REGULATORY GUIDE 1.72 Spray Pond Piping Made from Fiberglass-Reinforced Thermosetting Resin Rev 2, November 1978 The LGS spray pond does not use this type of pipe and therefore the guide does not apply.

(Category 1)

REGULATORY GUIDE 1.73 Qualification Tests of Electric Valve Operators Installed Inside the Containment of Nuclear Power Plants Rev 0, January 1974 This Regulatory Guide is applicable to safety-related valve operators. Limerick safety-related valve operators are in conformance with this guide which endorses/modifies IEEE 382-1972 as discussed in Section 8.1.6.1.

(Category 1)

REGULATORY GUIDE 1.74 Quality Assurance Terms and Definitions Rev 0, February 1974 Quality assurance during construction is discussed in the document "LGS Generating Station Units 1 and 2; Summary Description of the Quality Assurance Program for Design and Construction."

LGS will be in conformance with this guide, which endorses/modifies ANSI N45.2.10 (1973), during operation as discussed in the QATR.

(Category 1)

REGULATORY GUIDE 1.75 Physical Independence of Electric Systems Rev 2, September 1978 Although this guide, which endorses/modifies IEEE 384 (1974), does not apply to LGS (being for construction permit applications whose SER's are dated after February 1, 1974), the approach was taken to incorporate as much as possible of the guidelines into the partially completed design.

There are various alternate approaches and exceptions to the guide and IEEE 384 as discussed in Sections 7.1.2.5 and 8.1.6.1.

(Category 4 for Revision 1)

REGULATORY GUIDE 1.76 Design Basis Tornado for Nuclear Power Plants Rev 0, April 1974 CHAPTER 01 1.8-16 REV. 19, SEPTEMBER 2018

LGS UFSAR LGS is in conformance with this guide except that an alternate equivalent approach to paragraph C.1, regarding design basis tornado characteristics, is used. Details are discussed in Sections 2.3.1.2.4 and 3.3.

(Category 4)

REGULATORY GUIDE 1.77 Assumptions Used for Evaluating a Control Rod Ejection Accident for Pressurized Water Reactors Rev 0, May 1974 This guide is for PWRs and therefore is not applicable to LGS.

REGULATORY GUIDE 1.78 Assumptions for Evaluating the Habitability of a Nuclear Power Plant Control Room During a Postulated Hazardous Chemical Release Rev 0, June 1974 LGS complies with the intent of this guide. Details are discussed in Sections 2.2.3 and 6.4.

(Category 1)

REGULATORY GUIDE 1.79 Preoperational Testing of Emergency Core Cooling Systems for Pressurized Water Reactors Rev 1, September 1975 This guide is for PWRs and therefore does not apply to LGS.

REGULATORY GUIDE 1.80 Preoperational Testing of Instrument Air Systems Rev 0, June 1974 This guide was superseded by Regulatory Guide 1.68.3 in April 1982.

(Category 4)

REGULATORY GUIDE 1.81 Shared Emergency and Shutdown Electric Systems for Multi-Unit Nuclear Power Plants Rev 1, January 1975 LGS is in conformance with this guide as discussed in Section 8.1.6.1.

(Category 1)

REGULATORY GUIDE 1.82 Water Sources for Long-Term Recirculation Cooling Following a Loss-of-Coolant Accident Rev 2, May 1996 LGS is in conformance with this guide as discussed in Section 6.2.2.2.

REGULATORY GUIDE 1.83 Inservice Inspection of Pressurized Water Reactor Steam Generator Tubes Rev 1, July 1975 CHAPTER 01 1.8-17 REV. 19, SEPTEMBER 2018

LGS UFSAR This guide is for PWRs and therefore is not applicable to LGS.

REGULATORY GUIDE 1.84 Code Case Acceptability - ASME Section III Design and Fabrication The non-NSSS scope of supply is in accordance with this guide with the exception of the spray pond nozzles which used Code Case N-316 for installation. Approval of code cases for Class 3 equipment is not currently required by 10CFR50.55a. The NSSS scope of supply procedure for meeting the regulatory requirements is to obtain NRC approval for code cases applicable to Class I components only. These cases are discussed in Section 5.2.1.2. Approval of code cases for Class 2 and 3 equipment was not required at the time of the design of LGS, and is not currently required by 10CFR50.55a. Therefore, GE believes that this procedure in conjunction with 10CFR50, Appendix B, and other regulatory requirements provide adequate assurance of quality in the design and fabrication of safety-related equipment.

(Category 1)

REGULATORY GUIDE 1.85 Code Case Acceptability - ASME Section III Materials The non-NSSS scope of supply is in accordance with this guide except that Code Cases 1330-3 and 1481 were used in the manufacture of the offgas system aftercondensers. In addition, Code Case 1481 was applied to the post-LOCA hydrogen recombiners. Code Case 1330-3 was incorporated into the 1974 edition of the ASME B&PV Code, Section III. Code Case 1481 addresses the use of materials used in equipment operating above 800°F, since the present ASME B&PV Code, Section III is limited in applicability to equipment operating below 800°F. In order for the aftercondensers and recombiners to meet the requirements of the ASME B&PV Code, Code Case 1481 must be applied. The NSSS scope of supply procedure for meeting the regulatory requirements is to obtain NRC approval for code cases applicable to Class I components only.

These cases are discussed in Section 5.2.1.2. Approval of code cases for Class 2 and 3 equipment was not required at the time of the design of LGS, and is not currently required to 10CFR50.55a. Therefore, GE believes that this procedure in conjunction with 10CFR50, Appendix B and other regulatory requirements provide adequate assurance of quality in the design and fabrication of safety-related equipment.

With regard to Code Case N242 "Materials Certification, Section III, Division 1, Classes 1, 2, 3, MC and CS Construction," Regulatory Guide 1.85 calls for identification in the FSAR of those components and supports requiring the use of Paragraphs 1.0 through 4.0 of the Code Case.

Accordingly, Table 1.8-1, is provided.

(Category 1)

REGULATORY GUIDE 1.86 Termination of Operating Licenses for Nuclear Reactors Rev 0, June 1974 This guide is not applicable at the operating license stage.

CHAPTER 01 1.8-18 REV. 19, SEPTEMBER 2018

LGS UFSAR REGULATORY GUIDE 1.87 Guidance for Construction of Class 1 Components in Elevated-Temperature Reactors (Supplement to ASME Section III Code Cases 1592, 1593, 1594, 1595, and 1596)

Rev 1, June 1975 This guide is not applicable to LGS.

(Category 1)

REGULATORY GUIDE 1.88 Collection, Storage, and Maintenance of Nuclear Power Plant, Quality Assurance Records Rev 2, October 1976 This guide, which endorses/modifies ANSI N45.2.9 (1974), is not applicable to LGS (being for construction permit application submittals after October 1976). Quality assurance during construction is discussed in the document "LGS Generating Station Units 1 and 2; Summary Description of the Quality Assurance Program for Design and Construction." LGS will be in conformance during operation, except for certain alternate approaches to the ANSI Standard regarding correction to documents and storage, as discussed in the QATR.

(Category 1)

REGULATORY GUIDE 1.89 Qualification of Class 1E Equipment for Nuclear Power Plants Rev 0, November 1974 Regulatory Guide 1.89, Revision 0, does not apply to LGS. LGS equipment requiring qualification was qualified in accordance with NUREG-0588, Category II as described in Sections 8.1.6.1 and 3.11.

(Category 4)

REGULATORY GUIDE 1.90 Inservice Inspection of Prestressed Concrete Containment Structures with Grouted Tendons Rev 1, August 1977 LGS does not have a prestressed concrete containment and therefore this guide is not applicable.

REGULATORY GUIDE 1.91 Evaluation of Explosions Postulated to Occur on Transportation Routes Near Nuclear Power Plants Rev 1, February 1978 Although this guide does not apply to LGS (being for plants whose construction permits were docketed after February 24, 1978), LGS is in conformance as discussed in Section 2.2.3.

(Category 2)

REGULATORY GUIDE 1.92 Combining Modal Responses and Spatial Components in Seismic Response Analysis Rev 1, February 1976 CHAPTER 01 1.8-19 REV. 19, SEPTEMBER 2018

LGS UFSAR This guide does not apply to LGS (being for plants whose instruction permits were docketed after February, 1976). LGS seismic response analysis methods are discussed in Section 3.7 and 3.9.

Refer to Section 3.10.

(Category 1)

REGULATORY GUIDE 1.93 Availability of Electric Power Sources Rev 0, December 1974 The LGS design is in conformance as discussed in Section 8.2. LGS will conform to this guide during operation as discussed in Chapter 16.

(Category 4)

REGULATORY GUIDE 1.94 Quality Assurance Requirements for Installation, Inspection, and Testing of Structural Concrete and Structural Steel During the Construction Phase of Nuclear Power Plants Rev 1, April 1976 This guide, which endorses/modifies ANSI N45.25 (1974), is not applicable to LGS (being for plants whose construction permits are docketed after October, 1976). Quality assurance during construction is discussed in the document "LGS Generating Station Units 1 and 2; Summary Description of the Quality Assurance Program for Design and Construction."

The commitments to this Regulatory Guide and ANSI N45.2.5 were deleted since they were superseded by Exelons commitment to ASME NQA-1 1994 subpart 2.5.

(Category 1)

REGULATORY GUIDE 1.95 Protection of Nuclear Power Plant Control Room Operators Against an Accidental Chlorine Release Rev 1, January 1977 This guide is not applicable to LGS (being for plants whose construction permits were docketed after the guide's issuance). The LGS design for protection against accidental chlorine release is discussed in Sections 2.2.3 and 6.4.

(Category 1)

REGULATORY GUIDE 1.96 Design of Main Steam Isolation Valve Leakage Control Systems for Boiling Water Reactor Nuclear Power Plants Rev 0, May 1975 In 1994, LGS received approval to remove the MSIV-LCS and replace it with the MSIV Leakage Alternate Drain Pathway discussed in Section 6.7 (Category 1)

CHAPTER 01 1.8-20 REV. 19, SEPTEMBER 2018

LGS UFSAR REGULATORY GUIDE 1.97 Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident Rev 2, December 1980 LGS is in conformance with this guide to the extent discussed in Section 7.5.

(Category 3)

REGULATORY GUIDE 1.98 Assumptions Used for Evaluating the Potential Radiological Consequences of a Radioactive Offgas System Failure in a Boiling Water Reactor Rev 0, March 1976 LGS is in conformance with this guide except that an alternate approach is used for paragraph C.4.b (dose conversion factors) and there is a clarification to paragraph C.4.a regarding surface body dose rates. Details are discussed in Section 15.0.4.

(Category 1)

REGULATORY GUIDE 1.99 Radiation Embrittlement of Reactor Vessel Materials Rev 2, May 1988 LGS is in conformance with this guide as discussed in Section 5.3.1.4.

(Category 3)

REGULATORY GUIDE 1.100 Seismic Qualification of Electric Equipment for Nuclear Power Plants Rev 1, August 1977 This guide which endorses/modifies IEEE 344 (1975) does not apply to LGS (being for plants whose construction permits are docketed after the guide's issuance). LGS seismic qualification of electrical components is discussed in Section 3.10.

(Category 1)

REGULATORY GUIDE 1.101 Emergency Planning for Nuclear Power Plants Rev 2, October 1981 LGS is in conformance with this guide except for certain alternate approaches discussed in the Emergency Plan.

REGULATORY GUIDE 1.102 Flood Protection for Nuclear Power Plants Rev 1, September 1976 LGS is in conformance with this guide as discussed in Section 3.4.

(Category 2)

CHAPTER 01 1.8-21 REV. 19, SEPTEMBER 2018

LGS UFSAR REGULATORY GUIDE 1.103 Post-Tensioned Prestressing Systems for Concrete Reactor Vessels and Containments Rev 1, October 1976 LGS does not have a prestressed concrete containment and therefore this guide is not applicable.

REGULATORY GUIDE 1.104 Overhead Crane Handling Systems for Nuclear Power Plants Rev 0, February 1976 This guide was withdrawn by the NRC on August 16, 1979. The LGS reactor enclosure crane was designed and procured prior to the issuance of this guide. For explanatory purposes, a comparison with the guide is given in Section 9.1.5.

(Category 4)

REGULATORY GUIDE 1.105 Instrument Setpoints Rev 1, November 1976 Although this guide does not apply to LGS except for the RRCS (being for plants whose construction permits applications are docketed after Dec. 15, 1976). LGS will be in conformance during operation as discussed in Section 7.1.2.5 and Chapter 16.

(Category 2)

REGULATORY GUIDE 1.106 Thermal Overload Protection for Electric Motors on Motor-Operated Valves Rev 1, March 1977 This guide is not applicable to LGS (being for plants whose construction permits are docketed after issuance of the guide). The LGS design is discussed in Section 8.1.6.1.

(Category 1)

REGULATORY GUIDE 1.107 Qualifications for Cement Grouting for Prestressing Tendons in Containment Structures Rev 1, February 1977 LGS does not have a prestressed concrete containment and therefore this guide is not applicable.

REGULATORY GUIDE 1.108 Periodic Testing of Diesel Generator Units Used as Onsite Electric Power Systems at Nuclear Power Plants Rev 1, August 1977 Although this guide does not apply to LGS (being for plants whose construction permits are docketed after issuance of the guide), LGS is in conformance. All diesel generator protective trips which are enforced during a LOOP or emergency operation, are annunciated in a group trouble alarm in the main control room and individually in the diesel generator local annunciator panel. An indication of which of the protective trips is activated first is provided on the local annunciator panel to facilitate diagnosis of trouble. The surveillance feature which would indicate the first diesel generator protective trip, is not necessary for the safe and orderly shutdown and for maintaining the CHAPTER 01 1.8-22 REV. 19, SEPTEMBER 2018

LGS UFSAR plant in a safe shutdown condition. Periodic testing of the diesel generators is described in Section 8.1.6.1.20. LGS will be in conformance during operation as discussed and clarified in Chapter 16.

(Category 2)

REGULATORY GUIDE 1.109 Calculations of Annual Doses to Man from Routine Releases of Reactor Effluents for the Purpose of Evaluating Compliance with 10CFR50, Appendix I Rev 1, October 1977 LGS is in conformance with this guide as discussed in Section 5.2 of the EROL.

(Category 1)

REGULATORY GUIDE 1.110 Cost-Benefit Analysis for Radwaste Systems for Light-Water-Cooled Nuclear Power Reactors Rev 0, March 1976 This guide is not applicable to LGS (being for plants whose construction permit applications are docketed after June 4, 1976). This analysis was not performed for LGS.

(Category 1)

REGULATORY GUIDE 1.111 Methods for Estimating Atmospheric Transport and Dispersion of Gaseous Effluents in Routine Releases from Light-Water-Cooled Reactors Rev 1, July 1977 LGS is in conformance with this guide except for certain alternate approaches as discussed in Section 2.3.

(Category 1)

REGULATORY GUIDE 1.112 Calculation of Releases of Radioactive Materials in Gaseous and Liquid Effluents from Light-Water-Cooled Power Reactors Rev 0-R, May 1977 LGS is in conformance with this guide as discussed in Section 11.1.

(Category 1)

REGULATORY GUIDE 1.113 Estimating Aquatic Dispersion of Effluents from Accidental and Routine Releases for the Purpose of Implementing Appendix I Rev 1, April 1977 LGS is in conformance with this guide as discussed in Section 5.2 of the EROL.

(Category 1)

CHAPTER 01 1.8-23 REV. 19, SEPTEMBER 2018

LGS UFSAR REGULATORY GUIDE 1.114 Guidance on Being Operator at the Controls of a Nuclear Power Plant Rev 1, November 1976 LGS will be in conformance with the guide.

(Category 3)

REGULATORY GUIDE 1.115 Protection Against Low-Trajectory Turbine Missiles Rev 1, July 1977 The LGS analysis does not employ the guidelines of paragraph C.4 regarding damage probabilities assuming turbine failure. However, the total probability, calculated using assumptions acceptable to NRC on other projects, is well within the limits. Details are discussed in Section 3.5.1.3.

(Category 2)

REGULATORY GUIDE 1.116 Quality Assurance Requirements for Installation, Inspection, and Testing of Mechanical Equipment and Systems Rev 0-R, May 1977 This guide endorses/modifies ANSI N45.2.8 (1975). The ANSI standard is not specifically a part of the construction QA program, however, LGS is in general conformance with the guide. Quality assurance during construction is discussed in the document "LGS Generating Station Units 1 and 2; Summary Description of the Quality Assurance Program for Design and Construction."

The commitments to this Regulatory Guide and ANSI N45.2.8 were deleted since they were superseded by Exelons commitment to ASME NQA-1 1994 subpart 2.8.

(Category 1)

REGULATORY GUIDE 1.117 Tornado Design Classification Rev 1, April 1978 Although this guide does not apply to LGS (being for plants whose construction permit applications are docketed after May 30, 1978), LGS is in conformance except that an alternate approach is used for protection of the spray pond spray networks. Details are discussed in Section 3.5.1.4.

(Category 2)

REGULATORY GUIDE 1.118 Periodic Testing of Electric Power and Protection Systems Rev 2, June 1978 This guide, which endorses/modifies IEEE 338 (1977), does not apply to LGS except for the RRCS (being for plants whose construction permit applications are docketed after issuance of the guide).

The design for periodic testing of electric power and protection systems is discussed in Sections 8.1.6.1 and 7.1.2.5, respectively.

(Category 1)

CHAPTER 01 1.8-24 REV. 19, SEPTEMBER 2018

LGS UFSAR REGULATORY GUIDE 1.119 Surveillance Program for New Fuel Assembly Design Rev 0, June 1976 This guide was withdrawn June 1977.

REGULATORY GUIDE 1.120 Fire Protection Guidelines for Nuclear Power Plants Rev 1, November 1977 Per the letter transmitting Regulatory Guide 1.120 (Rev 1) LGS will be evaluated against BTP ASB 9.5-1 in lieu of this guide. LGS's conformance to ASB 9.5-1 is discussed in Appendix 9A.

(Category 1)

REGULATORY GUIDE 1.121 Bases for Plugging Degraded PWR Steam Generator Tubes Rev 0, August 1976 This guide is for PWRs and therefore is not applicable to LGS.

REGULATORY GUIDE 1.122 Development of Floor Design Response Spectra for Seismic Design of Floor-Supported Equipment or Components Rev 1, February 1978 This guide is not applicable to LGS (being for plants whose construction permit applications are under review after issuance of the guide). LGS floor design response spectra are discussed in Section 3.7.2.3.

(Category 1)

REGULATORY GUIDE 1.123 Quality Assurance Requirements for Control of Procurement of Items and Services for Nuclear Power Plants Rev 1, July 1977 Historical Information This guide endorses/modifies ANSI N45.2.13 (1976). Neither the guide nor the ANSI standard are specifically used during construction. Quality assurance during construction is discussed in the document "LGS Generating Station Units 1 and 2; Summary Description of the Quality Assurance Program for Design and Construction." LGS will conform during operation, as discussed and clarified in the QATR.

Regulatory Guide 1.123, Rev 1 has been withdrawn and superseded by Regulatory Guide 1.28, Rev 3, August 1985.

CHAPTER 01 1.8-25 REV. 19, SEPTEMBER 2018

LGS UFSAR Limerick will conform to Regulatory Guide 1.28, Rev.3, August 1985 during operation, as discussed and clarified in the QATR.

(Category 1)

REGULATORY GUIDE 1.124 Service Limits and Loading Combinations for Class 1 Linear-Type Component Supports Rev 1, January 1978 This guide does not apply to LGS (being for plants whose construction permit applications are docketed after January 10, 1978). This guide has not been used on LGS, and procedures for the subject matter of this guide are discussed in Section 3.9.

(Category 2)

REGULATORY GUIDE 1.125 Physical Models for Design and Operation of Hydraulic Structures and Systems for Nuclear Power Plants Rev 1, October 1978 This guide is not applicable to LGS (being for plants whose construction permits are under review after issuance of the guide).

(Category 1)

REGULATORY GUIDE 1.126 An Acceptable Model and Related Statistical Methods for the Analysis of Fuel Densification Rev 1, March 1978 This guide has not been applied. The fuel densification analysis defined in section 4.2.4.4.11 of NEDE-20944-P, "BWR 4/5 Fuel Design", September 1976 has been found acceptable by the NRC and is applicable to LGS.

(Category 1)

REGULATORY GUIDE 1.127 Inspection of Water-Control Structures Associated with Nuclear Power Plants Rev 1, March 1978 LGS will be in conformance with this guide during construction of the spray pond. The various investigations and inspections associated with the spray pond are discussed in Sections 2.4 and 2.5. LGS will be in conformance with this guide during operation.

(Category 3)

REGULATORY GUIDE 1.128 Installation Design and Installation of Large Lead Storage Batteries for Nuclear Power Plants Rev 1, October 1978 This guide is not applicable to LGS (being for plants whose construction permit applications are docketed after December 1, 1977). The LGS design of large lead storage battery facilities is discussed in Section 8.1.6.1 and 8.3.2.

CHAPTER 01 1.8-26 REV. 19, SEPTEMBER 2018

LGS UFSAR (Category 1)

REGULATORY GUIDE 1.129 Maintenance, Testing, and Replacement of Large Lead Storage Batteries for Nuclear Power Plants Rev 1, February 2 1978 This guide does not apply to LGS (being for plants whose construction permit applications are docketed after December 1, 1977). However, LGS is in conformance with this guide as described in Section 8.1.6.1. Periodic testing is discussed in Chapter 16 .

(Category 1)

REGULATORY GUIDE 1.130 Design Limits and Loading Combinations for Class 1 Plate-and-Shell-Type Component Supports Rev 0, July 1977 This guide is not applicable to LGS (being for plants whose construction permit applications are docketed after April 1, 1978). LGS design limits and loading combinations are discussed in Sections 3.9 and 5.4.1.4.

(Category 2)

REGULATORY GUIDE 1.131 Qualification Tests of Electric Cables, Field Splices, and Connections for Light-Water-Cooled Nuclear Power Plants Rev 0, August 1977 This guide is not applicable to LGS (being for plants whose construction permit applications are docketed after May 1, 1978). LGS qualification tests of electric cables, field splices, and connections are discussed in Section 3.11.

(Category 1)

REGULATORY GUIDE 1.132 Site Investigations for Foundations of Nuclear Power Plants Rev 1, March 1979 This guide is applicable to LGS only for new investigations conducted after March 30, 1979. No new investigations have been conducted since that time. Site investigations are discussed in Sections 2.4 and 2.5.

(Category 1)

REGULATORY GUIDE 1.133 Loose-Part Detection Program for the Primary System of Light-Water-Cooled Reactors Rev 1, May 1981 LGS is no longer in conformance with this guide. The Loose-Part Detection Program has been relaxed as discussed inn BWR Owners Group Licensing Topical Report NEDC-32975P and associated SER.

CHAPTER 01 1.8-27 REV. 19, SEPTEMBER 2018

LGS UFSAR REGULATORY GUIDE 1.134 Medical Certification and Monitoring of Personnel Requiring Operator Licenses Rev 2, April 1987 LGS will be in conformance with this guide, which endorses/ modifies ANSI/ANS 3.4-1983, as discussed in Section 13.1.

(Category 1)

REGULATORY GUIDE 1.135 Normal Water Level and Discharge at Nuclear Power Plants Rev 0, November 1977 This guide is not applicable to LGS (being for plants whose construction permits are docketed after May 1, 1978). The hydrologic analysis for LGS is discussed in Section 2.4.

(Category 1)

REGULATORY GUIDE 1.136 Material for Concrete Containments Rev 1, October 1978 This guide is not applicable to LGS (being for plants whose construction permit applications are docketed after November 30, 1978). LGS containment material is discussed in Section 3.8.1.

(Category 1)

REGULATORY GUIDE 1.137 Fuel Oil Systems for Standby Diesel Generators Rev 1, October 1979 This guide endorses/modifies ANSI N195 (1976) and is limited in its applicability to LGS to paragraph C.2, per the letter transmitting Revision 0 of this guide. LGS will conform to paragraph C.2 during operation, except that the fuel oil surveillance test requirements will be as described in the plant Technical Specifications. The design of fuel oil transfer system is discussed in Section 9.5.4.

(Category 2)

REGULATORY GUIDE 1.138 Laboratory Investigations of Soils for Engineering Analysis and Design of Nuclear Power Plants Rev 0, April 1978 This guide is applicable to LGS only for new investigations conducted after December 1, 1978. No new investigations have been conducted since that time. Site investigations are discussed in Sections 2.4 and 2.5.

(Category 1)

CHAPTER 01 1.8-28 REV. 19, SEPTEMBER 2018

LGS UFSAR REGULATORY GUIDE 1.139 Guidance for Residual Heat Removal Rev 0, May 1978 Although the LGS design was completed prior to the issuance of this guide, LGS is in conformance with the intent, subject to clarifications regarding system protection features and pressure relief discussed in Section 5.4.7. LGS will be in conformance with this guide during operation.

(Category 3)

REGULATORY GUIDE 1.140 Design, Testing, and Maintenance Criteria for Normal Ventilation Exhaust System Air Filtration and Adsorption Units of Light-Water-Cooled Nuclear Power Plants Rev 1, October 1979 This guide is not applicable to LGS per its implementation section. The LGS design was substantially completed prior to the issuance of this guide. For explanatory purposes, a comparison with Revision 1 of the guide is provided in Table 9.4-18.

(Category 1)

REGULATORY GUIDE 1.141 Containment Isolation Provisions for Fluid Systems Rev 0, April 1978 The LGS containment isolation system was substantially completed prior to the issuance of this guide which endorses/modifies ANSI N271 (1976). LGS is in conformance with the guide except for certain design features of closed systems inside containment, valve leakage control and leak testing. Details are provided in Section 6.2.4.

(Category 2)

REGULATORY GUIDE 1.142 Safety-Related Concrete Structures for Nuclear Power Plants (Other than Reactor Vessels and Containments)

Rev 0, April 1978 This guide, which endorses/modifies ACI 349-76, is not entirely applicable to LGS (being for plants whose construction permit applications are docketed after December 15, 1978). Practices specified in the UFSAR for design and construction of safety related concrete structures bring LGS into compliance with substantial portions of the guide. LGS safety-related concrete structures are discussed in Section 3.8.

(Category 1)

REGULATORY GUIDE 1.143 Design Guidance for Radioactive Waste Management Systems Structures and Components Installed in Light-Water- Cooled Nuclear Power Plants Rev 1, October 1979 LGS is in conformance with the intent of the guide, subject to the exceptions and clarifications listed in Table 3.2-1, Note 18. The design codes, standards, and quality assurance for radwaste CHAPTER 01 1.8-29 REV. 19, SEPTEMBER 2018

LGS UFSAR system piping and components are presented and discussed in Table 3.2-1; design of the radwaste structure is discussed in Section 3.8; radwaste management systems are discussed in Chapter 11.

(Category 1)

REGULATORY GUIDE 1.144 Auditing of Quality Assurance Programs for Nuclear Power Plants Rev 1, September 1980 This guide endorses/modifies ANSI N45.2.12 (1977). The guide and the ANSI standard are not specifically utilized during construction. Quality assurance during construction is discussed in the document "LGS Generating Station Units 1 and 2; Summary Description of the Quality Assurance Program for Design and Construction."

Regulatory Guide 1.28 superseded commitments to RG 1.144. LGS will comply with Regulatory Guide 1.28 during operation, as described in the QATR.

(Category 1)

REGULATORY GUIDE 1.145 Atmospheric Dispersion Models for Potential Accident Consequence Assessments at Nuclear Power Plants Rev 1, November 1982 The LGS X/Q values resulting at the EAB and LPZ are calculated using the NRC sponsored computer code PAVAN consistent with the procedures in Regulatory Guide 1.145, as discussed in Section 2.3.

REGULATORY GUIDE 1.146 Qualification of Quality Assurance Program Audit Personnel for Nuclear Power Plants Rev 0, August 1980 LGS will comply with this guide, which endorses/modifies ANSI N45.2.23 (1978), as described in the QATR.

Regulatory Guide 1.28 superseded commitments to RG 1.146. LGS will comply with Regulatory Guide 1.28 during operation, as described in the QATR.

REGULATORY GUIDE 1.147 Inservice Inspection Code Case Acceptability ASME Section XI Division 1 Latest Revision LGS conforms with this guide as specified in the Inservice Inspection Program and Inservice Testing documents .

REGULATORY GUIDE 1.148 Functional Specification for Active Valve Assemblies in Systems Important to Safety in Nuclear Power Plants Rev 0, March 1981 The program (Section 3.9.3.2b) for the initial procurement of LGS valves was developed prior to the issuance of Regulatory Guide 1.148 and therefore does not include such a functional valves CHAPTER 01 1.8-30 REV. 19, SEPTEMBER 2018

LGS UFSAR specification. However, the intent of a functional specification has been met by functional requirements in the existing valve specification.

REGULATORY GUIDE 1.150 Ultrasonic Testing of Reactor Vessel Welds During Preservice and Inservice Examinations Rev 1, February 1983 LGS will be in conformance with Regulatory Guide 1.150 to the extent practicable. The extent of compliance will be submitted with the RPV PSI Report.

REGULATORY GUIDE 1.155 Station Blackout Rev. 0, August 1988 LGS is in conformance with this guide by virtue of compliance with NUMARC 87-00, November 1987, except where Regulatory Guide 1.155 takes precedence. Compliance is discussed in Section 8.1.6.1.25.

REGULATORY GUIDE 1.166 Pre-earthquake Planning and Immediate Nuclear Power Plant Operator Postearthquake Actions March 1997 This guide provides guidance acceptable to the NRC staff for a timely evaluation after an earthquake of the recorded instrumentation data and for determining whether plant shutdown is required by 10 CFR Part 50.

REGULATORY GUIDE 1.167 Restart of a Nuclear Power Plant Shut Down by a Seismic Event March 1997 This guide provides guidance acceptable to the NRC staff for performing inspections and tests of nuclear power plant equipment and structures prior to restart of a plant that has been shut down by a seismic event.

REGULATORY GUIDE 1.181 Content of the Updated Final Safety Analysis Report in accordance with 10 CFR 50.71(e)

Rev 0, September 1999 This Guideline endorses NEI 98-03, Revision 1, Industry Update Guidelines for Final Safety Analysis Reports.

REGULATORY GUIDE 1.183 Alternative Radiological Source Terms for Evaluating Design Basis Accidents at Nuclear Power Reactors Rev 0, July 2000 This guideline supersedes Regulatory Guides 1.3, 1.5, and 1.25 for assumptions and methodology for assessing radiological consequences of design basis accidents. Alternative Source Terms (AST) for determination of off-site and control room dose was approved for use at LGS by NRC Safety Evaluation Report dated September 8, 2006. LGS is in conformance with this Regulatory Guide, with a one-time exception, as discussed in Section 15.0.4.

CHAPTER 01 1.8-31 REV. 19, SEPTEMBER 2018

LGS UFSAR REGULATORY GUIDE 1.190 Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence Rev 0, March 2001 This Guideline was not used as a design basis, which is discussed in Section 4.1.4.5, 4.3.2.8 and 5.3.1.6.2. LGS reactor pressure vessel neutron fluence calculations performed after October 2002 will be in conformance with this guide (Reference 5.3-13).

REGULATORY GUIDE 1.194 Atmospheric Relative Concentrations for Control Room Radiological Habitability Assessments at Nuclear Power Plants Rev 0, July 2003 The LGS X/Q values resulting at the control room intake are calculated using the NRC sponsored computer code ARCON96, consistent with the procedures in Regulatory Guide 1.194, as discussed in Section 2.3.

CHAPTER 01 1.8-32 REV. 19, SEPTEMBER 2018

LGS UFSAR Table 1.8-1 COMPONENT IDENTIFICATION FOR CODE CASE N242 VALVE OR SYSTEM PARTS OR COMPONENTS PSV-44-1F036 Screw ring pin, disc, spring steps,

-2F036 compression screw, gag screw, stem, base.

PSV-50-1F018 Base, disc, compression screw,

-2F018 spring step, gag screw, stem, guide.

PSV-50-1F033 Base, disc, stem, guide, compression

-2F033 screw, spring steps, gag screws.

PSV-51-1F025A,B,C,D Disc, stem, compression screw,

-2F025A,B,C,D spring step, cap, gag screw, base(1), guide.

PSV-51-1F029 Base, disc, stem, compression screw,

-2F029 spring step, cap, gag screw, guide.

PSV-51-1F030A,B,C,D Base, disc, stem, compression screw,

-2F030A,B,C,D spring step, cap, gag screw, guide.

PSV-51-1F097 Nozzle, disc, disc holder, guide,

-2F097 stem, adjusting ring, compression screw, spring step, screw ring pin, gag screw.

PSV-56-1F018 Nozzle, disc, disc holder, guide,

-2F018 stem, gag screw, adjusting ring, compression screw, spring step, screw ring pin.

PSV-56-1F020 Base, disc, stem, spring step,

-2F020 compression screw, gag screw, guide.

PSV-51-1F055A,B Adjusting bolt, disc insert, spindle PSV-51-2F055A,B point.

PSV-56-1F050 Base, disc, guide, compression screw,

-2F050 spring steps, gag screw, stem.

PSV-69-145 Stem, compression screw, spring

-245 steps, cap, base, disc, guide.

PSV-50-219 Base, stem, gag screw.

CHAPTER 01 1.8-33 REV. 13, SEPTEMBER 2006

LGS UFSAR Table 1.8-1 (Cont'd)

VALVE OR SYSTEM PARTS OR COMPONENTS PSV-56-225 Base, stem, gag screw.

PSV-45-1-61 Guide, compression screw, spring step.

PSV-45-1-62A,B Compression screw, spring steps, gag screw.

PSV-45-1-63 Guide, compression screw, spring steps.

PSV-45-1-65 Guide, compression screw, spring steps.

PSV-45-1-67 Guide, compression screw, spring steps.

PSV-52-127 Guide, compression screw, spring steps, gag screw.

PSV-52-2F012A,B Spring step, base, disc, gag screw, guide, compression screw, stem.

Main steam system, Pipe clamp for snubber, Unit 1 Mark: 26 in.-50k-M.S.

Main steam system, Pipe clamp for snubber, Unit 2 Mark: 26 in.-50k-M.S.

Recirculation system, Pipe clamp for snubber, Unit 1 Mark: 22 in.-50k-Recirc.

Recirculation system, Pipe clamp for snubber, Unit 2 Mark 22 in.-50k-Recirc.

Recirculation system, Pipe clamp for snubber, Unit 1 Mark: 28 in.-50k-Recirc. Disc.

Recirculation system, Pipe clamp for snubber, Unit 2 Mark: 28 in.-50k-Recirc. Disc.

Recirculation system, Pipe clamp for snubber, Unit 1 Mark: 28 in.-50k-Recirc. Suct.

Recirculation system, Pipe clamp for snubber, Unit 2 Mark: 28 in.-50k-Recirc. Suct.

CHAPTER 01 1.8-34 REV. 13, SEPTEMBER 2006

LGS UFSAR Table 1.8-1 (Cont'd)

VALVE OR SYSTEM PARTS OR COMPONENTS Diesel generator Starting air receiver system Diesel generator Starting air system piping and valves system Diesel generator Fuel oil day tank system Diesel generator Fuel oil system piping and valves system Diesel generator Lube oil makeup tank system Diesel generator Lube oil system piping and valves system Diesel generator Jacket water expansion tank system Diesel generator Jacket water intercooler piping system and valves (1)

Unit 1 only CHAPTER 01 1.8-35 REV. 13, SEPTEMBER 2006

LGS UFSAR 1.9 STANDARD DESIGNS This section is not applicable to LGS as it is not a standard design plant.

CHAPTER 01 1.9-1 REV. 13, SEPTEMBER 2006

LGS UFSAR 1.10 SYMBOLS AND TERMS 1.10.1 TEXT ACRONYMS Acronyms used throughout the UFSAR are listed in Table 1.10-1.

1.10.2 LOGIC SYMBOLS Logic symbols used on FCDs are shown in Figure 1.10-2.

1.10.3 PIPING IDENTIFICATION Piping is identified by a three-group identifier where the first group is the nominal pipe size in inches; the second is a three-letter group for the pipe class; and the third is a three-digit group sequentially assigned within a pipe class.

Example:

6" HBD 116 Size-------------------------------------------------------------------------------------------

Class---------------------------------------------------------------------------------------------------

Sequence-------------------------------------------------------------------------------------------------------

The three-letter group for the pipe class is described in detail in Table 1.10-2.

The three-digit sequence number is assigned consecutively to identify specific lines in a pipe class as follows:

Piping common to both units 0-99 and 500-699 Piping for Unit 1 100-199, 300-399, and 700-799 Piping for Unit 2 200-299, 400-499, and 800-899 1.10.4 VALVE IDENTIFICATION All manual and remotely operated valves have unique identification numbers for tracking purposes.

Listed below are the numbering systems used for each group of valves.

CHAPTER 01 1.10-1 REV. 13, SEPTEMBER 2006

LGS UFSAR Manual valves, except those which have a GE MPL number and those valves supplied by vendors as part of an equipment package and not installed by Bechtel, are identified by the following method:

52 1 006 System identification------------------------------------------------------------------

(P&ID number)

Unit number----------------------------------------------------------------------------------------

0 - Common 1 - Unit 1 2 - Unit 2 Sequence number------------------------------------------------------------------------------------------

(3-digit numbers)

Remote-operated valves that do not have a GE MPL number are identified by the operator number as follows:

HV 52 1 06 Valve type----------------------------------------------------------------------

System identification-------------------------------------------------------------------

(P&ID number)

Unit number----------------------------------------------------------------------------------------

Sequence number------------------------------------------------------------------------------------------

Those valves in GE's MPL are identified by the GE numbering system as follows:

HV E11 1 F031 Valve type----------------------------------------------------------------------

MPL system number-------------------------------------------------------------------

(Referenced on P&ID notes)

Unit number----------------------------------------------------------------------------------------

GE Valve number-------------------------------------------------------------------------------------------

Valve types are indicated in drawing M-00. Valves that are not numbered but are supplied as part of a vendor mounted equipment package are identified in the vendor's operation and maintenance manuals. This is done to avoid duplication in numbering these valves.

CHAPTER 01 1.10-2 REV. 13, SEPTEMBER 2006

LGS UFSAR 1.10.5 EQUIPMENT NUMBERING Equipment is identified on the P&IDs by a four-group identifier as discussed below.

Example:

1 A P 101 Unit number-------------------------------------------------------------------

0 - Common 1 - Unit 1 2 - Unit 2 Number of items per unit-------------------------------------------------------------

(Lettered alphabetically if more than one item; a zero(0) is used if only one item)

Equipment classification------------------------------------------------------------------------

(See description below)

Sequence number--------------------------------------------------------------------------------------------

Equipment classification is identified by type as follows:

A 13.8, 4.16, and 2.4 kV switchgear B 440 V load centers and motor control centers C Control boards or relay boards D Direct current equipment F Filters and cleaning equipment G Generators (turbine, diesel) and associated equipment H Hoists and cranes K Air compressors, chiller compressors, process fans, and blowers L Lighting, heater, and distribution panels P Pumps including drive motors R 33/220/500 kV switchgear and associated equipment S Miscellaneous T Tanks and pressure vessels U Floor sections V Air conditioning units, ventilation fans and exhausters W Power receptacles X Transformers Y Instrument ac equipment Z Computer equipment CHAPTER 01 1.10-3 REV. 13, SEPTEMBER 2006

LGS UFSAR 1.10.6 ELECTRICAL COMPONENT IDENTIFICATION This section describes the methods used to identify electrical equipment locations and to number electrical schemes, cables, and raceways.

1.10.6.1 Equipment Location Numbers Each piece of electrical equipment is identified by an equipment number as described in Section 1.10.4. To facilitate cable routing from one equipment location to another, a location number is also assigned to each piece of electrical equipment. Generally, the equipment number and equipment location number for a specific piece of electrical equipment are identical. For large pieces of electrical equipment, such as switchgear, load centers, and MCC, which are compartmentalized, the equipment location number consists of the basic equipment number plus additional suffixed information to identify a location within the equipment itself. The following two examples illustrate equipment location numbers:

Example 1: 10X101 Example 2: 10B22403 In the first example, the equipment number and equipment location number for transformer 10X101 are identical. In the second example, the basic MCC equipment number 10B224 is suffixed to establish an equipment location number, 10B22403, which identifies a specific cubicle within the MCC.

Equipment location numbers are generally assigned to items listed in the circuit and raceway schedules. Accordingly, most electrical equipment related to systems such as lighting, communications, and cathodic protection is not included.

Electrical equipment that is an integral part of mechanical equipment is assigned the same number as the mechanical equipment.

1.10.6.2 Scheme Cable Numbers Each electrical scheme is identified by a number with up to nine characters. The first character is numeric and refers to the plant unit number for which the scheme is applicable. The second character is alphabetic or numeric and refers to the separation group to which the cable belongs.

The third character is alphabetic and classifies the scheme by major plant system. The next six characters are numeric or alphanumeric, and provide a sequential, but arbitrary, identity for each scheme. (The letter designation at the end of the scheme number is the cable number.) Except for cabling associated with the plant lighting, communications, and cathodic protection systems, each cable in the plant is identified by a scheme cable number. Given below is an example of a typical scheme number including the cable number.

CHAPTER 01 1.10-4 REV. 13, SEPTEMBER 2006

LGS UFSAR 1 A Q 00100 A Unit number-------------------------------------------------------

System/channel identification---------------------------------------------

Plant system---------------------------------------------------------------------------

Scheme sequential number--------------------------------------------------------------------

Cable number----------------------------------------------------------------------------------------------

1.10.6.3 Raceway Numbers All electrical cable trays, ducts, conduits, manholes, conduit sleeves, and junction boxes are identified by six-character raceway numbers. The two examples given below illustrate typical raceway numbers for safety-related and nonsafety-related cable trays, respectively.

Safety-related 1 A C B B 01 Unit number----------------------------------------------

System/channel identification----------------------------------

Function------------------------------------------------------------------------

Main run--------------------------------------------------------------------------------

Branch run-----------------------------------------------------------------------------------------

Section number - (tray section 01)--------------------------------------------------------------------

Nonsafety-related 1 0 I B C 85 Unit Number----------------------------------------------

System/channel identification--------------------------------

Function-------------------------------------------------------------------------

Main run----------------------------------------------------------------------------------

Branch run------------------------------------------------------------------------------------------

Section number - (tray section 85)---------------------------------------------------------------------

CHAPTER 01 1.10-5 REV. 13, SEPTEMBER 2006

LGS UFSAR The following example illustrates a typical conduit number:

1 A S 999 Unit number-------------------------------------------------------------------

System/channel identification-----------------------------------------------------

Conduit location-----------------------------------------------------------------------------------

Conduit sequential number - (arbitrary no.)----------------------------------------------------------

CHAPTER 01 1.10-6 REV. 13, SEPTEMBER 2006

LGS UFSAR Table 1.10-1 ACRONYMS USED IN UFSAR AASHTO American Association of State Highway and Transportation Officials ABS absolute summation AC alternating current ACI American Concrete Association ACRS Advisory Committee on Reactor Safeguards ADS automatic depressurization system AE Architect/Engineer AEC Atomic Energy Commission AEOE-RMS air ejector offgas effluent radiation monitoring system AERVS auxiliary equipment room ventilation system AGC automatic gain control AGL above ground level AGMA American Gear Manufacturer Association AISC American Institute of Steel Construction AISI American Iron and Steel Institute ALARA as low as reasonably achievable AMCA Air Moving and Conditioning Association AMS American Meteorological Society ANI American Nuclear Insurers ANS American Nuclear Society ANSI American National Standards Institute AOV air-operated valve CHAPTER 01 1.10-7 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.10-1 (Cont'd)

APRM average power range monitor ARI alternate rod insertion ARMS area radiation monitoring system ARS acceleration response spectra ASCE American Society of Civil Engineers ASHRAE American Society of Heating, Refrigeration and Air Conditioning Engineers ASME B&PV American Society of Mechanical Engineers Boiler Code and Pressure Vessel Code ASTM American Society for Testing and Materials ATM analog trip module ATWS anticipated transient without scram ASD Adjustable Speed Drive AST alternative source term AWS American Welding Society AWWA American Water Works Association BMI Battelle Memorial Institute BNL Brookhaven National Laboratory BOC beginning of cycle BOP balance of plant BPV bypass valve BTP Branch Technical Position BWR boiling water reactor BWROG Boiling Water Reactor Owners Group CAC containment atmospheric control CAM continuous air monitor CAS central alarm station CHAPTER 01 1.10-8 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.10-1 (Cont'd)

CCU condensate cleanup CECWS control enclosure chilled water system CFD condensate filter/demineralizer CFR Code of Federal Regulations CGCS combustible gas control system CIGS containment instrument gas system CIGS-ADS containment instrument gas system - ADS control CIV combined intermediate valves CMAA Crane Manufacturers Association of America CMTR Certified Material Test Reports CO condensation oscillation CO-ADS condensation oscillation with ADS CP collection points CPR critical power ratio CPU central processing unit CRD control rod drive CRDM control rod drive mechanism CRDR Control Room Design Review CRGR Committee to Review Generic Requirements CREFAS control room emergency fresh air supply system CREFA-RMS control room emergency fresh air radiation monitoring system CRT cathode ray tube or equivalent video display interface device CRV-RMS control room ventilation radiation monitoring system CS core spray (system)

CSCWS control structure chilled water system CST condensate storage tank CHAPTER 01 1.10-9 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.10-1 (Cont'd)

CTSP-RMS charcoal treatment system process exhaust radiation monitoring system CVN charpy v-notch DA drainage area DAC distance-amplitude correction DAR Design Assessment Report DAS data acquisition system DBA design basis accident DBCD deep bed condensate demineralizer DBE design basis earthquake DBFL design basis flood level DC direct current DCWS drywell chilled water system DDOF dynamic degrees of freedom DEMA Diesel Engine Manufacturers Association DF decontamination factor DFFR Dynamic Forcing Function Information Report DG diesel generator DGEVS diesel generator enclosure ventilation system D-LDS drywell leak detection system DLPL digital loose parts locator DLV discharge line volume DLWL discharge line water-leg length DOP di-octylphthalate DOR Division of Operating Reactors (NRC)

DOT Department of Transportation DRBC Delaware River Basin Commission CHAPTER 01 1.10-10 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.10-1 (Cont'd)

DSLMS drywell sump level monitoring system DUC drywell unit coolers EAB exclusion area boundary ECCS emergency core cooling systems ECCS-UC emergency core cooling systems pump compartment unit coolers ECL effluent concentration limit EFCV excess flow check valve EFPY effective full power years EGM electronic governor module EHC electrohydraulic control ELLR extended lead line region EMI electromagnetic interference EOC end of cycle EOF emergency operations facility EOL end of life EOP emergency operating procedure EPA Environmental Protection Agency EPG emergency procedure guidelines/severe accident guidelines EPRI Electric Power Research Institute E/P electrical-to-pneumatic EQ environmental qualification EQR Environmental Qualification Report ERDA Energy and Research Development Administration ERFDS emergency response facility data system EROL Environmental Report - Operating License Stage CHAPTER 01 1.10-11 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.10-1 (Cont'd)

ESBRCS emergency switchgear and battery rooms cooling system ESD emergency shutdown ESF engineered safety feature ESW emergency service water (system)

FAA Federal Aviation Administration FATT fracture appearance transition temperature FCD functional control diagram FCS feedwater control system FM factory mutual FMEA failure modes and effects analysis FPCC fuel pool cooling and cleanup FPER Fire Protection Evaluation Report FPSS fire protection and suppression system FSAR Final Safety Analysis Report FSI fluid-structure interaction GDC General Design Criterion GE General Electric Company GE-NEPD General Electric - Nuclear Energy Program Division GKN Gemeinschaftskernkraftwerk Neckar GM Geiger-Mueller GRS gaseous radwaste system HCU hydraulic control unit HCRIS habitability and control room isolation system HED human engineering discrepancies CHAPTER 01 1.10-12 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.10-1 (Cont'd)

HELB high energy line break HEPA high efficiency particulate air HIC high integrity container HMI human machine interface HMS-RMS hot maintenance shop ventilation exhaust radiation monitoring system HP high pressure HPCI high pressure coolant injection (system)

HPCI-LDS HPCI leak detection system HPLPSI high pressure/low pressure system interlocks HSA high specific activity HTGR high temperature gas reactor HX heat exchanger H&V heating and ventilation HVAC heating, ventilation, and air conditioning HWC hydrogen water chemistry (system)

IBA intermediate break accident ICC inadequate core cooling ICFR increased core flow region IED instrument and electrical diagram IEEE Institute of Electrical and Electronics Engineers IES Illuminating Engineering Society IFR instrument flight rule IGSCC intergranular stress corrosion cracking ILRT integrated leak rate test INPO Institute of Nuclear Power Operations I/O input/output CHAPTER 01 1.10-13 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.10-1 (Cont'd)

IP intermediate pressure IPCEA Insulated Power Cable Engineers Association IPE Individual Plant Examination IRM intermediate range monitor ISI inservice inspection IWRC iron wire rope core KKB Kernkraftwerk Brunsbuettel KKPI Kernkraftwerk Phillipsburg KRB Kernkraftwerk RWE-Bayernwerk KWU Kraftwerk Union Atienqesellschaft LCO limiting condition of operation LD load LDS leak detection system LGS Limerick Generating Station LHGR linear heat generation rate LLRT local leak rate test LO licensed operators LOCA loss-of-coolant accident LOOP loss of offsite power LOR Licensed Operator Requalification Training Program LP low pressure LPCI low pressure coolant injection (system)

LPG liquid propane gas CHAPTER 01 1.10-14 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.10-1 (Cont'd)

LPRM local power range monitor LPZ low population zone LRD-RMS liquid radwaste discharge radiation monitoring system LRS liquid radwaste system LSA low specific activity LWR light water reactor MAPLHGR maximum average planar linear heat generation rate MARSS multiplex analog recording and switching system MCC motor control center MCM thousand circular mils MCPR minimum critical power ratio MES Meteorological Evaluation Services, Inc.

MFLCPR maximum fraction of limiting critical power ratio MFLPD maximum fraction of limiting power density MG motor-generator (set)

MLE mils lateral expansion MLHGR minimum linear heat generation rate MMDRS meteorological monitoring display and reporting system MOV motor-operated valves MPC maximum permissible concentration MPL master parts list MSIV main steam isolation valve MSIV-LCS main steam isolation valve leakage control system MSL-LDS main steam line leak detection system CHAPTER 01 1.10-15 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.10-1 (Cont'd)

MSL mean sea level MSL-RMS main steam line radiation monitoring system MSRV main steam relief valve MWL Maximum working load MUR PU Measurement Uncertainty Recapture - Power Uprate NAI Nuclear Associates International NBR nuclear boiler rated NBS National Bureau of Standards NDE non-destructive examination NDT nil ductility transition NDTT nil ductility transition temperature NEMA National Electrical Manufacturers Association NFPA National Fire Protection Association NMS neutron monitoring system NOAA National Oceanic and Atmospheric Administration NPSH net positive suction head NRB Nuclear Review Board NRC Nuclear Regulatory Commission NSE-RMS north stack effluent radiation monitoring system NSOA Nuclear Safety Operational Analysis NSSS nuclear steam supply system NSSSS nuclear steam supply shutoff system NTSB National Transportation and Safety Board NUMAC Nuclear Measurement Analysis and Control NWC normal water chemistry NWS National Weather Service CHAPTER 01 1.10-16 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.10-1 (Cont'd)

OBE operating basis earthquake ODA Operating Display Assembly OPEX Operating Experience OJT on-the-job training OLCPR operating limit critical power ratio OPRM Oscillation Power Range Monitor OSC Operations Support Center OSHA Occupational Safety and Health Administration OS&Y outside screw and yoke OT operational transient PA public address (system)

PAB protected area boundary PABX private automatic branch system PASS postaccident sampling system PBAPS Peach Bottom Atomic Power Station PCIG primary containment isolation gas (system)

PCLD-RMS primary containment leak detector radiation monitoring system PCPL-RMS primary containment post-LOCA radiation monitoring system PCRVICS primary containment and reactor vessel isolation control system PCT peak cladding temperature PCVR primary containment vacuum relief PFH partial feedwater heating PGCC power generation control complex P&ID piping and instrument diagram CHAPTER 01 1.10-17 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.10-1 (Cont'd)

PJM Pennsylvania, New Jersey, Maryland (Interconnection)

PLC Programmable Logic Controller PMF probable maximum flood PMP probable maximum precipitation PMS plant monitoring system PORC Plant Operations Review Committee PPC plant process computer (system)

PRA probabilistic risk assessment PRNM power range neutron monitor PRPM process radiation plenum monitoring PRMS process radiation monitoring system PRTGS pressure regulator and turbine-generator system PSAR Preliminary Safety Analysis Report PSAT saturated steam pressure in the RPV steam dome PSD power spectrum density PSI preservice inspection PVC polyvinyl chloride PWR pressurized water reactor QA quality assurance QC quality control RAIS refueling area isolation system RAVE-RMS refueling area ventilation exhaust radiation monitoring system RBI rod block interlock RBM rod block monitor RCIC reactor core isolation cooling (system)

CHAPTER 01 1.10-18 REV. 17, SEPTEMBER 2014

LGS UFSAR RCIC-LDS RCIC leak detection system CHAPTER 01 1.10-19 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.10-1 (Cont'd)

RCIC-UC RCIC system pump compartment unit coolers RCPB reactor coolant pressure boundary RCS reactor coolant system RECW reactor enclosure cooling water (system)

RECW-RMS reactor enclosure cooling water radiation monitoring system REIS reactor enclosure isolation system RERS reactor enclosure recirculation system RERV-RMS radwaste equipment rooms ventilation exhaust radiation monitoring system REV-RMS radwaste enclosure ventilation exhaust radiation monitoring system REVE-RMS reactor enclosure ventilation exhaust radiation monitoring system RFCS recirculation flow control system RFPT reactor feed pump turbine RHR residual heat removal RHR-CSM RHR containment spray mode RHR-LDS RHR leakage detection system RHR-SCM RHR shutdown cooling mode RHR-SPCM RHR suppression pool cooling mode RHRSW RHR service water (system)

RHRSW-RMS RHR service water radiation monitoring system RHR-UC RHR system pump compartment unit coolers RI refueling interlocks RIO Remote Input/Output RMCS reactor manual control system RMDS radiation monitoring and display system CHAPTER 01 1.10-20 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.10-1 (Cont'd)

RMS radiation monitoring system RMMS radiation and meteorological monitoring system RO Reactor Operator RPIS rod position information system RPS reactor protection system RPS-LDS recirculation pump seal leak detection system RPT recirculation pump trip RPV reactor pressure vessel RPVH-LDS reactor pressure vessel head leak detection system RRCS redundant reactivity control system RRRC Regulatory Requirements Review Committee RRHAC-RMS recombiner rooms and hydrogen analyzer components exhaust radiation monitoring system RRS required response spectrum RSCS rod sequence control system RSS remote shutdown system RSSV RSS ventilation system RTD resistance temperature detector RTNDT reference temperature (nil ductility transition)

RVI reactor vessel instrumentation RWCU reactor water cleanup (system)

RWCU-LDS reactor water cleanup leak detection system RWM rod worth minimizer RWP radiation work permit SAE Society of Automotive Engineers CHAPTER 01 1.10-21 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.10-1 (Cont'd)

SARA severe accident risk assessment SAS secondary alarm station SAW submerged arc SBA small break accident SCA single channel analyzer SCR silicon control rectifier SDIV scram discharge instrument volume SDV scram discharge volume SEB Structural Engineering Branch (NRC)

SEDVP-RMS steam exhauster discharge and vacuum pump exhaust radiation monitoring system SEP Systematic Evaluation Program SEIP Extra improved plow steel SER Safety Evaluation Report SGTS standby gas treatment system SGTS-UC SGTS filter room and access area unit cooler SIF stress intensification factor SIL Service Information Letter (General Electric)

SJAE steam jet air ejector SLCS standby liquid control system SLO senior licensed operators SMAW shielded metal arc SMUD Sacramento Municipal Utility District SOP System Operating Program SPDS safety parameter display system SPF standard project flood CHAPTER 01 1.10-22 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.10-1 (Cont'd)

SPFS safeguard piping fill system SPPSVS spray pond pump structure ventilation system SS stainless steel SPTMS suppression pool temperature monitoring system SSPC Steel Structures Painting Council SOE sequence of events SORV stuck open relief valve SQRT Seismic Qualification Review Team SRDI safety-related display instrumentation SRM source range monitor SRO Senior Reactor Operator SRP Standard Review Plan SRS solid radwaste system SRSS square root of the sum of the squares SRV safety/relief valve SRV-LDS safety/relief valve leak detection system SRVPI safety/relief valve position indication SSO safe shutdown SSE safe shutdown earthquake SSER Supplemental Safety Evaluation Report SSES Susquehanna Steam Electric Station SSE-RMS south stack effluent radiation monitoring system STA Shift Technical Advisor STP startup test procedure SWS service water system CHAPTER 01 1.10-23 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.10-1 (Cont'd)

SW-RMS Service water radiation monitoring system TAF top of active fuel TC thermocouple TCV turbine control valve TECW turbine enclosure cooling water (system)

TEMA Tubular Exchanger Manufacturers Association TEMR totally enclosed metallic raceway TG turbine-generator TIP traversing incore probe TLD thermoluminescent dosimeter TLV threshold limit valve TMI Three Mile Island (Unit 2)

TRA transient recording and analysis TRB Test Review Board TRS test response spectrum TSC Technical Support Center TVA Tennessee Valley Authority UBC Uniform Building Code UC unit coolers UFSAR Updated Final Safety Analysis Report UHS ultimate heat sink UL Underwriter's Laboratories UPS uninterruptible power supply USAS United States of America Standards USGS United States Geological Survey CHAPTER 01 1.10-24 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.10-1 (Cont'd)

USI unresolved safety issue UT ultrasonic test UV undervoltage V&V verification and validation VBWR Vallecitos Boiling Water Reactor VFR visual flight rules VOR very high frequency omni-direction range ZPA zero point acceleration CHAPTER 01 1.10-25 REV. 17, SEPTEMBER 2014

LGS UFSAR Table 1.10-2 PIPING AND VALVE CLASS IDENTIFICATION Pipe and valve classes are designated by a three-letter code. The first letter indicates the primary valve and flange pressure rating; the second letter, the type of material; and the third letter, the code to which the piping is designed.

FIRST LETTER - PRIMARY PRESSURE RATING C - 1500 psi D - 900 psi E - 600 psi F - 400 psi G - 300 psi H - 150 psi I - 250 psi J - 125 psi K - 175 psi L - 75 psi M - General use as designated on piping class sheets N - Sanitary drainage R - Threaded vents and drains S - Welded vents and drains X - Special Rating SECOND LETTER - MATERIAL A - Alloy steel B - Carbon steel C - Austenitic steel D - Copper F - Carbon steel - copper bearing G - Carbon steel - lined H - Cast iron J - Alloy steel K - PVC L - Carbon steel - impact test as code requires M - Duriron N - Carbon steel - galvanized P - Bronze Q - Brass CHAPTER 01 1.10-26 REV. 13, SEPTEMBER 2006

LGS UFSAR Table 1.10-2 (Cont'd)

THIRD LETTER - DESIGN CODE A- Nuclear power plant components, ASME B&PV Code, Sect. III, Class 1 B- Nuclear power plant components, ASME B&PV Code, Sect. III, Class 2 C- Nuclear power plant components, ASME B&PV Code, Sect. III, Class 3 D- Power Piping Code ANSI B31.1.0 F- National Fire Protection Code G- National Plumbing Code CHAPTER 01 1.10-27 REV. 13, SEPTEMBER 2006

LGS UFSAR 1.11 RRRC CATEGORY 1, 2, 3, AND 4 MATTERS 1.11.1 DISCUSSION OF CATEGORIES The Regulatory Requirements Review Committee has characterized the backfitting potential of certain regulatory guides and branch technical positions or other proposed modifications to existing staff positions by placing them in one of three categories (Reference 1.11-1):

a. Category 1 - Clearly forward fit only. No further staff consideration of possible backfitting is required.

b. Category 2 - Further staff consideration of the need for backfitting appears to be required for certain identified items of the regulatory position. These individual issues are such that existing plants need to be evaluated to determine their status with regard to these safety issues in order to determine the need for backfitting.

c. Category 3 - Clearly backfit. Existing plants should be evaluated to determine whether identified items of the regulatory position are resolved in accordance with the guide or by some equivalent alternative.

In addition to the above RRRC categories, there also exists an Office of Nuclear Reactor Regulation (NRC) Category 4 list of those matters not yet reviewed by the RRRC, but which have been deemed by the Director, Office of Nuclear Reactor Regulation, to warrant being addressed and considered in ongoing reviews.

The NRC transmitted a list of Category 2, 3, and 4 matters to the licensee (Reference 1.11-2), and requested that the listed items be considered in the LGS FSAR. Reference 1.11-2 defines these categories as follows:

a. Category 1 - Matters are to be applied in accordance with the implementation section of the published guide.

b. Category 2 - This is a new position whose applicability is to be determined on a case-by-case basis.

c. Category 3 - Conformance or an acceptable alternative is required.

d. Category 4 - Matters are to be treated like Category 2 matters until such time as they are reviewed by the RRRC, and a definite implementation program is developed.

Table 1.11-1 identifies the UFSAR sections containing material relevant to the RRRC and to the NRC categorized matters with the exception of Category 1 (those to be implemented in accordance with the implementation section of the published NRC position) which are outside the scope of this appendix.

The categorization of regulatory guides in the RRRC and NRC lists is given in Section 1.8.

CHAPTER 01 1.11-1 REV. 13, SEPTEMBER 2006

LGS UFSAR 1.

11.2 REFERENCES

1.11-1 Memorandum, E.G. Case, Chairman, Regulatory Requirements Review Committee to L.V.

Gossick, Executive Director for Operations, Regulatory Requirements Review Committee Meeting No. 31, July 11, 1975, (September 24, 1975).

1.11-2 Letter, Roger S. Boyd (NRC) to Edward G. Bauer, Jr. (PECo), (November 20, 1978).

CHAPTER 01 1.11-2 REV. 13, SEPTEMBER 2006

LGS UFSAR Table 1.11-1 CORRELATION OF LGS UFSAR SECTIONS WITH CATEGORY 2, 3, AND 4 MATTERS( 1 )

DOCUMENT REVISION DATE( 2 ) TITLE UFSAR SECTION REFERENCE A. RRRC CATEGORY 2 MATTERS BTP ASB 9.5-1 1 - Guidelines for Fire Protection for 9.5.1, Appendix 9A Nuclear Power Plants BTP MTEB 5-7 - 4/77 Material Selection and Processing 5.2.3 Guidelines for BWR Coolant Pressure Boundary Piping B. RRRC CATEGORY 3 MATTERS BTP RSB 5-1 1 1/78 Design Requirements of the Residual 5.4 Heat Removal System BTP RSB 5-2 (Draft) 0 3/78 Overpressurization Protection of Not applicable Pressurized Water Reactors While to LGS Operating at Low Temperatures CHAPTER 01 1.11-3 REV. 13, SEPTEMBER 2006

LGS UFSAR Table 1.11-1 (Contd)

C. NRR CATEGORY 4 MATTERS IMPLEMENTATION APPLICABLE DATE BRANCH SRP SECTION TITLE UFSAR SECTION REFERENCE I. Standard Review Plan (SRP) Criteria

1. 11/24/75 MTEB 5.4.2.1 BTP MTEB 5-3, Monitoring of Secondary Side Not applicable Water Chemistry in PWR Steam Generators to LGS

2. 11/24/75 CSB 6.2.1 BTP CSB 6-1, Minimum Containment Pressure Not applicable Model for PWR ECCS Performance Evaluation to LGS

3. 11/24/75 CSB 6.2.5 BTP CSB 6-2, Control of Combustible Gas 6.2.5 Concentrations in Containment following a LOCA

4. 11/24/75 CSB 6.2.3 BTP CSB 6-3, Determination of Bypass 6.2.3 Leakage Path in Dual Containment Plants

5. 11/24/75 CSB 6.2.4 BTP CSB 6-4, Containment Purging During 6.2.1 Normal Plant Operations

6. 11/24/75 ASB 9.1.4 BTP ASB 9.1, Overhead Handling Systems 9.1.4 for Nuclear Power Plants

7. 11/24/75 ASB 10.4.9 BTP ASB 10.1, Design Guidelines for Not applicable Auxiliary Feedwater System Pump Drive to LGS and Power Supply Diversity for PWR's

8. 11/24/75 SEB 3.5.3 Procedures for Composite Section Local 3.5.3 Damage Prediction (SRP Section 3.5.3, par. II.1.C)

9. 11/24/75 SEB 3.7.1 Development of Design Time History for 3.7.1 Soil-Structure Interaction Analysis (SRP Section 3.7.1, par. II.2)

10. 11/24/75 SEB 3.7.2 Procedures for Seismic System Analysis 3.7.2 (SRP Section 3.7.2 par. II)

11. 11/24/75 SEB 3.7.3 Procedures for Seismic Sub-system 3.7.3 Analysis (SRP Section 3.7.3, par. II)

12. 11/24/75 SEB 3.8.1 Design and Construction of Concrete Contain- 3.8.1 ments (SRP Section 3.8.1, par. II)

CHAPTER 01 1.11-4 REV. 13, SEPTEMBER 2006

LGS UFSAR Table 1.11-1 (Contd)

IMPLEMENTATION APPLICABLE DATE BRANCH SRP SECTION TITLE UFSAR SECTION REFERENCE

13. 11/24/75 SEB 3.8.2 Design and Construction of Steel Contain- Not applicable ments (SRP Section 3.8.2, par. II) to LGS

14. 11/24/75 SEB 3.8.3 Structural Design Criteria for 3.8.3 Category I Structures Inside Containment (SRP Section 3.8.3, par. II)

15. 11/24/75 SEB 3.8.4 Structural Design Criteria for Other 3.8.4 Seismic Category I Structures (SRP Section 3.8.4, par. II)

16. 11/24/75 SEB 3.8.5 Structural Design Criteria for Foundations 3.8.5 (SRP Section 3.8.5, par. II)

17. 11/24/75 SEB 3.7, 11.2 Seismic Design Requirements for Radwaste 3.2, 3.8.4 11.3, 11.4 Systems and Their Housing Structures (SRP 11.2, 11.3, 11.4 Section 11.2, BTP ETSB 11-1, par. B.v)

18. 11/24/75 SEB 3.3.2 Tornado Load Effect Combinations 3.3.2 (SRP Section 3.3.2, par. II.2.d)

19. 11/24/75 SEB 3.4.2 Dynamic Effects of Wave Action (SRP 3.4.2 Section 3.4.2, par. II)

20. 10/01/75 ASB 10.4.7 Water Hammer for Steam Generators with Not applicable Preheaters (SRP Section 10.4.7 par. 1.2.b) to LGS

21. 11/24/75 AB 4.4 Thermal-Hydraulic Stability (SRP 4.4 Section 4.4, par. II.5)

22. 11/24/75 RSB 5.2.5 Intersystem Leakage Detection (SRP Section 5.2.5 5.2.5 par. II.4) and Regulatory Guide 1.45 II. Other Positions

1. 12/1/76 SEB 3.5.3 Ductility of Reinforced Concrete and 3.5.3 Steel Structural Elements Subjected to Impactive or Impulsive Loads CHAPTER 01 1.11-5 REV. 13, SEPTEMBER 2006

LGS UFSAR Table 1.11-1 (Contd)

IMPLEMENTATION APPLICABLE DATE BRANCH SRP SECTION TITLE UFSAR SECTION REFERENCE

2. 8/01/76 SEB 3.7. Response Spectra in Vertical Direction Not applicable to LGS

3. 4/01/76 SEB 3.8.1 & BWR Mark III Containment Pool Dynamics Not applicable 3.8.2 to LGS

4. 9/01/76 SEB 3.8.4 Air Blast Loads 3.8.4

5. 10/01/76 SEB 3.5.3 Tornado Missile Impact 3.5

6. 6/01/77 RSB 6.3 Passive Failures During Long-Term 6.3.1 Cooling Following LOCA

7. 9/01/77 RSB 6.3 Control Room Position Indication of 6.3.2.9 and Manual (Handwheel) Valves in ECCS Table 6.3-7

8. 4/01/77 RSB 15.1.5 Long-Term Recovery from Steam Line Not applicable Break: Operator Action to Prevent to LGS Overpressurization (PWR)

9. 12/01/77 RSB 5.4.6, Pump Operability Requirements 5.4 5.4.7 & 6.3

10. 3/28/78 RSB 3.5.1 Gravity Missiles, Vessel Seal-Ring 3.5 Missiles Inside Containment

11. 1/01/77 AB 4.4 Core Thermal-Hydraulic Analysis 4.4.4

12. 1/01/78 PSB 8.3 Degraded Grid Voltage Conditions 8.3

13. 6/01/76 CSB 6.2.1.2 Asymmetric Loads on Components Located 1.12.3, 6.2.1.2 Within Containment Sub-compartments Appendix 6A

14. 9/01/77 CSB 6.2.6 Containment Leak Testing Program 6.2.6

15. 1/01/77 CSB 6.2.1.4 Containment Response Due to Main Steam Not applicable Line Break and Failure of MSLIV to Close to LGS

16. 11/01/77 ASB 3.6.1 & 3.6.2 Main Steam and Feedwater Pipe Failures 3.6

17. 1/01/77 ASB 9.2.2 Design Requirements for Cooling Water 9.2.2 to Reactor Coolant Pumps CHAPTER 01 1.11-6 REV. 13, SEPTEMBER 2006

LGS UFSAR Table 1.11-1 (Contd)

IMPLEMENTATION APPLICABLE DATE BRANCH SRP SECTION TITLE UFSAR SECTION REFERENCE

18. 8/01/76 ASB 10.4.7 Design Guidelines for Water Hammer in Not applicable Steam Generators with Top Feeding Design to LGS (BTP ASB 10.2)

19. 1/01/76 ICSB 3.11 Environmental Control Systems for Safety- 3.11 Related Equipment (1)

Regulatory Guides included in the RRRC and NRR lists are addressed in Section 1.8 (2)

Version in effect as of the date of Reference 1.11-2 CHAPTER 01 1.11-7 REV. 13, SEPTEMBER 2006

LGS UFSAR 1.12 UNRESOLVED SAFETY ISSUES 1.

12.1 INTRODUCTION

The NRC continuously evaluates the safety requirements used in its reviews against new information as it becomes available. Information related to the safety of nuclear power plants comes from a variety of sources including experience from operating reactors; research results; NRC staff and ACRS safety reviews; and vendor, architect-engineer, and utility design reviews.

Each time a new concern or safety issue is identified from one or more of these sources, the need for immediate action to ensure safe operation is assessed. This assessment includes consideration of the generic implications of the issue.

In some cases, immediate action is taken to ensure safety, for example, the derating of BWRs as a result of the channel box wear problems in 1975. In other cases, interim measures, such as modifications to operating procedures, may be sufficient to allow further study of the issue before making licensing decisions. In most cases, however, the initial assessment indicates that immediate licensing actions or changes in licensing criteria are not necessary. In any event, further study may be deemed appropriate to make judgments as to whether existing NRC requirements should be modified to address the issue for new plants or if backfitting is appropriate for the long-term operation of plants already under construction or in operation.

These issues are sometimes called generic safety issues because they are related to a particular class or type of nuclear facility rather than to a specific plant. Certain of these issues have been designated as unresolved safety issues (Reference 1.12-1). However, as discussed above, such issues are considered on a generic basis only after the NRC staff has made an initial determination that the safety significance of the issue does not prohibit continued operation or require licensing actions while the longer term generic review is under way.

In 1978, the NRC undertook a review of over 130 generic issues addressed in the NRC program.

The review is described in Reference 1.12-2. The report provides the following definition of an unresolved safety issue:

A USI is a matter affecting a number of nuclear power plants that poses important questions concerning the adequacy of existing safety requirements for which a final resolution has not yet been developed and that involves conditions not likely to be acceptable over the lifetime of the plants it affects.

Furthermore, the report indicates that in applying this definition, matters that pose "important questions concerning the adequacy of existing safety requirements" were judged to be those for which resolution is necessary to (1) compensate for a possible major reduction in the degree of protection of the public health and safety, or (2) provide a potentially significant decrease in the risk to the public health and safety. Quite simply, a USI is potentially significant from a public safety standpoint and its resolution is likely to result in NRC action on the affected plants.

All of the issues addressed in the NRC program were systematically evaluated against this definition as described in Reference 1.12-2. As a result, 17 USIs addressed by 22 tasks in the NRC program were identified. The issues and applicable task numbers are listed below. Progress on these issues was first discussed in the 1978 NRC Annual Report. The number(s) of the generic task(s) (for example, A-1) in the NRC program addressing each issue is indicated in parentheses following the title.

CHAPTER 01 1.12-1 REV. 16, SEPTEMBER 2012

LGS UFSAR

1. Water Hammer (A-1)

2. Asymmetric Blowdown Loads on the Reactor Coolant System (A-2)

3. Pressurized Water Reactor Steam Generator Tube Integrity (A-3, A-4, A-5)

4. BWR Mark I and Mark II Pressure-Suppression Containments (A-6, A-7, A-8, A-39)

5. Anticipated Transients Without Scram (A-9)

6. BWR Nozzle Cracking (A-10)

7. Reactor Vessel Materials Toughness (A-11)

8. Fracture Toughness of Steam Generator and Reactor Coolant Pump Supports (A-12)

9. Systems Interaction in Nuclear Power Plants (A-17)

10. Environmental Qualification of Safety-Related Electrical Equipment (A-24)

11. Reactor Vessel Pressure Transient Protection (A-26)

12. Residual Heat Removal Requirements (A-31)

13. Control of Heavy Loads Near Spent Fuel (A-36)

14. Seismic Design Criteria (A-40)

15. Pipe Cracks at Boiling Water Reactors (A-42)

16. Containment Emergency Sump Reliability (A-43)

17. Station Blackout (A-44)

The NRC has performed an in-depth and systematic review of generic safety concerns identified since January 1979 to determine if any of these issues should be designated as new USIs. The candidate issues originated from concerns identified in Reference 1.12-3, ACRS recommendations, abnormal occurrence reports, and other operating experience. The Commission considered the above information and approved the following four new unresolved safety issues:

1. Shutdown Decay Heat Removal Requirements (A-45)

2. Seismic Qualification of Equipment in Operating Plants (A-46)

3. Safety Implication of Control Systems (A-47)

4. Hydrogen Control Measures and Effects of Hydrogen Burns on Safety Equipment (A-48)

CHAPTER 01 1.12-2 REV. 16, SEPTEMBER 2012

LGS UFSAR A description of the above process together with a list of the issues considered is presented in Reference 1.12-4. An expanded discussion of each of the new USIs is also contained in Reference 1.12-4.

In addition to the four issues identified above, the Commission approved another issue, A-49, Pressurized Thermal Shock, as a USI in December 1981.

In December, 1987 the NRC issued a compilation of the generic safety issues as NUREG-0933, "A Prioritization of Generic Safety Issues." This compilation includes the USIs and is periodically supplemented to update the status of the safety issues.

1.12.2 APPLICABILITY TO LGS Seven of the twenty-seven tasks identified with the USIs are not applicable to LGS because they apply to PWRs only. These tasks are A-2, A-3, A-4, A-5, A-12, A-26, and A-49. Also, Tasks A-6 and A-7 only apply to Mark I or Mark III BWR containments. With regard to the remaining eighteen tasks that are applicable to LGS, the NRC staff has issued NUREG reports or rule changes providing its resolution of seventeen of the issues. These issues are listed below.

TASK NUMBER NUREG REPORT NO. AND TITLE A-1 NUREG-0927, "Evaluation of Water Hammer in Nuclear Power Plants - Technical Findings Relevant to Unresolved Safety Issue A-1".

NUREG-0993, "Regulatory Analysis for USI A-1, "Water Hammer".

NUREG-0800, SRP 3.9.3, 3.9.4, 5.4.6, 5.4.7, 6.3, 9.2.1, 9.2.2, 10.3 and 10.4.7, Various Titles.

A-8 NUREG-0808 "Mark II Containment Pool Dynamic Loads".

NUREG-0802, "Safety/Relief Valve Quencher Loads: Evaluation for BWR Mark II and III Containments".

NUREG-0800, SRP 6.2.1.1.c, "Pressure-Suppression Type BWR Containments".

A-9 NUREG-0460, Vol 4, "Anticipated Transients Without Scram for Light-Water Reactors".

10CFR50.62, Federal Register Notice 49FR2036.

A-10 NUREG-0619, "BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking".

A-11 NUREG-0744, Revision 1, "Resolution of the Task A Reactor Vessel Materials Toughness Safety Issue".

A-17 NUREG-1174, "Evaluation of Systems Interactions in Nuclear Power Plants".

NUREG-1229, "Regulatory Analysis for Resolution of USI A-17".

CHAPTER 01 1.12-3 REV. 16, SEPTEMBER 2012

LGS UFSAR A-24 NUREG-0588, Revision 1, "Interim Staff Position on Environmental Qualification of Safety-Related Electrical Equipment".

NUREG-0800, SRP 3.11, "Environmental Qualification of Mechanical and Electrical Equipment".

10CFR50.49, Federal Register Notice 47FR28363.

A-31 NUREG-0800, SRP 5.4.7 and BTP 5-1, "Residual Heat Removal Systems" (incorporate requirements of USI A-31).

A-36 NUREG-0612, "Control of Heavy Loads at Nuclear Power Plants".

A-39 NUREG-0802, "Safety/Relief Valve-Quencher Loads: Evaluation for BWR Mark II and III Containments".

NUREG-0800, SRP 6.2.1.1.c, "Pressure-Suppression Type BWR Containments".

A-40 NUREG-1233, "Regulatory Analysis for USI A-40".

NUREG-0800, SRP 2.5.2, 3.7.1, 3.7.2 and 3.7.3, Various Titles.

A-42 NUREG-0313, Revision 2, "Technical Report on Material Selection and Processing Guidelines for BWR Coolant Pressure Boundary Piping" (Note: Revision 1 is applicable prior to issuance of NRC Generic Letter 88-01.)

A-43 NUREG-0869, Revision 1, "USI A-43 Regulatory Analysis".

NUREG-0897, Revision 1, "Containment Emergency Sump Performance".

A-44 NUREG-1032, "Evaluation of Station Blackout Accidents at Nuclear Power Plants, Technical Findings Related to Unresolved Safety Issue A-44, Draft Report for Comment".

NUREG-1109, "Regulatory Analysis for the Resolution of Unresolved Safety Issue A-44, Station Blackout, Draft Report for Comment".

10CFR50.63, Federal Register Notice 53FR23215.

A-45 NUREG-1289, "Regulatory and Backfit Analysis for the Resolution of USI A-45".

NUREG-1292, "Shutdown Heat Removal Analysis: Plant Case Studies and Special Issues Summary Report".

A-47 NUREG-1217, "Evaluation of Safety Implications of Control Systems in LWR Nuclear Power Plants".

NUREG-1218, "Regulatory Analysis for Resolution of USI A-47".

A-48 10CFR50.44, Federal Register Notice 46FR58484.

CHAPTER 01 1.12-4 REV. 16, SEPTEMBER 2012

LGS UFSAR NUREG-1370, "Resolution of Unresolved Safety Issue A-48, "Hydrogen Control Measures and Effects of Hydrogen Burns on Safety Equipment".

The remaining issue applicable to LGS is Seismic Qualification of Equipment in Operating Plants (A-46). It is further discussed below.

1.12.3 DISCUSSIONS OF TASKS AS THEY RELATE TO LGS This section provides an implementation and status summary of LGS for each of the applicable USIs. This includes the NRC requirements summary of each issue as stated in Generic Letter 89-21 (Request for Information Concerning Status of Implementation of Unresolved Safety Issue Requirements).

A-1 Water Hammer REQUIREMENTS

SUMMARY

On March 15, 1984, the EDO sent the Commissioners a Policy Issue titled, "Resolution of Unresolved Safety Issue A-1, Water Hammer." In this Policy Issue the staff concluded that the frequency and severity of water hammer occurrences had been significantly reduced through (a) incorporation of design features such as keep-full systems, vacuum breakers, J-tubes, void detection systems and improved venting procedures, (b) proper design of feedwater valves and control systems and (c) increased operator awareness and training. Therefore, the resolution of USI A-1 did not involve any hardware or design changes on existing plants. It did involve SRP changes (forward fits) and a comprehensive set of guidelines and criteria to evaluate and upgrade utility training programs (per TMI Item I.A.2.3.). In addition, the assumption was made that for BWRs with isolation condensers a high reactor vessel water level feedwater pump trip was in place or being installed. This was necessary because calculated values had postulated an isolation condenser failure by water hammer that opened a direct pathway to the environment.

Items to certify:

1. A comprehensive set of guidelines and criteria to evaluate and upgrade utility training programs (per TMI Item I.A.2.3) is in place.

2. BWRs with isolation condensers have installed and operated a high reactor vessel water level feedwater pump trip.

IMPLEMENTATION AND STATUS

SUMMARY

1. TMI Item I.A.2.3 implementation was complete at the time of receipt of the operating license. The LGS training program has been upgraded and subsequently INPO accredited.

2. LGS does not have an isolation condenser.

A-8 Mark II Containment Pool Dynamic Loads REQUIREMENTS

SUMMARY

The requirement is that the 11 BWRs having the Mark II containment shall meet the requirements of GDC 16, "Containment Design."

CHAPTER 01 1.12-5 REV. 16, SEPTEMBER 2012

LGS UFSAR As stated in NUREG-0808, "Mark II Containment Program Load Evaluation and Acceptance Criteria", the original design of the Mark II containment system considered only those loads normally associated with DBAs that were known at the time. These included pressure and temperature loads associated with a LOCA, seismic loads, dead loads, jet impingement loads, hydrostatic loads due to water in the suppression chamber, overload pressure test loads, and construction loads. However, since the establishment of the original design criteria, additional loading conditions were identified that must be considered for the pressure-suppression containment system design.

In the course of performing large-scale testing of an advanced design pressure-suppression containment (Mark III), and during in-plant testing of Mark I containments, new suppression pool hydrodynamic loads were identified that had not been included explicitly in the original Mark II containment design basis. These additional loads result from dynamic effects of drywell air and steam being rapidly forced into the suppression pool during a postulated LOCA and from suppression pool response to SRV operation, which is generally associated with plant transient operating conditions. Because these new hydrodynamic loads had not been considered, the NRC staff determined that a detailed reevaluation of the Mark II containment system was required.

The issuance of NUREG-0808, NUREG-0802, and NUREG-0487 documented acceptable methods for calculating the hydrodynamic loads associated with plant transient conditions.

Specifically, the loads referenced in these NUREGs, as modified by the acceptance criteria, constituted the resolution of USI A-8. SRP 6.2.1 has been modified to reflect the applicability of these NUREGs to Mark II containment evaluations.

Implementation is believed to be complete for all Mark II BWRs. As part of the licensing process, the staff required that the new calculation methodology defined in the referenced NUREGs be utilized by the applicant before issuance of a full power license.

IMPLEMENTATION AND STATUS

SUMMARY

The Mark II containment pool dynamic loads were addressed in the DAR for LGS (Appendix 3A and 3B) during the initial operating license review. The NRC review is documented in SSER-2, Sections 6.2.1.7 and 6.2.1.8.

A-9 Anticipated Transients Without Scram The USI was resolved on June 26, 1984 with the publication of a final rule (10CFR50.62), to require improvements in plants to reduce the likelihood of failure of the RPS to shut down the reactor following anticipated transients and to mitigate the consequences of an ATWS event. The rule includes the following design-related requirements: 10CFR50.62(C)(l) - Diverse and Independent Auxiliary Feedwater Initiation and Turbine Trip for All PWRs, 10CFR50.62(C)(2) -

Diverse Scram Systems for CE and B&W Reactors, 10CFR50.62(C)(3) - ARI for BWRs, 10CFR50.62(C)(4) - SLCS for BWRs, and 10CFR50.62(C)(5) - Automatic RPT Under Conditions Indicative of an ATWS for BWRs. Information requirements and an implementation schedule are also specified.

IMPLEMENTATION AND STATUS

SUMMARY

LGS has completed implementation of ARI, RPT and adequate SLCS capacity. These were installed prior to fuel load and the Technical Specifications included RPT and SLCS. The SLCS CHAPTER 01 1.12-6 REV. 16, SEPTEMBER 2012

LGS UFSAR Technical Specification was revised in June 1989 when minor discrepancies were identified in the original Technical Specification.

A-10 BWR Feedwater Nozzle Cracking REQUIREMENTS

SUMMARY

Inspections of operating BWRs conducted up to April 1978 revealed cracks in the feedwater nozzles of 20 reactor vessels. It was determined that cracking was due to high-cycle fatigue caused by fluctuations in water temperature within the vessel in the nozzle region. This item was originally identified in NUREG-0371 and was later determined to be a USI.

By letter dated November 13, 1980, D.G. Eisenhut (NRC) provided licensees with a copy of NUREG-0619, "BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking." The letter stated that NUREG-0619 provided the resolution of the staffs generic technical activity A-10, a USI, which resulted from the inservice discovery of cracking in feedwater nozzles and CRD return line nozzles. NUREG-0619 describes the technical issues, GE and staff studies and analyses and the staff's positions and requirements. Licensees were required to respond, pursuant to 10CFR50.54(f), that implementation dates indicated in NUREG-0619 would be met.

Generic Letter 81-11 was subsequently issued to provide technical clarification to the November 13, 1980 letter and to clarify that it had been sent to PWR licensees for information only and that no response was required from PWR licensees.

IMPLEMENTATION AND STATUS

SUMMARY

Implementation of NUREG-0619 was reviewed during the initial operating license review. As discussed in the SER, LGS does not have a CRD system return line to the reactor vessel; equalizing valves are installed between the cooling water header and exhaust water header; the flow stabilizer loop is routed to the cooling water header; and both the exhaust header and flow stabilizer loop are stainless steel piping; and are acceptable.

A-11 Reactor Vessel Materials Toughness Because of the remote possibility of failure of nuclear RPVs designed to the ASME B&PV Code, the design of nuclear facilities does not provide protection against reactor vessel failure. Prevention of reactor vessel failure depends primarily on maintaining the reactor vessel material fracture toughness at levels that will resist brittle fracture during plant operation. At service times and operating conditions typical of current operating plants, reactor vessel fracture roughness properties provide adequate margins of safety against vessel failure; however, as plants accumulate more and more service time, neutron irradiation reduces the material fracture toughness and initial safety margins. This item was originally identified in NUREG-0371 and was later determined to be a USI.

10CFR50, Appendix G required that the charpy upper-shelf energy throughout the life of the vessel be no less than 50 ft-lbs unless it is demonstrated that lower values will provide margins of safety against failure equivalent to those provided by Appendix G of the ASME code. USI A-11 was initiated to address the staff's concern that some vessels were projected to have beltline materials with charpy upper-shelf energy less than 50 ft-lbs.

This USI was resolved in October 1982 with the issuance of NUREG-0744, Revision 1 which was later transmitted to all licensees with Generic Letter 82-26.

CHAPTER 01 1.12-7 REV. 16, SEPTEMBER 2012

LGS UFSAR NUREG-0744 provides a method for evaluation of reactor vessel materials when their charpy upper-shelf energy are predicted to fall below 50 ft-lbs. Plants will use the prescribed method when analysis of irradiation damage predicts that the charpy upper-shelf energy is below 50 ft-lbs.

IMPLEMENTATION AND STATUS

SUMMARY

Implementation of NUREG-0744 was addressed in the initial operating license review. LGS complies as discussed in SER and SSER-9 Section 5.3.1.2.

A-17 Systems Interaction in Nuclear Power Plants REQUIREMENTS

SUMMARY

Generic Letter 89-18, dated September 6, 1989, was sent to all power reactor licensees and constitutes the resolution of USI A-17. No licensee actions were required by Generic Letter 89-18.

Generic Letter 89-18 had two enclosures which (1) outlined the bases for the resolution of USI A-17, and (2) provided five general lessons learned from the review of the overall systems interaction issue. It was anticipated that licensees' review of this information would be considered in other programs, such as the "Individual Plant Examination for Severe Accident Vulnerabilities."

Specifically, the staff expected that insights concerning water intrusion and flooding from internal sources, provided in the appendix to NUREG-1174, will be considered in the IPE program. Also considered in the USI's resolution was the expectation that licensees would continue to review information on events at operating nuclear power plants in accordance with the requirements of TMI Item I.C.5 of NUREG-0737.

IMPLEMENTATION AND STATUS

SUMMARY

No changes were required for LGS.

I. The IPE for LGS was approved by the NRC by letter dated December 9, 1994.

II. TMI Item I.C.5 of NUREG-0737 is implemented through an Operating Experience Assessment Program as discussed in Section 1.13.

A-24 Qualification of Class 1E Equipment REQUIREMENTS

SUMMARY

The publishing of NUREG-0588, Revision 1, "Interim Staff Position on Environmental Qualification of Safety-Related Electrical Equipment" in July 1981 completed the staff resolution of Generic Technical Activity A-24, "Qualification of Class 1E Safety-Related Equipment." Part I of the report is the original "For Comment" NUREG-0588 which in conjunction with the DOR Guidelines was endorsed by a Commission Memorandum and Order as the interim position on this subject until "final" positions were established in rule making. On January 21, 1983 the Commission amended its regulations, in 10CFR50.49 (the rule), effective February 22, 1983 to codify existing qualification methods in national standards, regulatory guides, and certain NRC publications including NUREG-0588.

CHAPTER 01 1.12-8 REV. 16, SEPTEMBER 2012

LGS UFSAR The rule is based on the DOR Guidelines and NUREG-0588, which "provide guidance on (1) how to establish environmental service conditions, (2) how to select methods which are considered appropriate for qualifying the equipment in different areas of the plant, and (3) other areas such as margin, aging, and documentation." NUREG-0588 does not address all areas of qualification; it does supplement, in selected areas, the provisions of the 1971 and 1974 versions of IEEE 323.

The rule recognizes previous qualification efforts completed as result of Memorandum and Order CLI-80-20 and also reflects different IEEE 323 versions dependent on the date of the construction permit SER. Therefore, plant specific requirements may vary in accordance with the rule.

In summary, the resolution of A-24 is embodied in 10CFR50.49. A measure of whether each licensee has implemented the resolution of A-24 may therefore be found in the determination of compliance with 10CFR50.49. This was addressed by 72 SERs for operating plants shortly after publication of the rule and subsequently in operating license reviews pursuant to SRP 3.11. This was further addressed by the first round EQ inspections conducted by the Office of Inspection and Enforcement, the Regions, and Nuclear Reactor Regulation.

IMPLEMENTATION AND STATUS

SUMMARY

Environmental qualification of electrical equipment was addressed during the initial operating license review. LGS Unit 1 did not complete the necessary documentation until after the operating license was issued. However, the Unit 1 NPF-27 License Condition 2.C(5) was completed and closed in SSER-4. SSER-9 addressed EQ for LGS Unit 2.

A-31 RHR Shutdown Requirements This USI was resolved in May 1978 and affected PWRs and BWRs. The USI involved establishment of criteria for the design and operation of system necessary to take a power reactor from normal operating conditions to cold shutdown.

The USI was resolved with the issuance of SRP section 5.4.7. The SRP stated (BTP RSB 5-1) that, for purposes of implementation, plants would be divided into three classes: Class 1 would require full compliance with the BTP for construction permit or PDA applications which were docketed before January 1, 1978. Class 2 required a partial implementation of the BTP for all plants for which construction permit or PDA applications were docketed before January 1, 1978, and for which an operating license issuance was expected on or after January 1, 1979. Class 3 affected all operating reactors and all other plants for which issuance of the operating license was expected before January 1, 1979. The extent to which Class 3 plants would require implementation of the BTP was based on the combined inspection and enforcement and DOR review of related plant features. In general, the outcome of these evaluations were that only plants receiving operating licenses after January 1, 1979 were affected by this USI resolution.

IMPLEMENTATION AND STATUS

SUMMARY

The RHR shutdown requirements for LGS were addressed during the initial operating license review as addressed in SER and SSER-2 Section 5.4.7.

A-36 Control of Heavy Loads, Phases I & II REQUIREMENTS

SUMMARY

CHAPTER 01 1.12-9 REV. 16, SEPTEMBER 2012

LGS UFSAR The following is abstracted from NUREG-0612: In nuclear power plants heavy loads may be handled in several plant areas. If these loads were to drop in certain locations in the plant, they may impact spent fuel, fuel in the core, or equipment that may be required to achieve safe shutdown and continue decay heat removal. Task A-36 was established to systematically examine staff licensing criteria and the adequacy of measures in effect at operating plants, and to recommend necessary changes to assure the safe handling of heavy loads. The guidelines proposed include definition of safe load paths, use of load handling procedures, training of crane operators, guidelines on slings and special lifting devices, periodic inspection and maintenance for the crane, as well as various alternatives. The report NUREG-0612 completes Task A-36.

The requirements documents are the Generic Letter dated December 22, 1980 "Control of Heavy Loads" transmitting NUREG-0612 and Generic Letter 85-11 dated June 28, 1985 which stated that implementation of Phase I (guidelines noted above) was sufficient and that Phase II could be implemented by licensees as appropriate. Phase II was to have extended the issue beyond the guidelines noted above to include a showing that either single failure proof handling equipment was not needed or that it had been provided.

IMPLEMENTATION AND STATUS

SUMMARY

The requirements for heavy loads, NUREG-0612, were addressed in the initial operating license review. The licensee completed implementation in accordance with an August 13, 1984 submittal and Unit 1 Operating License NPF-27 License Condition 2.C(19).

See LGS UFSAR Section 3.12 for additional information on the control of heavy loads at LGS.

A-39 Determination of SRV Pool Dynamic Loads and Temperature Limits REQUIREMENTS

SUMMARY

BWR plants are equipped with SRVs to protect the reactor from overpressurization. Plant operational transients, such as turbine trips, will actuate the SRV. Once the SRV opens, the air column within the partially submerged discharge line is compressed by the high pressure steam released from the reactor. The compressed air discharged into the suppression pool produces high pressure bubbles. Oscillatory expansion and contraction of these bubbles create hydrodynamic loads on the containment structures, piping and equipment inside containment.

NUREG-0802 presents the results of the staff's evaluation of SRV loads. The evaluation, however, is limited to the quencher devices used in Mark II and III containments. With respect to Mark I containments, the SRV acceptance criteria are presented in NUREG-0661, and are dealt with as part of USI A-7 (Mark I Long-Term Program).

SRP 6.2.1.1.C, "Pressure-Suppression Type BWR Containments", addresses the applicable review criteria since all Mark II and III containment designs are understood to have completed their operating license reviews subsequent to resolution of this USI and reflection of the resolution in the SRP.

In conjunction with NUREG-0661, NUREG-0763 and NUREG-0783, the issuance of NUREG-0802 concludes USI A-39.

IMPLEMENTATION AND STATUS

SUMMARY

CHAPTER 01 1.12-10 REV. 16, SEPTEMBER 2012

LGS UFSAR See A-8.

A-40 Seismic Design Criteria - Short-Term Program REQUIREMENTS

SUMMARY

USI A-40 was originated in 1977. The basic objectives were (1) to study the seismic design criteria, (2) to quantify the conservatism associated with the criteria and (3) to recommend modifications to SRP if changes are justified. Lawrence Livermore National Laboratory completed the study and published their findings in NUREG/CR-1161 dated May 1980. The report recommended specific changes to the SRP. NRC staff reviewed the report and developed some other changes that would reflect the present state of seismic design practices. The resulting SRP changes were issued for public comments in June 1988, and the final SRP changes are to be published in September 1989.

The major SRP changes as a resolution of USI A-40 consist of (1) clarification of development of site specific spectra, (2) use of single synthetic time history, (3) location of input ground motion for Soil-Structure Interaction, and (4) design of flexible vertical tanks. Except for item (4), all other items do not constitute any additional requirements for current licenses and applications, and thus, no backfits are being required for these items. However, the revised provisions could be used for margin studies and reevaluations or IPE for External Events.

The participant utilities in Seismic Qualification Utility Group agreed to implement the changed criteria for flexible vertical tank for their plants. However, there are four plants (six reactors) where this issue has to be resolved on an individual basis. (These plants are: Callaway 1/2, Wolf Creek, Shearon Harris 1, and Watts Bar 1/2.) The 50.54(f) letters have been sent to the affected utilities.

IMPLEMENTATION AND STATUS

SUMMARY

Seismic qualification was addressed during the initial operating license review. The program is discussed in UFSAR Section 3.10 and was accepted as discussed in the SER, SSER-2, SSER-3, and SSER-9, Section 3.10.

A-42 Pipe Cracks in Boiling Water Reactors Pipe cracking has occurred in the heat-affected zones of welds in primary system piping in BWRs since mid-1960. These cracks have occurred mainly in Type 304 stainless steel which is the type used in most operating BWRs. The major problem is recognized to be IGSCC of austenitic stainless steel components that have been made susceptible to this failure by being "sensitized,"

either by postweld heat treatment or by sensitization of a narrow heat- affected zone near welds.

"Safe ends" that have been highly sensitized by furnace heat treatment while attached to vessels during fabrication were very early (late 1960s) found to be susceptible to IGSCC. Most of the furnace sensitized safe ends in older plants have been removed or clad with a protective material and there are only a few BWRs that still have furnace sensitized safe ends in use. Most of these, however, are in smaller diameter lines.

Earlier reported cracks (prior to 1975) occurred primarily in 4 inch diameter recirculation loop bypass lines and in 10 inch diameter core spray lines. Cracking is most often detected during ISI using UT techniques. Some piping cracks have been discovered as a result of primary coolant leaks.

CHAPTER 01 1.12-11 REV. 16, SEPTEMBER 2012

LGS UFSAR This USI was resolved with the issuance of NUREG-0313, Revision 1 which was transmitted to all holders of BWR operating licenses or construction permits in February 1981 via Generic Letter 81-

03. MPA B-05 was established for implementation of the resolution at operating plants.

NUREG-0313, Revision 1 provided the NRC staff's revised acceptable methods for reducing the intergranular stress-corrosion cracking susceptibility of BWR code class 1, 2, and 3 pressure boundary piping of sizes identified above and safe ends. In addition, it provided the requirements for augmented inservice inspection of piping with nonconforming materials.

As a result of further IGSCC degradations in large piping, the staff provided licensees with additional requirements in several NRC communications (i.e., Bulletin 82-03, Bulletin 83-2, Bulletin 84-11). The long-term resolution of IGSCC in BWR piping was provided in NUREG-0313, Revision 2 which was transmitted to all holders of BWR operating licenses via Generic Letter 88-01.

IMPLEMENTATION AND STATUS

SUMMARY

IGSCC was most recently addressed by the licensee in its response to Generic Letter 88-01. For LGS, this response consisted of an FSAR revision (Revision 54, dated October 1988), a Technical Specification revision (which was determined not to be necessary and was withdrawn on April 28, 1989) and an ISI program revision which will be completed and implemented at the next refueling outage for each unit.

A-43 Containment Emergency Sump Reliability REQUIREMENTS

SUMMARY

An issue existed concerning the availability of adequate recirculation cooling water following a LOCA when long-term recirculation of cooling water from the PWR containment sump, or the BWR RHR system suction intake, must be initiated and maintained to prevent core melt.

The technical concerns evaluation under USI A-43 were: (1) post-LOCA adverse conditions resulting from potential vortex formation and air ingestion and subsequent pump failure, (2) blockage of sump screens with LOCA generated insulation debris causing inadequate NPSH on pumps, and (3) RHR and containment spray pumps inoperability due to possible air, debris, or particulate ingestion on pump seal and bearing systems.

NUREG-0897, Revision 1 presents the results of the staff's technical findings. These findings established a need to revise current licensing guidance on these matters. Regulatory Guide 1.82 (Rev 0) and SRP (NUREG-0800) Section 6.2.2, "Containment Heat Removal Systems" were revised to reflect this new guidance.

This revised guidance applies only to future construction permits, preliminary design approvals, final design approvals, standardized designs, and applications of licenses to manufacture. For operating plants, the staff performed a regulatory analysis to determine if this new guidance should be applied. The results of this analysis was reported in NUREG-0869, Revision 1, "USI A-43 Regulatory Analysis." The staff concluded that the regulatory analysis does not support any new generic requirements for current licensees to perform debris assessments. However, an Information Notice was issued recommending (but not requiring) licensees use the revised guidance to conduct a 10CFR50.59 analysis for future insulation modifications or replacements.

CHAPTER 01 1.12-12 REV. 16, SEPTEMBER 2012

LGS UFSAR IMPLEMENTATION AND STATUS

SUMMARY

Suppression pool strainer blockage is discussed in UFSAR and SER Sections 6.2.2. Additional actions are being taken for LGS in response to NRC Bulletin 96-03.

A-44 Station Blackout Station blackout means the loss of offsite ac power to the essential and nonessential electrical buses concurrent with turbine trip and the unavailability of the redundant onsite emergency ac power system. WASH-1400 showed that station blackout could be an important risk contributor, and operating experience has indicated that the reliability of ac power systems might be less than originally anticipated. For these reasons station blackout was designated as a USI in 1980. A proposed rule was published for comment on March 21, 1986. A final rule, 10CFR50.63 "Loss of All Alternating Current Power," was published on June 21, 1988 and became effective on July 21, 1988. Regulatory Guide 1.155 was issued at the same time as the rule and references an industry guidance document NUMARC-8700. In order to comply with the A-44 resolution, licensees are required to:

• maintain onsite emergency ac power supply reliability above a minimum level

• develop procedures and training for recovery from a station blackout

• determine the duration of a station blackout that the plant should be able to withstand

• use an alternate qualified ac power source, if available, to cope with a station blackout

• evaluate the plant's actual capability to withstand and recover from a station blackout

• backfit hardware modifications if necessary to improve coping ability 10CFR50.63(c)(1) of the rule required each licensee to submit a response including the results of their coping analysis within 270 days from issuance of an operating license or the effective date of the rule, whichever is later.

IMPLEMENTATION AND STATUS

SUMMARY

The LGS electrical distribution system met the NRC design criteria prior to development of 10CFR50.63. The simultaneous loss of both offsite and onsite power is considered to be a highly unlikely occurrence.

Long-term operation following a loss of all ac power is limited only by suppression pool heatup and ambient heatup of the HPCI and RCIC pump rooms, where compartment cooling requires ac power, and by dc battery capacity.

The LOOP and SBO incidents are programmed as training exercises during the certification program at the LGS Simulator.

The station blackout event has also been incorporated into simulator requalification programs.

The plant staff have written emergency procedures for the station blackout event.

CHAPTER 01 1.12-13 REV. 16, SEPTEMBER 2012

LGS UFSAR The licensee submitted the LGS program for implementation of the station blackout rule on April 17, 1989.

A-45 Shutdown Decay Heat Removal Requirements REQUIREMENTS

SUMMARY

USI A-45 was closed out without any new licensing requirements other than the IPE, as described below. Since all of the significant USI A-45 results have been found to be highly plant specific, the Commission decided it was not appropriate to propose a single generic action to be applied uniformly to all plants.

The Commission is currently implementing the Severe Accident Policy (50FR32138) and will require all plants currently operating or under construction to undergo a systematic examination termed the IPE. The reason for this examination is to identify any plant specific vulnerabilities to severe accidents. The IPE analysis intends to examine and understand the plant emergency procedures, design, operations, maintenance, and surveillance to identify vulnerabilities. The analysis will examine both the decay heat removal system and those systems used for other related functions. For CE plants without power-operated relief valves, the need for a rapid depressurization capability will be addressed in the IPE program.

NRC has decided to subsume A-45 into the IPE program as the most effective way of achieving resolution of specific plant concerns associated with A-45.

IMPLEMENTATION AND STATUS

SUMMARY

The IPE for LGS was approved by the NRC by letter dated December 9, 1994.

A-46 Seismic Qualification of Equipment in Operating Plants As an outgrowth of the Systematic Evaluation Program, the need was identified for reassessment of design criteria and methods for the seismic qualification of mechanical equipment and electrical equipment. The seismic qualification of the equipment in operating plants must, therefore, be reassessed to ensure the ability to bring the plant to a safe shutdown condition when subject to a seismic event. The objective of this issue was to establish an explicit set of guidelines that could be used to judge the adequacy of the seismic qualification of mechanical and electrical equipment at operating plants in lieu of attempting to backfit current design criteria for new plants.

The resolution of USI A-46 was mainly based on work completed by the Seismic Qualification Utility Group and EPRI using the seismic and test experience data approach and reviewed and endorsed by the Senior Seismic Review and Advisory Panel and the NRC staff. The scope of the review was narrowed down to equipment required to bring each affected plant to hot shutdown and maintain it there for a minimum of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. A walk-through of each plant is required to inspect equipment in the scope. Evaluation of equipment will include: (a) adequacy of equipment anchorage; (b) functional capability of essential relays; (c) outliers and deficiencies (i.e., equipment with nonstandard configurations); and (d) seismic systems interaction.

The staff issued Generic Letter 87-02 on February 19, 1987, with associated guidance, requiring all affected utilities to perform an evaluation of the seismic adequacy of their plants. The specific requirements and approach for implementation are being developed jointly by the Seismic CHAPTER 01 1.12-14 REV. 16, SEPTEMBER 2012

LGS UFSAR Qualification Utility Group and the staff on a generic basis prior to individual member utilities proceeding with plant specific implementation (see discussion below).

IMPLEMENTATION AND STATUS

SUMMARY

Generic Letter 87-02 issued on February 19, 1987 and Supplement No. 1 thereto issued May 22, 1992, do not list Limerick as an USI A-46 Plant and therefore does not apply to Limerick, since seismic qualification was addressed during initial operating licensing review. Seismic/dynamic qualification of safety related electrical and mechanical equipment is discussed in LGS UFSAR Section 3.10 and was accepted as discussed in the SER, SSER-2, SSER-3, and SSER-9.

A-47 Safety Implications of Control Systems USI A-47 is being closed out with the issuance of Generic Letter 89-19 which was issued September 20, 1989. The Generic Letter states, "The staff has concluded that all PWR plants should provide automatic steam generator overfill protection, all BWR plants should provide automatic reactor vessel overfill protection, and that plant procedures and technical specifications for all plants should include provisions to verify periodically the operability of the overfill protection and to assure that automatic overfill protection is available to mitigate main feedwater overfeed events during reactor power operation. Also, the system design and setpoints should be selected with the objective of minimizing inadvertent trips of the main feedwater system during plant startup, normal operation, and protection system surveillance. The Technical Specifications recommendations are consistent with the criteria and the risk considerations of the Commission Interim Policy Statement on Technical Specification Improvement. In addition, the staff recommends that all BWR recipients reassess and modify, if needed, their operating procedures and operator training to assure that the operators can mitigate reactor vessel overfill events that may occur via the condensate booster pumps during reduced system pressure operation."

The Generic Letter provides requirements that licensees provide NRC with their schedule and commitments within 180 days of the Generic Letter date. The implementation schedule for actions on which commitments are made should be prior to startup after the first refueling outage, but no later than the second refueling outage, beginning 9 months after receipt of the Generic Letter.

IMPLEMENTATION AND STATUS

SUMMARY

The licensees response to Generic Letter 89-19 was submitted to the NRC on March 20, 1990 and was supplemented on May 4, 1990.

A-48 Hydrogen Control Measures and Effects of Hydrogen Burns on Safety Equipment REQUIREMENTS

SUMMARY

USI A-48 arose as a result of the large amount of hydrogen generated and burned within containment during the TMI accident. This issue covers hydrogen control measures for recoverable degraded core accidents for all BWRs and those PWRs with ice condenser containments.

Extensive research in this area has led to significant revision of the Commission's hydrogen control regulations, given in 10CFR50.44.

The rule in 10CFR50.44 requiring inerting of BWR Mark I and Mark II containments as a method for hydrogen control was published on December 2, 1981. The BWR Mark I and Mark II reactor containments have operated for a number of years with an inerted atmosphere (by addition of an CHAPTER 01 1.12-15 REV. 16, SEPTEMBER 2012

LGS UFSAR inert gas, such as nitrogen) which effectively precludes combustion of any hydrogen generated.

USI A-48 with respect to BWR Mark I and II containments is not only resolved but understood to be fully implemented in the affected plants.

The rule for BWRs with Mark III containments and PWRs with ice condenser containments was published on January 25, 1985. The rule required that these plants be provided with a means for controlling the quantity of hydrogen produced but did not specify the control method. In addition, the action plan for USI A-48 provided for plant specific reviews of lead-plants for reactors with Mark III and ice condenser containments. Sequoyah was chosen as the lead-plant for ice condenser containments and Grand Gulf for Mark III containments. Both of the lead-plant licensees chose to install igniter-type systems to burn the hydrogen before it reached threatening concentrations within the containment. Final design igniter systems have been installed not only in both lead plants, Sequoyah and Grand Gulf, but in all other ice condenser and Mark III plants as well.

Documentation of the staff's safety evaluations of the final analyses required to be submitted by these licensees by the rule are continuing toward completion in 1989.

Large dry PWR containments were excluded from USI A-48 because they have a greater ability to accommodate the large quantities of hydrogen associated with a recoverable degraded core accident than the smaller MARK I, II, III and ice condenser containments. However, this issue has continued to be considered and in 1989, hydrogen control for large dry PWR containments was identified as a high priority Generic Issue 121. (NUREG-0933). The resolution of Generic Issue 121 is being actively pursued in close coordination with more recent research findings.

The NRC staff has concluded that USI A-48 is resolved as stated in SECY 89-122. If interested, the report should be consulted for further details regarding the relationship of A-48 to other ongoing hydrogen activities.

IMPLEMENTATION AND STATUS

SUMMARY

LGS uses an inerted containment as discussed in Section 6.2.5 (see SER and SSER section 6.2.5). Both units received temporary exemptions from inerting during the initial startup testing program. Both units are now in full compliance .

1.

12.4 REFERENCES

1.12-1 "NRC Program for the Resolution of Generic Issues Related to Nuclear Power Plants,"

NUREG-0410, (January 1, 1978).

1.12-2 "Identification of Unresolved Safety Issues Relating to Nuclear Power Plants - A Report to Congress," NUREG-0510, (January 1979).

1.12-3 "NRC Action Plan as a Result of the TMI-2 Accident," NUREG-0660.

1.12-4 "Identification of New Unresolved Safety Issues Relating to Nuclear Power Plants, Special Report to Congress," NUREG-0705, (March 1981).

CHAPTER 01 1.12-16 REV. 16, SEPTEMBER 2012

LGS UFSAR 1.13 TMI-2 RELATED REQUIREMENTS FOR NEW OPERATING LICENSES 1.13.1 NUREG-0737, CLARIFICATION OF THE TMI ACTION PLAN REQUIREMENTS Following the accident at Three Mile Island Unit 2, the NRC developed the TMI Action Plan, NUREG-0660, to provide a comprehensive and integrated plan for improving the safety of power reactors. NUREG-0737 was issued with an October 31, 1980 letter from D.G. Eisenhut (NRC) to licensees of operating power reactors and applicants for operating licenses forwarding specific TMI-related requirements from NUREG-0660 which have been approved by the NRC for implementation at this time. In this NRC report, these specific requirements comprise a single document which includes additional information about implementation schedules, applicability, method of implementation review by the NRC, submittal dates, and clarification of technical positions. It should be noted that the total set of TMI-related actions have been documented in NUREG-0660, but only those items that the NRC has approved for implementation to date are included in NUREG-0737. to NUREG-0737 lists TMI Action Plan requirements for operating license applicants.

Section 1.13.2 itemizes these requirements sequentially according to the NUREG-0737 number.

Each item is accompanied by a response and/or reference to a section in the UFSAR that further discusses how the licensee or the LGS design complies with the requirement. These responses were revised periodically as ongoing efforts to address each requirement were completed.

1.13.2 TMI ACTION PLAN REQUIREMENTS FOR APPLICANTS FOR AN OPERATING LICENSE (ENCLOSURE 2 TO NUREG-0737)

• I.A.1.1 SHIFT TECHNICAL ADVISOR Position Each applicant shall provide an on-shift technical advisor to the shift supervisor. The STA may serve more than one unit at a multiunit site if qualified to perform the advisor function for the various units.

The STA 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 STA shall also receive training in plant design and layout, including the capabilities of instrumentation and controls and the control room. The applicant shall assign normal duties to the STAs that pertain to the engineering aspects of assuring safe operations of the plant, including the review and evaluation of operating experience.

Clarification (1) Due to the similarity in the requirements for dedication to safety, training, and onsite location and the desire that the accident assessment function be performed by someone whose normal duties involve review of operating experiences, our preferred position is that the same people perform the accident and operating experience assessment function.

The performance of these two functions may be split if it can be demonstrated the persons assigned the accident assessment role are aware, on a current basis, of the work being done by those reviewing operating experience.

CHAPTER 01 1.13-1 REV. 19, SEPTEMBER 2018

LGS UFSAR (2) To provide assurance that the STA will be dedicated to concern for the safety of the plant, our position has been the STAs must have a clear measure of independence from duties associated with the commercial operation of the plant. This would minimize possible distractions from safety judgments by the demands of commercial operations. We have determined that, while desirable, independence from the operations staff of the plant is not necessary to provide this assurance. It is necessary, however, to clearly emphasize the dedication to safety associated with the STA position both in the STA job description and in the personnel filling this position. It is not acceptable to assign a person who is normally the immediate supervisor of the shift supervisor to STA duties as defined herein.

(3) It is our position that the STA should be available within 10 minutes of being summoned and therefore should be onsite. The onsite STA may be in a duty status for periods of time longer than one shift, and therefore asleep at some times, if the 10 minute availability is assured. It is preferable to locate those doing the operating experience assessment onsite. The desired exposure to the operating plant and contact with the STA (if these functions are to be split) may be able to be accomplished by a group, normally stationed offsite, with frequent onsite presence.

We do not intend, at this time, to specify or advocate a minimum time onsite.

Response

See Section 13.1.2.1.1 for discussion of the STA position. Qualification requirements for STA positions are discussed in Section 13.1.3.1.

• I.A.1.2 SHIFT SUPERVISOR RESPONSIBILITIES Position Review the administrative duties of the shift supervisor and delegate functions that detract from or are subordinate to the management responsibility for assuring safe operation of the plant to other personnel not on duty in the control room.

Clarification (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 principle shall be reinforced that the shift supervisor should not become totally CHAPTER 01 1.13-2 REV. 19, SEPTEMBER 2018

LGS UFSAR 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.

(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 that 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

In the assignment of functions to the Shift Manager, consideration is given to aspects such as the need to keep the Shift Manager in control of and aware of plant operational, maintenance, and testing activities which may affect safe operation and the need to prevent administrative duties from detracting from the primary responsibility of assuring safe operation.

A letter was written by S.L. Daltroff (PECo) on December 26, 1979, which defines and emphasizes the primary management responsibility of the Shift Superintendent (now the Shift Manager). Similar to PBAPS, this letter will be promulgated to shift supervision in the form of an administrative procedure.

The letter referenced above also defined the duties of control room operators. The nature of the letter was not only to define and emphasize responsibility but to effect the establishment of a definite line of command. This letter will form the basis for an administrative procedure in which the duties of the control room operator will be defined.

In the administrative procedure covering shift operations, a directive will be written which will specify who can relieve the Shift Manager. It will require only that a member of Shift Supervision bearing an active senior license and qualified as an Emergency Director will have such an authority.

Temporary relief of the Shift Manager will normally be accomplished using the Shift Supervisor.

Duties and responsibilities, similar to those of the Shift Manager, will be defined in the administrative procedure covering shift operations. He will be a senior licensed individual having worked side-by-side with the Shift Manager, fully knowledgeable of the Shift Manager's responsibilities and the overall plant status at any given time.

CHAPTER 01 1.13-3 REV. 19, SEPTEMBER 2018

LGS UFSAR The licensee is engaged in a Management Development Program, which includes management training for shift supervisors. All management training courses include training in such topics as style of management, planning, delegation, communications, motivation, personnel and industrial relations and performance review. In addition, all shift supervision has, or will have prior to startup, completed the Genco II Kepner Tregoe Course in Decision Making. In the future, it is planned that shift supervision will have the opportunity to attend some of the subsequent courses associated both with the Management Development Program and the Kepner Tregoe Program.

The administrative responsibilities for all members of shift supervision are defined in an administrative procedure.

The administrative procedure covering shift operations will define shift supervision's administrative responsibilities. Those which will be retained will be those which are defined in that administrative procedure.

The duties and responsibilities of the Shift Manager during accident/transient conditions will be delineated in both the Emergency Plan and the administrative procedures governing shift operations. The procedures developed from the Emergency Plan will contain detailed responsibilities of the Shift Manager during such conditions.

The STA will hold a staff position in the Operations Group. He reports directly to the Shift Manager on his staff. The STA advises the Shift Manager concerning off-normal events and will make appropriate recommendations regarding corrective and precautionary actions.

See Section 13.1.2.1.1 for further discussion.

• I.A.1.3 SHIFT MANNING Position Assure that the necessary number and availability of personnel to man the operations shifts have been designated by the licensee. Administrative procedures should be written to govern the movement of key individuals about the plant to assure that qualified individuals are readily available in the event of an abnormal or emergency situation. This should consider the recommendations on overtime in NUREG-0578. Provisions should be made for an aide to the shift supervisor to assure that, over the long-term, the shift supervisor is free of routine administrative duties.

Clarification At any time a licensed nuclear unit is being operated in Modes 1-4 for a PWR (power operation, startup, hot standby or hot shutdown, respectively) or in Modes 1-3 for a BWR (power operation, startup, or hot shutdown, respectively), the minimum shift crew shall include two licensed senior reactor operators, one of whom shall be designated as the shift supervisor, two licensed reactor operators, and two unlicensed auxiliary operators. For a multiunit station, depending upon the station configuration, shift staffing may be adjusted to allow credit for licensed senior reactor operators and licensed reactor operators to serve as relief operators on more than one unit; however, these individuals must be properly licensed on each such unit. At all other times, for a unit loaded with fuel, the minimum shift crew shall include one shift supervisor who shall be a CHAPTER 01 1.13-4 REV. 19, SEPTEMBER 2018

LGS UFSAR licensed senior reactor operator, one licensed reactor operator, and one unlicensed auxiliary operator.

Adjunct requirements to the shift staffing criteria stated above are as follows:

(1) A shift supervisor with a senior reactor operator's license, who is also a member of the station supervisory staff, shall be onsite at all times when at least one unit is loaded with fuel.

(2) A licensed senior reactor operator shall, at all times, be in the control room from which a reactor is being operated. The shift supervisor may from time to time act as relief operator for the licensed senior reactor operator assigned to the control room.

(3) For any station with more than one reactor containing fuel, the number of licensed senior reactor operators onsite shall, at all times, be at least one more than the number of control rooms from which the reactors are being operated.

(4) In addition to the licensed senior reactor operators specified in (1), (2), and (3) above, for each reactor containing fuel, a licensed reactor operator shall be in the control room at all times.

(5) In addition to the operators specified in (1), (2), (3), and (4) above, for each control room from which a reactor is being operated, an additional licensed reactor operator shall be onsite at all times and available to serve as relief operator for that control room. As noted above, this individual may serve as relief operator for each unit being operated from that control room, provided he holds a current license for each unit.

(6) Auxiliary (nonlicensed) operators shall be properly qualified to support the unit to which assigned.

(7) In addition to the staffing requirements stated above, shift crew assignments during periods of core alterations shall include a licensed senior reactor operator to directly supervise the core alterations. This licensed senior reactor operator may have fuel handling duties but shall not have other concurrent operational duties.

Licensees of operating plants and applicants for operating licenses shall include in their administrative procedures provisions governing required shift staffing and movement of key individuals about the plant. These provisions are required to assure that qualified plant personnel to man the operational shifts are readily available in the event of an abnormal or emergency situation.

The following information regarding fatigue management and work hours controls is historical.

The current regulatory requirements are provided by the 10CFR26 Fitness for Duty Programs rule, which became effective on April 30, 2008. Implementation of the amended rule was required by October 1, 2009. Limerick administrative procedure LS-AA-119, "Fatigue Management and Work Hour Limits," was revised and issued to implement requirements for managing fatigue and controlling work hours in accordance with 10CFR26, Subpart I, "Managing Fatigue." The procedure defines the scope of workers that are subject to the fatigue management program and the scope of workers subject to work hour controls. The procedure also includes the 10CFR26 work hours limits.

CHAPTER 01 1.13-5 REV. 19, SEPTEMBER 2018

LGS UFSAR These administrative procedures shall also set forth a policy, the objective of which is to prevent situations where fatigue could reduce the ability of operating personnel to keep the reactor in a safe condition. The controls established should assure that, to the extent practicable, personnel are not assigned to shift duties while in a fatigued condition that could significantly reduce their mental alertness or their decision making ability. The controls shall apply to the plant staff who perform safety-related functions (e.g., senior reactor operators, reactor operators, auxiliary operators, health physicists, and key maintenance personnel).

IE Circular No. 80-02, "Nuclear Power Plant Staff Work Hours," dated February 1, 1980 discusses the concern of overtime work for members of the plant staff who perform safety-related functions.

The guidance contained in IE Circular No. 80-02 was amended by the July 31, 1980 NRC letter. In turn, the overtime guidance of the July 31, 1980 NRC letter was revised in Section I.A.1.3 of NUREG-0737. The NRC was issued a policy statement which further revises the overtime guidance as stated in NUREG-0737. This guidance is as follows:

Enough plant operating personnel should be employed to maintain adequate shift coverage without routine heavy use of overtime. The objective is to have operating personnel work a nominal 8-hour day, 40-hour week while the plant is operating. However, in the event the unforeseen problems require substantial amounts of overtime to be used, or during extended periods of shutdown for refueling, major maintenance or major plant modifications, on a temporary basis, the following guidelines shall be followed:

a. An individual should not be permitted to work more than 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> straight (excluding shift turnover time).

b. An individual should not be permitted to work more than 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> in any 24-hour period, nor more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in any 48-hour period, nor more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in any seven day period (all excluding shift turnover time).

c. A break of at least eight hours should be allowed between work periods (including shift turnover time).

d. Except during extended shutdown periods, the use of overtime should be considered on an individual basis and not for the entire staff on shift.

Recognizing that very unusual circumstances may arise requiring deviation from the above guidelines, such deviation shall be authorized by the plant manager or his deputy, or higher levels of management. The paramount consideration in such authorization shall be that significant reductions in the effectiveness of operating personnel would be highly unlikely. Authorized deviations to the working hour guidelines shall be documented and available for NRC review.

In addition, procedures are encouraged that would allow licensed operators at the controls to be periodically relieved and assigned to other duties away from the control board during their tours of duty.

Operating license applicants shall complete these administrative procedures before fuel loading.

Development and implementation of the administrative procedures at operating plants will be reviewed by the Office of Inspection and Enforcement beginning October 1, 1982.

CHAPTER 01 1.13-6 REV. 19, SEPTEMBER 2018

LGS UFSAR

Response

See Section 13.1.2 on shift manning.

The shift operations administrative procedure governs the required shift staffing and movement of key individuals about the plant, in particular the location of control operators and shift supervision.

An administrative procedure contains, working hour restrictions, which are in accord with current regulations at the time of writing.

The same administrative procedure that sets forth policies regarding overtime contains procedures which govern the deviation from overtime restrictions and how deviations will be documented.

The operations shift complement required when refueling operations are scheduled, along with the responsibilities of the refueling shift personnel, are defined in administrative procedures.

The licensee maintains a Nuclear Training Division. This organization compiles specific job requirements for operating people within power plants. For this list of job requirements, qualifying tests are generated. These tests are administered to applicants for promotion, with promotion to the applicable job described being contingent upon a passing grade. This applies to all plant operators including the equipment operator.

• I.A.2.1 IMMEDIATE UPGRADING OF OPERATOR AND SENIOR OPERATOR TRAINING AND QUALIFICATION Position Applicants for SRO license shall have 4 years of responsible power plant experience, of which at least 2 years shall be nuclear power plant experience (including 6 months at specific plant) and no more than 2 years shall be academic or related technical training. After fuel loading, applicants shall have 1 year of experience as a licensed operator or equivalent.

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

Applicants must revise training programs to include training in heat transfer, fluid flow, thermodynamics, and plant transients.

Clarification Applicants for SRO either come through the operations chain (C operator to B operators to A operator, etc.) or are degree-holding staff engineers who obtain licenses for backup purposes.

In the past, many individuals who came through the operator ranks were administered SRO examinations without first being an operator. This was clearly a poor practice and the letter of March 28, 1980 requires reactor operator experience for SRO applicants.

CHAPTER 01 1.13-7 REV. 19, SEPTEMBER 2018

LGS UFSAR However, NRC does not wish to discourage staff engineers from becoming licensed SROs. The effort is encouraged because it forces engineers to broaden their knowledge about the plant and its operation.

In addition, in order to attract degree-holding engineers to consider the shift supervisor's job as part of their career development, NRC should provide an alternate path to holding an operator's license for 1 year.

The track followed by a high school graduate (a nondegreed individual) to become an SRO would be 4 years as a control room operator, at least one of which would be as a licensed operator, and participation in an SRO training program that includes 3 months on-shift as an extra person.

The track followed by a degree-holding engineer would be, at a minimum, 2 years of responsible nuclear power plant experience as a staff engineer, participation in an SRO training program equivalent to a cold applicant training program, and 3 months on-shift as an extra person in training for an SRO position.

Holding these positions assures that individuals who will direct the license activities of licensed operators have had the necessary combination of education, training, and actual operating experience prior to assuming a supervisory role at the facility.

The staff realizes that the necessary knowledge and experience can be gained in a variety of ways. Consequently, credit for equivalent experience should be given to applicants for SRO licenses.

Applicants for SRO licenses at a facility may obtain their 1 year operating experience in a licensed capacity (operator or senior operator) at another nuclear power plant. In addition, actual operating experience in a position that is equivalent to a licensed operator or senior operator at military propulsion reactors will be acceptable on a one-for-one basis. Individual applicants must document this experience in their individual applications in sufficient detail so that the staff can make a finding regarding equivalency.

Applicants for SRO licenses who possess a degree in engineering or applicable sciences are deemed to meet the above requirements, provided they meet the requirements set forth in sections A.1.a and A.2 in enclosure in the letter from H.R. Denton (NRC) to all power reactor applicants and licensees, dated March 28, 1980, and have participated in a training program equivalent to that of a cold senior operator applicant.

The NRC has not imposed the 1 year experience requirement on cold applicants for SRO licenses. Cold applicants are to work on a facility not yet in operation; their training programs are designed to supply the equivalent of the experience not available to them.

Response

Applicants for SRO license will have at least 4 years of responsible power plant experience, of which at least 2 years will be nuclear plant experience, including 6 months at the plant and no more than 2 years will be academic or related technical training.

The requirements for certification are implemented in administrative procedures.

CHAPTER 01 1.13-8 REV. 19, SEPTEMBER 2018

LGS UFSAR The training programs for RO and SRO license will include training in heat transfer, fluid flow, thermodynamics, and plant transients. See Section 13.2.1.1 for further discussion.

• I.A.2.3 ADMINISTRATION OF TRAINING PROGRAMS Position Pending accreditation of training institutions, training instructors who teach systems, integrated response, transient and simulator courses shall successfully complete a SRO examination prior to fuel loading and instructors shall attend appropriate retraining programs that address, as a minimum, current operating history, problems and changes to procedure and administrative limitations. In the event an instructor is a licensed SRO, his retraining shall be the SRO requalification program.

Clarification The above position is a short-term position. In the future, accreditation of training institutions will include review of the procedure for certification of instructors. The certification of instructors may, or may not, include successful completion of an SRO examination.

The purpose of the examination is to provide NRC with reasonable assurance during the interim period that instructors are technically competent.

The requirement is directed to permanent members of training staff who teach the subjects listed above, including members of other organizations who routinely conduct training at the facility.

There is no intention to require guest lecturers who are experts in particular subjects (reactor theory, instrumentation, thermodynamics, health physics, chemistry, etc.) to successfully complete an SRO examination. Nor is it intended to require a system expert, such as the instrument and control supervisor teaching the control rod drive system, to sit for an SRO examination.

Response

The requirements for training instructors will be implemented in administration of the training program.

• I.A.3.1 REVISE SCOPE AND CRITERIA FOR LICENSING EXAMINATIONS Position Applicants for operator licenses will be required to grant permission to the NRC to inform their facility management regarding the results of examinations.

Contents of the licensed operator requalification program shall be modified to include instruction in heat transfer fluid flow, thermodynamics and mitigation of accidents involving a degraded core.

The criteria for requiring a licensed individual to participate in accelerated requalification shall be modified to be consistent with the new passing grade for issuance of a license.

CHAPTER 01 1.13-9 REV. 19, SEPTEMBER 2018

LGS UFSAR Requalification programs shall be modified to require specific reactivity control manipulations.

Normal control manipulations, such as plant or reactor startups, must be performed. Control manipulations during abnormal or emergency operation shall be walked through and evaluated by a member of the training staff.

An appropriate simulator may be used to satisfy the requirements for control manipulations.

Clarification The clarification does not alter the staff's position regarding simulator examinations.

The clarification does provide additional preparation time for utility companies and NRC to meet examination requirements as stated. A study is under way to consider how similar a nonidentical simulator should be for a valid examination. In addition, present simulators are fully booked months in advance.

Application of this requirement was stated in June 1, 1980 to applicants where a simulator is located at the facility. Starting October 1, 1981, simulator examinations will be conducted for applicants of facilities that do not have simulators at the site.

NRC simulator examinations normally require 2 to 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />. Normally, two applicants are examined during this time period by two examiners.

Utility companies should make the necessary arrangements with an appropriate simulator training center to provide time for these examinations. Preferably these examinations should be scheduled consecutively with the balance of the examination. However, they may be scheduled no sooner than 2 weeks prior to and no later than 2 weeks after the balance of the examination.

Response

The requirements for RO and SRO examinations and requalification programs will be implemented.

• I.B.1.2 EVALUATION OF ORGANIZATION AND MANAGEMENT Position Corporate management of the utility-owner of a nuclear power plant shall be sufficiently involved in the operational phase activities, including plant modifications, to assure a continual understanding of plant conditions and safety considerations. Corporate management shall establish safety standards for the operation and maintenance of the nuclear power plant. To these ends, each utility-owner shall establish an organization, parts of which shall be located onsite, to: perform independent review and audits of plant activities; provide technical support to the plant staff for maintenance, modifications, operational problems, and operational analysis; and aid in the establishment of programmatic requirements for plant activities.

The licensee shall establish an integrated organizational arrangement to provide for the overall management of nuclear power plant operations. This organization shall provide for clear management control and effective lines of authority and communication between the CHAPTER 01 1.13-10 REV. 19, SEPTEMBER 2018

LGS UFSAR organizational units involved in the management, technical support, and operation of the nuclear unit. The key characteristics of a typical organization arrangement are:

(1) Integration of all necessary functional responsibilities under a single responsible head.

(2) The assignment of responsibility for the safe operation of the nuclear power plant(s) to an upper-level executive position.

Utility management shall establish a group, independent of the plant staff, but assigned onsite, to perform independent reviews of plant operational activities. The main functions of this group will be to evaluate the technical adequacy of all procedures and changes important to the safe operation of the facility and to provide continuing evaluation and assessment of the plant's operating experience and performance.

Response

The licensees corporate and plant staff organizations for routine operations are described in Sections 17.2 and 13.1. The emergency organization is described in the nuclear emergency plan.

Independent review activities are described in Section 13.4

• I.C.1 SHORT-TERM ACCIDENT ANALYSIS AND PROCEDURE REVIEW Position In our letters of September 13 and 27, October 10 and 30, and November 9, 1979, we required licensees of operating plants, applicants for operating licenses, and licensees of plants under construction to perform analyses of transients and accidents, prepare emergency procedure guidelines, upgrade emergency procedures, and to conduct operator retraining (see also Item I.A.2.1 of this report). Emergency procedures are required to be consistent with the actions necessary to cope with the transients and accidents analyzed. Analyses of transients and accidents were to be completed in early 1980, and implementation of procedures and retraining were to be completed 3 months after emergency procedure guidelines were established; however, some difficulty in completing these requirements has been experienced. Clarification of the scope of the task and appropriate schedule revisions were included in NUREG-0737, Item I.C.1.

Pending staff approval of the revised analysis and guidelines, the staff will continue the pilot monitoring of emergency procedures described in Item I.C.8 (NUREG-0660). The adequacy of the BWR vendor's guidelines will be identified to each near-term operating licensee during the emergency procedure review.

Response

Emergency operating procedures are developed from the BWROG Emergency Procedure and Severe accident Guidelines (EPG/SAGs). Reference UFSAR Section 15.0.6 for a discussion of these guidelines. The development of the EPGs was based on reanalysis of transients and accidents and inadequate core cooling. The licensed operator training program includes training on the emergency operating procedures.

Additional information has been provided in a letter from V.S. Boyer (PECo) to D.G. Eisenhut (NRC) dated April 15, 1983.

CHAPTER 01 1.13-11 REV. 19, SEPTEMBER 2018

LGS UFSAR

• I.C.2 SHIFT RELIEF AND TURNOVER PROCEDURES Position The licensee 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 offgoing 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 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.

(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 or test that by itself could degrade a system critical to the prevention and mitigation of operational transients and accidents or initiate an operational transient (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 procedures (for example, periodic independent verification of system alignments).

Response

The requirements stated in this section will be implemented except for the request to establish separate checklists or logs for use by the offgoing and ongoing equipment operators and maintenance technicians.

A variety of shift turnover checklists or logs, situated in various locations of the plant and under the control of many groups would further hinder the transfer of vital information to the operating shift personnel with primary responsibility for plant operations. A limited number of checklists or logs, centralized in the control room and under the supervision of control room personnel, is essential to effective transfer of information.

Maintenance and testing of equipment vital to safe operation of the plant is performed with the knowledge and approval of the appropriate licensed control room operator. The checklists, status boards, or logs will be utilized to identify any equipment under maintenance or test that by themselves could degrade a system critical to the prevention and mitigation of operational CHAPTER 01 1.13-12 REV. 19, SEPTEMBER 2018

LGS UFSAR transients and accidents, or initiate an operational transient. Some of this information will be supplied to the control room operators and supervisors, as appropriate, by the equipment operators and technicians for entry into the checklists and logs. Shift personnel meetings under the direction of shift supervision are normally held shortly after shift turnover. Offgoing equipment operators will normally be relieved at their job locations in the plant. Equipment operators will, when job conditions permit, complete and review an applicable shift turnover checkoff list. If plant operations require that equipment operators conduct shift turnover on the job away from their normal turnover location and no turnover checklist is executed, the person making relief will, at the earliest convenience, report to shift supervision to obtain a supplementary briefing. Examples of activities that could preclude normal turnover include filling the main generator with hydrogen and executing a demineralizer regeneration.

Checklists for oncoming and offgoing control room operators and oncoming shift supervisors to be used during shift turnover will be included in administrative procedure for shift operations.

A checklist for shift turnover to be used by equipment operators will be written and will be included in the shift operations administrative procedure.

Included as part of the shift operations administrative procedure, and specifically in the sections relating to shift turnover, instructions will be communicated to the various levels of shift operating personnel directing that, when deficiencies in the turnover process are noticed primarily by the discovery of information which was not surfaced during the turnover, such deficiencies will be brought to the attention of shift supervision, who will in turn initiate a modification to the turnover checkoff list. This mechanism will ensure that, as job responsibilities change, appropriate modifications will be made to the checklist.

• I.C.3 SHIFT SUPERVISOR RESPONSIBILITIES This item is included with Section I.A.1.2, Shift Supervisor responsibilities.

Response

This requirement will be implemented.

• I.C.4 CONTROL ROOM ACCESS 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 operation, and the predesignated 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 CHAPTER 01 1.13-13 REV. 19, SEPTEMBER 2018

LGS UFSAR 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 the control room.

Response

An administrative procedure for control room access will be written and will define the authority and responsibility of the Shift Manager, or alternate, to exercise control over control room access.

This administrative procedure will provide the Shift Manager, or alternate, with authority to order persons out of the control room if they have gained entrance and were not authorized or if conditions in the control room change to an extent which changes the access requirements.

Administrative procedures establish a clear line of authority and responsibility in the control room for emergency conditions. This will include the line of succession for the person in charge of the control room.

During plant emergencies, lines of communications and authority for the subject plant management personnel will be delineated in the Emergency Plan. This will include those persons reporting to the TSC, EOF, and Press Facility.

• I.C.5 FEEDBACK OF OPERATING EXPERIENCE Position Each licensee will review its administrative procedures to assure that operating experience from within and outside the organization is continually provided to operators and other operational personnel and is incorporated in training programs.

Response

The Regulatory Assurance Section is supervised by the Manager, Regulatory Assurance, who reports to the Vice President, LGS and is responsible for ensuring review of operating experience reports that may be directed to the plant by various industry groups and regulatory agencies and for disseminating such reports to the appropriate personnel for review for applicability to LGS and determination of required action.

In addition, the External and Internal Operating Experience (OPEX) program ensures that appropriate events that occur within the Exelon fleet and in the industry are evaluated for similar conditions at the station. To ensure consistency between various plants within the Exelon fleet, a corporate OPEX coordinator provides overall coordination and direction to this program.

Mechanisms exist for identifying, screening, and investigating OPEX items. The corporate OPEX coordinator screens OPEX issues. Depending on the OPEX item being investigated, appropriate corporate, station or other qualified personnel evaluate the issue. Corporate actions are identified if required and are tracked for completion within the site action tracking program. Appropriate status reporting and monitoring of OPEX are also performed. The site OPEX coordinator function resides within Regulatory Assurance.

• I.C.6 VERIFY CORRECT PERFORMANCE OF OPERATING ACTIVITIES Position CHAPTER 01 1.13-14 REV. 19, SEPTEMBER 2018

LGS UFSAR It is required (from NUREG-0660) that licensees' procedures be reviewed and revised, as necessary, to assure that an effective system of verifying the correct performance of operating activities is provided as a means of reducing human errors and improving the quality of normal operations. This will reduce the frequency of occurrence of situations that could result in or contribute to accidents. Such a verification system may include automatic system status monitoring, human verification of operations, and maintenance activities independent of the people performing the activity (see NUREG-0585, Recommendation 5), or both.

Response

Plant procedures will describe a system for the control of removal and restoration and alignment of safety-related plant systems or equipment. This system will use a combination of control room indicators, operability testing, or independent verification (subject to radiation exposure limitations), to ensure that equipment is in its correct alignment.

• I.C.7 NSSS VENDOR REVIEW OF PROCEDURES Position Obtain NSSS vendor review of power ascension and emergency operating procedures to further verify their adequacy.

Response

This requirement will be implemented.

• I.C.8 PILOT MONITORING OF SELECTED EMERGENCY PROCEDURES FOR NEAR-TERM OPERATING LICENSE APPLICANTS Position Correct emergency procedures as necessary based on the NRC audit of selected plant emergency operating procedures (e.g., SBA, loss of feedwater, restart of ESF following a loss of ac power and steam line break).

Response

Information on emergency procedures (NUREG-0737, Item I.C.1) was provided to the NRC in a response (Letter from V.S. Boyer to D.G. Eisenhut dated April 15, 1983) to Generic Letter 82-33, Supplement 1 to NUREG-0737. Emergency operating procedures are developed from the current revision of the BWROG Emergency Procedure Guidelines.

• I.D.1 CONTROL ROOM DESIGN REVIEWS Position Licensees and applications for operating licenses are required to conduct a detailed control room design review to identify and correct design deficiencies. This detailed control room design review is expected to take about a year. Those applicants for operating licenses who are unable to CHAPTER 01 1.13-15 REV. 19, SEPTEMBER 2018

LGS UFSAR complete this review prior to issuance of a license shall make preliminary assessments of their control rooms to identify significant human factors and instrumentation problems and establish a schedule approved by us for correcting deficiencies. These applicants will be required to complete the more detailed control room reviews on the same schedule as licensees with operating plants.

Clarification Applicants for operating license who will be unable to complete the detailed control room review prior to issuance of a license are required to perform a preliminary control room design assessment to identify significant human factors problems. Applicants will find it of value to refer to the draft document, NUREG/CR-1580, "Human Engineering Guide to Control Room Evaluation," in performing the preliminary assessment. We will evaluate the applicant's preliminary assessments including the performance by us of onsite reviews/audits. Our onsite review/audit will be on a schedule consistent with applicant licensing needs and will emphasize the following aspects of the control room:

(1) The adequacy of information presented to the operator to reflect plant status for normal operation, anticipated operational occurrences, and accident conditions; (2) The groupings of displays and the layout of panels; (3) Improvements in the safety monitoring and human factors enhancement of controls and control displays; (4) The communications from the control room to points outside the control room, such as the onsite technical support center, remote shutdown panel, offsite telephone lines, and to other areas within the plant for normal and emergency operation.

(5) The use of direct rather than derived signals for the presentation of process and safety information to the operator; (6) The operability of the plant from the control room with multiple failures of nonsafety-grade and nonseismic systems; (7) The adequacy of operating procedures and operator training with respect to limitations of instrumentation displays in the control room; (8) The categorization of alarms, with unique definition of safety alarms; (9) The physical location of the shift supervisor's office either adjacent to or within the control room complex.

Prior to the onsite review/audit, we will require a copy of the applicant's preliminary assessment and additional information which will be used in formulating the details of the onsite review/audit.

Response

The CRDR effort directed by Item I.D.I and required by Supplement 1 to NUREG-0737 began in 1980 with the licensee's participation in the BWROG CRDR Subcommittee. The subcommittee CHAPTER 01 1.13-16 REV. 19, SEPTEMBER 2018

LGS UFSAR produced a BWR Owner's Group Generic CRDR Program which addresses Item 5.1.b of Supplement 1. This generic program was submitted to the NRC for review in August 1981. The review and subsequent discussions between the NRC and representatives of the subcommittee have resulted in a supplement to the review program.

A preliminary review of the LGS control room was conducted using the original design review program in October 1981. At that time, the LGS control room was still in the construction phase, and the formal LGS emergency procedures were not available for the walk-through.

The licensee subsequently developed a program to address the assessment, implementation and verification phases of the LGS CRDR Program. This program was submitted in August 1983 and a report was submitted in June 1984 and supplemented in November 1984 and June 1985.

Basic Requirements Completion Dates:

(Numbering refers to corresponding portions of Section 5 of Supplement 1) 5.1.a) As was the case during the initial review phase, a person competent in human factors engineering as well as persons competent in system design and system operation were included in the assessment phase of the Program. This assessment was completed in April 1984.

5.1.b) A detailed review of the control room has been completed as discussed in current status above. Completion of the review to address the supplemental checklist and those items not included in the preliminary review due to construction status was completed in January 1984.

5.1.c) Assessment of the HEDs was completed in June 1985.

5.1.d) Proposed improvements have been reviewed by the multidisciplinary task force described in 5.1.a to ensure that the proposed change addresses the identified HED and does not create additional HEDs. All changes have been integrated with other control room modifications.

5.2.a) The program plan for completing the CRDR was completed and is outlined below:

i. Completed the generic review program including the supplemental review and the emergency procedure walk- through.

ii. Assessed the identified HEDs and generated recommendations for modification to those HEDs that warrant a change.

iii. Each of the proposed modifications were reviewed to verify that it corrected the HED it was intended to correct and did not create any new unacceptable HEDs.

The modifications have been coordinated with the balance of the NUREG-0737 Supplement 1 initiatives.

iv. The NRC conducted an in-progress audit in December 1983.

CHAPTER 01 1.13-17 REV. 19, SEPTEMBER 2018

LGS UFSAR 5.2.b) A summary report was prepared and submitted in June 1984 and supplemented in November 1984 and June 1985. These reports included proposed modifications and their Unit 1 schedules. Unit 2 modifications and schedules were provided in October 1988.

• I.D.2 PLANT SAFETY PARAMETER DISPLAY CONSOLE Position Each applicant and licensee shall install a SPDS that will display to operating personnel a minimum set of parameters which define the safety status of the plant. This can be attained through continuous indication of direct and derived variables as necessary to assess plant safety status.

Response

The LGS design includes a PMS. This system is based, in part, on the GE emergency response system described in Reference 1.13-7. The SPDS is a part of this PMS. The SPDS is not safety-related, as discussed in Supplement 1 to NUREG-0737. Sensors, isolators, signal conditioners or other components which provide input to the SPDS are Q-listed if they are part of a safety-related system. The SPDS parameters, a subset of the parameters available in the PMS data base, are based on the Regulatory Guide 1.97 (Rev 2) BWR parameter list. All of the critical safety functions defined in Supplement 1 to NUREG-0737, "Clarification of TMI Action Plan Requirements," for a BWR, are addressed by the PMS process variables.

The parameters included in the SPDS display are based on the entry conditions for the LGS EOPs. As changes and improvements are made to the RPV control and containment control procedures, the system can be modified to reflect these changes. The system has been designed in accordance with the guidance provided in NUREG-0696.

A safety analysis describing the basis on which the selected parameters are sufficient to assess the safety status of each identified function for a wide range of events was transmitted by letter from J.S. Kemper (PECo) to A. Schwencer (NRC) dated September 2, 1983.

The software debugging, validation, testing, and acceptance testing will be completed during the Power Ascension Test Program. The SPDS and Regulatory Guide 1.97 parameter displays will be functional within 30 days after the completion of the 100 hour0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> warranty run at 100% power.

• I.G.1 TRAINING DURING LOW POWER TESTING Position We require applicants for a new operating license to define and commit to a special low power testing program approved by NRC to be conducted at power levels no greater than 5% for the purposes of providing meaningful technical information beyond that obtained in the normal startup test program and to provide supplemental training.

Clarification CHAPTER 01 1.13-18 REV. 19, SEPTEMBER 2018

LGS UFSAR Chapter 14 of the Final Safety Analysis Report describes the applicant's initial test program. The objectives of the initial test program include both training and the acquisition of technical data.

This program has been determined by the staff to be acceptable as reported in Section 14 of this report. However, we require the applicant to perform additional testing and training beyond the requirements of the initial test program.

Response

The BWROG program for compliance with NUREG-0737 Requirement I.G.1 was transmitted to the NRC via letter (BWROG-8120) from D.B. Waters (BWROG) to E.G. Eisenhut (NRC). The generic program described in this document is divided into five sections: I-Preoperational Testing; II-Cold Functional Testing; III-Hot Functional Testing; IV-Startup Testing; and V-Additional Training and Testing. The initial test program for LGS as described in Chapter 14 follows the testing described in the first four sections of the BWROG program. During this program, the licensee expects to perform significant plant transients only once, but with a maximum of licensed personnel in attendance. The LGS unit unique simulator provides an excellent mechanism for training people without affecting the real plant. Repetition of startup tests solely for testing purposes will be done on this simulator. Chapter 14 has been changed to describe the additional testing discussed in section V of the BWROG program.

Additional training is to be included in the certification program on the LGS simulator which shall include total loss of offsite and onsite ac power.

• II.B.1 REACTOR COOLANT SYSTEM VENTS Position Each applicant and licensee shall install RCS and reactor vessel head high point vents remotely operated from the control room. Although the purpose of the system is to vent noncondensable gases from the RCS which may inhibit core cooling during natural circulation, the vents must not lead to an unacceptable increase in the probability of a LOCA or a challenge to containment integrity. Since these vents form a part of the reactor coolant pressure boundary, the design of the events shall conform to the requirements of 10CFR50, Appendix A, "General Design Criteria."

The vent system shall be designed with sufficient redundancy that assures a low probability of inadvertent or irreversible actuation. Each licensee shall provide the following information concerning the design and operation of the high point vent system:

(1) Submit a description of the design, location, size, and power supply for the vent system along with results of analyses for LOCA initiated by a break in the vent pipe. The results of the analyses should demonstrate compliance with the acceptance criteria of 10CFR50.46.

(2) Submit procedures and supporting analysis for operator use of the vents that also include the information available to the operator for initiating or terminating vent usage.

Clarification A. General CHAPTER 01 1.13-19 REV. 19, SEPTEMBER 2018

LGS UFSAR (1) The important safety function enhanced by this venting capability is core cooling. For events beyond the present design basis, this venting capability will substantially increase the plant's ability to deal with large quantities of noncondensable gas which could interfere with core cooling.

(2) Procedures addressing the use of the RCS vents should define the conditions under which the vents should be used as well as the conditions under which the vents should not be used. The procedures should be directed toward achieving a substantial increase in the plant being able to maintain core cooling without loss of containment integrity for events beyond the design basis. The use of vents for accidents within the normal design basis must not result in a violation of the requirements of 10CFR50.44 or 10CFR50.46.

(3) The size of the RCS vents is not a critical issue. The desired venting capability can be achieved with vents in a fairly broad spectrum of sizes. The criteria for sizing a vent can be developed in several ways. One approach, which may be considered, is to specify a volume of noncondensable gas to be vented and in a specific venting time. For containments particularly vulnerable to failure from large hydrogen releases over a short period of time, the necessity and desirability for contained venting outside the containment must be considered (e.g., into a decay gas collection and storage system).

(4) Where practical, the reactor coolant system vents should be kept smaller than the size corresponding to the definition of LOCA (10CFR50, Appendix A). This will minimize the challenges to the ECCS since the inadvertent opening of a vent smaller than the LOCA definition would not require ECCS actuation, although it may result in leakage beyond technical specification limits. On PWRs, the use of new or existing lines whose smallest orifice is larger than the LOCA definition will require a valve in series with a vent valve that can be closed from the control room to terminate the LOCA that would result if an open vent valve could not be reclosed.

(5) A positive indication of valve position should be provided in the control room.

(6) The reactor coolant vent system shall be operable from the control room.

(7) Since the RCS vent will be part of the RCPB, all requirements for the reactor pressure boundary must be met, and, in addition, sufficient redundancy should be incorporated into the design to minimize the probability of an inadvertent actuation of the system.

Administrative procedures may be a viable option to meet the single failure criterion. For vents larger than the LOCA definition, an analysis is required to demonstrate compliance with 10CFR50.46.

(8) The probability of a vent path failing to close, once opened, should be minimized; this is a new requirement. Each vent must have its power supplied from an emergency bus. A single failure within the power and control aspects of the reactor coolant vent system should not prevent isolation of the entire vent system when required. On BWRs, block valves are not required in lines with safety valves that are used for venting.

(9) Vent paths from the primary system to within containment should go to those areas that provide good mixing with containment air.

CHAPTER 01 1.13-20 REV. 19, SEPTEMBER 2018

LGS UFSAR (10) The reactor coolant vent system (i.e., vent valves, block valves, position indication devices, cable terminations, and piping) shall be seismically and environmentally qualified in accordance with IEEE 344 (1975) as supplemented by Regulatory Guide 1.100, Regulatory Guide 1.92 and SEP 3.92, 3.43, and 3.10. Environmental qualifications are in accordance with the May 23, 1980 Commission Order and Memorandum (CLI-80-21).

(11) Provisions to test for operability of the reactor coolant vent system should be a part of the design. Testing should be performed in accordance with subsection IWV of Section XI of the ASME Code for Category B valves.

(12) It is important that the displays and controls added to the control room as a result of this requirement not increase the potential for operator error. A human factor analysis should be performed taking into consideration:

(a) the use of this information by an operator during both normal and abnormal plant conditions, (b) integration into emergency procedures, (c) integration into operator training, and (d) other alarms during emergency and need for prioritization of alarms.

B. BWR Design Considerations (1) Since the BWROG has suggested that the present BWR designs have an inherent capability to vent, a question relating to the capability of existing systems arises. The ability of these systems to vent the RCS of noncondensable gas generated during an accident must be demonstrated. Because of differences among the head vent systems for BWRs, each licensee or applicant should address the specific design features of this plant and compare them with the generic venting capability proposed by the BWROG. In addition, the ability of these systems to meet the same requirements as the PWR vent system must be documented.

(2) In addition to RCS venting, each BWR licensee should address the ability to vent other systems, such as the isolation condenser which may be required to maintain adequate core cooling. If the production of a large amount of noncondensable gas would cause the loss of function of such a system, remote venting of that system is required. The qualifications of such a venting system should be the same as that required for PWR venting systems.

Response

The BWROG position on NUREG-0737, Item II.B.1 requirements for RCS vents is contained in D.B. Waters (BWROG) letter to D.G. Eisenhut (NRC) dated April 24, 1981, D.B. Waters (BWROG) letter to D.G. Eisenhut (NRC) dated October 8, 1980, and T.D. Keenan (BWROG) letter to D.G. Eisenhut (NRC) dated October 17, 1979. The licensee concurs with the BWROG conclusion that adequate RCS venting capability is provided by the existing plant design. The following is a description of the existing LGS provisions for RCS venting and an assessment of this capability relative to the NUREG-0737 position and clarification.

CHAPTER 01 1.13-21 REV. 19, SEPTEMBER 2018

LGS UFSAR Position (1)

LGS is provided with five power-operated, safety-grade SRVs (ADS valves PSV-41-F013E, H, K, M, and S) that would be the primary means of venting noncondensable gases from the RPV following a LOCA. The point of connection of the vent lines to the vessel is such that accumulation of gases above this elevation in the vessel will not inhibit natural circulation cooling of the reactor core. These ADS valves are self-actuating at their set relieving pressure to provide system overpressure protection and can also be actuated automatically or manually from the control room to depressurize the reactor. Operation of the ADS valves requires only safety-grade equipment and controls and does not require any source of offsite or ac power. The valves are controlled by dc power from the safeguard batteries and are pneumatically actuated from individual safety-grade accumulators and a safety-grade nitrogen bottle supply for long-term operation. Additional information regarding the design, qualification, power source, etc., of the SRVs is presented in Sections 5.1, 5.2.2, 6.2, 6.3, 7.3, 9.3.1.3, and 15.

Although the power-operated, safety-grade SRVs discussed above satisfy the NUREG-0737 requirements, the following other means of venting noncondensables from the RPV exist:

a) Nine other SRVs (PSV-41-F013 A-D, F, G, J, L, and N) are provided. These valves are identical to those used for ADS except that they are not equipped for automatic actuation or provided with safety-grade air supplies. They may be individually operated from the control room provided that the normal instrument air supply is available. Normally open reactor head vent line 2"- DBA-108 discharges to main steam line "C", which can then be vented to the suppression pool by opening any of the three SRVs on that line.

b) Normally closed reactor vessel head vent valves (2"-HV-41-F001 and F002) are provided. These motor- operated valves are operable from the control room, provided that the normal power supplies are available. The head vent lines discharge to the drywell equipment drain tank.

c) The main steam-driven HPCI and RCIC system turbines exhaust to the suppression pool. These will function automatically to ensure adequate core cooling, as discussed in Sections 6.3 and 5.4 and, in the process, provide continuous venting of noncondensables to the suppression pool during their operation. The effect of noncondensables in the HPCI and RCIC turbine steam has been analyzed and the results are described in the D.B. Waters (BWROG) letter to D.G. Eisenhut (NRC) dated April 24, 1981.

The effects of inadvertent opening of a SRV or both head vent valves would be the same as a small steam line break. A complete steam line break is part of the plant's design basis, and smaller size breaks have been shown to be of lesser severity. A number of reactor system blowdowns due to SORV have confirmed this. Similarly, a break in any of the systems enumerated above would be less severe than a complete steam line break. Because the results of the complete steam line break analysis have demonstrated compliance with the acceptance criteria of 10CFR50.46, no new analyses are required to show conformance with 10CFR50.46 for vent line failures.

Position (2)

CHAPTER 01 1.13-22 REV. 19, SEPTEMBER 2018

LGS UFSAR In the development of the BWR EPG, this issue was considered. The EPG regarding reactor vessel level control addresses all contingent actions required to maintain RPV level. These actions include venting for all instances when the accumulation of noncondensables may be of concern. Further discussion of this issue is contained in the D.B. Waters (BWROG) letter to D.G.

Eisenhut (NRC) dated April 24, 1981.

Clarification A(1)

The automatic and/or manual operation of the RCS vent paths described above provides effective venting capability to deal with large quantities of noncondensable gas. This venting capability will preclude the possibility of noncondensable gas accumulation interfering with core cooling.

Clarification A(2)

The BWR EPG include provisions for RCS venting for all instances when the accumulation of noncondensables may be of concern. This topic is further discussed in the D.B. Waters (BWROG) letter to D.G. Eisenhut (NRC) dated April 24, 1981. As stated in the response to Position (1), the use of these vent paths or their failure will not result in a violation of the requirements of 10CFR50.46.

An analysis demonstrating that the direct venting of noncondensable gases into the primary containment will not result in violation of combustible gas concentration limits is presented in Section 6.2.5. The gas generation rates assumed in this analysis are in accordance with 10CFR50.44 and Regulatory Guide 1.7.

Clarification A(3)

Because the containments are inerted, and postaccident combustible gas control is maintained by oxygen deficiency, the LGS design is insensitive to the rate or extent of metal-water reaction up to the point where containment pressurization is limiting. This point is substantially beyond the present Regulatory Guide 1.7 design basis as demonstrated by the conservative assessment of this margin provided in Sections 6.2.1.3.4 and 6.2.5.

Further consideration will be given to the impact of combustible gas source terms beyond the present design basis in response to the proposed NRC degraded core rulemakings.

Clarification A(4)

As stated in the response to Position (1), a failure of one of the above vents would result in the equivalent of a small steam line break LOCA.

Clarification A(5)

SRV position indication is provided in the control room by the acoustic monitoring system described in Section 7.6.1.5. Direct position indication is provided in the control room for the HPCI, RCIC, and head vent valves.

Clarification A(6)

CHAPTER 01 1.13-23 REV. 19, SEPTEMBER 2018

LGS UFSAR Each SRV, HPCI, RCIC, and head vent valve may be individually operated from the control room.

Clarification A(7)

All design requirements for the RCPB have been met in the design of appropriate portions of each vent path described above. Because inadvertent operation of a vent path will cause only a minor plant transient as described in the response to Position (1), redundancy is not felt to be necessary. Compliance with 10CFR50.46 is assured for all events as described in the response to Position (1).

Clarification A(8)

Block valves are not provided on the SRV lines in accordance with the clarification. The isolation provisions for the HPCI and RCIC steam lines will withstand a single active failure. Such provisions are not felt to be necessary for the head vent valves for the reasons discussed in the response to clarification A(7).

Clarification A(9)

The point within primary containment to which noncondensables are vented is not of concern because the containment is inerted and effective mixing is assured. Mixing of gases within the primary containment is discussed in Section 6.2.5.2.3.

Clarification A(10)

The equipment, piping, controls, and position indication associated with the ADS SRV and HPCI vent paths described above have been environmentally qualified in accordance with Commission Order and Memorandum CLI-80-21 and seismically analyzed as described in Chapter 3. Portions of the RCIC and the head vent line required for venting are also designed to withstand seismic accelerations. The RCIC valves are environmentally qualified to achieve containment isolation.

Clarification A(11)

The SRVs and the HPCI and RCIC steam valves are tested in accordance with 10CFR50, Appendix J and the intent of subsection IWV of Section XI of the ASME B&PV Code.

Clarification A(12)

This clarification does not apply because no new equipment is being provided to meet the RCS venting requirements.

Clarification B(1)

The information provided above and in the referenced letters demonstrates that the LGS ADS SRVs meet all of the BWROG implementation criteria and NRC requirements for RCS venting.

Clarification B(2)

The following ECCS are available for maintenance of reactor vessel water level at LGS.

CHAPTER 01 1.13-24 REV. 19, SEPTEMBER 2018

LGS UFSAR

a. HPCI

b. RCIC

c. LPCI

d. CS None of the operating modes of the above systems require venting other than from the reactor vessel.

LGS is not equipped with isolation condensers.

• II.B.2 PLANT SHIELDING The information in the position and response is historical and represents the original plant design requirements based on source terms consistent with TID-14844. The application of Alternative Source Terms (AST) per Regulatory Guide 1.183 has resulted in the re-assessment of control room and off-site radiological consequences from design basis accidents. Shielding design remains on the TID-14844 source terms; however, Regulatory Guide 1.183 source terms may be used for re-evaluations.

Position With the assumption of a postaccident release of radioactivity equivalent to that described in Regulatory Guide 1.3, "Assumptions Used for Evaluating the Potential Radiological Consequences of a Loss-of-Coolant Accident for Boiling Water Reactors," and Regulatory Guide 1.4, "Assumptions Used for Evaluating the Potential Radiological Consequences of a Loss-of-Coolant Accident for Pressurized Water Reactors" (i.e., the equivalent of 50% of the core radioiodine, 100% of the core noble gas inventory, and 1% of the core solids are contained in the primary coolant), 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, MCCs, and instrument areas, in which personnel occupancy may be unduly limited or safety equipment may be unduly degraded by the radiation fields during postaccident operations of these systems.

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

Clarification The purpose of this item is to ensure that licensees examine their plants to determine what actions can be taken over the short-term to reduce radiation levels and increase the capability of operators to control and mitigate the consequences of an accident. The actions should be taken pending conclusions resulting in the long-term degraded core rulemaking, which may result in a need to consider additional sources.

CHAPTER 01 1.13-25 REV. 19, SEPTEMBER 2018

LGS UFSAR 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. For purposes of this evaluation, vital areas and equipment are not necessarily the same vital areas or equipment defined in 10CFR73.2 for security purposes. The security center is listed as an area to be considered as potentially vital, since access to this area may be necessary to take action to give access to other areas in the plant.

The control room, TSC, sampling station, and sample analysis area must be included among those areas where access is considered vital after an accident. (Refer to section III.A.1.2 of this report for discussion of the TSC and EOF.) The evaluation to determine the necessary vital areas should also include, but not be limited to, consideration of the post-LOCA hydrogen control system, containment isolation reset control area, manual ECCS alignment area (if any), MCCs, instrument panels, emergency power supplies, security center, and radwaste control panels.

Dose rate determinations need not be for these areas if they are determined not to be vital.

As a minimum, necessary modification must be sufficient to provide for vital system operation and for occupancy of the control room, TSC, sampling station, and sample analysis area.

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

(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, "Control of Combustible Gas Concentrations in Containment Following a Loss-of-Coolant Accident," and SRP 15.6.5 with appropriate decay times based on plant design (i.e., assuming the radioactive decay that occurs before fission products can be transported to various systems).

(a) Liquid-Containing Systems: 100% of the core equilibrium noble gas inventory, 50%

of the core equilibrium halogen inventory, and 1% of all others are assumed to be mixed in the reactor coolant and liquids recirculated by RHR, HPCI, and LPCI, or the equivalent of these systems. In determining the source term for recirculated, depressurized cooling water, assuming that the water contains no noble gases.

(b) Gas-Containing Systems: 100% of the core equilibrium noble gas inventory and 25% of the core equilibrium halogen activity are assumed to be mixed in the containment atmosphere. For vapor-containing lines connected to the primary system (e.g., BWR steam lines), the concentration of radioactivity shall be determined assuming the activity is contained in the vapor space in the primary coolant system.

(2) Systems Containing the Source Systems assumed in your analysis to contain high levels of radioactivity in a postaccident situation should include, but not be limited to, containment, RHR system, safety injection systems, chemical and volume control system, containment spray recirculation system, sample lines, gaseous radwaste systems, and SGTS (or equivalent of these systems). If any of these systems or others that could contain high levels of radioactivity were CHAPTER 01 1.13-26 REV. 19, SEPTEMBER 2018

LGS UFSAR excluded, you should explain why such systems were excluded. Radiation from leakage of systems located outside of containment need not be considered for this analysis.

Leakage measurement and reduction is treated under section III.D.1.1, "Primary Coolant Outside Containment." Liquid waste systems need not be included in this analysis.

Modifications to liquid waste systems will be considered after completion of section III.D.1.4, "Radwaste System Design Features To Aid in Accident Recovery and Decontamination."

(3) Dose Rate Criteria The design dose objectives for personnel in a vital area should be such that the guidelines of GDC 19 will not be exceeded during the course of the accident. GDC 19 requires that adequate radiation protection be provided such that the dose to personnel should not be in excess of 5 rem whole body, or its equivalent to any part of the body for the duration of the accident. When determining the dose to an operator, care must be taken to determine the necessary occupancy times 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 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 objectives dose rates are average rates in the area. Local hot spots may exceed the dose rate guidelines. 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: <15 mrem/hr (averaged over 30 days).

These areas will require full-time occupancy during the course of the accident. The control room and onsite TSC 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) Areas Requiring Infrequent Access: GDC 19. These areas may require access on an irregular basis, 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 of sites where occupancy may be needed often, but not continuously.

(4) Radiation Qualification of Safety-Related Equipment The review of safety-related equipment which may be unduly degraded by radiation during postaccident operation of this equipment relates to equipment inside and outside of the primary containment. Radiation source terms calculated to determine environmental qualification of safety-related equipment consider the following:

(a) LOCA events which completely depressurize the primary system should consider releases of the source term (100% noble gases, 50% iodines, and 1% particulates) to the containment atmosphere.

CHAPTER 01 1.13-27 REV. 19, SEPTEMBER 2018

LGS UFSAR (b) LOCA events in which the primary system may not depressurize should consider the source term (100% noble gases, 50% iodines, and 1% particulates) to remain in the primary coolant. This method is used to determine the qualification doses for equipment in close proximity to recirculating fluid systems inside and outside of containment. Non-LOCA events both inside and outside of containment should use 10% noble gases, 10% iodines, and 0% particulate as a source term. Table 1.13-6 summarizes these considerations.

Response

A. Introduction The design review of plant radiation and shielding was performed as required by NUREG-0737 Item II.B.2 and is described below. The purpose of the review was to identify potential problem areas and equipment which may require the development of special postaccident procedures, installation of additional permanent or temporary shielding, relocation of components or piping, or requalification of components.

Areas that are vital for postaccident occupancy or operation and all safety-related equipment were evaluated to determine if access and performance of required operator activities or equipment functions might be unduly impaired due to the presence of the postulated radiation source in the selected systems. Systems required or postulated to process highly radioactive fluids or gases outside the containment during postaccident conditions were selected for evaluation. Radiation levels in adjacent plant areas due to contained sources in piping and equipment of these systems were estimated. Airborne sources caused by leakage from the primary containment and systems containing postaccident sources were also included in the evaluation for vital areas as described below.

The identification of vital areas and a summary of the methodology used to determine radiation doses for these areas and to equipment are presented below. Doses to personnel in vital areas and access paths are listed in Tables 1.13-1 and 1.13-2, respectively. The identification of essential equipment, doses to equipment used for qualification purposes, and the results of the review of equipment for the postulated radiation sources are provided in the separate EQR. The results of the shielding design review for vital areas are provided below in Section H.

B. Vital Area Identification Areas which may require occupancy to permit an operator to aid in the mitigation of or recovery from an accident are designated as vital areas. A review of LGS was made which determined that the following areas should be designated vital areas.

Continuous Occupancy

1) Main Control Room

2) Technical Support Center

3) Operations Support Center CHAPTER 01 1.13-28 REV. 19, SEPTEMBER 2018

LGS UFSAR

4) Security Center Infrequent Occupancy

1) Counting Room

2) Radiochemistry laboratory

3) Postaccident sampling station

4) North stack instrument room

5) HVAC panels at el 304'

6) Radwaste control room

7) Diesel generator area Potential vital areas that are not listed above were excluded for the following reasons. The post-LOCA hydrogen control (recombiner) system and containment isolation valves are all automatic or remotely controlled by the operator in the main control room and require no local access. There is no manual ECCS alignment area at LGS. Instrument panels and MCCs are not included because the control and alignment of essential systems are accomplished from the main control room and require no local action.

Eleven access paths to vital areas were also identified and included in this review.

C. Selection of Systems for Radiation and Shielding Review A review was made to determine which systems could be required to operate and/or could be expected to contain highly radioactive materials following an accident where substantial core damage has occurred. The results of this review are presented below.

1. CS, HPCI, RCIC, RHR, and Safeguard Piping Fill Systems.

The CS, RHR, HPCI (water side), RCIC (water side), and safeguard piping fill systems would contain suppression pool water being injected to the RCS.

Although the HPCI and RCIC systems could also carry condensate, suppression pool water was assumed for this review for conservatism. The steam sides of the HPCI and RCIC systems would operate on reactor steam.

2. RHR System (Shutdown Cooling Mode)

The RHR system recirculates reactor water when it operates in the shutdown cooling mode. Before operation in this mode can be initiated, the reactor must be depressurized to less than 75 psig. This depressurization is expected to remove substantially all of the noble gases released into the reactor water. Following an accident, the HPCI, RCIC, RHR (LPCI mode), and CS systems would inject water into the RCS. This water from the condensate tank and/or the suppression pool CHAPTER 01 1.13-29 REV. 19, SEPTEMBER 2018

LGS UFSAR would dilute the reactor water prior to the initiation of shutdown cooling with the RHR system. This review assumed that there are no noble gases in the reactor water in the RHR system for the shutdown cooling mode and that the reactor water is diluted by the suppression pool water volume.

3. CRD System The operation of the CRD system was reviewed to determine if the scram discharge headers will contain highly radioactive water following an accident. It was determined that they will not. Prior to a scram, the CRD housings contain condensate water delivered by the CRD pumps. When a scram occurs, some of this condensate water from the CRD is discharged to the scram discharge header.

After the scram, some condensate and reactor water flows to the scram discharge header until it is completely filled. This takes a matter of seconds. Since the vents and drains in the scram discharge header are isolated by the scram, all discharge flow then stops.

Since it is not reasonable to assume that significant core damage occurs in the first few seconds following a scram, the scram discharge header will contain only a mixture of condensate and preaccident reactor water following this postulated accident.

4. RWCU System For an accident with resulting core damage, the RWCU system would be isolated and would contain no highly radioactive materials beyond the second isolation valve. On a BWR this system is not needed for RCS venting. It would not be practical to use it for accident recovery after a major accident. It was therefore assumed that this system would not operate with highly contaminated reactor water.

5. Gaseous Radwaste System For an accident with resulting core damage, it would not be practical to use the gaseous radwaste system for accident recovery. Noble gas isotopes with long lives would cause excessive offsite doses if the gaseous radwaste system was used after a design basis accident. It was therefore assumed that this system would not operate.

6. Postaccident Sampling System Sampling lines used after an accident would contain primary containment gas, secondary containment gas, reactor coolant (pressurized or depressurized) or suppression pool water, depending on the sampling line take-off location.

7. Containment Atmospheric Control System The recombiner system and associated H2-O2 analyzer lines would recirculate primary containment gas after an accident in order to keep hydrogen and oxygen concentrations at acceptable levels.

8. SGTS and RERS CHAPTER 01 1.13-30 REV. 19, SEPTEMBER 2018

LGS UFSAR The SGTS and RERS would collect airborne activity in the secondary containment following an accident. Radioactivity would be collected on the filters and charcoal beds in these systems.

9. Containment The free volume of the primary containment is assumed to initially contain large amounts of postaccident activity. These sources, as well as those assumed for the suppression pool, are described below. Shine through the drywell and wetwell walls would cause a negligible increase to the secondary containment airborne and piping doses, and therefore was not included in this review.

10. MSIV Leakage Alternate Drain Pathway Following the accident, the MSIV Leakage Alternate Drain Pathway will be aligned.

The sources associated with this pathway are discussed below. Shine through the turbine condenser shield wall is considered negligible and therefore, was not included in this review.

D. Source Release Fractions The following release fractions were used as a basis for determining the concentrations for the radiation and shielding review:

Source A: Containment atmosphere: 100% noble gases, 25% halogens Source B: Suppression pool liquid: 50% halogens, 1% solids Source C: Reactor steam: 100% noble gases, 25% halogens Source D: Pressurized reactor coolant: 100% noble gases, 50% halogens, 1% solids These release fractions were applied to the total curies available for the particular chemical species (i.e., noble gas, halogen, or solid) for an equilibrium fission product inventory for a light-water reactor core.

E. Source Term Models The assumptions used for release fractions for the radiation and shielding design review are outlined above. These release fractions are, however, only the first step in modeling the source terms for the activity concentrations in the systems under review. The decay time and dilution volume also affect the rationale for the selection of values for these parameters.

1. Decay Time For conservatism, no decay time credit was taken for the radioactive decay that might occur before fission products would be transported to the various systems.

CHAPTER 01 1.13-31 REV. 19, SEPTEMBER 2018

LGS UFSAR

2. Dilution Volume The volume used for dilution is important, affecting the calculations of dose rate in a linear fashion. The following dilution volumes were used with the release fractions listed above in Section D to arrive at the final source terms for the shielding reviews.

Source A: Drywell and suppression pool free air volumes.

Source B: The volume of the RCS (based on reactor coolant density at the operating temperature and pressure) plus the suppression pool water volume.

Source C: The total reactor system steam volume.

Source D: The volume of the RCS.

3. Contained Sources and Drywell and Secondary Containment Airborne Sources In defining the contained sources, accident operating modes were assumed for each system. In defining the limits of the connected piping subject to contamination listed below, normally shut valves were assumed to remain shut.

• CS system - Source B

• HPCI system Liquid - Source B Steam - Source C (with credit for steam specific activity reduction due to turbine operation).

• RCIC system Liquid - Source B Steam - Source C (with credit for steam specific activity reduction due to turbine operation).

• RHR system - Source B (all modes)

• Postaccident Sampling Lines Gas sample lines - Source A Liquid sample lines - Source D

• Containment Atmospheric Control (Recombiner) System - Source A (Drywell free volume only)

• Drywell - Source A

• MSIV Leakage Alternate Drain Pathway - Source C

• SGTS, RERS, and Secondary Containment Activity CHAPTER 01 1.13-32 REV. 19, SEPTEMBER 2018

LGS UFSAR The following major assumptions were used to calculate the secondary containment airborne radiation doses and the radiation doses for the SGTS filters and the RERS filters.

a. 100% of the noble gases and 25% of the halogens are available for leakage into the secondary containment.

b. The primary to secondary containment leak rate is 0.5% per day.

c. Airborne activity in the secondary containment is confined to spaces below the refueling floor for normal reactor enclosure/refueling area HVAC alignment. Other alignments have been evaluated to provide additional flexibility during refueling operations.

d. The RERS flow rate is two secondary containment air changes per hour.

e. The SGTS flow rate is one air change per day. (For equipment qualification of equipment in the reactor enclosure, the secondary containment airborne doses and RERS filter doses were conservatively based on an SGTS flow rate of one-half air change per day. This results in a longer holdup time and therefore higher doses. For equipment qualification of the SGTS and equipment in the vicinity, an SGTS flow of one air change per day was used.)

f. The RERS charcoal filter is 95% efficient with respect to halogens.

g. The SGTS charcoal filter is 100% efficient with respect to halogens for filter loading.

h. The activity inventory in the core was based on 1000 days burnup and daughter product formation was not considered. These assumptions, which have off-setting effects, were necessitated by limitations in the computer code used to treat the transport of activity from primary to secondary containment.

i. The capacities of the RERS and SGTS filters are sufficient to sustain cleanup for the duration of the accident.

j. Deleted

4. Airborne Sources for Vital Areas All the vital areas and access paths are located in the turbine enclosure, radwaste enclosure, control structure, administration building, diesel generator enclosure, TSC, and yard areas. The transport pathway of the airborne sources in these areas consists of leakage from the primary containment to the reactor enclosure, and discharge to the environment via the RERS and the SGTS. The airborne activity discharged then re-enters the buildings through the ventilation intake systems after dilution within the building wake cavity.

CHAPTER 01 1.13-33 REV. 19, SEPTEMBER 2018

LGS UFSAR The assumptions used in calculating the released airborne activity are the same as those listed in Section 3 above the secondary containment except that an SGTS flow rate of one air change per day and the technical specification minimum filter efficiencies are used to maximize the activity released (i.e. RERS is 95%, and SGTS is 99%, efficient). Also, an assumed 5 gpm systems leakage (at suppression pool activity concentration) to the secondary containment is included in the analysis.

The atmospheric dispersion factors (X/Q), along with their calculation basis, are given in Section 15.10 Section 15.10.2.2 Control Room Dose Module includes the main control room, HVAC panels, and the north stack instrument room. The X/Q's for the other vital areas are analyzed using the modified Halitsky X/Q methodology. This methodology is discussed below.

J. Halitsky's efforts summarized in Reference 1.13-1 present the basic equation as follows:

X / Q K /A u where:

A = cross-sectional area, M2 orthogonal to u

= wind speed, m/s K = isopleth (Concentration coefficient - dimensionless)

It is found in many cases that the above Halitsky equation still provides a reasonable estimate of X/Q. Several correction factors can be applied to this equation to account for situation and plant specific features, such as:

• Stream line flows are used in most wind tunnel tests

• Release points are generally much higher than 10 meters above ground

• Null wind velocity is observed at certain periods of time

• Isothermal temperatures are used in wind tunnel tests

• Buoyancy and jet momentum effects are ignored

• Typical 1 hr field tests account for plume meander effects while 3-5 minute wind tunnel tests do not.

A modified Halitsky X/Q methodology was thus formulated and is presented below.

X/ Q K

• f1

• f2

• f3

• f4

• f5

• f6 (sec/m3) u CHAPTER 01 1.13-34 REV. 19, SEPTEMBER 2018

LGS UFSAR As a test of the modified Halitsky method, calculated values of X/Q, without using factors f4 and f5 due to their uncertainty, were compared to the 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> field test X/Q data from Rancho Seco (Reference 1.13-3). Only one X/Q was found to be higher than the calculated value. This was due to an external wake influence caused by wind channeling between the nearby cooling towers. The wind channeling prevented the normal wake turbulence and variation effects over time, which normally spread the plume over a wide area. In most cases the modified Halitsky X/Q was found to be a conservative estimate of the measured X/Q; in some cases it was significantly higher.

The choice of K factors and the suggested modifying factors f 1, f2, etc, are discussed below.

K factors: The choice of an appropriate K factor from the wind tunnel test data is critical for the X/Q estimate to be valid. Halitsky, in Reference 1.13-1, has several sets of K isopleths for round topped containments (PWRs) and block buildings (BWRs). Multiple building complexes must be simulated by single equivalent structures. The effluent velocity to wind speed ratio of approximately 1 is valid for most power plant systems. Various angles of wind incidence are shown to account for vortexing which could result in worse conditions than a wind normal to the building face. K factors should be estimated for various combinations of wind incidence angle and the appropriate effective building cross-sectional area causing the wake (not just the containment area) to determine the peak value as was done by Walker (Reference 1.13-4).

Wind speed (): Halitsky's K values are based on wind speeds measured at the top of the containment or building. Therefore, the Reference 1.13-2 five percentile wind speed at a 10 meter height should be adjusted to the actual speed at the top of containment or release point. The five percentile wind speed is adjusted using the formulation presented by Wilson (Reference 1.13-5) as follows:

Z uT u ZRe f where:

uT = wind speed at height Z ZRef = 10 meters (five percentile wind speed reference height)

Wind speed change factor (f1), and Wind direction change factor (f2): The factor supplied from Reference 1.13-2, shown below, were used.

Time Periods f1 f2 0 - 8 hrs 1 1 8 - 24 hrs .67 .88 CHAPTER 01 1.13-35 REV. 19, SEPTEMBER 2018

LGS UFSAR 24 - 96 hrs .50 .75 96 - 720 hrs .33 .50 720 hrs & on .25 .33 Wind turbulence effect (f3): Wilson (Reference 1.13-5) and field tests confirm Halitsky's statement that his K isopleths are a factor of 5 to 10 too conservative due to not accounting for random fluctuations of the wind approaching the building. Therefore, a factor of 0.2 was used for f3.

Elevated release effect (f4): Bouwmeester (Reference 1.13-6) indicates that there are up to 10 null wind speed conditions during an hour of data collection. During these periods the effects of jet momentum, plume rise, and buoyancy would result in the radioactive effluent being discharged above the effective wake boundary and thus not entering the wake cavity. A reduction factor of 1 was used.

Time average effects (f5): Wind speed variations and wind direction meandering effects are not modeled in wind tunnel tests to account for this effect. Reference 1.13-6 indicates the use of the following equation:

tp 1/2 Cp Cm tm where:

Cp = prototype concentration Cm = model concentration tp = prototype sampling time tm = model equivalent sampling time Normal wind tunnel data is taken for 3 to 10 minute samples. Thus, for a 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> field test, Cp = .22 to .41 Cm and for an 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> field test, Cp = .08 to .14 Cm. A value of 0.5 was conservatively assumed for f5.

Adjustment to top of stack (f6): To account for wind speed at the top of the stack instead of the Reference 1.13-2 five percentile wind speed at 10 meters height, the factor f6 u / uT was included. The f6 value equals 0.66.

The resultant X/Q (sec/m3) calculated for each of the vital areas except for the main control room, HVAC panels and north stack instrument room (control room X/Q calculated in Section 15.10 was used) are thus shown in Table 1.13-7.

For the MSIV Leakage Alternate Drain Pathway, the F6 factor is 1.0, since the release point is not an elevated release point.

F. Radiation Dose Calculation

1. Primary and Secondary Containment Doses CHAPTER 01 1.13-36 REV. 19, SEPTEMBER 2018

LGS UFSAR The sources described above in Section E were used to estimate doses from the systems included in the radiation and shielding design review. No vital areas are located in the primary or secondary containments, thus the doses described in this section were used for equipment qualification purposes only.

Both gamma and beta post-LOCA doses were calculated for the primary containment. The doses were calculated by assuming that 100% of the core noble gas inventory and 50% of the core halogen inventory are released. These source terms are consistent with those specified in NUREG-0588 and NUREG-0737.

The primary containment airborne dose calculations assumed that 50% of the 50%

(i.e. 25%) halogen release from the core plates out instantaneously, as assumed implicitly in Regulatory Guide 1.3 (Rev 2). The airborne doses were calculated assuming source terms diluted by the primary containment (drywell and wetwell) free volume. These assumptions are consistent with those specified in NUREG-0737.

The beta doses and dose rates for qualification of equipment were calculated assuming an infinite cloud geometry. The beta doses and dose rates for qualification of coatings were calculated assuming a semi-infinite cloud geometry.

For components inside primary containment the total integrated gamma doses were calculated by adding the post-LOCA primary containment gamma cloud dose to the 40 year normal operating dose. Dose distance relationships were not used to reduce post-LOCA doses inside primary containment.

Both gamma and beta post-LOCA doses were also calculated for the secondary containment, based on the source terms described above in Section E. For compartments inside the secondary containment, the post-LOCA gamma radiation levels were conservatively determined by adding the maximum piping contact dose in that compartment to the secondary containment gamma cloud dose. The total integrated gamma dose was then determined by adding the post-LOCA integrated dose to the 40 year normal operating integrated dose. The equipment qualification levels for all safety-related electrical components were compared to the applicable calculated dose. For those components initially listed as inadequately qualified, more detailed calculations were performed, taking into account dose/distance relationships in order to determine more realistic doses. A set of dose/distance curves for each system was developed as part of this effort.

2. Doses in Other Plant Areas for Equipment Qualification Doses for specified areas outside the secondary containment were also calculated as described below, for equipment qualification purposes. For the SGTS equipment compartment, the post-LOCA gamma dose is the contact dose of the SGTS filters. For the remaining areas, the post-LOCA gamma doses were determined by adding the cloud, filter and piping shine doses from adjacent compartments and the control structure cloud dose, as applicable. These post-LOCA doses were added to the normal operating integrated dose to CHAPTER 01 1.13-37 REV. 19, SEPTEMBER 2018

LGS UFSAR determine the total integrated gamma doses. Beta doses outside secondary containment would be negligible for equipment qualification purposes, and therefore they were not calculated.

3. Vital Area and Access Path Doses Calculations were performed to determine airborne and shine doses from the sources described above in Section E to the vital areas and access paths. These doses were used to determine personnel exposures, using occupancy factors as described below in Section G. For radiation doses due to direct shine, credit was taken for attenuation through the walls and due to distance. For airborne doses, both gamma and beta contributions were included. In the access path airborne dose calculations for the yard area routes, the most conservative X/Q bounding that route was used.

G. Personnel Exposure Limits The general basis for personnel radiation exposure guidelines was GDC 19. The following additional radiation limit guidelines were used to evaluate occupancy and accessibility of plant vital areas and access paths.

Radiation Exposure Guidelines Occupancy Dose Objective Continuous Rem for duration Infrequent Rem for all activities Accessway 10 Rem/hr These dose objectives are for personnel access only.

Emergency Response Procedures specify the criteria for radiological habitability monitoring to insure the dose objectives are not exceeded. Based on the results of the habitability monitoring personnel in the affected areas may be instructed to don protective devices or limit stay times to maintain the dose objectives.

The dose rate received by personnel in vital areas of continuous occupancy should be <15 mrem/h (average over 30 days). The doses for these areas were determined using the control room occupancy factors contained in SRP 6.4, as discussed in NUREG-0737, i.e.,

1.0 for 0-1 day; 0.6 for 1-4 days; and 0.4 for over 4 days.

The dose received by personnel in an infrequent occupancy of vital areas and access paths is determined by taking into account the frequency and duration of the activities anticipated for that area, and is consistent with GDC 19 limits. Average area dose rates are used to determine personnel exposure, although local hot spots may exist.

H. Results of Dose Calculations

1. Environmental Qualification of Equipment Normal operating radiation doses and conservative post-LOCA gamma and beta doses are provided in the Equipment Qualification Report and its references for all CHAPTER 01 1.13-38 REV. 19, SEPTEMBER 2018

LGS UFSAR areas containing safety-related equipment. Equipment was reviewed against these doses or, if necessary, against reduced doses calculated as described above in Section F.1. The results of the review of equipment are provided in the EQR.

2. Personnel Access The reactor enclosure and refueling floor will be inaccessible after a design basis LOCA. However, this does not present a problem since they do not contain any vital areas requiring operator access. The non-LOCA reactor enclosure will be accessible.

Doses to the vital areas described above in Section B from the sources described above in Section E are provided in Table 1.13-1. The dose objective of Table 1.13-1 are not used to limit access in the event of an accident.

Dose rates for vital area access paths are provided in Table 1.13-2. These access paths are given in Table 1.13-5.

The airborne and direct shine doses must be added together to show the total dose to personnel in the vital areas and access paths.

Peak shine dose rates are provided in Table 1.13-1 along with the integrated doses. The dose rate at any given time for a vital area can be estimated by multiplying the peak dose rate by an appropriate factor which can be determined by using the curves in Figures 1.13-1 and 1.13-2.

Potential problem areas that were identified in the design review of plant shielding are listed in Table 1.13-3, along with the solutions that will be followed for these areas.

I. Conclusion Areas and safety-related equipment vital for postaccident occupancy or operation were identified, and postaccident doses were calculated in accordance with the requirements of NUREG-0737. Also in Table 1.13-3, potential problem areas were identified, and solutions for these problems were determined. No additional shielding is required as a result of this study.

• II.B.3 POST ACCIDENT SAMPLING The information in the position and response is historical and represents the original plant design requirements based on source terms consistent with TID-14844. The application of Alternative Source Terms (AST) per Regulatory Guide 1.183 has resulted in the re-assessment of control room and off-site radiological consequences from design basis accidents. See UFSAR Chapter 15 for additional information.

Position A design and operational review of the reactor coolant and containment atmosphere sampling line 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 183/4 rem to the whole body or extremities, respectively. Accident conditions should assume a Regulatory Guide 1.3, "Assumptions Used for Evaluating the Potential CHAPTER 01 1.13-39 REV. 19, SEPTEMBER 2018

LGS UFSAR Radiological Consequences of a Loss-of-Coolant Accident for Boiling Water Reactors," or Regulatory Guide 1.4 "Assumptions Used for Evaluating the Potential Radiological Consequences of a Loss-of-Coolant Accident for Pressurized Water Reactor" release of fission products. If the review indicates that personnel could not promptly and safely obtain 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 (in less than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />) certain radionuclides that are indicators of the degree of core damage. Such radionuclides are noble gases which indicate cladding failure and isotopes which indicate fuel melting. The initial reactor coolant spectrum should correspond to a Regulatory Guide 1.3 or Regulatory Guide 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 chemical analyses assuming a highly radioactive initial sample (Regulatory Guide 1.3 or Regulatory Guide 1.4 source term). Both analyses shall be capable of being completed promptly (i.e., the boron sample analysis within an hour and the chloride sample analysis within a shift).

Clarification The following items are clarifications of requirements identified in NUREG-0578, NUREG-0660, or the September 13, 1979, October 30, 1979, September 5, 1980 and October 31, 1980 clarification letters.

(1) The applicant shall have the capability to promptly obtain reactor coolant samples and containment atmosphere samples. The combined time allotted for sampling and analysis should be 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> or less from the time a decision is made to take a sample.

(2) The applicant shall establish an onsite radiological and chemical analysis capability to provide, within the 3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> time frame established above, quantification of the following:

(a) Certain radionuclides in the reactor coolant and containment atmosphere that may be indicators of the degree of core damage (e.g., noble gases, iodines and cesiums, and nonvolatile isotopes);

(b) Hydrogen levels in the containment atmosphere; (c) Dissolved gases (e.g., hydrogen), chloride (time allotted for analysis subject to discussion below), and boron concentration of liquids; and (d) Alternatively, have inline monitoring capabilities to perform all or part of the above analyses.

(3) Reactor coolant and containment atmosphere sampling during postaccident conditions shall not require an isolated auxiliary system (e.g., the letdown system, reactor water cleanup system) to be placed in operation in order to use the sampling system.

CHAPTER 01 1.13-40 REV. 19, SEPTEMBER 2018

LGS UFSAR (4) Pressurized reactor coolant samples are not required if the applicant can quantify the amount of dissolved gases with unpressurized reactor coolant samples. The measurement of either total dissolved gases or hydrogen gas in reactor coolant samples is considered adequate. Measuring the oxygen concentration is recommended, but is not mandatory.

(5) The time for a chloride analysis to be performed is dependent upon two factors: (a) if the plant's coolant water is seawater or brackish water, and (b) if there is only a single barrier between primary containment systems and the cooling water. Under both of the above conditions, the applicant shall provide for a chloride analysis within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of the sample being taken. For all other cases, the applicant shall provide for the analysis to be completed within 4 days. The chloride analysis does not have to be done onsite.

(6) The design basis for plant equipment for reactor coolant and containment atmosphere sampling and analysis must assume that it is possible to obtain and analyze a sample without radiation exposures to any individual exceeding GDC 19 (i.e., 5 rem whole body, 75 rem extremities).

(7) If inline monitoring is used for any sampling and analytical capability specified herein, the applicant shall provide backup sampling through grab samples, and shall demonstrate the capability of analyzing the samples. Established planning for analysis at offsite facilities is acceptable. Equipment provided for backup sampling shall be capable of providing at least one sample per day for 7 days following onset of the accident and at least one sample per week until the accident condition no longer exists.

(8) The applicant's radiological and chemical sample analysis capability shall include provisions to:

(a) Identify and quantify the isotopes of the nuclide categories discussed above to levels corresponding to the source terms given in Regulatory Guides 1.3 or Regulatory Guide 1.4 and Regulatory Guide 1.7, "Control of Combustible Gas Concentration in Containment Following a Loss-of-Coolant Accident." Where necessary and practicable, the ability to dilute samples to provide capability for measurement and reduction of personnel exposure should be provided. Sensitivity of onsite liquid sample analysis capability should be such as to permit measurement of nuclide concentration in the range from approximately 1 Ci/g to 10 Ci/g.

(b) Restrict background levels of radiation in the radiological and chemical analysis facility from sources such that the sample analysis will provide results with an acceptably small error (approximately a factor of 2). This can be accomplished through the use of sufficient shielding around samples and outside sources, and by the use of ventilation system design which will control the presence of airborne radioactivity.

(9) Accuracy, range, and sensitivity shall be adequate to provide pertinent data to the operator in order to describe radiological and chemical status of the RCS.

CHAPTER 01 1.13-41 REV. 19, SEPTEMBER 2018

LGS UFSAR (10) In the design of the postaccident sampling and analysis capability, consideration should be given to the following items:

(a) Provisions for purging sample lines, for reducing plateout in sample lines, for minimizing sample loss or distortion, for preventing blockage of sample lines by loose material in the RCS or containment, for appropriate disposal of the samples, and for flow restrictions to limit reactor coolant loss from a rupture of the sample line. The postaccident reactor coolant and containment atmosphere samples should be representative of the reactor coolant in the core area and the containment atmosphere following a transient or accident. The sample lines should be as short as possible to minimize the volume of fluid to be taken from containment. The residues of sample collection should be returned to containment or to a closed system.

(b) The ventilation exhaust from the sampling station should be filtered with charcoal adsorbers and high efficiency particulate air filters.

(11) If gas chromatography is used for reactor coolant analysis, special provisions (e.g.,

pressure relief and purging) shall be provided to prevent high pressure argon from entering the reactor coolant.

(12) Applicants should provide a description of the implementation of the position and clarification including pipe and instrumentation drawings, together with either (a) a summary description of procedures for sample collection, sample transfer or transport, and sample analysis, or (b) copies of procedures for sample collection, sample transfer or transport, and sample analysis, in accordance with the proposed review schedule but in no case less than 4 months prior to the issuance of an operating license. A postimplementation review will be performed.

Response

Provisions for postaccident reactor coolant and containment atmosphere sampling and analysis are described in Sections 6.2.5, 7.5.1 and 11.5.5.

Limerick license amendment numbers 166/129 approved the elimination of the requirement to have and maintain the Post Accident Sampling System. The following items were committed to as part of the license amendment numbers 166/129.

1. Limerick has developed contingency plans for obtaining and analyzing highly radioactive samples of reactor coolant, suppression pool, and containment atmosphere. The contingency plans are contained in the Limerick chemistry procedures. Establishment of contingency plans is considered a regulatory commitment.

2. The capability for classifying fuel damage events at the Alert level threshold has been established at a level of core damage associated with radioactivity levels of 300 micro-curies/gm dose equivalent iodine in the primary coolant system. This capability is described in Limericks emergency plans and emergency plan implementing procedures. The capability for classifying fuel damage is considered a regulatory commitment.

CHAPTER 01 1.13-42 REV. 19, SEPTEMBER 2018

LGS UFSAR

3. Limerick has established the capability to monitor radioactive iodines that have been released offsite to the environs. This capability is described in the emergency plans and emergency plan implementing procedures. The capability to monitor radioactive iodines is considered a regulatory commitment.

The following information contained in the UFSAR regarding the regulatory requirements for post accident sampling is retained for historical purposes.

A grab sample system designed by GE is provided. Radiological spectrum and chemical analysis capabilities have been established to ensure that the appropriate analyses can be performed in a timely manner.

Shielding requirements and source terms used will be consistent with those used for the Design Review of Plant Shielding, discussed under Item no. II.B.2.

• II.B.4 TRAINING FOR MITIGATING CORE DAMAGE Position We require that the applicant develop a program to ensure that all operating personnel are trained in the use of installed plant systems to control or mitigate an accident in which the core is severely damaged. They must then implement the training program.

Clarification STAs and operating personnel from the plant manager through the operations chain to the licensed operators shall receive this training. The training program shall include the following topics:

(1) Incore Instrumentation (a) Use of fixed or movable incore detectors to determine extent of core damage and geometry changes.

(b) Use of thermocouples in determining peak temperatures; methods for extended range readings; methods for direct readings at terminal junctions.

(2) Excore Nuclear Instrumentation (a) Use of excore nuclear instrumentation for determination of void formation; void location basis for excore nuclear instrumentation response as a function of core temperatures and density changes.

(3) Vital Instrumentation (a) Instrumentation response in an accident environment; failure sequence (time to failure, method of failure); indication reliability (actual versus indicated level).

(b) Alternative methods for measuring flows, pressures, levels, and temperatures.

(i) Determination of pressurizer level if all level transmitters fail.

(ii) Determination of letdown flow with a clogged filter (low flow).

CHAPTER 01 1.13-43 REV. 19, SEPTEMBER 2018

LGS UFSAR (iii) Determination of other RCS parameters if the primary method of measurement has failed.

(4) Primary Chemistry (a) Expected chemistry results with severe core damage; consequences of transferring small quantities of liquid outside containment; importance of using leak-tight systems.

(b) Expected isotopic breakdown for core damage; for clad damage.

(c) Corrosion effects of extended immersion in primary water; time to failure.

(5) Radiation Monitoring (a) Response of process and area monitors to severe damage; behavior of detectors when saturated; method for detecting radiation readings by direct measurement at detector output (overranged detector); expected accuracy of detectors at different locations; use of detectors to determine extent of core damage.

(b) Methods of determining dose rate inside containment from measurements taken outside containment.

(6) Gas Generation (a) Methods of hydrogen generation during an accident; other sources of gas (Xe, Kr);

techniques for venting or disposal of noncondensables.

(b) Hydrogen flammability and explosive limit; sources of oxygen in containment or RCS.

Managers and technicians in the instrumentation and control, health physics, and chemistry departments shall receive training commensurate with their responsibilities.

Response

The lesson plan for the training program for mitigating core damage was developed prior to fuel loading, and training completed prior to full power operation. The course outline is presented below.

Core Cooling Mechanics Alternate methods of core cooling Core spray and core flooding Heat removal paths Boron precipitation Fuel cladding quenching Limiting core conditions Steam and water cooling Potentially Damaging Operating Conditions Vulnerable plant operating conditions CHAPTER 01 1.13-44 REV. 19, SEPTEMBER 2018

LGS UFSAR Core cooling with systems unavailable Gas/Steam Binding Affecting Core Cooling Sources of gas/steam vapor Symptoms/effects of gas/steam binding Recognizing Core Damage Data collection, instrumentation, and systems Fuel/clad behavior Reporting requirements Core Recriticality Reactor Shutdown margin Maintaining subcriticality SLCS Instrumentation response Hydrogen Hazards During Accidents Sources of hydrogen and oxygen Hazardous concentrations and reduction Gas venting Monitoring Critical Parameters During Accident Conditions Parameter identification Instrumentation reliability, accuracy, and failure Radiation Hazards and Radiation Monitor Response Emergency plan implementation High radiation areas Sampling Radiation monitor response and failure Criteria for Operation and Cooling Mode Selection Core cooling procedures Core cooling equipment and methods STAs and operating personnel from the Station Superintendent through the operations chain including the licensed operators receive this training.

Other plant managerial personnel and technicians in the instrumentation and control, health physics, and chemistry groups also receive training commensurate with their responsibilities during accident conditions.

• II.D.1 RELIEF AND SAFETY VALVE TEST REQUIREMENTS Position PWR and BWR licensees and applicants shall conduct testing to qualify the RCS relief and safety valves under expected operating conditions for design basis transients and accidents.

Clarification CHAPTER 01 1.13-45 REV. 19, SEPTEMBER 2018

LGS UFSAR 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 (Rev 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. RCS relief and safety valve qualification shall include qualification of associated control circuitry, piping, and supports, as well as the valves themselves.

(1) Performance Testing of Relief and Safety Valves - The following information must be provided in report form:

(a) Evidence supported by test of safety and relief valve functionability for expected operating and accident (non-ATWS) conditions must be provided to NRC. The testing should demonstrate that the valves will open and reclose under the expected flow conditions.

(b) Since it is not planned to test all valves on all plants, each licensee must submit to NRC a correlation or other evidence to substantiate that the valves tested in the EPRI or other generic test program demonstrate the functionability of as-installed primary relief and safety valves. This correlation must show that the test conditions used are equivalent to expected operating and accident conditions as prescribed in the FSAR. The effect of as-built relief and safety valve discharge piping on valve operability must be accounted for, if it is different from the generic test loop piping.

(c) Test data including criteria for success and failure of valves tested must be provided for NRC staff review and evaluation. These test data should include data that would permit plant specific evaluation of discharge piping and supports that are not directly tested.

(2) Qualification of PWR block valves - Although not specifically listed as a short-term lessons learned requirement in NUREG-0578, qualification of PWR block valves is required by the NRC Task Action Plan NUREG-0660 under task Item II.D.1. It is the understanding of the NRC that testing of several commonly used block valve designs is already included in the generic EPRI PWR safety and relief valve testing program to be completed by July 1, 1981. By means of this letter, NRC is establishing July 1, 1982 as the date for verification of block valve functionability. By July 1, 1982, each PWR licensee, for plants so equipped, should provide evidence supported by test that the block or isolation valves between the pressurizer and each power-operated relief valve can be operated, closed, and opened for all fluid conditions expected under operating and accident conditions.

(3) ATWS Testing - Although ATWS testing need not be completed by July 1, 1981, the test facility should be designed to accommodate ATWS conditions of approximately 3200 to 3500 (Service Level C pressure limit) pounds per square inch and 700°F with sufficient capacity to enable testing of relief and safety valves of the size and type used on operating PWRs.

Response

CHAPTER 01 1.13-46 REV. 19, SEPTEMBER 2018

LGS UFSAR The licensee participated in the BWROG program to test SRVs. The test program has been successfully completed and is described in Reference 1.13-8. The applicability of the test results to the LGS valves is described in appendix A of Reference 1.13-8.

An engineering evaluation was done to identify the expected operating conditions for SRVs during design basis transients and accidents. This evaluation identified one event for which testing was appropriate. This event, the alternate shutdown cooling mode, is an anticipated operating condition that has been considered in the design analysis (Section 5.4.7.5).

The test results documented in the topical report verify the adequacy of the LGS valve operation and integrity under the expected discharge conditions. The loads on the valve and piping induced by the liquid discharge were shown to be lower than the high pressure steam discharge loads for which the system is designed. The test results also provide flow capacity information to show that sufficient shutdown cooling flow is provided through one or two valves, dependent on reactor and system conditions. Clarification Items (2) and (3) are not applicable to BWRs.

• II.D.3 RELIEF AND SAFETY VALVE POSITION INDICATION Position RCS 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.

Clarification (1) The basic requirement is to provide the operator with unambiguous indications of valve position (open or closed) so that appropriate operator actions can be taken.

(2) The valve position should be indicated in the control room. An alarm should be provided in conjunction with this indication.

(3) The valve position indication may be safety-grade. If the position indication is not safety-grade, a reliable single channel direct indication, powered from a vital instrument bus, may be provided if backup methods of determining valve position are available and are discussed in the emergency procedures as an aid to operator diagnosis of an action.

(4) The valve position indication should be seismically qualified consistent with the component or system to which it is attached.

(5) The position indication should be qualified for its appropriate environment (any transient or accident which would cause the relief or safety valve to lift) and in accordance with Commission Order of May 23, 1980 (CLI-80-21).

(6) It is important that the displays and controls added to the control room as a result of this requirement not increase the potential for operator error. A human factor analysis should be performed taking into consideration:

(a) the use of this information by an operator during both normal and abnormal plant conditions, CHAPTER 01 1.13-47 REV. 19, SEPTEMBER 2018

LGS UFSAR (b) integration into emergency procedures, (c) integration into operator training, and (d) other alarms during emergency and need for prioritization of alarms.

Response

An acoustic monitoring system that meets the requirements of NUREG-0737 and Regulatory Guide 1.97 is provided for LGS (Sections 7.6.1.5 and 7.6.2.5). The system is designed to the following general requirements:

a. A reliable, single channel, direct indication system is provided.

b. The individual valve position (OPEN/CLOSED) is displayed in the control room. In conjunction with this indication, a third indication signifies that the individual valve has been open. These lights are located above each SRV control switch. An alarm is provided in the control room to annunciate when any valve is open.

c. The position indications are powered from a highly reliable non-Class 1E power source (Section 8.3.1.1.1).

A diverse means of valve position indication as specified in the EOPs is provided by the redundant safety-grade suppression pool temperature monitoring system.

This is powered from a Class 1E power source.

d) All valve position system components are seismically qualified except for the power supply.

e) All valve position system components located in a potentially harsh environment qualified for a LOCA environment.

f) A human factors analysis was performed to integrate this new information into the control room. The individual OPEN/CLOSED/WAS OPEN indication is located above the SRV control switch.

The WAS OPEN indication was added to aid the operator in determining which valve has opened when a relief valve instantaneously opens on high pressure and closes immediately. This indication is also used to aid the operator in sequencing the relief valves when the reactor is manually depressurized.

Additional human factors aspects were considered during the CRDR required by Item I.D.1.

• II.E.1.1 AUXILIARY FEEDWATER SYSTEM EVALUATION

Response

These requirements are not applicable to BWRs.

CHAPTER 01 1.13-48 REV. 19, SEPTEMBER 2018

LGS UFSAR

• II.E 1.2 AUXILIARY FEEDWATER SYSTEM INITIATION AND FLOW

Response

This requirement is not applicable to BWRs.

• II.E.3.1 EMERGENCY POWER FOR PRESSURIZER HEATERS Position Consistent with satisfying the requirements of GDC 10, 14, 15, 17, and 20 for the event of LOOP, the following positions shall be implemented.

(1) The pressurizer heater power supply design shall provide the capability to supply, from either the offsite 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 conditions.

(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.

Clarification (1) Redundant heater capacity must be provided, and each redundant heater or group of heaters should have access to only one Class 1E division power supply.

(2) The number of heaters required to have access to each emergency power source is that number required to maintain natural circulation in the hot standby condition.

(3) The power sources need not necessarily have the capacity to provide power to the heaters concurrently with the loads required for LOCA.

(4) Any changeover of the heaters from normal offsite power to emergency onsite power is to be accomplished manually in the control room.

(5) In establishing procedure to manually load the pressurizer heaters onto the emergency power sources, careful consideration must be given to:

CHAPTER 01 1.13-49 REV. 19, SEPTEMBER 2018

LGS UFSAR (a) which ESF loads may be appropriately shed for a given situation; (b) reset of the safety injection actuation signal to permit the operation of the heaters; and (c) instrumentation and criteria for operator use to prevent overloading a diesel generator.

(6) The Class 1E interfaces for main power and control power are to be protected by safety-grade circuit breakers (see also Regulatory Guide 1.75).

(7) Being non-Class 1E loads, the pressurizer heaters must be automatically shed from the emergency power sources upon the occurrence of a safety injection actuation signal (see item 5.b, above).

Response

This requirement is applicable to PWRs only. Because the BWR operates in all modes with both liquid and steam in the RPV, saturation conditions are always maintained irrespective of system pressure. There is no need for emergency power to maintain natural circulation or to keep the system pressurized.

The LGS power-operated MSRVs can be actuated using emergency power and have no block valves. They are described in Section 5.2.2. They are nitrogen-operated valves, with their normal gas supply coming from the PCIG compressors, which are described in Section 9.3.1.3. Standby ac power is available to the PCIG compressors following a LOOP.

The MSRVs are provided with gas accumulators described in Section 5.2.2.4, for reliable short-term operation without PCIG system operation. A safety-grade gas bottle supply system, described in Section 9.3.1.3, is available for long-term MSRV operation.

Safety-grade reactor vessel level indication is provided in the control room in accordance with Regulatory Guide 1.97 (Rev 2). Additional information is provided in Section 7.5.

• II.E.4.1 DEDICATED HYDROGEN CONTROL PENETRATIONS Position Plants using external recombiners or purge systems for postaccident combustible gas control of the containment atmosphere should provide containment penetration systems for external recombiner or purge systems that are dedicated to that service only, that meet the redundancy and single failure requirements of GDC 54 and 56 and that are sized to satisfy the flow requirements of the recombiner or purge system.

The procedures for the use of combustible gas control systems following an accident that results in a degraded core and release of radioactivity to the containment must be reviewed and revised, if necessary.

Clarification CHAPTER 01 1.13-50 REV. 19, SEPTEMBER 2018

LGS UFSAR (1) An acceptable alternative to the dedicated penetration is a combined design that is single failure proof for containment isolation purposes and single failure proof for operation of the recombiner or purge system.

(2) The dedicated penetration or the combined single failure proof alternative shall be sized such that the flow requirements for the use of the recombiner or purge system are satisfied. The design shall be based on 10CFR50.44 requirements.

(3) Components furnished to satisfy this requirement shall be safety-grade.

(4) Licensees that rely on purge systems as the primary means for controlling combustible gases following a LOCA should be aware of the positions taken in Reference 1.13-9. This proposed rule, published in the Federal Register on October 2, 1980, would require plants that do not now have recombiners to have the capacity to install external recombiners by January 1, 1982. (Installed internal recombiners are an acceptable alternative to the above.)

(5) Containment atmosphere dilution systems are considered to be purge systems for the purpose of implementing the requirements of this TMI Task Action item.

Response

The containment hydrogen recombiner system, described in Sections 6.2.5 and 9.4.5, is used for postaccident combustible gas control. The recombiners are permanently installed external to the primary containment and are remotely operated from the control room. The design of the containment penetrations associated with the hydrogen recombiner system is single failure proof for containment isolation purposes during system operation and single failure proof for operation of the recombiner system.

LGS complies with each of the points of clarification as described below.

(1) The containment isolation arrangement uses a combined type of design which is single failure proof as permitted by this clarification item. The hydrogen recombiner supply and return lines connect to the high volume purge lines outside the primary containment. Each high volume purge line is provided with redundant, normally closed isolation valves installed in series outboard of the connection point with the hydrogen recombiner lines.

This redundancy ensures that isolation of the high volume purge lines remains single failure proof during operation of the recombiners. Each supply and return line for the hydrogen recombiners is provided with two, normally closed containment isolation valves in series. Because two valves in series are provided, the failure of an isolation valve in the open position would not jeopardize containment integrity. The provision of two redundant hydrogen recombiner packages ensures that the recombination function can be performed in the event of a failure of an isolation valve in the closed position.

(2) The recombiner supply and return lines have been sized such that the flow requirements of the recombiners are satisfied for the full range of possible containment pressures that may exist during the time period when the recombiners are required to operate.

CHAPTER 01 1.13-51 REV. 19, SEPTEMBER 2018

LGS UFSAR (3) As discussed in Section 9.4.5.1.3, the hydrogen recombiner packages, their associated piping, and the containment isolation provisions for the recombiner lines and the containment purge lines are designed as safety-related.

(4) LGS does not rely on a purge system as the primary means for controlling combustible gases following a LOCA.

(5) LGS does not use a containment air dilution system for combustion gas control.

• II.E.4.2 CONTAINMENT ISOLATION DEPENDABILITY Position (1) Containment isolation system designs shall comply with the recommendations of SRP Section 6.2.4 (i.e., that there be diversity in the parameters sensed for the initiation of containment isolation).

(2) All plant personnel shall give careful consideration to the definition of essential and nonessential systems, identify each system determined to be essential, identify each system determined to be nonessential, describe the basis for selection of each essential system, modify their containment isolation designs accordingly, and report the results of the reevaluation to the NRC.

(3) All nonessential 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.

(5) The containment setpoint pressure that initiates containment isolation for nonessential penetrations must be reduced to the minimum compatible with normal operating conditions.

(6) Containment purge valves that do not satisfy the operability criteria set forth in BTP CSB 6-4 or the Staff Interim Position of October 23, 1979 must be sealed closed as defined in SRP 6.2.4., item II.3.f during operational conditions 1, 2, 3, and 4. Furthermore, these valves must be verified to be closed at least every 31 days.

(7) Containment purge and vent isolation valves must close on a high radiation signal.

Clarification (1) The reference to SRP 6.2.4 in position 1 is only to the diversity requirements set forth in that document.

(2) For postaccident situations, each nonessential penetration (except instrument lines) is required to have two isolation barriers in series that meet the requirements of GDC 54, 55, 56, and 57, as clarified by SRP Section 6.2.4. Isolation must be performed automatically CHAPTER 01 1.13-52 REV. 19, SEPTEMBER 2018

LGS UFSAR (i.e., no credit can be given for operator action). Manual valves must be sealed closed, as defined by SRP Section 6.2.4, to qualify as an isolation barrier. Each automatic isolation valve in a nonessential penetration must receive the diverse isolation signals.

(3) Regulatory Guide 1.141 (Rev 2) will contain guidance on the classification of essential versus nonessential systems and is due to be issued by June 1981. Requirements for operating plants to review their list of essential and nonessential systems will be issued in conjunction with this guide including an appropriate time schedule for completion.

(4) Administrative provisions to close all isolation valves manually before resetting the isolation signals is not an acceptable method of meeting position 4.

(5) Ganged reopening of containment isolation valves is not acceptable. Reopening of isolation valves must be performed on a valve-by-valve basis, or on a line-by-line basis, provided that electrical independence and other single failure criteria continue to be satisfied.

(6) The containment pressure history during normal operation should be used as a basis for arriving at an appropriate minimum pressure setpoint for initiating containment isolation.

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

(7) Sealed closed purge isolation valves should be under administrative control to assure that they cannot be inadvertently opened. Administrative control includes mechanical devices to seal or lock the valve closed, or to prevent power from being supplied to the valve operator. Checking the valve position light in the control room is an adequate method for verifying every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> that the purge valves are closed.

Response

A description of compliance with each Position and Clarification is provided below.

Position (1), Clarification (1)

The containment isolation system design has been reviewed for compliance with SRP 6.2.4 regarding diversity in the parameters sensed for the initiation of containment isolation. Section 6.2.4 and Table 6.2-17 identify all containment isolation signals provided. There are eleven valves classified as nonessential that do not receive diverse containment isolation signals.

Two valves on the feedwater lines (HV-109A, HV-109B) are normally closed and will be opened only for startup of the feedwater system before the control rods are withdrawn or when performing hydrostatic testing of the RPVs during unit shutdown.

CHAPTER 01 1.13-53 REV. 19, SEPTEMBER 2018

LGS UFSAR The RCIC vacuum pump discharge line is provided with a stop-check valve (HV-F002) to prevent flow from the containment. A remote manually actuated motor operator ensures the long-term positive closure of the stop-check valve. This arrangement ensures that the essential RCIC pump-turbine will be ready to operate in the event of a reactor vessel isolation occurrence accompanied by loss of feedwater flow.

The recirculation pump cooling water supply and discharge isolation valves (HV-106, HV-107) and the drywell chilled water isolation valves (HV-122, HV-123, HV-128, HV-129) have provisions for remote manual isolation consistent with GDC 57. Closure of these isolation valves is undesirable unless the cooling water lines have failed.

The HPCI and RCIC steam supply line warmup valves (HV-F100, HV-F076, respectively) are provided with appropriate isolation signals to secure the line when system isolation is required. There is no adverse consequence associated with the valve opening or leaking while these systems are in operation.

The main steam drain line isolation valves (HV-F016, F019) are normally closed during power operation. They provide a path from the steam lines to the main condenser for removal of condensation during shutdown and startup periods and during periods of low load. The six automatic isolation signals provided for these valves are the same as those provided for the MSIVs.

The main steam and recirculation loop sample line isolation valves (HV-F084, F085 and HV-F019, F020, respectively) are typically open less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> per year during normal plant operations. The two isolation signals which are provided for these valves ensure their automatic closure before any fuel damage would occur for all anticipated periods of sample line use.

The RWCU supply line isolation valves (HV-F001, F004) are provided with the following signals to initiate automatic valve closure:

a. Reactor low water level

b. Line break in RWCU high flow heat exchanger high temperature compartment high temperature

c. SLCS operation These isolation signals are provided to protect the core in case of a possible break in the RWCU, to protect the ion exchange resin from damage due to high temperature, and to prevent the removal of boron by the ion exchange resin.

The RWCU system is described in Section 5.4.8. Closing times of the RWCU isolation valves have been chosen to prevent the reactor vessel water level from falling below the top of active fuel if a break were to occur in any of the RWCU lines. Diverse isolation signals are supplied to isolate the RWCU in the unlikely event of such a line break. The system is intentionally left in service whenever the above isolation signals are not activated to provide continuous purification of a portion of the recirculation flow.

CHAPTER 01 1.13-54 REV. 19, SEPTEMBER 2018

LGS UFSAR Position (2), Clarification (3)

All systems penetrating containment have been evaluated and identified as either essential or nonessential. Table 6.2-17 provides the results of this evaluation for each line, and Table 6.2-27 provides the basis for the selection of essential/nonessential systems.

Position (3), Clarification (2)

Systems determined to be nonessential are provided with diverse, automatic isolation signals, except as described in the response to Position (1). Manual valves are sealed closed as discussed in Section 6.2.4.3.

Position (4), Clarifications (4), (5)

The control systems for automatic isolation valves are such that resetting the isolation signal will not result in the automatic reopening of these valves. The HPCI and RCIC steam line isolation valves are exceptions as discussed in Section 7.1.2.11. Ganged reopening of containment isolation valves is performed only where the operation of multiple valves is required for system operation. Sample inlet and return valve controls for the drywell radiation monitors and combustible gas analyzers are ganged as described in Sections 6.2.4.3.1.3.2.8 and 6.2.4.3.1.3.2.1. RECW and drywell chilled water valve controls are ganged as described in Sections 6.2.4.3.1.3.2.10 and 6.2.4.3.1.3.2.11.

Position (5), Clarification (6)

The setpoint for the drywell high pressure isolation signal is set at the minimum compatible with normal operation. Section 7.3.1.1.2.4.6 describes the selection of the drywell high pressure setpoint.

Position (6), Clarification (7)

Containment purge valves comply with BTP CSB 6-4 as discussed below and in Sections 9.4.5.1.

Two purge isolation valves have closure times greater than 6 seconds (2"-HV-105 and 2"-HV-111 have closure times of 15 seconds). An analysis of the radiological consequences of a LOCA that occurs during purging was performed to justify the line size and the valve closure time used in the purge system. Using the assumptions of BTP CSB 6-4, the resulting doses were a small fraction of the 10CFR100 limits. For local leak rate tests, the leakage rate of the purge isolation valves, combined with the leakage rate for all other penetrations and valves subject to Type B and C tests will be less than 0.60 La, in accordance with 10CFR50, Appendix J.

Position (7)

The containment purge isolation valves isolate on receipt of any one of the following safety-related isolation signals:

a. high drywell pressure

b. reactor low water level

c. reactor enclosure high radiation CHAPTER 01 1.13-55 REV. 19, SEPTEMBER 2018

LGS UFSAR

d. refueling floor high radiation In addition to the safety-related isolation signals listed above, the containment purge and vent isolation valves (HV-114, 115, 104, 112, 123, 124, 135, 147, 121, 131, 109) will isolate on receipt of a nonsafety-related north stack effluent high radiation signal (Sections 6.2.4.3 and 11.5).

The setpoint of the isolation signal (approximately 4 Ci/cc) has been selected to ensure valve closure before offsite doses exceed EPA Protective Action Guide Level 2 limits (1 rem whole body/5 rem thyroid). Containment purging will not be undertaken during periods of power operation when this monitor is out of service unless a temporary replacement of equivalent sensitivity is used. Provisions are included in the Technical Specifications for periodic instrument calibrations and channel checks.

An analysis has been performed to demonstrate that the offsite doses that might result if a LOCA were to occur during purging operations would be less than both 10CFR100 and EPA Protection Action Guide limits. This analysis used the assumptions of SRP Section 6.2.4 and BTP CSB 6-4 and assumes a pre-existing spike that results in coolant activity levels in excess of Technical Specification limits. The analysis methodology was in accordance with Reference 1.13-10.

• II.F.1 ACCIDENT MONITORING INSTRUMENTATION ATTACHMENT 1, Noble Gas Effluent Monitor 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, "Instrumentation to Follow the Course of an Accident," which has already been initiated, and in other Regulatory Guides, which will be promulgated in the near-term.

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 necessary to cover the ranges of interest.

(1) Noble gas effluent monitors with an upper range capacity of 105 Ci/cc (Xe-133) are considered to be practical and should be installed in all operating plants.

(2) Noble gas effluent monitoring shall be provided for the total range of concentration extending from normal condition (ALARA) concentrations to a maximum of 105 /Ci/cc (Xe-133). Multiple monitors are considered to be necessary to cover the ranges of interest.

The range capacity of individual monitors should overlap by a factor of 10.

It is important that the displays and controls added to the control room as a result of this requirement not increase the potential for operator error. A human factor analysis should be performed taking into consideration:

(1) The use of this information by an operator during both normal and abnormal plant conditions; CHAPTER 01 1.13-56 REV. 19, SEPTEMBER 2018

LGS UFSAR (2) Integration into emergency procedures; (3) Integration into operator training; and (4) Other alarms during emergency and need for prioritization of alarms.

Clarification NUREG-0578, section 2.1.8b provided the basic requirements for this item. Letters dated September 27, 1979 and November 9, 1979, provided clarification and NUREG-0660, Item II.F.1 provided the action plan for additional accident monitoring instrumentation by noble gas effluent radiological monitor requirements. Additional clarification was provided by letters dated September 5, 1980 and October 31, 1980.

By summary clarification, the following guidelines were established:

(1) Applicants shall provide continuous monitoring of high level postaccident releases of radioactive noble gases from the plant. Gaseous effluent monitors shall meet requirements specified in Table 1.13-8. Typical plant effluent pathways to be monitored are also given in the table.

(2) The monitors shall be capable of functioning both during and following an accident.

System designs shall accommodate a design basis release and then be capable of following decreasing concentrations of noble gases.

(3) Offline monitors are not required for the PWR secondary side main steam safety valve and dump valve discharge lines. For this application, externally mounted monitors viewing the main steam line upstream of the valves are acceptable with procedures to correct for the low energy gammas the external monitors would not detect. Isotopic identification is not required.

(4) Instrumentation ranges shall overlap to cover the entire range of effluents from normal (ALARA) through accident conditions. The design description shall include the following:

(a) System description, including:

i. instrumentation to be used, including range or sensitivity, energy dependence or response, calibration frequency and technique, and vendor's model number, if applicable; ii. monitoring locations (or points of sampling), including description of methods used to assure representative measurements and background correction; iii. location of instrument readout(s) and method of recording, including description of the method or procedure for transmitting or disseminating the information or data; iv. assurance of the capability to obtain readings at least every 15 minutes during and following an accident; and CHAPTER 01 1.13-57 REV. 19, SEPTEMBER 2018

LGS UFSAR

v. the source of power to be used.

(b) Description of procedures or calculational methods to be used for converting instrument readings to release rates per unit time, based on exhaust air flow and considering radionuclide spectrum distribution as a function of time after shutdown.

(5) Applicants should have available for review the final design description of the as-built system, including piping and instrument diagrams together with either (a) a description of procedures for system operation and calibration, or (b) copies of procedures for system operation and calibration. Changes to technical specifications will be required. Applicants will submit the above details in accordance with the proposed review schedule, but in no case less than 4 months prior to the issuance of an operating license. A postimplementation review will be performed.

The design description shall include the information provided in Table 1.13-8.

Until final implementation on January 1, 1982, all operating reactors must provide an interim method for quantifying high level releases which meet the requirements of the Table 1.13-8. This method is to serve only as a provisional fix until the accident monitoring instrumentation is installed, calibrated, tested and approved by January 1, 1982. Methods are to be developed to quantify release rates up to 10,000 Ci/sec for noble gases from all potential release points and any other areas that communicate directly with systems which may contain primary coolant or containment gases. Measurements/analysis capabilities of the effluents at the final release point (e.g., stack) should be such that measurements of individual sources which contribute to the common release point may not be necessary. For noble gases, an acceptable method of meeting the intent of this requirement is to modify the existing monitoring system, such that portable high range survey instruments set in shielded collimators "see" small sections of the sampling lines. The applicant shall provide the following information on its method to quantify gaseous releases of radioactivity from the plant during an accident.

(a) An interim system/method description for noble gas effluents, including:

i. Instrumentation to be used including range or sensitivity, energy dependence, and calibration frequency and technique; ii. monitoring/sampling locations, including methods to assure representative measurements and background radiation correction; iii. a description of method to be employed to facilitate access to radiation readings. For January 1, 1981, control room readout is preferred; however, if impractical, in situ readings by an individual with verbal communication with the control room is acceptable based on (iv), below; iv. capability to obtain radiation readings at least every 15 minutes during an accident; and CHAPTER 01 1.13-58 REV. 19, SEPTEMBER 2018

LGS UFSAR

v. source of power to be used. If normal alternating current power is used, an alternate backup power supply should be provided. If direct current power is used, the source should be capable of providing continuous readout for 7 consecutive days.

(b) Procedures for conducting all aspects of the measurement/analysis, including:

i. procedures for minimizing occupational exposures; ii. calculational methods for converting instrument readings to release rates based on exhaust air flow and taking into consideration radionuclide spectrum distribution as function of time after shutdown; iii. procedures for dissemination of information; and iv. procedures for calibration.

Response

All reactor enclosure stack releases following an accident will be through the north stack. The wide range accident monitoring subsystem of the north stack effluent monitoring system provides continuous monitoring of postaccident releases of noble gases in accordance with the requirements of Table 1.13-8. The system is described in Sections 7.6 and 11.5.2.2.1, and its piping and instrumentation diagram is provided in drawing M-26. Control room displays provided for this system meet the requirements of Regulatory Guide 1.97 (Rev 2), and are described in Section 7.5. Table 1.13-9 outlines the requirements for an interim method for quantifying releases to be used by operating reactors and therefore is not applicable to LGS. Human factors aspects of TMI Item II.F.1 are considered part of the CRDR required by Item I.D.1.

ATTACHMENT 2, Sampling and Analysis of Plant Effluents 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, "Instrumentation to Follow the Course of an Accident," which has already been initiated, and in other regulatory guides, which will be promulgated in the near-term.

Because 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.

It is important that the displays and controls added to the control room as a result of this requirement not increase the potential for operator error. A human factor analysis should be performed taking into consideration:

(1) The use of this information by an operator during both normal and abnormal plant conditions; CHAPTER 01 1.13-59 REV. 19, SEPTEMBER 2018

LGS UFSAR (2) Integration into emergency procedures; (3) Integration into operator training; and (4) Other alarms during emergency and need for prioritization of alarms.

Clarification NUREG-0578, section 3.1.8b provided the basic requirements for this item. Letters dated September 27, 1979 and November 9, 1979, provided clarification, however, NUREG-0660 inadvertently omitted this requirement on the action plan for additional accident monitoring instrumentation by sampling and analysis of plant effluents. Additional clarification was provided by letters dated September 5, 1980 and October 31, 1980.

By summary clarification, the following guidelines were established:

(1) Applicants shall provide continuous sampling of plant gaseous effluent for postaccident releases of radioactive iodines and particulates to meet the requirements of Table 1.13-10.

Applicants shall also provide onsite laboratory capabilities to analyze or measure these samples. This requirement should not be construed to prohibit design and development of radioiodine and particulate monitors to provide online sampling and analysis for the accident condition. If gross gamma radiation measurement techniques are used, then provisions shall be made to minimize noble gas interference.

(2) The shielding design basis is given in Table 1.13-10. The sampling system design shall be such that plant personnel could remove samples, replace sampling media and transport the samples to the onsite analysis facility with radiation exposures that are not in excess of GDC 19 of 5 rem whole body exposure and 75 rem to the extremities during the duration of the accident.

(3) The design of the systems for the sampling of particulates and iodines should provide for sample nozzle entry velocities which are approximately isokinetic (same velocity) with expected induct or instack air velocities. For accident conditions, sampling may be complicated by a reduction in stack or vent effluent velocities to below design levels, making it necessary to substantially reduce sampler intake flow rates to achieve the isokinetic condition. Reductions in air flow may well be beyond the capability of available sampler flow controllers to maintain isokinetic conditions; therefore, the staff will accept flow control devices which have the capability of maintaining isokinetic conditions with variations in stack or duct design flow velocity of +/-20%. Further departure from the isokinetic condition need not be considered in design. Corrections for an isokinetic sampling conditions, as provided in Appendix C of ANSI 13.1 (1969) may be considered on an ad hoc basis.

(4) Effluent streams which may contain air with entrained water (e.g., air ejector discharge) shall have provisions to ensure that the adsorber is not degraded while providing a representative sample (e.g., heaters).

(5) License applicants should have available for review the final design description of the as-built system, including P&IDs together with either (a) a description of procedures for system operation and calibration, or (b) copies of procedures for system operation and CHAPTER 01 1.13-60 REV. 19, SEPTEMBER 2018

LGS UFSAR calibration. Changes to technical specifications will be required. Applicants will submit the above details in accordance with proposed review schedule, but in no case less than 4 months prior to the issuance of an operating license. A postimplementation review will be performed.

Response

Sampling of plant gaseous effluents for postaccident releases of iodines and particulates is provided as part of the wide range accident monitoring subsystem of the north stack effluent radiation monitoring system described in Sections 7.6 and 11.5.2.2.1. The design of onsite laboratory facilities for analysis of these samples is described in Chapter 12. The design of the sampling media and sampling considerations are in conformance with Table 1.13-10. Human factors aspects of TMI Item II.F.1 are considered part of the CRDR required by Item I.D.1.

ATTACHMENT 3, Containment High Range Radiation Monitor Position In containment radiation level monitors with a maximum range of 108 rad/hr shall be installed. A minimum of two such monitors that are physically separated shall be provided. Monitors shall be developed and qualified to function in an accident environment.

Clarification (1) Provide two radiation monitor systems in containment which are documented to meet the requirements of Table 1.13-11.

(2) The specification of 108 rad/hr in the above position was based on a calculation of postaccident containment radiation levels that include both particulate (beta) and photon (gamma) radiation. A radiation detector that responds to both beta and gamma radiation cannot be qualified to post-LOCA containment environments but gamma-sensitive instruments can be so qualified. In order to follow the course of an accident, a containment monitor that measures only gamma radiation is adequate. The requirement was revised in the October 30, 1979 letter to provide for a photon-only measurement with an upper range of 107 R/hr.

(3) The monitors shall be located in containment(s) in a manner as to provide a reasonable assessment of area radiation conditions inside containment. The monitors shall be widely separated so as to provide independent measurements and shall "view" a large fraction of the containment volume. Monitors should not be placed in areas which are protected by massive shielding and should be reasonably accessible for replacement, maintenance, or calibration. Placement high in a reactor building dome is not recommended because of potential maintenance difficulties.

(4) For BWR Mark III containments, two such monitoring systems should be inside both the primary containment (drywell) and the secondary containment.

(5) The monitors are required to respond to gamma photons with energies as low as 60 keV and to provide an essentially flat response for gamma energies between 100 keV and 3 MeV, as specified in Table 1.13-11. Monitors that use thick shielding to increase the CHAPTER 01 1.13-61 REV. 19, SEPTEMBER 2018

LGS UFSAR upper range will underestimate postaccident radiation levels in containment by several orders of magnitude because of their insensitivity to low energy gamma and are not acceptable.

Response

The primary containment post-LOCA radiation monitors described in Sections 7.1, 7.6.1, and 11.5.2.3.1 have a maximum range of 1 rad/hr to 108 rad/hr and are physically separated. They are designed and qualified to function in an accident environment.

Section 11.5.2.3.1 describes the degree of conformance with Item II.F.1 Attachment 3 and Table 1.13-11. Additional human factors aspects were considered during CRDR required by Item I.D.1.

ATTACHMENT 4, Containment Pressure Monitor Position A continuous indication of containment pressure shall be provided in the control room of each operating reactor. Measurement and indication capability shall include three times the design pressure of the containment for concrete, four times the design pressure for steel, and -5 psig for all containments.

Clarification (1) Design and qualification criteria are outlined in Appendix B of NUREG-0737.

(2) Measurement and indication capability shall extend to 5 pounds per square inch absolute for subatmospheric containments.

(3) Two or more instruments may be used to meet requirements. However, instruments that need to be switched from one scale to another scale to meet the range requirements are not acceptable.

(4) Continuous display and recording of the containment pressure over the specified range in the control room is required.

(5) The accuracy and response time specifications of the pressure monitor shall be provided and justified to be adequate for their intended function.

Response

The containment pressure instrumentation is described in Section 7.5.1. The design and qualification of the instrumentation meets the guidelines of Regulatory Guide 1.97 (Rev 2) and Appendix B of NUREG-0737. The accuracy and maximum response time for the complete recording and indicating monitors conforms to the requirements of ANS 4.5 (1980) paragraphs 6.3.4 and 6.3.5, which is the referenced document of Regulatory Guide 1.97. Additional human factors aspects were considered during CRDR required by Item I.D.1.

ATTACHMENT 5, Containment Water Level Monitor CHAPTER 01 1.13-62 REV. 19, SEPTEMBER 2018

LGS UFSAR Position 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. A wide range instrument shall also be provided for BWRs and shall cover the range from the bottom of the containment to the elevation equivalent to a 600,000 gallon capacity. For 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.

Clarification (1) The containment wide range water level indication channels shall meet the design and qualification criteria as outlined in Appendices B and C. The narrow range channel shall meet the requirements of Regulatory Guide 1.89.

(2) The measurement capability of 600,000 gallons is based on recent plant designs. For older plants with smaller water capacities, licensees may propose deviations from this requirement based on the available water supply capability at their plant.

(3) Narrow range water level monitors are required for all sizes of sumps but are not required in those plants that do not contain sumps inside the containment.

(4) For BWR pressure-suppression containments, the ECCS suction line inlets may be used as a starting reference point for the narrow range and wide range water level monitors, instead of the bottom of the suppression pool.

(5) The accuracy requirements of the water level monitors shall be provided and justified to be adequate for their intended function.

Response

The existing suppression pool water level instrumentation and the compliance with the above position is described in Section 7.5.1 and meets the requirements of Regulatory Guide 1.97 (Rev 2). Additional human factors aspects were considered during CRDR required by Item I.D.1.

ATTACHMENT 6, Containment Hydrogen Monitor Position 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% hydrogen concentration under both positive and negative ambient pressure.

Clarification (1) Design and qualification criteria are outlined in Appendix B.

(2) The continuous indication of hydrogen concentration is not required during normal operation. If an indication is not available at all times, continuous indication and recording shall be functioning within 30 minutes of the initiation of safety injection.

CHAPTER 01 1.13-63 REV. 19, SEPTEMBER 2018

LGS UFSAR (3) The accuracy and placement of the hydrogen monitors shall be provided and justified to be adequate for their intended function.

Response

The existing hydrogen instrumentation and the compliance with the above position is described in Section 7.5.1 and meets the requirements of Regulatory Guide 1.97 (Rev 2). Additional human factors aspects were considered during CRDR required by Item I.D.1.

For Limerick Generating Station, continuous indication and recording will be functioning within 90 minutes of the initiation of safety injection. The basis for this 60 minute extension, is as follows:

(1) information provided by the monitors is not immediately required following LOCA, as referenced in the Limerick Hydrogen and Oxygen Generation Analysis, Section 6.2.5.3 of the UFSAR. (2) it is appropriate to delay actions necessary to initiate hydrogen and oxygen monitoring until the immediate actions required of the operating crew, to assure that safety systems are functioning properly and critical safety functions are being accomplished, are complete. This is due to the relative safety significance of ensuring critical safety functions are being accomplished in the initial stages of the accident.

The hydrogen monitors have been downgraded to non-safety related as described in NRC Letter to Exelon Nuclear,

Subject:

"Limerick Generating Station, Units 1 and 2 Issuance of Amendment Re: Elimination of Requirements for Hydrogen Recombiners and Hydrogen/Oxygen Monitors (TAC Nos. MC2741 and MC2742)," dated 04/13/05. With the elimination of the Design Basis LOCA hydrogen release, hydrogen monitors are no longer required to mitigate DBAs and, therefore, do not meet the definition of safety related. However, because hydrogen monitors are required to diagnose the course of beyond DBAs, each licensee should verify that it has made a regulatory commitment to maintain a hydrogen monitoring system capable of diagnosing beyond DBAs.

The 0% - 10% hydrogen concentration range is discussed in NUREG-0737, from which the , Position and Clarification was obtained. See NUREG-0737 11.F 1, Attachment 6 for more information.

Measurement capability over the range of 0% to 10% hydrogen concentration is acceptable as the High Hydrogen Alarm setpoint (4%) falls within this range. Figures 6.2-42/43 show that the Drywell Hydrogen concentration will only exceed 10%, at least 8 days after a LOCA, with no hydrogen control. With recombiner operation at 150 scfm or a 150 scfm purge, hydrogen levels in the drywell will not exceed 4%. Figures 6.2-42/43 show that the Suppression Pool Hydrogen concentration will not exceed 4% for at least 30 days after a LOCA.

• II.F.2 INSTRUMENTATION FOR DETECTION OF INADEQUATE CORE COOLING Position Licensees shall provide a description of any additional instrumentation or controls (primary or backup) proposed for the plant to supplement existing instrumentation (including primary coolant saturation monitors) in order to provide an unambiguous, easy-to-interpret indication of ICC. 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.

Clarification CHAPTER 01 1.13-64 REV. 19, SEPTEMBER 2018

LGS UFSAR (1) Design of new instrumentation should provide an unambiguous indication of ICC. This may require new measurements or a synthesis of existing measurements which meet design criteria (item 7).

(2) The evaluation is to include reactor water level indication.

(3) Licensees and applicants are required to provide the necessary design analysis to support the proposed final instrumentation system for ICC and to evaluate the merits of various instruments to monitor water level and to monitor other parameters indicative of core cooling conditions.

(4) The indication of ICC must be unambiguous in that it should have the following properties:

(a) It must indicate the existence of ICC caused by various phenomena (i.e., high void fraction-pumped flow as well as stagnant boil-off); and (b) It must not erroneously indicate ICC because of the presence of an unrelated phenomenon.

(5) The indication must give advanced warning of the approach of ICC.

(6) The indication must cover the full range from normal operation to complete core uncovery.

For example, water level instrumentation may be chosen to provide advanced warning of two-phase level drop to the top of the core and could be supplemented by other indicators such as incore and core-exit thermocouples provided that the indicated temperatures can be correlated to provide indication of the existence of ICC and to infer the extent of core uncovery. Alternatively, full range level instrumentation to the bottom of the core may be employed in conjunction with other diverse indicators such as core-exit thermocouples to preclude misinterpretation due to any inherent deficiencies or inaccuracies in the measurement system selected.

(7) All instrumentation in the final ICC system must be evaluated for conformance to Appendix B of NUREG-0737, "Clarification of TMI Action Plan Requirements," as clarified or modified by the provisions of items 8 and 9 that follow. This is a new requirement.

(8) If a computer is provided to process liquid level signals for display, seismic qualification is not required for the computer and associated hardware beyond the isolator or input buffer at a location accessible for maintenance following an accident. The single failure criteria of item 2, Appendix B, need not apply to the channel beyond the isolation device if it is designed to provide 99% availability with respect to functional capability for liquid level display. The display and associated hardware beyond the isolation device need not be Class 1E, but should be energized from a high reliability power source which is battery backed. The quality assurance provisions cited in Appendix B, item 5, need not apply to this portion of the instrumentation system. This is a new requirement.

(9) Incore thermocouples located at the core-exit or at discrete axial levels of the ICC monitoring system and which are part of the monitoring system should be evaluated for conformity with Attachment 1, "Design and Qualification Criteria for PWR Incore Thermocouples," which is a new requirement.

CHAPTER 01 1.13-65 REV. 19, SEPTEMBER 2018

LGS UFSAR (10) The types and locations of displays and alarms should be determined by performing a human factors analysis taking into consideration:

(a) the use of this information by an operator during both normal and abnormal plant conditions, (b) integration into emergency procedures, (c) integration into operator training, and (d) other alarms during emergency and need for prioritization of alarms.

Response

The design of LGS does not include the use of incore thermocouples for detection of ICC. The licensee endorses the position of the BWROG that there is no technical basis for requiring incore thermocouples in addition to the existing reactor water level instrumentation. A justification of the adequacy of the existing instrumentation to detect conditions of ICC is provided in section 2.3 of NEDO-24708A. Reactor water level instrumentation which is used to monitor ICC is described and reviewed for conformance to Regulatory Guide 1.97 (Rev 2) in Section 7.5.

• II.G.1 POWER SUPPLIES FOR PRESSURIZER RELIEF VALVES, BLOCK VALVES AND LEVEL INDICATORS Position Consistent with satisfying the requirements of GDC 10, 14, 15, 17, and 20 for the event of LOOP, the following positions shall be implemented:

Power supply for pressurizer relief and block valves and pressurizer level indicators -

(1) Motive and control components of the power-operated relief valves shall be capable of being supplied from either the offsite power source or the emergency power source when the offsite power is not available.

(2) Motive and control components associated with the power-operated relief and block valves shall be capable of being supplied from either the offsite power source or the emergency power source when the offsite power is not available.

(3) Motive and control power connections to emergency buses for the power-operated relief valves 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. The 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.

Clarification CHAPTER 01 1.13-66 REV. 19, SEPTEMBER 2018

LGS UFSAR (1) Although the primary concern resulting from lessons learned from the accident at TMI is that the power-operated relief and block valves must be closable, the design should retain, to the extent practical, the capability to also open these valves.

(2) The motive and control power for the block valve should be supplied from an emergency power bus different from the source supplying the power-operated relief valves.

(3) Any changeover of the power-operated relief and block valve motive and control power from the normal offsite power to the emergency onsite power is to be accomplished manually in the control room.

(4) For those designs in which instrument air is needed for operation, the electrical power supply should be required to have the capability to be manually connected to the emergency power sources.

Response

BWRs do not have pressurizer equipment. However, the LGS power-operated MSRVs can be actuated using emergency power and there are no block valves. They are described in Section 5.2.2. The relief valves are nitrogen-operated valves with their normal gas supply coming from the PCIG compressors which are described in Section 9.3.1.3. Standby ac power is available to the PCIG compressors following a LOOP.

The MSRVs are provided with gas accumulators described in Section 5.2.2.4 for reliable short-term operation without PCIG system operation. A safety-grade, gas supply system, described in Section 9.3.1.3, for long-term operation of the MSRVs is used for the ADS.

• II.K.1 IE BULLETINS ON MEASURES TO MITIGATE SMALL BREAK LOCAs AND LOSS OF FEEDWATER ACCIDENTS

• II.K.1.5 ASSURANCE OF PROPER ENGINEERED SAFETY FEATURES FUNCTIONING Position Review all safety-related valve positions, positioning requirements, and positive controls to assure that valves remain positioned (open or closed) in a manner to ensure the proper operation of engineered safety features. Also, review related procedures, such as those for maintenance, testing, plant and system startup, and supervisory periodic (e.g., daily/shift checks) surveillance to ensure that such valves are returned to their correct positions following necessary manipulations and are maintained in their proper positions during operational modes.

Response

Valve positioning requirements, positive controls, and test and maintenance procedures associated with ESF systems are addressed in station administrative procedures which have been generated based on the requirements of IE Bulletin 79-08 Item 6. MOVs in safety-related systems are normally maintained in a configuration such as to require the least number of valve automatic movements upon system actuation. The position of manual ECCS valves considered vital to system operability is controlled by the use and documentation of either locks, checklists, or independent verification. Surveillance test procedures for ESF systems include return-to-normal CHAPTER 01 1.13-67 REV. 19, SEPTEMBER 2018

LGS UFSAR steps or checklists to ensure that the system is returned to service. Prior to fuel load, all ESF systems were confirmed to be aligned in accordance with approved checklists.

• II.K.1.10 REVIEW AND MODIFY, AS REQUIRED, PROCEDURES FOR REMOVING SAFETY-RELATED SYSTEMS FROM SERVICE (AND RESTORING TO SERVICE) TO ASSURE OPERABILITY STATUS IS KNOWN Position Review and modify, as required, procedures for removing safety-related systems from service (and restoring to service) to assure operability status is known.

Response

An administrative procedure addressing the release from service and the return to service of safety-related equipment has been written to address the requirements of IE Bulletin 79-08 Item

8. This procedure, and surveillance test procedures, provide controls to ensure that the status of safety-related system operability is known prior to removal from service and return to service.

• II.K.1.17 TRIP PRESSURIZER LEVEL BISTABLE SO THAT LOW PRESSURE (RATHER THAN PRESSURIZER LOW PRESSURE AND PRESSURIZER LOW LEVEL COINDICENCE) WILL INITIATE SAFETY INJECTION Position Trip pressurizer level bistable so that low pressure (rather than pressurizer low pressure and pressurizer low level coincidence) will initiate safety injection.

Response

This requirement is not applicable to LGS which has GE-designed reactors.

• II.K.1.20 PROVIDE PROCEDURES AND TRAINING TO OPERATORS FOR PROMPT MANUAL REACTOR TRIP FOR LOSS OF FEEDWATER, TURBINE TRIP, MAIN STEAM LINE ISOLATION VALVE CLOSURE, LOSS OF OFFSITE POWER, LOSS OF STEAM GENERATOR LEVEL, AND LOW PRESSURIZER LEVEL Position Provide procedures and training to operators for prompt manual reactor trip for loss of feedwater, turbine trip, MSIV closure, LOOP, loss of steam generator level, and low pressurizer level.

Response

This requirement is not applicable to LGS.

CHAPTER 01 1.13-68 REV. 19, SEPTEMBER 2018

LGS UFSAR

• II.K.1.21 PROVIDE AUTOMATIC SAFETY-GRADE ANTICIPATORY REACTOR TRIP FOR LOSS OF FEEDWATER, TURBINE TRIP, OR SIGNIFICANT DECREASE IN STEAM GENERATOR LEVEL Position Provide automatic safety-grade anticipatory reactor trip for loss of feedwater, turbine trip, or significant decrease in steam generator level.

Response

This requirement is not applicable to LGS.

• II.K.1.22 PROPER FUNCTIONING OF HEAT REMOVAL SYSTEMS Position Describe the actions, both automatic and manual, necessary for proper functioning of the auxiliary heat removal systems (e.g., RCIC) that are used when the main feedwater system is not operable. For any manual action necessary, describe in summary form the procedure by which this action is taken in a timely sense.

Response

See Section 5.4.6 and 5.4.7 for discussion of the automatic and manual actions necessary for the proper functioning of heat removal systems when the main feedwater system is not available.

• II.K.1.23 DESCRIBE ALL USES AND TYPES OF REACTOR VESSEL LEVEL INDICATION FOR BOTH AUTOMATIC AND MANUAL INITIATION OF SAFETY SYSTEMS. DESCRIBE OTHER INSTRUMENTATION THAT MIGHT GIVE THE OPERATOR THE SAME INFORMATION ON PLANT STATUS Position Describe all uses and types of reactor vessel level indication for both automatic and manual initiation of safety systems. Describe other instrumentation that might give the operator the same information on plant status.

Response

Water level indication and measurement is discussed in Sections 7.2, 7.3, 7.5 and 7.7 and shown in drawing M-42 and Figure 7.7-1.

Automatic initiation of safety systems based on reactor water level is accomplished by the following instrument configurations:

1. RPS - Control rod scram is accomplished by four analog loops arranged in a one-out-of-two-twice logic such that the failure of any one switch or of any one set CHAPTER 01 1.13-69 REV. 19, SEPTEMBER 2018

LGS UFSAR of sensing lines will not defeat the safety action. This scheme uses four condensing chamber reference legs and two variable leg sensing lines.

2. PCRVICS - Group I Isolation is accomplished by four analog loops arranged in a one-out-of-two-twice logic such that the failure of any one switch or of any one set of sensing lines will not defeat the safety action. This scheme uses four condensing chamber reference legs and four variable leg sensing lines.

3. ECCS - Initiation of ADS, HPCI, LPCI, Core Spray and diesel generator start is accomplished by four analog loops arranged in a one-out-of-two-twice logic for each of the initiation trip units such that the failure of any one switch or any one set of sensing line will not defeat the safety action. This scheme uses the same sensing lines discussed in the PCRVICS above.

4. ATWS - Initiation of the ATWS functions is accomplished by four analog loops arranged in a one-out-of-two-twice logic such that failure of one switch or set of sensing lines will not defeat the safety action. This scheme uses two condensing chamber reference legs and two variable leg sensing lines. These are different variable lines from those used for the RPS.

Manual initiation of the safety system based on water level may also be accomplished by use of the following indications: (note: all of the reactor water level instruments in this control room have a common reference zero.)

a. Three narrow range level indicators and one wide range indicator are installed on the reactor console. The narrow range instruments also feed a signal to a recorder on the reactor console. This scheme employs three condensing chamber reference legs and two variable leg sensing lines.

The wide range indicator scheme employs a separate condensing chamber reference leg and variable leg sensing line.

b. Two postaccident range level indications, in response to Regulatory Guide 1.97, are installed on the ECCS panel. Each indication consist of overlapping wide range and fuel zone indicators. These schemes used two condensing chamber reference legs and four variable leg sensing lines.

c. This indication is supplemented by the single channel upset range on the reactor panel and shutdown range on the recirculation and RWCU panel.

Both of these schemes use the same condensing chamber reference leg and variable leg sensing line.

d. In addition, all of these indications are fed into the ERFDS (SPDS) computer for display in a temperature compensated reactor water level display.

These instruments are augmented by the other parameters required by Regulatory Guide 1.97 (Rev 2) in the control room. These instruments are addressed in the EOPs to be used by the operator to assess plant conditions. The above water level and supplemental instrumentation was subjected to a human factors review and emergency procedure walk-through prior to fuel load.

• II.K.2 COMMISSION ORDERS ON BABCOCK & WILCOX PLANTS CHAPTER 01 1.13-70 REV. 19, SEPTEMBER 2018

LGS UFSAR

Response

These requirements are not applicable to LGS.

• II.K.3 FINAL RECOMMENDATIONS OF B&O TASK FORCE

• II.K.3.1 INSTALLATION AND TESTING OF AUTOMATIC PORV ISOLATION SYSTEM This section is not applicable to LGS.

• II.K.3.2 REPORT ON OVERALL SAFETY EFFECT OF PORV ISOLATION SYSTEM This section is not applicable to LGS.

• II.K.3.3 FAILURE OF PORV OR SAFETY VALVE TO CLOSE Position Assure that any failure of a power-operated relief valve or safety valve to close will be reported to the NRC promptly. All challenges to the power-operated relief valves or safety valves should be documented in the annual report. This requirement is to be met before fuel load.

Response

Procedures for prompt notification of NRC include any failure of a SRV to close as one of the events requiring the shift manager to expeditiously notify the NRC.

• II.K.3.5 AUTOMATIC TRIP OF REACTOR COOLANT PUMPS DURING LOCA This section is not applicable to LGS.

• II.K.3.7 EVALUATION OF PORV OPENING PROBABILITY DURING OVERPRESSURE TRANSIENT This section is not applicable to LGS.

• II.K.3.9 PROPORTIONAL INTEGRAL DERIVATIVE CONTROLLER MODIFICATION This section is not applicable to LGS.

• II.K.3.10 PROPOSED ANTICIPATORY TRIP MODIFICATION This section is not applicable to LGS.

• II.K.3.11 JUSTIFICATION IN THE USE OF CERTAIN POWER-OPERATED RELIEF VALVES CHAPTER 01 1.13-71 REV. 19, SEPTEMBER 2018

LGS UFSAR

Response

There are no power-operated relief valves at the LGS. The ADS system employs five SRVs to relieve high pressure in the reactor so that flow from LPCI and/or the CS systems enters the reactor in the event that RCIC and/or the HPCI system cannot maintain the reactor water level.

See Sections 5.2.2 and 7.3 for further discussion.

• II.K.3.12 CONFIRM EXISTENCE OF ANTICIPATORY REACTOR TRIP UPON TURBINE TRIP This section is not applicable to the LGS.

• II.K.3.13 SEPARATION OF HPCI AND RCIC SYSTEM INITIATION LEVELS -

ANALYSIS AND IMPLEMENTATION Position Currently, the RCIC system and the HPCI system both initiate on the same low water level signal and both isolate on the same high water level signal. The HPCI system will restart on low water level but the RCIC system will not. The RCIC system is a low flow system when compared to the HPCI system. The initiation levels of the HPCI and RCIC system should be separated so that the RCIC system initiates at a higher water level than the HPCI system. Further, the RCIC system initiation logic should be modified so that the RCIC system will restart on low water level. These changes have the potential to reduce the number of challenges to the HPCI system and could result in less stress on the vessel from cold water injection. Analyses should be performed to evaluate these changes. The analyses should be submitted to the NRC staff and changes should be implemented if justified by the analysis.

Response

Analysis performed by the BWROG (NEDO-24951) has concluded that changing the initiation setpoint of HPCI/RCIC is unwarranted. The report recommended a modification to the RCIC circuitry to permit auto-restart of RCIC on low level after a high level trip. Therefore, modifications to the RCIC trip circuitry have been made to delete the high water level turbine trip and to apply this signal to the auto-close circuit of the steam supply valve. This provides automatic operation of the RCIC system to trip at high water level and auto-restart at low water level.

• II.K.3.15 MODIFY BREAK DETECTION LOGIC TO PREVENT SPURIOUS ISOLATION OF HPCI AND RCIC SYSTEMS Position The HPCI and RCIC systems use differential pressure sensors on elbow taps in the steam lines to their turbine drives to detect and isolate pipe breaks in the systems. The pipe break detection circuitry has resulted in spurious isolation of the HPCI and RCIC systems due to the pressure spike which accompanies startup of the systems. The pipe break detection circuitry should be modified so that pressure spikes resulting from HPCI and RCIC system initiation will not cause inadvertent system isolation.

CHAPTER 01 1.13-72 REV. 19, SEPTEMBER 2018

LGS UFSAR Submit sufficient documentation to support a reasonable assurance finding by the NRC that the modifications, as implemented, have resulted in satisfying the concerns expressed in the previous requirements.

Response

The HPCI/RCIC steam line isolation logic has been modified to address the spurious isolation of these systems due to the pressure spike which accompanies startup of them. The modification consists of adding a time delay to the high flow trip logic of HPCI/RCIC. This prevents the instantaneous pressure spike from causing a system isolation.

• II.K.3.16 REDUCTION OF CHALLENGES AND FAILURES OF RELIEF VALVES -

FEASIBILITY STUDY AND SYSTEM MODIFICATIONS Position The record of relief valve failures to close for all BWRs in the past 3 years of plant operation is approximately 30 in 73 reactor-years (0.41 failures per reactor-year). This has demonstrated that the failure of a relief valve to close would be the most likely cause of a small break LOCA. The high failure rate is the result of a high relief valve challenge rate and a relatively high failure rate per challenge (0.16 failures per challenge). Typically, five valves are challenged in each event.

This results in an equivalent failure rate per challenge of 0.03. The challenge and failure rates can be reduced in the following ways:

(1) Additional anticipatory scram on loss of feedwater (2) Revised relief valve actuation setpoints (3) Increased ECC flow (4) Lower operating pressures (5) Earlier initiation of ECCS (6) Heat removal through emergency condensers (7) Offset valve setpoints to open fewer valves per challenge (8) Installation of additional relief valves with a block or isolation valve feature to eliminate opening of the SRVs, consistent with the ASME Code (9) Increasing the high steam line flow setpoint for MSIV closure (10) Lowering the pressure setpoint for MSIV closure (11) Reducing the testing frequency of the MSIVs (12) More stringent valve leakage criteria (13) Early removal of leaking valves.

CHAPTER 01 1.13-73 REV. 19, SEPTEMBER 2018

LGS UFSAR An investigation of the feasibility and contraindications of reducing challenges to the relief valves by use of the aforementioned methods should be conducted. Other methods should also be included in the feasibility study. Those changes which are shown to reduce relief valve challenges without compromising the performance of the relief valves or other systems should be implemented. Challenges to the relief valves should be reduced substantially (by an order of magnitude).

Clarification Failure of the power-operated relief valve to reclose during the TMI-2 accident resulted in damage to the reactor core. As a consequence, relief valves in all plants, including BWRs, are being examined with a view toward their possible role in a small break LOCA.

The SRVs are dual-function pilot-operated relief valves that use a spring-actuated pilot for the safety function and an external air diaphragm actuated pilot for the relief function.

The operating history of SRVs has been poor. A new design is used in some plants, but the operational history is too brief to evaluate the effectiveness of the new design. Another way of improving the performance of the valves is to reduce the number of challenges to the valves. This may be done by the methods described above or by other means. The feasibility and contraindications of reducing the number of challenges to the valves by the various methods should be studied. Those changes which are shown to decrease the number of challenges without compromising the performance of the valves or other systems should be implemented.

Response

The licensee endorses the BWROG generic response to Item II.K.3.16 for LGS. This response is described in Reference 1.13-11. The following recommendations from this reference have been implemented at LGS in order to reduce the challenges to relief valves by approximately an order of magnitude:

1) Low water level isolation setpoint (see section 6.3.1.1.1 of Reference 1.13-11).

The RPV water level isolation setpoint for MSIV closure is being lowered from Level 2 to Level 1 as part of the ATWS modifications for LGS.

2) Low-low set relief or equivalent manual actions (see section 6.3.1.3.1 of Reference 1.13-11). This recommendation ensures that by following the initial pressurization the pressure will be relieved by one valve alone, and the remaining SRVs will not experience any subsequent actuation. At LGS this will be accomplished manually as directed by the EOPs to manually open SRVs to terminate SRV cycling by reducing RPV pressure to below the lowest SRV safety lift setpoint, in accordance with guidance from the current BWROG EPGs.

3) Reduce MSIV testing frequency (see section 6.3.1.4.4 of Reference 1.13-11). A number of isolation events occur when the MSIV closure tests are being conducted. Reducing the MSIV test frequency would result in a reduction in the number of isolation events. Appropriate reductions have been made to the frequency of testing for the LGS MSIVs.

CHAPTER 01 1.13-74 REV. 19, SEPTEMBER 2018

LGS UFSAR

• II.K.3.17 REPORT ON OUTAGES OF ECCS SYSTEMS LICENSEE REPORT AND PROPOSED TECHNICAL SPECIFICATION CHANGES Position Several components of the ECCS are permitted by technical specifications to have substantial outage times (e.g., 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> for one diesel generator; 14 days for the HPCI system). In addition, there are no cumulative outage time limitations for ECCS. Licensees should submit a report detailing outage dates and lengths of outages for all ECCS for the last 5 years of operation. The report should also include the causes of the outages (i.e., controller failure, spurious isolation).

Clarification The present technical specifications contain limits on allowable outage times for ECCS and components. However, there are no cumulative outage time limitations on these same systems.

It is possible that ECCS equipment could meet present technical specification requirements but have a high unavailability because of frequent outages within the allowable technical specifications.

The licensees should submit a report detailing outage dates and length of outages for all ECCS for the last 5 years of operation, including causes of the outages. This report will provide the staff with a quantification of historical unreliability due to test and maintenance outages, which will be used to determine if a need exists for cumulative outage requirements in the technical specifications.

Based on the above guidance and clarification, a detailed report should be submitted. The report should contain (1) outage dates and duration of outages; (2) causes of the outage; (3) ECCS or components involved in the outage; and (4) corrective action taken. Tests and maintenance outages should be included in the above listings which are to cover the last 5 years of operation.

The licensee should propose changes to improve the availability of ECCS equipment, if needed.

Applicants for an operating license shall establish a plan to meet these requirements.

Response

Starting from the date of commercial operations, for a period of five calendar years for each instance of ECCS unavailability because of component failure, maintenance outage (both forced or planned), or testing, the following information will be collected:

a. Outage date

b. Duration of outage

c. Cause of outage

d. ECCS or component involved

e. Corrective action taken CHAPTER 01 1.13-75 REV. 19, SEPTEMBER 2018

LGS UFSAR The above information will be assembled into a report, which will also include a discussion of any changes, proposed or implemented, deemed appropriate, to improve the availability of the ECCS equipment.

• II.K.3.18 MODIFICATION OF ADS LOGIC - FEASIBILITY FOR INCREASED DIVERSITY FOR SOME EVENT SEQUENCES Position The ADS actuation logic should be modified to eliminate the need for manual actuation to assure adequate core cooling. A feasibility and risk assessment study is required to determine the optimum approach. One possible scheme that should be considered is ADS actuation on low reactor vessel water level provided no HPCI or high pressure core spray flow exists and a low pressure ECCS is running. This logic would complement, not replace, the existing ADS actuation logic.

Response

Option 4, as outlined in the BWROG Generic Response to NUREG-0737 Item II.K.3.18, has been implemented prior to fuel load. Specifically, modifications were made to add a timer that would bypass the high drywell pressure permissive after a sustained low water level and to add an ADS manual inhibit switch.

• II.K.3.21 RESTART OF CORE SPRAY AND LPCI SYSTEMS Position The CS and LPCI system flow may be stopped by the operator. These systems will not restart automatically on loss of water level if an initiation signal is still present. The CS and LPCI system logic should be modified so that these systems will restart if required to assure adequate core cooling. Because this design modification affects several core cooling modes under accident conditions, a preliminary design should be submitted for staff review and approval prior to making the actual modification.

Part a By January 1, 1981, each licensee shall submit proposed design modifications and supporting analysis which will contain sufficient information to support a reasonable assurance finding by the NRC that the above position is met. The documentation should include as a minimum:

(1) A discussion of the design with respect to the above paragraphs of IEEE 279 (1971);

(2) Support information including system design description, logic diagrams, electrical schematics, piping and instrument diagrams, test procedures and technical specifications (3) Sufficient documentation to demonstrate that the system, as modified, would not degrade proper system functions.

Part b CHAPTER 01 1.13-76 REV. 19, SEPTEMBER 2018

LGS UFSAR Licensee to implement modifications at the next refueling outage following staff approval of the design unless this outage is scheduled within 6 months of the approval date. In this event, modifications will be completed during the following refueling outage.

Response

The licensee endorses the BWROG position for Item II.K.3.21 for LGS. This position was forwarded to the NRC by letter from D.B. Walters (BWROG) to D.G. Eisenhut (NRC) dated December 29, 1980. The conclusion of this position is that automation of the restart of LPCI and CS will result in a net decrease in safety because of the complexity of the logic required. Logic modifications to the LPCI and CS systems are therefore not warranted for LGS.

• II.K.3.22 AUTOMATIC SWITCH-OVER OF RCIC SYSTEM SUCTION - VERIFY PROCEDURES AND MODIFY DESIGN Position The RCIC system takes suction from the CST with manual switch-over to the suppression pool when the CST level is low. The switch-over should be made automatically. Until the automatic switch-over is implemented, licensees should verify that clear and cogent procedures exist for the manual switch-over of the RCIC system suction from the CST to the suppression pool.

Response

Modifications have been made to change the RCIC system suction valve logic to automatically switch suction from the CST to the suppression pool on low CST level.

• II.K.3.24 CONFIRM ADEQUACY OF SPACE COOLING FOR HPCI AND RCIC SYSTEMS Position Long-term operation of the RCIC and HPCI systems may require space cooling to maintain the pump-room temperatures within allowable limits. Applications should verify the acceptability of the consequences of a complete loss of ac power. The RCIC and HPCI systems should be designed to withstand a complete loss of offsite ac power to their support systems, including coolers, for at least 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

Response

At LGS, the HPCI and RCIC compartment unit coolers are powered by onsite emergency power and therefore continue to be available during a LOOP. The unit coolers are described in Section 9.4.2.2. The ESW pumps which provide flow to the coolers are also powered from onsite emergency power. Adequate space cooling is therefore assured during a LOOP. There are no other supporting systems that require offsite power such that operation of the HPCI and RCIC systems would be impaired if offsite power should be lost. The current LGS design is therefore acceptable.

• II.K.3.25 EFFECT OF LOSS OF AC POWER ON PUMP SEALS CHAPTER 01 1.13-77 REV. 19, SEPTEMBER 2018

LGS UFSAR Position The licensees should determine, on a plant specific basis, by analysis or experiment, the consequences of a loss of cooling water to the reactor recirculation pump seal coolers. The pump seals should be designed to withstand a complete loss of ac power for at least 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. Adequacy of the seal design should be demonstrated. The results of the evaluation and proposed modifications are due by July 1, 1981. Modifications are to be implemented by January 1, 1982.

Clarification The intent of this position is to prevent excessive loss of RCS inventory following an anticipated operational occurrence. Loss of ac power for this case is construed to be LOOP. If seal failure is the consequence of loss of cooling water to the reactor coolant pump seal coolers for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, due to LOOP, one acceptable solution would be to supply emergency power to the component cooling water pump.

Response

At LGS, two systems are available for cooling the recirculation pump seals: the RECW system and the recirculation pump seal purge system. Recirculation pump vendor test data has shown that if either one of these seal cooling systems is operating, seal temperatures will remain within acceptable limits and excessive seal deterioration is not expected to occur.

The primary cooling for the recirculation pump seals is provided by the RECW system which cools the reactor water that flows to the lower seal cavity. After a LOOP, the RECW pumps will be powered by onsite emergency power and will restart automatically. The service water system, which normally provides cooling water to the RECW heat exchangers, will not be available, but cooling water to the heat exchangers can be provided via manual realignment of the ESW system. If the RECW pumps do not restart or are unavailable for some other reason, the ESW can be manually routed directly to the recirculation pump seals for cooling by way of the RECW piping.

Backup cooling is provided by the recirculation pump seal purge system which injects cool water from the CRD system into the lower seal cavity. The CRD pumps are powered from the emergency diesels and can be manually restarted once onsite power is available. Therefore, the CRD pumps provide an alternate method for seal cooling during a LOOP. However, the ability to use CRD may be limited by the requirement to limit the RPV cooldown rate.

Even in the remote case where neither cooling source is reestablished and gross seal degradation occurs, the GE analysis performed under the direction of the BWROG has shown that the maximum coolant loss would be limited to 70 gpm per pump. This loss is small enough to be compensated for by normal or emergency reactor water level controls. It should be noted that since the initial licensing of the LGS Units, an improved seal design, prone to even less leakage in the event of failure, has been installed on the pumps.

Instrumentation for various parameters, including seal cavity pressure, seal staging and drain flows, drywell equipment drain sump pump flow and drywell floor drain sump pump flow is available to the operator to indicate potential seal failure. In addition, gross seal failure may lead to CHAPTER 01 1.13-78 REV. 19, SEPTEMBER 2018

LGS UFSAR changes in drywell pressure, temperature, or radioactivity, all of which are monitored and recorded in the control room.

It is therefore concluded that a total loss of recirculation pump seal cooling is not a problem at LGS and modifications are not necessary.

• II.K.3.27 PROVIDE COMMON REFERENCE LEVEL FOR VESSEL LEVEL INSTRUMENTATION Position Different reference points of the various reactor vessel water level instruments may cause operator confusion. Therefore, all level instruments should be referenced to the same point.

Either the bottom of the vessel or the top of the active fuel are reasonable reference points.

The applicant is to submit documentation by January 1, 1981 and implement action by April 1, 1981.

Response

All reactor vessel water level instruments are referenced to the bottom of the dryer skirt. Section 7.7.1.1.3.1.3 contains additional design information.

• II.K.3.28 VERIFY QUALIFICATION OF ACCUMULATORS ON ADS VALVES Position Safety analysis reports claim that air or nitrogen accumulators for the ADS valves are provided with sufficient capacity to cycle the valves open five times at design pressures. GE has also stated that the ECCS are designed to withstand a hostile environment and still perform their function for 100 days following an accident. Licensee and applicant should verify that the accumulators on the ADS valves meet these requirements, even considering normal leakage. If this cannot be demonstrated, the licensee and applicant must show that the accumulator design is still acceptable.

Clarification The ADS valves, accumulators, and associated equipment and instrumentation must be capable of performing their functions during and following exposure to hostile environments and taking no credit for nonsafety-related equipment or instrumentation. Additionally, air (or nitrogen) leakage through valves must be accounted for in order to assure that enough inventory of compressed air is available to cycle the ADS valves.

Response

The criteria and design basis for short-term ADS valve operation and accumulator capacity is given in Section 5.2.2.4.1. Long-term vessel depressurization capability for the alternate shutdown cooling flow path described in Section 5.4.7.5 is provided by supplying nitrogen to the ADS valves from the safety-grade system described in Section 9.3.1.3.

CHAPTER 01 1.13-79 REV. 19, SEPTEMBER 2018

LGS UFSAR

• II.K.3.30 REVISED SMALL BREAK LOCA METHODS TO SHOW COMPLIANCE WITH 10CFR50, APPENDIX K Position The analysis methods used by NSSS vendors and/or fuel suppliers for small break LOCA analysis for compliance with 10CFR50, Appendix K, should be revised, documented, and submitted for NRC approval. The revisions should account for comparisons with experimental data, including data from the LOFT Test and Semiscale Test facilities.

Clarification As a result of the accident at TMI-2, the Bulletins and Orders Task Force was formed within the Office of Nuclear Reactor Regulation. This task force was charged, in part, to review the analytical predictions of feedwater transients and small break LOCAs for the purpose of assuring the continued safe operation of all operating reactors, including a determination of acceptability of emergency guidelines for operators.

As a result of the task force reviews, a number of concerns were identified regarding the adequacy of certain features of small break LOCA models, particularly the need to confirm specific model features (e.g., condensation heat transfer rates) against applicable experimental data. These concerns, as they applied to each LWR vendor's models, were documented in the task force reports for each LWR vendor. In addition to the modeling concerns identified, the task force also concluded that, in light of the TMI-2 accident, additional systems verification of the small break LOCA model as required by II.4 of 10CFR50, Appendix K, was needed. This included providing predictions of Semiscale Test S-07-10B, LOFT Test (L3-1), and providing experimental verification of the various modes of single-phase and two-phase natural circulation predicted to occur in each vendor's reactor during small break LOCAs.

Based on the cumulative staff requirements for additional small break LOCA model verification, including both integral system and separate effects verification, the staff considered model revision as the appropriate method for reflecting any potential upgrading of the analysis methods.

The purpose of the verification was to provide the necessary assurance that the small break LOCA models were acceptable to calculate the behavior and consequences of small primary system breaks. The staff believes that this assurance can alternatively be provided, as appropriate, by additional justification of the acceptability of present small break LOCA models with regard to specific staff concerns and recent test data. Such justification could supplement or supersede the need for model revision.

The specific staff concerns regarding small break LOCA models are provided in the analysis sections of the Bulletins and Orders Task Force reports for each LWR vendor. These concerns should be reviewed in total by each holder of an approved ECCS model and addressed in the evaluation as appropriate.

The recent tests include the entire Semiscale small break test series and LOFT Test (L3-1) and (L3-2). The staff believes that the present small break LOCA models can be both qualitatively and quantitatively assessed against these tests.

CHAPTER 01 1.13-80 REV. 19, SEPTEMBER 2018

LGS UFSAR Other separate effects tests (e.g., Oak Ridge National Laboratory core uncovery tests) and future tests, as appropriate, should also be factored into this assessment.

Based on the preceding information, a detailed outline of the proposed program to address this issue should be submitted. In particular, this submittal should identify (1) which areas of the models, if any, the licensee intends to upgrade, (2) which areas the licensee intends to address by further justification of acceptability, (3) test data to be used as part of the overall verification/upgrade effort, and (4) the estimated schedule for performing the necessary work and submitted this information for staff review and approval.

Response

The response to the NRC small break model concerns was provided at a meeting between the NRC and GE on June 18, 1981. Information provided at this meeting showed that, based on the small break test results and sensitivity studies, the existing GE small break LOCA model satisfies the concerns of NUREG-0626 and is in compliance with 10CFR50, Appendix K. Therefore, the GE model is acceptable relative to the concerns of Item II.K.3.30, and no model changes need to be made to satisfy this item.

Documentation of the information provided at the June 18, 1981 meeting was provided via the letter from R.H. Buchholz (GE) to D.G. Eisenhut (NRC), dated June 26, 1981.

• II.K.3.31 PLANT SPECIFIC CALCULATIONS TO SHOW COMPLIANCE WITH 10CFR50.46 Position Plant specific calculations using NRC approved models for small break LOCAs as described in II.K.3 item 30 to show compliance with 10CFR50.46 should be submitted for NRC approval by all licensees.

Calculations to be submitted by January 1, 1983 or 1 year after staff approval of LOCA analysis models, whichever is later (required only if model changes have been made).

Response

The small break LOCA calculations included in the LGS LOCA analysis are given in Section 6.3.3.7 and Table 6.3-5. The references listed in Section 6.3.6 describe the currently approved 10CFR50, Appendix K methodology used to perform these calculations. Compliance with 10CFR50.46 has previously been established for that methodology. As stated in the June 26, 1981, letter from R.H. Buchholz (GE) to D.G. Eisenhut (NRC), no model changes are needed to satisfy NUREG-0737 Item II.K.3.30; therefore, there is no need to revise the calculations given in Section 6.3.3.7.

The response provided above is historical. The original LOCA analysis has been replaced, and the applicable LOCA analysis is discussed in Section 6.3.3.7.

• II.K.3.44 EVALUATION OF ANTICIPATED TRANSIENTS WITH SINGLE FAILURE TO VERIFY NO FUEL FAILURE Position CHAPTER 01 1.13-81 REV. 19, SEPTEMBER 2018

LGS UFSAR For anticipated transients combined with the worst single failure and assuming proper operator actions, licensees should demonstrate that the core remains covered or provide analysis to show that no significant fuel damage results from core uncovery. Transients which result in a SORV should be included in this category. The results of the evaluation are due January 1, 1981.

Response

The BWROG transmitted a generic response to this requirement by letter dated December 29, 1980, from D.B. Waters (BWROG) to D.G. Eisenhut (NRC). This response contains an evaluation that states the worst case transient with single failure combination for BWR/4 plants is the loss of feedwater event with failure of the HPCI system. A SORV was also considered in addition to the HPCI failure. The results of these studies indicate that the core remains covered during the entire course of the transient either due to RCIC system operation or automatic or manual depressurization permitting low pressure inventory makeup. The operator action assumed in the analysis is to manually depressurize the vessel to permit low pressure injection.

By letter dated November 16, 1981, from J.S. Kemper (PECo) to D.G. Eisenhut (NRC), the licensee verified that the assumptions and initial conditions used in the BWROG generic report are representative of LGS.

• II.K.3.45 EVALUATION OF DEPRESSURIZATION WITH OTHER THAN ADS Position Analyses to support depressurization modes other than full actuation of the ADS (e.g., early blowdown with one or two SRVs) should be provided. Slower depressurization would reduce the possibility of exceeding vessel integrity limits by rapid cooldown.

Response

The applicant endorses the BWROG position on Item II.K.3.45 for LGS. This position is presented in Reference 1.13-11 and is summarized below.

An evaluation of alternate modes of depressurization other than full actuation of the ADS was made by the BWROG with regard to the effect of such reduced depressurization rates on core cooling and vessel integrity.

Depressurization by full ADS actuation constitutes a depressurization from about 1050 to 180 psig in approximately 3.3 minutes. The alternate modes of depressurization that were evaluated considered vessel depressurization over the same pressure range (1050 to 180 psig) within two different time periods (6-10 minutes and 15-20 minutes). The cases considered show that no appreciable improvement can be gained by slower depressurization based on core cooling considerations. Because a full ADS blowdown is well within the design basis of the RPV and ADS is properly designed to minimize the threat to core cooling, no change in the depressurization rate is necessary, and no modifications to LGS are needed for this TMI item.

• II.K.3.46 RESPONDING TO MICHELSON CONCERNS Position CHAPTER 01 1.13-82 REV. 19, SEPTEMBER 2018

LGS UFSAR GE should provide a response to the Michelson concerns as they relate to BWRs.

Clarification GE provided a response to the Michelson concerns as they relate to BWRs by letter dated February 21, 1980. Licensees and applicants should assess applicability and adequacy of this response to their plants.

Response

All of the generic February 21, 1980 GE responses are applicable to LGS Units 1 and 2 and are adequate in terms of a response to the Michelson concerns for LGS.

• III.A.1.1 EMERGENCY PREPAREDNESS, SHORT-TERM Position Comply with 10CFR50, Appendix E and Regulatory Guide 1.101, "Emergency Planning for Nuclear Power Plants," and meet the essential elements of NUREG-75/111, "Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants," or have a favorable finding form the Federal Emergency Management Agency.

Response

Emergency planning is discussed in the Emergency Plan.

• III.A.1.2 UPGRADE EMERGENCY SUPPORT FACILITIES Position Establish an interim onsite TSC separate from, but close to, the control room for engineering and management support of reactor operations during an accident. The TSC shall be large enough for the necessary utility personnel and five NRC personnel, have direct display or call-up of plant parameters, and dedicated communication with the control room, emergency operations facility, and the NRC. Provide a description of and a completion schedule for establishing a permanent TSC in accordance with the regulatory position of NUREG-0696, "Functional Criteria for Emergency Response" (February 1981).

Establish an onsite OSC, separate from but with communications to the control room for use by operation support personnel during an accident.

Designate a near-site EOF with communications with the plant to provide evaluation of radiological releases and coordination of all onsite and offsite activities during an accident.

These requirements shall be met before fuel loading.

Response

CHAPTER 01 1.13-83 REV. 19, SEPTEMBER 2018

LGS UFSAR The three types of emergency response facilities required by Section 8 have been provided for LGS.

The TSC meets all of the requirements of section 8.2.1 and is fully functional.

The OSC meets all of the requirements of section 8.3.1 and is fully functional.

The EOF is located approximately 20 miles from the LGS site. The EOF meets all of the technical requirements of section 8.4.1 and is fully functional.

Staffing of the EOF and the TSC is described in the Emergency Plan.

• III.A.2 EMERGENCY PREPAREDNESS Position (1) Each nuclear facility shall upgrade its emergency plan to provide reasonable assurance that adequate protective measures can and will be taken in the event of a radiological emergency. Specific criteria to meet this requirement is delineated in NUREG-0654 (FEMA-REP-1), "Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparation in Support of Nuclear Power Plants."

(2) Perform an emergency response exercise to test the integrated capability and a major portion of the basic elements existing within emergency preparedness plans and organizations.

Response

Emergency planning is discussed in the Emergency Plan.

• III.D.1.1 PRIMARY COOLANT OUTSIDE CONTAINMENT Position Applicants shall implement a program to reduce leakage from systems outside containment that would or could contain highly radioactive fluids during a serious transient or accident to as-low-as-practical levels. This program shall include the following:

(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 intervals not to exceed each refueling cycle.

CHAPTER 01 1.13-84 REV. 19, SEPTEMBER 2018

LGS UFSAR Clarification Applicants shall provide a summary description, together with initial leak test results, of their program to reduce leakage from systems outside containment that would or could contain primary coolant or other highly radioactive fluids or gases during or following a serious transient or accident.

(1) Systems that should be leak tested are as follows (any other plant system which has similar functions or postaccident characteristics even through not specified herein, should be included):

(a) RHR, (b) Containment spray recirculation, (c) HPCI recirculation, (d) Containment and primary coolant sampling, (e) RCIC, (f) Makeup and letdown (pressurized water reactors only), and (g) Waste gas (includes headers and cover gas system outside of containment in addition to decay or storage system).

Include a list of systems containing radioactive materials which are excluded from program and provide justification for exclusion.

(2) Testing of gaseous systems should include helium leak detection or equivalent testing methods.

(3) Should consider program to reduce leakage potential release paths due to design and operator deficiencies as discussed in our letter to all operating nuclear power plants regarding North Anna and related incidents, dated October 17, 1979.

Response

A review of all systems designed to handle highly radioactive fluids during or after a serious transient or accident has been performed to ensure that appropriate design features to minimize leakage have been included. System isolation provisions have been reviewed in conjunction with this effort (Section 6.2.7). A leak reduction program for these systems will be implemented prior to and after fuel load to measure actual leakage rates and to identify sources of leakage in order that total leakage may be reduced to as-low-as-practical levels. The leakage reduction program is described in Section 6.2.8.

The October 17, 1979, NRC generic letter regarding radioactive releases to North Anna Unit 1 expanded the scope of NUREG-0737 Item III.D.1.1 to include a review of potential radioactive release pathways that would not be related to the handling of highly radioactive fluids during or after a core damage event. This generic letter required "...that release paths exemplified by the CHAPTER 01 1.13-85 REV. 19, SEPTEMBER 2018

LGS UFSAR North Anna Unit 1 incident or similar release paths as identified in IE Circular 79-21 should also be considered."

In response to this request per clarification (3), above, a review has been performed to identify all potential unplanned release paths for radioactive fluids during normal plant operation. As shown in Table 1.13-4, it has been determined that existing design provisions and administrative controls are sufficient to prevent unplanned and unmonitored releases of radioactivity.

During review of IE Bulletin 80-10, all interfaces between normally nonradioactive and radioactive systems were identified. It was determined that design provisions adequately maintain boundaries between nonradioactive/radioactive interfaces (Item 4 in Table 1.13-4). These design provisions include one of the following:

a. Two normally closed valves in series

b. One normally closed valve and one check valve in series

c. Two check valves in series

d. Heat exchanger tube sheets (in most cases, the nonradioactive fluid is maintained at a higher pressure than the radioactive fluid).

In the event that leakage or operator errors (e.g., valve mispositionings or incorrect valve lineups) lead to contamination of a nonradioactive system, the process sampling system and numerous grab sampling points for the following normally nonradioactive systems are provided to support a routine contamination monitoring program:

a. Circulating water

b. RECW

c. TECW

d. Clarified water

e. Makeup demineralizers

f. Drywell chilled water

g. Auxiliary steam (both steam and feedwater)

h. Plant waste water effluent

i. Service water

j. Instrument and service air In addition to the above sampling provisions, the following systems are monitored for radioactive contamination by the process radiation monitoring system:

CHAPTER 01 1.13-86 REV. 19, SEPTEMBER 2018

LGS UFSAR

a. ESW and RHR service water

b. RECW

c. Service water In the event that a nonradioactive system is found to be contaminated, corrective action will be taken to prevent leakage to the environment and isolate and repair the source of the contamination.

• III.D.3.3 IMPROVED INPLANT IODINE INSTRUMENTATION UNDER ACCIDENT CONDITIONS Position (1) Each licensee shall provide equipment and associated training and procedures for accurately determining the airborne iodine concentration in areas within the facility where plant personnel may be present during an accident.

(2) Each applicant for a fuel loading license to be issued prior to January 1, 1981 shall provide the equipment, training, and procedure necessary to accurately determine the presence of airborne radioiodine in areas within the plant where plant personnel may be present during an accident.

Clarification Effective monitoring of increasing iodine levels in the buildings under accident conditions must include the use of portable instruments using sample media that will collect iodine selectively over xenon (e.g., silver zeolite) for the following reasons:

(1) The physical size of the auxiliary and/or fuel handling building precludes locating stationary monitoring instrumentation at all areas where airborne iodine concentration data might be required.

(2) Unanticipated isolated "hot spots" may occur in locations where no stationary monitoring instrumentation is located.

(3) Unexpectedly high background radiation levels near stationary monitoring instrumentation after an accident may interfere with filter radiation readings.

(4) The time required to retrieve samples after an accident may result in high personnel exposures if these filters are located in high dose rate areas.

After January 1, 1981, each applicant and licensee shall have the capability to remove the sampling cartridge to a low background, low contamination area for further analysis. Normally, counting rooms in auxiliary buildings will not have sufficiently low backgrounds for such analyses following an accident. In the low background area, the sample should first be purged of any entrapped noble gases using nitrogen gas or clean air free of noble gases. The licensee shall have the capability to measure accurately the iodine concentrations present on these samples under accident conditions. There should be sufficient samplers to sample all vital areas.

CHAPTER 01 1.13-87 REV. 19, SEPTEMBER 2018

LGS UFSAR For applicants with fuel loading dates prior to January 1, 1981, provide by fuel loading (until January 1, 1981) the capability to accurately detect the presence of iodine in the region of interest following an accident. This can be accomplished by using a portable or cart-mounted iodine sampler with attached SCA. The SCA window should be calibrated to the 365 KeV of I-131 using the SCA. This will give an initial conservative estimate of presence of iodine and can be used to determine if respiratory protection is required. Care must be taken to assure that the counting system is not saturated as a result of too much activity collected on the sampling cartridge.

Response

Sampling methods and procedures have been implemented at LGS which will permit the measurement of in-plant iodine concentrations during accident conditions. A description of this method is as follows:

The sampling method uses portable air samplers with a combination particulate filter and iodine sampling cartridge sampling head. The sampling heads use a glass fiber particulate filter and a CESCO style (2.25" diameter by 1.04" thickness) iodine charcoal cartridge. The cartridge normally used is the CESCO-type charcoal cartridge. When long sampling times are required, a larger capacity charcoal cartridge is available. During emergency conditions, with high xenon or krypton concentrations potentially present, either a silver zeolite or a silver impregnated silica gel adsorber canister will be employed.

Iodine activity on the sample cartridge will be determined by gamma isotopic analysis using a computer based multichannel analyzer with high resolution intrinsic germanium detectors located in the LGS counting room. The counting room is located in the radwaste enclosure at el 217'. An assessment of the NUREG-0737 shielding study indicates that the counting room dose rates and airborne radioactivity concentrations are low enough to permit sample analysis during accident conditions.

Isotopic analysis will permit iodine identification in the presence of xenon and krypton. If the analysis of iodine becomes impossible due to interference (high background) from xenon or krypton, then either silver zeolite cartridges will be used or the charcoal cartridge will be purged with clean bottled nitrogen or breathing air to reduce the interference. If the use of silver zeolite does not sufficiently reduce the xenon or krypton interference, the silver zeolite cartridges will also be purged with clean bottled nitrogen or bottled breathing air available onsite.

The Health Physics technical staff have been trained in the implementation of this postaccident procedure.

• III.D.3.4 CONTROL ROOM HABITABILITY Position In accordance with Item III.D.3.4 applicants shall assure that control room operators will be adequately protected against the effects of accidental release of toxic and radioactive gases and that the nuclear power plant can be safely operated or shut down under DBA conditions (GDC 19).

CHAPTER 01 1.13-88 REV. 19, SEPTEMBER 2018

LGS UFSAR Clarification (1) All applicants must make a submittal to us regardless of whether or not they met the criteria of the referenced SRP sections. The new clarification specifies that applicants that meet the criteria of the SRP should provide the basis for their conclusion that Section 6.4 of the SRP requirements are met. Applicants may establish this basis by referencing past submittals to us and/or providing new or additional information to supplement past submittals.

(2) All applicants with control rooms that meet the criteria of the following sections of the SRP:

2.2.1-2.2.2 Identification of Potential Hazards in Site Vicinity, 2.2.3 Evaluation of Potential Accidents, and 6.4 Habitability Systems shall report their findings regarding the specific SRP sections as explained below.

References 1.13-12, 1.13-13 and 1.13-14 should be used for guidance.

Applicants shall submit the results of their findings as well as the basis for those findings by January 1, 1981. In providing the basis for the habitability finding, applicants may reference their past submittals. Applicants should, however, ensure that these submittals reflect the current facility design and that the information requested in Table 1.13-12 is provided.

(3) All applicants with control rooms that do not meet the criteria of the above listed references, SRPs, regulatory guides, and other references shall perform the necessary evaluations and identify appropriate modifications.

Each applicant submittal shall include the results of the analyses of control room concentrations from postulated accidental release of toxic gases and control room operator radiation exposures from airborne radioactive material and direct radiation resulting from DBAs. The toxic gas accident analysis should be performed for all potential hazardous chemical releases occurring either on the site or within 5 miles of the plant boundary. Regulatory Guide 1.78 lists the chemicals most commonly encountered in the evaluation of the control room habitability but is not all inclusive.

The DBA radiation source term should be for the LOCA containment leakage and ESF leakage contribution outside containment as described in Section 15.6.5, appendices A and B. In addition, BWR facility evaluations should add any leakage from the MSIVs (i.e, valve steam leakage, valve seat leakage, MSIV Leakage Alternate Drain Pathway release) to the containment leakage and ESF leakage following a LOCA. This should not be construed as altering our recommendations in section D of Regulatory Guide 1.95 (Rev 2) regarding MSIV-LCS. Other DBAs should be reviewed to determine whether they might constitute a more severe control room hazard than the LOCA.

In addition to the accident analysis results, which should either identify the possible need for control room modifications or provide assurance that the habitability systems will operate under all postulated conditions to permit the control room operators to remain in the control room to take appropriate actions required by GDC 19, the applicant should submit sufficient information needed CHAPTER 01 1.13-89 REV. 19, SEPTEMBER 2018

LGS UFSAR for an independent evaluation of the adequacy of the habitability systems. Table 1.13-12 lists the information that should be provided along with applicant's evaluation.

Response

The information required for control room habitability evaluation as listed in Table 1.13-12 is provided in Sections 1.2, 2.2, 6.4, and 9.4. LGS complies with all criteria of control room habitability in accordance with Item III.D.3.4.

CHAPTER 01 1.13-90 REV. 19, SEPTEMBER 2018

LGS UFSAR 1.

13.3 REFERENCES

1.13-1 D. H. Slade, ed., Meteorology and Atomic Energy, TID 24190 (1968).

1.13-2 K. G. Murphy and K. M. Campe, "Nuclear Power Plant Control Room Ventilation System Design for Meeting General Criterion 19", 13th AEC Air Cleaning Conference.

1.13-3 Start, G. E., J. H. Cate, C. R. Dickson, N. R. Ricks, G. H. Ackerman, and J. F.

Sagendorf, "Rancho Seco Building Wake Effects on Atmospheric Diffusion",

NOAA Technical Memorandum, ERL ARL-69 (1977).

1.13-4 Walker, D. H., R. N. Nassano, M. A. Capo: "Control Room Ventilation Intake Selection for the Floating Nuclear Power Plant", 14th ERDA Air Cleaning Conference (1976).

1.13-5 D. J. Wilson, "Contamination of Air Intakes from Roof Exhaust Vents", ASHRAE Trans. 82, Part 1 pp. 1024-1038 (1976).

1.13-6 R. J. B. Bouwmeester, K. W. Kothari, R. N. Meroney, "An Algorithm to Estimate Field Concentrations Under Nonsteady Meteorological Conditions from Wind Tunnel Experiments", NUREG/CR-1474, NRC, (9/80).

1.13-7.1 General Electric Emergency Response Information System, Licensing Topical Report, 1.13-8 General Electric Licensing Topical Report, NEDE-24988-P and NEDE-24988.

1.13-9 "Proposed Interim Amendments to 10CFR50 Related to Hydrogen Control and Certain Degraded Core Considerations", SECY-80-399, Federal Register, (October 2, 1980).

1.13-10 Letter to D.G. Eisenhut (NRC) from T.J. Dente (BWROG), "Supplement to BWR Owner's Group Evaluation of NUREG-0737, Item II.E.4.2(7)", (June 14, 1982).

1.13-11 "BWR Owners' Group NUREG-0737 Implementation: Analysis and Positions Submitted to the NRC", GE NEDO-24951, (June 1981).

1.13-12 Regulatory Guide 1.78, "Assumptions for Evaluating the Habitability of Regulatory Power Plant Control Room During a Postulated Hazardous Chemical Release".

1.13-13 Regulatory Guide 1.95, "Protection of Nuclear Power Plant Control Room Operators Against an Accident Chlorine Release".

1.13-14 K.G. Murphy and K.M. Campe, "Nuclear Power Plant Control Room Ventilation System Design for Meeting General Design Criterion 19," 13th AEC Air Cleaning Conference, (August 1974).

CHAPTER 01 1.13-91 REV. 19, SEPTEMBER 2018

LGS UFSAR Table 1.13-1 VITAL AREA RADIATION DOSES(8)

PIPING AND CLOUD SHINE AIRBORNE SHINE PLUS DOSE AIRBORNE DOSE PEAK DOSE TOTAL WHOLE BODY WHOLE BODY OBJECTIVE ORGAN DOSES OBJECTIVES VITAL AREAS(1) MAJOR SOURCE RATE (Rem/hr) DOSE (Rem) DOSE (Rem) (2) DOSE (Rem) (Rem) (Rem) (Rem)

Continuous Occupancy Main Control Room (8) ECCS/RHR pipe 1.1 4.2 4.3x10-1 4.6 5.0 Thyroid: 6.29x10°(4) 30 (SRP 6.4 Occupancy)

Skin : 7.6 30 Technical Support Center RHR Pipe/Reactor 2.7x10 -3 1.5x10 -2 1.47x10 -1 1.62x10 -1

5.0 Thyroid

2.3x10 -1 30 (SRP 6.4 Occupancy) Enclosure Cloud Skin : 3.6x10-1 30 Operational Support Center RHR Pipe/Reactor 6.6x10-3 6.7x10-2 1.97 2.0 5.0 Thyroid: <30(5) 30 (SRP 6.4 Occupancy) Enclosure Cloud Skin : 1.6 30 Security Center RHR Pipe/Reactor 1.7x10-1 7.3x10-1 1.3 2.0 5.0 Thyroid: <30(5) 30 (SRP 6.4 Occupancy) Enclosure Cloud Skin : 1.03 30 Infrequent Occupancy Counting Room(6) ECCS/RHR Pipe 5.5x10-4 1.3x10-3 1.2x10-1 1.3x10-1 5.0 Thyroid: 21.5 30 Skin : 1.2 30 Radiochemical Laboratory(6) ECCS/RHR Pipe 9.3x10-3 3.0x10-2 1.2x10-1 1.6x10-1 5.0 Thyroid: 21.6 30 Skin : 1.2 30 Postaccident Sampling H2 Recombiner/ 6.6x10-1(3) 3.4x10-1(3) 2.5x10-3 3.4x10-1(3) 5.0 Thyroid: 2.9x10-3 30 Station (31 min Occupancy ECCS Pipe at time = 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />) Skin : 3.7x10-2 30 Post-LOCA North Stack Instrument North Stack 3.9 3.9 8.7x10-1 4.8 (7) 5.0 Thyroid: 1.8x10-2 30 Room (1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Occupancy)

Skin : 4.2x10-1 30 HVAC Panels ECCS/RHR Pipe 3.8x10-1 3.8x10-1 8.8x10-2 4.7x10-1 5.0 Thyroid: 3.2x10-2 30 (1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Occupancy)

Skin : 4.1x10-1 30 Radwaste Control Room ECCS/RHR Pipe 2.1x10-2 6.7x10-2 2.36x10-1 3.0x10-1 5.0 Thyroid: <30(5) 30 (6)

Skin : 1.2 30 Diesel Generator Area ECCS/RHR Pipe/Reactor 8.1x10-3 8.1x10-3 3.0x10-2 4.4x10-2 5.0 Thyroid: 5.0x10-2 30 (1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Occupancy) Enclosure Cloud Skin : 2.0x10-2 30 (1)

Occupancy factors used to calculate doses are listed in parentheses for each vital area. SRP 6.4 occupancy factors are for 30 days. For vital areas with 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> occupancy, the doses reflect 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> occupancy at the maximum postaccident dose rate unless otherwise specified.

(2)

Airborne whole body doses are specified for the listed vital areas.

(3)

Doses do not include shine from sample source. See Table 11.5-3 .

(4)

MCR Dose was calculated assuming zero inleakage through the MCR Doors. This requires installation of a MCR door seal described in section 6.4 and 15.10.

(5)

The calculated Airborne Organ dose was approximately 35 rem over 30 days. Emergency Response Procedures specify the criteria for radiological habitability monitoring to insure the dose objectives are not exceeded. Based on the results of the habitability monitoring personnel in the affected areas maybe instructed to don protective devices or limi t stay times to maintain the dose objectives.

(6)

The stay times assumed for these areas are half of the stay times specified in SRP 6.4.

(7)

Doses to personnel traversing the Refuel Floor on route to and then occupying the North Stack Instrument Room would be 2.86 Rem if a LOCA were to occur while the upper layer of the reactor well shield plugs were removed in OPCON 1, 2 and 3. Doses to personnel traversing the turbine enclosure roof to the reactor enclosure roof on route to and from, and while occupying the North Stack Instrument Room would be 2.9 Rem, if a Unit 2 LOCA were to occur, and 3.957 Rem, if a Unit 1 LOCA were to occur, when both layer of the shield plugs are removed in OPCON 3. These lower doses are a result of a more location specific analysis of the travel routes. The 4.8 Rem value remains the bounding value in all other conditions and areas until specific analysis are performed.

(8)

The information in this Table is historical and represents original plant design requirements. The application of Alternative Source Terms per Regulatory Guide 1.183, resulted in the recalculation of control room dose. See Chapter 15 for details.

CHAPTER 01 1.13-92 REV. 14, SEPTEMBER 2008

LGS UFSAR Table 1.13-2 RADIATION DOSES FOR VITAL AREA ACCESS PATHS(1) (2) (5) (7)

Peak Peak Peak Peak Piping Airborne Sum of Shine Airborne Airborne Access Transit and Cloud Shine Plus Whole Path (2) Time (min.) Whole Body Thyroid Skin Beta Dose (Rem) Dose (Rem) Body Dose (Rem) Dose (Rem) Dose (Rem)

A 4 6x10-3 1x10-3 7x10-3 1.4x10-2 9x10-4 A' (Alternate) 3 2x10-3 1x10-3 3x10-3 1x10-2 7x10-4 B 2 3x10-3 5x10-4 4x10-3 7x10-3 5x10-4 C 0.5 3x10-3 8x10-4 4x10-3 1x10-2 7x10-4 C' (Alternate) 3 3x10-2 5x10-3 4x10-2 7x10-2 5x10-3 D 2 2x10-1(3) 5x10-4 2x10-1(3) 7x10-3 5x10-4 D' (Alternate) 4 5x10-3(3) 1x10-3 6x10-3(3) 1.4x10-2 1x10-3 E (4) (4) (4) (4) (4) (4)

E' (Alternate) 15 3x10-3 2.4x10-2 3x10-2 3.3x10-1 2x10-2 E(Alternate)

Unit 1 LOCA 15 7.8x10-1(6) 2.4x10-2 8.0x10-1 3.3x10-1 2x10-2 Unit 2 LOCA 15 2.5x10-1 2.4x10-2 2.7x10-1 3.3x10-1 2x10-2 F 2 1x10-3 4x10-3 5x10-3 5.1x10-2 4x10-3 F' (Alternate) 0.5 6x10-3 1x10-3 7x10-3 1.3x10-2 9x10-4 (1) Dose rates for all parts of access paths are <10 Rem/hour except as noted in Table 1.13-3.

(2) Access paths are described in Table 1.13-5.

(3) Dose rates will increase slightly at time t = 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> when the H2 recombiner starts operating, but doses will still be below the peak values shown in this table.

(4) Path is not accessible. See Table 1.13-3.

(5) The above doses exclude the impact of the MSIV leakage alternate drain pathway. This source is significant only for paths through the Turbine Enclosure. SCBAs may be required for thyroid protection.

(6) This is an increase of 1.057 Rem (total) above the unit 2 LOCA dose due to the shine from the unit 1 drywell head through the reactor building north wall. These doses are based on the lower layer of reactor well shield plugs being removed on one unit in OPCON 3, and both layers of the other unit being installed or have the unit in OPCON 4 or 5.

(7) The information in this Table is historical and represents original plant design requirements based on source terms consistent with TID-14844. The application of Alternative Source Terms per Regulatory Guide 1.183 may be used to determine vital area radiation doses for subsequent evaluations.

CHAPTER 01 1.13-93 REV. 14, SEPTEMBER 2008

LGS UFSAR Table 1.13-3 SOLUTIONS TO POTENTIAL VITAL AREA ACCESS PROBLEMS(1)(2)

Potential Description Solution Remarks Problem Area Access Path D The northeast area of the It is preferable to use From Figure 1.13-1, it can be seen that radwaste enclosure at access path D' instead the dose rate near the airlock will fall el 217' near the of access path D until below 10 Rem/hr about 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> after a DBA.

airlock for the reactor the dose rate falls Access path D would be used for access to enclosure will have below 10 Rem/hr in the the radwaste control room, radiochemical radiation levels of vicinity of the airlock. laboratory, or counting area from the 20 R/hr at time control room.If access is required before t = 0 hours0 days <br />0 hours <br />0 weeks <br />0 months <br />. the dose rate for access path D has fallen to acceptable levels, the operators can use access path D' to enter the radwaste control room. However, it is not necessary to prohibit access in the vicinity of the airlock because the radiation levels decay rapidly and are in a localized area with short transit.

Access Path E The stairway next to the Access path E' should The first sample from the north stack reactor enclosure exhaust be used until the dose instrument room must be taken within stack will have peak rate falls below 10 R/hr 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Due to the long time required radiation levels of in the stairway. If both to pass through the stairway in access 28 R/hr at time the upper and lower path E and the extent of the radiation t = 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. reactor well shield plugs field, access to the north stack instrument are removed, then use room using this stairway is not possible path E until after time t = 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

Access Path E If both reactor well shield Access path E should be Access to the refueling floor will not drop plugs on either Unit are used until the dose rate below 10 R/hr until after time t = 9 hrs.

removed, the refueling floor falls below 10 R/hr on the travel path will have refueling floor.

radiation levels of 100 R/hr at t = 0 hours0 days <br />0 hours <br />0 weeks <br />0 months <br />.

(1) Access paths are described in Table 1.13-5.

(2) This information had not been updated to reflect the current licensing design basis. The information should be used for historical reference only and not to support the design basis of the plant.

CHAPTER 01 1.13-94 REV. 13, SEPTEMBER 20068

LGS UFSAR Table 1.13-4 POTENTIAL UNPLANNED RELEASE PATHS Administrative System(s) Boundary Potential Release Path Control Air Removal and HV-07-142, -143, -144, Airborne contamination release Operating procedure Sealing Steam -145, (Normally Closed) (local) if valves left open requires valve closure after equalizing pressures Liquid Radwaste 62-0021 (Normally Closed) Airborne contamination release Operating procedure Equipment Drain (local) if valve is left open requires valve closure Processing Control Rod Drive XV-47-1F180 Scram discharge header Operating procedure XV-47-1F181 volume release to DRW or provides precaution notice XV-47-1F010 equipment drain collection XV-47-1F011 tank (All valves fail closed)

Various Nonradioactive Valves or heat exchanger Potential cross contamination Routine analysis in Systems tube sheets at radioactive/nonradioactive chemistry surveillance system interfaces Plumbing and Drainage Open area drains and/or Inappropriate use of segregated Precaution notices, drain equipment drains drain systems plugs, curbs and/or color-coded labels around drains to identify Plumbing and Drainage Open area and/or equipment Open drains are a potential Controlled opening of drains inside reactor path for air flow from plugged drains enclosure (air supply fan secondary containment, if area and refueling floor) the 1/4 in. wg. negative pressure is interrupted Liquid Radwaste Offsite disposal of sump Sump oil is potentially Chemistry sample analysis Collection oil contaminated required prior to disposal Liquid Radwaste and Release of final radwaste Unauthorized release Routine surveillance Waste Water batch to cooling tower (inadvertent) blowdown (monitored)

CHAPTER 01 1.13-95 REV. 13, SEPTEMBER 20068

LGS UFSAR Table 1.13-5 ACCESS PATH IDENTIFICATION(1)

Access Path Route Description Reference (Bechtel) Drawings A (TSC to Security From TSC (yard), proceed to the security center 8031-C-2, M-102, M-103, and M-104 Center and Main Control (administration building). Continue west to the Unit 2 turbine Room/Operation Support enclosure entrance (el 217', Columns 41 & K). Entering Center) turbine enclosure (corridor 354), proceed west to the control structure. Continue to stairs/elevator (Columns 20 & N), then proceed upstairs to el 269'. Enter main control room or exit north for OSC.

A' (Alternate to A) From TSC (yard), proceed to the turbine enclosure truck bay 8031-C-2, M-102, M-103, and M-104 (room 335, el 217 ft', Columns 22 & R) Enter bay and take stairs (Columns 22 & R) to el 269'. Exit stairs to the south for either the OSC or main control room.

B (Security Center to From security center, proceed west to turbine enclosure Unit 8031-C-2 and M-102 Turbine Enclosure/ 2 entrance at el 217', Columns 41 & J. Continue west Control Structure, across Unit 2 turbine enclosure (corridor 354) to the control el 217') structure or Unit 1 turbine enclosure.

C (Main Control Room In main control room, proceed to stairs/elevator (Columns N 8031-M-104 and M-105 to HVAC Panel Area) & 20). Continue up stairs/elevator to el 304'. Exit into HVAC panel area.

C' (Alternate to C) Exit main control room through control structure into turbine 8031-M-104 and M-105 enclosure at el 269'. Proceed to stairs near Columns J & 5 and continue upstairs to el 302'. Enter exhaust fan area and proceed east to control structure and enter HVAC panel area.

D (Main Control Room In main control room, proceed to stairs/elevator near 8031-M-104, M-103 and M-102 to PASS and the Columns N & 20. Continue downstairs to el 217'. Exit Radwaste Enclosure stairwell. This area contains the PASS. To continue to the Vital Areas) vital areas located in the radwaste enclosure, exit the control structure to the Unit 1 turbine enclosure. Proceed west to the radwaste enclosure entrance at Columns J & 14. Enter radwaste area and continue south for control room or west for chemistry lab and counting room.

CHAPTER 01 1.13-96 REV. 13, SEPTEMBER 20068

LGS UFSAR Table 1.13-5 (Cont'd)(1)

Access Path Route Description Reference (Bechtel) Drawings D' (Alternate to D) In main control room, proceed to stairs/elevator near 8031-M-104, M-103 and M-102 Columns N & 20. Continue downstairs to el 217' and the PASS. Exit control structure and proceed west (corridor 352) to turbine enclosure exit (Columns Jb & 5). Exit building and proceed south to the end of the radwaste enclosure, then turn east. Enter radwaste enclosure near Columns 13 & C.

Proceed north to vital areas.

E (Radwaste Enclosure Exit the radwaste enclosure at Columns J & 14. Walk east 8031-M-102, M-103, M-104, M-105 el 217' to North through Unit 1 turbine enclosure to control structure. Walk M-124, and M-139 Stack Instrument up stairs at Columns M & 20 to el 332'. Proceed southeast Room) across room to stairs at Columns J & 21.8 next to the north stack. Climb stairs to el 411', north stack instrument room.

E' (Alternate to E) Exit the radwaste area at Columns J & 14. Continue east 8031-M-102, M-103, M-104, M-105, through turbine enclosure into Unit 2 side After entering Unit M-106, and M-139 2 side, continue east to the Unit 2 reactor enclosure entrance (Column 32). Enter stairs near Columns J & 32 and continue up the stairs to el 352' (refueling floor). Proceed south on refueling floor to the door on the south wall between the two units (Columns 22 & D). Enter door and proceed up ladder to south stack instrument area (el 411'). Cross roof area to north stack instrument room.

E (Alternate to E & E, Personnel shall use the most dose-efficient pathway to enter 8031-M-102, M-103, M-104, M-105, M-if both reactor well the 217 elevation of the control structure. Continue up stairs 106, and M-139 shield plugs are at Columns M and 20 to elevation 324. Proceed out onto removed) turbine enclosure roof Take scaffold stairs at Columns Kg and 17.6 to reactor enclosure roof elevation 411, proceed along farthest north point of travel on roof to north stack instrument room WRAM sample area.

F (Radwaste Enclosure Proceed south through radwaste enclosure to exit at 8031-M-102 el 217' to Diesel Columns C & 13. Enter yard and move towards south)

Generator Bays entrance of the emergency diesel generator bays. Enter bay area.

F' (Alternate to F) Proceed south through radwaste enclosure and exit into yard. 8031-M-102 Continue northeast towards reactor enclosure. Enter generator bays through the north entrance.

(1) This information has not been updated to reflect the current licensing design basis. The information should be used for historical reference only and not support the design basis of the plant.

CHAPTER 01 1.13-97 REV. 13, SEPTEMBER 20068

LGS UFSAR Table 1.13-6 RADIATION QUALIFICATION OF SAFETY-RELATED EQUIPMENT(1)

Non-LOCA HELB Source LOCA Source Term (Noble Term (Noble Containment Gas/Iodine/ Particulate) Gas/Iodine/Particulate)

Outside Percent (100/50/1) in RCS Percent (10/10/0) in RCS Inside Larger of (100/50/1) (10/10/0) In RCS in containment or (100/50/1) in RCS (1) This Table is based on the requirements of Regulatory Guides 1.3, 1.5, and 1.25, consistent with the source terms of TID-14844. Alternative Source Terms, per Regulatory Guide 1.183 requirements may be used for the qualification of safety related equipment.

CHAPTER 01 1.13-98 REV. 14, SEPTEMBER 2008

LGS UFSAR Table 1.13-7 X/Q VALUES FOR VITAL AREAS(2)

Time Final Periods Base X/Q Modifying Factors X/Q (hours) (sec/m3) f1 f2 f3 f4 f5 f6 (sec/m3)

Technical Support Center 0-8 1.58x10-4 1 1 .2 1 .5 .66(1) 1.04x10-5 8-24 1.58x10-4 .67 .88 .2 1 .5 .66(1) 6.15x10-6 24-96 1.58x10-4 .50 .75 .2 1 .5 .66(1) 3.91x10-6 96-720 1.58x10-4 .33 .50 .2 1 .5 .66(1) 1.72x10-6 720 & on 1.58x10-4 .25 .33 .2 1 .5 .66(1) 8.6 x10-7 Diesel Generator Areas 0-8 2.57x10-4 1 1 .2 1 .5 .66(1) 1.70x10-5 8-24 2.57x10-4 .67 .88 .2 1 .5 .66(1) 1.00x10-5 24-96 2.57x10-4 .50 .75 .2 1 .5 .66(1) 6.36x10-6 96-720 2.57x10-4 .33 .50 .2 1 .5 .66(1) 2.80x10-6 720 & on 2.57x10-4 .25 .33 .2 1 .5 .66(1) 1.40x10-6 Security Center 0-8 5.16x10-4 1 1 .2 1 .5 .66(1) 3.41x10-5 8-24 5.16x10-4 .67 .88 .2 1 .5 .66(1) 2.01x10-5 24-96 5.16x10-4 .50 .75 .2 1 .5 .66(1) 1.28x10-5 96-720 5.16x10-4 .33 .50 .2 1 .5 .66(1) 5.62x10-6 720 & on 5.16x10-4 .25 .33 .2 1 .5 .66(1) 2.81x10-6 Turbine Building HVAC 0-8 8.25x10-4 1 1 .2 1 .5 .66(1) 5.45x10-5 Air Intakes - PASS, OSC 8-24 8.25x10-4 .67 .88 .2 1 .5 .66(1) 3.21x10-5 24-96 8.25x10-4 .50 .75 .2 1 .5 .66(1) 2.04x10-5 96-720 8.25x10-4 .33 .50 .2 1 .5 .66(1) 8.98x10-6 720 & on 8.25x10-4 .25 .33 .2 1 .5 .66(1) 4.49x10-6 Radwaste Building HVAC 0-8 6.19x10-4 1 1 .2 1 .5 .66(1) 4.09x10-5 Air Intake - Radiation 8-24 6.19x10-4 .67 .88 .2 1 .5 .66(1) 2.41x10-5 Chemistry Lab, Counting 24-96 6.19x10-4 .50 .75 .2 1 .5 .66(1) 1.53x10-5 Room, Radwaste Control Room 96-720 6.19x10-4 .33 .50 .2 1 .5 .66(1) 6.74x10-6 720 & on 6.19x10-4 .25 .33 .2 1 .5 .66(1) 3.37x10-6 Main Control Room, 0-8 3.46x10-4 HVAC Panels, and North 8-24 2.04x10-4 Stack Instrument Room 24-96 1.30x10-4 96-720 5.71x10-5 720 & on 2.85x10-5 (1) For the MSIV Leakage Alternate Drain Pathway, the F 6 factor is 1.0, since this release point is not an elevated release point.

(2) This Table is historical. The application of Alternative Source Terms per Regulatory Guide 1.183 resulted in the re-evaluation of X/Q values. See UFSAR Section 2.3.

CHAPTER 01 1.13-99 REV. 14, SEPTEMBER 2008

LGS UFSAR Table 1.13-8 HIGH-RANGE NOBLE GAS EFFLUENT MONITORS (TABLE II.F.1-1)

REQUIREMENT - Capability to detect and measure concentrations of noble fission products in plant gaseous effluents during and following an accident. All potential accident release paths shall be monitored.

PURPOSE - To provide the plant operator and emergency planning agencies with information on plant releases of noble gases during and following an accident.

DESIGN BASIS MAXIMUM RANGE Design range values may be expressed in Xe-133 equivalent values for monitors employing gamma radiation detectors or in microcuries per cubic centimeter (Ci/cc) of air at standard temperature and pressure for monitors employing beta radiation detector (Note: 1R/hr @ 1 ft = 6.7 Ci Xe-133 equivalent for point source). Calibrations with a higher energy source are acceptable.

The decay of radionuclide noble gases after an accident (i.e., the distribution of noble gas changes) should be taken into account.

105 Ci/cc - Undiluted containment exhaust gases (e.g., PWR reactor building purge, BWR drywell purge through the SGTS).

- Undiluted PWR condenser air removal system exhaust.

104 Ci/cc - BWR reactor building (secondary containment) exhaust air.

- PWR secondary containment exhaust air.

103 Ci/cc - Buildings with systems containing primary coolant or primary coolant offgases (e.g., PWR auxiliary buildings, BWR turbine buildings).

- PWR steam safety valve discharge, atmospheric steam dump valve discharge.

102 Ci/cc - Other release points (e.g., radwaste buildings, fuel handling/storage buildings).

CHAPTER 01 1.13-100 REV. 13, SEPTEMBER 2006

LGS UFSAR Table 1.13-8 (Cont'd)

REDUNDANCY - Not required; monitoring the final release point of several discharge inputs is acceptable.

SPECIFICATIONS - (None) Sampling design criteria per ANSI N13.1.

POWER SUPPLY - Vital instrument bus or dependable backup power supply to normal alternating current.

CALIBRATION - Calibrate monitors using gamma detectors to Xe-133 equivalent (1R/hr @ 1 ft = 6.7 Ci Xe-133 equivalent for point source). Calibrate monitors using beta detectors to Sr-90 or similar long-lived beta isotope of at least 0.2 MeV.

DISPLAY - Continuous and recording as equivalent Xe-133 concentrations or Ci/cc of actual noble gases.

QUALIFICATION - The instruments shall provide sufficiently accurate responses to perform the intended function in the environment to which they will be exposed during accidents.

DESIGN - Offline monitoring is acceptable for all CONSIDERATIONS ranges of noble gas concentrations.

- Inline (induct) sensors are acceptable for 102 Ci/cc to 105 Ci/cc noble gases. For less than 102 Ci/cc, offline monitoring is recommended.

- Upstream filtration (prefiltering to remove radioactive iodines and particulates) is not required; however, design should consider all alternatives with respect to capability to monitor effluents following an accident.

- For external mounted monitors (e.g., PWR main steam line, the thickness of the pipe should be taken into account in accounting for low-energy gamma radiation.

CHAPTER 01 1.13-101 REV. 13, SEPTEMBER 2006

LGS UFSAR Table 1.13-9 INTERIM PROCEDURES FOR QUANTIFYING HIGH-LEVEL ACCIDENTAL RADIOACTIVITY RELEASES (TABLE II.F.1-2)

Applicants are to implement procedures for estimating noble gas and radioiodine release rates if the existing effluent instrumentation goes off-scale.

Examples of major elements of a highly radioactive effluent release special procedures (noble gas).

- Preselected location to measure radiation from the exhaust air, e.g., exhaust duct or sample line.

- Provide shielding to minimize background interference.

- Use of an installed monitor (preferable) or dedicated portable monitoring (acceptable) to measure the radiation.

- Predetermined calculational method to convert the radiation level to radioactive effluent release rate.

CHAPTER 01 1.13-102 REV. 13, SEPTEMBER 2006

LGS UFSAR Table 1.13-10 SAMPLING AND ANALYSIS OR MEASUREMENT OF HIGH-RANGE RADIOIODINE AND PARTICULATE EFFLUENTS IN GASEOUS EFFLUENT STREAMS (TABLE II.F.1-3)

EQUIPMENT - Capability to collect and analyze or measure representative samples of radioactive iodines and particulates in plant gaseous effluents during and following an accident. The capability to sample and analyze for radioiodine and particulate effluents is not required for PWR secondary main steam safety valve and dump valve discharge lines.

PURPOSE - To determine quantitative release of radioiodines and particulates for dose calculation and assessment.

DESIGN BASIS - 102 Ci/cc of gaseous radioiodine and particu-SHIELDING lates, deposited on sampling media; 30 minutes ENVELOPE sampling time, average gamma energy (E) of 0.5 MeV.

SAMPLING MEDIA

- Iodine > 90% effective adsorption for all forms of gaseous iodine.

- Particulates > 90% effective retention for 0.3 micron () diameter particles.

SAMPLING CONSIDERATIONS

- Representative sampling per ANSI N13.1 (1969).

- Entrained moisture in effluent stream should not degrade adsorber.

- Continuous collection required whenever exhaust flow occurs.

- Provisions for limiting occupational dose to personnel incorporated in sampling systems, in sample handling and transport, and in analysis of samples.

CHAPTER 01 1.13-103 REV. 13, SEPTEMBER 2006

LGS UFSAR Table 1.13-10 (Cont'd)

ANALYSIS

- Design of analytical facilities and preparation of analytical procedures shall consider the design basis sample.

- Highly radioactive samples may not be compatible with generally accepted analytical procedures; in such cases, measurement of emissive gamma radiations and the use of shielding and distance factors should be considered in design.

CHAPTER 01 1.13-104 REV. 13, SEPTEMBER 2006

LGS UFSAR Table 1.13-11 CONTAINMENT HIGH-RANGE RADIATION MONITOR (TABLE II.F.1-4)

REQUIREMENT - The capability to detect and measure the radiation level within the reactor containment during and the following an accident.

RANGE - 1 rad/hr to 108 rads/hr (beta and gamma) or alternatively 1 R/hr to 107 R/hr (gamma only).

RESPONSE - 60 keV to 3 MeV photons, with linear energy response (+/-20%) for photons of 0.1 MeV to 3 MeV. Instruments must be accurate enough to provide usable information.

REDUNDANT - A minimum of two physically separated monitors (i.e., monitoring widely separated spaces within containment).

DESIGN AND - Category I instruments as described in Appendix QUALIFICATION A, except as listed below.

SPECIAL - In situ calibration by electronic signal CALIBRATION substitution is acceptable for all range decades above 10 R/hr. In situ calibration for at least one decade below 10 R/hr shall be by means of calibrated radiation source. The original laboratory calibration is not an acceptable position due to the possible differences after in situ installation. For high-range calibration, no adequate sources exist, so an alternate was provided.

SPECIAL - Calibrate and type-test representative specimens ENVIRONMENTAL of detectors at sufficient points to demonstrate QUALIFICATIONS linearity through all scales up to 106 R/hr. Prior to initial use, certify calibration of each detector at least one point per decade of range between 1 R/hr and 103 R/hr.

CHAPTER 01 1.13-105 REV. 13, SEPTEMBER 2006

LGS UFSAR Table 1.13-12 INFORMATION REQUIRED FOR CONTROL ROOM HABITABILITY EVALUATION (TABLE III.D.3.4-1)

(1) Control room mode operation, i.e., pressurization and filter recirculation for radiological accident isolation or chlorine release (2) Control room characteristics:

(a) air volume control room (b) control room emergency zone (control room, critical files, kitchen, washroom, computer room, etc.)

(c) control room ventilation system schematic with normal and emergency air flow rates (d) infiltration leakage rate (e) high efficiency particulate air filter and charcoal absorber efficiencies (f) closest distance between containment and air intake (g) layout of control room, air intakes, containment building, and chlorine, or other chemical storage facility with dimensions (h) control room shielding including radiation streaming from penetrations, doors, ducts, stairways, etc.

(i) automatic isolation capability-damper closing time, damper leakage and area (j) chlorine detectors or toxic gas (local or remote)

(k) self-contained breathing apparatus availability (number)

(l) bottled air supply (hours supply)

(m) emergency food and potable water supply (how many days and how many people)

(n) control room personnel capacity (normal and emergency)

(o) potassium iodide drug supply CHAPTER 01 1.13-106 REV. 13, SEPTEMBER 2006

LGS UFSAR Table 1.13-12 (Cont'd)

(3) Onsite storage of chlorine and other hazardous chemicals:

(a) total amount and size of container (b) closest distance from control room air intake (4) Offsite manufacturing, storage, or transportation facilities of hazardous chemicals (a) identify facilities within a 5 mile radius (b) distance from control room (c) quantity of hazardous chemicals in one container (d) frequency of hazardous chemical transportation traffic (truck, rail, and barge)

(5) Technical specifications (refer to Standard Technical Specifications)

(a) chlorine detection system (b) control room emergency filtration system including the capability to maintain the control room pressurization at 1/8 inch water gauge, verification of isolation by test signals and damper closure times, and filter testing requirements.

CHAPTER 01 1.13-107 REV. 13, SEPTEMBER 2006

LGS UFSAR Figures 1.2-1 through 1.2-72 Deleted

LGS UFSAR LEGEND

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1. THESE REPRESENT TURBINE INLET CONDITIONS AND ARE BASED ON 100% DRY STEAM IN THE STEAM DOME.

LIMERICK GENERATING STATION UNITS 1 AND 2 UPDATED FINAL SAFETY ANALYS IS REPORT

,- REACTOR REACTORSYSTEM HEAT BALANCE STEAM HEAT BALLA NCE UNIT 2 FIGURE 1.2-73 Rev.

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• 4 STRA!NER NAME PLATE. PEeD DOC No. HE -265-Z7-I RHRHRAINER 70P UODULE aSSEII8LT. PECO DOC No.. NE-265-21-1.2 I 3 B RHR STRAINER MOOU~E GENERAL ARRCT. PECO DOC No_ HE-265-29-1 B CORE SPRAY STRAINER TOP "ODUlE ASSE"8~ Y. PECO DOC No. NE-265*3O-I.2

• 3 CORE SPRAY STRAI NER "OOUlE GENERAl. ARRCT. PECO DOC No. NE -2S5'JI-I CORE SPRAY ..aUNT! He ELBa'. PECO Doe No. NE-165-"-I RHR )TRAI NER SOTTOII Il00UlE ASSEIIS~ Y. PECO DOC No. NE-2&5-],-I I 2 tORE SPRAY STRAI HER BOTTOII "ODULE ASSEIIBL T. PECO DOC No. HE-265-]4-1

• 2 RHR I CO~E SPRAY PLATE O£TlI~S, PECO DOC No. NE-265'

TAPEUO DUTCHMAN rLONGE ASSEIIBL Y PECO DOC No. NE-265'42-t MECHANI CAL H=:+,===-----f:i~CP.lH

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A IrtJ"C "'C 6 5 3 2 rILE No, U83205,.oCN 06.Q3.98 UFSAR FIGURE 1.2-83 Sht. 1 of 2 Rev, 09 11/99

8 7 5 3 2 8Z£8-r'.l ROUTE H H

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16"-H88'220 KEY PLAN eONTNUEO ON owe ..-298 G

GENERAL NOTES:

I. SC.ll.[' r.." - r"Q" 2 STIt_1I ASS£M8l Y INJ SHOP FIiIIRIC ...TIOH TO lIE .. .tCeOROONC£ WlTM Pf;CO sPECE"IC"TII)N NE'26S, J. STR_R 5UPPORTS NIl) SHOP FI08RlCATIOI< TO lIE .. .tCCOROIOHCE WITH F'teO SPEO'ICATIOI< NE-269.

4. rI08li1CAT~* ..sT.ot.LATION INJ ..sP£CTIQN ~ STR_IIS TO \It .. .tCCORO,lNCE WlTI! ASuE: COO( MOllREwtNTS. ASOIE .. " " II.oIIST ~DJ. TI< srR~1IS NIt H CLASS NC. THE BOU,,", ~ CtASS "'.

5. FABRICATION* ..sT.ot.LATION INJ IIISPtCTlON ~ SuPPORTS TO BE .. .tCCCRllMC[

WIT.. IHSlBll7 1M. EIlITION WITt< ,;o()£1()A MOUGH "ARC*' 1971 F

E G 270'

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o o REFERENCE DRAWINGS:

RNA STR_R Z"'211, 2A21"211. 2CF211 , 2C2F211 ARRCT owe .. -8329 COl!( _"'v RNA STR_II 28"211. 282F211. 20"'211" 2DlF211 MRc:T owe; STR~ Z..... 2 .. ARRJWC£IIENT owe; COll£ SPRAV STR~R 28"'214 ARRJWC£IIENT pwc;

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ON ewe "'317 IoISe ECCS ST~MEII I)(T....S. P(CO DOC No. N-oo(-2&5-25-1 RHI

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8 _ STRMEII _ E ClNE~.II. _CT, P(co DOC No. N-OO(*2U*29-1 B CORt SPIt....,. STIUINER TOP W!XIIA.[ ASS£1I8I. Y, P(co DOC No. "'-00(*l55*JO-1,2 , "

CORt SPRAY STR"""::'" W!XIIA.E ClNE~.II. MRc:T, Keo DOC No. "'-00(*2$$*J1-1

'COR( SPRAY IIOUN1'ING ELBOW. P(co DOC No.N-QOE*2SS*J8*1 RHI STR~ BOTTOW W!XIIA.[ ASSt ...: .. , KeD OOC ..... N*OO( *2&S*3g*,. 2 COII£ SPRAY STR......::~ BOTTO" IIOCU.£ ASStWIIlY, P(CO DOC ..... "'*00(*26S*14-1' 2

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*:-:'IH~IH>' ~t,. MECHANICAL A

o 8 7 6 5 3 2 UFSAR FIGURE 1.2-83 Sht 2 of 2 Rev. 09 11/99

Chapter 1 2010-022 fNEW UFSAR CHAPTER 1 FIGURE Page 13 o f 48 Legend - ' . ..

1. = Flow, IbnV'hr 1060 Ii '" Enthalpy. Btu/Ibm p "-

F = Te llllerature. OF M '" Mois ture. % t,, f,, Ma in Steam Flow 15.287E+{)6 # -

P '" Pres sure, ps ia

" <Jf><:::

~

1190.0H-0.43 M -

Carryunder = 0.25% 1003 p-35 15 Main Feed Flow MWt Wd = 100 % 15.388Et{)6 II 15.255E-+{)6 #

531.5 Ii 405.5 H 405.3 Ii 536.0 OF Total 427.2 OF 427.1 ~ F Core Flow

='"

6 h = 0.9 Ii ,

lOO.OE-+{)6 JLL H Cleanup 1.330E+05 II 418.4 H 439.0 OF Dcmineralizer System 3.200E+{)4 # Control Rod Drive 1.330E+05 II 68.0 H Feed Flow 530.6 H 97.2 OF 535.3 OF

-Conditions at upstrcam s ide ofTSV Core Themul Power 3515.0 Pullll Heating 9.0 Ocanup Los ses -4.4 Other System Losses -1.1 LlMl: RICK GEN l:R ATING STATION Turbine Cycle Usc 3518.5 MWt UN ITS I AND 2 UP DATED FINAL SAFETY ANAL YSIS KEPOR r REACTOR REACTOR SYSTEM SYSTEM IIEATHEAT BALANCE BLANCE (UNIT 1i Note: Wd indicates recirculation drive flow. FIGURE 1.2-84FIGURE 1.2-84Rev. 16, 09/12

LGS UFSAR Figures 1.10-1 Deleted

INPUT (If NOT THE STARTING POINT I AUlt INIT I""NG O[V"[

INPUT 4C.TUATtD 8Y OR (lUTPUT Pl4YSI CAL CCN)I TlON 50 IliMAl LOCATION SIGNAl. IS PR(S(HT 50 I CHAI.. PIt( SOIl Iot!(N CCN)lTtON IS \otI£.II CONDITION o[SCRUJ[D itlTHIN tHE o[SeJUIII(O WITHIN OUTPUT BLOCK CXISTS. OUTPUt TI!( aOCK OISTS.

INPUT INPuT PC_ISSIVE DEVIC( 'ONTIIOLLED OCYIC[ OR I4[(HAHISM AUX AUlI INPut INPuT TYI>. Of MEeH. OUTPUT OR I4[(H. LlNKAG(.

OUTPUT

~~~Ii~~~ ~:"'~~L~M~~~iin~Sr;$L~slt£s SUCH AS VALII[ OR PlH' SWl101&OR DEstGMAl(D IN THE IIINER !IlOCll. THIS tOND. OR O[VICE tfF"[('TS THE Of"£RAlION or THE fiNAL DEVICE, IT HAS ELEO.

INPUTS,IoI[CH INPUTS, _ INPUTS (14[(.H OR [LtC) AfI) M£C.H OR (LECT OUTPUTS. THIS DEVICE IS ~llY A VALVE. THIS IS ALSO USE!) ,OR OTHER INPUT /OUlPUT PMR SQUIKE5 SUCH AS AI R OR H't1)ftAUll',

A SOLENOID PILOT VALVE fQR All "IR QP(RATEO VALVE IS AN (X_lE Of THIS TYPE O[VIC£. lIN£S AO;SOCUTtO \11TH LCGI: S'noI8OlS

[LEC T. flOIoI SIGNAL M(CH ..... ICAl LlNKJIIO(

LIMERICK GENERATING STATION UNITS 1 AND 2 UPDATED FINAL SAFETY ANALYSIS REPORT LOGIC SYMBOLS FIGURE 1.'.2

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L L

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~O.l::>'t~ 3S0a LIMERICK GENERATING STATION UNITS 1 & 2 UPDATED FINAL SAFETY ANALYSIS REPORT DOSE RATE REDUCTION FACTORS FOR ECCS/RHR PIPING (O.TO 24 HRS)

FIGURE 1.13-1 Rev. 10 10/00

0 N

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J I o 0(1)

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H Ol.J'V~ 3S0a LIMERICK GENERATING STATION UNITS 1 AND 2 UPDATED FINAL SAFETY ANALYSIS REPORT DOSE RATE REDUCTION FACTORS FOR ECCS/RHR PIPING (24 TO 720 HRS)

FIGURE 1.13-2