ML20142A548

4 to Updated Final Safety Analysis Report, Section 3.6, Protection Against Dynamic Effects Associated with the Postulated Rupture of Piping

ML20142A548
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Site:	Hope Creek
Issue date:	05/21/2020
From:	Public Service Enterprise Group
To:	Office of Nuclear Reactor Regulation
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LR-N20-0036
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3.6 PROTECTION AGAINST DYNAMIC EFFECTS ASSOCIATED WITH THE POSTULATED RUPTURE OF PIPING This section describes the method of protection against dynamic effects associated with postulated ruptures in high energy and moderate energy piping located both inside and outside of the primary containment, as defined in Section 3.6.3. The methods used to determine pipe rupture locations and to analyze the results of the ruptures - which include jet thrust forces, jet impingement forces, piping dynamic responses, and compartment pressure temperature transients - are also described. A description is also provided for the design measures implemented to ensure that no function necessary to mitigate the consequences of a pipe rupture is lost during any postulated rupture.

The definitions of terms used in this section are provided in Section 3.6.3.

3.6.1 Postulated Piping Failures In Fluid Systems The failure of high or moderate energy piping could cause damage to surrounding structures, systems, and components. Nuclear safety-related systems are designed to ensure that components required for the safe shutdown and isolation of the reactor do not fail as a result of a failure in a high or moderate energy piping system. Depending on the fluid system involved and the rupture location, postulated piping failures can result in one or more of the following effects: pipe whip, jet impingement, environmental effects, i.e., pressure, temperature, and humidity; water spray; and flooding.

Essential systems and components are protected from the effects listed below, unless it can be demonstrated that their function is not impaired:

1. Pipe whip - Pipe whip is the unrestrained movement of a pipe due to the reaction force imposed on the pipe by 3.6-1 HCGS-UFSAR Revision 0 April 11, 1988

fluid discharging from a rupture. Protection against pipe whip can be provided by interposing structural members between high energy piping and the essential systems and components, by providing pipe whip restraints on the high energy piping, or by locating essential systems and components sufficiently distant from high energy piping.

Through wall cracks in moderate energy systems do not cause pipe whip. Examples of typical pipe whip restraints are shown on Figure 3.6-1.

A whipping pipe is assumed to cause functional failure of an impacted pipe of smaller nominal pipe size. The whipping pipe could also lead to the development of a through wall crack in an impacted pipe of the same nominal pipe size with thinner wall thickness. The whipping pipe is assumed to have sufficient energy to cause the failure of impacted electrical cable and instrumentation, unless the equipment is shown to be sufficiently strengthened or protected. High energy piping is located away from the essential safety-related systems wherever practical. Otherwise, piping is provided with pipe whip restraints.

2. Jet impingement - Jet impingement loads, resulting from postulated pipe failures, are considered for equipment and safety-related systems. The blowdown of fluid from the rupture of a high energy pipe can exert forces on nearby equipment sufficient to damage the equipment. Protection against jet impingement can be provided by installing jet impingement barriers to deflect the blowdown jet, or by locating essential systems and components a sufficient distance from high energy piping.

Jets from postulated pipe breaks in the drywell are analyzed in detail. All equipment located within the potential impingement zone of a jet is identified as a target. A target is not considered impacted when structural members or equipment shield it from the jet 3.6-2 HCGS-UFSAR Revision 0 April 11, 1988

effects. After all the targets are identified, they are tabulated by pipe break location. Each target is then further organized into one of four safety categories:

a. Nonsafety-related equipment - This equipment consists of items that are not required either for safe shutdown or to mitigate the effects of any pipe break in question.

b. Essential safety-related equipment - This equipment consists of items that must remain in operation or be available for operation in order to accomplish safe shutdown or to mitigate the effects of the particular pipe break being examined.

c. Nonessential safety-related equipment - This equipment consists of items that are required for some postulated pipe breaks, but are not required for safe shutdown or to mitigate the effects of the particular pipe break being examined.

d. Redundant, essential safety-related equipment - This equipment consists of items that are designed to mitigate the effects of a postulated pipe break but, due to sufficient system redundancy and/or separation, may not actually be required for safe shutdown of the plant.

Nonsafety-related equipment, and redundant, essential safety-related and nonessential safety-related equipment are reviewed and identified only, whereas essential safety-related equipment is analyzed for functional as well as structural integrity. The jet impingement loads are reduced by accounting for the frictional effects and target shape factors that reduce the total force on the target. Where structural integrity of equipment or the function of essential safety-related equipment is exceeded 3.6-3 HCGS-UFSAR Revision 0 April 11, 1988

by the calculated jet impingement force, protection is provided by spatial separation or by the addition of barriers or enclosures.

Jet impingement loads in the Reactor Building are reviewed along with other pipe break effects on a compartment by compartment basis.

Structures designed to enclose and separate high energy piping from essential safety-related equipment are designed to sustain the predicted jet impingement and pipe whip loads. Loss of the impacted safety-related systems occupying the compartment where the postulated pipe break occurs is considered in the evaluation of the plant's ability to shut down, cool down, or isolate.

3. Environmental - Ruptures in high energy piping result in the release of fluid that can increase temperature, pressure, humidity, and radiation levels in the vicinity of the pipe failure and also in remote areas that communicate with the local atmosphere. Essential systems and components may be exposed to abnormal conditions that could degrade the capability of that equipment to perform its function. Safety-related equipment is qualified to meet the above environmental conditions resulting from postulated breaks.

Piping systems whose failure could generate hazardous environmental conditions are generally located in compartments that are capable of being isolated from required safety-related systems. Isolation of compartments that enclose high energy lines is provided by maintaining normally closed accessways; by sealing penetrations through walls and slabs; and by providing automatic isolation of other communication paths, such as ventilation ductwork, except where the design provides for steam venting through an adjacent compartment. Compartments are designed to withstand the maximum 3.6-4 HCGS-UFSAR Revision 0 April 11, 1988

internal pressurization that can develop as a result of a pipe failure, and are provided with vent capability to the atmosphere or adjacent areas where these effects would not escalate the event.

Essential systems and components are either located in areas not affected by pipe ruptures or are qualified for operation under the maximum environmental conditions that they may be subjected to as a result of pipe ruptures.

Pressure rise analysis and verification of structural adequacy of enclosures used to provide protection are discussed in Sections 3.8.2, 3.8.3, and 3.8.4. Transport of a steam environment that could affect the habitability of the main control room is discussed in Section 6.4.2.

Radiation is an additional environmental consequence of some pipe failures. Essential equipment is designed to tolerate integrated exposure resulting from normal plant operations. Essential equipment inside and outside the primary containment is designed for the additional exposure resulting from a design basis accident (DBA).

Equipment qualification is discussed in Section 3.11, with other radiological considerations discussed in Section 12.1.

4. Water spray - Water itself is a hazard to certain equipment, particularly electrical equipment. In most cases, spatial separation and intermediate obstructions are adequate to prevent spray from reaching the equipment. Essential equipment, i.e., equipment that is required to operate under and/or mitigate the accident condition and that can potentially be subjected to water spray, is either designed to operate when wetted, or is protected from water sprays where necessary by barriers or equipment enclosure.

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5. Flooding - Any significant failure of a steam or fluid system may result in flooding in the vicinity of the rupture and in the compartments into which the released fluid drains. The flooding rate and the total fluid volume released are based on the pipe break configuration, the service of the system, and the time required to isolate the system. The plant drainage system handles minor releases of fluid with no adverse effects on essential systems and components.

Compartments containing safety-related equipment are designed with features that permit rapid detection and isolation of flooding resulting from major line breaks, except where it can be demonstrated that flooding would not affect the performance of that equipment or its redundant counterparts.

Because of the high degree of equipment and system separation in the plant, flooding of an Emergency Core Cooling System (ECCS) equipment room is limited to one division of equipment.

3.6.1.1 Design Bases Pipe breaks are postulated to occur in all high energy fluid system piping, or a portion of the system, in accordance with the criteria in Section 3.6.2. Pipe cracks are postulated to occur in all moderate energy fluid system piping, in accordance with the criteria in Section 3.6.2.1.3.

The failure of piping containing high energy fluid may lead to damage of surrounding systems and equipment. The effects of such a failure, including pipe whip, fluid jet impingement, flooding, compartment pressurization, and environmental effects, require special consideration to ensure the following:

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1. The ability to safely shut down the reactor and maintain it in a safe shutdown condition

2. Containment integrity

3. That a postulated pipe break on a line that is not part of the reactor coolant pressure boundary (RCPB) will not cause a loss of reactor coolant

4. Resultant radiation exposures are below the guideline values in 10CFR50.67.

In analyzing the effects of postulated pipe ruptures, the following assumptions are made:

1. Each pipe break in high energy fluid system piping or crack in moderate energy fluid system piping is considered separately as a single, postulated, initial event occurring during normal plant conditions.

2. Offsite power is assumed to be unavailable if a trip of the turbine generator or the Reactor Protection System (RPS) is a direct consequence of the postulated piping rupture.

3. A single, active component failure is assumed to occur in systems used to mitigate the consequences of the postulated piping rupture and to shut down the reactor, except as noted in item 4 below.

4. Where the postulated piping rupture is assumed to occur in one of the two redundant trains of either the Residual Heat Removal (RHR)

System, Safety Auxiliaries Cooling System (SACS), Station Service Water System (SSWS), Auxiliary Building control Area chilled water system, a single active component failures in the other 3.6-7 HCGS-UFSAR Revision 17 June 23, 2009

train is not assumed, as discussed in NRC Branch Technical Position (BTP) ASB 3-1, Paragraph B.3.b.(3). These dual purpose, moderate energy systems are powered from both onsite and offsite sources and are designed, constructed, and inspected to standards appropriate for nuclear safety-related systems.

5. All available systems, including those actuated by operator actions, may be employed to mitigate the consequences of the postulated piping rupture. In judging the availability of systems, both the postulated piping rupture and its direct consequences, and the assumed single active component failure and its direct consequences, are considered. The feasibility of carrying out operator actions is judged on the availability of ample time and adequate access to equipment for the required actions.

6. An unrestrained whipping pipe is considered capable of causing functional failure in impacted piping of smaller nominal pipe size.

It could also lead to the development of through wall leakage cracks in impacted piping of equal or larger nominal pipe size with thinner wall thickness.

A postulated pipe break inside the primary containment, up to and including a rupture of the recirculation piping, in conjunction with a safe shutdown earthquake (SSE) and a single active component failure, will not prevent the plant from achieving and maintaining reactor shutdown, maintaining containment integrity, and maintaining dose levels within 10CFR50.67 guidelines. Outside the primary containment, the single failure is qualified to BTP ASB 3-1, Paragraph B.3.b.

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3.6.1.2 Description A listing of high energy fluid system piping is provided in Table 3.6-1. All other piping in the plant that is pressurized above atmospheric pressure is considered to be moderate energy piping. The routing of high energy fluid system piping within the Reactor Building and the primary containment is shown on the isometric drawings referenced in Section 3.6.1.2.1.

For each pipe rupture location determined in accordance with the criteria of Section 3.6.2.1, an analysis is performed using the assumptions of Section 3.6.1.1 to verify that the consequences of the pipe rupture are acceptable. These analyses are summarized below for high energy and moderate energy fluid systems.

Proximity of the essential systems and components to the high and moderate energy fluid system piping is reviewed and the essential systems and components are located with acceptable separation, unless the effects of pipe failure can be withstood.

3.6.1.2.1 High Energy Fluid Systems All high energy fluid system piping is described in the following paragraphs.

The discussion of each high energy fluid system includes a general system description and discussion of pipe break locations, the compartment pressure temperature transient, and a verification of the reactor shutdown capability.

3.6.1.2.1.1 Main Steam System The four 26-inch main steam lines are routed as shown on Figure 3.6-2 for the portion inside the primary containment, and on Figure 3.6-3 for the portion outside the primary containment. The A and B steam lines are connected to the south side of the reactor vessel and the C and D steam lines are connected to the north side of the vessel. All four steam lines penetrate the east side of the 3.6-9 HCGS-UFSAR Revision 0 April 11, 1988

primary containment. The portion of the Reactor Building through which the main steam lines are routed (between the primary containment and the Turbine Building) is referred to as the main steam tunnel and is separated from other areas of the reactor building by concrete walls and slabs. Only piping, HVAC, valves, and associated instrumentation are located in the main steam tunnel.

Figure 3.6-4 shows an elevation view of the main steam tunnel penetration chamber.

The following features are incorporated into the design of the main steam line and nearby structures to mitigate the consequences of a main steam line break or to minimize the probability of its occurrence:

1. A venturi type flow restrictor is located in each main steam line inside the primary containment. The flow restrictor reduces the rate of loss of reactor coolant from a main steam line break downstream of the restrictor. The flow restrictors are described in Section 5.4.4.

2. Each main steam line is provided with three or four main steam safety/relief valves (SRVs) that reduce the probability of breaks by protecting the steam line against overpressurization. The SRVs are described in Section 5.2.2.

3. Each main steam line is provided with two fast acting main steam isolation valves (MSIVs), one upstream and one downstream of the primary containment penetration. These valves close automatically upon receipt of signals indicating high steam flow or high temperature in the vicinity of the main steam piping outside the primary containment, as well as upon receipt of other initiating signals discussed in Section 7.3. This is done to 3.6-10 HCGS-UFSAR Revision 0 April 11, 1988

terminate blowdown through breaks outside the primary containment.

The MSIVs are described in Section 5.4.5.

4. Moment limiting pipe restraints are located upstream of the inboard MSIVs and downstream of the outboard MSIVs in order to ensure the operability of these valves in the event of a main steam line break in the general vicinity of the valves. The piping between the containment inboard MSIV and the outboard MSIV is designed to the stress limit criteria of Section 3.6.2.1.1.1 so that no break is postulated in this region.

The main steam lines are provided with pipe whip restraints inside the primary containment and in the main steam tunnel. Typical restraints inside the primary containment are shown on Figure 3.6-1. Figure 3.6-4 shows the locations of the restraints in the main steam tunnel. As shown on Figures 3.6-5 and 3.6-6, the anchor and restraint upstream and downstream of the outboard MSIVs span between the north and south walls of the tunnel and restrain all four steam lines. A built-up member, shown on Figures 3.6-4 and 3.6-7, extending out from the north wall to the south wall of the main steam tunnel limits the possible upward movement of the upper elbow of each steam line in the tunnel. Additionally, the vertical portion of the steam line run in the tunnel is restrained against the east wall of the tunnel at two separate locations, as shown on Figure 3.6-7.

After entering the Turbine Building from the main steam tunnel, the main steam lines are routed along the west side of the turbine building before turning eastward and running to the turbines. This arrangement is shown on Figure 3.6-3.

In reviewing the potential consequences of jet impingement resulting from main steam line breaks, it was determined that some breaks inside the primary containment could result in impingement on the 3.6-11 HCGS-UFSAR Revision 0 April 11, 1988

control rod drive (CRD) withdrawal piping. Analysis shows no significant increase in scram times resulting from withdrawal line crimping under jet impingement loads, as discussed in Reference 3.6-3. Electrical cabling associated with essential systems and components is either routed to avoid jet impingement, shown to be redundant, or has barriers, as necessary, to provide protection from postulated breaks of main steam piping.

1. Pipe break locations - The postulated pipe break locations and the pipe whip restraint locations for the main steam piping are shown on Figures 3.6-2 and 3.6-3. The calculated stress levels, usage factors, and postulated break types are listed in Tables 3.6-2 and 3.6-3.

2. Compartment pressure temperature transients - the pressure temperature transient in the primary containment resulting from a complete circumferential break of one main steam line is discussed in Section 6.2.1.

Protection against overpressurization of the main steam tunnel in the event of a main steam line break in the tunnel is provided by two sets of blowout panels. One set of blowout panels is located in the east wall of the penetration chamber of the main steam tunnel and vents to the auxiliary building main steam tunnel. The second set of blowout panels is located in the steam vent that leads upward from the tunnel and discharges to the atmosphere above the top of the Auxiliary Building. This steam vent is shown on Figures 3.6-8 and 3.6-39.

A pressure temperature transient analysis for a main steam line break in the tunnel was performed using the analytical technique described in Reference 3.6-1 and the blowdown data provided in Table 3.6-4. The flow schematic diagram used is shown on Figures 3.6-40 and 3.6-9, and the results of the analysis are listed in Table 3.6-5 and 3.6-12 HCGS-UFSAR Revision 0 April 11, 1988

shown graphically on Figures 3.6-41 through 3.6-44. The main steam tunnel is designed to withstand the maximum pressure developed, and the MSIVs are qualified to operate under environmental conditions more severe than those calculated to occur.

Analysis shows that gross structural failure of the Turbine Building floors, steel framework and operating deck as a result of a main steam line break within the Turbine Building will not occur.

In this analysis, credit is taken for structural failure (blowout) of the insulated metal siding on the south and east exterior walls of the Turbine Building, above Elevation 125 feet 6 inches.

3. Verification of reactor shutdown capability - Breakage of a main steam line inside the primary containment would result in a nonisolable blowdown of the reactor vessel. The sequence of events that would occur automatically to shut down the reactor and cool the core is discussed in Section 6.3.2.

For a main steam line break outside the primary containment, the MSIVs will be closed automatically because of high steam flow, low reactor water level, or high temperature in the vicinity of the main steam lines. Closure of the MSIVs will cut off steam flow to the feedwater pump turbines, causing the pumps to coast down and stop. The reactor will be tripped by low reactor water level or closure of the MSIVs. After isolation of the reactor vessel, the Reactor Coolant System pressure will increase until the setpoint of the SRVs is reached. Steam will then be automatically discharged to the suppression chamber to limit the pressure rise.

Low reactor water level will initiate operation of the High Pressure Coolant injection (HPCI) and Reactor Core 3.6-13 HCGS-UFSAR Revision 0 April 11, 1988

Isolation Cooling (RCIC) Systems to maintain reactor water level.

If both the HPCI and RCIC systems are unavailable, the Automatic Depressurization System (ADS) will be automatically initiated to depressurize the reactor vessel so that the Low Pressure Coolant Injection (LPCI) and Core Spray Systems can inject water into the vessel. These latter two systems are initiated automatically by low reactor water level and will provide sufficient flow to restore reactor water level and cool the core.

After reactor water level has been restored, the operator will manually initiate a reactor shutdown. When the Reactor Coolant System pressure and temperature have decreased sufficiently, the shutdown cooling mode of the RHR system can be manually initiated to bring the reactor to cold shutdown.

A combination of pipe whip restraints, jet impingement barriers, and separation by distance or intervening structures is used to ensure the availability of essential systems and components in the event of a main steam line break in either the primary containment or the main steam tunnel. Essential systems and components located in these areas are qualified to operate under the environmental conditions resulting from such a break. Since no essential systems and components are located in the turbine building, no special provisions are necessary to provide protection for equipment in this area from the effects of pipe breaks. Where turbine building interactions may have indirect impact on essential systems, such as TACS impacts that could affect SACS, special separation, pipe whip pathways, concrete barriers and stress evaluations of pipe break locations can be considered as mitigating or protection factors.

3.6.1.2.1.2 Reactor Recirculation System The two reactor recirculation loops are located entirely within the primary containment and are arranged on opposite sides of the reactor pedestal and biological shield. Pipe whip restraints anchored in the reactor pedestal and biological shield are 3.6-14 HCGS-UFSAR Revision 19 November 5, 2012

provided for the recirculation loops and are arranged as shown on Figure 3.6-

10. This system prevents unrestrained pipe whip resulting from a postulated rupture at any of the identified break locations. The restraints are of two different designs: a U-strap design, and a frame type design. The U-strap restraints consist of two basic components: the frame attached to a support member, and two straps attached to each frame. Stainless steel bars or wire ropes are used as straps. A schematic detail of a U-strap restraint is shown on Figure 3.6-11. The frame type restraints are located at azimuths 90 and 270 at an elevation of approximately 98 feet and are fabricated of steel plate.

The postulated break locations on the reactor recirculation system lead to significant jet impingement loads on the CRD withdrawal lines. However, analysis shows no significant increase in scram times resulting from CRD withdrawal line crimping under jet impingement loads, as discussed in Reference 3.6-3. Complete severance of CRD withdrawal piping does not prevent the associated control rods from being inserted into the reactor core. In addition, electrical cabling associated with essential systems and components is protected by routing to avoid jet impingement or is protected by adding jet impingement barriers.

1. Pipe break locations - The postulated pipe break locations for the recirculation loop piping are shown on Figure 3.6-12. The calculated stress levels, usage factors, and postulated break types are listed in Table 3.6-6. The blowdown time history for a recirculation system pipe break is provided in Table 3.6-7.

2. Compartment pressure temperature transient - The pressure temperature transient in the primary containment resulting from a complete circumferential rupture of one recirculation loop is discussed in Section 6.2.1.

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3. Verification of reactor shutdown capability - The automatic sequence of events that shuts down the reactor and cools the core in the event of a recirculation loop rupture is discussed in Section 6.3.2. A combination of pipe whip restraints, jet impingement barriers, and separation by distance is used to ensure the availability of sufficient equipment to accomplish these functions.

3.6.1.2.1.3 Feedwater System The discharge lines from the three reactor feedwater pumps are routed into a common mixing header in the Turbine Building. From this header, two parallel 24-inch feedwater lines enter the main steam tunnel and then penetrate the primary containment. Inside the primary containment, the two lines diverge to form symmetrical headers on opposite sides of the reactor vessel. Each header splits into three 12-inch risers that attach to the reactor vessel nozzles. The routing of the feedwater lines in the main steam tunnel and the primary containment is shown on Figures 3.6-13 and 3.6-14.

Each feedwater containment penetration is provided with three check valves as containment isolation valves: one inside primary containment, and two in the main steam tunnel. In the event of a feedwater line break outside the primary containment, these check valves close to prevent backflow from the reactor vessel. Thus, flow from the break comes from the feedwater pump side only.

Moment limiting pipe restraints ensure the operability of the outboard containment isolation valve closest to the primary containment in the event of a feedwater line break. The inboard valve and the second outboard valve need not be protected from overstress due to pipe whip, since only one of these valves may be damaged by a single pipe break and the two remaining isolation valves provide adequate redundancy to ensure the containment isolation function. See Reference 3.6-11 for the results of the analyses of the feedwater check valves.

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The feedwater lines are provided with pipe whip restraints inside the primary containment, and in the main steam tunnel. Typical restraints inside the primary containment are shown on Figure 3.6-1. The restraint in the tunnel, RS-1, spans between the north and south walls of the tunnel and limits the motion of both feedwater lines on pipe break, as shown on Figure 3.6-6. A built-up member from the north wall to the south wall of the steam tunnel limits the possible upward movement of the upper elbows of the feedwater lines, as shown on Figure 3.6-4.

In reviewing the potential consequences of jet impingement resulting from feedwater line breaks, it was determined that breaks near the first elbow inside the primary containment would result in impingement on the MSIV operators. Steel plate barriers have been provided to protect the operability of the MSIVs from this source of impingement. Electrical cabling associated with essential systems and components is routed to avoid jet impingement, or jet impingement barriers have been provided for protection, from postulated breaks of feedwater piping.

1. Pipe break locations - The postulated pipe break locations and the pipe whip restraint locations for the feedwater piping are shown on Figures 3.6-13 and 3.6-14. The calculated stress levels, usage factors, and postulated break types are listed in Tables 3.6-8 and 3.6-9.

2. Compartment pressure temperature transients - The pressure temperature transient in the primary containment resulting from a break of any of the feedwater lines in the drywell is exceeded in severity by the transients resulting from recirculation loop and main steam line breaks, which are discussed in Section 6.2.1. The pressure temperature transient resulting from a feedwater line break in the main steam tunnel or the Turbine Building is exceeded in severity by the transient 3.6-17 HCGS-UFSAR Revision 8 September 25, 1996

resulting from a main steam line break, which is discussed in Section 3.6.1.2.1.1.

3. Verification of reactor shutdown capability - A feedwater line break inside the primary containment would result in a nonisolable blowdown of the reactor vessel. The automatic sequence of events that shuts down the reactor and cools the core is discussed in Section 6.3.2.

An analysis to determine the feedwater check valve dynamics and stresses following a double ended break of the feedwater line outside containment has been performed. The RELAP 5/ MOD 1 computer code was used to predict the maximum valve disc angular velocity and the peak pressures upstream and downstream of the valve disc following closure. In addition, a sensitivity analysis was performed to select the feedwater check valve that yields the most conservative stress results.

An inelastic stress analysis was performed on the valve body, disc, hinge arm, and valve seat with the calculated stresses determined to be less than stress allowables. In addition, the maximum displacement of the hinge arm before and after valve disc closure was determined and deemed acceptable. Stresses were evaluated for the faulted condition based on the methods for analysis and design limits contained in Appendix F of the ASME B&PV Code,Section III.

For a feedwater line break outside the primary containment, differential pressure across the containment isolation check valves in the reverse direction causes these valves to close rapidly, isolating the reactor vessel from the break. The loss of feedwater flow causes the reactor water level to drop, initiating a reactor 3.6-18 HCGS-UFSAR Revision 0 April 11, 1988

scram when the reactor water level 3 trip point is reached. Water level continues to drop because of steam generation from decay heat, causing closure of the MSIVs when the level 1 trip point is reached, as well as initiation of the RCIC and HPCI systems when the reactor water level 2 trip point is reached. Once the reactor has been scrammed and the Reactor Coolant System isolated, the sequence of events is similar to that for a main steam line break outside the primary containment.

A combination of pipe whip restraints, jet impingement barriers, and separation by distance or intervening structures is used to ensure the availability of essential systems and components in the event of a feedwater line break in either the drywell or the main steam tunnel. Since no essential systems and components are located in the Turbine Building, no special provisions are necessary to provide protection for equipment in this area from the effects of pipe breaks.

3.6.1.2.1.4 Condensate System The Condensate System is located entirely within the Turbine Building. No pipe whip restraints are provided for the condensate piping.

1. Pipe break locations - Since the condensate system consists of non-nuclear class piping, breaks are postulated to occur at each location of potential high stress, such as pipe fittings, valves, and welded attachments. Breaks need not be postulated at locations that are subject to low stresses, consistent with Section 3.6.2.1.1.

2. Compartment pressure temperature transients - Since the normal fluid temperature in the Condensate System is less than 135F, no significant pressure temperature transient results from a condensate line break.

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3. Verification of reactor shutdown capability - In the event of a condensate line break, low suction pressure causes the feedwater pumps to trip. A subsequent loss of feedwater flow results in closure of the containment isolation check valves, thus preventing reactor blowdown through the break. The sequence of events that occur from this point on is the same as for breakage of a feedwater line outside the primary containment.

Because no essential systems and components are located in the Turbine Building, special provisions are not necessary to protect equipment in this area from the effects of pipe breaks. The flooding effects of a condensate line break are exceeded by the effects of a circulating water line expansion joint rupture in the Turbine Building, which is discussed in Sections 10.4.1 and 10.4.5.

3.6.1.2.1.5 Reactor Water Cleanup System The Reactor Water Cleanup (RWCU) System takes suction from each reactor recirculation loop within the primary containment. Two 4-inch RWCU suction lines converge into one 6-inch RWCU suction line that is routed up to Elevation 150 feet 6 inches, at which point it penetrates the primary containment. The RWCU piping is then routed through the various RWCU equipment compartments at Elevations 132 feet, 145 feet, and 162 feet in the Reactor Building, including the pipe chase compartment, the regenerative and nonregenerative heat exchanger compartment, two filter/demineralizer compartments, and two RWCU recirculation pump compartments. The RWCU return piping is routed from the pipe chase compartment directly into the main steam tunnel, where the piping branches into two 4-inch lines. One line connects to the A feedwater line, and the other connects to the B feedwater line. Both of these connections to the feedwater lines are located between the two outboard containment isolation valves in the feedwater lines.

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The RWCU suction line is provided with two fast acting isolation valves, one upstream and one downstream of the primary containment penetration. These valves close automatically upon receipt of signals indicating high differential flow (ratio of RWCU suction to return) or high temperature in the vicinity of the RWCU piping outside the drywell, as well as upon receipt of other initiating signals discussed in Section 7.3. This is done in order to terminate blowdown through breaks outside the drywell. To ensure the operability of these valves in the event of a RWCU suction line break, moment limiting pipe restraints are located upstream of the inboard containment isolation valve and downstream of the outboard containment isolation valve.

Whip restraints are also located on the portion of the RWCU suction line within the drywell.

In reviewing the potential consequences of jet impingement resulting from RWCU line breaks, it was determined that breaks in the RWCU return lines in the main steam tunnel do not impinge on any essential equipment. It was also determined that RWCU line breaks in the pipe chase compartment do not result in unacceptable impingement on the RWCU outboard containment isolation valve, since the containment isolation valve is far from the closest break location.

However, a RWCU line break in this compartment will result in impingement on the containment spray system containment isolation valves. These isolation valves are motor operated and "fail as is." Also, this system is not needed to mitigate the effects of the RWCU line break. Therefore, protective barriers are not needed.

1. Pipe break locations - The postulated pipe break locations and the pipe whip restraint locations for the RWCU piping inside and outside the primary containment are shown on Figures 3.6-15 and 3.6-16, respectively. The calculated stress levels, usage factors, and postulated break types for these portions of the RWCU piping are listed in Tables 3.6-10 and 3.6-11.

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2. Compartment pressure temperature transients - The pressure temperature transient in the primary containment resulting from a break in the drywell portion of the RWCU suction line is exceeded in severity by the transients resulting from recirculation loop, main steam line, and intermediate size breaks, which are discussed in Section 6.2.1.

Protection against overpressurization of the RWCU equipment compartments in the reactor building as a result of RWCU line breaks in these areas is provided by interconnecting steam venting paths between the various compartments and by blowout panels leading to the outside atmosphere.

The RWCU heat exchanger compartment vents directly into the pipe chase compartment. Two of the four pump rooms vent directly to the pipe chase compartment. These two pump rooms serve as part of the vent path for the remaining pump rooms. The pipe chase compartment is vented to the suppression chamber compartment, and then to steam vent located on the west side of the reactor building. The steam vent is open to the atmosphere at its upper end via a set of blowout panels. This venting pathway is shown on Figure 3.6-45.

Pressure temperature transient analyses for cases involving RWCU line breaks in the RWCU equipment compartments are performed using the analytical technique described in Reference 3.6-16 and with the blowdown data provided in Table 3.6-4. These blowdown data are developed using Reference 3.6-2. The flow schematic diagram used for breaks in the RWCU equipment compartments is shown on Figure 3.6-17, and the results of the analyses are listed in Table 3.6-5. Pressure and temperature 3.6-22 HCGS-UFSAR Revision 17 June 23, 2009

transient curves for a RWCU filter demineralizer line break in the filter demineralizer room are shown on Figures 3.6-46 and 3.6-47, respectively.

The RWCU equipment compartments are designed to withstand the maximum pressure due to a pipe break. The outboard containment isolation valves for the RWCU system and other systems located in the pipe chase compartment are designed to operate under environmental conditions more severe than those calculated to occur due to a pipe break.

3. Verification of reactor shutdown capability - A RWCU suction line break inside the drywell results in a nonisolable blowdown of the reactor vessel. The automatic sequence of events that shuts down the reactor and cools the core is discussed in Section 6.3.2.

For a RWCU line break outside the drywell, the RWCU containment isolation valves are closed automatically due to high differential flow in the RWCU system or high temperature in the RWCU equipment compartments. Backflow from the feedwater lines into the RWCU return line is prevented by closure of the two check valves in the return line. If the break occurs in the RWCU piping within the main steam tunnel, the MSIVs will close automatically due to high temperature in the tunnel. Once MSIV isolation has occurred, the sequence of events is similar to that for a main steam line break outside the primary containment. If the break occurs in the RWCU equipment compartments, however, no reactor scram or MSIV closure results, due to the rapid termination of blowdown. After investigation of the cause of the RWCU system isolation, the operator initiates a normal shutdown of the reactor.

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A combination of pipe whip restraints, jet impingement barriers, and separation by distance or intervening structures ensures the availability of essential systems and components in the event of an RWCU line break occurring in the drywell, the main steam tunnel, torus compartment, or the RWCU equipment compartments. Essential systems and components located in these areas and the suppression chamber compartment are designed to operate under the environmental conditions resulting from the break. Among the RWCU equipment compartments, only the pipe chase compartment contains safety-related equipment: the primary containment purge line, the containment spray lines, HVAC isolation instrumentation, and the RWCU outboard containment isolation valve. The containment isolation valves in the purge containment spray lines are normally closed during reactor operation and are not required to operate after a RWCU line break outside primary containment. Therefore, they require no protection. RWCU pipe breaks in the torus compartment were reviewed to verify that no essential component would be adversely affected.

3.6.1.2.1.6 HPCI Steam Supply Line The HPCI steam supply piping has a nominal diameter of 10 inches for the portion inside the drywell and 12 inches for most of the portion outside the drywell. The supply line connects to main steam line C inside the drywell. The line penetrates the drywell at Elevation 106 feet 1-1/4 inches, entering the HPCI pipe chase compartment located at Elevation 99 feet 9 inches in the Reactor Building. It then penetrates the floor of the HPCI pipe chase compartment and runs toward the HPCI pump compartment located at Elevation 54 feet. The routing of this line is shown on Figures 3.6-18 and 3.6-19.

During normal reactor operation, the supply line is pressurized from main steam line C up to HPCI turbine steam supply valve HV-F001.

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The HPCI steam supply line is provided with two fast acting isolation valves, one upstream and one downstream of the primary containment penetration. These valves close automatically upon receipt of signals indicating high steam flow or high temperature in the vicinity of the HPCI piping outside the drywell, as well as upon receipt of other initiating signals discussed in Section 7.3. This is done in order to terminate blowdown through breaks outside the drywell.

Moment limiting pipe restraints are located upstream of the inboard containment isolation valve and downstream of the outboard containment isolation valve in order to ensure the operability of these valves in the event of a break in the HPCI steam supply line near the valves. Pipe whip restraints are also located on the HPCI steam supply line in the drywell, in the HPCI pipe chase compartment at Elevation 99 feet 9 inches, in the HPCI pump compartment and the torus compartment. Typical restraints inside the drywell are shown on Figure 3.6-1.

1. Pipe break locations - The postulated pipe break locations and the pipe whip restraint locations for the HPCI steam supply line are shown on Figure 3.6-18 for the portion of the line inside the drywell and on Figure 3.6-19 for the portion of the line outside the drywell. The calculated stress levels, usage factors, and the postulated break types are listed in Tables 3.6-12 and 3.6-13.

2. Compartment pressure temperature transients - The pressure temperature transient in the primary containment resulting from a break in the portion of the HPCI steam supply line in the drywell is exceeded in severity by the transients resulting from recirculation loop breaks and main steam line breaks, which are discussed in Section 6.2.1.

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Protection against overpressurization of the HPCI pump compartment and of the HPCI pipe chase compartment at Elevation 99 feet 9 inches in the Reactor Building, as a result of HPCI steam supply line breaks in these areas, is provided by steam venting paths and blowout panels leading to the outside atmosphere. The HPCI pipe chase compartment is vented to the atmosphere via blowout panels located on the west side of the Reactor Building, as shown on Plant Drawings P-0044-1 and P-0045-1. The HPCI pump compartment is vented to the suppression chamber compartment via hinged, metal plate blowout panels located in the HPCI pump compartment wall at Elevation 71 feet. These hinged panels open to relieve pressure in the HPCI pump compartment, but do not allow pressurization of the suppression chamber compartment to result in steam flow back into the HPCI pump compartment.

Pressure transient analyses for cases involving HPCI steam supply line breaks in the HPCI pump compartment and in the HPCI pipe chase compartment area are performed using the analytical technique described in Reference 3.6-1 and with the blowdown data provided in Table 3.6-4. The flow schematic diagram used for breaks in these two compartments is shown on Figure 3.6-17, and the results of the analyses are listed in Table 3.6-5. Pressure and temperature transient curves for a HPCI steam supply line break in the HPCI pump compartment are shown on Figures 3.6-20 and 3.6-21, respectively.

The HPCI pump compartment, the torus compartment, and the pipe chase compartment are designed to withstand the maximum pressures due to a pipe break. No equipment located in the HPCI pump compartment is required to operate following a break of the HPCI steam supply line, except the sensing lines leading to PDSH 9434-1 and 3.6-26 HCGS-UFSAR Revision 20 May 9, 2014

9434-2. These sensing lines are not impacted by the jets caused by postulated breaks in the HPCI pump compartment. All equipment located in the HPCI pipe chase compartment and suppression chamber compartment that is required to operate following a break of the HPCI steam supply line is qualified to operate under environmental conditions more severe than those calculated to occur due to pipe break.

3. Verification of reactor shutdown capability - A HPCI steam supply line break inside the drywell results in a nonisolable blowdown of the reactor vessel. The automatic sequence of events that shuts down the reactor and cools the core is discussed in Section 6.3.2.

For a HPCI steam supply line break outside the drywell, the steam supply line containment isolation valves are closed automatically, terminating reactor vessel blowdown. No reactor scram occurs, due to the rapid termination of blowdown. After investigating the cause of the HPCI steam supply line isolation, the operator initiates a normal shutdown of the reactor.

A combination of pipe whip restraints and separation by distance or intervening structures ensures the availability of essential systems and components in the event of a HPCI steam supply line break occurring in the drywell, the HPCI pipe chase compartment, or the HPCI pump compartment. Essential systems and components located in these areas are designed to operate under the environmental conditions resulting from the break. Electrical cabling associated with essential systems and components is either routed to avoid jet impingement, or jet impingement barriers are provided.

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One pipe whip restraint is provided for the portion of the HPCI steam supply line located within the HPCI pump compartment. This whip restraint is provided for the protection of penetrations and SACS cooling water lines from the consequences of pipe whip due to a HPCI line break adjacent to the turbine.

3.6.1.2.1.7 RCIC Steam Supply Line The RCIC steam supply line has a nominal diameter of 4 inches for the portion inside the drywell and 6 inches for the portion outside the drywell. The supply line connects to main steam line A inside the drywell. The line penetrates the drywell and enters the RCIC pipe chase compartment at Elevation 106 feet. At Elevation 99 feet 9 inches in the Reactor Building, the line enters the suppression chamber compartment. It then enters the RCIC pump compartment located at elevation 54 feet. The routing of this line is shown on Figures 3.6-22 and 3.6-23. During normal reactor operation, the line is pressurized from the main steam line up to RCIC turbine steam supply valve HV-F045.

The RCIC steam supply line is provided with two fast acting isolation valves, one upstream and one downstream of the primary containment penetration. These valves close automatically upon receipt of signals indicating high steam flow or high temperature in the vicinity of the RCIC piping outside the drywell, as well as upon receipt of other initiating signals discussed in Section 7.3. This is done in order to terminate blowdown through breaks outside the drywell.

Moment limiting pipe restraints are located upstream of the inboard containment isolation valve and downstream of the outboard containment isolation valve in order to ensure the operability of these valves in the event of a break in the RCIC steam supply line near the valves. Pipe whip restraints are also located on the RCIC 3.6-28 HCGS-UFSAR Revision 0 April 11, 1988

steam supply line inside the drywell, in the RCIC pipe chase compartment, and in the suppression chamber compartment in the Reactor Building. Typical restraints inside the drywell are shown on Figure 3.6-1.

1. Pipe break locations - The postulated pipe break locations and the pipe whip restraint locations for the RCIC steam supply line are shown on Figure 3.6-22 for the portion of the line inside the drywell and on Figure 3.6-23 for the portion of the line outside the drywell. The calculated stress levels, usage factors, and postulated break types are listed in Tables 3.6-14 and 3.6-15.

2. Compartment pressure temperature transients - The pressure temperature transient in the primary containment resulting from a break in the portion of the RCIC steam supply line in the drywell is exceeded in severity by the transients resulting from recirculation loop breaks and main steam line breaks, which are discussed in Section 6.2.1.

Protection against overpressurization of the RCIC pump compartment and of the RCIC pipe chase compartment at Elevation 99 feet 9 inches in the Reactor Building as a result of RCIC steam supply line breaks in these areas is provided by steam venting paths to the suppression chamber compartment, and then to a steam vent containing blowout panels leading to the outside atmosphere. The steam vent and blowout panels are located on the west side of the Reactor Building, as shown on Plant Drawings P-0044-1 and P-0045-1.

The RCIC pump compartment is vented to the suppression chamber compartment via hinged, metal plate blowout panels located in the RCIC pump compartment wall at Elevation 71 feet. These hinged panels open to relieve pressure in the RCIC pump compartment, but do not allow pressurization of the suppression chamber compartment to result in steam flow back into the RCIC pump compartment.

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Pressure temperature transient analyses for cases involving RCIC steam supply line breaks in the RCIC pump compartment and the RCIC pipe chase compartment were performed using the analytical technique described in Reference 3.6-1 and the blowdown data provided in Table 3.6-4. The flow schematic diagram used for breaks in these two compartments is shown on Figure 3.6-17, and the results of the analyses are listed in Table 3.6-5. Pressure and temperature transient curves for a RCIC steam supply line break in the RCIC pump room are shown on Figures 3.6-24 and 3.6-25, respectively.

The RCIC pump compartment is designed to withstand the maximum pressure due to pipe break. No equipment located in the RCIC pump compartment is required to operate following a RCIC steam supply line break, except the sensing lines to PDSH 9435-1 and 9435-2.

These sensing lines do not receive jet impingement or pipe whip loading. The pressure temperature transient in the suppression chamber compartment at the 54-foot elevation, resulting from a break in the portion of the RCIC steam supply line within that compartment, is exceeded in severity by the transient resulting from a HPCI steam supply line rupture in the same compartment. All equipment located in the suppression chamber compartment that is required to operate following a break of the RCIC steam supply line is qualified to operate under environmental conditions more severe than those calculated to occur due to a break of the HPCI steam supply line.

3. Verification of reactor shutdown capability - A RCIC steam supply line break inside the drywell results in a nonisolable blowdown of the reactor vessel. The automatic sequence of events that shuts down the reactor and cools the core is discussed in Section 6.3.2.

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For a RCIC steam supply line break outside the drywell, the steam supply line containment isolation valves are closed automatically on high steam flow, terminating reactor vessel blowdown. No reactor scram occurs, due to the rapid termination of blowdown.

After investigation of the cause of the steam supply line isolation, the operator initiates a normal shutdown of the reactor.

A combination of pipe whip restraints and separation by distance or intervening structures ensures the availability of essential systems and components in the event of a RCIC steam supply line break occurring in the drywell, the RCIC pipe chase compartment, the suppression chamber compartment, or the RCIC pump compartment.

Essential systems and components located in these areas are designed to operate under the environmental conditions resulting from the break. Electrical cabling associated with essential systems and components is either routed so as to avoid jet impingement, or jet impingement barriers are provided.

No pipe whip restraints are provided for the portion of the RCIC steam supply line located within the RCIC pump compartment, because no essential systems or component are impacted by a jet or a pipe whip.

3.6.1.2.1.8 Main Steam Drain Lines The main steam drain lines connect to the four main steam lines, both inside and outside the drywell. Inside the drywell, 2-inch drain lines that connect to each of the main steam lines are headered together into a single 3-inch line, which then penetrates the primary containment. This 3-inch drain header has two normally open containment isolation valves, one upstream and one 3.6-31 HCGS-UFSAR Revision 0 April 11, 1988

downstream of the primary containment penetration. The inboard and outboard isolation valves are provided with valve operability restraints. The routing of the main steam drain lines is shown on Figures 3.6-26 and 3.6-27.

1. Pipe break locations - The postulated pipe break locations and the pipe whip restraint locations for the main steam drain lines are shown on Figures 3.6-26 and 3.6-27. The calculated stress levels, usage factors, and postulated break types are listed in Tables 3.6-16 and 3.6-17.

2. Compartment pressure temperature transients - The pressure transient in the primary containment resulting from a break in a main steam drain line within the drywell is exceeded in severity by transients resulting from recirculation loop breaks and main steam line breaks. The temperature transient in the primary containment resulting from a main steam drain line break is exceeded in severity by the transient resulting from an intermediate size break. These design basis transients are discussed in Section 6.2.1.

The pressure temperature transient in the main steam tunnel resulting from a main steam drain line break within the tunnel is exceeded in severity by the transient resulting from a main steam line break.

3. Verification of reactor shutdown capability - A main steam drain line break inside the drywell results in a nonisolable blowdown of steam from the reactor vessel through the broken line. The automatic sequence of events that shuts down the reactor and cools the core is discussed in Section 6.3.2.

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For the case of a main steam drain line break inside the main steam tunnel, the resultant temperature rise in the tunnel causes both the MSIVs and the main steam drain line containment isolation valves to close automatically, thereby terminating steam blowdown through the break. After the isolation valves have been closed, the sequence of events is similar to that for a main steam line break outside the drywell.

A combination of pipe whip restraints and separation by distance or intervening structures is used to ensure the availability of essential systems and components in the event of a main steam drain line break in either the drywell or the main steam tunnel.

3.6.1.2.1.9 RPV Head Vent Line The RPV head vent line is a 2-inch line located entirely within the drywell.

From its connection point to a flanged nozzle on the RPV top head, the line is routed horizontally and then generally downward to a penetration through the containment seal plate. From this point, the line continues downward to its connection with the 26-inch main steam line A.

1. Pipe break locations - The postulated pipe break locations for the RPV head vent line are shown on Figure 3.6-28.

The calculated stress levels, usage factors, and postulated break types are listed in Table 3.6-18.

2. Compartment pressure temperature transients - Since the RPV head vent line is located entirely within the drywell, breakage of this line has no effect on plant areas outside the primary containment.

The pressure transient in the primary containment resulting from a break in the RPV head 3.6-33 HCGS-UFSAR Revision 0 April 11, 1988

vent line is exceeded in severity by transients resulting from recirculation loop breaks and main steam line breaks. The temperature transient in the primary containment resulting from a break in the RPV head vent line is exceeded in severity by the transient resulting from an intermediate size break. These design basis transients are discussed in Section 6.2.1.

3. Verification of reactor shutdown capability - An RPV head vent line break results in a nonisolable blowdown of steam into the drywell.

The automatic sequence of events that shuts down the reactor and cools the core is discussed in Section 6.3.2.

Separation by distance or intervening structures ensures the availability of essential systems and components in the event of an RPV head vent line break.

3.6.1.2.1.10 Standby Liquid Control Injection Line The discharge lines from the two standby liquid control (SLC) injection pumps are headered together outside the drywell and penetrate the drywell as a single 1-1/2 inch line. This line traverses the lower part of the drywell, and connects to the A core spray injection loop line. The SLC injection line is provided with three containment isolation valves: two parallel stop check valves outside the drywell, and a simple check valve inside the drywell. Only that portion of the line between the reactor vessel nozzle and the inboard check valve is considered high energy during periods when the reactor is pressurized.

1. Pipe break locations - The postulated pipe break locations for the SLC injection line are shown on Figure 3.6-29. The calculated stress levels, usage factors, and postulated break types are listed in Table 3.6-19.

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2. Compartment pressure temperature transients - Since the high energy portion of the SLC injection line is located entirely within the drywell, a break of this line has no effect on plant areas outside the primary containment. The pressure temperature transient inside the primary containment resulting from a break in the SLC injection line is exceeded in severity by the transients resulting from recirculation loop breaks and main steam line breaks, which are discussed in Section 6.2.1.

3. Verification of reactor shutdown capability - A SLC injection line break between the RPV and the first check valve in that line results in a nonisolable blowdown from the reactor vessel into the drywell. The automatic sequence of events that shuts down the reactor and cools the core is discussed in Section 6.3.2.

Separation by distance and/or intervening structures ensures the availability of essential systems and components in the event of a SLC injection line break.

3.6.1.2.1.11 RHR Shutdown Cooling Suction Line The RHR shutdown cooling suction line is a 20-inch line connected to reactor recirculation loop B. The line is routed horizontally and vertically to its containment penetration at Elevation 106 feet. The line is provided with two normally closed containment isolation valves, one inboard and one outboard of the primary containment penetration. Thus, only that portion of the line between the recirculation loop and the inboard containment isolation valve is considered high energy. The routing of the line is shown on Figure 3.6-30.

The RHR shutdown cooling suction line is provided with pipe whip restraints on the portion of the line inside the drywell. Examples of these restraints are shown on Figure 3.6-1.

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1. Pipe break locations - The postulated pipe break locations and the pipe whip restraint locations for the RHR shutdown cooling suction line are shown on Figure 3.6-30. The calculated stress levels, usage factors, and postulated break types are listed in Table 3.6-20.

2. Compartment pressure temperature transients - Since the high energy portion of the RHR shutdown cooling suction line is located entirely within the drywell, a break in the line has no effect on plant areas outside the primary containment. The pressure temperature transient in the primary containment resulting from a break in the RHR shutdown cooling suction line is exceeded in severity by the transients resulting from recirculation loop breaks and main steam line breaks, which are discussed in Section 6.2.1.

3. Verification of reactor shutdown capability - An RHR shutdown cooling suction line break results in a nonisolable blowdown of the reactor vessel into the drywell. The automatic sequence of events that shuts down the reactor and cools the core is discussed in Section 6.3.2.

A combination of pipe whip restraints and separation by distance or intervening structures ensures the availability of essential systems and components in the event of a break in the RHR shutdown cooling suction line.

3.6.1.2.1.12 RHR Shutdown Cooling Return Lines One 12-inch RHR shutdown cooling return line is associated with RHR loop A and a second return line is associated with RHR loop B. The two lines are routed almost symmetrically on opposite sides of the drywell. Each RHR shutdown cooling return line from the discharge 3.6-36 HCGS-UFSAR Revision 0 April 11, 1988

of the associated RHR pump and heat exchanger penetrates the drywell at Elevation 106 feet. Each line is then routed to its connection with the discharge riser of the reactor recirculation loop at Elevation 114 feet 4-1/2 inches. The routing of this piping is shown on Figure 3.6-31.

Each RHR shutdown cooling return line is provided with a motor operated, normally closed, globe type containment isolation valve outside the drywell.

There is also a check valve in each return line inside the drywell. Only that portion of the line between the reactor recirculation line and the inboard check valve is considered high energy.

Each RHR shutdown cooling return line is also provided with pipe whip restraints on the portion of the line inside the drywell. Examples of these restraints are shown on Figure 3.6-1.

1. Pipe break locations - The postulated pipe break locations and the pipe whip restraint locations for the RHR shutdown cooling return lines are shown on Figure 3.6-31. The calculated stress levels, usage factors, and postulated break types are listed in Table 3.6-21.

2. Compartment pressure temperature transients - Since the high energy portion of the RHR shutdown cooling return lines is located entirely within the drywell, a break in one of the lines has no effect on plant areas outside the primary containment. The pressure temperature transient in the primary containment resulting from a break in an RHR shutdown cooling return line is exceeded in severity by the transients resulting from recirculation loop breaks and main steam line breaks, which are discussed in Section 6.2.1.

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3. Verification of reactor shutdown capability - An RHR shutdown cooling return line break results in a nonisolable blowdown of the reactor vessel. The automatic sequence of events that shuts down the reactor and cools the core is discussed in Section 6.3.2.

A combination of pipe whip restraints, and separation by distance or intervening structures ensures the availability of essential systems and components in a event of a break in the RHR shutdown cooling return line.

3.6.1.2.1.13 LPCI Injection Lines There are four 12-inch LPCI injection lines; one is associated with each of the four RHR pumps. The four lines are routed symmetrically inside the drywell, with the A and C injection lines entering the north side of the drywell and the B and D lines entering the south side of the drywell. Each LPCI injection line penetrates the drywell at Elevation 106 feet and is routed up to Elevation 146 feet 3-1/2 inches, where it connects to a reactor vessel nozzle. The routing of this piping is shown on Figure 3.6-32.

Each LPCI injection line is provided with a motor operated, normally closed, gate type containment isolation valves outside the drywell. There is also a check valve in each injection line inside the drywell. Only that portion of the line between the reactor vessel nozzle and the inboard check valve is considered high energy.

Each LPCI injection line is restrained to prevent pipe whip inside the drywell.

Typical pipe whip restraints are shown on Figure 3.6-1.

1. Pipe break locations - The postulated pipe break locations and the pipe whip restraint locations for the LPCI 3.6-38 HCGS-UFSAR Revision 0 April 11, 1988

injection lines are shown on Figure 3.6-32. The calculated stress levels, usage factors, and postulated break types are listed in Table 3.6-22.

2. Compartment pressure temperature transients - Since the high energy portion of the LPCI injection lines is located entirely within the drywell, a break in one of the lines has no effect on plant areas outside the primary containment. The pressure temperature transient in the primary containment resulting from a break in a LPCI injection line is exceeded in severity by the transients resulting from recirculation loop breaks and main steam line breaks, which are discussed in Section 6.2.1.

3. Verification of reactor shutdown capability - A LPCI injection line break results in a nonisolable blowdown of the reactor vessel into the drywell. The automatic sequence of events that shuts down the reactor and cools the core is discussed in Section 6.3.2.

A combination of pipe whip restraints and separation by distance or intervening structures ensures the availability of essential systems and components in the event of a break in a LPCI injection line.

3.6.1.2.1.14 Core Spray Injection Lines There are two core spray injection lines: one associated with core spray pumps A and C, and one associated with core spray pumps B and D. The two lines are routed symmetrically within the drywell. Each core spray injection line penetrates the drywell at Elevation 106 feet 9 inches and is routed up to Elevation 156 feet 7-5/8 inches before connecting to a RPV nozzle. The routing of the piping is shown on Figure 3.6-33.

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Each core spray injection line is provided with a containment isolation valve outside the drywell. There is also a check valve in each injection line inside the drywell. Only that portion of the line between the reactor vessel nozzle and the inboard check valve is considered high energy.

Each core spray injection line is restrained to prevent pipe whip inside the drywell. Typical pipe whip restraints are shown on Figure 3.6-1.

1. Pipe break locations - The postulated pipe break locations and the pipe whip restraint locations for the core spray injection lines are shown on Figure 3.6-33. The calculated stress levels, usage factors, and postulated break types are listed in Table 3.6-23.

2. Compartment pressure temperature transients - Since the high energy portion of the core spray injection line is located entirely within the drywell, a break in one of the lines has no effect on plant areas outside the primary containment. The pressure temperature transient in the primary containment resulting from a break in a core spray injection line is exceeded in severity by the transients resulting from recirculation loop breaks and main steam line breaks, which are discussed in Section 6.2.1.

3. Verification of reactor shutdown capability - A core spray injection line break results in a nonisolable blowdown of the reactor vessel. The automatic sequence of events that shuts down the reactor and cools the core is discussed in Section 6.3.2.

A combination of pipe whip restraints and separation by distance or intervening structures ensures the availability of essential systems and components in the event of a break in a core spray injection line.

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3.6.1.2.1.15 Control Rod Drive Hydraulic System The two CRD drive water pumps are located in the reactor building. The high energy discharge pipes from the two pumps are headered together into a single 2-inch pipe that is routed in the reactor building to the CRD hydraulic system master control station at Elevation 102 feet. From this master control station, a 2-inch cooling water header and a 2-inch charging water header are routed to the hydraulic control units (HCUs) on the north side and south side of the drywell.

1. Pipe break locations - Since the CRD pump discharge line is incapable of maintaining a high energy flow stream, pipe whip and jet impingement are not credible, and no whip restraints are provided. Through wall leakage cracks are examined in accordance with Section 3.6.2.1.2.

Separation by distance and/or intervening structures ensures the availability of essential systems and components in the event of a through wall leakage crack in the control rod drive hydraulic system piping.

2. Compartment pressure temperature transients - Since the normal fluid temperature in the CRD hydraulic system is less than 120°F, no significant pressure temperature transient results from postulated breaks.

3. Verification of reactor shutdown capability - Loss of water pressure due to a break in the CRD pump discharge line, cooling water header, or charging water header does not prevent the control rods from being inserted into the reactor core. Reactor pressure alone is sufficient to fully insert the control rods. At lower reactor pressures, the scram accumulators assist in supplying the energy necessary to insert the control rods.

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3.6.1.2.1.16 Auxiliary Steam Lines Auxiliary steam from the auxiliary boiler is distributed via a 10- and a 16-inch header to the various steam consuming components in the Turbine Building, the radwaste area of the Auxiliary Building, and the Reactor Building. This auxiliary steam header traverses the Auxiliary Building at Elevation 96 feet, passing into the Turbine Building. A 6-inch steam supply line enters the Reactor Building to provide steam for HPCI and RCIC turbine testing at Elevation 73 feet 7-3/8 inches.

1. Pipe break locations - Since the auxiliary steam lines consist of nonnuclear class piping, breaks are postulated to occur at each location of potential high stress, such as pipe fittings, valves, and welded attachments.

2. Compartment pressure temperature transients - The portions of the auxiliary steam lines routed through the Auxiliary Building and the Reactor Building are unpressurized during normal reactor operation.

Pressure temperature transient analyses were not performed.

3. Verification of reactor shutdown capability - An auxiliary steam line break has no effect on operation of the reactor, since reactor systems, including electrical cabling, are not located in areas through which the auxiliary steam lines are routed.

3.6.1.2.1.17 Reactor Vessel Drain Line The 2-inch reactor vessel drain connects to the reactor vessel at Elevation 114 feet 0-1/2 inches. The drain line is routed vertically and horizontally until it penetrates the west side of the reactor pedestal at Elevation 102 feet 9 inches as a 4-inch line. The drain line is routed horizontally south through control and bypass valves and then vertically to Elevation 120 feet 6 inches, 3.6-42 HCGS-UFSAR Revision 0 April 11, 1988

where it ties into the reactor water clean up system, without penetrating the primary containment.

1. Pipe break locations - The postulated pipe break locations for the reactor vessel drain line is shown on Figure 3.6-34. The calculated stress levels, usage factors, and postulated break types are listed in Table 3.6-24.

2. Compartment pressure temperature transients - The pressure transient in the primary containment resulting from a break in the reactor vessel drain line within the drywell is exceeded in severity by transients resulting from recirculation loop breaks and main steam line breaks. The temperature transient in the primary containment resulting from a reactor vessel drain line break is exceeded in severity by the transient resulting from an intermediate size break. These design basis transients are discussed in Section 6.2.1.

3. Verification of reactor shutdown capability - A reactor vessel drain line break inside the drywell results in a nonisolable blowdown of the reactor vessel through the broken line. The automatic sequence of events that shuts down the reactor and cools the core is discussed in Section 6.3.2.

A combination of pipe whip restraints and separation by distance and/or intervening structures is used to ensure the availability of essential systems and components in the event of a reactor vessel drain line break in the drywell.

3.6-43 HCGS-UFSAR Revision 8 September 25, 1996

3.6.1.2.1.18 Reactor Vessel Head Spray Line The head spray line has been removed. However, the analysis of a postulated head spray line break discussed in Appendix 6B bounds the effects of an RPV head vent line break. Therefore, the discussion regarding a postulated head spray line break is still valid.

Compartment pressure temperature transients - Since the high energy portion of the reactor vessel head spray line was located entirely within the drywell, a postulated break in the line has no effect on the plant areas outside the containment. The drywell head region is pressurized by postulated breaks on the head spray line above the containment seal plate. The pressure temperature transient for the drywell head region is discussed in Appendix 6B. The pressure temperature transient in the 3.6-44 HCGS-UFSAR Revision 14 July 26, 2005

remainder of the primary containment resulting from a postulated break in the reactor head spray line is exceeded in severity by transients resulting from recirculation loop breaks and main steam line breaks, which are discussed in Section 6.2.1.

3.6.1.2.1.19 Standby Diesel Generator Starting Air System The 3-inch standby diesel generator starting air line connects to the diesel generator from the starting air skid. There are 4 starting air skids (1 per diesel generator). Each skid is located in the respective diesel generator compartment.

1. Pipe break locations - The postulated pipe break locations and the pipe whip restraint locations for the starting lines are shown on Figure 3.6-48. The calculated stress levels, usage factors, and postulated break types are listed in Table 3.6-29.

For the purposes of pipe break and jet impingement analysis the emergency diesel generator and its associated auxiliaries are considered a single system. As a single system a single failure is only required to be postulated 3.6-45 HCGS-UFSAR Revision 14 July 26, 2005

in one system. Separation of the diesel generator rooms by 18 inch reinforced concrete walls protect other diesel generator units and auxiliaries from damage due to a pipe break in adjacent diesel generator rooms. Therefore, a pipe break in any one of the diesel generator rooms will not affect the remaining diesel generator units and their associated auxiliaries.

All of the air start piping, valves and receivers from the check valve on the air receiver inlet (including the check valve) to the air start solenoid valve on the engine are designed to Seismic Category I, ASME Section III, Class 3, requirements. Refer to Vendor Technical Document PM018Q-0048 for component descriptions.

The compressor, air dryer, and piping up to the air receiver inlet check valve are not built to meet ASME code requirements because they do not serve a safety-related function. The air start valves, air distributors, and the diesel engine cylinders are all pressure retaining parts downstream of the air start solenoid valves which do serve a safety-related function and are non-ASME code items built to Seismic Category I requirements. The air start solenoid pilot valves reduce the starting air pressure to approximately 250 psi, therefore, these components, which are downstream of the air start solenoid pilot valves, are actually located in a moderate energy portion of the system. The non-ASME III pipe in the air-start system is designed to Seismic Category I requirements. These are specialty items that are not available as ASME components but which are built to the SDG manufacturers own critical specifications (see Table 3.2-1, Item XII).

2. Compartment pressure - temperature transients - This high energy line contains compressed air. Therefore, the mass momentum of the high energy line will be lower than the comparable steam system of same pressure and temperature.

3.6-46 HCGS-UFSAR Revision 20 May 9, 2014

Also, the doors of each compartment are not pressure tight and they do not communicate directly with other compartments. As a result, the additional air mass discharged into the compartment will be vented to the corridors on both ends of the compartments and through the HVAC ducts. Therefore, the compartment will not experience room pressurization due to starting air line break.

Also, the safety-related commodities in the room are qualified to operate under the environmental conditions specified in Table 3.11-1C.

3. Verification of reactor shutdown capability - The starting air line break does not directly cause a trip of the turbine generator. Therefore, offsite power is assumed to be available (See Section 3.6.1.1). As a result, normal shutdown sequence will be followed to achieve cold shutdown and the standby diesel generators will not be started or required. The starting air skids are located in the respective diesel generator compartment.

Therefore, the effects of starting air line breaks are confined to the diesel generator compartment which is in the diesel generator area of Auxiliary Building. A combination of pipe whip restraints and separation by distance or intervening structures ensures the availability of essential systems and components in the event of a break in the starting air line. As a result, the safe shutdown equipment located in the Reactor Building will not be affected.

3.6.1.2.2 Moderate Energy Fluid Systems Through wall leakage crack locations are postulated in areas containing essential systems and components in accordance with the criteria stated in Section 3.6.2.1.2. When moderate energy fluid systems share a compartment with safety-related components, the effects of water spray and flooding are reviewed, although pipe 3.6-47 HCGS-UFSAR Revision 0 April 11, 1988

crack locations may not be postulated. When moderate energy fluid systems share a compartment with high energy fluid systems, the water spray and flooding effects resulting from a postulated moderate energy line leakage crack are considered if the effects exceed those resulting from the postulated high energy line break effects.

The moderate energy piping failure review was conducted in the Reactor Building, and diesel and control areas of the Auxiliary Building. The postulated failure of a moderate energy line can at most affect only the operations of one train of a redundant safety-related system due to the provisions for physical separation of redundant trains. Further, for the purpose of this evaluation, it was conservatively assumed that the impacted train failed to perform its safety function. The crack sizes postulated, and the nominal pipe sizes in which moderate energy pipe cracks are postulated to occur, are discussed in Section 3.6.2.1.3.3. Additional criteria used in the moderate energy fluid systems analysis are discussed in Section 3.6.1.1.

A list of moderate energy systems with the normal operating temperature and pressure is provided in Table 3.6-28. The definition of a moderate energy fluid system is stated in Section 3.6.3.3.

Operation of the Standby Diesel Generators (SDG) is not required during the normal plant operating conditions defined in SRP 3.6.1, however, the fuel oil transfer line is pressurized by the static head of the fluid in the line while the SDG is not in operation. During SDG operation, the fuel oil transfer line is pressurized to approximately 47 psig. It is routed from the fuel oil storage tank at elevation 54' through the recirculation ventilation room (see Section 9.4.6) on elevation 77' to the respective fuel oil day tank on elevation 102'. Any cracks in this line would only effect systems associated with the diesel being served by that transfer 3.6-48 HCGS-UFSAR Revision 0 April 11, 1988

line because of SDG compartmentalization. However, a review of the potential fire hazard created by the fluid spray was performed. The fuel oil would have to be heated above its flash point of 125 by any potential ignition source.

The fuel oil transfer pumps at elevation 54' are canned pumps. The ventilation fans are direct drive and completely contained within the distribution ductwork. These units contain no heating coils that could act as potential ignition sources.

3.6.1.3 Safety Evaluation The analyses of postulated pipe ruptures summarized in Section 3.6.2 verify that the consequences of any single rupture of fluid system piping in the plant do not prevent safe shutdown of the reactor.

The offsite radiological consequences of piping ruptures are enveloped by a Reactor Recirculation System break inside the primary containment, and by main steam system and feedwater system breaks outside the primary containment. The radiological consequences of these breaks are presented in Sections 15.6.5, 15.6.4, and 15.6.6, respectively.

Special consideration has been given to separation of areas in the Reactor Building containing essential systems and components from high energy pipe break compartments and the effects of postulated pipe ruptures. HVAC ducts penetrating high energy pipe break compartment walls are equipped with backpressure dampers, while other types of penetrations through the walls are designed as steam tight.

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3.6.2 Determination of Pipe Failure Locations and Dynamic Effects Associated With Postulated Piping Failures Information concerning break and crack location criteria and methods of analysis is presented in this section. The break location criteria and methods of analysis are needed to evaluate the dynamic effects associated with postulated ruptures of high and moderate energy piping inside and outside the primary containment.

3.6.2.1Criteria Used to Determine Pipe Break and Crack Locations and Their Configurations 3.6.2.1.1 Break Locations in High Energy Fluid System Piping The consequences of high energy line cracks have been considered during the review of high energy line breaks. Jet impingement pressure and temperature, pipe whip, environmental effects, etc., for high energy piping system line breaks have been evaluated in accordance with Sections B.1.a and B.1.c of BTP MEB 3-1 (SRP 3.6.2). Due to this review, any pipe failure consequence that could adversely affect the safety of the plant has been considered. This conclusion is based on the following:

1. The criteria in Section B.1.a are invoked whenever possible to separate essential equipment from high energy piping. In this case, breaks are arbitrarily postulated without consideration of stress levels.

2. When it is not possible to separate high energy piping from essential equipment, redundancy is provided or an evaluation is performed to ensure that the equipment will remain operable.

3. In areas in which high energy pipe is routed a sufficient number of breaks have been postulated such that the effects of jet impingement, pipe whip, environment, etc., envelop any postulated leakage crack effects.

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The following discussion shows that for all areas of the plant the existing criterion used to postulate high energy line breaks encompasses the effects of high energy line cracks:

High energy piping outside the reactor building The separation review program ensures that high energy pipes are not routed near systems, components, or structures essential to safe shutdown in areas other than the reactor building. The piping in this area meets the criteria of Section B.1.a where breaks are arbitrarily postulated to ensure separation of high energy piping and essential equipment. It is therefore concluded that cracks in this area will not degrade the safety of the plant.

High energy piping in the reactor building (excluding primary containment and containment penetration areas)

Excluding the main steam tunnel piping, the systems which qualify as high energy piping in the reactor building are the RWCU, CRD, RCIC, and HPCI systems. Routing of the RWCU, RCIC, and HPCI systems has been controlled so that they are located in well defined areas (e.g., pipe chases, pump rooms, torus compartment, etc.). These compartments have also been evaluated for environmental, flood, pressure, etc., effects using the worst-case pipe break condition. Breaks in these areas are postulated as described in this section, to thoroughly encompass the effects of high energy pipe cracks. The CRD system analysis is described in Section 3.6.1.2.1.15. Cracks in the CRD system have been examined at every fitting and change of direction in accordance with Section 3.6.2.1.2. It is therefore concluded that cracks in this area will not degrade the safety of the plant.

The main steam tunnel has numerous postulated pipe breaks. Several other lines also have breaks postulated at every fitting and change of direction. The effects of these postulated pipe breaks in the tunnel will therefore encompass the effects of any pipe cracks that may have been postulated.

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Primary containment: During the pipe break review, in excess of 360 high energy line jets were examined for their consequences. In light of the separation between the high energy systems in the primary containment, it is reasonable to assume that these high energy breaks will always govern. Any equipment, system, or structure in primary containment must be designed for the extreme environment regardless of its particular location. The combination of separation and redundancy (the preferred method of protection) is also integral to components and piping routed in the primary containment. This is verified in the jet impingement evaluation where breaks are postulated at various elevations and azimuths. It is therefore concluded that the effects of pipe cracks in this area are less severe than the effects of high energy pipe breaks, and therefore acceptable.

See Reference 3.6-12 regarding the postulation of intermediate pipe breaks. See Reference 3.6-13 regarding acceptability for elimination of arbitrary intermediate pipe breaks. See References 3.6-14 and 3.6-15 regarding the elimination of additional intermediate pipe break locations.

3.6.2.1.1.1 Piping in Containment Penetration Areas Except for the feedwater system, high energy pipes penetrating the primary containment are provided with valve operability restraints that are located reasonably close to the containment isolation valves and are designed to withstand the loadings resulting from a pipe break either inboard of the inboard isolation valve restraints or outboard of the outboard isolation valve restraints so that neither isolation valve operability nor leaktight integrity of the containment penetration would be impaired as a result of such pipe breaks. Terminal ends of the piping runs extending beyond these portions of high energy piping are considered to originate at a point adjacent to the required valve operability restraints and outboard of the outboard isolation valve operability restraints or inboard of the inboard isolation valve operability restraints.

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Valve operability restraint configuration and break locations of the feedwater system are explained in Section 3.6.1.2.1.3.

Breaks are not postulated in these portions of high energy piping in containment penetration areas provided that the following design stress and fatigue limits are satisfied:

1. For ASME B&PV Code,Section III, Class 1 Piping:

a. The maximum stress range, S , calculated by equation 10 of n

Paragraph NB-3653 of the ASME B&PV Code,Section III, does not exceed 2.4 S for those loads and conditions for which m

normal and upset stress limits have been specified, including an operating basis earthquake (OBE) transient.

b. If the maximum stress range of equation 10 exceeds 2.4 S ,

m the stress ranges calculated by both equation 12 and equation 13 of Paragraph NB-3653 do not exceed 2.4 S .

m

c. The cumulative usage factor associated with normal, upset, and testing conditions is less than 0.1.

d. The loading resulting from a postulated pipe break beyond these portions of the piping does not cause the stress as calculated by equation 9 of Paragraph NB-3652 to exceed 2.25 S , except for the portion of piping between the m

isolation valve and the adjacent restraints protecting the operability of the valve. For this latter portion of piping, higher stresses are permitted, provided that a plastic hinge is not formed and that the operability of the isolation valve is ensured.

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2. For ASME B&PV Code,Section III, Class 2 and 3 Piping:

a. The maximum stress range, as calculated by the sum of equations 9 and 10 of Paragraph NC-3652, considering normal and upset plant conditions, does not exceed 0.8 (1.2 S + S h A

).

b. The maximum stress, as calculated by equation 9 of Paragraph NC-3652, under the loadings resulting from a postulated rupture of fluid system piping beyond these portions of piping, does not exceed 1.8 S . Higher stresses h

are permitted in pipe between the outboard isolation valve and the adjacent restraints protecting the operability of the valve, provided that:

(1) All circumferential and longitudinal welds in that pipe region are fully radiographed (2) Analysis shows that a plastic hinge is not formed and that the operability of the valve is ensured.

In addition to these stress and fatigue criteria, high energy piping in containment penetration areas must meet the following requirements:

1. Welded pipe support attachments are avoided to eliminate stress concentrations.

2. The number of circumferential and longitudinal pipe welds and branch connections is minimized.

3. The length of the piping run is minimized, consistent with requirements to keep stress levels low and to provide access for inservice inspection.

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4. The design at points of pipe anchors, welded connections, and containment penetrations does not require welding directly to the outer surface of the piping (flued, integrally forged pipe fittings are acceptable), except where such welds are 100 percent volumetrically examinable inservice and a detailed stress analysis is performed to demonstrate compliance with the limits of the stress and fatigue criteria stated above.

5. To the extent practicable, the inservice examination completed during each inspection interval will provide volumetric examination of circumferential and longitudinal pipe welds within these portions of piping, as required by ASME B&PV Code,Section XI. See Sections 5.2.4 and 6.6 for additional information.

6. When a no-break region is established, the terminal end for piping in the region is consequently shifted away from the containment anchor. The terminal end is located adjacent to the pipe whip restraints that limit the bending and torsion moments exerted on the isolation valve as a consequence of pipe break. These restraints are:

a. Located reasonably close to the isolation valves

b. Capable of withstanding the loadings resulting from postulated pipe rupture beyond this portion of the piping such that neither valve operability nor the leaktight integrity of the primary containment is impaired.

7. Operability of the isolation valve is ensured for pipe break events where it is required to ensure primary containment integrity.

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The main steam and the main feedwater lines are conservatively designed in accordance with the criteria stated above. However, for additional conservatism, the enclosure for the main steam and main feedwater lines is also designed for the effects of pressurization, flooding, and the environment resulting from the single area crack of either the main steam or main feedwater lines. The nonmechanistic single area pipe crack of the main steam or main feedwater lines is postulated to occur either upstream or downstream of the outboard containment isolation valves. Safety-related equipment in the enclosure is environmentally qualified for the pressure, temperature, radiation, humidity, and flooding resulting from the worst case, single area pipe crack.

A mechanistic double-ended break of the largest branch line of the feedwater system is also postulated to occur within this enclosure. The effects of pipe whip, jet impingement, pressurization, and flooding due to the branch line break are considered in the evaluation of the enclosure design adequacy.

3.6.2.1.1.2 Recirculation System Piping See Section 3.6.2.6 for a discussion of recirculation system piping.

3.6.2.1.1.3 Class 1 Piping (Other Than Recirculation System Piping and Piping in Containment Penetration Areas)

Breaks in high energy Class 1 piping (ASME B&PV Code, Section III) are postulated to occur at the following locations:

1. At terminal ends of piping runs or branch runs

2. At intermediate locations between terminal ends, as determined by one of the two following criteria:

3.6-56 HCGS-UFSAR Revision 0 April 11, 1988

a. The maximum range of stress intensity as calculated by ASME B&PV Code equation 10 and either equation 12 or 13 exceeds 2.4 S .

m

b. The cumulative usage factor exceeds 0.1.

When the above stress and usage factor criteria are not exceeded, the minimum of two intermediate breaks based on highest stress, as calculated by Equation 10 of Paragraph NB-3653, are not postulated unless the break location is in the proximity of a welded attachment.

Intermediate pipe break locations are initially based upon committed design piping stress calculations in accordance with the above criteria.

As a result of piping reanalysis, the highest stress locations may be shifted. An initially determined pipe break location will not be changed as a consequence however unless one of the following conditions exist:

1. Reanalysis shows that the maximum stress range or the cumulative usage factor at another location not only exceeds that for the initial pipe break location but also exceeds the above pipe break criteria. In addition, the break at the new location results in more serious consequences to safety-related systems than the initial break.

2. Significant changes are made in the routing, size, or wall thickness of the pipe after the initial pipe break determination.

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3.6.2.1.1.4 Class 2 and 3 Piping (Other Than Recirculation System Piping and Piping in Containment Penetration Areas)

Breaks in high energy Class 2 and 3 piping (ASME B&PV Code,Section III) are postulated to occur at the following locations:

1. At terminal ends of piping runs or branch runs

2. At intermediate locations between terminal ends, as determined by one of the two following criteria:

a. At each location of potential high stress, such as pipe fittings with elbows, tees, reducers, etc; valves; and welded attachments

b. At each location where the maximum stress range, as calculated by the sum of equations 9 and 10 of Paragraph NC-3652, considering normal and upset plant conditions, exceeds 0.8(1.2 S + S ).

h A When the above stress criteria are not exceeded, the minimum of two intermediate breaks based on highest stress, as calculated by the sum of Equations 9 and 10 of Paragraph NC-3652, are not postulated unless the break location is in the proximity of a welded attachment.

Intermediate pipe break locations are initially based upon committed design piping stress calculations in accordance with the above criteria. As a result of piping reanalysis, the highest stress locations may be shifted. An initially determined pipe break location will not be changed as a consequence, however, unless one of the following conditions exist:

1. Reanalysis shows that the maximum stress range at another location not only exceeds that for the initial pipe break location but also exceeds the 3.6-58 HCGS-UFSAR Revision 0 April 11, 1988

above pipe break criteria. In addition, the break at the new location results in more serious consequences to safety-related systems than the initial break.

2. Significant changes are made in the routing, size, or wall thickness of the pipe after the initial pipe break determination.

3.6.2.1.1.5 Nonnuclear Class Piping Breaks in high energy nonnuclear class piping are postulated to occur at the following locations:

1. At terminal ends of piping runs or branch runs

2. At each intermediate location of potential high stress, such as pipe fittings with elbows, tees, reducers, etc; valves; and welded attachments.

Alternatively, the break locations for nonnuclear class piping can be selected according to the same criteria used for Class 2 and 3 piping, provided that all necessary analyses are made.

3.6.2.1.2 Crack Locations in Moderate Energy Fluid System Piping Through wall leakage cracks are postulated to occur in moderate energy piping located in areas containing essential systems and components. Cracks are postulated to occur in accordance with either of the two following criteria:

1. At locations of potential high stress, such as pipe fittings with elbows, tees, reducers, etc; valves; and welded attachments

2. For Class 1 piping (ASME B&PV Code,Section III), at locations where the maximum stress range, as calculated by equation 10 of Paragraph NB-3652, exceeds 1.2 S , and for m

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Class 2 or 3 piping (ASME B&PV Code,Section III) or nonnuclear piping, at locations where the maximum stress range, as calculated by the sum of equations 9 and 10 of Paragraph NC-3652, exceeds 0.4 (1.2 S + S ).

h A The above criteria notwithstanding, cracks are not postulated in those portions of moderate energy piping located in the following areas:

1. Areas in which high energy pipe breaks are postulated, provided that moderate energy piping cracks would not result in more severe environmental conditions than the high energy pipe breaks.

2. Between containment isolation valves, provided that:

a. The piping meets the requirements of Subarticle NE-1120 of the ASME B&PV Code,Section III

b. The maximum stress range for Class 1 piping (ASME B&PV Code,Section III), as calculated by equation (10) of Paragraph NB-3652, does not exceed 1.2 S , and the maximum stress range m

for Class 2 and 3 (ASME B&PV Code,Section III) or nonnuclear piping, as calculated by the sum of equations 9 and 10 of Paragraph NC-3652, does not exceed 0.4 (1.2 S + S ).

h A 3.6.2.1.3 Types of Breaks and Cracks in Fluid System Piping 3.6.2.1.3.1 Circumferential Breaks A circumferential break is assumed to result in both:

1. Severance of a high energy pipe on a plane perpendicular to the pipe axis 3.6-60 HCGS-UFSAR Revision 0 April 11, 1988

2. Separation amounting to at least a one-diameter lateral displacement of the ruptured piping ends, unless physically limited by piping restraints, structural members, or piping stiffness. Pipe whipping is assumed to occur in the plane defined by the piping geometry and configuration and to cause pipe movement in the direction of the jet reaction.

Circumferential breaks are postulated in high energy fluid system piping of nominal pipe size greater than 1 inch, at the locations determined by the criteria listed in Section 3.6.2.1.1, except where it can be shown that the maximum stress is in the circumferential direction and is at least 1.5 times the longitudinal stress, in which case a longitudinal break is postulated in pipes of nominal pipe sizes 4 inches and larger.

3.6.2.1.3.2 Longitudinal Breaks A longitudinal break is assumed to result in an axial split parallel to the pipe axis, without causing pipe severance. The break opening area is assumed to be equal to the effective cross-sectional flow area of the pipe at the break location. The split is assumed to be oriented so that the jet reaction force causes out of plane bending of the piping configuration. Piping movement is assumed to occur in the direction of the jet reaction unless limited by piping restraints, structural members, or piping stiffness.

Longitudinal breaks are postulated in high energy fluid system piping of nominal pipe sizes 4 inches and larger, at the locations determined by the criteria listed in Section 3.6.2.1.1, with the following exceptions.

Longitudinal breaks are not postulated:

1. At terminal ends 3.6-61 HCGS-UFSAR Revision 0 April 11, 1988

2. At intermediate break locations chosen to satisfy the criterion for a minimum number of break locations

3. At locations where the criteria of Section 3.6.2.1.1 are not satisfied, but it is shown that the maximum stress is in the longitudinal direction and is at least 1.5 times the circumferential stress, in which case only circumferential breaks are postulated.

3.6.2.1.3.3 Through Wall Leakage Cracks Through wall leakage cracks are postulated to occur in moderate energy fluid system piping exceeding a nominal pipe size of 1 inch, at the locations determined by the criteria listed in Section 3.6.2.1.2. A crack is assumed to occur at any orientation about the circumference of a pipe. Fluid flow from a crack is based on a circular opening with an area equal to that of a rectangle one half the pipe diameter in length and one half the pipe wall thickness in width.

3.6.2.2 Analytical Models to Define Forcing Functions and Response Models 3.6.2.2.1 Recirculation Piping System See Section 3.6.2.6.2 for a discussion relating to the Recirculation Piping System.

3.6.2.2.2 Piping Systems Other Than The Recirculation Piping System Analysis to determine the jet impingement effects and the piping and restraint displacements resulting from a pipe break are performed in general accordance with Reference 3.6-7. Analysis of jet thrust forces is described in Section 2.2 of Reference 3.6-7. Fluid jet impingement forces are discussed in Section 2.3 of Reference 3.6-7.

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Impulsive loading and impact combined with impulsive loadings are described in Sections 3.2 and 3.3, respectively, of Reference 3.6-7.

Piping response to pipe break loads are analyzed by various methods, applied in the appropriate circumstances. These methods include energy balance, lumped parameter and non-linear time history analysis models. The forcing function used in piping dynamic analysis is obtained using Reference 3.6-8. A typical pipe break forcing function and piping system model used for the dynamic response analysis are provided on Figure 3.6-38. Pipe rebound effects are also considered in this analysis.

Two different types of pipe break whip design problems are addressed. The first type of problem is to ensure the operability of containment isolation valves and the leaktight integrity of the primary containment following any postulated pipe break. The second type of problem is to ensure that pipe whip resulting from postulated breaks is controlled sufficiently to prevent damage to adjacent safety-related systems.

Valve operability and primary containment integrity is verified by dynamic analysis of the piping system in the containment penetration area under the conditions imposed by pipe break outside that region, beyond the moment limiting restraints near the isolation valve. The bases for ensuring valve operability are as follows:

1. For the postulated pipe break, pipe stress at the junction with the isolation valve does not exceed 1.1 times the static minimum yield strength.

2. Rigid restraints intended for ensuring valve operability do not exceed their pipe break design load.

3. Piping in the containment penetration area exceeds the limits of neither Section 3.6.2.1.1.1.(1.d) for ASME 3.6-63 HCGS-UFSAR Revision 0 April 11, 1988

Class 1 pipe nor Section 3.6.2.1.1.1.(2.a) for Class 2 or 3 pipe.

4. Valve operator peak acceleration, in multiples of gravity, does not exceed the fundamental frequency of the acceleration response, in hertz.

5. Pipe restraints designed for normal operation design load events are assumed to contribute no pipe break restraint.

Protection of essential systems against uncontrolled pipe whip resulting from postulated breaks is ensured by pipe whip restraints, which are located so as to most effectively limit abnormal pipe movement. Pipe whip restraints are designed to permit free pipe movement during normal design events, but to limit the pipe break whip to acceptable movements. The pipe whip restraints are designed to provide the strength, stiffness, and pipe whip energy absorption capacity needed to limit pipe motion. The bases for design and dynamic analysis to control pipe break whipping motion are:

1. The postulated pipe break is permitted to cause neither pipe whip restraint failure nor pipe whip motion threatening to an essential system.

2. The loading condition of a piping system prior to postulated rupture, in terms of pressure, temperature, and stress state, is that condition associated with reactor operation at 100 percent of power.

3. Dynamic analytical methods used for calculating the piping/restraint system response to the pipe break forces adequately account for the effects of the following:

a. Pipe mass, stiffness, and resistance to dynamic plastic hinge formation and propagation 3.6-64 HCGS-UFSAR Revision 0 April 11, 1988

b. Pipe whip restraint resistance to pipe impact in terms of stiffness, yield strength, and impact energy absorption

c. Transient time history of the pipe break blowdown forces acting on the exit leg of the pipe rupture

d. The requirement for clearance between pipe and pipe whip restraint during any normal design event.

4. Plastic deformation design limit for structural members of pipe whip restraints is limited to the ductility ratio of the system. A ductility ratio limit equal to 20 is used for compression, flexure, and shear. A review of the design of structural steel beams in flexure, for loads other than tornado, indicates that the demands for ductility ratios are less than 10. The ductility ratio of 50 percent of ultimate strain divided by yield strain is used for tension members. The members are proportioned to preclude lateral and local buckling.

3.6.2.2.2.1 RELAP4/MOD5 A lumped parameter model simulates the ruptured piping system for input into the computer code RELAP4/MOD5, as discussed in Reference 3.6-2. The code computes time, varying pressure, momentum flux, and mass acceleration throughout a system containing water, steam, and/or a two phase mixture. From these data, the blowdown reaction load is computed by a postprocessor REPIPE, discussed in Reference 3.6-10, using the following relations:

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(3.6-1)

FM t

u . m (dV g . mdV

[Ponouo( ouono)]. mdSo Si[Pi ni ui ( i ui. ni)]. mdSi where:

F = total resultant force acting on pipe m = unit vector in the direction of force V = volume of RELAP4 control volume u = unit vector in direction of local fluid velocity q = mass density of fluid S = control volume surface o = subscript for outlet n = unit vector in the direction of positive flow i = subscript for inlet p = pressure.

3.6.2.3 Dynamic Analysis Methods to Verify Integrity and Operability 3.6.2.3.1 Recirculation Piping System See Section 3.6.2.6.3 for a discussion of the Recirculation Piping System.

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3.6.2.3.2 Piping Systems Other Than The Recirculation Piping System The pipe break restraints provided for protection from high energy pipe breaks are of two basic types: pipe whip restraints and valve operability restraints.

Pipe whip restraints are provided solely to protect nearby structures and essential equipment from damage due to whipping pipes and are designed so that a gap is maintained between the pipe and the restraint during normal plant conditions. Valve operability restraints are provided near primary containment isolation valves whose operability is required following a break of the pipe in which they are installed. These operability restraints are designed to limit the stress in the piping near the valve to below the dynamic yield strength of the material in order to ensure operability of the valve. To accomplish this function, it is normally necessary to minimize the gap between the pipe and the restraint so that contact occurs during normal plant conditions.

3.6.2.3.2.1 Design Loading Combinations The design loading combinations applied in the design of restraints are categorized with respect to the plant operating conditions, which are identified as normal, upset, emergency, and faulted, as described in Section 3.9.3. Pipe break is considered as a faulted plant condition for those piping systems remaining intact. For the high energy piping system in which the break has occurred, the ASME B&PV Code,Section III categorization of operating conditions no longer controls the design.

3.6.2.3.2.2 Design Stress Limits 3.6.2.3.2.2.1 Valve Operability Restraints When restraints for piping are designed so that contact between pipe and restraint will occur during normal plant conditions, the design loading combinations for normal, upset, emergency, and faulted 3.6-67 HCGS-UFSAR Revision 0 April 11, 1988

conditions are applicable to pipe without rupture. In evaluating the supports and restraints for normal operation of pipe Classes 1, 2, and 3 (ASME B&PV Code,Section III), the design stress limits applied in evaluating loading combinations for normal, upset, emergency, and faulted (except for pipe rupture) conditions are those given in Tables 3.9-9 and 3.9-13. After rupture of the supported pipe occurs, the piping system is no longer within the jurisdiction of the ASME B&PV Code,Section III, because the pressure boundary has been breached. The restraints are evaluated for pipe rupture loads as described in Section 3.6.2.2.2.

3.6.2.3.2.2.2 Pipe Whip Restraints When restraints are designed solely to control pipe whip movement following a postulated pipe rupture and to function independently of the normal support system, only the design pipe rupture loads are applicable.

To ensure that pipe whip restraints function independently of the normal support system, the motions of the intact pipe due to all normal and upset plant conditions and the vibratory motion of the safe shutdown earthquake (SSE) are calculated and used to specify a minimum clearance between the pipe and the restraint. Wherever possible, gaps between pipes and restraints are maximized to avoid possible contact during plant operation. Where a particular location requires minimizing a gap, shims are provided to permit adjustment of the gap size during hot functional testing.

Pipe whip restraints are evaluated for the pipe rupture loads as described in Section 3.6.2.2.2.

3.6.2.4 Guard Pipe Assembly Design Criteria Guard pipe assemblies are not used at HCGS.

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3.6.2.5 Material to be Submitted for the Operating License Review Pipe break and crack locations were obtained in accordance with the criteria of Section 3.6.2.1. High energy piping break locations as well as break types, circumferential or longitudinal, are identified on piping isometric drawings provided in Section 3.6.1 and referenced in Section 3.6.1.2.1.

The augmented inservice inspection requirement is described in Section 6.6.

Pipe whip restraints were designed as discussed in Section 3.6.2.3. The restraint locations and orientations are shown on various figures referenced in Section 3.6.1.2.1. Jet thrust and impingement forces were determined in accordance with Sections 3.6.2.2 and 3.6.2.3.

The effects of breaks and cracks are discussed in detail in Section 3.6.1. The results are based on the protection evaluation criteria provided in Section 3.6.1. Any protection measures to ensure safe shutdown, i.e, barriers, separation, and restraints, are also discussed.

3.6.2.6 Determination of Break Locations and Dynamic Effects Associated with the Postulated Rupture of Recirculation System Piping (NSSS) 3.6.2.6.1 Criteria Used to Define Break Location and Configuration The following section establishes the criteria for the location and configuration of postulated breaks.

3.6.2.6.1.1 Definition of High Energy Fluid System High energy fluid systems are defined to be those systems, or portions of systems, that during normal plant conditions are either in operation or are maintained pressurized under conditions where either one or both of the following are met:

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1. Maximum operating temperature exceeds 200F

2. Maximum operating pressure exceeds 275 psig.

The recirculation piping system is a high energy fluid system designed to the ASME Boiler and Pressure Vessel (B&PV) Code,Section III, Class 1 requirements.

No portion of the recirculation piping system is a moderate energy fluid system.

Normal plant conditions are defined as the plant operating conditions during reactor startup, operation at power, hot standby, or reactor cooldown to a cold shutdown condition.

3.6.2.6.1.2 Postulated Pipe Breaks A postulated pipe break is defined as a sudden, gross failure of the pressure boundary either in the form of a complete circumferential severance (guillotine break) or as the development of a sudden, longitudinal break and is postulated for high energy fluid systems only.

The following high energy piping systems or portions of piping systems are considered to have a potential for initiation of a postulated pipe break during normal plant conditions and are analyzed for potential damage due to dynamic effects:

1. All piping that is part of the RCPB and subject to reactor pressure continuously during plant operation

2. All piping that is beyond the second isolation valve, but that is subject to reactor pressure continuously during plant operation

3. In addition to piping under 1. and 2., all other piping systems or portions of piping systems considered high energy systems.

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Portions of piping systems that are isolated from the source of the high energy fluid during normal plant conditions are exempted from consideration of postulated pipe breaks. This would include portions of piping systems beyond a normally closed valve. Pump and valve bodies are also exempted from consideration of pipe break because of their greater wall thickness.

A high energy piping system break is neither postulated to occur simultaneously with a moderate energy piping system break nor is any pipe break outside primary containment postulated to occur concurrently with a postulated pipe break inside primary containment.

3.6.2.6.1.3 Exemptions from Pipe Whip Protection Requirements Protection from pipe whip need not be provided if any one of the following conditions exist:

1. Following a single postulated pipe break, piping for which the unrestrained movement of either end of the ruptured pipe in any feasible direction about a plastic hinge, formed within the piping, cannot impact any structure, system, or component important to safety.

2. Piping for which the internal energy level associated with whipping is insufficient to impair the safety function of any structure, system, or component to an unacceptable level. Any line restrictions, e.g., flow limiters, between the pressure source and break location, and the effects of either a single ended or double ended flow condition, are accounted for in the determination of the internal fluid energy level associated with the postulated pipe break reaction. The energy level in a whipping pipe is considered as insufficient to rupture an impacted pipe of equal or greater nominal pipe size and equal or heavier wall thickness.

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3.6.2.6.1.4 Location for Postulated Pipe Breaks Postulated pipe break locations are selected in accordance with the intent of Regulatory Guide 1.46, the U.S. Nuclear Regulatory Commission (NRC) Branch Technical Position (BTP) APCSB 3-1, Appendix B, and as expanded in NRC Branch Technical Position MEB 3-1. For ASME B&PV Code,Section III, Class 1 piping systems which are classified as high energy, the postulated break locations are:

1. The terminal ends of the pressurized portions of the pipe run.

Terminal ends are extremities of piping runs that connect to structures, equipment, or pipe anchors that act as rigid constraints to piping motion and thermal expansion. A branch connection to a main piping run is a terminal end for a branch run, except when the branch and main run is modeled as a common piping system during the piping stress analysis.

2. At intermediate locations between the terminal ends where the maximum stress range between any two load sets, including the zero load set, according to Subarticle NB-3600 of the ASME B&PV Code,Section III, for upset plant conditions and an independent OBE event transient, exceeds the following:

a. If the stress range, as calculated using equation 10 of the ASME B&PV Code exceeds 2.4 S but is not greater than 3 S ,

m m no breaks are postulated unless the cumulative usage factor exceeds 0.1.

b. The stress ranges, as calculated by equations 12 or 13 of the ASME B&PV Code, exceed 2.4 S or if the cumulative usage m

factor exceeds 0.1 when equation 10 exceeds 3 S .

m 3.6-72 HCGS-UFSAR Revision 0 April 11, 1988

3. When the above stress and usage factor criteria are not exceeded, the minimum of the two intermediate breaks based on highest stress, as calculated by Equation 10 of Paragraph NB-3653, are not postulated, unless the break location is in the proximity of a welded attachment.

3.6.2.6.1.5 Types of Breaks to be Postulated in Fluid System Piping The following types of breaks are postulated in high energy fluid system piping:

1. No breaks need be postulated in piping having a nominal diameter less than or equal to 1 inch.

2. Circumferential breaks are postulated only in piping exceeding a 1-inch nominal pipe diameter.

3. Longitudinal breaks are postulated only in piping having a nominal diameter equal to or greater than 4 inches.

4. Circumferential breaks are to be assumed at all terminal ends. At each of the intermediate postulated break locations identified to exceed the stress and usage factor limits of the criteria in Section 3.6.2.6.1.4 for Class 1 piping systems, either a circumferential or a longitudinal break, or both, are postulated per the following:

a. Circumferential breaks are postulated at fitting joints.

b. Longitudinal breaks are postulated in the center of the fitting at two diametrically opposed points (but not concurrently) located so that the reaction force is perpendicular to the plane of the piping and produces out of plane bending.

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c. Consideration is given to the occurrence of either a longitudinal or circumferential break. Examination of the state of stress in the vicinity of the postulated break location may be used to identify the most probable type of break. If the maximum stress range in the longitudinal direction is greater than 1.5 times the maximum stress range in the circumferential direction, only the circumferential break may be postulated, and conversely if the maximum stress range in the circumferential direction is greater than 1.5 times the stress range in the longitudinal direction, only the longitudinal break may be postulated. If no significant difference between the circumferential and longitudinal stresses is determined, then both types of breaks are considered.

5. For design purposes, a longitudinal break area is assumed to be the equivalent of one circumferential pipe area, unless analytical methods representing test results can conservatively reduce forces based on a mechanistic approach.

6. For both longitudinal and circumferential breaks, after assessing the contribution of upstream piping flexibilities, pipe whipping is assumed to occur in the plane defined by the piping geometry and configuration for circumferential breaks and out of plane for longitudinal breaks, and to cause pipe movement in the direction of the jet reaction.

7. For a circumferential or longitudinal break, the dynamic force of the jet discharge at the break location is based upon the effective cross-sectional flow area of the pipe and on a calculated fluid pressure as modified by an analytically or experimentally determined thrust 3.6-74 HCGS-UFSAR Revision 0 April 11, 1988

coefficient. Justifiable line restrictions, flow limiters, and the absence of energy reservoirs are taken into account, as applicable, in the reduction of the jet discharge.

3.6.2.6.2 Analytical Methods to Define Blowdown Forcing Functions and Response Models 3.6.2.6.2.1 Analytical Methods to Define Blowdown Forcing Functions Rupture of a pressurized pipe causes the flow characteristics of the system to change, creating reaction forces that can dynamically excite the piping system.

The reaction forces are a function of time and space and depend upon the fluid state within the pipe prior to the rupture, the break flow area, frictional losses, plant system characteristics, piping system, and other factors. The methods used to calculate the reaction forces are presented in the following sections.

3.6.2.6.2.1.1 Criteria The following criteria are used for calculation of fluid blowdown forcing functions:

1. Circumferential breaks are assumed to result in pipe severance and separation amounting to at least a one pipe diameter lateral displacement of the ruptured piping sections, unless physically limited by piping restraints, structural members, or piping stiffness, as may be demonstrated by the inelastic pipe whip analysis discussed in Section 3.6.2.2.2.

2. For circumferential breaks, the dynamic force of the jet discharge at the break location is based on the effective cross-sectional flow area of the pipe and on a calculated fluid pressure as modified by an analytically or 3.6-75 HCGS-UFSAR Revision 0 April 11, 1988

experimentally determined thrust coefficient. Justifiable line restrictions, flow limiters, positive pump controlled flow, and the absence of energy reservoirs are taken into account, as applicable, in the reduction of the jet discharge.

3. A rise time not exceeding 1 millisecond is used for the initial pulse, unless longer crack propagation times or rupture opening times are substantiated by experimental data or analytical theory.

3.6.2.6.2.1.2 Forcing Functions The predicted blowdown forces on pipes fed by a pressurized vessel can be described by transient (time dependent) and steady state forcing functions. The forcing functions used are based on methods described in Reference 3.6-4. These may be simply described as follows:

1. The transient forcing functions occur at points along the pipe from the propagation of waves (wave thrust) along the pipe and, at the broken end, from the reaction force due to the momentum of the fluid leaving the end of the pipe (blowdown thrust).

2. The waves cause various sections of the pipe to be loaded with time dependent forces. It is assumed that the pipe is one dimensional, in that there is no attenuation or reflection of the pressure waves at bends, elbows, and the like. Following the rupture, a decompression wave is assumed to travel from the break at a speed equal to the local speed of sound within the fluid. Wave reflections occur at the break end and at the pressure vessel end until a steady flow condition is established. Free space and vessel conditions are used as boundary conditions. The blowdown thrust causes a time dependent reaction force 3.6-76 HCGS-UFSAR Revision 0 April 11, 1988

perpendicular to the pipe break that reaches a final steady state value.

3. The initial blowdown force on the pipe is taken as the sum of the wave and blowdown thrusts and is equal to the vessel pressure (P )

0 times the break area (A). After the initial decompression period, i.e., the time it takes for a wave to reach the first change in direction, the force is assumed to drop off to the value of the blowdown thrust, i.e., 0.7 P A.

0

4. Time histories of transient pressure, flow rate, and other thermodynamic properties of the fluid can be used to calculate the blowdown force on the pipe using the following equation:

A u2 F = (P - Pa) + (3.6.2) gc where in any consistent set of units:

F = blowdown force P = pressure at exit plane P = ambient pressure u = velocity at exit plane q = density at exit plane A = area of break g = Newton's gravitational constant c

5. Following the transient period, a steady state period is assumed to exist. Steady state blowdown forces are calculated considering frictional effects. For the recirculation system, these effects reduce the blowdown forces from the theoretical maximum of 1.26 P A.

0 The 3.6-77 HCGS-UFSAR Revision 0 April 11, 1988

method of accounting for these effects is presented in Reference 3.6-4.

For subcooled water, a reduction from the theoretical maximum of 2.0 P A 0

is found through the use of Bernoulli's equation and standard equations, such as Darcy's equation, which account for friction.

3.6.2.6.2.2 Pipe Whip Dynamic Response Analyses The prediction of time dependent and steady thrust reaction loads, caused by the blowdown of subcooled, saturated, and two phase fluid from a ruptured pipe, is used in the design and evaluation of dynamic effects of pipe breaks. A detailed discussion of the analytical methods employed to compute these blowdown loads is given in Section 3.6.2.6.2.1.

The following criteria are used for performing the pipe whip dynamic response analyses:

1. A pipe whip analysis is performed for each postulated pipe break.

However, a given analysis can be used for more than one postulated break location if the blowdown forcing function, piping and restraint system geometry, and piping and restraint system properties are conservative for other break locations.

2. The analysis includes the dynamic response of the pipe components and the pipe whip restraints which transmit loading to the structures.

3. The analytical model adequately represents the mass/inertia and stiffness properties of the system.

4. Pipe whipping is assumed to occur in the plane defined by the piping geometry and configuration and to cause pipe movement in the direction of the jet reaction.

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5. Piping contained within the broken loop is no longer considered part of the RCPB. Plastic deformation in the pipe is considered as a potential energy absorber. A limit of strain is imposed on the pipe material.

6. Components such as vessel safe ends and valves, which are attached to the broken piping system and do not serve a safety function or whose failure would not further escalate the consequences of the accident, are not designed to meet ASME B&PV Code imposed limits for essential components under faulted loading. However, if these components are required for safe shutdown or if they serve a safety function to protect the structural integrity of an essential component, limits to meet the ASME B&PV Code requirements for faulted conditions and limits to ensure operability, if required, are met.

The pipe whip analysis is performed using the pipe dynamic analysis (PDA) computer program discussed in Reference 3.6-5. PDA is a computer program used to determine the response of a pipe subjected to the thrust force occurring after a pipe break. The program treats the situation in terms of a generic pipe break configuration, which involves a straight, uniform pipe fixed at one end and subjected to a time dependent thrust force at the other end. A typical restraint used to reduce the resulting deformation is also included at a location between the two ends. Nonlinear and time independent stress strain relations are used for the pipe and the restraint. Similar to the popular plastic hinge concept, bending of the pipe is assumed to occur only at the fixed end and at the location supported by the restraint.

Shear deformation is also neglected. The pipe bending moment deflection (or rotation) relation used for these locations is obtained from a static, nonlinear, cantilever beam analysis. Using the moment rotation relation, nonlinear equations of motion of the pipe are formulated using an energy consideration, and the equations 3.6-79 HCGS-UFSAR Revision 0 April 11, 1988

are numerically integrated in small time steps to yield time-history information of the deformed pipe.

A comprehensive verification program has been performed to demonstrate the conservatisms inherent in the PDA pipe whip computer program and the analytical methods used. Part of this verification program included an independent analysis by Nuclear Services Corporation (NSC), under contract to General Electric Company (GE), of the recirculation piping system for the 1969 Standard Plant Design. The recirculation piping system was chosen for study due to its complex piping arrangement and assorted pipe sizes. The NSC analysis included elastic plastic pipe properties, elastic plastic restraint properties, and gaps between the restraint and pipe, and is documented in Reference 3.6-6. The piping/restraint system geometry and properties and fluid blowdown forces were the same in both analyses. However, a linear approximation was made by NSC for the restraint load deflection curve supplied by GE. This approximation is demonstrated on Figure 3.6-36. The effect of this approximation is to give lower energy absorption of a given restraint deflection. Typically, this yields higher restraint deflections and lower restraint to structure loads than the GE analysis. The deflection limit used by NSC is the design deflection at one-half of the ultimate uniform strain for the GE restraint design. The restraint properties used for both analyses are provided in Table 3.6-26.

A comparison of the NSC analysis with the PDA analysis, as presented in Table 3.6-27 and on Figure 3.6-37, shows that PDA predicts higher loads in 15 of the 18 restraints analyzed. This is due to the NSC model including energy absorbing effects in secondary pipe elements and structural members. However, PDA predicts higher restraint deflections in 50 percent of the restraints. The higher deflections predicted by NSC for the lower loads are caused by the linear approximation used for the force deflection curve rather than by differences in computer techniques. This comparison demonstrates that the simplified modeling system used in PDA is adequate for pipe 3.6-80 HCGS-UFSAR Revision 0 April 11, 1988

rupture loading, restraint performance, and pipe movement predictions within the meaningful design requirements for these low probability postulated accidents.

3.6.2.6.3 Dynamic Analysis Methods to Verify Integrity and Operability This section provides the criteria and methods used to evaluate the effects of pipe displacements on safety-related structures, systems, and components following a postulated pipe rupture.

3.6.2.6.3.1 Pipe Whip Effects Following a Postulated Pipe Rupture.

Pipe whip (displacement) effects on safety-related structures, system, and components can be placed in two categories:

1. Pipe displacement effects on components, e.g., nozzles, valves, tees, etc, that are in the same piping run in which the break occurred.

2. Pipe whip or controlled displacements onto external components, e.g.,

building structure, other piping systems, cable trays and conduits, etc.

The criteria which are used for determining the effects of pipe displacements on in-line components are as follows:

1. Components such as vessel safe ends and valves that are attached to the broken piping system and do not serve a safety function, or whose failure would not further escalate the consequences of the accident, need not be designed to meet the limits for essential components under faulted loading imposed by the ASME B&PV Code,Section III.

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2. If these components are required for safe shutdown or serve a safety function to protect the structural integrity of an essential component, limits to meet the ASME B&PV Code requirements for faulted conditions and limits to ensure operability, if required, are met.

The methods used to calculate the pipe whip loads on piping components in the same run as the postulated break are described in Section 3.6.2.6.2.2.

3.6.2.6.3.2 Loading Combinations and Design Criteria for Pipe Whip Restraints Pipe whip restraints, as differentiated from piping supports, are designed to function and carry the load from an extremely low probability gross failure in a piping system carrying high energy fluid. The piping integrity does not depend on the pipe whip restraints for any loading combination. If the piping integrity is lost because of a postulated break, the pipe whip restraint acts to limit the movement of the broken pipe to an acceptable distance. The pipe whip restraints, i.e., those devices which serve only to control the movement of a ruptured pipe following gross failure, will be subjected to a once in a lifetime loading. The pipe break event is considered to be an accident condition for the ruptured pipe, its restraints, and structure to which the restraint is attached. The design and analysis of these components for this event are performed specifically as described in Section 3.6.2.6.2 and as described in the following paragraphs.

The pipe whip restraints used for the recirculation system consist of straps (either carbon steel ropes or stainless steel bars) attached to a steel frame.

The analytical methods used in the design of these restraints have been improved by incorporation of the latest force deflection data available for wire rope and by 3.6-82 HCGS-UFSAR Revision 0 April 11, 1988

using GE's PDA code for the dynamic analysis. Load capacities for the restraint frames were developed by using a finite element structural analysis program code (SAP) and were confirmed by a test series using slowly applied loading methods to determine restraint load deflection data in the tangential direction (parallel to the restraint base). The results of this test program are presented in Reference 3.6-9.

The specific design objectives for the restraints are:

1. The restraints shall in no way increase the reactor coolant pressure boundary stresses by their presence during any normal mode of reactor operation or condition.

2. The restraint system shall function to stop the movement of pipe failure (gross loss of piping integrity) without allowing either damage to critical components or missile development.

3. The restraints shall provide minimum hindrance to inservice inspection of the process piping.

For the purposes of design, the pipe whip restraints are designed for the following dynamic loads:

1. Blowdown thrust of the pipe section that impacts the restraint.

2. Dynamic inertia loads of the moving pipe section that is accelerated by the blowdown thrust and subsequent impact on the restraint.

3. Design characteristics of the pipe whip restraints are included and verified by the pipe whip dynamic analysis described in Section 3.6.2.6.2.2.

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4. Since the pipe whip restraints are not contacted during normal plant operation, the postulated pipe rupture event is the only design loading condition.

For non-NSSS pipe whip restraints, an evaluation of the impact of seismic loads on pipe whip restraints has been performed. The results of this evaluation demonstrated that seismic stresses in pipe whip restraints are extremely low.

Therefore, the pipe whip restraints will not fail during a seismic event and collapse onto safety-related components.

The postulated pipe rupture loads are the only design loading conditions for the NSSS pipe whip restraints because other loads are negligible in relationship to the pipe rupture loads.

The recirculation loop pipe whip restraints are composed of two parts: the straps and the restraint frame. Both parts of the restraining device function as load carrying members and will deflect under load. The load configurations for a restraint are shown on Figure 3.6-11. The components of the restraints are categorized as Type I and II, as described below:

1. Type I, radial load carrying members - These members consisting of cables or bars, will absorb energy when loaded in the direction perpendicular to the restraint base by elastic and plastic deformation as shown on Figure 3.6-11.

2. Type II, tangential load carry members - These members, consisting of restraint frames, will absorb energy when loaded in the direction parallel to the base by plastic deformation as shown in Figure 3.6-11.

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Each of these components is constructed of a different material in order to fulfill different design objectives. The design requirements and design limits for each component are therefore different. They are specified as below:

1. Type I - straps

a. For carbon steel wire ropes, the maximum acceptable load is 90 percent of the load carrying capacity of the cable in the restraint configuration. This limit takes into consideration the efficiency reduction experienced when a cable is wrapped around a pipe.

This means that the design load is limited to about 5 percent of the minimum certified load carrying capacity of the cable in tension.

b. For stainless steel bars, the design limit base is 50 percent of the minimum uniform ultimate tensile elongation.

2. Type 2, Restraint frames - Design limits for the ASTM A36 restraint frames are as follows:

a. Design load - The load bearing member is primarily a cantilever beam with an extra support (the diagonal plate) at approximately midspan. At loads approaching the plastic moment capability of the beam, the plastic hinge forms at the section determined from an elastic structural analysis. The maximum design load and the ultimate load are calculated based on plastic moment capability, Mp, of this section, with the diagonal plate stressed uniformly at the minimum ultimate stress of 58,000 psi specified for ASTM A36 material.

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b. Design deflection - The design and ultimate deflection are calculated assuming the beam remains straight and rotates about a point on the upper surface of the beam. The maximum design deflection at the load point is calculated assuming the diagonal plate undergoes 10 percent elongation. This corresponds to 50 percent of the minimum ultimate elongation of 20 percent as specified for ASTM A36 material. The ultimate deflection of the beam is based on a 20 percent ultimate elongation of the diagonal plate.

3.6.2.6.4 Material to be Submitted for the Operating License Review 3.6.2.6.4.1 Implementation of Criteria for Pipe Break Location and Orientation The criteria for selection of postulated pipe breaks in the recirculation piping system are provided in Section 3.6.2.6.1. The postulated breaks and types, recirculation pipe breaks selected in accordance with these criteria are shown on Figure 3.6-12. Conformation with the criteria is demonstrated in Table 3.6-6.

3.6.2.6.4.2 Implementation of Special Protection Criteria The location of pipe whip restraints provided for the recirculation piping systems are also shown in Figure 3.6-12. Using the analysis methods of Section 3.6.2.6.2.2, this system of restraints was found to prevent unrestrained pipe whip at the break locations, postulated in Section 3.6.2.6.1.

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3.6.2.7 Standard Review Plan Rule Review 3.6.2.7.1 Acceptance Criterion II.1 Acceptance criterion II.1 of Standard Review Plan (SRP) Section 3.6.2 provides that postulated pipe rupture locations in containment should meet BTP MEB 3-1, which imposes new limits of 2.4 S for Class 1 pipe, in equations 10 and 12 of Paragraph NB-3653 of the ASME B&PV Code,Section III, for which pipe breaks must be postulated.

The HCGS NSSS design meets the intent of MEB 3-1, Revision 1, with the following clarifications:

1. GE meets the requirements of criterion B.1.d, B.3.a (2-5), and B.3.b, as described in Sections 3.6.2.6.1.5 and 3.6.2.6.2.1.1.

2. GE has taken the following positions on the remaining items of BTP MEB 3-1, Revision 1, criteria within GE scope:

a. Criterion B.1.c(1) - GE uses criteria from SRP Section 3.6.2, Revision 0, which requires no break postulation if equation 10 is less than 3 S and the cumulative usage factor is less than 0.1.

Section 3.6.2.6.1.4 discusses this criterion in detail.

The HCGS non-NSSS design meets the intent of MEB 3-1, Revision 1, with the following clarifications:

1. For Class 1 piping, when the stress and usage factor criteria in Section 3.6.2.1.1.3.b are not exceeded, the minimum of two intermediate breaks based on highest stress, as calculated by Equation 10 of Paragraph NB-3653, are not postulated unless the break location is in the proximity of a welded attachment.

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2. For Class 2 and 3 piping, when the stress criteria of Section 3.6.2.1.1.4.b are not exceeded, the minimum of two intermediate breaks based on highest stress, as calculated by the sum of Equations 9 and 10 of Paragraph NC-3652, are not postulated unless the break location is in the proximity of a welded attachment.

In addition to limiting the stress and usage factor values for Class 1 piping and limiting the stress values for Class 2 and 3 piping, the following criteria are all required to be met when considering deletion of arbitrary intermediate breaks:

1. The piping systems are not susceptible to Intergranular Stress Corrosion Cracking (IGSCC) nor to unanticipated waterhammer/thermal transient events.

2. The piping system is included in the piping startup testing program for steady state vibrations.

3. Safety-related equipment in the vicinity of the deleted intermediate break remains environmentally qualified to the non-dynamic effects of the pipe break with the greatest consequences on the equipment.

4. The deleted intermediate break is not in the vicinity of a welded attachment.

3.6.2.7.2 Acceptance Criterion II.3 Acceptance criterion II.3 of SRP Section 3.6.2 provides criteria for initial conditions used in the dynamic analysis of postulated pipe break of the pressurized non-NSSS piping during operation at power. The initial condition to be used is the greater of the contained energy at hot standby or at 102 percent power.

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On HCGS, the dynamic analysis of postulated pipe break is based on the initial condition of 100 percent power in the pressurized pipe. It is recognized that, for short periods of time, the pressure and enthalpy in some systems may be higher for some modes than for 100 percent power operation. From a safe and realistic protection point of view, 100 percent power represents the high energy condition of most likely occurrence, due to the relatively short time period of operation at the higher energy modes.

3.6.3 Definitions Certain terms used in Sections 3.6.1 and 3.6.2 have specific meanings, as described below:

1. Essential systems and components - Systems and components required to shut down the reactor, maintain it in a safe shutdown mode, and mitigate the consequences of a postulated piping failure, without offsite power.

2. High energy fluid systems - Fluid systems that, during normal plant conditions, are either in operation or maintained pressurized under conditions where either or both of the following are met:

a. Maximum operating temperature exceeds 200°F

b. Maximum operating pressure exceeds 275 psig.

3. Moderate energy fluid systems - Fluid systems that, during normal plant conditions, are either in operation or maintained pressurized above atmospheric pressure under conditions where both the following are met:

a. Maximum operating temperature is 200F or less

b. Maximum operating pressure is 275 psig or less.

3.6-89 HCGS-UFSAR Revision 0 April 11, 1988

A system that qualifies as a high energy fluid system for only short periods and qualifies as a moderate-energy fluid system for the majority of the time is classified as a moderate energy fluid system, provided that the total time the system operates within high energy pressure/temperature conditions is less than either of the following:

a. 2 percent of the time that the system operates as a moderate energy fluid system

b. 1 percent of the normal operating life span of the plant.

4. Normal plant conditions - Plant operating conditions during reactor startup, operation at power, hot standby, or reactor cooldown to cold shutdown condition.

5. Upset plant conditions - Plant operating conditions during system transients, which may occur with moderate frequency during plant service life and are anticipated operational occurrences, but not during system testing.

6. S and S - Allowable stresses at maximum (hot) temperature and h A allowable stress range for thermal expansion, respectively, as defined in Article NC-3600 of the ASME B&PV Code,Section III.

7. S - Design stress intensity, as defined in Article NB-3600 of the m

ASME B&PV Code,Section III.

8. S - Primary plus secondary stress intensity range for normal and n

upset conditions, as defined in Paragraph NB-3653 of the ASME B&PV Code,Section III.

3.6-90 HCGS-UFSAR Revision 0 April 11, 1988

9. Single active component failure - Malfunction or loss of function of a component of electrical or fluid systems. The failure of an active component of a fluid system is considered to be a loss of component function as a result of mechanical, hydraulic, pneumatic, or electrical malfunction, but not the loss of component structural integrity. The direct consequences of a single active component failure are considered to be part of the single failure.

10. Terminal ends - Extremities of piping runs that connect to structures, components, e.g., vessels, pumps, valves, or pipe anchors that act as rigid constraints to piping thermal expansion. A branch connection to a main piping run is a terminal end of the branch run, except when all three of the following conditions are in effect:

a. The nominal size of the branch run is at least half that of the main run

b. The intersection is not rigidly constrained to the building structure

c. The branch run and main run are included together in the same piping stress analysis model.

For piping in containment penetration areas, terminal ends are selected at points located immediately beyond the required valve operability restraints inside and outside primary containment.

In piping runs which are maintained pressurized during normal plant conditions for only a portion of the run, i.e., up to the first normally-closed valve, a terminal end of such runs is the piping connection to this closed valve.

3.6-91 HCGS-UFSAR Revision 0 April 11, 1988

11. Cumulative usage factor - The sum of all contributions to fatigue damage by every stress cycle during the life of the component. (ASME Section III, Subsection NB-3222.4).

3.6.4 References 3.6-1 Bechtel Power Corporation, "Subcompartment Pressure Analyses," BN-TOP-4, Revision 0, July 1976.

3.6-2 Idaho National Engineering Laboratory, "RELAP4/MOD5, Computer Program for Transient Thermal-Hydraulic Analysis of Nuclear Reactors and Related Systems," ANCR-NUREG-1335, September 1976.

3.6-3 General Electric, "Hanford 2 Crimped CRD Hydraulic Withdrawal Line" (propriety filing), NEDE-24834, Revision 0, June 1980.

3.6-4 General Electric, "System Criteria and Applications for Protection Against the Dynamic Effects of Pipe Break," General Electric Specification No. 22A2625, Revision 2, June 1973.

3.6-5 General Electric, PDA - "Pipe Dynamic Analysis Program for Pipe Rupture Movement" (proprietary filing), NEDE-10313.

3.6-6 Nuclear Services Corporation, "Final Report Pipe Rupture Analysis for Recirculation System for 1969 Standard Plant Design," GEN 02.

3.6-7 Bechtel Power Corporation, "Design for Pipe Break Effects," BN-TOP-2, Revision 2, May 1974.

3.6-92 HCGS-UFSAR Revision 0 April 11, 1988

3.6-8 F.J. Moody, "Fluid Reaction and Impingement Loads," ASCE Specialty Conference on Structural Design of Nuclear Plant Facilities, Vol 1, December 1973, pp 219-262.

3.6-9 General Electric, "Recirculation System Pipe Whip Restraint for the BWR 4, 218 and 251, Mark I and Mark II Product Line Plant,"

General Electric Design Report No. 22A4046, Revision 0.

3.6-10 Control Data Corporation, "REPIPE Application Reference Manual,"

Revision A, May 20, 1980.

3.6-11 R.L. Mittl, PSE&G, to W. Butler, NRC, "Safety Evaluation Report Confirmatory Issue 1; Feedwater Isolation Check Valve Analysis",

dated July 26, 1985 and September 9, 1985.

3.6-12 R.L. Mittl, PSE&G, to W. Butler, NRC, "Elimination of Arbitrary Intermediate Pipe Breaks", dated June 11, July 3, and August 9, 1985.

3.6-13 NUREG-1048, HCGS SSER No. 3, Appendix 0, "NRC Safety Evaluation for the Elimination of Arbitrary Intermediate Pipe Breaks",

October 1985.

3.6-14 C. McNeill, PSE&G, to E. Adensam, NRC, "Elimination of Additional Intermediate Pipe Break Locations", dated December 18, 1985.

3.6-15 NUREG-1048, HCGS SSER No. 5, Appendix O, "NRC Safety Evaluation for the Elimination of Arbitrary Intermediate Pipe Breaks", April 1986.

3.6-16 COMPARE-MOD 1 A Computer Code for Transient Analysis of Volumes With Heat Sinks, Flowing Vents and Doors, LA-7199-MS.

3.6-93 HCGS-UFSAR Revision 17 June 23, 2009

TABLE 3.6-1 HIGH ENERGY FLUID SYSTEM PIPING Fluid System Extent of High Enersx Piping Reactor recirculation From reactor vessel suction nozzles to recirculation pumps to reactor vessel discharge nozzles, as shown on Figure 5.4-2 Main steam From reactor vessel nozzles to main steam stop valves, as shown on Figures 5.1-3 Feedwater From condensate filter/deminera1izers through feedwater heaters and reactor feedwater pumps to reactor vessel nozzles, shown on Figures 10.4-4; 10.4-5, 10.4-6, and 5.1-3 Condensate From *condensate pumps through steam jet air ejector condensers, steam packing exhauster, and condensate fi1terjdeminera1izers, as shown on Figures 10.4-4 and 10.4-4 RYCU From reactor recirculation loops through RYCU pumps, regenerative and nongenerative heat exchangers, and cleanup filter/demineralizers to feedwater lines, as shown on Figures 5.4-2, 5.4-17, 5.4-19, and 5.1-3 Reactor vessel drain From reactor vessel bottom head nozzle to RWCU line inside* primary containment, as shown on Figures 5.4-2 and 5.4-17 1 of 3 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.6*1 (Cont)

• Fluid System HPCI steam supply Extent of Hish Energy Piping From main steam line C to HPCI turbine steam supply valve HV-FOOl as shown on Figure 6.3-1 RCIC steam supply From main steam line A to RCIC turbine steam supply valve HV-F045, as shown on Figures 5.4-8 and 5.4-9 Main steam drain lines From main steam lines inside drywell and from main steam lines outside drywell to the condenser, as shown on Figure 5.1-3 RPV head vent line From reactor vessel top head nozzle to main steam line A, as shown on Figure 5.1-3 Standby liquid control From core spray injection line A to injection inboard check valve, as shown on Figures 9.3-8 and 5.1*3 RHR shutdown cooling From reactor recirculation loop to suction inboard containment isolation valve, as shown on Figure 5.4-13 RHR shutdown cooling From reactor recirculation loops to return inboard check valves, as shown on Figure 5.4-13 LPCI injection From reactor vessel nozzles to inboard check valves, as shown on Figure 5.4-13 Core spray injection From reactor vessel nozzles to inboard check valves, as shown on Figure 6.3-7 2 of 3 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.6-1 (Cent)

Fluid System Extent of High Energy Piping CRD hydraulic From CRD drive water pumps to master control station to HCUs, as shown on Figures 4.6-5 and 4.6-6 Auxiliary steam From auxiliary boiler to various steam consuming components, as shown on Figure 9.5-30 Emergency diesel From starting air skid to emergency diesel I

generator as generator starting shown on Figure 9,5-28 air line

• HCGS-UFSAR 3 of 3 Revision 14 July 26, 2005

(Historical Information)

TABLE 3.6-2 FINAL MAIN STEAM SYSTEM PIPING STRESS LEVELS AND PIPE BREAK DATA (PORTION INSIDE PRIMARY CONTAINMENT)

Break Stress Stress Cumulative Limit Basis for Node Node By EQ. 10 2.4 sm Break Break Line A 1 TTJ 27.78 0.010 42.5 c TE 45 EG 56.58 0.010 42.5 c TE Line B 1 TTJ 25.93 0.010 42.5 c TE 49 EL 49.83 0.010 42.5 c TE Line C 1 TTJ 26.88 0.010 42.5 c TE 42 EL 56.15 0.010 42.5 c TE Line D 1 TTJ 28. 0 0.010 42.5 c TE 39 EL 61.99 0.020 42.5 c TE THIS TABLE CONTAINS HISTORICAL DATA ONLY AND IS NO LONGER UPDATED.

FOR CURREN'r INFORMATION, SEE THE LATEST APPLICABLE STRESS CALCULATIONS.

1 of 2 HCGS-UFSAR Revision 16 May 15, 2008

(Historical Information)

TABLE 3.6-2 (Cant)

(1) Locations of the nodes are shown in Figure 3.6-2 (2) used to denote the node type are as follows:

TTJ transition joint EL Elbow (3) Break types are indicated as follows:

C Circumferential (4) Symbols used to denote the basis for break selection are as follows:

TE Terminal end THIS TABLE CONTAINS HISTORICAL DATA ONLY AND IS NO LONGER UPDATED.

FOR CURRENT INFORMATION, SEE THE LATEST APPLICABLE STRESS CALCULATIONS.

2 of 2 HCGS-UFSAR Revision 16 May 15, 2008

(Historical Information)

TABLE 3.6-3 FINAL MAIN STEAM SYSTEM PIPING STRESS LEVELS AND PIPE BREAK DATA (PORTION OUTSIDE PRIMARY CONTAINMENT)

Total Pipe Break Stress Stress Limit Basis for Node Node EQ.9+EQ.10 0.8{1.2Sh+SA) Break Break Point ill ksi ksi

~

45 BW 22.76 37.8 C TE 215 BW 23.24 37.8 C TE 385 BW 23.80 37.8 C TE 565 BW 25.90 37.8 C TE 75 EL 24.26 37.8 C MBL 245 EL 25.09 37.8 C MBL (1) Locations of the nodes are shown in Figure 3.6-3 (2) Symbols used to denote the node type are as follows EL Elbow BW Buttweld (3) Break types are indicated as follows C - Circumferential (4) Symbols used to denote the basis for break selection are as follows:

TE - Terminal end MBL - Intermediate break locations selected to satisfy the requirements for a minimum number of break locations where such locations are in the proximity of welded attachments.

THIS TABLE CONTAINS HISTORICAL DATA ONLY AND IS NO LONGER UPDATED.

FOR CURRENT INFORMATION, SEE THE LATEST APPLICABLE STRESS CALCULATIONS.

1 of 1 HCGS-UFSAR Revision 16 May 1 2008

1 of 3 HCGS-UFSAR Revision 17 June 23, 2009

TABLE 3.6-4 (Cont)

Isolation Valve Closure{l)

Valve Signal Total Break Rate Enthalpy Isolation Closing Delay Internal High Energy Line {s) (lbm/s) (Btu/lbm) Valves Time(s) Time(s) Time (s)

RWCU valve and pump room 0.0 0.0 420.3 HVFOOl 40.9( 2 )

Case 7 (MPS w/EWTR) 0.005 416.59 420.3 HVF004 40.9 12 )

0.025 1194.71 437.0 HVF039 check valve 0.480 659.65 439.9 1.380 404.46 423.6 3.980 408.41 379.8 10.230 265.61 413.3 100.000 265.61 413.3 RWCU line at the heat 0.0 0.0 420.3 HVFOOl 3s.o 12 l 5.0 40.0 exchangers (RWCU heat 0.005 416.7 420.3 HVF004 35.o 12 l 5.0 40.0 exchanger room) Case 2 0.025 1194.8 437.0 HVF039 check valve (MPS w/FWTR) 0.480 659.7 439.9 1.380 404.5 423.6 3.980 408.5 379.8 10.230 265.6 413.3 100.000 265.6 413.3 RWCU discharge line at the 0.0 821.7 88.3 HVF001 35.0( 2 ) 5.0 40.0 inlet nozzle to the filter/ 0.0001 1670.2 88.3 HVF004 35.0( 2 ) 5.0 40.0 demineralizer vessel (RWCU 0.005 572.2 97.0 HVF039 check valve filter/dernineralizer room) o. 98 315.2 175.3 Case 6 2.58 281.7 254.3 6.58 236.9 325.0 10.03 218.5 367.7 41.0 218.5 367.7 2 of 3 HCGS-UFSAR Revision 17 June 23, 2009

TABLE 3.6-4 (Cent)

(1)

Break Rate Isolation High Energy Line (s) (lbm/s) Valves HPCI steam supply line 0.0 1088.4 1192.2 HVF002 35.0 (HPCI pump room) 0.282 1088.4 1192.2 HVF003 35.0 0.283 414.0 1192.2 35.0 414.0 1192.2 35.1 0.0 1192.0 HPCI steam supply line 0.0 1088.36 1192.2 HVF002 35.0 (HPCI pipe chase) 0.0651 1088.36 1192.2 HVF003 35.0 0.0652 414.0 1192.2 35.0 414.0 1192.2 35.1 0.0 1192.2 RCIC steam supply line 0.0 164.68 1192.2 HVF007 11.0 (RCIC pump room) 11.0 164.68 1192.2 HVFOOB 11.0 11.1 o.o 1192.2

!1) These values are the assumed valve closure times in the pressure temperature transient analysis. These analyses are insensitive to small variations I

in actual valve closing times.

{2) The required closing time for this valve, which was specified for containment isolation P~trt)OE~eE;, Since the peak pressure and temperature occur long before valve closure, the analysis is insensitive to the (3) All RWCU line breaks evaluated at the following conditions: Normal feedwater temperature, reduced feedwater temperature, Increased Core Flow (ICF),

Minimum Pump Speed (MPS), and MPS with reduced feedwater temperature. The mass and energy release resulting in the peak break node pressure/temperature is provided.

3 of 3 HCGS-UFSAR Revision 17 June 23, 2009

TABLE 3.6-5 PRESSURE-TEMPERATURE TRANSIENT ANALYSIS RESULTS FOR HIGH-ENERGY PIPE BREAKS OUTSIDE PRIMARY CONTAINMENT Calculated Peak(S)

Initial Condition Relative I (1,2)

Pressure Temp. Temp. Humid.

_crl_ ITL (%)

1 RWCU Pump Disch. Line 4405: RWCU Pump Rm. 1.7 217 104 50 Break 4403: RWCU Pump Rm. 1.7 217 104 50 2 RWCU Hx Line Break 4506: RWCU Hx Rm. 2.1 217 120 50 (4" Line Break) 3 HPCI Steam Supply 4102: Torus Rm. 1.5 302 90 90 Line (Chase) 4327: HPCI Pipe Chase 2.0 302 90 4329: North Pipe Chase 1.5 302 90 4409: Steam Vent 1.5 302 90 90 (1) (3) 4 RWCU 6" Line Break 4319: RCIC Chase 1.7 302 95 90 4321: South Chase 1.6 218 95 90 4402: South Chase 1.7 218 95 90 (1) 5 RWCU 6" Line Break 4505: South Pipe Chase 1.8 218 95 90 6 RWCU F/D Line Break 4620: RWCU F/D Rm. 6.4 231 104 50 4621: RWCU F/D Rm. 6.4 231 104 50 7 RWCU F/D Line Break 4502: RWCU Valve & Pump Rm. 1.9 218 115 50 4503: RWCU Valve & Pump Rm. 1.9 218 120 50 8 HPCI Steam Supply 4111: HPCI Pump Rrn. 2.8 301 85 90 Line (Pump Rm. )

(4 J 9 RCIC Steam Supply 4110: RCIC Pump Rm. 2.8 301 80 90 Line (Pump Rrn.)

10 Main Steam Line 4316: MST Penetration Rm. 16.3 315 120 30 Break in the Penetration 4518: MST Unit Cooler Rm. 16.3 315 120 30 Chamber of the Main Steam Tunnel 11 Main Steam Line MST & Emergency Vent Stack 10.0 297 120 30 Break in the Main Steam Tunnel (1) The initial pressure in all of the rooms was 14.7 psia.

(2) Outside atmospheric conditions were assumed to be 14.7 psia, 70°F, and 90% relative humidity.

(3) Peak temperature is based on Case 3.

(4) Peak temperature is based on Case 8.

(5) Calculated peak pressure and temperature values bound these determined at 3952 MWth.

1 of 1 HCGS-UFSAR Revision 17 June 23, 2009

TABLE 3.6-6 FINAL RECIRCULATION SYSTEM PIPING STRESS RATIOS AND PIPE BREAK DATA - LOOP A (4)

Stress Ratio per ASME Equation EQ 10 EQ 12 EQ 13 Break 2.4 s 2.4 s 2.4 s Usage Break Break Basis mm m Ident{ 1 ) Factor Type ( 2 ) Section No.

Sl 0.452 0.072 0.414 0.00 CRCMF 3.6.2.6 Fl 0.534 0.060 0.420 0.00 CRCMF 3.6.2.6 F2 0.664 0.187 0.425 0.00 CRCMF 3.6.2.6 F3 0.557 0.093 0.445 o.oo CRCMF 3.6.2.6 F4 0.603 0.104 0.440 0.00 CRCMF 3.6.2.6 F5 0.639 0.177 0. 433 0.00 CRCMF 3.6.2.6 F6(3) 1. 008 0.088 0.758 0.010 CRCMF 3.6.2.6 F7(3) 1.142 0.130 0.748 0.010 CRCMF 3.6.2.6 F8(3) 1.002 0.089 0.613 0.00 CRCMF 3.6.2.6 F9(3) 1.335 0.329 0.750 0.010 CRCMF 3.6.2.6 F10(3) 1.159 0.264 0.747 0.010 CRCMF 3.6.2.6

(!)Location at the nodes are shown in Figure 3.6-12.

(2) CRCMF = Circumferential (3) Postulated Arbitrary Intermediate Breaks (AIB) are not required and stress ratios are not applicable.

(4) Reference PSE&G Calculation C-0142 NOTE: THIS TABLE CONTAINS HISTORICAL DATA ONLY AND IS NO LONGER UPDATED.

FOR CURRENT INFORMATION, SEE THE LATEST APPLICABLE STRESS CALCULATION.

I 1 of 1 HCGS-UFSAR Revision 12 May 3, 2002

TABLE 3.6-6A FINAL RECIRCULATION SYSTEM PIPING STRESS RATIOS AND PIPE BREAK DATA - LOOP B (4)

Stress Ratio per ASME Equation EQ 10 EQ 12 EQ 13 Break 2.4 s 2.4 s 2.4 s Usage Break Break Basis mm m Ident(l) (2)

Factor Type Section No.

Sl 0.450 0.046 0.414 o.oo CRCMF 3.6.2.6 Fl 0. 492 0.062 0.427 o.oo CRCMF 3.6.2.6 F2 0.687 0.215 0. 422 0.00 CRCMF 3.6.2.6 F3 0.565 0.092 0. 429 o.oo CRCMF 3.6.2.6 F4 0.648 0.169 0.427 o.oo CRCMF 3.6.2.6 F5 0.655 0.203 0.425 0.00 CRCMF 3.6.2.6 F6(3) 0.912 0.080 0.753 0.01 CRCMF 3.6.2.6 F7(3) 1.060 0.152 0.753 0.01 CRCMF 3.6.2.6 F8 (3) 1. 045 0.164 0.617 0.00 CRCMF 3.6.2.6 F9(3) 1. 325 0.377 0.757 0.01 CRCMF 3.6.2.6 Fl0(3) 1.153 0.295 0.742 0.01 CRCMF 3.6.2.6 (1) Location at the nodes are shown in Figure 3.6-12.

(2) CRCMF =Circumferential.

(3) Postulated Arbitrary Intermediate Breaks (AIB) are not required and stress ratios are not applicable.

(4) Reference PSE&G Calculation C-0142.

NOTE: THIS TABLE CONTAINS HISTORICAL DATA ONLY AND IS NO LONGER UPDATED.

FOR CURRENT INFORMATION, SEE THE LATEST APPLICABLE STRESS CALCULATION.

I 1 of 1 HCGS-UFSAR Revision 12 May 3, 2002

TABLE 3.6~7 RECIRCULATION SYSTEM BLOWDOWN TIME HISTORY Rate, Enthalpy, Time. s 1bm/s .Btu/1bm 0 0 544.5 0.00255 1210 544.5 0.00496 3600 544.5 0.00804 8410 544.5 0.00924 10,810 544.5 0.01180 16,400 544.5 0.01580 24,500 544.5 0.01880 30,190 544.5 0.01910 30,780 544.5 0.01911 11,660 544.5 0.01980 12,140 544.5 0.02580 16,340 544.5 0.03380 21,860 544.5 0.04180 26,880 544.5 0.05480 31,300 544.5 0.05890 32,060 544.5 5.00000 32,060 544.5

• HCGS*UFSAR 1 of 1 Revision 0 April 11, 1988

(Historical Information)

TABLE 3.6 B FINAL FEEDWATER SYSTEM PIPING STRESS LEVELS AND PIPE BREAK DATA (PORTION INSIDE PRIMARY CONTAINMENT)

AE-035 Break Stress Stress Cumulative Limit Basis for Node Node By EQ. 10 Usage 2.4 sm Break Break Point( 1 ) ~

(2)

(ksil Factor (ksi) ~( 3 ) Selection( 4 )

200 TTJ 67.60 0.6017 47.34 c TE 315 TTJ 65.93 0.5445 47.34 c TE 265 TTJ 67.69 0.5376 47.34 c TE 130 TEE 80.14 0.4595 47.34 C&L SFL 95 TEE 114.42 0.4304 47.34 C&L SFL 70 TTJ 57.50 0.2105 47.34 C&L SFL 60 TTJ 57.30 0.2107 47.34 C&L SFL 25 TTJ 61.66 0.2498 47.34 C&L SFL 15 TTJ 57.62 0. 2144 47.34 c TE 178 LUG 17.78 0.3399 47.34 s SFL 288 LUG 21.57 0.3438 47.34 s SFL 250 LUG 14.52 0.3252 47.34 s SFL 225 LUG 18.47 0.1514 47.34 8 SFL 108 LUG 22.39 0.8374 47.34 s SFL (1) Locations of the nodes are shown in Figure 3.6-13 (2) Symbols used to denote the node t)~e are as follows:

TTJ - Tapered transition BRA - Branch Connection TEE - Tee LUG - Shear Lug (3) Break types are indicated as follows:

C- Circumferential L- Longitudinal S - Slot break at welded attachment (4) Symbols used to denote the basis for break selection are as follows:

TE - Terminal end SFL - Stress and fatigue limits established in Section 3.6.2.1.1.3 are not met.

THIS TABLE CONTAINS HISTORICAL DATA ONLY AND IS NO LONGER UPDATED.

FOR CURRENT INFORMATION, SEE THE LATEST APPLICABLE STRESS CALCULATIONS.

1 of 1 HCGS-UFSAR Revision 16 May 15, 2008

(Historical Infol-mation)

TABLE 3.6-BA FINAL FEEDWATER SYSTEM PIPING STRESS LEVELS AND PIPE BREAK DATA (PORTION INSIDE PRIMARY CONTAINMENT)

AE-036 Pipe Break Stress Stress Cumulative Limit Basis for Node Node By EQ. 10 Usage 2.4 s Break Break m

Point (l) TY~ (ksi) Factor Type Self::!ction 200 TTJ 68.87 0.6099 47.34 c TE 315 TTJ 64.44 0.5359 47.34 c TE 265 TTJ 69.02 0.5463 47.34 c TE 130 TEE 86.37 0.6775 47.34 C&L SFL 95 TEE 93.96 0.8276 47.34 C&L SFL 70 TTJ 57.25 0.2101 47.34 C&L SFL 60 TTJ 57.11 0.2105 47.34 C&L SFL 25 TTJ 61.65 0.2497 47.34 C&L SFL 15 TTJ 57.65 0.2145 47.34 c TE 180 BRA 53.19 0.2765 47.34 s SFL 178 LUG 16.90 0.3388 47.34 s SFL 288 LUG 21.87 0.3434 47.34 s SFL 250 LUG 15.15 0.3260 47.34 s SFL 225 LUG 19.36 0.1518 47.34 s SFL 108 LUG 24.16 0.8539 47.34 s SFL (1) Locations of the nodes are shown in Figure 3.6-13 (2) Symbols used to denote the node type are as follows:

TTJ - Tapered transition joint BRA - Branch Connection TEE - Tee LUG - Shear Lug (3) Break types are indicated as follows:

C Circumferential L - Longitudinal S - Slot break at welded attachment (4) Symbols used to denote the basis for break selection are as follows:

TE - Terminal end SFL - Stress and fatigue limits established in Section 3.6.2.1.1.3 are not met.

THIS TABLE CONTAINS HISTORICAL DATA ONLY AND IS NO LONGER UPDATED.

FOR CURRENT INFORMATION, SEE THE LATEST APPLICABLE STRESS CALCULATIONS.

1 of 1 HCGS-UFSAR Revision 16 May 15, 2008

(Historical Information)

TABLE 3.6-9 FINAL FEEDWATER SYSTEM PIPING STRESS LEVELS AND PIPE BREAK DP.TA (PORTION OUTSIDE PRIMARY CONTAINMENT)

Pipe Break Total Stress Limit Basis for Node Node Stress 0. 8 ( 1. 2 Sh +SA) Break Break (1) J~(2) ~(3) (4)

(ksi) {ksil Selection Feedwater lines:

70 BW 11.39 32.40 c TE 630 BW 11.36 32.40 c TE HPCI pump discharge to FW:

AOS BW 19.94 32.40 c TE A10 BW 19.68 32.40 c TE RCIC pump discharge to FW:

60 BW 9.30 32.40 c TE 958 BW 23.53 32.40 c TE RWCU discharge to FW:

40 BW 9.82 32.40 c TE 665 BW 9.95 32.40 c TE (1) Locations of the nodes are shown in Figure 3.6-14 (2) Symbols used to denote the node type are as follows:

BW -* Butt weld (3} Break types are indicated as follows:

C ** Circumferential (4} Symbols used to denote the basis for break selection are as follows:

TE ** Terminal end THIS TABLE CONTAINS HISTORICAL DATA ONLY AND IS NO LONGER UPDATED.

FOR CURRENT INFORMATION, SEE THE LATEST APPLICABLE STRESS CALCULATIONS.

1 of 1 HCGS-UFSAR Revision 16

. May 15, 2008

TABLE 3.6-10 FINAL RWCU SYSTEM PIPING STRESS LEVELS AND PIPE BREAK DATA (PORTION INSIDE PRIMARY CONTAINMENT)

Pipe Break Stress Stress cumulative Limit Basis for Node{S) Node By EQ 10 Usage 2.4 Sm Break Break Point(l) Type(2) (ksi) Factor {ksi) Type(3) se1ection(4) 90 BW 15.65 0.0002 43.60 c TE 101 BW 67.941 0.8869 43.60 C&L SFL 480 BW 12.86 0.0000 43.60 c TE 518 BW 11.64 0.0000 43.60 c TE 760 RED 69.73 0.1853 43.60 c SFL 799 BW 15.01 0.0003 43.60 c TE 108 TTJ 76.288 0.5386 43.60 C&L SFL 109 DSW 51.813 0.1346 43.60 C&L SFL 570 sw 61.26 0.6088 43.60 c SFL sw c 575 61.58 0.6386 43.60 SFL 819 sw 25.59 0.0056 43.60 c TE 705 TTJ 42.66 0.0059 34.64 c TE 710 TTJ 69.42 0.3583 34.64 C&L SFL 910 RED 48.52 0.0154 43.60 c SFL 920 sw 9.14 0.0003 43.60 c TE 855 BW 14.68 0.0001 43.60 c TE 902 TTJ 43.17 0.0075 34.64 c TE 905 TTJ 69.97 0.4372 34.64 C&L SFL 984 RED 48.52 0.0155 43.60 c SFL 988 sw 9.19 0.0003 43.60 c TE 968 BW 10.25 0.0000 43.60 c TE

• HCGS-UFSAR 1 of 2 Revision 7 December 29, 1995

TABLE 3.6-10 (Cent)

(1) Locations of the nodes are shown in Figure 3.6-15 (2) Symbols used to denote the node type are as follows:

TTJ - Tapered transition joint BW - Butt weld RED - Reducer SW - Socket weld (3) Break types are indicated as follows:

C- Circumferential L- Longitudinal (4) Symbols used to denote the basis for break selection are as follows:

TE - Terminal end SFL - Stress and fatigue limits established in Section 3.6.2.1.1.3 are not met.

(5) Node points 101, 108, and 109 are branch connections on flow element No35 which are not within the snubber reduction program scope; therefore, values listed are not revised to reflect the snubber reduction configuration *

• HCGS-UFSAR 2 of 2 Revision 7 December 29, 1995

TABLE 3.6-11 FINAL RWCU SYSTEM PIPING STRESS LEVELS AND PIPE BREAK DATA (PORTION OUTSIDE PRIMARY CONTAINMENT)

Total Pipe Break Stress Stress Limit Basis for Node Node EQ. 9+EQ. 10 0.8(1.2 S +S ) Break Break hA Point( 1 ) (2) (3) ( 4)

Type (ksi) (ksi) Type Selection E ANCH 38.83 32.4 c TE D ANCH 18.95 32.4 c TE 250 FL 26.76 32.4 c TE 370 FL 12.69 32.4 c TE 255 FL 12.66 32.4 c TE 380 FL 17.43 32.4 c TE B ANCH 12.32 32.4 c TE 5 BW 15.26 32.4 c TE 640 BW 16.58 32.4 c TE 50 BW 13.50 32.4 c TE 850 ANCH 16.76 32.4 c TE

( 1) Locations of the nodes are shown on Figure 3.6-16.

(2) Symbols used to denote the node type are as follows:

FL Flange BW Butt weld ANCH Anchor (3) Break type is indicated as follows:

c Circumferential (4) Symbol used to denote the basis for break selection is as follows:

TE Terminal end 1 of 1 HCGS-UFSAR Revision 21 November 9, 2015

(Historical Information)

TABLE 3.6-12 FINAL HPCI SYSTEM PIPING STRESS LEVELS AND PIPE BREAK DATA (PORTION INSIDE PRIMARY CONTAINMENT)

Pipe Break Stress Stress Cumulative Limit Basis for Node Node By EQ. 10 Usage 2.4 sm Break Break

( 3) ( 4)

Point( 1 ) (2) 402 TTJ 31.3 0.0026 42.48 c TE 420 BW 33.2 0.0015 42.48 c TE (1} Locations of the nodes are shown in Figure 3.6-18 (2) Symbols used to denote the node type are as follows:

TTJ transition joint BW Buttweld (3) Break types are indicated as follows:

C Circumferential (4) Symbols used to denote the basis for break selection are as follows:

TE Terminal end THIS TABLE CONTAINS HISTORICAL DATA ONLY AND IS NO LONGER UPDATED.

FOR CURRENT INFORMATION, SEE THE LATEST APPLICABLE STRESS CALCULATIONS.

1 of 1 HCGS-UFSAR Revision 16 May 15, 2008

TABLE 3.6-13 FINAL HPCI SYSTEM PIPING STRESS LEVELS AND PIPE BREAK DATA (PORTION OUTSIDE PRIMARY CONTAINMENT)

Pipe Break Total Stress Limit Basis for Node Node Stress 0.8(1.2 S +S ) Break Break h A (1) (2) (3) (4)

Point Type (ksi) (ksi) Type Selection Pump Discharge (see Feedwater and Core Spray)

Turbine Steam Supply 79 BW 23.20 32.40 C TE 120 BW 10.55 32.40 C TE C ANCH 22.86 32.40 C TE 182 BW 16.41 32.40 C TE 110 BW 8.765 32.40 C TE (1) Locations of the nodes are shown in Figure 3.6-19 (2) Symbols used to denote the node type are as follows:

BW - Butt weld ANCH - Anchor (3) Break types are indicated as follows:

C - Circumferential (4) Symbols used to denote the basis for break selection are as follows:

TE - Terminal end 1 of 1 HCGS-UFSAR Revision 24 May 21, 2020

(Historical Information}

TABLE 3.6-14 FINAL RCIC SYSTEM PIPING STRESS LEVELS AND PIPE BREAK DATA (PORTION INSIDE PRIMARY CONTAINMENT)

Pipe Break Stress Stress cumulative Limit Basis for Node Node By EQ. 10 usage 2.4 sm Break Break (2) ~(3)

~ ~ (ksi) '[;'a,,.., ~

{ksi) Selection~

405 TTJ 53.666 0.0028 42.14 c TE 420 DMW 28.934 0.0023 33.72 c MBL 455 BW 49.756 0.0028 42.14 c TE (1} Locations of the nodes are shown in Figure 3.6-22 (2) Symbols used to denote the node type are as follows:

TTJ Tapered transition joint BW Butt weld DMW Dissimilar Metal Weld (3} Break types are indicated as follows:

c Circumferential

{4) Symbols used to denote the basis for break selection are as follows:

TE Terminal end MBL Intermediate break locations selected to satisfy the requirements for a minimum number of break locations where such locations are in the proximity of welded attachments.

THIS TABLE CONTAINS HISTORICAL DATA ONLY AND IS NO LONGER UPDATED.

FOR CURREN'r INFORMATION, SEE THE LATEST APPLICABLE STRESS CALCULATIONS.

1 of 1 HCGS-UFSAR Revision 16 May 15, 2008

TABLE 3.6*15

• FINAL RCIC SYSTEM PIPING STRESS LEVELS AND PIPE BREAK DATA (PORTION OUTSIDE PRIMARY CONTAINMENT)

Total Pipe Break Stress Stress Limit Basis for Node Node EQ.9+EQ.l0 0.8(1.2 Sh+SA) Type Break Point{l) Type{ 2 ) (ksi) (ksi) 3 Break( ) Selection( 4 )

A ANCH 41.82 32.4 c TE 85 BW 11.13 32.4 c TE 44 BW 7.61 32.4 c TE (1) Locations of the nodes are shown in Figure 3.6-23 (2) Symbols used to denote the node type are as follows:

BW - Butt weld ANCH- Anchor (3) Break types are indicated as follows:

C - Circumferential (4) Symbols used to denote the basis for break selection are as follows:

TE

• Terminal end

• HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

• MAIN STEAM DRAIN PIPING STRESS LEVELS AND PIPE BREAK DATA (PORTION INSIDE PRIMARY CONTAINMENT)

• Breaks are postulated at every fitting and change of direction .

Refer to Figure 3.6-26

• HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

TABLE 3.6-17 FINAL MAIN STEAM DRAIN PIPING STRESS LEVELS AND PIPE BREAK DATA (PORTION OUTSIDE PRIMARY CONTAINMENT)

Pipe Break Node Total Stress Limit Basis for Point Node Stress O.B(1.2S +S Break Break

__ilL TYPe(2) {ksil <ksi} Type !3) Selection(4) 1208 TE 13.33 32.40 c TE 765 BW 17.35 32.40 c TE 680 BW 20.43 32.40 c TE 610 BW 22.01 32.40 c TE 540 BW 23.92 32.40 c TE 274 BW 20.72 32.40 c TE 75 BW 9.05 32.40 c TE 1 of 2 HCGS-UFSAR Revision 12 May 3, 2002

TABLE 3.6-17 (Cont)

(1) Locations of the nodes are shown in Figure 3.6-27.

{2) Symbols used to denote the node type are as follows:

EL - Elbow TEE Tee BY - Butt weld (3) Break types are indicated as follows:

C - Circumferential (4) Symbols used to denote the basis for break selection are as follows:

TE - Terminal end SFL - Stress and fatigue limits established in Section 3.6.2.1.1.3 are not met.

2 of 2 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.6*18 RPV HEAD VENT PIPING STRESS LEVELS AND PIPE BREAK DATA Breaks are postulated at every fitting and change of direction.

Refer to Figure 3.6-28 .

• HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

TABLE 3.6-19 STANDBY LIQUID CONTROL INJECTION PIPING

~* STRESS LEVELS AND PIPE BREAK DATA Breaks are postulated at every fitting and change of direction .

Refer to Figure 3.6-29 .

• HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

TABLE 3.6-20 FINAL RHR SHUTDOWN COOLING SUCTION PIPING STRESS LEVELS AND PIPE BREAK DATA Pipe Break Stress Stress cumulative Limit Basis for Node Node By EQ. 10 usage 2.4 s Break Break m 4 Point(l) ~(2) Cksil Factor !ksi) ~(3) Selection( )

500 TTJ 42.5 0.013 34.05 c TE 530 TTJ 24.2 0.0303 42.375 c TE

{1) Locations of the nodes are shown in Figure 3.6-30 (2) Symbols used to denote the node type are as follows:

TTJ Tapered transition joint (3) Break types are indicated as follows:

C Circumferential (4) symbols used to denote the basis for break selection are as follows:

TE Terminal end

• HCGS-UFSAR 1 of 1 Revision 7 December 29, 1995

TABLE 3.6-21 FINAL RHR SHUTDOWN COOLING RETURN PIPING STRESS LEVELS AND PIPE BREAK DATA Pipe Break stress Stress Cumulative Limit Basis for Node Node By EQ. 10 Usage 2.4 sm Break Break Point<l> TypeC2) <ksil Factor <ksil Type<3> Selection(4)

LOOP A 12"-CCA-116(SS}

12"-DLA-069(CSS) 600 TTJ 17.1 0.00 34.05 c TE 622 TTJ 21.7 0.0088 42.375 c TE LOOP B 12"-CCA-115(SS) 12"-DLA-02l(CSS)

• I 600 TTJ 17.4 0.00 34.05 c TE 625 TTJ 23.4 0.0092 42.375 c TE (1) Locations of the nodes are shown in Figure 3.6-31 (2) Symbols used to denote the node type are as follows:

TTJ Tapered transition joint (3) Break types are indicated as follows:

C Circumferential (4) symbols used to denote the basis for break selection are as follows:

TE Terminal end

• HCGS-UFSAR 1 of 1 Revision 7 December 29, 1995

TABLE 3.6-22 FINAL LPCI INJECTION PIPING STRESS LEVELS AND PIPE BREAK DATA Pipe Break stress Stress Cumulative Limit Basis for Node Node By EQ. 10 Usage 2.4 s Break Break m

Pointtll Typet2l Cksi> Factor Cksi> Type<3> Selectionl4l Line 12"-DLA-014 80 TTJ 64.01 0.0335 42.48 c TE 25 TTJ 36.81 0.0027 42.48 c TE Line 12"-DLA-015 180 TTJ 64.04 0.0334 42.48 c TE 125 TTJ 31.36 0.0014 42.48 c TE Line 12"-DLA-055 495 TTJ 67.05 0.044 42.48 c TE 425 TTJ 28.96 0.0005 42.48 c TE Line 12"-DLA-056 395 TTJ 67.98 0.0482 42.48 c TE 335 EL 50.02 0.0022 42.48 c MBL 325 TTJ 19.34 0.0001 42.48 c TE 393 EL 76.55 0.0465 42.48 c MBL

• HCGS-UFSAR 1 of 2 Revision 7 December 29, 1995

TABLE 3.6-22 (Cont)

• (1) Locations of the nodes are shown in Figure 3.6-32 (2) Symbols used to denote the node type are as follows:

TTJ Tapered transition joint EL Elbow (3) Break types are indicated as follows:

C Circumferential (4) Symbols used to denote the basis for break selection are as follows:

TE Terminal end MBL Intermediate break locations selected to satisfy the requirements for a minimum number of break locations where such locations are in the proximity of welded attachments .

• HCGS UFSAR 2 of 2 Revision 0 April 11, 1988

TABLE 3.6-23 FINAL CORE SPRAY INJECTION PIPING STRESS LEVELS AND PIPE BREAK DATA Pipe Break Stress Stress Cumulative Limit Basis for Node Node By EQ. 10 Usage 2.4 sm Break Break Point<1> Type<2> Cksil Factor Cksi> TypeC3l Selection<4l Line 12" - DLA-001 150 RED 53.366 0.0327 42.48 c TE 35 TTJ 25.073 0.0004 42.48 c TE Line 12" - DLA-023 140 RED 48.745 0.034 42.48 c TE 35 TTJ 24.409 0.002 42.48 c TE (1) Locations of the nodes are shown in Figure 3.6-33 (2) Symbols used to denote the node type are as follows:

TTJ Tapered transition joint RED Reducer (3) Break types are indicated as follows:

c Circumferential (4) symbols used to denote the basis for break selection are as follows:

TE Terminal end

• HCGS-UFSAR 1 of 1 Revision 7 December 29, 1995

• REACTOR VESSEL DRAIN PIPING STRESS LEVELS AND PIPE BREAK DATA

• Shown as part of RWCU .

Refer to Table 3.6-10 and Figure 3.6-15 .

• HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

TABLE 3.6-25 THIS TABLE INTENTIONALLY DELETED 1 of 1 HCGS-UFSAR Revision 14 July 26, 2005

TABLE 3.6-26 PDA VERIFICATION RESTRAINT DATA(l)

Pipe Rest Load Initial Effective Total Size Direction Limit Clearance Clearance Clearance in. Restra1ntC2) in. in. in.

12 oo 27,733 0.24 6.129 4 1.941 5.941 12 90" 14,795 0.401 9.063 4 12.247 16.247 16 0" 109,265 0.24 6.728 4 1.934 5.934 16 90" 62,599 0.377 8.978 4 12.187 16.187 24 0" 102,228 0.24 8.222 4 1.984 5.984 24 90" 55,531 0.375 11.972 4 13.685 17.685 24 38o(J) 109,888 0.24 5.588 4 5.698 9.698 24 52o(J) 109,835 0.24 5.473 4 8.462 12.462 (1) The restraint data listed applies to one bar of a restraint.

(2) F m C2 (~restraint)N where F is the resistance force for one bar of a restraint and (3) o whet'e ( .:lrestraint) * ( pipe) - total clearance Applies to restraint RCR 3 only. See Figure 3.6-38.

1 of 1 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.6*27 COMPARISON Of PDA AND NSC CODE Fraction of Design Restraint Restraint Pipe Break Restraint No. of Bars load ~Kiesl Deflection ~in.~ Deflection ~%l Deflection ~in.2 Oesignation~12 Oesignation{12 POA NSC ..fQL NSC POA _]g_ PDA NSC ~ NSC RC1 RCR1 5 5 803.2 788.3 6.57 7.926 79.93 96.4 17.72 15.58 J

RC2 RCR1 5 5 766.4 458.4 14.99 7.495 125 62.6 35.83 24.52 ll RC3 RCR2 6 6 747.0 639.7 2.27 3.73 27.65 45.35 17.16 20.11 ll RC3 RCR2 66 796.6 780.3 10.22 10.54 85.4 88.1 41.48 43.0 ll RC4 RHR3 5 5 846.0 838.4 8.2 8.05 92.95 97.98 18.87 16.43 Ll RC4 RCR3 8 8 1319.0 1073.9 5.43 4.2 99.23 76.85 23.28 17.25 ll RC4C RCR3 8 8 1260.7 1275.0 4.49 5.58 80.37 99,89 22.56 18.73 v

RC6A RCR3 88 928.5 722.5 1.22 1.77 22.46 31.7 23.68 95.39 v

RC7 RCR7 6 6 953.3 801.6 6.28 5.76 76.4 70.12 16.46 21.63 J

RC8 RCR6 4 4 599.0 N/A 8.28 N/A 64.2 N/A 26.76 N/A ll RCR7 6 6 895.0 N/A 8.16 N/A 68.2 N/A 29.316 N/A RC9C RCR6 4 4 575.8 520.16 4.16 5.53 50.63 67.33 13.2 14.56 v

RC9 RCR8 6 6 830.2 546.8 11.408 6.815 95.29 56.9 36.612 26.24 Ll RC11A RCR8 66 818.3 493.6 10.98 5.99 91.72 50.07 31.404 23.71 RC12 RCR9 66 N/A 832.9 N/A 6.3 N/A 76.9 N/A 15.7 RC13 RCR10 4 4 668.4 478.4 5.87 3.66 93.5 58.39 13.37 10.44 RC16 RCR11 4 4 687.4 518.4 6.59 4.38 105 69.86 15.37 10.22 RC14C RCR20 8 8 285.0 309.6 2.83 5.88 46.3 95.92 15.45 13.96 v

RC14 RCR20 88 116.3 129.9 0.96 3.36 10.5 37.1 22.12 23.56 ll.

(1) Break designations and restraints designations are shown on Figure 3.6-38.

1 of 1 HCGS*UFSAR Revision 7 December 29, 1995

TABLE 3.6-28 MODERATE ENERGY FLUID SYSTEM PIPING Pressure Temperature Fluid System (psig) (oF}

Demineralized Water 100 70 Condensate & Refueling 190 108 Water Storage & Refueling Station Service Water 65 89 (2) (3)

Safety Auxiliaries Cooling 110 95 (4)

Reactor Auxiliaries Cooling 110 95 Fire Protection 125 70 CRD Hydraulics 10 100 (Pump Suction Only)

Standby Liquid Control 10 80 (Pump Suction Only)

Reactor Core Isolation Cooling 50 120 (excluding the steam supply line) ( l)

Residual Heat Removal 125 120 Core Spray 125 120 Fuel Pool Cooling & 135 90 Torus Water Cleanup High Pressure Coolant Injection 110 140 Chilled Water System - Reactor 65 60 Building and Drywell, and Auxiliary Building Control Area I

(1) Evaluated as a moderate energy line.

(2) 89°F maximum UHS Temperature permitted by Plant Technical Specifications (3) 95°F System Design (Supply) 120°F System Design (Discharge)

I (4) 100°F maximum post-accident 1 of 1 HCGS-UFSAR Revision 11 November 24, 2000

TABLE 3.6-29 FINAL STARTING AIR PIPING STRESS LEVELS AND PIPE'BREAK DATA Total Pipe Break Stress Stress Limit Basis for Node Node EQ.9+EQ.l0 0.8(1.2Sh+SA) Break Break Point{l) Type(2) ksi ksi Type(3) Selection C50 sw 14.3 33.91 c TE 320 sw 13.7 33.91 c TE 450 sw 8.2 33.91 c TE D50 sw 16.0 33.91 c TE

• (1) Locations of the nodes are shown in Figure 3.6-3 (2) Symbols used to denote the node type are as follows:

SW Socket weld (3) Break types are indicated as follows:

C Circumferential (4) Symbols used to denote the basis for break selection are as follows:

TE - Terminal end

• HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

tP!PE

• 5H!M SUPPORT PIPE WHIP RESTRAINT.S TYPE I E.LEVAT/0/v' REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION TYPICAL PIPE WHIP RESTRAINT DETAIL Sheet 1 of7 UPDATEDFSAR FIGURE 3.6-1

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PIPE Will? I?ESTIFAIA/T TYPE ..llL ELEVA liON REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION TYPICAL PIPE WHIP RESTRAINT DETAIL UPDATEDFSAR Sheet 3 of7 FIGURE3.6*1

SEC770/V REVISION0 APRIL11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION TYPICALPIPEWHIP RESTRAINTDETAIL UPDATEDFSAR Sheet 4 of7 FIGURE3.6-1

• PL AAI/£LEVAT!tJN .SECTION SHIM SUPPORT DETAIL REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION TYPICALPIPEWHIP RESTRAINTDETAIL Sheet 5of 7 UPOATEO FSAR FIGURE3.6~1

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• L .3 x5 x.3B TYP

.114" t:/> Ap3Z5 BtJLTS SI-I!M SUPPORT DETAIL REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK 1\!UCLEAR GENERATING STATION TYPICALPIPEWHIP RESTRAINTDETAIL UPDATEDFSAR Sheet 6 of7 FIGURE3.6-1

7YP

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• NOTES:

1. M.S. LINEA IS SIMILARTO LINED

2. M.S. LINEB IS SIMILARTO LINEC

\ 0 PR-74 3. - Cl RCUMFERENTIAL BREAK

4. - TERMINALEND

~: 5. PR - PIPEWHIPRESTRAINT

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REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION MAINSTEAMPIPING ISOMETRIC(PORTIONINSIDE PRIMARYCONTAINMENT)

Sheet1 of2 UPDATEDFSAR FIGURE3.6~2

NOTES:

SEE SHEET1 FOR NOTES.

REVIStON0 APRIL 11. 1988 PUBLIC SERVICE ELECTRIC AND GAS~~~:::

HOPE CREEK NUCLEAR GENERATING MAINSTEAMPIPING ISOMETRIC(PORTIONINSIDE PRIMARYCONTAINMENT)

UPDATEDFSAR Sheet Zof 2 FIGURE3.6-2

NOTES:

1. IRIAKS. WHIP RESTRAINT$ SHOWN ARE TYI'ICAL OF ALL FOU AMAIN ITIAM LINES.

I. liS -PIPEWHIPRESTRAINT I.

0-

-TERMINAL £NO

4. CIRCUfiii"IAENTIAL BREAK L -- I.OCATIOft OF P'R

1. ,)( -BREAKLOCATION 7, I -BUMPER RESTRAINT L ALL wtllll RUTRAINT LOCATIONS ARE TYPICAL fOft THE FOUR MAIN STEAM LINES.

r L ~ PIPING IEVOND Tl-111 POINT

11. f> t1 MODIRATI ENERGY

-IRIAKIIN HIGH ENERGY PIPING BlYOND THIS IIOINT ARE ASSUMED AT EVIAY FITTING.

Rev1s1on12, , 3 2002 Moy Hope CreekNuclearGenerot1n& Stabon PSEG Nuclear,LLC MPJN STEAM PIPING ISOM RIC (PORTION OUTSIDE PRIMARY HOPE CREEK NUCLEAR GENERATINGSTATION CONTPJNMENT>

UpdatedFSAR Figure 3.6-3

© 2000PStG Nuclear.tlC. All RightsReserved.

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Ut REVISION 0 APRil*11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION MAINSTEAMPIPINGAND FEEDWATER PIPINGANCHORFS-11 INSIDEMAIN STEAMTUNNEL UPDATEDFSAR FIGURE3.6*5 I

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1-I I REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION PRESSURE-TEMPERATURE TRANSIENT ANALYSIS MODELFOR A MAINSTEAMLINEBREAKINTHE MAINSTEAMTUNNEL UPDATEDFSAR FIGURE3.6-8

A== 817.9 Ft2 C= 0.69 L/A = 0.028/Ft v = 86,712 ft3 V =854,940 Ft3 A -= 623.5 Ft2 C=0.9 LIA =0.0004/Ft A= 109.0 Ft2 A == 10000 Ft2 C= 0.68 C= 1.0 L/A = 0.077/Ft LIA == 0.0001/Ft V =5,103 Ft3 A= 120 Ft2

@) C= 0.68 L/A = 0.099/Ft A= 365.6 Ft2 C=0.85 L/A = 0.0026/Ft V = 4,618 Ft3 V = 24,294 Ft3 MSLBREAK

@I POINTfj A= 139.26 Ft2 C= 0.82 L/A = OD94/Ft*

A= 215.4 Ft2 v =: 5,249 ft3 c'"'o.84 LIA = 0.01/Ft BOP

@IP = 1 PSIG A= 220.3 Ft2 c =0.76 L/A = 0.210/Ft V =39,532 Ft3 V= 2,643 Ft3 CD A""237.5Ft2 C= 0.80 0

L/A = 0.020/Ft

~-***************************MII I

I II II V == 6,912 Ft3 &

ISOLATEDFROM THE REST OF TUNNELBY VENTILATION BARRIER.

V == 25,735Ft3 REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING ST AliON w****************************

PRESSURE- TEMPERATURE TRANSIENT SCHEMATIC DIAGRAM FOR A MAIN STEAMLINE BREAK IN MAIN STEAMTUNNEL UPDATED FSAR FIGURE3.6*9

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)

,..~-- ~-III!..*Jl-~ /

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A A ELE\/AT=O~

,u_w.._.....

..... *~-

!::]

LOOP ,4 SAME A9 LOCJP IJ 1J;J££SS OiH£~iSE ~SIIEC/F~D PUBLiC SERVICE ELECTRiC AND GAS COMPANY HOPE £REEk NUCLEAR GENERATiNG STATIOi!

ARRAr,JGErtr1ff',ff Of RECIRCULATION LOOP PIPE \i;H;P RESTRAii'JTS Sheet 1 of2 P'.~ ...... ,... _,.,.4ft riUUM£: ~.0* !U

X X

Loop A 0

~. f7

~.I

\I I

i

~' \ Loop B A........_it!III,;J'

.£..., }l:_ \

Ss: I PUBLIC SERVICE ELECTRIC AIID GAS COMPAIIY HOPE CREEKNUCLEARGENERATING STAT;ON I

ARRArJGEMENT OF REC!RCULATIOftJ LOOP P!PE WHIP RESTRA!i'JTS c:a.. ......... ..#) ....... 9

~**'I;I"V~ & VI C.

UPOATELl FSAR FIGURE 3!6-lU

BAR RESTRAINT FRAME (a} Load Applied Perpendicular to Restraint Base Against Cables

• BAR RESTRAINT FRAME lbl Load Applied Parallel to Frame Bose Against One Side of Restramt Frame REVISION0 APRIL 11. 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION TYPICALRECIRCULATION SYSTEM PIPEWHIPRESTRAINT UPDATEDFSAR FIGURE3.6-11

......---,i PR-3 NOTE: l. FIGURESHOWNIS LOOPB.

LOOPA SAMEAS LOOP B UNLESSSPECIFIED r;;;;-'1 INDICATESWHIP RESTRAINT

2. L::.J IDENTIFICATION PR*2

3. C- CIRCUMFERENTIAL BREAK

4. TE. TERMINALEND

5. X* BREAKLOCATION 20" RHR CONN. /

LOOPBONLY 6. PIPE WHIP RESTRAINTS PR 21,22,27, AND 28 ON LOOPSA AND 8 ARE INACTIVE.

IPR-27 ~___... { BP-201 (AE SUPPLIED)

REVISION 0 APRIL* 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION RECIRCULATION SYSTEMISOMETRIC UPDATEDFSAR FIGURE3.6-12

NOTES:

0

1. FW LINEAE-03615SIMILARTO LINEAE-036

2. CIRCUMFERENTIAL BREAK AE-036-0LA 12"

3. C0 LONGITUDINAL BREAK 4.@ TERMINALEND

5. PR PIPEWHIPRESTRAINT 6.- LOCATIONOF PR 7.~ BUMPERTYPE RESTRAINT IPR-2081 B. A

9. )(

ANCHOR BREAKLOCATION 10.0 SLOTBREAK,DEFINEDAS A LONGITUDINAL BREAKIN THE RUN PIPINGWITHFLOWAREA EQUALTO THE CROSSSECTIONALAREAOF THE WELDEDATTACHMENT.

11. LOCATEDON AE*036-DLA-12" ONLYWITHFLOWAREA EQUALTO CROSS-SECTIONAL AREABASEDON INSIDE DIAMETEROF BRANCHPIPE.

(SEE NOTE11)

REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AE-035-DLA-20' FEEDWATERPIPINGISOMETRIC (PORTIONINSIDEPRIMARY CONTAINMENT)

UPDATEDFSAR FIGURE3.6*13

( NOTES:

0 CIRCUMFERENTIAL BREAK e

1.

2. TERMINALEND

~*

3. RS PIPEWHIP RESTRAINT(FWl (SAMEON BOTH FW LINES)

B-2

4. PR PIPEWHIP RESTRAINTCNON FW) s.

B BUMPERRESTRAINT

• • LOCATIONOF PR

7. n9n BUMPERTYPE

.

• ANCHOR AE-037-DBB-24"

8. )( BREAKLOCATION

.... 1 RS-4

• ~ PIPINGBEYONDTHISPOINT HASBREAKSASSUMEDAT

(

EVERYFITTING

~ ~

j

11. PIPINGBEYONDTHIS POINT IS MODERATEENERGY

12. SHIMMINGNOTREQUIREDPER NO BREAKZONE ITYP.2 LINES)

DELETIONOF ARBITRARY INTERMEDIATE BREAKS AE-034-0BB-24" AE-036-DLA-24" AE-034-DBB-4" a

Revision September 25. 1996 PUBLIC SERVICE ELECTRIC AID GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION FEEDWATERPIPINGISOMETRIC

. ( AE-035-0LA-24"

{PORTIONOUTSIDEPRIMARY CONTAINMENT)

UPOATED FSAR FIGURE3.&-14

e s NOTES:

1. NODEPOINTS AND C2"*DBA*110) ARE PARTOF THE REACTORVESSELDRAIN.

2. @ - CIRCUMFERENTIAL BREAK

3. @ -TERMINAL END

4. PR - PIPEWHIPRESTRAINT

6. - LOCATIONOF WHIP RESTRAINT 6.

~ -BUMPERTYPERESTRAINT

7. A -ANCHOR p:>-

8. X -BREAKLOCATION

9. PIPING BEYOND THIS POINT IS 1,.NOMINALDIAMETER r~-PIPING

10. BEYONDTHISPOINT IS MODERATEENERGY

~ 11. 0 - LONGITUDINAL BREAK 4"x2" REO.

~

~

~\

Revision7 December 29, 1995 PUBLIC SERVICE ELECTRIC AID GAS co*MY HOPE CREEK NUCLEAR GENERATING IT ATION EL. 87'-8 112" I

PR-261.._,- -...~1111'..

RWCU PIPING ISOMETRIC (PORTIONINSIDEPRIMARY CONTAINMENT)

UPDATEDFSAR FlOURE 3.8*15

2 3 4 5 HV-F039

.... {V021) c c

~,

'""-. FOR CONT.

SEE FiG.3.6-14 FOR CONT.

SEE FIG. 3.6*15 B

NOTES: B

1. - C~RCUMFERENTIAL BREAK

2. @ -TERMINAL END BREAK

3. R -PIPEWHtPRESTRAINT 4, - -LOCATIONOF WHIP RESTRAtNT

5. ~ -BUMPERTYPE RESTRAINT 6.

7.

8.

e-A X

-ANCHOR DENOTESROOM NUMBER

-PIPE BREAKLOCATION l BG-005*DBC3"

9. If1> PIPINGBEYONDTHISPOINT JS 1" NOMINALDIAMETER BG-006*DBC*3" A

• to. ~ PiPINGBEYONDTHISPOiNT I

I

~REACTOR IS MODERATEENERGY ~------------------------------~ A WATER CLEAN-UP PSEC tm.EM LLC

11. ~ PIPINGBEYONDTHISPOINT HASBREAKSAT EVERYFtTTING PUMP 1BP-221 HOPE CREEK CEtiRATMC STATION RWCU PIPitli IS(I4E TRIC

12. **- SHtMMINGNOT REQUIREDPER DELETIONOF ARBITRARY (Pmll'* OUTSUE PRIMARY C'*TAitHNn INTERMEDIATE BREAKS Updoted F'SAR Sheet 1 of 3 Rev1s1on 21, Nov \2115 Fa g. 3.6-16 2 3 4 5 C1) 2013 PSEG Nuclear LLC. AI I Rights Reserved.

• NOTES:

SEE SHT. 1 FOR NOTES CLEANUP Fl LTEA OEMINELARIZER 1AF203 CLEAN*UPFILTEA DEMINERALIZER 1BF203 4V-':J9388 CONT.ON SHT.3

• ~

REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ElECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION RWCUPIPINGISOMETRIC (HIGHENERGYPORTIONOUTSIDE PRIMARYCONTAINMENT)

UPDATEDFSAR Sheet2of3 FIGURE3.6-16

NOTES:

CLEAN*UP FILTER SEE SHEET 1 FOR NOTES DEMINERALIZE A AF 203

~~

1AP*223 FOR CONT. SEE SHT.2

-t

~V015

/ PUBLIC ND GAS SERVICEEEKLGEEC:~~lNG COMPANY STATION HOPECRE AWCUPIPING1;oO~~~SIDE (HIG~ir~~~~~~~~AINMENl)

Sheet3 of3

A*3.5ft2 UA-0.92/ft C*0.62 RWCUFiler (!J RWCUFIRtt (l Demlnerallzer Demlneralizef Rm4621 Rm4620 B 162ft E1162ft v- 1,100ft3 v- 1,100ft3 A-4.6ft2 UA*0.22/It A-29.1 ft2 C*0.82 A*17.2ft2 LIA

• 0.22/ft C*0.63

!A A*19.6ft2 UA*0.1811't c-o.83 LIA-0.17/ft

~*4*0.82 RWCUHeat:Ex Rm4506

(§J

~Pf::r*

U) Rm4502 RWCUYalve&

PumpRoom Q) Rm4503 RWCU Valve & ~

E1145ft v- 6,860ft3 El 145ft PllnpRoom v- 10,300 ft3 Rm4SOS y .. 2,900JIS c4- 3*0.84 v- 2,820ft"J El145ft I

A*3'.0ft2 A*189.4ft2 LIA*O.OMI: A*30.Sft2 UA*0.12/ft UA*0.121ft

~ .... 3-0.827 eo-7-0.87

~-.s*0.66 ~-12*0.62 C,::t-7*0.84 c,.a-7*0.84 Rm4405 RWCU Pllnp Room

~UI

~~~time Q) Rm4403 RWCU cw a 132ft v- 5,700ft3 Plln~Room v- 2,780ft3 Rm4402

£ El1 ft v- 2,700ft3 £ A*84.2ft2 A*4&.oft2 UA*0.07/ft UA*0.1MI

@ C*0.84 (7- 9 *M2 Almo$pl)ere Ca- 7-0.86 v- 1iJllft3 80P@1~

A

• 288

~Chase B 102ft

<E Rm4319 Rm4327 0 UA

• 0.01/ft v.. 14,000 I'P RCIC~eCime El102 HPCI~~ Chase c-o.83

• Rm4321 v- 4,000ft3 El 102 v .. 3,500ft3 3

A*277ft2 A*72ft2 A-63.0 A*173 ft2, ltlge pals UA*0.11m SteamVn @ UA*O.OOift IJA-0.1Mt LIA*0.1 :.\111 El133.25ft Cs-,o-0.91 Ca-1o*0.89 C14-1o*O.90 C*0.91 v -~9,409 ft3 c,o-e-0.82 c,o- e*0.82 C,o- 14* 0.82 I

..ca.p-0279 I

SteamVent El102-198ft v- 8,74Sft3 Plpt Cllast El102 Rm 4329 Rm4409 v- 14,000ft3 A*216ft2 IJA*0.1&'1'1 C*0.82 Q

El54

&77ft TorusChamberCompartment Rm4102 V = 4.8x10Sft3 J BOP I BOP I BOP BOP @ 0.25pslg 0 @ Typ. ofInternal Panels lrfRmPump and  ::;.clf:P & ~f:P&  ::..~

El54ft a 54ft 954ft El 54ft v- 37,000ft3 v - 35,000 ft3 v -18,000 ft3 v - 37,000 ft3 A*48.4ft2 A*48.4ft2 A-10.5ft2 UA*0.1m UA-0.331'11 c-o.e2 c-o.e2

.&. CASE 1, &.CASE 2, etc.

NOTES: PUBLICSERVICEELECTRICANDGAS COMPANY

1. The volumes shown on this figure have been reduced by HOPEGREEKGENERATINGSTATION the volume of equipment as estimated on Sheet 13.

2. Room 4329 bas no high-energy lines and is conservatively PRESSURE-TEMPERATURE neglected. TRANSIENT SCHEMATICDIAGRAM

3. C is same in both directions unless noted otherwise. FOR HPCI,RCIC,AND RWCU UNE BREAKSOUTSIDECONTAINMENT Updated FSAR Sheet1 of 1 Revision 2, April11.1990 Fig. 3.6-17

MAINSTEAM //

/ \

AB-032-V(D)LA- 26~ // ~

/// /~80

/

,/

NOTES:

~

1. - CIRCUMFERENTIAL BREAK

,/

2. - TERMINALEND

3. PR - PIPEWHIPRESTRAINT

4. - LOCATIONOF PR

5. nh - BUMPERTYPE ..,._ 001-DBA-10"

6. A - ANCHOR

7. X - BREAKLOCATION 8.

• • - SHIMMINGNOTREQUIREDPER DELETIONOF ARBITRARYINTERMEDIATE BREAKS REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ElECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION HPCISTEAMSUPPLYPIPING ISOMETRIC (PORTION INSIDE PRIMARYCONTAINMENT)

UPDATEDFSAR FIGURE3.6-18

.-~--~~-----------------------------------------------------

NOTES:

1. @ TERMINALEND

2. X BREAKLOCATION

3. Jxxxx) ROOM NUMBER R3

..., ,FOR CONT. SEE FIGURE3.6*18 4.

~ PIPINGBEYONDTHISPOINT IS 1"NOMINALPIPE SIZE 5.

~ PIPINGBEYONDTHISPOINT IS MODERATEENERGY

8. ANCHOR

7. CIRCUMFERENTIAL BREAK

8. R PIPEWHIPRESTRAINT 9.~ BUMPERTYPE RESTRAINT 1 0 . - PIPEWHIPLOCATIONS

11. ** SHIMMINGNOTREQUIREDPER DELETIONOF ARBITRARY F0.002*DBB.S" INTERMEDIATE BREAKS PUBLICSERVICEELECTRICAND GAS COMPANY HOPE CREEKGENERATINGSTATION HCPISTEAMSUPPLYPIPING ISOMETRIC(PORTIONOUTSIDE PRIMARYCONTAINMENT}

UPDATEDFSAA REVISION1, APRIL11, 1989 FIGURE3.6-19

w i=

u; w

a:

)

en en LLI a:

a.

zt-LLI t-a:

~

0 0

~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~

~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~

~

~ ~

~ ~

PUBLICSERVICEELECTRICAND GAS COMPANY HOPE CREEK GENERATINGSTATION PRESSURETRANSIENT ANALYSIS FOR A HPCI STEAMSUPPLYLINE B IN THE HPCIPUMPROOM UPDATEDFSAR REVISION1, APRIL11, 1989 FIGURE3.6-20

COMPARTMENT TEMPERATURE VS. TIME o..Q..,...

,~

~~

' l\

\\

\

\

'~ ....0

~~

' "~ ~

--..................... .......__ "~~ -

.A~o.... .......

~ 0 i.... 8....

PUBLICSERVICEELECTRICAND GAS COMPANY HOPE CREEK GENERATINGSTATION TEMPERATURE TRANSIENT ANALYSIS FOR HPCISTEAM SUPPLYLINE BREAKIN THE HPCIPUMPROOM UPDATEDFSAR REVISION1, APRIL11,1989 FIGURE3.6-21

NOTES:

~

1. - CIRCUMFERENTIAL BREAK

2. - TERMINALEND

3. PR - PIPE WHIP RESTRAINT

4. - LOCATIONOF PR

5. Ph - BUMPERTYPE 6.

7.

• X

- ANCHOR BREAK LOCATION 8.

• • - SHIMMINGNOT REQUIREDPER DELETIONOF ARBITRARYINTERMEDIATE BREAKS REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION RCICSTEAMSUPPLV PIPING ISOMETRIC(PORTIONINSIDE PRIMARYCONTAINMENT)

UPDATEDFSAR FIGURE3.6*22

NOTES:

1. -R- PIPE WHIP RESTRAINT

2. CIRCUMFERENTIAL BREAK FOR CONT.

SEE FIG. 3*6*22 3. @ TERMINALEND

' ' ..... ...,... 4. LOCATIONOF RESTRAINT

.. 5. X BREAKLOCATION

6. A ANCHOR 7.

fh PIPINGBEYONDTHISPOINTIS 1" NOMINALPIPE DIAMETER 8.

~ PIPINGBEYONDTHIS POINTIS MODERATEENERGY

9. DELETED

10. lxxxxI DENOTESROOM NUMBER

11. ** SHIMMINGNOT REQUIRED PER DELETIONOF ARBITRARY INTERMEDIATE BREAKS REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION RCICSTEAMSUPPLYPIPING ISOMETRIC(PORTIONOUTSIDE PRIMARYCONTAINMENT)

UPDATEDFSAR FIGURE3.&.23

-~

N J

~- -

0 v"

./

v

/

c:s

~

l--- ~ ~ j LLI

& ~

i= ..a

'\

u; ,___... ..

LLI a: \ 1\

l

'~

U'.J en LLI a:

a.

z '1\

w ~

....a: 1!\.

~

& 'IIIII 0

0 .., r- *

\ t;:,.

i\ 11\ .....

~'

~

~

r---...........

'~

0 (VIScl):a~nSS3~ct PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK GENERATING STATION PRESSURETRANSIENT ANALYSIS FOR A RCIC STEAMSUPPLYLINE BREAKIN THE RCIC PUMPROOM UPDATEDFSAA REVISION1, APRil11,1989 FIGURE3.6-24

COMPARTMENT TEMPERATURE VS. TIME N

~ I l

\'

"" ~

~~

0

t. ""..

--.... :::..).. .,

t

~

1~

' 1\

U'

\ ~

co ......,

\'  :::&

F=

I"~ i

" ~

~

~

""' 4 t'l

~~

~~...._

' ~ .......

0

~ ~

t'l ~~~~~

0 N ~ i..... .....2 .....~ ... ... -- - - 8i2 i:5~fil ~ 0.....

PUBLICSERVICEELECTRICAND GAS COMPANY HOPE CREEKGENERATINGSTATION TEMPERATURE TRANSIENT ANALYSIS FOR RCIC STEAMSUPPLYLINE BREAKIN THE RCIC PUMPROOM UPDATEDFSAR REVISION1, APRIL11,1989 FIGURE3.6*25

NOTES:

1. 0 - CfRCUMFERENfiAL BREAK

2. @ -TERMINAL END 3.

4.

5.

6.

- R - PIPE WHIPRESTRAINT

-LOCATIONOF RESTRAINT

- BUMPERTYPE

-ANCHOR

7. BREAKSPOSTULATED AT

-EVERYFITTING REVISION ~

APRIL 11, NO GAS COMPANY PUBLIC SERVI:~:LLEE;~~~~~RATING STAnON HOPE CREEK RAIN PIPING MAINSTEAMDRTIONINSIDE ISOMETRIC(~NTAINMENT)

PRIMARYc=::.:____~_ . ,._, I UPDATEDFSAR FIGURE3.6-2 6

NOTES:

1. p>- PIPING BEYOND THIS POINT IS 1" NOMINAL PIPE SIZE.

2. *p>-- PIPING BEYOND THIS POINT p:>-

IS MODERATE ENERGY.

3. BREAKS ARE POSTULATED AT EVERY* FITTING IN PIPING BEYOND THIS POINT

4. ~ -BUMPER TYPE

s. )( - DENOTES BREAK LOCATION 1J

8. -DRAIN POT OFF THE MAIN STEAM LINES.

7. R -PIPE WHIP RESTRAINT

8. -- LOCATION Of PIPE WHIP RESTRAINT i, 9. -TERMINAL END 0

0 -CIRCUMFERENTIAL BREAK

• ~

CD FOR CONT.

0 10.

"t 1 v

SEE FIG.3.&3

• CTYP.)

ID

• I SEE NOTE4 FOR CONT. SEE FIG. I ....

Revision7 tift' December 29, 1995

,c; PUBliC SERVICE ELECTRIC AID GAS CO.AIY HOPE CREEK IUCLEAR BEIERATIIG ITATIOI MAIN STEAM DRAIN PIPING ISOMETRIC (PORTION OUTSIDE PRIMARY CONTAINMENT)

UPDATED FSAR Shiel1of2 FIGURE3.8-27

8 7 5 4 2 H H NOTES:

1. 8 - BUMPERRESTRAINT

2. R -PIPEWHIPRESTRAINT

3. -TERMINAL END G 4. -CIRCUMFERENTIAL BREAK

5. -- LOCATION OF PIPEWHIPRESTRAINT

-BREAK LOCATION

- PIPINGBEYONDTHISPOINT IS 1,. NOMINALPIPE SIZE 8.

-PIPING BEYOND THIS POINT IS MODERATEENERGY.

9. -BREAKSAREPOSTULATED AT EVERY FITTING IN PIPING BEYOND THIS POINT 84 R3/R4 R2 E E 87 R13/R14 11/R12 89 D 0 R21/R22 AB.078*D8A*2" 811 FOR CONT., SEE FIG. 3.6-3

.. / (TYP.OF 4)

/ R31/R32 c c B 8 PSEG NUCLEAR,L.L.C.

A HOPE CREEK GENERATINGSTATION A MAH1 STEAH DRAIN PIPI~IG ISOHETRIC (PORTION CIUTSIOF PR!HARY CCIIH AlNHF~ITl L co Updated FSAR Sr,eet "- ot "-

~ ~

Revtswn 'J i'-, Ma~ '00r J :_

J, C::

8 l 4

NOTES:

1) BREAKSPOSTULATED AT EVERYFITTING

. ANDCHANGEOF DIRECTION.

2) PIPINGBEYONDTHISIS 1"NOMINALDIAMETER.

3) PIPINGBEYONDTHISIS MODERATEENERGY.

FOR CONT.

SEE PT. A ,,"'"'

ON THISOWG. 5"'

REVISION 0 F0021 +--,

APRIL 11, 1888

,....__ AB-030-VLA-26" (V191I~ Jl PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION (M.S. UNE A)

RPV HEADVENTPIPINGISOMETRIC UPDATEDFSAR FIGURE3.6-28

NOTES:

CORE SPRAYLINE BE* 023* DLA*12" (2:> PIPINGBEYONDTHISPOINTIS I

1}

MODERATEENERGYPIPING.

~

vo~

PIPINGBEYONDTHISPOINTHAS 2)

I BREAKSASSUMEDAT EVERY FITTINGAND CHANGEOF DIRECTION.

~*

REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AID GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION STANDBYLIQUIDCONTROL INJECTION PIPINGISOMETRIC UPDATEDFSAR FIGURE3.6-29

NOTES:

1. @)CIRCUMFERENTIAL BREAK

2. @ TERMINAL END

3. PR-PIPE WHIP RESTRAINT

4. - LOCATION OF PR

6. ,A, BUMPER TYPE

6. A ANCHOR

1. X BREAK LOCATION

8. ~ PIPING BEYOND THIS POINT IS MODERATE ENERGY

9. -SHIMMING NOT REQUIREO PER DELETION OF ARBITRARY INTERMEOIA.fE BREAKS

• DLA*010t CCA*114

~

I I IIBBRECIRCoLOOP B 0

28" VCA 0111 0 0

____ rp I I I

• • PR -121 I Revision 7 December 29, 1995 PUIUC SERVICE ELECTRIC MD lAS C. .AIY HOPE CREEK NUCLEAR GENERATIIO STAnDI RHR SHUTDOWN COOLING SUCTION PIPING ISOMETRIC

• UPDATED FSAR FIGURE 3.8-30

l l l i . I - J . .1. .J - - - - - - - - - - - - : . . . . . - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - " - - - - - -. . . .

NOTES:

I PR*1361t--+-*

1. @-CIRCUMFERENTIAL BREAK RECIRCULATION LOOP A

2. @ - TERMINAL END

3. PR - PIPE WHIP RESTRAINT

4. - - LOCATION OF PR I. X - BREAK LOCATION I. **-SHIMMING NOT REQUIRED PER DELETION OF ARBITRARY INTERMEDIATE BREAKS

~

Revision7 December 29, 1995 PUBLIC SERVICE ELECTRIC AID GAS co*ANY HOPE CREEK NUCLEAR IEIERATIIIGITATIOI RHR SHUTDOWN COOLING RETURN PIPING ISOMETRIC LOOP A UPDATED FSAR Sheet 1of2 FIGURE 3.8-31

• RECIRCULATION LOOPB NOTES:

1. 0 -CIRCUMFERENTIAL BREAK Revision7 December 29, 1995

2. -TERMINAL END PUBLIC SERVICE ELECTRIC AID IAI COIIPAIY

3. PR -PIPEWHIPRESTRAINT HOPE CREEK IUCLEAR GEIERATIIG IJATIOI

4. --LOCATION OF PR RHR SHUTDOWN COOLING RETURN PIPING ISOMETRIC

5. X -BREAKLOCATION LOOPB

6. -SHIMMINGNOTREQUIRED PER DE LETIONOF ARBITRARY Sheet2of2 INTERMEDIATE BREAKS UPDATEDFSAR FIGURE 3.8-31

NOTES:

~

1. -CIRCUMFERENTIAL BREAK

2. - TERMINAL END

3. PR - PIPE WHIP RESTRAINT

4. - LOCATION OF PR

5. !lh - BUMPER TYPE 6.

7.

X

- ANCHOR

- BREAK LOCATION 8.

• • - SHIMMING NOT REQUIRED PER DELETION OF ARBITRARY INTERMEDIATE BREAKS ELEV. 106'.0" REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND.GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION LPCI INJECTION PIPING ISOMETRIC

"'- ELEV. 106' .0" UPDATED FSAR FIGURE 3.6-32

• I

/

(/.~~,

....- ------- ......... NOTES:

1.

2.

0 CIRCUMFERENTIAL TERMINALEND BREAK

3. PR PIPE WHIPRESTRAINT

4. LOCATIONOF PR

5. ~ BUMPERTYPE 6.

7.

)(

ANCHOR BREAKLOCATION

~

8. PIPINGBEYONDTHISPOINT IS MODERATEENERGY.

9.

• • -SHIMMING NOT REQUIRED PER DELETIONOF ARBITRARY INTERMEDIATE BREAKS

___,, PR-991

~:-F~z~, ** I PR-108 REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION CORE SPRAYINJECTION PIPINGISOMETRIC INSIDECONTAINMENT UPDATED FSAR FIGURE3.6-33

REACTORVESSELDRAINPIPINGISOMETRIC INCLUDEDAS PARTRWCU PIPING ISOMETRIC(PORTIONINSIDEPRIMARY CONTAINMENT),

FIGURE3.6-15 REVISION 0 APRIL 11. 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK IUCLEA.R GENERATING STATION REACTORVESSELDRAINPIPING ISOMETRIC UPDATED FSAR FIGURE3.6-34

THISFIGUREHASBEENDELETED PSEG NUCLEARLL.C.

HOPECREEKGENERATING STATION HOPECREEKUFSAR -REV 14 SHEET1 OF 1 July 26, 2005 F3.6-35

TYPICAL FORCE DEFLECTION CURVE fOA A 6-BAR, 24*tn. PIPE RESTAA"IT LOAD'EO AT 00 1100~----------~--------------------------------------,

24 F

• 6(102.2284& .. &.98410. 1 - " " '

/

/

//

/

/ / DEFLECTIONLIMit J

//~LINEAR IDEALIZATION

,..__ _ TOlAL CLEARANCE* 5.98in .

• 10 PIPE OEFLECTION.6 Cin.t 12 15 TOTALCLEARANCE* +

INIT~

CLEA~ANCE 14 *nJ EF:J CLEARANCE f1.88in.l REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION TYPICALFORCE-DEFLECTION CURVEFOR RECIRCULATION SYSTEMPIPEWHIP RESTRAlNT UPDATED FSAR FIGURE3.6-36

KEY:

~* TYPICALBREAKLOCATION

~

• TYPICAL~ESTRAINT Revision 7 DESIGNATION December 29, 1995 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION BREAKLOCATIONS AND RESTRAINTS ANALYZED, PDA VERIFICATION PROGRAM UPDATEDFSAR FIGURE3.6-37

v NORTH CONTAINMENT WALL .;If' I ,,

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3.7 SEISMIC DESIGN All structures, systems, and components are defined as either Seismic Category I or non-Seismic Category I. The requirements for Seismic Category I identification are given in Section 3.2 with a list of the qualified structures, systems, and components.

All structures, systems, and components important to plant safety are designed to withstand a safe shutdown earthquake (SSE} and an operating basis earthquake (OBE).

The SSE is based on an evaluation of the maximum earthquake potential considering the regional and local geology, seismology, and specific characteristics of local subsurface material. The SSE produces the maximum vibratory ground motion for which Seismic Category I structures, systems, and components are designed to remain functional. These structures, systems, and components are those necessary to ensure:

1. The integrity of the reactor coolant pressure boundary (RCPB).

2. The capability to shut down the reactor and maintain it in a safe shutdown condition.

3. The capability to prevent or mitigate the consequences of accidents that could result in potential offsite exposures comparable to the guideline exposures of 10CFR50.67.

The OBE is an earthquake that, considering the regional and local geology, seismology, and specific characteristics of local subsurface material, could reasonably be expected to affect the plant site during the operating life of the plant. Seismic Category I structures, systems, and components of the nuclear power plant necessary for continued operation without undue risk to the health and safety of the public are designed to remain functional 3.7-1 HCGS-UFSAR Revision 17 June 23, 2009

and within applicable stress and deformation limits during the vibratory ground motion produced by an OBE.

3.7.1 Seismic Input 3.7.1.1 Desian Response Spectra The design response spectra, which comply with the requirements of Regulatory Guide 1.60, are shown on Figures 3.7-1 and 3.7-2, in both the hor-izontal and vertical directions, respectively, for the SSE.

For the OBE, the design response spectral values are taken as half of the SSE values.

Based on geological and seismological information, as discussed in Sections 2.5.2.6 and 2.5.2.7, the maximum ground acceleration values for both horizontal and vertical components of the earthquake are 10 percent and 20 percent of gravity for an OBE and SSE, respectively.

The vibratory ground motion (free field) produced by the seismic motion, as defined by the design response spectra, and the design time history are conservatively applied at the elevation that corresponds to the bottom of the structural foundation in the free field wi~hout the effect of the structures.

3.7.1.2 Desi&n Time Histpty Two synthetic time history motions of 24 seconds duration have been generated by modifying the 1952 Taft earthquake according to the techniques described in Reference 3.7-1. The synthetic time history motions have been generated because the response spectra of available recorded earthquake time histories do not adequately match the site design response spectra. Figures 3.7-3 and 3.7-4 show the synthetic time history motions for the SSE in horizontal and vertical directions, respectively. These time history motions are the same time histories shown in BC-TOP-4A, Reference 3.7-1. For 3.7-2 HCGS-UFSAR Revision 0 April 11, 1988

the OBE, the values of the synthetic time history are taken as half of the SSE values.

Figures 2-13, 2-14, 2-17, and 2-18, in Reference 3.7-1, show that the response spectra of the synthetic time-history motions for the horizontal and vertical directions envelop the corresponding design spectra for 1 percent, 2 percent, 5 percent, 7 percent, and 10 percent damping values. The response spectra are computed at 71 frequencies identified in Section 2.5.1 of Reference 3.7-1.

The design time histories are used in the structural seismic analysis. The acceleration time-history from the result of the structural seismic analysis is used for the generation of floor response spectra.

3.7.1.3 Critical Dampin& values 3.7.1.3.1 Critical Damping Values (NSSS)

The damping factors indicated in Table 3.7-1 are used in the response analysis of various Nuclear Steam Supply System (NSSS) systems. components, and equipment, and in preparation of floor response spectra used as forcing inputs for piping and equipment analysis or testing.

For a general compliance or alternate approach assessment, see the Regulatory Guide commitment matrix in Section 1.8.1 for commitment, revision number, and scope.

GE supplied NSSS analysis, design, and/or equipment used in this facility is in compliance with the intent of Regulatory Guide 1.61, which delineates damping values that should be applied to modal dynamic seismic analysis of Seismic Category I structures and components. The damping values used in the seismic analysis conform to the data available on the subject when the analysis was performed, which was the practice accepted by industry and the NRC at the time of the design.

3.7-3 HCGS-UFSAR Revision 0 April 11, 1988

The damping values shown for NSSS materials in Table 3.7-1 are less than those given by Regulatory Guide 1.61; therefore, the calculated responses are conservative.

3.7.1.3.2 Critical Damping Values (Non-NSSS)

For non-NSSS Seismic Category I structures, systems, and components, critical damping, values, expressed as a percentage of critical damping are shown in Table 3.7-2 and comply with Regulatory Guide 1. 61. For cable tray support systems. the damping value is 15 percent of critical for the SSE. As discussed in Section 3.10.3, the testing of cable tray systems clearly demonstrates that a substantial amount of vibration energy is dissipated by friction between cables and by friction between cables and the cable tray.

The strain dependent soil damping values used in the seismic analysis are based upon measured values, as shown in Section 2.5.4.

3.7.1.4 Supportin& Media for Seismic Cate&OIY I Structures All Seismic Category I structures, including plan dimensions of foundation, foundation embedment depth, and total structural height are listed in Table 3.7-3.

The structures in the power block area and the Station Service Water System (SSWS) intake structure rest on the Vincentown Formation, as identified in the soil profiles of Figures 3.7*5 and 3.7-6.

However, there is approximately a 10-foot layer of engineered backfill between the foundation and the Vincentown Formation. A description of the supporting media and their properties is provided in Section 2.5.4.

3.7.1.5 SRP Rule Review Acceptance Criterion II.l(b) of SRP Section 3.7.1 addresses design time history calculations for seismic ground motion. Specifically, spectral values calculated from the design time history should have 3.7-4 HCGS-UFSAR Revision 0 April 11, 1988

frequency ranges in agreement with Table 3. 7 .1*1 of the SRP, or selection of a set of frequencies should be such that each frequency is within 10 percent of the previous one. In addition, no more than five points of the spectra obtained from the design time history should fall below the design response spectra.

On Hope Creek, in the chosen set of frequencies for the 28*33 Hz range, each frequency is generally not within 10 percent of the previous one. In addition, the spectra obtained from the design time history have more than eight points that fall below the design response spectra for 1 percent, 2 percent, 5 percent, and 7 percent damping.

The design time histories used on Hope Creek are taken from Bechtel Topical Report BC*TOP-4A, Revision 3. These time histories that encompass the SRP deviations have been reviewed and approyed by the NRC Staff.

3.7.2 Seismic System Analysis 3.7.2.1 Seismic Analysis Metbods 3.7.2.1.1 Seismic Analysis Methods (NSSS)

Seismic Category I NSSS systems and components are under the category of a seismic subsystem and are discussed in Section 3.7.3.

3.7.2.1.2 Seismic Analysis Methods (Non-NSSS)

The two analytical methods utilized for the structural response analysis and the seismic soil structure interaction of Category I structures are discussed in the following sections. The Seismic Category I structures are supported by separate foundation base mats. The relative motions between the base mats are calculated in the soil structure interaction analyses, and the seismic joints between the base mats are designed to accommodate twice the maximum relative displacement between the adjacent base mats. Methods to 3.7-5 HCGS-UFSAR Revision 0 April 11, 1988

account for relative displacement effects on Seismic Category I systems and components are discussed in Section 3.7.3.

3.7.2.1.2.1 Soil Structure Interaction Two methods used to analyze the soil structure interaction effects are the finite elements method and the impedance (half-space) approach. The finite element method is used for the design base and the independent verification analysis, whereas the impedance approach is used to reconcile the results of the finite element analysis.

3.7.2.1.2.1.1 Finite Element Method In the finite element method of analysis, the design earthquake motion is defined at the foundation level in the free field. This motion is deconvolved in a one dimensional free field analysis of the site soil deposits to determine the bedrock motion at the base of the soil column model. When this bedrock motion is applied at the base of the soil column, it produces the design earthquake motion at the control point. One dimensional amplification theory is used for this purpose. The computed bedrock motion is then used as input to a finite 'element model of the soil structure system to compute the structural responses.

The analysis is performed iteratively to account for the strain dependent nature of the nonlinear soil properties. In each iteration the analysis is linear but the soil properties are adjusted from iteration to iteration until the computed soil strains are compatible with the soil properties used in the analysis. The soil structure interaction analysis models are composed of two dimensional, plane strain finite elements representing the structure foundation mats, nonlinear strain dependent soil medium, and lumped mass beam elements representing the structures. The direct integration time history method is used for the soil structure interaction analysis of the intake structure and the East-West and vertical directions of the power block structures.

3.7-6 HCGS-UFSAR Revision 0 April 11, 1988

The complex frequency response analysis method is used for the soil structure interaction of the North*South direction of the power block structures. The building base mat motions, including translation and rocking components obtained from the interaction analysis, are in general used as input for subsequent seismic analysis of the more detailed structural models.

3.7.2.1.2.1.2 Impedance (Half-Space) Approach In the soil structure interaction analysis, using the impedance approach, the effect of the foundation medium is represented by the foundation impedances, which are functions of the base mat dimensions, embedment depth, elastic properties of the foundation medium, and forcing frequencies. With the foundation impedances known, the structure foundation system is modeled by coupling the fixed-base structural model with the foundation impedances through the basemat. The method of coupling and the equation of motion, is described in Appendix D of BC-TOP-4 (Reference 3. 7 -1). The technique used to determine the composite modal damping of the interaction system is also given in Appendix D of Reference 3.7-1.

The effects of embedment which increase both damping and stiffness of the soil structure systems are considered.

3.7.2.1.2.2 Structural Response Seismic structural responses of Category I structures are calculated using the modal superposition time history technique for independent earthquake components in the vertical and two horizontal directions.

Both the OBE and the SSE are considered in all directions for the power block. For the intake structure, the SSE is considered in all directions, and the OBE is considered using the above procedures for the North-South and Vertical directions only. The intake structure OBE load condition in the East-West direction is considered by scaling the appropriate SSE East-West direction conditions by a 70 percent factor. This 70 percent factor is chosen because it is observed from the North-South response spectra that a value of 3.7-7 HCGS*UFSAR Revision 0 April 11, 1988

70 percent of SSE conservatively envelopes the OBE response. The resulting OBE and SSE response data include time-histories of floor acceleration and associated floor response spectra, maximum displacements, and member forces.

Seismic analysis of the structures consider all modes with frequencies up to 33 cps. Consideration of modes higher than 33 cps does not result in more than a 10 percent increase in response.

3.7.2.2 Natural Frequencies and Response L9ads Natural frequencies of the significant modes of the Reactor Building, the Auxiliary Building, and the SSWS intake structure are shown in Table 3. 7-4. The significant mode shapes of the Reactor Building and the Auxiliary Building are shown on Figures 3. 7 *10 through 3.7-57 for each of three orthogonal directions: east-west, north-south, and vertical.

Figures 3.7-58 through 3.7-119 show the structural responses, i.e.,

displacements, accelerations, shear forces, bending moments, and axial forces, of the Reactor Building, the Auxiliary Building, and the SSWS intake structure for each of the three orthogonal directions.

In-structure floor response spectra at critical locations are shown on Figures 3.7-120 through 3.7-155. The curves are shown for each of the three orthogonal directions at the damping values used for each design earthquake. A brief description of the location of each series of response spectrum curves is provided below with the corresponding figure numbers:

1. Figures 3. 7-120 through 3. 7-125

• Reactor Building at Elevation 102 feet 0 inches

2. Figures 3.7-126 through 3.7-131 - Reactor Building at Elevation 201 feet 0 inches 3.7-8 HCGS-UFSAR Revision 0 April 11, 1988

3. Figures 3.7-132 through 3.7-137- Auxiliary Building diesel generator area at Elevation 130 feet 0 inches

4. Figures 3.7-138 through 3.7-143- Auxiliary Building diesel generator area at Elevation 178 feet 0 inches

s. Figures 3.7-144 through 3.7-149 -Auxiliary Building control area at Elevation 137 feet 0 inches

6. Figures 3.7-150 through 3.7-155 Intake structure at Elevation 122 feet 0 inches.

3.7.2.3 Procedure Used for Modeling <Non-NSSS>

section 3.2 identifies the Seismic Category I structures, systems, and components. This section discusses Seismic Category I structures. Section 3. 7. 3 discusses Seismic category I subsystems and components.

Procedures for development of the building mathematical models are discussed in this section, and those for development of the finite element soil models are discussed in Section 3.7.2.5.

The mathematical models of the Reactor Building, Auxiliary Building, and intake structure are shown on Figures 3.7-7 through 3.7-9. The building mathematical models consist of lumped masses connected by massless, elastic beam members.

Masses are located at floor elevations and elevations of major mass concentration. Masses are computed by considering the weights of the floor, floor framing, structural walls, and columns above and below the floor level, nonstructural walls above the floor level, and all equipment (except the reactor vessel), components, and piping systems. The number and location of the mass points are chosen so that all significant degrees of freedom have been incorporated in the models to ensure that an accurate representation of the dynamic response is obtained. Since the mass and stiffness distributions in the buildings are generally unsymmetric, the effects of torsional rotation are 3.7-9 HCGS-UFSAR Revision 0 April 11, 1988

included by using three dimensional models having six dynamic degrees of freedom at each mass point and by including the computed eccentricities between the centers of mass and centers of structural rigidity. The beam elements representing structural walls and columns connecting two adjacent floors are located at the center of rigidity of the cross section. The elastic properties of the beam members include the effects of bending, shear, axial, and torsional structural stiffnesses. Material damping characteristics are defined in accordance with Table 3.7-2, and are incorporated into modal superposition time history analyses, using a strain energy weighting technique.

Separate mathematical models for vertical floor flexibility analysis are formulated for each building. In these models, the floor diaphragms are modeled to allow for vertical floor flexibility effects. The floors are modeled using horizontal elements connected between vertical resisting elements. The horizontal elements are tuned in frequency to match the floor vertical frequencies, as calculated in separate analyses using detailed finite element meshes. The vertical elements represent the concrete walls and steel columns of the building.

Criteria used for decoupling subsystems from Seismic Category I structures are discussed in Section 3.2 of Reference 3.7-1.

3.7.2.4 Soil structure Interaction Three categories of seismic soil structure interaction analyses are performed for the major plant structures. The design base analyses are performed using the finite element method. Independent finite element soil structure interaction analyses are subsequently performed to verify the "design base" analyses. The impedance approach (the half-space) soil-structure interaction analyses are performed to evaluate the adequacy of the finite element soil structural interaction analysis results, used in the plant design.

3.7-10 HCGS-OFSAR Revision 8 September 25, 1996

3.7.2.5 Design Base Analysis The design base seismic soil structure interaction analyses are performed to determine the response time histories at the base mats of all Category I and major non-Category I structures for use in subsequent seismic analyses of the individual structures, and to evaluate maximum dynamic soil pressures beneath the base mats and against exterior walls of the buildings during a seismic event. The maximum dynamic responses (displacements, accelerations, and member forces) induced in the structure due to the building base motions obtained from the soil structure interaction analyses, are determined, and the floor response spectra at selected elevations in each structure are developed for use in subsequent analyses of the structural components, mechanical equipment, and attached piping systems. These analyses are performed for the following structures:

1. Reactor Building

2. Auxiliary Building

3. Turbine Generator Buildings

4. Service Water Intake Structure The soil structure interaction analyses are performed by constructing two dimensional finite element mathematical models of soil and structures at the site. These models are subjected to seismic excitations at the base of the soil model, determined by deconvolution analyses.

For the intake structure and the East-West and vertical analysis of the power block area the computer code DECON is used in the free field soil column deconvolution analysis to generate the bedrock motion. The interaction analyses employ a direct time integration procedure in which the time history of responses of the soil structure system are calculated using a step by step 3.7-11 HCGS-UFSAR Revision 0 April 11, 1988

integration of the coupled equations of motion. The computer code EDSGAP is used for these analyses.

For the North-South analyses of the power block both the free field soil column deconvolution and the soil structure interaction analyses are performed using the computer code FLUSH, Reference 3.7-6.

Figures 3.7-156 and 3.7-159 show the coupled soil and structure models constructed along the north-south and east-west directions for both the power block area and the intake structure.

The soil structure interaction analysis models are used for the following analyses:

1. Figure 3.7-156 is the horizontal model used for the North-South analysis of the Reactor Building and the Auxiliary Building.

2. Figure 3.7-156a is the vertical model used for the vertical analysis of the Reactor Building and the Auxiliary Building.

3. Figure 3.7-157 is the horizontal model used for the East-West analysis of the Reactor Building .

4. Figure 3. 7 -15 7 a is the horizontal model used for the East-West analysis of the Auxiliary Building.

5. Figure 3.7-158 is the model used for the horizontal North-South and Vertical analyses of the intake structure, and

6. Figure 3.7-159 is the horizontal model used for the East-West analysis of the intake structure.

Each model consists of a vertical section of plane strain isotropic quadrilateral elements representing the soil and foundation mats, HCGS-UFSAR Revision 0 April 11, 1988

and lumped mass beam simplified stick models representing the Seismic category I and major non-Seismic category I structures. The simplified models used in the soil structure interaction analyses are two dimensional and are developed based on the detailed three dimensional building models, which are discussed in Section 3. 7. 2. 3. The simplified models have significant mode shapes and frequencies closely matching those of the detailed models.

For the modeling of supporting soil, the lateral boundaries are either simulated by transmitting boundaries or located far enough from the building to minimize the effect due to wave reflections from the model boundary. All significant interaction effects occur within 300 feet of the power block area and 200 feet of the intake structure. An evaluation of soil shear strains and accelerations shows a return to free field conditions within these distances.

Parametric studies are performed for the power block area and the intake structure area to evaluate the depth of soil structure interaction model, variations in soil damping, and variations in soil modulus.

The criterion used in the depth parametric studies is that further increases in the depth of soil structure interaction models would not alter the interactive response of the structures. For the power block area, this criterion is met using a soil structure interaction model with a depth of 402 feet below grade.

For the intake structure area, this criterion is met using a soil-structure

~ interaction model with a depth of 300 feet below grade.

The results of the soil structure interaction analysis for the power block indicate that the average soil strain of the foundation soil is about 4

S.Oxl0- in/in. Based on the available information on soil properties (Figure 2.5-41) it is concluded that the soil properties could vary by approximately +/-50 percent from the final iterated average soil properties. A soil variation study of the power block area was performed using the above bases. The results indicate that the major response spectral peak frequency shifts +/-22 percent and 3.7-13 HCGS-UFSAR Revision 0 April 11, 1988

minor peaks have insignificant frequency shifts. For conservatism, the computed horizontal response spectral peaks are broadened by +/-25 percent for the major peak and +/-15 percent for secondary peaks.

No explicit soil variation study was performed for the vertical direction. Due to the high ground water table, the effective compressional wave velocity of the saturated soil is controlled by the compressional wave velocity of the ground water. Accordingly, the vertical effective compressional wave velocity is not sensitive to variations in the soil shear modules. Therefore, it is concluded that the peak broadening of +/-15 percent for the major peak and +/-10 percent for secondary peaks are adequate.

Because dynamic soil properties underlying the power block area and the intake structure are essentially the same, the broadening criteria for the power block area response spectra are also applicable to the response spectra of the intake structure. However, the design of the intake structure was originally based on preliminary requirements which called for +/-50 percent broadening of the response spectra. The preliminary +/-SO percent spectral peak broadening criteria are maintained as the final broadening criteria for the intake structure response spectra since they are conservative.

The variation studies for soil damping showed that, for the HCGS site, changes from upper bound to lower bound damping properties result in frequency shifts of

+/-2 percent in the building base mat spectra.

The vertical layer depth dimension of the soil finite element mesh is selected based on the procedure outlined in Reference 3.7-6 and Section 3.3 of Reference 3. 7-1 so that the soil model is able to pass an adequately high frequency of the interaction system.

The boundary conditions on the side boundaries of the finite element soil model depend on the direction of input motion. When the input motion is horizontal, the nodal points on the vertical boundaries 3.7-14 BCGS-UFSAR Revision 8 September 25, 1996

are restrained from moving vertically. In the case of vertical input motion, the nodal points on the vertical side boundary of the model are restrained from moving horizontally.

The soil structure interaction analysis is performed by applying the deconvoled bedrock motion at the base of the finite element model developed above. The base rock input motion is generated through deconvolution analysis. Input spectra to the deconvolution analyses are the design response spectra described in Section 3.7.1.1. The input elevations to the deconvolution analyses are the foundation levels of the embedded structures. The technique used for the deconvolution analysis is discussed in Reference 3.7-4.

Separate time history analyses are performed for the vertical and two orthogonal horizontal earthquakes. The analyses for horizontal earthquake excitation are used to determine horizontal base mat as well as rocking acceleration time histories. The analyses for vertical earthquake excitation are used to determine vertical base mat acceleration time histories.

The effective soil shear strain levels, equal to 60 percent of the max~ shear strains, are determined throughout the soil region of the models (For the North-South analysis of the power block, the computer co"de FLUSH calculates effective shear strain levels as 65 percent of the maximum shear strains). Effective shear strain levels are used to determine strain compatible soil properties.

Nonlinear, strain dependent characteristics of the soil are treated using an iterative linear approach. During each step of the iterative analytical process, the assumed soil properties used in the model are evaluated for compatibility with induced strain levels. The properties are revised and the analyses repeated until compatibility within 10 percent is obtained.

For the power block area, the effect of structure-soil structure interaction is considered in the soil structure interaction analyses by including multiple buildings in each model, as shown on Figures 3.7-156 and 3.7-157.

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The initial design base seismic soil-structure interaction analysis was performed using the assumption that construction of both units would be completed prior to start of operation of Unit 1. However, with the cancellation of Unit 2, the Unit 2 Reactor Building is terminated at elevation 132 feet 0 inches, resulting in a non-symmetric configuration. The North-South analysis is revised to include the effects of the Unit 2 cancellation. For the East-West direction, a parametric analysis has been performed to evaluate the effects of the partially completed Unit 2 on the seismic structural responses and other major plant structures. It is concluded that the cancellation of Unit 2 has no significant impact on the seismic structural responses of other plant structures.

3.7.2.5.1 Independent Finite Element Verification Analysis Independent soil structure. interaction verification analyses are performed to verify the accuracy of the results of the design base analyses. These analyses are performed using the finite element method and take foundation embedment into account. The computer code FLUSH is used in this study.

In this independent analysis, the NRC broad band design response spectra are specified at the foundation elevation in the free field.

Simplified seismic structural models for the Reactor Building, the Auxiliary Building, and the Turbine Building are developed for use in the FLUSH soil structure interaction analyses. The dynamic behavior of the simplified structural models compared reasonably well with that of the structural models used in the design base analysis. The horizontal North-South, the horizontal East-West, and the vertical seismic soil structure interaction analyses are performed for both the ~SE and the OBE cases. The results of the independent analyses are determined to be in reasonable agreement with those of the design base analyses.

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3.7.2.5.2 Impedance (Half-Space) Approach Analyses Seismic soil structure interaction analyses of all Seismic Category I structures are performed using the impedance approach with strain independent soil properties for the North-South, East-West and the vertical excitations.

The impedance approach analysis is performed to assess the adequacy of the results of the finite element analysis. The impedance analysis results are used to confirm the adequacy of the plant design.

3.7.2.6 Development of Floor Response Spectra 3.7.2.6.1 Floor Response Spectra (NSSS)

Floor response spectra for NSSS equipment are developed considering three components of earthquake motion. The individual floor response spectra in each orthogonal direction are then obtained as the square root of the sum of the squares (SRSS) combination of the collinear contributions, due to the three directions of earthquake motion. These are used to predict the total floor response spectra at each frequency.

3.7.2.6.2 Floor Response Spectra (Non-NSSS}

Time history analyses for independent excitation in one vertical and two horizontal excitations are performed to develop the floor response spectra. The mathematical models and the analytical method used are as described in Sections 3.7.2.1, 3.7.2.3, and 3.7.2.4.

The floor response spectrum at a given location and direction is developed considering the three components of the earthquake motion. The response spectral values for each frequency at a given location and direction are combined by taking the square root of the sum of the squares (SRSS) of the co-directional response spectral values from each of the three components of earthquake motion at critical 3.7-17 HCGS-UFSAR Revision 17 June 23, 2009

locations. These response spectra are compared to the single directional response spectra, resulting in a difference of less than 5 percent. Therefore, single directional response spectra are used. The effect of rocking causes amplification in floor response spectra. For horizontal floor spectra, rocking effects are directly included due to incorporation of both translational and rocking base mat time-histories in the seismic structural analyses.

For vertical floor spectra, rocking effects are calculated from seismic structural analyses using vertical base mat time histories and rocking time histories separately, and combining the response using the SRSS method.

3.7.2.7 Tbree Components of Earthquake Motion <Non*NSSS)

The time history analysis method is employed for the seismic analysis of all Seismic Category I structures. Maximum structural responses, displacements, accelerations, and member forces, due to each of the three components of earthquake motion, are obtained.

In accordance with Regulatory Guide l. 92, parametric studies were performed to evaluate the significance of an out of plane response from an in plane base excitation. These studies verified that the out of plane structural responses added no significant contribution to the in plane structural responses.

3.7.2.8 Combination of Modal Responses <Non-NSSS)

When the response spectrum method is used in seismic analysis of structures, systems, and components, the modal responses, i.e.,

displacements, accelerations, and member forces, are combined in accordance with Regulatory Guide 1.92.

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3.7.2.9 Interaction Between Adjacent Structures 3.7.2.9.1 Interaction of Non-Seismic Category I Structures with Seismic Category I Structures The Turbine Building and the administration facility are the only non-Seismic Category I structures located near Seismic Category I structures. They are designed to withstand an SSE in accordance with Section 3.8.4. Dynamic analyses of these structures are performed using the time history method. Structure to structure interaction between the Turbine Building and the administration facility, and the Seismic Category I buildings is accounted for by including all buildings in the soil structure interaction model shown on Figure 3.7-157.

Structural separation is provided to ensure that physical contact between Seismic Category I and non-Seismic Category I structures does not occur. Considering the variability and uncertainties associated with parameters in the analysis, the minimum separation between the structures is maintained at twice the absolute sum of the predicted maximum displacements (due to seismic loadings) of the adjacent structures. Table 3.7-6 compares the actual structural gaps with the worst computed gaps.

3.7.2.9.2 Interaction Between Adjacent Seismic Category I Structures Structural separation is provided to ensure that physical contact between adjacent Seismic Category I structures does not occur.

Considering the variability and uncertainties associated with the parameters in the analysis, the minimum separation between the structures is maintained at twice the absolute sum of the predicted maximum displacements (due to seismic loadings) of the adjacent structures. Table 3. 7 *6 compares the actual structural gaps with the worst computed gaps.

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3.7.2.10 Effects of Parameter Variations On Flooi Response Spectra 3.7.2.10.1 Effects of Parameter Variations on Floor Response Spectra (NSSS)

To account for potential variations in the primary structure response frequencies due to uncertainties in material properties of the soil and structure, to the soil structure interaction techniques, to approximation of damping, and to approximations in dynamic modeling, the computed floor response spectra are peak broadened as shown in Table 3.7*7.

3.7.2.10.2 Effects of Parameter Variations on Floor Response Spectra (Non-NSSS)

To account for variations in the structural frequencies. owing to uncertainties associated with the soil modulus, damping, and structural properties, and also to approximations in the modeling techniques used in the seismic analysis, the computed floor response spectra are smoothed, and peaks associated with each of the structural frequencies are broadened.

Variation studies in soil damping, shear moduli, and the depth of soil~models were performed to evaluate the effects on the response spectra at the foundation level. These studies showed some variations in frequency of in*structure response spectra. The overall effect of the shift in the peak frequency of the spectral acceleration on the in-structure response spectra was determined by the SRSS of the individual variations.

The amounts of peak widening associated with the structural frequencies used at HCGS are +/-25 percent for the dominant spectral peaks and +/-15 percent for all other responses for the North-South and East-West directions of the power block area, +/-15 percent for the dominant spectral peaks and +/-10 percent for all other responses for the vertical direction of the power block area, and +/-50 percent for the intake structure.

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3.7.2.11 Use of Constant Vertical Static Factors Equivalent static load factors are not used in the seismic design of Seismic Category I structures. The methodology used for the vertical seismic analysis is similar to the horizontal analysis.

3.7.2.12 Method Used to Account for TorsiQnal Effects <Non-NSSS)

Torsional response in the seismic analysis of the Seismic Category I structures, resulting from eccentricity between center of mass and center of rigidity, is explicitly included in the analytical procedure, as discussed in Section 3.7.2.3.

In addition to the torsional responses discussed above, the shear resisting elements, such as concrete walls, are capable of resisting an additio~al torsional moment assumed to be equivalent to the story shear acting with an additional eccentricity of 5 percent .of the maximum building dimension at that level.

3.7.2.13 Comparison of Responses A comparison between the response spectrum and time history method of dynamic analysis is not applicable, because only the time history method of analysis is used on major Seismic Category I structures.

3.7.2.14 Methods for Seismic Analysis of Dams Dams are not provided on HCGS.

3.7.2.15 Determination of Seismic Catego[y 1 Structure Oyerturnin&

Moments The overturning moment for Seismic Category I structures is the absolute sum of the moments at the level of the base mat of each stick of the mathematical model. For each stick, the moment at the base is determined by the method discussed in Section 3.7.2.1.

3.7-21 HCGS-UFSAR Revision 0 April 11, 1988

The components of the earthquake motion used are the same as those discussed in Section 3.7.2.6.

Section 3.8.5 discusses the factor of safety against overturning for several loadings, including seismic loads.

3.7.2.16 Analysis Procedure for Damping <Non-NSSS)

When the time history analysis with the modal superposition technique is used in the seismic analysis of the structures, the equivalent modal damping ratio for each mode is calculated based on the use of the stiffness as weighting function.

When the time history analysis with direct integration technique (EDSGAD) is used in the finite element soil structure interaction analysis, the damping matrix C is assumed to consist of the following linear combination of the mass M and stiffness K matrices:

C - oM + ,8K (3.7-1)

The damping coefficients, Q and fJ, are determined such that a reasonable approximation of the soil strain compatible damping over the frequency range of interest is provided.

For the finite element soil-structure interaction analysis using the computer code FLUSH, the stiffness matrix or the complex equation of motion are formed using the complex shear moduli.

Where ~ is the fraction of the critical damping which may vary from element to element, G is the shear modulus and i -~. The damping is included in the analysis by the use of complex shear modulus.

For the impedance (half-space) approach soil structure interaction analysis, the damping is included in the composite modal damping of 3.7-22 HCGS-UFSAR Revision 0 April 11, 1988

the interaction system. The technique to determine the composite modal damping of an interaction system is given in Appendix D of Reference 3.7-1.

3.7.3 Seismic Subsystem Analysis This section discusses the seismic analysis of equipment, piping, and supports for Seismic Category I heating, ventilating, and air conditioning (HVAC) ducts, cable trays, conduits, and the NSSS components.

3.7.3.1 Seismic AnAlysis Methods 3.7.3.1.1 Seismic Analysis Methods (NSSS)

Analysis of Seismic Category I NSSS systems and components is accomplished, where applicable, using the response spectrum or time history approach. Both use the natural period, mode shapes.,

and appropriate damping factors of the particular system. Certain pieces of equipment that have very high natural frequencies are analyzed statically if the fundamental frequency of the component is greater than the zero period acceleration (ZPA} frequency of the excitation. In some cases, dynamic testing of equipment is used for seismic qualification.

The time history analyses involve the solution of the equations of dynamic equilibrium discussed in Section 3.7.1.1.1 by means of the method discussed in Section 3.7.3.1.1.2. In this case, the duration of motion is of sufficient length to ensure that the maximum values of response have been obtained.

A response spectrum analysis involves the solution of the equations of motion discussed in Section 3.7.3.1.1.1 by the method discussed in Section 3.7.3.1.1.3. The method of combining responses for the three components of an earthquake motion is described in Section 3.7.3.6 for NSSS systems, components, and equipment.

Seismic and dynamic analysis methods include the investigation of a 3.7-23 HCGS-UFSAR Revision 0 April 11, 1988

sufficient number of modes to ensure participation of all significant modes. All modal responses that cumulatively contribute to at least 90 percent of the total response are included. This meets the criterion that the inclusion of any additional modes does not result in more than a 10 percent increase in the overall response.

3.7.3.1.1.1 The Equations of Dynamic Equilibrium Assuming velocity proportional damping, the dynamic equilibrium equations for a lumped mass, distributed stiffness system are expressed in matrix form as:

[M] {u (t)} + [C) {u(t)} + [K] (u(t)} - 0 (3.7-2) or (M]{u(t)) + [CJ{u(t)} + [K]{u(t))

• P(t) 3 *IM]{u (t))

8 where:

{u(t)} time dependent displacement vector (lxN) of nonsupport points relative to the base support displacement u s (t)

{u(t)} time dependent velocity vector (lxN) of nonsupport points relative to the base support velocity u (t)

{u(t)} time dependent acceleration vector (lxN) of nonsupport points relative to the base support acceleration u (t) s 3.7-24 HCGS-UFSAR Revision 0 April 11, 1988

(ut(t)}, {uft{t)}- total displacement and acceleration, respectively

[M) diagonal matrix of lumped masses

[C] damping matrix (NxN)

[K] stiffness matrix (NxN)

P(t) - time dependent inertial force vector acting at nonsupport points.

The manner in which a distributed mass, distributed stiffness system is idealized into a lumped mass, distributed stiffness system of the NSSS component is shown on Figure 3. 7-160, along with a schematic representation of relative acceleration, support acceleration, and total acceleration.

3.7.3.1.1.2 Solution of Equations of Motion by Mode Superposition The technique used for the solution of the equations of motion is the method of mode superposition, in which the equations of motion are decoupled by the eigen transformation.

The set of homogenous equations represented by the undamped free vibration of the system is:

[M] (u(t)} + [KJ {u(t)} * (0} (3.7-5)

Since the free oscillations are assumed to be harmonic, the displacement vector (u(t)} can be written as:

iwt (u(t {~} e (3.7-6) 3.7-25 HCGS-UFSAR Revision 0 April 11, 1988

where: {~) column matrix of the amplitude of displacements {u} w circular frequency of oscillation t time Substituting Equation 3.7-6 and its derivatives into Equation 3.7-5, iwt and noting that e is unequal to zero for all values of wt, yields: 2 (-w [M] + [KJ) (;} - {0} (3.7-7) Equation 3. 7-7 is the characteristic equation for the classical eigenvalue problem, in which the eigenvalues are the frequencies of vibrations, wi , and the eigenvectors are the mode shapes, t;i}, ( i-1 t 2 1 * * *

• n)
• For each frequency wi , there is a corresponding solution vector

{~i}. It can be shown that the mode shape vectors are orthogonal with respect to the weighted stiffness matrix [K] in the n-dimensional vector space. The eigenvectors are also orthogonal with respect to the weighted mass matrix [M]. The orthogonality of the eigenvectors is used to effect a coordinate transformation to the generalized coordinate system, in which the governing equations of motion are decoupled. Thus, the problem becomes one of solving n independent differential equations rather than n simultaneous differential equations, and because the system is linear, the principle of superposition holds, and the total response of the system oscillating simultaneously in n modes is determined by direct addition of the responses in the individual modes. 3.7-26 HCGS-UFSAR Revision 0 April 11, 1988

3.7.3.1.1.3 Analysis by the Response Spectrum Method The response spectrum method is based on the fact that the modal responses can be expressed in terms of a set of convolution integrals of differential equations. The advantage of this form of solution is that, for a given ground motion, the only variables under the integral are the damping factor and the frequency. Thus, for a specified damping factor it is possible to construct a curve that gives a maximum value of the integral as a function of frequency. This curve is called a response spectrum for the particular input motion and the specified damping factor. The integral bas units of velocity; consequently, the maximum of the integral is called the spectral velocity. Using the calculated natural frequencies of vibration of the system, the maximum values of the modal responses are determined directly from the appropriate response spectrum. The modal maxima are then combined as discussed in Section 3.7.3.7. 3.7.3.1.1.4 Dynamic Analysis of Seismic Category 1 Systems and Components The time history and the response spectrum techniques are used as applicable for the dynamic analysis of Seismic Category I NSSS systems and components. Dynamic analysis of piping systems, equipment, and interconnected components is as follows:

1. Piping systems Each pipeline is idealized as a mathematical model consisting of lumped masses connected by elastic members. The stiffness matrix for the piping system is determined using the elastic properties of the pipe. Included are the effects of torsion, bending, shear, and axial deformations, as well as the change in stiffness due to curved members. Next, the mode shapes and the undamped natural frequencies are obtained. When 3.7-27 HCGS-UFSAR Revision 0 April 11, 1988

the piping system is anchored and supported at points with different excitations, the response spectrum analysis is performed using the envelope response spectrum of all attachment points. Alternately, the multiple excitation analysis methods may be used where acceleration time*histories or response spectra are applied to all piping system attachment points. The maximum relative displacement between anchors is determined from the dynamic analysis of the structures, and the results are used for a static analysis to determine the additional stresses due to relative anchor point displacements.

2. Equipment

• Each component of equipment is idealized as a mathematical model consisting of lumped masses connected by elastic members or springs.

When the equipment is supported at more than two points located at different elevations in the building, the response spectrum analysis is performed using the enveloped response spectrum of all attachment points. Alternately, the multiple excitation analysis methods may be used where individual acceleration time-histories or response spectra are applied at each of the equipment attachment points. The maximum relative displacements between supports are determined from the dynamic analysis of the structures and are used for a static analysis to determine the secondary stresses due to support displacements.

3. Differential seismic movement of interconnected components

          - The procedure for considering differential displacements for  equipment   anchored   and  supported    at  points   with different input motion is as follows:

3.7-28 HCGS-UFSAR Revision 0 April 11, 1988

a. The maximum relative displacements between the supporting points induce additional stresses in the equipment supported at these points. These stresses can be evaluated by performing a static analysis where each of the supporting points is displaced a prescribed amount. The time history of displacement at each supporting point is obtained from the corresponding acceleration time history, which is provided as input for the dynamic analysis of the total component. These displacements are used to calculate stresses by determining the peak nodal responses.

b. In the static calculation of the stresses due to relative displacements in the response spectrum method, the maximum value of the modal displacement is used. Therefore, the mathematical model of the equipment is subjected to the maximum displacement vector of its supporting points obtained from the modal displacements. This procedure is repeated for the significant modes of the structure, i.e., those that contribute most to the total displacement response at the supporting

c. point. The total stresses due to relative displacement are obtained by combining the modal results using the square root of the sum of the squares (SRSS) method. Because the maximum displacements for different modes do not occur at the same time, the SRSS method is a reliable method.

d. When a component is covered by the ASME B6PV Code, the stresses due to relative displacement as obtained above are treated as secondary stresses.

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3.7.3.1.1.5 Seismic Qualification by Testing For certain Seismic Category. I equipment and components where dynamic testing is necessary to ensure functional integrity, test performance data and results reflect the following:

1. Performance data of equipment that, under the specified conditions, was subjected to dynamic loads equal to or greater than those to be experienced under the specified seismic inservice conditions.

2. Test data from previously tested comparable equipment that, under similar conditions, was subjected to dynamic loads equal to or greater than those specified.

3. Actual testing of equipment in accordance with one of the methods described in Sections 3.9.2.2 and 3.10.

3.7.3.1.2 Seismic Analysis Methods (Non*NSSS) 3.7.3.1.2.1 Equipment Seismic qualification of equipment is performed by using either analysis or dynamic testing, or a combination of both. 3.7.3.1.2.1.1 Analysis Seismic qualification of equipment is performed by analysis when the equipment can be adequately idealized as a system of lumped masses and stiffnesses, and when the analysis can determine its structural and functional adequacy. The seismic analysis methods used for equipment are similar to methods used for seismic systems, and are described in Section 3.7.2. They include:

1. Response spectrum analysis 3.7*30 HCGS-UFSAR Revision 0 April 11, 1988

2. Time history analysis.

3.7.3.1.2.1.2 Dynamic Testing Seismic adequacy can also be established by means of dynamic testing or previous dynamic envirorunental performance data that demonstrate that the equipment meets the seismic design criteria. Acceptable test methods are as follows:

1. continuous sinusoidal test, sine beat test, or decaying sinusoidal test when the floor acceleration spectrum is a narrow band response spectrum

2. Random motion teet, or equivalent, when the floor response spectra have broad-band frequency content.

3.7.3.1.2.1.3 Combination of Analysis and Dynamic Testing Some types of equipment cannot be practically qualified by analysis or testing alone. This may be because of the size of the equipment, ita complexity, or the large number of similar configurations. Experimental methods are used to aid in the formulation of the mathematical model for any piece of equipment. Mode shapes and frequencies are determined experimentally and incorporated into a mathematical model of the equipment. 3.7.3.1.2.2 Piping Systems Reference 3. 7-2 describes the methods used for seismic analysis of piping systems.

3. 7. 3 .1. 2. 3 Supports for Seismic category I Heating, Ventilating, and Air conditioning Ducts, Cable Trays, and Conduits These supports are qualified as follows:

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1. supports for HVAC ducts are analyzed by the response spectrum method

2. Analysis of supports for cable trays and conduits is based on the response spectrum method and/or experimental data acquired from actual seismic testing performed on cable tray and support systems.

3.7.3.2 Detepmination of Numper of Earthquake cycles 3.7.3.2.1 Determination of Number of Earthquake Cycles (NSSS) 3.7.3.2.1.1 Piping Systems A total of 50 peak OBE stress cycles are postulated for fatigue evaluation. 3.7.3.2.1.2 other Equipment and Components. To evaluate the number of cycles engendered by a given earthquake, a typical BWR building-reactor dynamic model was excited by three different recorded time histories:

1. May 18, 1940, El Centro NS component, 29.4 seconds

2. 1952, Taft N 69° W component, 30 seconds

3. March 1957, Golden Gate s 80° E component, 13.2 seconds.

The modal response was truncated so that the response of three different frequency bandwidths could be studied: 0 to 10 hertz, 10 to 20 hertz, and 20 to 50 hertz. This was done to give a good approximation of the cyclic behavior expected from structures with different frequency content. 3.7-32 HCGS-UFSAR Revision 8 September 25, 1996

Enveloping the results from the three earthquakes and averaging the results from several different points of the dynamic model, the cyclic behavior described in Table 3.7-5 was formed. Independent of earthquake or component frequency, 99. 5 percent of the stress reversals occur below 75 percent of the maximum stress level, and 95 percent of the reversals occur below 50 percent of the maximum stress level. In summary, the cyclic behavior number of fatigue cycles of a component during an earthquake is determined in the following manner:

1. The fundamental frequency and peak seismic loads are determined by a standard seismic analysis, i.e., from eigenvalue extractions and a forced response analysis.

2* The number of cycles that the component experiences are determined using Table 3. 7 *5, according to the frequency range within which the fundamental frequency lies ..

3. For fatigue evaluation. 0.5 percent (0.005) of these cycles are conservatively assumed to be at the peak load and 4.5, (.045) at or above the three-quarter peak. The remainder of the cycles have negligible contribution to fatigue usage.

The SSE has the highest level of response. However, the encounter probability of an SSE is so small that it is not necessary to postulate the possibility of more than one SSE occurring during the 40-year life of a plant. Fatigue evaluation due to the SSE is not necessary because it is a faulted condition and thus not required by the ASHE B&PV Code, Section III. The OBE is an upset condition and therefore must be included in fatigue evaluations, according to the ASME B&PV Code, Section III. 3.7-33 HCGS-UFSAR Revision 0 April 11, 1988

Investigation of seismic histories of many plants shows that, during a 40*year life, it is probable that five earthquakes will occur with 10 percent of the proposed SSE intensity, and one earthquake will occur with approximately 20 percent of the proposed SSE intensity. To cover the combined effects of these earthquakes and the cumulative effects of even lesser earthquakes, ten peak OBE stress cycles are postulated for fatigue evaluation. 3.7.3.2.2 Determination of Number of Earthquake Cycles (Non*NSSS) In general, the design of the equipment is not fatigue controlled because the equipment is designed to remain elastic and the number of cycles in an earthquake is low. Equipment that is qualified by analysis is designed to remain elastic during the earthquake. Any fatigue effects on tested equipment are accounted for by five OBEs and one SSE. The minimum duration for each condition is 20 seconds. Consequently, the number of cycles of the earthquake has been accounted for. To conduct a fatigue evaluation for nuclear Class I piping, the number of cycles for a given load set is obtained by considering ten maximum stress cycles per earthquake, and assuming five OBEs and one SSE to occur within the life of the plant. 3.7.3.3 Procedure Used for Modelin& 3.7.3.3.1 Procedure Used for Modeling (NSSS) An important step in the seismic analysis of Seismic Category I systems, components, or structures is the procedure used for modeling. The techniques curre~tly being used are represented by lumped masses and a set of spring dashpots idealizing both the inertial and stiffness properties of the system. The details of the mathematical models are determined by the complexity of the actual system and the information required for the analysis. 3.7-34 HCGS-UFSAR Revision 0 April 11, 1988

The modeling procedure uses an adequate number of masses or degrees of freedom to determine the response of all Seismic Category I and applicable non-Seismic Category I structures and equipment. The refinement of all dynamic models is sufficient for analysis up through at least 60 hertz. The number of masses or degrees of freedom is adequate so that any further refinement does not result in more than a 10 percent increase in the final response. This means that the number of degrees of freedom is equal to at least twice the number of modes with frequencies up through 60 hertz. 3.7.3.3.1.1 Modeling of Reactor Pressure Vessel and Internals The seismic loads on the reactor pressure vessel (RPV) and its internals are based on a dynamic analysis of the Reactor Building with the appropriate forcing function supplied at ground level. For this analysis, the models shown on Figure 3.7-161 and the mathematical model of the building are coupled together. This mathematical model consists of lumped masses connected by elastic (linear) members. Using the elastic properties of the structural components, the stiffness properties of the model are determined, and the effects of bending and shear are included. Mass points are located at all points of critical interest, such as anchor points, supports, and points of discontinuity. In addition, mass points are chosen such that the total mass of the structure is generally uniformly distributed over all the mass points, and the full range of frequency of response of interest is adequately represented. Furthermore, to facilitate hydrodynamic mass calculations, several mass points, (fuel, shroud, vessel) are selected at the same elevation. The various lengths of control rod drive (CRD) housings are grouped into the two representative lengths shown on Figure 3.7-161. These lengths represent the longest and shortest housings, in order to adequately represent the full range of frequency response of the housings. The high fundamental frequencies of the CRD housings result in very small seismic loads. Furthermore, the small frequency differences 3.7-35 HCGS-UFSAR Revision 17 June 23, 2009

between the various housings due to the length differences result in negligible differences in dynamic response. Hence, the modeling of intermediate length members becomes unnecessary. Not included in the mathematical model are the stiffness of light components, such as jet pumps, in-core guide tubes and housings, spargers, and their supply headers. This is done to reduce the complexity of the dynamic model and is justified because dynamic interaction is not significant. Floor response spectra generated from the analysis are used for the seismic responses of these components. The presence of water and other structural components, e.g., fuel within the RPV, introduces a dynamic coupling effect. Dynamic effects of water enclosed by the RPV are accounted for by introduction of a hydrodynamic mass matrix, which serves to link the acceleration terms of the equations of motion of points at the same elevation in concentric cylinders with a fluid entrapped in the annulus. Details of the hydrodynamic mass derivation are given in Reference 3.7-3. The seismic model of the RPV and its internals has two hori%ontal coordinates for each mass point considered in the analysis. The remaining translational coordinate (vertical) is excluded because the vertical frequencies of the RPV and internals are well above the significant horizontal frequencies. Furthermore, all support structures, the building, and the primary containment walls have a common centerline; therefore, the coupling effects are negligible. A separate vertical analysis is performed. Dynamic loads due to vertical motion are added to or subtracted from the static weight of the components, whichever is more conservative. The two rotational coordinates about each node point are excluded because the contribution of rotating inertia is negligible. Since all deflections are assumed to be within the elastic range, the rigidity of some components may be accounted for by equivalent linear springs. The shroud support plate in its own plane is extremely stiff and is modeled as a rigid link in the translational direction. The shroud support legs and the local flexibilities of the vessel and shroud 3.7-36 HCGS-UFSAR Revision 8 September 25, 1996

contribute to the rotational flexibf.lities, and are modeled as an equivalent torsional spring. 3.7.3.3.1.2 Modeling of Piping Systems The continuous piping system is modeled as an assemblage of three dimensional straight or curved pipe elements. The mass of each pipe element is lumped at nodes connected by a weightless elastic member, representing the physical properties of each segment. The pipe lengths between mass points are no greater than a length that would have a natural frequency of 33 hertz when calculated as a simply supported beam. In addition, mass points are located at the beginning and end of each elbow, tee, and other such components as main valves, relief valves, and pumps. The torsional effects of the valve operators and other equipment with offset centers of gravity with respect to the center line of the pipe are included in the analytical model. The criteria employed for decoupling the main steam and recirculation piping systems, thus establishing the analytical models necessary to perform seismic analyses, are given below:

1. The small branch lines, 6-inch diameter and less, are decoupled from the main steam and recirculation piping systems and analyzed separately.

2. The stiffness of all the anchors and the supporting steel is large enough to effectively decouple the piping on either side of the anchor for analytic and code jurisdictional boundary purposes. The RPV is very stiff and massive compared to the piping system; thus, during normal operating conditions, the RPV is also assumed to act as an anchor. Penetration assemblies (head fittings) are also very stiff compared to the piping system and are assumed to act as an anchor. The stiffness matrix at the attachment location of the process pipe head fitting, i.e., main steam, reactor core isolation cooling (RCIC),

3.7-37 HCGS-UFSAR Revision 0 April 11, 1988

residual heat removal (RHR) supply, or RHR return, is sufficiently high to decouple the penetration assembly from the process pipe. GE analysis indicates that a satisfactory minimum stiffness for this attachment point is the stiffness in bending and torsion of a cantilever that is equal to a pipe section of the same size as the process pipe, and equal in length to three times the outer diameter of the process pipe. 3.7.3.3.1.3 Modeling of Equipment For dynamic analyses, Seismic Category I equipment is represented by lumped mass systems that consist of discrete masses connected by weightless springs. The criteria used to lump masses are:

1. The number of modes of a dynamic system is controlled by the number of masses used. Therefore, the number of masses is chosen so that all significant modes are included. The modes are considered significant if the corresponding natural frequencies are less than 33 hertz and the stresses calculated from these modes are greater than 10 percent of the total stresses obtained from lower modes.

2. Mass is lumped at any point of significant concentrated weight, e.g., the motor in the analysis of the pump motor stand and the impeller in the analysis of the pump shaft.

3. If the equipment has a free end overhang span with flexibility that is significant compared to the center span, a mass is lumped at the overhang span.

4. When a mass is lumped between two supports, it is located at a point where the maximum displacement is expected to occur. This tends to lower the natural frequencies of the equipment. This results in a conservative analysis, because the equipment frequencies are in the higher 3.7-38 HCGS-UFSAR Revision 0 April 11, 1988

spectral range of response spectra. Similarly, in the case of live loads (mobile) and a variable support stiffness, the location of the load and the magnitude of support stiffness are chosen so as to yield the lowest frequency content for the system. This ensures conservative dynamic loads, since the equipment frequencies are always higher than the frequencies at which the spectral peaks occur. If such is not the case, the model is adjusted to give more conservative results. 3.7.3.3.1.4 Field Location of Supports and Restraints The final location of seismic supports and restraints for Seismic Category I piping, piping system components, and equipment, including the placement of snubbers, is checked against the drawings and instructions issued by the engineer. An additional examination of these as-built supports and restraining devices is made to ensure that the location and characteristics of these supports and restraining devices are consistent with the dynamic and static analyses of the systems. The final analyses of the as-built systems are performed as necessary. and the final, certified, as-built design reports are issued.

3. 7 ._3. 3. 2 Procedure Used for Modeling (Non-NSSS)

Mathematical models are used that describe the mass and stiffness properties of the equipment. The models define the dynamic behavior of the equipment within the frequency range of interest. The boundary conditions are modeled to reflect the actual mounting conditions. The equipment is represented by lumped mass models. Massless elastic members are used to connect the masses. Supports for HVAC ducts are modeled as two dimensional, lumped mass, plane frame models. The masses are lumped at the center of the ducts. Sections 2 and 3 of Reference 3.7-2 discuss the techniques and procedures used to model piping other than buried piping. 3.7-39 HCGS-UFSAR Revision 0 April 11, 1988

3.7.3.4 BAsis for Selection of Fregpencies 3.7.3.4.1 Basis for Selection of Frequencies (NSSS) All frequencies in the range of 0.25 to 33 hertz are considered in the analysis and testing of systems, components, and equipment. These frequencies are excited under the seismic excitation. If the fundamental frequency of a component is greater than or equal to 33 hertz, it is treated as seismically rigid and analyzed accordingly. Frequencies less than 0.25 hertz are not considered, as they represent very flexible structures not encountered in this plant. The frequency range between 0.25 hertz and 33 hertz covers the range of the broad band response spectrum used in the design. 3.7.3.4.2 Basis for Selection of Frequencies (Non*NSSS) The natural frequencies of components are calculated. Only those modes that have natural frequencies less than 33 hertz are considered in the dynamic analysis. If a component has a fundamental frequency equal to or greater than 33 hertz, it is considered seismically rigid. In this ease, the acceleration response of the component equals the floor acceleration. If the natural frequency of the component falls within the broadened peak of the response spectrum curve, then it is designed to take the peak response load. 3.7.3.5 Use of Equivalent Static L9ad Method of Analysis 3.7.3.5.1 Use of Equivalent Static Load Method of Analysis (NSSS) When the natural frequency of a structure or component is unknown, it may be analyzed by applying a static force at the center of mass. To account conservatively for the possibility of more than one significant dynamic mode, the static force is calculated as 1.5 3.7-40 HCGS-UFSAR Revision 0 April 11, 1988

times the mass times the maximum spectral acceleration from the floor response spectra of the points of attachment of multi supported structures. The factor of 1. S is adequate for a simple beam type of structure. For simply supported structures, the peak spectral acceleration is used. For other, more complicated structures, the factor used is justified. 3.7.3.5.2 Use of Equivalent Static Load Method of Analysis (Non-NSSS) The equivalent static load method is used when the natural frequency of the equipment is not determined. If the equipment can be adequately represented by a single degree of freedom system, then the applied inertia load is equal to the weight of the equipment times the peak value of the response spectrum curve. Seismic acceleration coefficients for multiple degree of freedom systems, which may be in the resonance region of the amplified response spectra curves, are increased by 50 percent to account conservatively for the increased modal participation. Appendix D of Reference 3. 7*2 discusses the use of the equivalent static load method of analysis, as applicable to piping. 3.7.3.6 Tbree Components of Earthquake Motion 3.7.3.6.1 Three Components of Earthquake Motion (NSSS) The simultaneous use of three components of earthquake motion was not a design basis requirement of the construction permit for this plant. However, the NSSS components and equipment are evaluated to the requirements of Regulatory Guide 1.92. 3.7.3.6.1.1 Response Spectrum Method Response spectra generated by GE are developed considering three components of earthquake motion. The individual floor response HCGS-UFSAR Revision 0 April 11, 1988

spectra in each orthogonal direction are obtained by the SRSS combination of the collinear contribution due to the three directions of earthquake motion. These are used to predict the total response at each frequency. 3.7.3.6.1.2 Time History Method When the time history method of analysis is used, the time history responses from each of the three components of the earthquake motion are combined algebraically at each time step. The maximum response is obtained from this combined time solution. 3.7.3.6.2 Three Components of Earthquake Motion (Non-NSSS) For equipment, cable trays, supports for cable trays, and HVAC ducts, the three spatial components of the earthquake are considered in the same manner as structures described in Section 3.7.2.6. The criteria used for combining the results of horizontal and vertical seismic responses of piping systems are described in Section 5.1 of Reference 3.7-2. 3.7.3.7 Combination of Modal Responses 3.7.3.7.1 Combination of Modal Responses (NSSS) All piping and equipment analyzed or supplied by GE is evaluated to the requirements of Regulatory Guide 1.92. When the response spectrum method of modal analysis is used, all modes except the closely spaced modes (i.e., the difference between any two natural frequencies is equal to or less than 10 percent) are combined by the square root of the sum of the squares ( SRSS) , as described in Section 3. 7. 3. 7. 1. 1. Closely spaced modes are combined by the double sum method described in Section 3.7.3.7.1.2. 3.7-42 HCGS-UFSAR Revision 17 June 23, 2009

In the time history method of dynamic analysis, the vector sum at every step is used to calculate the combined response. The use of the time history method precludes the need to consider modal spacing. 3.7.3.7.1.1 Square Root of the Sum of the Squares The square root of the sum of the squares (SRSS) combination of modal responses is defined mathematically as: 0.5 n R- L: i-1 (3.7-8) where: combined response th response due to the i mode number of modes considered in the analysis 3~7.3.7.1.2 Procedure for Combining Closely Spaced Modal Responses The double sum method is used to combine the responses of closely spaced. modes when the response spectrum method of modal dynamic analysis is used. This method is defined mathematically as: 0.5 N N R- {3.7-9) where R is the representative maximum value of a particular response of a given element to a given component of excitation, ~ is the peak value of the response of the element due to the k th mode. and N is the number of significant modes considered in the modal response 3.7-43 HCGS-UFSAR Revision 0 April 11, 1988

combination. In addition, R is the peak value of the response of s th the element attributed to the s mode. Also,

                               -1

~s-(3.7-10) in which : and where: wk and pk are the modal frequency and the damping ration in th the k mode. respectively, and td is the duration of the earthquake. 3.7.3.7.2 Combination of Modal Responses (Non-NSSS) The modal responses of equipment are combined by the SRSS method. The absolute values of two closely spaced modes are added before I being combined with the other modes by the SRSS method. Two consecutive modes are defined as closely spaced when their frequencies differ from each other by 10 percent or less. 3.7-44 HCGS-UFSAR Revision 0 April 11, 1988

3.7.3.8 Analytical Procedure for Pipin& 3.7.3.8.1 Analytical Procedure for Piping (NSSS) The analytical procedures for piping analyses are described in Section 3.7.3.1.1.4. Methods to include differential piping support movements at different support points are also described. 3.7.3.8.2 Analytical Procedure for Piping (Non-NSSS) The design criteria and the analytical procedures applicable to piping systems are as described in Section 2 of Reference 3. 7 2. 4 The methods used to consider differential piping support movements at different support points are described in Section 4 of Reference 3.7*2.

• 3.7.3.9 Multiple Supported Equipment Components With Distinct Inputs 3.7.3.9.1 Multiple Supported Equipment Components With Distinct Inputs (NSSS}

The procedure and criteria for the analysis of multiple supported equipment components with distinct inputs are described in Section 3.7.3.1.1.4. 3.7.3.9.2 Multiple Supported Equipment Components With Distinct Inputs (Non-NSSS) For piping systems J cable trays, and HVAC ducts of which the supports have two or more distinct inputs, a response spectrum curve envelops the curves at all support locations. Section 4 of Reference 3. 7-2 discusses the methods used for analysis of multiple supported piping systems due to seismic anchor differential movement. 3.7-45 HCGS-UFSAR Revision 0 April 11, 1988

When a piping system is subjected to a distinct input consisting of significantly varying amplitudes at supports, nozzles, or anchors, a more realistic approach using the multiple support excitation analysis method is considered. Either time history or multiple response spectrum analysis methods are used. The same analytical procedures and criteria described in Section 3. 7. 3. 8. 2 are applied for this type of analysis, with the additional parameters coming from the unit vector r, which is computed as the response due to static support displacement. The time*history method uses the u-.q + rUr in the eqU.tion of motion for the unsupported degree of freedom, U (partitioned dynamic equilibrium matrix). ~ is the orthonormal mode shapes, q is the matrix of modal amplitudes, and U is the support displacement amplitudes. The multiple support response spectrum method uses the unit r vector to calculate a modal participation factor for each distinct group of support input that directly corresponds to a modal spectra value. After all spectra participation, absolute summation of supports due to each distinct group, the total response is calculated by performing modal and spatial combination in accordance to Regulatory Guide 1.92. 3.7.3.10 Use of Constant Vertical Static Factors 3.7.3.10.1 Use of Constant Vertical Static Factors (NSSS) Constant vertical static factors are not used by General Electric. 3.7.3.10.2 Use of Constant Vertical Static Factors (Non-NSSS) Constant vertical static factors are not used in the seismic design of subsystems. 3.7.3.11 I9rsiopal Effects of Eccentric Masses 3.7.3.11.1 Torsional Effects of Eccentric Masses (NSSS) Torsional effects of eccentric masses for the piping systems are discussed in Section 3.7.3.3.1.2. 3.7-46 HCGS-UFSAR Revision 0 April 11, 1988

The RPV is an axisymmetric model with no built* in eccentricity. Therefore; the torsional effects on the RPV are only those associated with the Reactor Building model and are accounted for in the Reactor Building model, as described in Section 3.7.2.3. 3.7.3.11.2 Torsional Effects of Eccentric Masses (Non*NSSS) The torsional effects of valves and other eccentric masses are considered in the seismic *analysis of piping by the techniques discussed in Section 3.2 of Reference 3.7*2. 3.7.3.12 Bu;ied Seismic CateKO[Y I PipinK Systems and Tunnell

          <Non-NSSS)

Buried Seismic Category I piping that is connected between the intake structure and the Reactor Building is analyzed and designed for seismic effects in accordance with Section 6 of Reference 3.7-1 and Part IIIof Reference 3.7-7. Additional requirements for design and manufacture of the prestressed concrete pipe are in accordance with American Water Works Association (AWA) Standard C-301. The flexible joints are designed to accommodate the maximum postulated axial and rotational movements induced by a seismic event, thereby allowing the system to follow the displacements that take place in the surrounding soil. The piping is also founded on engineered backfill, as discussed in Section 3. 8. 6 .1. This base will essentially eliminate any soil settlement or arching so that the joint integrity and water tightness can be maintained during and after a seismic event. In addition, the service water pipeline has been evaluated using the recommended guidelines provided in NUREG/CR-1161 (Reference 3.7-8). In all cases, the final design meets or exceeds the allowables required by NUREG/CR-1161. There is no buried tunnel at HCGS. 3.7-47 HCGS-UFSAR Revision 0 April 11, 1988

3.7.3.13 Interaction of Other Pipin& With Seismic Catecory I Pipin& 3.7.3.13.1 Interaction of Other Piping With Seismic Category I Piping (NSSS) When other non .. seismic Category I piping is attached to Seismic Category I piping, the other piping is analytically coupled sufficiently so as not to degrade significantly the accuracy of the analysis of the Seismic Category I piping. Furthermore, other piping is designed to withstand an SSE to prevent failure of Seismic Category I piping. 3.7.3.13.2 Interaction of Other Piping With Seismic Category I Piping (Non*NSSS) The techniques used to consider the interaction of Seismic Category I piping with non-Seismic Category I piping are discussed in Section 3.4 of Reference 3.7*2. 3.7.3.14 Seismic Analysis for Reactor Internals !NSS§) The modeling of the RPV and the internals is discussed in Section 3.7.3.3.1.1. The damping values are given in Table 3.7-1. The seismic model is shown on Figure 3. 7-161, and a s\llB1.Uary of loading conditions, evaluation criteria, calculated maximum stresses in the selected locations, and the allowable stresses are given in Table 3.9-5. 3.7.3.15 Analysis Procedures for Dampin& 3.7.3.15.1 Analysis Procedures for Damping (NSSS) In a linear dynamic analysis, the procedure used to account properly for damping in different elements of a coupled system model is as follows: 3.7-48 HCGS-UFSAR Revision 0 April 11. 1988

1. The structural damping of the various structural elements of the model are first specified. Each value is referred to as the damping ratio (Bj) of a particular element that contributes to the complete stiffness of the system.

2. Perform a modal analysis of the linear system model. This will result in the eigenvector matrices (;) normalized such that:

(3.7*13) and [I] (3.7-14) 2 where [K] is the stiffness matrix, ['W ] is the circular T natural frequency, and [~ ] is the transpose of the mode shape matrix ~, which contains all translational and rotational coordinates.

3. Using the strain energy of the individual components as a weighting function, the following equation is used to obtain a suitable damping ratio (pi) for the mode i:

N L (3.7-15)

         ~   -  ~l--1~----------

where: N total number of structural elements components of the i mode eigenvector corresponding to the j beam ~lement ~j percent damping associated with element j 3.7-49 HCGS-UFSAR Revision 0 April 11, 1988

K stiffness contribution of element j Y~ circular natural frequency of mode i jJT transpose of f defined above i fJ percent critical damping associated with element j 3.7.3.15.2 Analysis Procedure for Damping (Non-NSSS) In general, a single damping value, as shown in Table 3.7-2, is used for the analysis of Seismic Category I subsystems. 3.7.3.16 SRP Bule ReView Acceptance criterion II . 2 (b) of SRP Section 3. 7. 3 establishes the number of OBE cycles to be assumed for component fatigue analysis. It requires 50 OBE peak stress cycles for the life of the plant. In the HCGS design, 50 peak OBE stress cycles are postulated for the NSSS piping in accordance with the SRP. However, 10 peak OBE cycles are postulated for other NSSS equipment and components... This 10-cycle approach has been approved by the NRC-MEB on the grounds of "equivalent level of safety.* This approval was contingent upon GE's presentation of the fatigue calculation of the most limiting component in the BWR 4 product line; see Reference 3.7*5. This presentation took place during the Limerick Generating Station licensing process. The results of the fatigue calculation for the most limiting RPV Component for B'WR/4 product line were presented and were found acceptable by NRC-MEB. 3.7-50 HCGS-UFSAR Revision 0 April 11, 1988

3.7.4 Seismic Instrumentation 3.7.4.1 Comparison With ReJUlatotY Guide 1.12. Reyision 1 The seismic instrumentation system of Hope Creek Generating Station (HCGS) complies with:_ Regulatory Guide 1.12, Revision 1, except as discussed below. The response spectrum recorders required by Position l.C of Regulatory Guide 1.12 are not supplied as discrete instruments. Instead, triaxial time-history accelerographs are provided at the required locations. Together with a multichannel magnetic tape recorder and a response spectrum analyzer, this system yields more complete information than that from response-spectrum recorders. Following a seismic event, recorded acceleration data from the triaxial time history accelerographs are fed into a response spectrum analyzer, one channel at a time, to produce seismic response spectra. Permanent records of the response spectra are provided by an x-y plotter. This system meets the intent of Position l.C of Regulatory Guide 1.12. Position 3 of the Regulatory Guide does not apply, since the HCGS safe shutdown earthquake (SSE) is 0.2 g. 3.7.4.2 LoCation and Description of Instrumentation 3.7.4.2.1 Triaxial Time History Accelerographs (T/A) One T/A is provided at each of the following locations:

1. Free field, 60 feet below grade in the northwest quadrant of the plant site, 500 feet from the reactor building, on the Vincentown Formation

2. Primary containment foundation, Elevation 54 feet, in the northeast quadrant of the Reactor Building 3.7-51 HCGS-UFSAR Revision 0 April 11, 1988

3. Reactor Building, Elevation 201 feet, in the northwest quadrant on the refueling floor

4. Reactor piping (core spray piping entering the reactor),

Elevation 115 feet, in the north quadrant of the drywell along the reactor centerline

5. Auxiliary Building foundation, Elevation 54 feet, in the northwest quadrant of the Auxiliary Building.

T/As produce a record of the time varying acceleration at the sensor location. The signal amplitude is proportional to the instantaneous acceleration value of the point on the structure/component to which the T/A is attached. Each T/A contains three accelerometers mounted in a mutually orthogonal array. All T/As have their principal axes oriented identically, with one horizontal axis parallel to the major horizontal axis assumed in the plant seismic analysis. A triaxial seismic trigger (S/T), sensitive in north-south, east-west, and vertical directions, is provided at the primary containment foundation to start the T/A sensor recording system. The multichannel magnetic tape recorders for the system are housed in the system control panel, which is located in the control complex. The tape recording system is capable of simultaneously recording signals from all of the T/As. 3.7.4.2.2 Triaxial Peak Recording Accelerographs (P/A) One P/A is provided at a location on the reactor equipment (reactor support lateral truss), a location on the reactor piping (core spray piping entering the reactor), and on Seismic Category I equipment at the most significant location outside of the primary containment structure (on the station service water pump piping, in the intake structure). 3.7-52 HCGS-UFSAR Revision 0 April 11, 1988

P/As record the actual peak response at the sensor location. Each P/A contains three accelerometers mounted in a mutually orthogonal array. All P /As have their principal axes oriented identically, with one horizontal axis parallel to the major horizontal axis assumed in the seismic analysis. Data from the P/As are manually retrieved following an earthquake. 3.7.4.2.3 Triaxial Response Spectrum Recorder (R/R) One R/R is provided at the primary containment foundation. Irmnediate main control room indication is provided by the system response spectrum annunciator. The R/R is comprised of three R/Rs mounted in a mutually orthogonal array, with one horizontal R/R mounted parallel to the major horizontal axis assumed in the seismic analysis. Each R/R consists of a spring mass system with 16 vibratory reeds responsive to 16 discrete frequencies. Each reed is fitted with a stylus that inscribes a roark on a permanent recording plate. This scribe mark is proportional to the I maximum acceleration to which its respective reed has been subjected. These data are manually retrieved following an earthquake. Each R/R also contains 16 response spectrum switches (R/8), integrally related to each of the 16 vibratory reeds. When any reed senses acceleration greater than the preset level, the R/S contacts close, providing main control room annunciation at the response spectrum annunciator. Annunciation is provided independently for each of the 16 discrete frequencies. 3.7.4.2.4 Triaxial Response Spectrum Annunciator {R/A) One R/A assembly is provided in the main control room, mounted as an insert in the main vertical board. 3.7-53 HCGS-UFSAR Revision 17 June 23, 2009

The R/A provides visual annunciation that predetermined acceleration limits, both warning and design, within the response spectrum have been exceeded. The R/A contains three banks of indicator lamps, one bank for each of three mutually perpendicular axes. Each bank contains a double row of 16 colored indicator lamps per row. Amber lamps indicate acceleration levels approaching design limits, while red lamps indicate that design limits have been exceeded. Each pair of indicator lamps per bank is associated with a single vibratory reed. 3.7.4.2.5 Triaxial Seismic Switch (S/S) One S/S is provided on the primary containment foundation. The S/S is provided to monitor the occurrence of an operating basis earthquake (OBE) acceleration at the mounting location. The S/S contains three sensor relay modules mounted in a mutually orthogonal array, with one horizontal axis parallel to the major horizontal axis asswned in the seismic analysis. When any axis is excited beyond the OBE acceleration level, the S/S contacts close, providing immediate main control room annunciation. 3.7.4.2.6 System Control Panel The system control panel is located in the upper control equipment room of the control complex. It houses the recording and playback units used in conjunction with the T/A sensors to produce a time history and frequency amplitude record of a seismic event. The panel also contains signal conditioning equipment associated with the R/R, R/A, S/S, and the system power supply modules. A cassette tape deck is provided to record the output signal of each T/A. Each tape deck records four channels of information, i.e., the three output signals from each accelerometer within the respective T/A and a timing mark signal. 3.7-54 HCGS-UFSAR Revision 0 April 11, 1988

A cassette tape playback unit is included to provide an immediate analog record of acceleration versus time on the integral strip chart recorder. Any one signal channel of a tape may be selected along with timing marks to generate a recording on the strip chart recorder. In addition, all four channels are available simultaneously for use with the auxiliary spectrum analyzers. 3.7.4.3 Control Room Operator Notification Activation of the S/S causes audible and visual annunciation in the main control room to alert the main control room operator that OBE acceleration levels have been exceeded. The peak acceleration levels experienced by the primary containment foundation and the free field are determined following a seismic event by playing back the recorded T/A data from the respective sensor tape, and reading the peak value from the strip chart recorder located in the system control panel discussed in Section 3.7.4.2.6. Alternatively, the sensor tape can be examined on a spectrum. analyzer and the results plotted on an x*y plotter located in the control complex. The R/R located on the primary containment foundation provides immediate indication in the main control room of any design response spectra values for discrete frequencies that have been exceeded following a seismic event. 3.7.4.4 Comparison of Measured and Predicted Responses Initial determination of the seismic event level is performed immediately following a seismic event. A comparison of the measured response spectra from the primary containment foundation and the calculated OBE response spectra is made. If either the response spectra from the R/R or the peak acceleration from the T/A, experienced at the primary containment foundation or the free field. exceed the allowable OBE acceleration level. the plant is immediately placed in shutdown condition. To resume operation, a 3.7-55 HCGS-UFSAR Revision 0 April 11, 1988

detailed seismic analysis will be performed to compare the calculated response spectra with measured response spectra at locations where sensors were installed. Time history records from free field triaxial time history accelerographs shall be used as input ground motions for the detailed soil structure interaction analysis. Newly calculated structural response spectra will also be compared with design floor response spectra to determine the seismic effects on structures, components and equipment. A report on the analysis results will be submitted to the NRC for permission to restart plant operation. An outline of the post-seismic event plant procedures is provided on Figure 3.7-162. 3.7.4.5 Inservice surveillance Each seismic instrument is periodically demonstrated operable in accordance I with Section 7. 7 .1.10. channel checks, channel The seismic instruments are designed to ensure that calibration, and channel functional tests can be I performed to frequencies identified in Section 7.7.1.10. 3.7.5 References 3.7-1 Bechtel Power Corporation, "Seismic Analysis of Structures and Equipments for Nuclear Power Plants, Bechtel Topical Report" BC-TOP-4A, Revision 3, November 1974. 3.7-2 Bechtel Power Corporation, "Seismic Analysis of Piping Systems," BP-TOP-1, Revision 3, January 1976. 3.7-3 L. K. Liu, "Seismic Analysis of the Boiling Water Reactor," Symposium on Seismic Analysis of P~essure Vessel and Piping Components, First National Congress on Pressure Vessel and Piping, San Francisco, California, May 1971. 3.7-4 R. B. Reimer, et al, "Evaluation of Pacoima Dam Accelerogram," Proceedings of the Fifth World Conference on Earthquake Engineering, Rome, Italy, 1973. 3.7-56 HCGS-UFSAR Revision 10 September 30, 1999

3.7-5 R. Bosnak, Letter to R. Artigas, *Number of OBE Fatigue Cycles in the BWR NSSS Design," February 18, 1973. 3.7-6 J. Lysmer, et al, "FLUSH A Computer Program for Approximate 3-D Analysis of Soil-Structure Interaction Problems," Report No. EERC 75-30, University of California, Berkeley, 1975. 3.7-7 Public Service Electric and Gas, "Additional Site Stability Evaluation Hope Creek Generation Station" December, 1976. 3.7-8 NUREG/CR-1161, Recommended Revisions to Nuclear Regulatory Commission Seismic Design Criteria, prepared by Lawrence Livermore Laboratory for U.S. Nuclear Regulatory Commission, May 1980. 3.7-57 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.7-1 CRITICAL DAMPING RATIOS FOR ANALYSIS OF NSSS MATERIALS Percent Critical Dampins Item OBE Condition SSE Condition Welded structural assemblies 1.0 2.0 Steel frame structures 2.0 3.0 Equipment 2.o< 2> 3.0 Bolted or riveted structural 4.0 7.0 assemblies Vital piping systems: Diameter greater than 12 in. 2.0 3.0 Diameter less than or equal 1.0 2.0 to 12 in. Reactor pressure vessel, shroud 2.0 4.0 support, support skirt, shroud head, and separator Control rod drive (CRD) housings 1.0 2.0 and guide tubes Fuel assemblies 4.0 (vert.) 6.0 6.0 (horiz.} CRD restraint bellows and stabilizer 2.0 4.0 Primary containment, RPV pedestal, 4.0 7.0 and biological shield wall 1 of 2 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.7-1 (Cont) (1) In the dynamic analysis of active components as defined in Regulatory Guide 1.48, this value is also used for SSE *

• HCGS-UFSAR 2 of 2 Revision 0 April 11, 1988

TABLE.3.7-2 DAMPING VALUES FOR SEISMIC CATEGORY I STRUCTURES, SYSTEMS, AND COMPONENTS(l) (NON-NSSS) Modal Damping Values, Percent of Critical Dampin& Structure or Component Equipment and large diameter piping 3 systems (pipe diameter in excess of 12 inshes){ 2 ) Small diameter piping systems (pipe 1 2 diameter equal to or less than 12 inches) Welded steel structures 2 4 Bolted steel structures 4 7 Prestressed concrete structures 2 5 Reinforced concrete structures '4 7 {1) Damping values for foundation material and for foundation structure interaction analysis are not included in this table. (2) This includes both material and structural damping. If the piping system consists of only one or two spans with little structural damping, the values for small diameter piping are used. (3) In the dynamic analysis of active components as defined in Regulatory Guide 1.48, this value is also used for SSE., 1 of 1 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.7-3 FOUNDATION DATA FOR MAJOR STRUCTURES Plan Dimensions of Structural Foundation Structure Foundation Height(l). ft Depth( 2 ), ft Reactor Building 192 ft 6 in. x 261 62 and South 312 ft 0 in. Radwaste Building North Radwaste 192 ft 6 in. x 132 62 Building and plant 312 ft 0 in. cancelled area Diesel generator, 164 ft 8 in. x 158 62 control and central 312 ft 0 in. radwaste buildings Turbine Building 364 ft 4 in. x 158 62 194 ft 10 in. 265 ft 6 in. x 158 62 Administration 194 ft 10 in. facility ssws 103 ft 6 in. X 69.5 34.5 intake structure 94 ft 0 in. (1) These heights are measured from the bottom of the base mat to the highest point of the structure. (2) These depths are measured from the bottom of the base mat to grade elevation . 1 of 1 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3. 7-4 SIGNIFICANT NATURAL FREQUENCIES FOR SEISMIC CATEGORY I STRUCTURES Be1ctoi BY1lg1n& A~il1atx Bu!ldin& lnt1ke StiJ&S:tYie Mode Freq, Mode Freq, Mode Freq, Direction N.s!...._ _Hz_ ~ -HL li2.- .JlL North* 4 6.20 5 9.5 south 4 4.09 8 15.28 6 10.0 10 8.87 7 10.0 11 8.97 19 26.5 17 12.34 East- 5 4.25 5 6.48 11 13.5 west 7 4.45 9 16.54 22 36.7 10 8.87 11 19.80 11 8.97 18 12.74 Vertical 15 11.42 7 13.24 21 35.3 17 12.34 9 16.54 18 12.74 10 17.54 27 18.35 11 19.80 45 28.24 Torsion 3 2.50 .6 12.36

• HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

TABLE 3. 7-5 NUMBER OF DYNAMIC RESPONSE CYCLES EXPECTED DURING A SEISMIC EVENT Frequency band. Hz 20-50 Total number of seismic cycles 168 359 643 Number of seismic cycles - 0.5 percent cycles between 75 percent and 100 percent

 *of peak loads                      0.8       1.8      3.2 Number of seismic cycles -

4.5 percent cycles between 50 percent and 75 percent of peak loads 7.5 16.2 28.9

• HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

TABLE 3.7-6 ACTUAL AND THE WORST COMPUTED STRUCTURAL GAPS FOR CATEGORY I STRUCTURES Category I and Actual The Worst Computed Non-Category I Structural Gaps Structural Gaps Structures Provided lin.) Required (in.) Reactor Building and 1.75 0.74 Auxiliary Building Reactor Building and 2.00 0.92 Turbine Building Auxiliary Building and 1.75 o. 74 Plant Cancelled Area Auxiliary* Building 2.00 0.91 and Turbine Building Plant Cancelled Area 2.00 0.88 and Administration Facility Auxiliary Building 2.00 0.87 and Administration Facility

• HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

TABLE 3.7-7 FLOOR RESPONSE SPECTRA PEAK BROADENING CRITERIA (NSSS) Response Spectra Peak Direction Broadening Criteria North-South and +/-25 percent for any spectral peak East-West between approximately 3.5 and 6 Hz I (Peak response in this frequency range is due to soil response).

                                +/-15 percent for all other responses Vertical                         +/-15 percent for all responses 1 of 1 HCGS-UFSAR                                                    Revision 17 June 23, 2009

• FREQUENCY (cps) 015 01

 ~......
 ~ *~~~~~~~~~~~~~~

(sees.) REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION SSE HORIZONTAL GROUNDSPECTRA 0.20g UPDATEDFSAR FIGURE3.7-1

• FREQUENCY (cps)

PERIOD (sees.) REVISION0 APRIL 11. 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION SSE VERTICAL GROUNDSPECTRA 0.2()g UPDATEDFSAR FIGURE3.7..2

E z 0

  ~

a: w

  ..J w

()

  ~   -o.
      -o.30~----------~------------~------------~----------~----------~

0.0 5.0 10.0 15.0 20.0 25.0 TIME-SECONDS REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION SYNTHETIC TIME-HISTORY OF THE HORIZONTAL COMPONENTOF THE DESIGNEARTHQUAKE FOR SSE UPDATED FSAR FIGURE3.7-3

0.2 0.1

 § z     0.0 0
 ~

a: w

 ...J w

(,) 0

 <(
      ~.304-----------~------------.-----------~r-----------~------------,

0.0 5.0 10.0 15.0 20.0 25.0 TIME-SECONDS REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION SYNTHETIC TIME*HISTORY OF THE VERTICALCOMPONENTOF THE DESIGNEARTHQUAKE FOR SSE UPDATEDFSAR FIGURE3.74

• Formation Saturated Unit Welgni: *

(pcf)

                                                   *Poisson's
                                                     .Ratio Vincentown Sand: greenish-gray     t16              0.43 fine to medium sand REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION IDEALIZED  SOILPROFILE FOR THE POWER BLOCKAREA UPDATEDFSAR                  FIGURE3.7-5

• Formation r.~ ..-....~.-:......"'.!"._"'**!'~."!":.-::...."!"'.-.'!'!'~:~~"'!'*......'""."'"*.~:~""::!:'...""! ~.-:

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                                                                                                                                                                                                             +1oo*
                                                                                                                                                                          *o:..ui*.:

ML (hydraulic fill) 110

                                                                                                                                                                                                              +72'
          'Old River                                 :fineto coarse
                                                                                                                                                                                                              +68' Bottom'            Sand graysand                                                                                         124                                     0.40
                                                                                                                                                                                                              +65' Kirkwood                    Clay:grey,medium-stiff                                                                        124                                   0.40 to stiff clayey1011
                                                                                                                                                                                                              +55'
     .~       '*~ :-~*           ~;          ~~. O:               **                                             *"'~                *-~* :.~    -.,.~~~~          *.*:.*\::**~~**. t ..**~:
        ** 8~~~* sand=*r~ddi.h-br~ri mica-..
          **             M                f                                       f . !II'   .. *     ... *                ** 0  M<j *..     ...  ....        .....* *

• 124 0.40 ceousfinetomedium~and

  .. 4   -....*~.~-::.'.:         ** - * * *.""'*  *.*;..!-:;:.~.!*.-::'"~':.*:*.::**~*:::~.::: ...*~*~: . *. *
                                                                                                                                                                                                               +45' OxidizedVIncentown                                                                                                         121                                  0.43
                                                                                                                                                                                                               +40'
                                                                          /.1        ;/ //                                                             / / // // // // //

Vincentown Sand: greenish-gray 121 0.43 finetomediumsand

                                                                                                                                                                                                                -30' REVISION0 APRIL11,1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION IDEALIZEDSOILPROFILE FOR THE INTAKESTRUCTUREAREA UPDATEDFSAR                                                    FIGURE3.7*6

• Reactor Building Shell k
• Center of Mass z = Center of Rigidity or Massless Point YIE*W)

                           *5                              Rigid Connection
                           *6 X {N*S)
                                                -*f't*J-   Translational and/or Rotational Spring 7

Interior Structure 8 9 Radwaste Section Drywell 10 RPV

                                                                            !~I
                                                             ...---*11~23 Shield Wall     l30
                                                                & Pedestal      T
                                                         ~ -~~r~~Ht 37 6

Internals 42, *45 69 . I 67 52 60 43 63 64

~~

65 74 76 84 91 r

                                                                 .l.-.J.73 82                 98

L ~~;

71 12 *-::-:- 79 80 81 f 89 ' 97 :105 99 86 166

                                                          ~7 106 127                                          167 114 94             95 104             tt       tl 118
                                                        *1oat-#H,1,                    112 102 11oT     ,,6 j            .

109 REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDING MATHEMATICAL MODEL UPDATEDFSAR FIGURE3.7-7

REVISION0 APRIL11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDING MATHEMATICAL MODEL UPDATEDFSAR FIGURE3.7-8

70.0' - WftT

                                       )

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REVISION0 APRIL11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION INTAKESTRUCTURE MATHEMATICAL MODEL UPDATEDFSAR FIGURE3.7*9

ModeNumber4 N-S =Triangle Direction Frequency (CPS)=4.09 E-W =Square Direction Vertical"" Cross REVISION 0 APRIL11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGSHELL-MODESHAPES,MODE4 UPDATEDFSAR FIGURE3.7-10

Mode Number4 Direction N*S =Triangle {CPS) =4.09 Frequency Direction E-W =Square Vertical

• Cross REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGDRYWELL-MODESHAPES,MODE4 UPDATED FSAR FIGURE3.7-11

ModeNumber4 DirectionN*S =Triangle Frequency (CPS) = 4.09 DirectionE-W =Square Vertical= Cross REVISION0 APRIL'11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGBIOLOGICAL. SHIELDWALL.AND RPV PEDESTAL.- MODE SHAPES,MODE 4 UPDATEDFSAR FIGURE3.7-12

ModeNumber5 Direction N*S =Triangle (CPS) s::: 4.25 Frequency Direction E*W = Square Vertical =Cross REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGSHELL-MODESHAPES,MODE 5 UPOATED FSAR FIGURE3.7*13

ModeNumber5 Direction = N-S Triangle Frequency (CPS)= 4.25, Direction E*W = Square Vertical "' Cross REVISION 0 APRIL 11. 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGDRYWELL-MODE SHAPES,MODE 5 UPDATEDFSAR FIGURE3.7-14

ModeNumber5 Direction = N-S Triangle Frequency (CPS)= 4.25 DirectionE-W =Square

                               =

Vertical Cross REVISION0 APRIL11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGBIOLOGICAL SHIELDWALLAND RPV PEDESTAL-MODESHAPES,MODE5 UPDATEDFSAR FIGURE3.7-15

ModeNumber7 DirectionN-S =Triangle (CPS)= 4.45 Frequency DirectionE-W = Square Venical =Cross REVISION0 APRIL11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGSHELL-MODESHAPES,MODE7 UPDATEDFSAR FIGURE3.7-16

ModeNumber7 DirectionN*S:Triangle (CPS) Frequency = 4.45 Direction E*W =Square Vertical= Cross REVISION0 APRIL11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGDRYWELL-MODESHAPES,MODE7 UPDATEDFSAR FIGURE3.7-17

• t-P.

                            ~
                        *fl.
                       ;t n~

d* ModeNumber7 N-S = Triangle Direction Frequency(CPS)= 4.45 Direction E-W =Square

                                      =

Vertical Cross REVISION0 APRIL11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGBIOLOGICAL SHIELDWALLAND RPV PEDESTAL-MODESHAPES,MODE 7 UPDATEDFSAR FIGURE3.7*18

ModeNumber10 Direction N*S""Triangle Frequency (CPS)= 8.87 Direction E-W = Square Vertical=Cross REVISION0 APRIL 11, 1988 PUBLIC SERVICE ElECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGSHELL-MODE SHAPES,MODE 10 UPDATEDFSAR FIGURE3.7-19

ModeNumber10 DirectionN*S =Triangle Frequency (CPS)= 8.87 DirectionE-W =Square Vertical= Cross REVISION 0 APRIL 11, 1988 PUBLICSERVICEELECTRICAND GAS COMPANY HOPE CREEKNUCLEARGENERATINGSTATION REACTORBUILDINGDRYWELL-MODE SHAPES,MODE 10 UPDATEDFSAR FIGURE3.7-20

ModeNumber10 DirectionN-S = Triangle Frequency (CPS) :o: 8.87 DirectionE*W =-Square Vertical

                                =Cross REVISION0 APRIL 11. 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGBIOLOGICAL SHIELDWALLAND RPV PEDESTAL-MODESHAPES,MODE 10 UPDATEDFSAR                  FIGURE3.7-21

ModeNumber11 = Direction N*S Triangle Frequency (CPS)= 8.97 Direction E*W == Square Vertical= Cross REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGSHELL-MODESHAPES,MODE 11 UPDATEDFSAR FIGURE3.7*22

I,/f I q~

                      .. c
                           ~

f* lo ModeNumber11 Direction N*S =Triangle Frequency (CPS)= 8.97 Direction E*W =Square Vertical = Cross REVISION 0 APRIL11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGDRYWELL-MODE SHAPES,MODE 11 UPDATEDFSAR FIGURE3.7-23

ModeNumber11 Direction N-S"" Triangle Frequency (CPS}=8.97 Direction = E*W Square Vertical .. Cross REVISION 0 APRIL 11, 1988 PUBLICSERVICEELECTRICAND GAS COMPANY HOPE CREEKNUCLEARGENERATINGSTATION REACTORBUILDINGBIOLOGICAL SHIELDWALLAND RPV PEDESTAL-MODE SHAPES,MODE 11 UPDATEDFSAR FIGURE3.7-24

ModeNumber16 DirectionN*S=Triangle Frequency (CPS)=11.42 DirectionE*W =Square

                                 =

Vertical Cross REVISION0 APRIL 11. 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGSHELL-MODESHAPES,MODE 15 UPDATEDFSAR FIGURE3.7*25

                      ~ ~ :.
                          ~ :.
                        ~~     I

• I :~ 1- 4a.

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                        ~
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I :~ ModeNumber15 Direction N-S =Triangle Frequency (CPS)= 11.42 Direction E-W =Square

                                                =

Ve"ical Cross REVISION0 APRIL*11,1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGDRYWELL-MODE SHAPES,MODE 15 UPDATEDFSAR FIGURE3.7-26

• \

p *~

                            ~ *1-J "'1-I~~-.,*

[ [

                              ~
                             -t ModeNumber15                         Direction N-S = Triangle (CPS) = *11.42 Frequency                            Direction E-W =Square Vertical=

Cross REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGBIOLOGICAL SHIELDWALLAND RPV PEDESTAL-MODE SHAPES,MODE 15 UPDATEDFSAR FIGURE3.7-27

ModeNumber17 Direction N*S == Triangle Frequency (CPS) = 12.34 Direction E*W =Square Vertical= Cross REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGSHELL-MODESHAPES,MODE 17 UPDATEDFSAR FIGURE3.7-28

Mode Number 17 Direction N*S =Triangle Frequency (CPS I = 12 .34l Direction E-W '"' Square Vertical ::z: Cross REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGDRYWELL-MODE SHAPES,MODE 17 UPDATEDFSAR FIGURE3.7-29

ModeNumber17 DirectionN-S == Triangle {CPS) = 12.34 Frequency DirectionE-W =Square Vertical=Cross REVISION0 APRIL11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGBIOLOGICAL SHIELDWALLAND RPV PEDESTAL-MODESHAPES,MODE 17 UPDATEDFSAR FIGURE3.7-30

ModeNumber18 Direction N-S =Triangle Frequency {CPS)== 12.74 Direction E*W =Square Vertical = Cross REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGSHELL-MODESHAPES,MODE 18 UPDATEDFSAR FIGURE3.7-31

ModeNumber18 Direction N-S =Triangle

 *Frequency (CPS)= 12.74      Direction E-W = Square Ver:tical
                                   =Cross REVISION0 APRIL 11. 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGDRYWELL-MODESHAPES,MODE 18 UPDATED FSAR                 FIGURE3.7*32

• li r.~ M

                                      *~
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                                       ~
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                                     +
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ModeNumber 18 Direction N-S =Triangle Frequency (CPS) == 12.7 4 Direction E-W = Square Vertical= Cross REVISION0 APRIL 11, 1988 PUBLIC SERVICE ElECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGBIOLOGICAL SHIELDWALLAND RPV PEDESTAL-MODE SHAPES,MODE 18 UPDATEDFSAR

ModeNumber27 DirectionN-S =Triangle Frequency (CPS)'"'18.35 DirectionE-W =Square

                               =

Vertical Cross REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGSHELL-MODESHAPES,MODE27 UPDATEO FSAR FIGURE3.7-34

ModeNumber27 DirectionN-S = Triangle Frequency (CPS)=18.35 = E*W Square Direction Ve"ical = Cross REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGDRYWEll-MODE SHAPES,MODE 27 UPDATEDFSAR FIGURE3.7-35

ModeNumber27 DirectionN-5..., Triangle Frequency (CPS)=18.35 DirectionE-W =Square

                             = Cross Vertical REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGBIOLOGICAL SHIELDWALLAND RPV PEDESTAL-MODE SHAPES,MODE 27 UPDATEDFSAR                 FIGURE3.7-36

ModeNumber45 DirectionN*S =Triangle Frequency = (CPS) 28.24 DirectionE*W =sQuare

                              =

Vertical Cross REVISION0 APRIL11. 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGSHELL-MODESHAPES,MODE45 UPDATEDFSAR FIGURE3.7-37

ModeNumber45 Direction N-S = Triangle Frequency (CPS)= 28.24 Direction = E*W Square Vertical =Cross REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGDRYWELL-MODESHAPES,MODE45 UPDATEDFSAR FIGURE3.7*38

• Q t

lJ j ~

                          <II lo 4 1-4   i-1-

(/ ~* ModeNumber45 Direction = N-S Triangle Frequency (CPS)= 28.24 Direction = E-W Square

                                         =Cross Vertical REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGBIOLOGICAL SHIELDWALLAND RPV PEDESTAL-MODESHAPES,MODE45 UPDATEDFSAR                 FIGURE3.7-39

ModeNumber4 Direction N-S =Triangle Frequency (CPS)= 6.20 Direction E*W =Square Vertical= CroSs REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDING DIESELGENERATORAREA-MODESHAPES,MODE 4 UPDATEDFSAR FIGURE3.740

ModeNumber4 DirectionN*S = Triangle (CPS)= 6.20 Frequency DirectionE*W = Square

                             = Cross Vertical REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY      BUILDINGCONTROL AND RADWASTEAREAS-MODESHAPES,MODE4 UPDATED FSAR                FIGURE3.7-41

ModeNumber5 Direction N*S = Triangle Frequency (CPS}=6.48 Direction = E-W Square Vertical "" Cross REVISION0 APRIL11. 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDING DIESELGENERATORAREA-MODESHAPES,MODE5 UPDATEDFSAR FIGURE3.7-42

ModeNumber5 Direction N-S =Triangle {CPS)=6.48 Frequency Direction E*W =Square Vertical= Cross REVISION0 APRIL 11. 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDINGCONTROL AND RADWASTEAREAS-MODESHAPES,MODE5 UPDATED FSAR FIGURE3.7-43

ModeNumber6 DirectionN-S = Triangle (CPS).,12.36 Frequency *DirectionE*W =Square Vertical

                                "" Cross REVISION0 APRIL11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY      BUILDING DIESELGENERATORAREA-MODESHAPES,MODE6 UPDATEDFSAR                 FIGURE3.7-44

ModeNumber.6 DirectionN-S =Triangle Frequency (CPS) = 12.36 DirectionE-W = Square Vertical = Cross REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDINGCONTROL AND RADWASTEAREAS-MODE SHAPES,MODE 6 UPDATEDFSAR FIGURE3.7-45

Hode Nu.rnber 7 Direction X =TRIANGLE Frequ~ncy = 13.24 cps Direction Y =SQUARE Direction Z =CROSS.. REVISION0 APRIL*11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDING DIESELGENERATORAREA-MODE SHAPES,MODE 7 UPDATEDFSAR FIGURE3.7-46

• r I

J lP

                                         *p l
                                                     *A
           ~.
                                                       ;j
                        ._,.....,...      $          .J,
           *+.
               /                           L         l
                                           ~

i

                   ~

I

                                     ~      ~        .. ~
                                              \. 1
 .l-....-    ::a:- === )
                                        \       '
                                                  -'~\\*
                                                 '*     I
                                                                                --~----**** ... - 1

t-1ode Number7 Direction X = TRIANClLE Frequency= 13.24 cps Direction Y =SQUARE Direction Z =CROSS REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDINGCONTROL AND RADWASTEAREAS-MODESHAPES,MODE7 UPDATEDFSAR FIGURE3.7-47

• ModeNumber8 DirectionN*S "' Triangle (CPS) = 15.28 Frequency DirectionE-W =Square

                              =

Vertical Cross REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDING DIESELGENERATORAREA-MODESHAPES,MODE 8 UPDATEDFSAR FIGURE3.748

• ModeNumber8 DirectionN-S =Triangle (CPS) = 15.28 Frequency Direction =

E-W Square

                               =

Vertical Cross REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDINGCONTROL AND RADWASTEAREAS-MODESHAPES,MODE 8 UPDATEDFSAR FIGURE3.7-49

• ModeNumber9 DirectionN-S =Triangle Frequency (CPS)==16.54 DirectionE-W = Square

                             =Cross Vertical REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY    BUILDING DIESELGENERATORAREA-MODE SHAPES,MODE9 UPDATEDFSAR                  FIGURE3.7-50

ModeNumber*9 DirectionN*S =Triangle (CPS)= 16.54 Frequency Direction = E*W Square Vertical=Cross REVISION 0 APRIL 11. 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDINGCONTROL AND RADWASTEAREAS-MODE SHAPES,MODE9 UPDATED FSAR FIGURE3.7-51

ModeNumber10 DirectionN-S =Triangle Frequency (CPS)= 17.54 DirectionE-W = Square Venical = Cross REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDING DIESELGENERATORAREA-MODESHAPES,MODE 10 UPDATEDFSAR

ModeNumber10 Direction = N-S Triangle Frequency (CPS)=17.54 DirectionE-W =Square Vertical=Cross REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDINGCONTROL AND RADWASTEAREAS-MODESHAPES,MODE 10 UPDATEDFSAR FIGURE3.7-53

I

                                                  /"'t I

I

  ~ODE NUMSER JJ FREOOENCY IC~Sl

• 19.80 O!RECiJON X
• 1P.JR~CLE O!REC1!DN Y
• SOUARE OJR:CTJDN 1
• CROSS REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDING DIESELGENERATORAREA-MODE SHAPES,MODE 11 UPDATED FSAR FIGURE3.7-54

1100£ NUMBER Jl F"REOUENCY ICP'SJ II u. BO OJRECi!DN X

• TRlANCi.."E D!R!CiJON Y SQU~Rf DlRECTJON l
• CROSS REVISION0 APRIL11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDINGCONTROL AND RADWASTEAREAS-MODE SHAPES,MODE 11 UPDATEDFSAR FIGURE3.7-55
• ModeNur.nber12 Frequen-cy *(CPS)= 20.10 Qirection Direction N*S =Triangle

                                         =

E-W Square Vertical*. Cross REVISION0 APRIL'11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDING DIESELGENERATORAREA-MODE SHAPES,MODE 12 UPDATED FSAR FIGURE3.7-56

• Mode Number 12 Direction N~S =Triangle Frequency (CPS) = 20.10 Direction E*W ""Square Vertical= Cross REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDINGCONTROL AND RADWASTEAREAS-MODE SHAPES,.MODE 12 UPDATED FSAR FIGURE3.7-57

l I 250 l f I I I I 50 0 0.2 0.4 0'.6 Maximum Displacement (in} 0.8 1.0 REVISION 0 APRIL11, 1988 PUBLICSERVICEELECTRICAND GAS COMPANY HOPE CREEKNUCLEARGENERATINGSTATION REACTORBUILDINGSHELL N-S DISPLACEMENT UPDATEDFSAR FIGURE3.7-58

• 'i.

                                                                ..~

300 - -* rr II

                                                        ,       ~BE ll Ill 250 li I;
                                                                     . -.     -. *v     -.SSE*

I f--

                                                                                    ~

j

                                                                                  ~

200 Ll

                      ~
                                            . -v
                       =
                      .9                  I
                       ~

Q,l 150 iii Ll I .

                                                                                           -   **+

l I

• 100

_.li .- 0 *r,.-' '1 so*~-

                                                                      *o.a                             o. 5
                   ..          0         0.1                                           0.4
             'I                                        0.2 a       ~*                              Maximum Displacement On)

REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDING SHELL E-W DISPLACEMENT UPDATED FSAR FIGURE3.7-59

I '

                      ~*
                                . .._ .       ..                                           OBE :-

t444-I-H~4+1~H+*I+t .J-+.--a--U:ll-1.*,..*;;..~SSE .

                                ,    ..             ~
                       -~****                          ,::*-
                              ~
                                           *~
 .I I                   *1:=::::             ;'l
                                                 ~

I.

        .         *, .              : I~       . . .:
    ~ *4..... "'~:.!..:.:. .. .:4~-::~]-**
      .      ~      ... .            '    .   ~~
                                                       . 50 o. 0    . . . . 2. ~ . .

4. ' .

                                                                                                                        *2 .

I. Muxlmum Vertlcallllsplaccment (ln x 10 ) REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGSHELL VERTICALDISPLACEMENT UPDATED FSAR FIGURE3.7-60

200 180

     'h
   *41

• 160 6'

              ~

c: Q 140

             ~

Ql Ll.l 120

• 100 0 0.1 0.2 0.3 0.4 .

Maximum Horizontal Displacement (in} 0.5 REVISION0 APRIL11. 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTOR BUILDING DRVWELL N-S DISPLACEMENT UPDATEDFSAR

• 200

[f' l. IRO .-r . -* . . . -

                                                                  ~

I*

                        ....6.

CBE

                                      }6£)
                                                            ~~              ~
  ..t.
                               . t:'l
    ,._=~-~u*   , .: . - - ~ -*. ' -

100 f* I II.

                                                    ., ll Hn f

0 0.1 0.2 0.3 I {/

 .                                           Maximum Uorizontal Displacement (ln)
 *    :t~

REVISION0 APRIL11. 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTOR BUILDING DRYWELL E-W DISPLACEMENT UPDATEDFSAR FIGURE 3.7-62

r:

                                                                       .,...,...,,...,....,....,.-,-......,-,-......,....,,J ~

1.

                                                                                                                           *~-----

160 '.I--~ .. I I

       \
   '          140                                                               '
                                                                                       -r.r : . . .

1,. 'I I 'i

                                                                    ' 4                                 !
   .t                                                                       :A
                                                                 .. L-;+-                                                       .~~1.

I c ....,_~+-j_.l...,.,IH-i-.+-.*.;.....1-H....,_j..,.:..J-l[L/.J~.__.L!. ~- 120 - l/. 0

                                  -T         * *        *

• T .* t -- * *  : ~~:;....... **

t ~ .' ra .f. '  ; 4. ,,

i. > , ' . , A CIJ WJ 0.1 . *o.z o.J

                                                                                                                                            *--~

0 0.4 Maximum Horizontal Displacement (in) REVISION0 APRIL* 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGSHIELDWALL AND RPV PEDESTAL N*S DISPLACEMENT UPDATEDFSAR FIGURE3.7*63

wn - v

                            ~-'
                                                     .     - ..   ~

0 BE 140 - /'" I -~ \ g

                       . ~  .,

II '-

                                                                 ~~ SSE
 *./:       .::
           .9 120      -             *-

Ql l1i J(JQ II

                               ~
                                         !I ll
                                                                 ~*

ll

                                          '      '   "' *~

sn j*- (.I . .3 Maxlmum H~rlzont-.l OlsJ>lAcement (In) REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGSHIELDWALL AND RPV PEDESTAL E-W DISPLACEMENT UPDATEDFSAR FIGURE3.7-64

c: 0 QJ l.tJ Maximum Ho*rizontal Acceleration REVISION0 APRIL11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGSHELL N-S ACCELERATION UPDATEDFSAR FIGURE3.7-65

I i+-1++1-HH+*I/HI++*H--

• OBEV V ... ... SSE.

I I 1-f+*+i'-f-I*H-- * ~ * -t++t-H+*H ll 200 v I"

• I I 1 l+l+-t~H-t++H-I~+-H--ll-l*t+t-H*t-t-t+r*t+ir-t t-t+t+t il-l r ~*

          . 150 1+1-+,+t.-:1-H-+t-H-f++:Hi+I'-H-i-H-H-!H+++-l!-H-,++1H-I I*

v 100,HH,+HH-H-~i/~~H+,+HH++HH++t-H4++~H

  'I                                * * *H-IH-+H"H-a                       Maximum Horizontal Ac:ecleratlon (g)

REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGSHELL E-W ACCELERATION UPOATEO FSAR FIGURE3.7-66

H-f+J-+H-++H- * -- * -*

                                                          .'.              ~. ; - .
                                                                                                   .. 1-f-.
                                                                                                        -I-250
                                                     . OBE"
                                                                                                   * -    1-t{                     .. , I                           -

• 1-*

a' 200 I I .. 1-r-*

• I ISO . -~ . .. - . -I- . \ .

I l }i

                          ,: r t                                                       - *, l . ,. .    --

4

           ** 'it. ....
    ~.---:,--:.:---:',~ .v- ! l' h....
                          * cO.                     0       .. 0. 1 . .     : 0. 2
                                                                         . ~

o. 3 ; o* .f' 0.5 Maximum ftorb:ontal Acce~;eratlon (g)

REVISION0 APRIL 11. 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDING SHIELDWALLAND RPV PEDESTAL E..W ACCELERATION UPDATED FSAR

                                       . i.
        ~   ...

H-f+Ht++f-H:OBE- SSE* *. **

• 120

• c .:

I r---- . J .

                                                                                               ~
           ~*          .~     100
                       '~

r- . 80 6* 0 o.s  ::' .0.:15 0.20 0.25

    -           &:)*

Muxtmum Vorllcai*~Cc~lunatlon (g) REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDING SHIELDWALLRPV PEDESTAL VERTICALACCELERATION UPDATEDFSAR FIGURE3.7-73

300 250

 -c 200 0
  ~

ltJ QJ UJ 150

• 100 50 Maximum Shear (x104 kips)

REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGSHELL N-S SHEARFORCES UPDATEDFSAR FIGURE3.7~74

                                                                                     -H-+++1!-+1-H-H 300 B

I T

                                                                                 . (H-I I    I I

I I I I 250

                                                                   'I                 +/-ttl:+/-+       I I      I     :

• I  :*l~f-FF j s.

g 20()

• I +-t-++ i-tt+++

                                                                               '    I    * *I  I
                      .s

_j ~ , *

                       ...         I               ~-SSE
                                                                                   +

I I

                       ~

e (Xl 150 Ll 100

  . d.. . " ., .,. .

50 ()* I ** * \ *

o. 2.0 4. 0 6.0 8.0 10.0 MadmumShear(x 'io4 kips)

REVISION0 APRIL11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGSHELL E-W SHEARFORCES UPDATEDFSAR FIGURE3.7-75

                                                        * * * ** *        * *

• J**-1H -f* ~1+1++-il-l

                                                   - ~ ~  ~   ...
                                           * * **  *'     *1-Ml..J-.I*H..:J~H~+-11-l         HH-+-I+t+l
                                                                      * *1**"1-f*~ .If*t-4 1-H*I+I-t-t 250  ~~~~-~--~-~H4**I1*+:~dj*r~I*~~~UJ~~~~

I I I Ti**l+f*t-+1:.t-4-f*I+H*

• I 150 ose* *** * * *. * * ,

                                                                                        ~  ~
                        ~: .       . .' :- .. ; : : : ~ ; . .. * ; . ' cf-t'i-1:+-H-i:-f-t*t-1-t_ .            *.  *
   ... . , . . it:. ""' .I     50   !-
                                  ~~~~~~--~~~~~~~~~~

_d_,.P' 0 I  ! 3 4 4 . ~. . .*. b ~ . 4 Maximum Axlol Force (x 10 kips) REVISION0 APRIL 11. 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGSHELL VERTICALAXIALFORCES UPDATEDFSAR FIGURE3.7*76

180

  .b
 ~*

160 4.

     +J
     ~

c: 140 0

     +J fC Q)

Maximum Shear (xlo2 kips) REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGDRYWELL N-S SHEAR FORCES UPDATEDFSAR

2U() -* - . ........................,..,. .......

                                                                                                                                            ~-
  ~r*~"-

t 1;.\ JRO .. .. - .. ~- . I ~

                 .';;!                                                     II
                           '.b HiU I                               .. r.-

I f .. (\. I

                                                                              *~- H-f.. I~ :+-'1 g
                                                  ,*.w               ~                               **++:++.-1.--+  -~;- *
                     '1~*

OBE t.

• t:l
• I

                                             .2 I           J                                CIJ
             ~                               LtJ
                               ':"                12U                                                                                          I++++H -* *-

• I

  '------' **6                         .(. *

=...:  ; J.' .

 '         *t:t===t                               lOll H-1-H l+l+t-i+H-ll-t++... H4-"t+HJ I ;
   ~

I J 1-

                                                                                             --I I \1      q     .                                     0           1. 0        2.0                 3.0                          4.0                5.0         n.o I_.,

2 Maximum Shear(x 10 kips) REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGDRYWELL E-W SHEAR FORCES UPDATEDFSAR FIGURE3.7-78

200 ---~.-.-..~~ ~r: '  :; iii~ * *

                .4.\.*                    . ~~*1-+JI-II.J-4+-H-H .JH
                               . . 140                                _._: .! .
                                                           .. .                                             *.. OB                                  .... ~:,.

a W~l-f~:-14.:-'"1-iJ.;.l*;l-l:  :-411*hi"'4 H-l+li-1-1+1-*.y;t.::F*P.SSE:

                                                                     .:-J.:...J.:                                                                   . :; . -  ~   !  l .; * *         -  ...
                           ~-                                  o                ...... ,.~'""'     .. ..,  *              ~ ~

• f ':.' ~ ' : ';' ~* I I! t * *. I* : ' . . * . ~ .~ ;  ; :* ; ; ; ~ .' : ; : ' * . . . , *

                           .!l .. 120 fll'                ~ . ::'    .                            '  .     :
                                                                 ** 1          ... '          ' ..
                                        *~   ~~~-         ~~
                                                   ~     ~..
                                           *

• w  ;
• t ** " "'

                                                                                                                                                                           ,..        ~       : ...

1-+*1-+,.+-,1'-1, * :  :. * --

• I ., . t l I .'

0 2 3 \ 4' 5 6 2

    .... 'II ..                                                                     Maximum Axial 11orce (x 10 Ups)

REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGDRYWELL VERTICALAXIALFORCES UPDATEDFSAR FIGURE3.7-79

16

 ~*
    ~
    '+-

s::

    .....0
    ~

ttJ QJ L4J

• *cr* ***----4-:o*---a:a--*-12*~ o-*--16~ o-* zo. o Maximum Shear (xi02 kips)

REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION

                                  .       REACTORBUILDING SHIELDWALLAND RPV PEDESTAL N-S SHEARFORCES UPDATEDFSAR                 FIGURE3.7*80

• *-V'-

          ~                                                        ...    -.       .-     ...        - .. -.   ~       - ..

r:"

           ~-                         160                    ..      .-                 -                                        -                        ..

I ,.1

                                                                                           ~    '                                                  ~
                      \

I

           ~
              .                       140                      SSE dJe..

1

            '{                               -- -i- .. '                       -    - . '.
                                                                                             ..         ..             :     ~

I g ~IJ

  ~
                                                                  ~

Q 120 i

                                 .2      '
                                  .,.                     I
                                  ~

n CD I:Q

f'l .

1--- .'*II

                                                                                                                                             ~
                            )                                               -.

J()()

                                                  ..                                               .r; : .                                             -
 'dY*~*,
                                                                                                 ~
                                                                         *~                                                            ~
                      . .              80 o.o 6*.                                                 4.0                         8.0                    12.0                   16.0               20.0
    - *        !::)

• Maximum Shear. (x ttl kips)

REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDING SHIELDWALLAND RPV PEDESTAL E-W SHEARFORCES UPDATED FSAR FIGURE3.7-81

 .I
                      \'
                                                              -.     *   ..   .                   ..    ' ..    - . * * .  * * . *1-t-f-f..I ..I-J I .       ~. .
            '1
                            \

OBE 120 H-t-H-H-t-l-f-1FJ...:.I-"FHH++-Hf-f+H-f-I+H::I"Ff-~oo>>f-+*~*H._,.

~ ~ SSE

                                                                                                                                       .. +H!+H I~.*:.
  ~:-~                    J
                           .~)**
                                                                                                     ** t
  *~*,            .
                                                                  *: ' . . .~: .*I: : ~ *~ . ... : .

lOO.HH-H-~*+H~*rHH++-H~-rH~~HH-f-+-HK~~~II~

                                                         .  - . . "'   --+<****-          .
                                                                                                 ~*                            ~*---
                                                       '                        ~ ... ;

l *

                              ................. .                        . . ; *- -     ~

6*

    - .        -=>.

REVISION0 APRIL11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDING SHIELDWALLAND RPV PEDESTAL VERTICALAXIALFORCES UPDATEDFSAR FIGURE3.7*82

I I 250 I -

                      - c:

0 I +.> I - res Cl.l I.&J I I 100

   ... .. "is*'..

o* 4 A* 50 0 24 6 8 Maximum Moment (xto6 kip-ft) REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING ST ATIDN REACTORBUILDINGSHELL N-SMOMENT UPDATEDFSAR FIGURE3.7-83

300 HH++HH++HH++HH++~++HH+H

      ... - ....\- . -
                             .. - .. to
                                          .. r"       .
                   .- *:  *~ . : ., . '
                                          ~ ' . I'\ -

50'

0. 2 4 6 Maximum Moment(x 106ktp-ft)

REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGSHEll E-WMOMENT UPDATEDFSAR FIGURE3.7-84

             <,;J*

ft:S

                            <U L&J 1---.-.t~.O       .......

I" . " .. I .... . . 0 0.4 0.8 1.2 1.6 2.0 4 Maximum Moment (xl0 kip-ft) REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGDRYWELL N-SMOMENT UPOATED FSAR FIGURE3.7-85

 ,F 2UU                   .. . .         - ....
 ~

IRO .. .- - -- ~- .... ll

       *.6                 ~                 . -.       - ..       '.               .. .
                                                                                  ~
                           ~

..SSE 1()0

                                     !-       fill                                                      -

OBE

     <l'              .. . -                                      .. . -.              ..          . -.

1\ g t4n - - q

           .9                                      . -       .            -    ..            ... . .
                                                        *~ ~

tU  : iil 120 [\

                        -    .-         '       1-            '  '  - ...    ..      . ...     . *-.      .  .

too """ .. t- .. i-* t-t- f-. RO 0 0.4 0.8 I. 2 1. 6 4 Ma.xlmum Moment(x 10 klp*ft* REVISION0 APRIL 11. 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDINGDRYWELL E-WMOMENT UPDATEDFSAR FIGURE3.7-86

                                               -*~***

160 *-----:sst~~-!-

.::..::..:.::::.:t~--:_: :*:**:~~ :.::..~..:.::*. ~ _... *---* oar*~-*

 <~:
                    --****-~-*-**--*-**-*----                                        '..
 ,.          140.

I.!- 1: 0 1'0 WJ Q)

• 804---------------------~----~

                 *O                2.0 Maximum Moment (xlo4 kip-ft) 4.0                     6.0             8.0 REVISION0 APRIL11. 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDING SHIELDWALLAND RPV PEDESTAL N-SMOMENT UPDATEDFSAR                                           FIGURE3.7-87

r-v-~- t----' .. -. ~ 0 ,. w * .. ..._ . -*. I

            ~-                             160                                                                      ..

I

                                                                ~ *~ - .. r       -.     ... - ' . .       .. ~ -.                .    .
                        \
             ~*                                                               -.

140

            ~                                       l
              ,.                                              !-SSE t                                   "h'          1-.J- .
                                                              ..o~~                     ... . f- -              . --- .. -    ..

I g ' l_/;',

                               \

Cl 120

          ..                    1     .9
                                                                                             ;                :        1!

I*.*.

                                    -~

v

                                    ......        ~ - ...
                                                      ~-          .  .        -.                     .- .                           -

1--- I

         .'*4                  j 100                                                       ""'
  ~*~*.                                           .
                         '        .          I
                                                    -                         *r-
                                                                                             \
                                                                                                .  ..   ".               - - --       I*

T *

                                                                                     ; ~ ~ ~
                                            !  . l.

I: o.o -- 80 (!,* 2.0 4.0 6.0 8.0 1\

• e)
• 4 Maximum .Moment (x 10 lclp*ft}

REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORBUILDING SHIELDWALLAND RPVPEDESTAL E*WMOMENT UPDATEDFSAR FIGURE3.7-88

• * I l l *

                                                                        *J11 I
                                                                               ~~*

1 _.._. _ _

• 194 --_._........_,;......,._._,,f:~ .

                                                                        ;  I l l
                                   '    ; I,

• I *

                                     --+*  I
                                     . I I

I

              'I-154
  + -l 1+-

1: 0

  ~

rei QJ Lt.J

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                                                          .                                                   ~;-
                                !                                   _J           *--~-----*

0.0 0.10 0.20 0.30 0.40 0.50 0.60 Maximum Displacement (in) REVISION0 APRIL11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDING DIESELGENERATORAREA N-S DISPLACEMENT UPDATEDFSAR FIGURE3.7-89

• 21.0*

                    =-t                             =t=-

{

                                               -a
                       -+

1.90 -+ 1.70 JI

                                                 ---1 150 130
                    --f-1*

110

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             =13=1                              -
            -__--{*             ____;::_~SSE
                                              -=

90 70

  .so o.o          o.. os 0.10       0.15    0.20
   .Maximum Horizontal Displacement (in)

REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDING DIESELGENERATORAREA E-W DISPLACEMENT UPDATEDFSAR FIGURE3.7-90

210

• 190 170 150 I

130 OBE 70 SSE 50 J 0.0 0.01 0.02 0.03 Maximum Vertieal Displacement (in) REVISION0 APRIL*11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDING DIESELGENERATORAREA VERTICALDISPLACEMENT UPDATED FSAR

I

                                                                 ;    .                  I  I   I 0 1    ., ,

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54 .....

                                    '.'1 0.0                              0.1                           0.2               . 0.3                                  0.4                              0.5 r~aximum Displacement                                         (in)

REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDING CONTROLAND RADWASTEAREAS N-S DISPLACEMENT UPDATEDFSAR FIGURE3.7-92

190 L 170 150 OBE:

                                  --SSE:

130  !-+

• 1:-f-*-

            =::::::::v-110                    -        --::;=:j 7
                                      =::1 90
                              --+-- -**-***~

70 50 I o.oo 0.05 0.10 0.15 o.~o Maximum Horizontal Displacement. *(in) REVISION 0 APRIL 11. 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDING CONTROLAND RADWASTEAREAS E-W DISPLACEMENT UPDATEO FSAR FIGURE3.7-93

170 ... II--

I I 150

                                                , ,    I L*

I 130

 .IJ
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c: 0 . , I ..

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                                '§E l ..

70 .. I I nsE ~ IL I I': *'

           .. lL
           .IF                                  SSE 50 o.o                    0.*0'1              0.02 Maximum Vertical Displacement {in)

REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDING CONTROLAND RADWASTEAREAS VERTICALDISPLACEMENT UPDATEDFSAR FIGURE3.7-94

154 ..

 ........ 134 ..
  ~
  "+-

c: 0

  ~

114 - - - OBE 1'0 QJ LIJ SSE 94 .. 74 54 0.0 0.25 0.50 0.75 Maximum Acceleration {g) REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDING DIESELGENERATORAREA N~S ACCELERATION UPDATEDFSAR FIGURE3.7-95

• :210

                ~*- *litiirr~rl¥b~~:~:~~§~~::::~
                      *-*-----.---...---*---"'~--1--'-"-....,_::t:_,____ .~~~ ;. ;                                                                        I )*****

190 170

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50 -~ -~ rt::;;:~-.;-~-1-.r<k--~Ht r; ..H ... *

• o.o 1.0 2.0 3.0 4.0 s.o 6.0 Maximum Horizontal Acceleration (g)

REVISION0 APRIL 11. 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDING DIESELGENERATORAREA E-W ACCELERATION UPDATEDFSAR FIGURE3.7*96

• 210 .. . I 190 170

   ~
         *.150 s:::

0 130 .. .. ..

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rd (1) r:a m T 110

• 90.

                               .OBE           ::

70 g ~$,~ I= 50 "T o.o 0.2 0.4 0.6 Maximum Vertical Acceleration (g) REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDING DIESELGENERATORAREA VERTICALACCELERATION UPDATEDFSAR FIGURE3.7*97

...:.:p:* J ' . :*., . ....'*------ '

  . f.,}

4-134 .. -- . : ' ./, ...:.. _;_:__t__:.:_....;_ ...:: ..:..:

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                                ' .... '.t J.

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94 1'

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74 -. --~ ' f .-==~~~--- .:__~

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                  . : :\\:-~~:~::::::~ ::=:::t ~ ~:

54 . ..... . * . I .. - I 0.0 0.25 0.50 0.75 Maximum Horizontal Acceleration (G) REVISION0 APRIL11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDING CONTROLAND RADWASTEAREAS N-S ACCELERATION UPDATEDFSAR FIGURE3.7-98

190

            .-l~~~:~-~!-~0:--t~:)i~r~:~-~w:-s 170  -                                                  !                   .

150 1

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                * -*;.~

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                                     ~

110 0.0 0.1 0.2 0.3 0.4 0.5 0.6 Maximum Horizontal Acceleration (g) REVISION0 APRIL'11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDING CONTROLAND RADWASTEAREAS E*W ACCELERATION UPDATEDFSAR FIGURE3.7-99

• 19J

                         '                  _1            '

170 I

                              'I                        I I

150 I 1

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c: l!' I 0 ' I

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 ...... 110
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                             'I l
                                             'I             ..

I' .. 50 . o.n 0.2 0.4 0.6 Maximum Vertical Acceleration (g) REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDING CONTROLAND RADWASTEAREAS VERTICALACCELERATION UPDATEDFSAR

• - - .-..,........_. 1 *

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0. 0 -i . 0 . -2* .'p . ,-:/: 0 ...-- .. 4

• 0 Maximum Shear (xl04 kips)

REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDING DIESELGENERATORAREA N*S SHEARFORCES UPDATED FSAR FIGURE3.7-101

• 210 ~ ---------------------------------------------

I .: . .!

                            .. * *. :-.~~ .. -~-:-~~: -:~:~: __ ::                             -~~    ::.: OBE.:~              ~~ :.:~~-~:--

I

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• J

      ~-190 ~1-h
            -         I I

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4J

  'PI  150 -:  ---~_-_-_-_-__-__-__---*"'1:*-:- *-:!. . .: ~-:_;:-_~- ~-~-.:. r:_-:_~_:_-~- - -;-_:-.~-~-~- -~-:-._~-:-*-* .: . ~--*-----_-_.__- - -
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I ... . . . : *: :::. .... . . ... i - .*~..  :.- ... MaximumShear (x 10 k1.ps

4. * )

REVISION 0 APRIL 11. 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDING DIESELGENERATORAREA E-W SHEARFORCES UPDATEDFSAR FIGURE3.7-102

• 210
• 190 OBE 170 ss so ' .. * - - ! -

     *0.0    1.0      2.0        3.0 Ma?imum Axial Force (x*lo4 kips)

REVISION0 APRIL11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDING DIESELGENERATORAREA VERTICALAXIALFORCES UPDATEDFSAR

1 174 ' .. ' r:: 0

 +o) tO QJ Lr.J 1

7 4 .... --* --*---*-* ~~-~-- ... **-~**. --~-ll .. I I t I -. 54 ..,...__ _---r-'----"T"'""-.L..-,* _-..., 0.0 1.0 2.0 3.0 t1aximum Shear {xlo4 kips) REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDING CONTROLAND RADWASTEAREAS N-S SHEARFORCES UPDATEDFSAR FIGURE3.7-104

190'" .... . .. . ! . . - - - - - *- - * .

                             --*-----           ~  *--   ---    ~
                       .:. F--- *--~.:- :.:.: _.-: ~-~*- -~7 ~~-~-~ ~-: :~

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• 70 L....L.---1-----,

           ......... --~-- ... ;. -*

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     ; '-~~~~~~ (~~--~-~~

50 ... ... . . . ' T

                                .. * * - . i                    --  ~-

1 I o.o 1.0 2.0 3.0 4.0 4 Maximum Shear (x 10 kips) REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDING CONTROLAND RADWASTEAREAS E-W SHEARFORCES UPDATEDFSAR FIGURE3.7-105

190 170 150

 -      130                       '
 --4.1
 \a.i c

0 110

 *.-I
  -4.1 I'CS Q,)
 .-1 r.a 90 70 50                                 .

1.0 2.0 3.0 4.0 4 Maximum Axial Force (x 10 kips) REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDING CONTROLAND RADWASTEAREAS VERTICALAXIALFORCES UPDATEDFSAR FIGURE3.7-106

• 194

                                                        ~;-;-~

174 154 74 54 ~-~~~==~~~~~~~~ 0.0 1.0 2.0 3.0 . .. 4. 0 f1aximumMoment(xi06 kip-ft) REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARYBUILDING DIESELGENERATORAREA N-SMOMENT UPDATED FSAR FIGURE3.7-107

• 210 190 170 150

  ..... 130 6

g Q) 110 r-1 fll 90 70 so ~----~-------------4----~ o.o 1.0 2.0 3.0 4.0 6 Maximum Manent (x 10 kip-ft} REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION AUXILIARY BUILDING DIESELGENERATORAREA EAWMOMENT UPDATEDFSAR FIGURE3.7-108

           -r

-

• I ,

1 I

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c:: 0 10

                                                                     S~E*

1

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  =.

90..0 80-0 i'O.. Il' - .1 .. 1 *

• l 1 o i i '* I I 1 i, ' ...... . L '

o.o . 0.06 0.12 0.18 0.24 0.3 DISPLACEMENT (IN) REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION SERVICEWATER INTAKESTRUCTURE CELLWALLS E~W DISPLACEMENT UPDATEDFSAR FIGURE3.7-112

• l.W.O 130.. 0 I

I 1.20.0 ' . .. I I

• I I uo.o I

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                          ..                                      OBE
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I 100-0 .. .. SSE

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90... 0 ' I

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                                                       *L..                I.

0.18

                                                                                     - 0.24         0.3 0.0                                   0.1.2 ACCELERATION (G)

REVISION0 APRIL 11. 1988 PUBLIC SERVICE ElECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION SERVICEWATERINTAKESTRUCTURE CELLWALLS N*SACCELERATION UPDATEDFSAR FIGURE3.7-113

• 140.0 130.0 uo.o

                            '                  OBE:

110.. 0

   -£....
     ~

100.. 0

     ~
     ~

i! SSE I

• 90.0 .. ,.

BO-O I J

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                              '          j 1.-          '                         ~7.-t o.os      0.16            0+24 ACCELERATION (G)

I REVISION 0 APRIL' 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION SERVICEWATERINTAKESTRUCTURE CELLWALLS E-W ACCELERATION UPDATEDFSAR FIGURE3.7-114

• l.W.O 130.0 I I uo.o I

uo.o I

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I 100.. 0 '

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                   '                                                         I 90.0                .'                         7SSE I

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o. 0 o. 2 0.4 o. 6 o. 8 1.0 3

SHEAR (KIPS x 10 ) REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION SERVICEWATER INTAKESTRUCTURE CELLWALLS N*SSHEARFORCES UPDATEDFSAR FIGURE3.7-115

140.0  ;

                *-                                     I 130.0                                                 j
                                                       '      :            I j          I            ;
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                                                   ~

uo.o  ;

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l ' I t  :  :

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I so.o I 70.0 i I I -- .. L 0.0 0.3 0.6 0.9 1.2 1.5 3 Shear (kips x 10 ) REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION SERVICEWATERINTAKESTRUCTURE CELLWALLS N*SSHEARFORCES UPDATEDFSAR FIGURE3.7-116

• l.W.O 130.0 I I

120.0

                     '                         I OBE I

I

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uo.. o I I I

     ~

100.0

     =

I I

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1

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                  -o.o    '  . L*

0.3

                                    '. I     . 1-*

o. s I

o."' 9 - 1.2 1.5 3 A..~L FORCE (KIPS X 10 ) REVISION 0 APRIL 11. 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION SERVICEWATERINTAKESTRUCTURE CELLWALLS VERTICALAXIALFORCES UPDATEDFSAR FIGURE3.7-117

130.0 1.20.0

                             ~ '

uo.o

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• 90.. 0
• SSE.

I' 80 .. 0

                                        '                 OBE '.

70,.(J - ' .* *

• I I I o ,  : I i I I : ~ ' L .*. ' .. ; . . .. I
• 1_, I ' **.:......__

               ~0                   L2                 ~4              &6                  4. 8            6.0 REVISION0 APRIL11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION SERVICEWATERINTAKESTRUCTURE CELLWALLS N*SMOMENT UPDATEDFSAR                          FIGURE3.7-118

140.0  : t' 130.0  :

                 '\

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                                            '                   SSE
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I 110.0

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                                                                                                      --      -J.

o. 0 2. 0 4.0 6.0 8.0 10.0 4

MOMENT(KIP- FT x10 REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION SERVICEWATERINTAKESTRUCTURE CELLWALLS E-WMOMENT UPDATEDFSAR FIGURE3.7-119

0

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                   'T'YP'ICAL RPV AND INTI.fltNAL fltEACTOA HIESSUFIE VESSEL snAM S9AAATOA GUIDE TUIES CRD HOUSINGS fltEFUEUNG IELLOWS _..._.,..,.,_

STEAM SEPAAATOR SHROUO YISSEL FUEL GUIOETUIES VESSEL SKIRT CONTROL lltOD DRIVE HOUSING CSHORTEm REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORPRESSUREVESSELAND INTERNALS SEISMICMODEL UPDATEDFSAR

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                            /

DAMAGE I NO DAMAGE VISUAL INSPECTION

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         *REPORT RESULTS TO NRC REVISION0 APRIL*11. 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION POSTSEISMICEVENT PLANTPROCEDURES UPDATEDFSAR

3.8 DESIGN OF CATEGORY I STRUCTURES 3.8.1 Concrete Containment This section is not applicable to HCGS because it has a steel containment. 3.8.2 Steel Containment The steel containment is an ASME B&PV Code Class MC vessel designed to house the Nuclear Steam Supply System (NSSS). The steel containment is a part of the Primary Containment System, which limits the postulated release of radioactivity from the NSSS. This section describes the structural design considerations for the primary containment and includes information that provides the bases for design, construction, and testing of the steel containment, except as modified by the plant unique analysis report, submitted to the NRC under separate cover (letter from R.L. Mittl to Albert Schwencer, dated February 10, 1984.) The primary containment consists of a drywell, a pressure suppression chamber, and an interconnecting vent system. The drywell is a steel pressure vessel with the shape of a light bulb. The pressure suppression chamber is a torus shaped steel pressure vessel located below and encircling the drywell. A vertical section of the drywell and suppression chamber is shown on Figure 3.8-1. 3.8.2.1 Containment Description 3.8.2.1.1 Drywell The drywell, shown on Figure 3.8-1, is a steel pressure vessel with a spherical lower portion 68 feet inside diameter, a cylindrical upper portion 40 feet 6 inches inside diameter, and a removable, flanged, hemi-ellipsoidal top head, 33 feet 2 inches inside diameter. Its overall height is 114 feet 9 inches. The bottom elevation of the spherical portion is 77 feet 10 inches. Inner and 3.8-1 HCGS-UFSAR Revision 0 April 11, 1988

outer steel cylindrical skirts that are encased in concrete and anchored to a concrete pedestal support the drywell. The outer skirt is designed to transfer the drywell loads at the bottom of the drywell into the foundation and is the primary support for the drywell during construction. The inner skirt extends into the drywell and transfers reactor pressure vessel (RPV) loads into the foundation. The inside of the drywell is filled with concrete up to Elevation 86 feet 11 inches. The drywell is enclosed by the concrete drywell shield wall. An air gap of nominally 2 inches separates the drywell vessel from the concrete drywell shield wall. The air gap permits displacement of the vessel, but the size of the gap is limited to allow transfer of postulated jet impingement forces into the drywell shield wall without rupturing the vessel. There are a few, very localized areas, below Elevation 100 feet-0 inches, where the air gap is reduced to as narrow as 0.5 inches. Generally, the reduced gap permits unrestrained displacement of the drywell vessel. Where restraint occurs, the structural effects have been included in the shell analysis. Additionally, a few localized areas exist where no concrete backing is provided. These areas have been evaluated to verify that the vessel alone can satisfactorily resist postulated jet impingement forces without the added resistance of the shield wall. The drywell is supported laterally by the drywell shield wall near the top of the cylindrical portion of the vessel. The lateral supports are designed to permit vertical and radial displacement of the vessel. Beam supports are provided for the drywell structural steel framing at Elevations 100 feet 2 inches and 121 feet 7-1/2 inches. The supports are designed to permit differential radial movement between the beams and the shell. Weld pads are provided on the drywell shell for the attachment of pipe supports, pipe restraints, and similar items. 3.8-2 HCGS-UFSAR Revision 0 April 11, 1988

Containment spray headers at Elevations 129 feet 2 inches and 137 feet 3 inches and a monorail at Elevation 135 feet 6 inches are supported by the drywell shell. The drywell water seal plate is supported by the drywell at elevation 176 feet 11 inches. Access to the drywell is provided through a bolted equipment hatch at Elevation 107 feet and another bolted equipment hatch with a double-door air lock at Elevation 107 feet. 3.8.2.1.2 Drywell Head Assembly The drywell head provides a flanged removable closure at the top of the drywell for RPV access during refueling operations. The drywell head assembly consists of a hemi-ellipsoidal head held in place to the drywell flange by bolts, as shown on Figure 3.8-2. The head is made of 1-1/2-inch thick plate with a 4-inch thick flange and is secured with 180, 2-1/2-inch diameter bolts to the 4-inch thick drywell flange. The head to drywell flanged connection is made leaktight by two replaceable compression seals. Test connections are provided between the seals to allow pneumatic testing from a remote location, outside the steel containment. A personnel access manhole with double, testable seals is provided in the drywell head. Figure 3.8-2 shows details of the drywell head assembly. 3.8.2.1.3 Drywell Equipment Hatches and Personnel Air Lock Two 12-foot inside diameter equipment hatches in the drywell, at elevation 107 feet, permit the transfer of equipment and components. One hatch, at azimuth 135, consists of a hatch barrel and a bolted cover with double, testable seals. The other hatch, at azimuth 315, with similar seals, is furnished with a personnel air lock welded to the removable cover. The personnel air lock is an 8-foot 10-1/2-inch inside diameter cylindrical pressure vessel with inner and outer bulkheads. Interlocked doors, 3-feet 9-inches wide by 7-feet 1-inch high, with double, testable compression seals are 3.8-3 HCGS-UFSAR Revision 0 April 11, 1988

furnished in each bulkhead. The doors are mechanically interlocked to ensure that at least one door is locked to maintain the primary containment integrity. Figures 3.8-3 and 3.8-4 show details of the equipment hatch and the equipment hatch with personnel air lock, respectively. 3.8.2.1.4 Control Rod Drive Removal Hatch One 3-foot inside diameter control rod drive (CRD) removal hatch at Elevation 103 feet 6 inches in the drywell permits transfer of the CRD assemblies. The hatch is furnished with double, testable seals and a bolted cover. Figure 3.8-5 shows details of the CRD removal hatch. 3.8.2.1.5 Drywell Penetrations Two general types of process pipe penetrations are provided: those that must accommodate thermal movement as shown by type A on Figure 3.8-6, and those that experience insignificant thermal stress as shown by types B and C on Figure 3.8-6. The bellows used in Type A triple flued head containment penetrations are designed, fabricated, tested, and examined in accordance with the requirements for Class 2 components of ASME B&PV Section III Code. Non-NSSS: The list of non-NSSS systems and their penetration identification numbers that use a Type A triple flued head are shown in Table 3.8-20. The design considerations for Nuclear Class 1 flued heads consist of evaluation of the loads transmitted to the flued head by the piping from both sides due to: 3.8-4 HCGS-UFSAR Revision 0 April 11, 1988

1. Thermal expansion

2. Seismic reactions

3. Dead weight loads

4. Internal pressure

5. Dynamic loads

6. Thermal gradient effects through the flued head body

7. Thermal transient effects as a result of temperature and pressure changes in the system

8. Discontinuity effects resulting from dissimilar metal welds, if any

9. Fatigue analysis using cumulative usage approach (NB-3653.5 of Section III).

Nuclear Class 2 flued heads are evaluated to the loads listed above with the exception of items 6., 7., and 9. The type A triple flued head containment penetrations are anchored to the building steel as shown in revised Figure 3.8-6. In the connecting piping analyses, the flued head is considered a rigid anchor. Piping reaction loads (forces, bending moments and torsion) are evaluated as stated above. Fatigue is considered per item(9) above and includes evaluation of the flued head and the butt weld between the flued head and the process pipe. NSSS: The main steam piping and the head fittings are designed and fabricated to the requirements of the 1971 edition of Section III of the ASME B&PV Code with addenda through and including those of 3.8-5 HCGS-UFSAR Revision 0 April 11, 1988

Summer 1972. The main steam head fittings are analyzed to the requirements of NB-3200 of the 1977 editions of Section III of the ASME B&PV Code and are evaluated to more restrictive stress limits of BTP MEB 3-1 in SRP 3.6.2. The design report for main steam head fittings includes the evaluation of fatigue and the effect of pipe rupture loads. The head fitting is modeled as a pipe element with rigid stiffness, and its effect on the main steam piping is evaluated to the requirements of NB-3600 of Section III of the ASME B&PV Code. A typical instrumentation penetration, a typical electrical penetration, and a typical traversing in-core probe (TIP) penetration are shown on Figures 3.8-7, 3.8-8, and 3.8-9, respectively. The maximum allowable temperature of the drywell shield wall concrete in the areas around the drywell penetrations is 200F. 3.8.2.1.6 Suppression Chamber The suppression chamber consists of 16 mitered cylindrical shell segments joined together to form a torus shaped pressure vessel located below and encircling the drywell, as shown on Figure 3.8-10. The suppression chamber has a major diameter of 112 feet 8 inches, a minor or chamber diameter of 30 feet 8 inches, and contains water to an approximate depth of 14 feet. Vertical sections of the suppression chamber are shown on Figures 3.8-11 and 3.8-12. The 1-inch thick suppression chamber shell is reinforced by full 360 ring beams located 3-1/2 inches from each mitered joint and by partial ring beams at each midcylinder location, which extend a short distance beyond the suppression chamber equator, as shown on Figure 3.8-11. The ring beams provide stiffening for the suppression chamber shell and also allow for transfer of shell pressure loads and support reactions from the vent system, piping, spray header, and monorail and catwalk to the suppression chamber support columns. 3.8-6 HCGS-UFSAR Revision 17 June 23, 2009

The suppression chamber is supported on columns symmetrically arranged in two concentric rings. These columns consist of 2-1/4-inch thick flange plates connected by a 1-inch thick web. The columns are pinned to the base plate assembly at the bottom and to the column connection assembly at the top (Figure 3.8-11), thus carrying only axial loads. Horizontal loads on the suppression chamber are transferred into the drywell foundation pedestal by a horizontal restraint system. The horizontal restraint has pinned connections and slotted holes to allow for thermal expansion of the suppression chamber. Details of the suppression chamber columns and horizontal restraint system are shown on Figures 3.8-11 through 3.8-13. Attachments to the suppression chamber include vent system supports; penetrations; access hatches; supports for the spray header, monorail and catwalk; pipe supports; and weld pads. 3.8.2.1.7 Suppression Chamber Access Hatches Four 4-foot inside diameter access hatches in the suppression chamber permit personnel access and the transfer of equipment and components. Each hatch is furnished with double, testable seals. See Figure 3.8-14 for details of the suppression chamber access hatches. 3.8.2.1.8 Vent System The drywell and the suppression chamber are connected by eight equally spaced vent pipes, each with an internal diameter of 6 feet 2 inches. These vent pipes are connected to a common mitered header within the suppression chamber with a major diameter of 112 feet 8 inches and a minor diameter of 4 feet 3 inches. Connected to the header are 80 downcomers that terminate at Elevation 68 feet 0-1/2 inch, below the normal water level of the suppression pool at Elevation 71 feet 2-1/2 inches. The downcomers have a 2-foot nominal diameter. At the drywell end, the vent line 3.8-7 HCGS-UFSAR Revision 0 April 11, 1988

openings are protected by jet deflectors to prevent damage to the vent system from postulated jet impingement loadings originating in the drywell. A vacuum breaker assembly is located at the suppression chamber end of each vent line to limit differential pressure between the drywell and suppression chamber. The vent lines are provided with two-ply testable expansion bellows assemblies at the suppression chamber penetrations to accommodate differential movement between the drywell and suppression chamber. The vent system is supported in the suppression chamber by columns, an upper truss, and a downcomer bracing system. The columns transfer vent system loads into the suppression chamber ring girders. The upper truss connects the vent line and vent header to the ring girder above. Details of the vent system components and supports are shown on Figures 3.8-15 through 3.8-17. 3.8.2.2 Applicable Codes, Standards, and Specifications The codes, standards, and specifications used in the design and construction of the primary containment are listed in Table 3.8-1. Structural specifications are prepared to cover the areas related to design and construction of the primary containment. These specifications emphasize important points of industry standards for design and construction of the primary containment and reduce options that otherwise would be permitted by the industry standards. The following areas are covered in the specifications:

1. Design loads, loading combinations, and allowable stresses for the drywell, suppression chamber, vent system, penetrations, and accessories

2. Materials for primary containment components 3.8-8 HCGS-UFSAR Revision 0 April 11, 1988

3. Fabrication methods, including welding requirements

4. Nondestructive examination requirements

5. Test requirements.

Section 1.8 provides references to regulatory guides discussed in the FSAR. Regulatory Guides specific to this section are discussed in Sections 3.8.2.4 and 3.8.2.5. 3.8.2.3 Loads and Loading Combinations Table 3.8-2 lists the loading combinations used for the design and analysis of the primary containment. 3.8.2.3.1 Dead Load The dead load includes the weight of the primary containment structure and appurtenances plus any other permanent loads, such as concrete and hydrostatic loads. 3.8.2.3.2 Live Load The live load includes the weight superimposed by the use and occupancy of the steel containment, such as moveable equipment and monorail and personnel loading. 3.8.2.3.3 Design Basis Accident Pressure Load Transients resulting from the design basis accident (DBA) and other lesser accidents are presented in Section 6.2.1, and serve as the basis for the primary containment internal design pressure of 62 psig. 3.8-9 HCGS-UFSAR Revision 0 April 11, 1988

3.8.2.3.4 Thermal Loads The operating and postulated DBA temperatures inside the primary containment used for the structural analysis are as follows: Temperature (F) Condition Drywell Suppression Chamber Operating 130 to 150 50 to 150 Design Basis Accident 340 310 3.8.2.3.5 Earthquake Loads Earthquake loads are in accordance with those discussed in Section 3.7. 3.8.2.3.6 Wind and Tornado Loads Wind and tornado loads are not considered during plant operation, because the primary containment is enclosed by the Reactor Building. 3.8.2.3.7 External Pressure Loading An external to internal differential pressure of 3 psi, as described in Section 6.2.1, is considered in the design of the primary containment. 3.8.2.3.8 Pipe Rupture Loads The drywell and appurtenances are designed for local pipe rupture effects. Section 3.6 contains a detailed discussion of postulated pipe ruptures and their effects. 3.8-10 HCGS-UFSAR Revision 0 April 11, 1988

3.8.2.3.9 Pool Swell and Main Steam Relief Valve Discharge Loads The suppression chamber and vent system are designed for pool swell loads resulting from a loss-of-coolant accident (LOCA) and for safety/relief valve discharge loads. 3.8.2.3.10 Post-Accident Containment Flooding During the period after a LOCA, the entire primary containment, including the suppression chamber, vent system, and drywell, may be flooded up to Elevation 201 feet. This condition is considered in the primary containment design. 3.8.2.3.11 Test Pressure Load Upon completion of erection, the primary containment vessel, penetrations, and appurtenances undergo an overpressure test at 71.5 psig, followed by a leak rate test at 62 psig. 3.8.2.4 Design and Analysis Procedures This section describes the procedures used by the primary containment manufacturer and engineer, Pittsburgh-Des Moines Corporation (PDM), and its subcontractor, NUTECH Engineers Incorporated, for the design and analysis of the primary containment. All computer programs referenced are described in Appendix 3A. The ASME B&PV Code Class MC components and Class MC component supports, described in Section 3.8.2.1, are designed and analyzed in accordance with Article NE-3000 of Subsection NE and Article NF-3000 of Subsection NF, respectively, of the ASME B&PV Code, Section III, Division 1, and as augmented by the applicable provisions of Regulatory Guide 1.57. 3.8-11 HCGS-UFSAR Revision 0 April 11, 1988

3.8.2.4.1 Drywell The BOSOR4 computer program is used to analyze the drywell shell. The BOSOR4 mathematical model is shown on Figure 3.8-18. The ASME B&PV Code provides compressive stress requirements for spherical shells subjected to external pressure loads. It does not, however, address specific requirements for compressive stresses in spherical shells that are produced from loads other than external pressure. Therefore, the following procedure is used to demonstrate the adequacy of the drywell shell when subjected to compressive loads:

1. The critical buckling pressure for the drywell spherical shell is determined for buckling of a thin shell sphere under uniform external pressure and is then used to compute a critical buckling stress in the shell.

2. The ASME B&PV Code allowable compressive stress for the drywell shell under external pressure is determined.

3. The factor of safety, which includes an allowance for shell imperfections, against drywell shell buckling under external pressure is established by dividing the critical buckling stress by the ASME B&PV Code allowable compressive stress.

4. The critical buckling stress for the drywell shell, when subjected to external pressure and other compressive loads, is determined from a BOSOR4 analysis.

5. The factor of safety obtained in 3. above is applied to the critical buckling stress determined in 4. above to obtain the theoretical allowable compressive stress for the drywell shell when subjected to a particular loading combination.

3.8-12 HCGS-UFSAR Revision 0 April 11, 1988

The procedure above meets the intent of Regulatory Guide 1.57, since the method maintains a factor of safety that includes an allowance for shell imperfections as established by the ASME B&PV Code for the external pressure loads. For additional information on the drywell buckling analysis see Appendix 3E. All computed shell stresses are within the allowable values developed by applying ASME B&PV Code safety factors to the computed critical buckling stresses. The drywell shell is analyzed for internal pressure using the BOSOR4 computer program. The analysis includes the local effects of jet impingement using localized finite element models of the drywell shell. The air space between the outside surface of the drywell shell and the adjacent concrete drywell shield wall is modeled with gap elements. An incremental analysis procedure is used where the total load is applied in small steps until the gap is closed. The results show that all stresses are within their respective allowable values. 3.8.2.4.2 Drywell Head Assembly Stresses in the drywell head are determined for dead load, seismic load, and internal and external pressure using linear elastic theory for thin shells. Stresses in the shell resulting from jet impingement are computed using Welding Research Council Bulletin 107, Reference 3.8-1. Resulting stresses are combined and compared with ASME B&PV Code allowable values for specified loading combinations. The shell is analyzed for external pressure using the ASME B&PV Code, Section III, Paragraph NE-3133. A BOSOR4 model of the drywell head and flange area is used to examine the flanges and bolts under jet impingement load in combination with the internal pressure. 3.8-13 HCGS-UFSAR Revision 0 April 11, 1988

3.8.2.4.3 Drywell Equipment Hatches and Personnel Air Lock 3.8.2.4.3.1 Equipment Hatch The equipment hatch is designed and analyzed in accordance with Section III, Subsection NE of the ASME B&PV Code. The cover plate is modeled as a simply supported circular flat plate and analyzed inelastically by means of yield line theory for jet impingement loads. The hatch barrel and shell junction are analyzed using the computer program BOSOR4. The stress intensities computed are compared with the ASME B&PV Code allowable values. 3.8.2.4.3.2 Drywell Equipment Hatch and Personnel Air Lock The equipment hatch and personnel air lock are designed in accordance with the ASME B&PV Code, Section III, Subsection NE. Reinforcement requirements for the opening in the drywell shell for the hatch barrel is determined by area replacement in accordance with the ASME B&PV Code, Section III, Paragraph NE-3332. Stresses resulting from external forces were computed manually in accordance with Welding Research Council Bulletin 107, Reference 3.8-1. The stress analysis of the hatch cover plate and air lock barrel is accomplished using the computer program ANSYS. 3.8.2.4.4 Drywell and Suppression Chamber Penetrations Design and analysis requirements of the drywell and suppression chamber penetrations include the following:

1. Ensure that reinforcing around the penetration complies with area replacement requirements of the ASME B&PV Code, Section III, Subarticle NE-3330.

2. Calculate stresses and stress intensities in the penetration nozzle for specified loading combinations. The calculated stress intensities are compared to ASME B&PV Code allowable values.

3.8-14 HCGS-UFSAR Revision 0 April 11, 1988

3. Calculate stresses in the nozzles to insert plate weld for specified loading combinations. These stresses are compared to ASME B&PV Code allowable values. The weld is also checked to ensure that it meets the ASME B&PV Code minimum weld size requirements.

4. Determine stresses in the insert plate at the nozzle to insert plate junction for specified loading combinations, by the method described in Reference 3.8-1. Calculated stresses are compared to ASME B&PV Code allowable values.

5. Determine stresses in the vessel shell at the insert plate to shell junction for specified loading combinations, by the method described in Reference 3.8-1. Calculated stresses are compared to ASME B&PV Code allowable values.

3.8.2.4.5 Suppression Chamber The seismic analysis of the suppression chamber by the response spectra method uses a 360 finite element beam model, as shown on Figure 3.8-19. The suppression chamber stress analysis uses a typical 1/32 segment, finite element beam and shell model, as shown on Figure 3.8-20, and the STARDYNE computer program. The suppression chamber horizontal restraint system is analyzed using a finite element model of a 1/32 segment of the torus to compute shell and ring beam stresses, and manual calculations to compute stresses in other parts of the support system. Stress intensities are calculated for specified loading combinations and compared to ASME B&PV Code allowable values, and found to be acceptable. 3.8-15 HCGS-UFSAR Revision 0 April 11, 1988

3.8.2.4.6 Vent System A finite element beam and shell model of a 1/16 segment of the vent system and suppression chamber, as shown on Figure 3.8-21, is used to compute the response of the vent system for all loads except seismic and certain downcomer lateral loads. A 360 beam model, as shown on Figure 3.8-22, is used to compute the response of the vent system for seismic and certain downcomer lateral loads. Finite element models shown on Figures 3.8-23 and 3.8-24 are used to determine stresses at the vent line vent header and vent header downcomer intersections. The resultant stress intensities are compared with ASME B&PV Code allowable values. 3.8.2.4.7 Plant-Unique Analysis A corroborative analysis is performed for the suppression chamber and vent system for applicable load combinations, including hydrodynamic loads resulting from main steam relief valve discharge and LOCA phenomena, in accordance with the GE Mark I Containment Load Definition Report, Reference 3.8-2; the Hope Creek Plant Unique Load Definition Report, Reference 3.8-3; and appropriate GE Mark I Containment Program Application Guides. Appendix 3B includes a summary description of the confirmatory analysis methods used for stress assessment and identifies modifications to the suppression chamber and vent system. 3.8.2.4.8 Ultimate Capacity of Steel Containment An analysis was performed to determine the ultimate capacity of the containment. The results of this analysis are summarized in Appendix 3I. 3.8.2.5 Structural Acceptance Criteria Structural acceptance criteria for the ASME B&PV Code Class MC components and Class MC component supports, which form the bases for establishing allowable stress values, deformation limits, and 3.8-16 HCGS-UFSAR Revision 0 April 11, 1988

factors of safety, are established by Section III, Subsection NE and Subsection NF, respectively, of the ASME B&PV Code, as augmented by the requirements of Regulatory Guide 1.57. The allowable stress criteria for ASME B&PV Code Class MC components and Class MC component supports are listed in Tables 3.8-2 and 3.8-3 for various loading conditions. 3.8.2.6 Materials, Quality Control, and Special Construction Techniques 3.8.2.6.1 Materials All materials for Class MC components and component supports meet the requirements of Subsections NE and NF, as applicable, of Section III of the ASME B&PV Code. The primary containment components, other than stainless steel items, have been painted to protect against corrosion. 3.8.2.6.1.1 Drywell Shell Materials used in construction of the drywell shell assembly include the following: Item ASME Specification Drywell shell SA-516, Grade 70 Beam seats pad plate and stiffeners SA-516, Grade 70 3.8.2.6.1.2 Drywell Head Materials used in construction of the drywell head assembly include the following: 3.8-17 HCGS-UFSAR Revision 0 April 11, 1988

Item ASME Specification Drywell head and lower flange SA-516, Grade 70 Bolts SA-320, Grade L43 Nuts SA-194, Grade 7 3.8.2.6.1.3 Drywell Support Skirts Materials used in construction of the drywell support skirts include the following: Item ASME Specification Inner and outer skirts SA-516, Grade 70 Base plates SA-516, Grade 70 Anchor bolts SA-354, Grade BC 3.8.2.6.1.4 Drywell Access Hatches Materials used in construction of the drywell access hatches include the following: Item ASME Specification Sleeve and cover SA-516, Grade 70 Bolts SA-320, Grade L43 or SA-193, Grade B7 Item ASME Specification Nuts SA-194, Grade 7 3.8-18 HCGS-UFSAR Revision 0 April 11, 1988

3.8.2.6.1.5 Penetrations Materials used in construction of piping and electrical penetrations include the following: Item ASME Specification Insert plates SA-516, Grade 70 Nozzles SA-516, Grade 70 SA-155, Grade KCF 70 SA-333, Grade 6 SA-333, Grade 1 SA-312, Type 304L 3.8.2.6.1.6 Suppression Chamber Materials used in construction of the suppression chamber and its supports include the following: Item ASME Specification Shell, ring beams, and ring beam SA-516, Grade 70 stiffeners Support columns SA-537, Class 2 Base plates SA-537, Class 2 Bolting material SA-540, Grade B21, Class 1 Pins SA-540, Grade B21, Class 5 Horizontal restraint system: Struts SA-36 Connecting plates SA-537, Class 2 Bolting material FA-540, Grade B21, Class 1 3.8-19 HCGS-UFSAR Revision 0 April 11, 1988

3.8.2.6.1.7 Vent System Materials used in construction of the vent system include the following: Item ASME Specification Vent line SA-516, Grade 70 Vent header SA-516, Grade 70 Downcomers SA-516, Grade 70 Bellows ring SA-240, Type 304L 3.8.2.6.2 Welding Welding conforms to the requirements of the ASME B&PV Code, Section III, Subsections NE and NF, as applicable. All butt seam welds in the shell of the primary containment vessel are full penetration, double bevel welds. All welders and weld procedures are qualified in accordance with Section IX of the ASME B&PV Code. Post-weld heat treatment for pressure-retaining components is in accordance with the ASME B&PV Code, Section III, Subsection NE and NF, as applicable. 3.8.2.6.3 Materials Testing The pressure retaining parts and attachments to the pressure retaining parts of the primary containment vessel are impact tested, in accordance with the applicable Subsections of the ASME B&PV Code, Section III. The impact specimens were tested at +5F or below. 3.8-20 HCGS-UFSAR Revision 0 April 11, 1988

3.8.2.6.4 Nondestructive Examination of Welds Nondestructive examination of all pressure retaining welds is in accordance with the ASME B&PV Code, Section III, Subsections NE and NF, as applicable. 3.8.2.6.5 Quality Control The quality assurance provisions of the applicable parts of Articles in Sections NA-4000, NE-4000, NE-5000, NF-4000, and NF-5000 of Section III of the ASME B&PV Code, including Code Case N-242, were followed in all phases of design, procurement, shop fabrication, and field installation of the primary containment. 3.8.2.6.6 Erection Tolerances Erection tolerances for the primary containment vessel meet the requirements of Section III of the ASME B&PV Code. In addition, the specified erection tolerances include the following:

1. The top head flange is within 2 inches of the design elevation and is level within 1/2 inch.

2. Penetrations are within 1/2 inch of their specified elevation and azimuth at their intersection with the vessel.

3. Alignment of penetrations are within 1/2 degree of the design alignment.

Actual deviations from the above are evaluated in accordance with procedures covered in Section 3.8.2.6.5. 3.8.2.6.7 Corrosion The thickness of pressure boundary elements and other critical components of the primary containment has been increased beyond 3.8-21 HCGS-UFSAR Revision 0 April 11, 1988

minimum design thickness to include a corrosion allowance as follows:

1. Drywell shell: 1/16 inch

2. Suppression chamber shell and ring girders: 1/8 inch

3. Vent lines and vent header: 1/16 inch

4. Downcomers: 1/8 inch

5. Vent header and downcomer supports: 1/8 inch

6. Pipe supports and related items: 1/8 inch for submerged items and 1/16 inch for portions above water.

3.8.2.6.8 Special Construction Techniques Erection of the primary containment was performed by PDM using methods, tools, and equipment generally accepted in the industry. 3.8.2.7 Testing and Inservice Surveillance 3.8.2.7.1 Preoperational Testing 3.8.2.7.1.1 Structural Acceptance Test The primary containment is pneumatically tested to 1.15 times the design pressure during the containment overpressure test, in accordance with Article NE-6000 of Subsection NE, Section III of the ASME B&PV Code. The personnel air lock is pneumatically tested to 1.15 times the design pressure, following shop fabrication and field erection, to verify its structural integrity. 3.8-22 HCGS-UFSAR Revision 0 April 11, 1988

3.8.2.7.1.2 Leak Rate Testing The leaktight status of the primary containment is verified during the integrated leak rate test performed in accordance with 10CFR50, Appendix J, Option B. See Section 6.2.6 for a description of the primary containment integrated leak rate test. 3.8.2.7.2 Inservice Leak Rate Testing Inservice leak rate testing is discussed in Section 6.2.6. 3.8.2.8 SRP Rule Review 3.8.2.8.1 Deleted 3.8.2.8.2 Acceptance Criterion II.4(f) Acceptance Criteria II.4(f) of SRP Section 3.8.2 and the relevant acceptance criteria of SRP Sections 3.8.3, 3.8.4 and 3.8.5 require that a design report be prepared and is considered acceptable if it contains the information specified in Appendix C of SRP Section 3.8.4 Sufficient information is provided in the HCGS FSAR to outline the structural design of the Seismic Category I structures. This information includes such items as structural description and geometry, load combinations, materials used, applicable codes and standards, and computer codes, as required by Regulatory Guide 1.70, Revision 3. As required by 10CFR50 Appendix B, information is also available to enable an audit of these Seismic Category I structures to inspect and verify their structural integrity. The information available for such an audit is consistent with the information requested in Appendix C to SRP 3.8.4. 3.8-23 HCGS-UFSAR Revision 9 June 13, 1998

3.8.2.8.3 Acceptance Criterion II.5 Acceptance Criterion II.5 of SRP Section 3.8.2 refers to Table 3.8.2-1 of the SRP for allowable stresses for the loading combinations given in SRP Section 3.8.2.II.3(b). The design requirements for HCGS deviate from the SRP requirements for two loading combinations: testing, and post-accident containment flooding. For these two loading conditions, the specified allowable stress for HCGS is higher than that specified in Table 3.8.2-1 of the SRP. However, the calculated stresses for the Class MC components are less than the SRP stress limits for these two loading conditions. 3.8.3 Primary Containment Internal Structures 3.8.3.1 Description of the Internal Structures The functions of the primary containment internal structures include support and shielding of the reactor pressure vessel (RPV) and support of piping and equipment. The primary containment internal structures are constructed of concrete and structural steel and include the following:

1. RPV pedestal

2. Biological shield

3. Platforms and pipe restraints

4. Biological shield lateral truss and RPV stabilizer.

Figure 3.8-1 shows the general arrangement of the primary containment, including the internal structures. 3.8-24 HCGS-UFSAR Revision 0 April 11, 1988

3.8.3.1.1 Reactor Pressure Vessel Pedestal The RPV pedestal, approximately 26-feet high, is a vertical, cylindrical, reinforced concrete structure that rests on the drywell floor/pedestal mat and supports the RPV, biological shield, drywell platforms, and pipe restraints. The RPV pedestal has an outside diameter of 29 feet 11 inches and a wall thickness of 4 feet 10 inches. The thickness at the top of the pedestal increases to 5 feet 9 inches, where it supports both the RPV and the biological shield. Figure 3.8-25 shows the connection of the RPV pedestal to the base foundation. The biological shield is supported on the RPV pedestal, as described in Section 3.8.3.1.2. The RPV is supported on the pedestal through a ring girder, as described in Section 5.3.3.1. The ring girder is attached to the RPV pedestal by 120, 3-1/4-inch diameter high strength anchor bolts, as shown on Figure 3.8-26. Figures 3.8-27 and 3.8-28 show reinforcement details for the RPV pedestal. Openings are provided to allow access for personnel, piping, and equipment into the pedestal cavity, with additional reinforcement furnished at the openings. Embedded transfer girders are provided to transfer loads around the CRD penetrations. A carbon steel liner plate on the inside of the RPV pedestal acts as a concrete form during construction. 3.8.3.1.2 Biological Shield The biological shield is a 49-foot high, vertical, cylindrical shell that provides primary radiation shielding, as well as support for pipe restraints and drywell platforms. It is designed as a composite steel-concrete structure and is constructed of carbon steel inner and outer plates with concrete and shear ties between the two plates. 3.8-25 HCGS-UFSAR Revision 0 April 11, 1988

The biological shield has an inside diameter of 26 feet 5 inches and a wall thickness of 1 foot 9 inches, as shown on Figure 3.8-29. The outer steel plate is 1-1/2 inches thick, and the inner steel plate is 3/4-inch thick. These inner and outer plates are connected with shear ties spaced on approximately 4-degree centers in the circumferential direction and 12-inch centers in the vertical direction to provide adequate shear transfer. Internal stiffeners are provided to withstand local loads transferred through pipe restraints and drywell platform attachments. The annular space between the inner and outer plates is filled with concrete. The upper section, above Elevation 125 feet 5-1/2 inches, contains high density concrete for radiation shielding in the reactor core area. The biological shield is connected to the top of the RPV pedestal by 60, 3-1/4-inch diameter, high strength anchor bolts embedded in the pedestal, as shown on Figure 3.8-26. The biological shield lateral truss and RPV stabilizer, which provide lateral support to the biological shield and RPV, are attached to the top of the biological shield. The biological shield has penetrations with hinged doors or removable plugs to accommodate piping connections to the RPV, and also to provide access for inservice inspection. All doors are bolted to penetration sleeves, and the inner section of certain doors are filled with boron concrete where required for radiation shielding. 3.8.3.1.3 Platforms and Pipe Whip Restraints Two major platforms are furnished in the drywell to provide access and support to piping and equipment. The platforms consist of structural steel framing with steel grating. Built up box shapes are used for beams that must resist significant biaxial loading. Beams that span between the RPV pedestal or the biological shield and the drywell shell are provided with sliding connections at the drywell shell. Thus, no significant thermal axial loads are developed in the beams, and no significant thermal radial loads are imposed on the pedestal, biological shield, or primary containment 3.8-26 HCGS-UFSAR Revision 0 April 11, 1988

shell. Figures 3.8-31 and 3.8-32 show details of the drywell platforms. Pipe whip restraints are provided inside the drywell to prevent pipe whip due to a high energy pipe break. The restraints are of two different designs: a U-strap design, and a frame type design. Typical restraints inside the drywell are shown on Figure 3.6-1. 3.8.3.1.4 Biological Shield Lateral Truss and RPV Stabilizer The lateral truss and the RPV stabilizer provide lateral support for the biological shield and the RPV during seismic and pipe break loading. The lateral truss spans horizontally between the primary containment and the biological shield. It is shaped like an eight-point star and is fabricated from steel plate and pipe sections. Figure 3.8-33 shows details of the lateral truss. The truss transfers lateral forces from the RPV and the biological shield through the drywell shell to the concrete drywell shield wall by eight shear lugs attached to the drywell shell. The shear lugs are designed to permit vertical and radial thermal expansion of the drywell shell. The RPV stabilizer spans horizontally between the biological shield and the RPV. 3.8.3.2 Applicable Codes, Standards, and Specifications The codes, standards, and specifications used in the design and construction of the primary containment internal structures are listed in Table 3.8-7. Specifications were prepared specifically to cover the areas related to design and construction of the primary containment internal structures. These specifications supplement the industry standards for the primary containment internal structures, and reduce options that would otherwise be permitted by the industry standards. They cover the following major areas: 3.8-27 HCGS-UFSAR Revision 0 April 11, 1988

1. Furnishing and delivering concrete,

2. Forming, placing, finishing, and curing concrete,

3. Furnishing, detailing, fabricating, delivering, and placing reinforcing steel,

4. Splicing reinforcing steel,

5. Furnishing, detailing, fabricating, delivering, and erecting structural steel,

6. Coating of steel and concrete surfaces.

Section 1.8 provides references to Regulatory Guides discussed in the FSAR. 3.8.3.3 Loads and Loading Combinations Tables 3.8-4 through 3.8-6 list the load combinations used for the design and analysis of the primary containment internal structures. 3.8.3.3.1 RPV Pedestal Table 3.8-4 lists the load combinations used for the design of the RPV pedestal. Descriptions of the loads are as follows:

1. Dead load, live load, and seismic loads - For a description of dead load, live load, and seismic loads, see Section 3.8.2.3.

2. Thermal loads - The RPV pedestal is designed for the temperature gradient resulting from the postulated design accident condition.

3. Pipe break loads - The RPV pedestal is designed to withstand pipe break loads due to a postulated break of 3.8-28 HCGS-UFSAR Revision 0 April 11, 1988

any high energy pipe, including a 28-inch diameter recirculation loop pipe. The analysis considers the effects of jet impingement, pipe whip, and pipe reaction. An equivalent static load of 1860 kips is considered, which includes an appropriate dynamic load factor to account for the dynamic nature of the load. Section 3.6 contains a detailed discussion of postulated pipe breaks and their effects.

4. Additional loads - For conservatism, a subcompartment pressurization is postulated due to a nonmechanistic break inside the bioshield. This loading is resisted by the pedestal. For additional information, see Appendix 6B.1.2.

3.8.3.3.2 Biological Shield Tables 3.8-4 and 3.8-5 list the load combinations used for the design of the biological shield. The most severe loading condition combines the DBA loads with the maximum seismic loads. Descriptions of the loads are as follows:

1. Dead load, live load, and seismic loads - For a description of dead load, live load, and seismic loads, see Section 3.8.2.3.

2. Abnormal pressure load - The biological shield is designed for internal pressurization due to a postulated break of any high energy pipe, including a 28-inch diameter recirculation loop pipe. The following two pressure conditions are considered:

a. Maximum unbalanced pressure, which is a pressure condition occurring shortly after pipe break that produces a net lateral load on the biological shield.

3.8-29 HCGS-UFSAR Revision 0 April 11, 1988

b. Maximum uniform pressure, which is a pressure condition after pipe break that produces a uniform 150 psig internal pressure.

3. Thermal loads - The biological shield is designed for the temperature gradient resulting from the postulated design accident condition.

4. Pipe break loads - The biological shield is designed to withstand the pipe break effects due to a postulated break of any high energy pipe. The analysis considers the effects of jet impingement, pipe whip, and pipe reaction. Equivalent static loads are considered, including an appropriate dynamic load factor to account for the dynamic nature of the load. Section 3.6 contains a detailed discussion of postulated pipe breaks and their effects.

5. Additional loads - For conservatism, a subcompartment pressurization is postulated due to a nonmechanistic break inside the bioshield. This loading is resisted by the pedestal. For additional information, see Appendix 6.B.1.2.

3.8.3.3.3 Platforms and Pipe Whip Restraints The drywell platforms are designed using the AISC working stress design methods, except for pipe whip restraints supported by the platforms. The pipe whip restraints are designed to undergo local inelastic deformations due to postulated pipe break loads. The inelastic deformations do not cause loss of function of the pipe whip restraints. The built-up beams that support the pipe whip restraints are designed to withstand all postulated pipe break loads. Design accident pressure, operating and design accident thermal, and seismic loads have been considered in the design of the drywell platforms. The uniform design live load for the grating and framing 3.8-30 HCGS-UFSAR Revision 0 April 11, 1988

2 beam is 200 lb/ft . The design load for the framing beams also includes the gravity load, thermal reaction load, and seismic reaction load of all piping and equipment supported on the beams. Table 3.8-5 lists the load combinations used to design the drywell platforms and pipe whip restraints. 3.8.3.3.4 Biological Shield Lateral Truss The lateral truss is designed using the AISC working stress design methods. It is designed for lateral loads, including seismic and postulated pipe break effects. Design accident pressure, and operating and design accident thermal loads have been considered in the design of the lateral truss. Table 3.8-5 lists the load combinations used to design the lateral truss. 3.8.3.4 Design and Analysis Procedures This section describes the procedures used for the design and analysis of the primary containment internal structures. All computer programs referenced are described in Appendix 3A. 3.8.3.4.1 RPV Pedestal The RPV pedestal is designed for axisymmetric loads, which include dead load and design accident temperature load, using the FINEL computer program. Both concrete and reinforcing steel materials are included in the model. The operating and design accident temperature gradients are computed. For transient loads, such as design accident pressure and thermal loads, the most critical combination of these loads is considered. The RPV pedestal is also designed for nonaxisymmetric loads, which include seismic loads, design accident pressure and pipe break loads, and RPV and biological shield loads, using the STRUDL and ASHSD computer programs. 3.8-31 HCGS-UFSAR Revision 0 April 11, 1988

Figure 3.8-34 shows a vertical section through the finite-element model used to analyze the RPV pedestal. The model includes the RPV pedestal, the foundation anchorage, and the biological shield. Concrete and reinforcing steel stresses, due to axisymmetric and nonaxisymmetric loads, are combined where applicable to determine the total stress and are compared with allowable values. 3.8.3.4.2 Biological Shield The biological shield is analyzed as an axisymmetric structure. The FINEL computer program is used in analysis of axisymmetric loads, which include dead load, design accident thermal load, and design accident uniform pressure load. The temperature gradient across the thickness of the wall is computed. For nonaxisymmetric loads, which include design accident unbalanced pressure load, seismic load, and pipe break load, the ASHSD computer program is used. Figure 3.8-34 shows a vertical section through the finite element model used to analyze the biological shield. Total stresses in the biological shield are determined by summing the stresses resulting from axisymmetric and nonaxisymmetric loads and are compared with allowable values. Openings in the biological shield are analyzed locally to determine reinforcement requirements using the ASME B&PV Code area replacement method. Local stiffening of the shell is provided by thick walled penetration sleeves and reinforcing rings. 3.8.3.4.3 Platforms and Pipe Whip Restraints The drywell platforms are designed using conventional elastic design methods, in accordance with the AISC Specification, Part I. Members that are impacted as a result of postulated pipe break are designed using elasto-plastic methods to determine energy absorption capacity, as described in Bechtel Topical Report BN-TOP-2, Reference 3.8-4. 3.8-32 HCGS-UFSAR Revision 0 April 11, 1988

3.8.3.4.4 Biological Shield Lateral Truss Seismic forces in the lateral truss are calculated using the methods described in Section 3.7. Axial force, shear force, and moment in the lateral truss due to postulated pipe break are calculated using the STRUDL computer program. 3.8.3.4.5 Plant Unique Analysis A confirmatory analysis is performed for the suppression chamber and internal structures for all applicable loads, including hydrodynamic loads resulting from main steam relief valve discharge and loss-of-coolant accident (LOCA) phenomena, in accordance with NUREG 0661; NUREG 0763; the GE Mark I Containment Load Definition Report, Reference 3.8-2; the Hope Creek Plant-Unique Load Definition Report, Reference 3.8-3; and appropriate GE Mark I Containment Program Application Guides. Appendix 3B includes a summary description of the confirmatory analysis methods used for stress assessment and identifies potential modifications to the suppression chamber internal structures. 3.8.3.5 Structural Acceptance Criteria 3.8.3.5.1 Concrete The RPV pedestal and the biological shield are designed for the factored load combinations listed in Table 3.8-4, in accordance with the strength method in American Concrete Institute (ACI) 318. 3.8.3.5.2 Structural Steel Structural steel portions of the containment internal structures include the biological shield, platforms, pipe whip restraints, and lateral truss. For normal loading conditions, the allowable stresses are in accordance with the AISC Specification for the Design, Fabrication, and Erection of Structural Steel for Buildings. 3.8-33 HCGS-UFSAR Revision 0 April 11, 1988

For extreme environmental and abnormal loading conditions, the allowable stresses are given in Table 3.8-5. For members that are impacted as a result of postulated pipe break effects, energy absorption is determined and compared to the energy input in order to verify that energy absorption capacity exceeds energy input. 3.8.3.6 Materials, Quality Control, and Special Construction Techniques The criteria of ACI 349, Code Requirements for Nuclear Safety-Related Concrete Structures, applicable to this section are not used by HCGS. This section discusses the alternate criteria used. 3.8.3.6.1 Concrete Containment Internal Structures The concrete and reinforcing steel materials for the primary containment internal structures are discussed in Section 3.8.6. 3.8.3.6.2 Biological Shield and Biological Shield Lateral Truss 3.8.3.6.2.1 Materials Materials used in the construction of the biological shield and the lateral truss include the following standard specifications: Item Specification Biological shield outer plate ASTM A537, Class 1, electric furnace doubleslagged plus vacuum degassed in accordance with supplementary requirements S-1 of ASTM A20 3.8-34 HCGS-UFSAR Revision 0 April 11, 1988

Item Specification Biological shield inner plate ASTM A537, Class 1 Horizontal & vertical stiffener ASTM A537, Class 1 plate Bars for shear ties ASTM A321 Bolts for shear ties ASTM A490 Top plate and bottom plate ASTM A537, Class 1 Lateral truss pipe members ASTM A618 Biological shield anchor bolts ASTM A540, Class 3, Grade B23 Normal weight concrete See Section 3.8.6.2.4 High density concrete See Section 3.8.6.2.5. 3.8.3.6.2.2 Welding Procedure and Qualifications The biological shield is fabricated using welding procedures prepared and qualified in accordance with the requirements of the ASME B&PV Code, Section III, Subsection ND, Article ND-4000, and Section IX. Nondestructive examination of welds, including radiographic examination, ultrasonic examination, magnetic particle examination, and liquid penetrant examination, is in accordance with the ASME B&PV Code, Section III, Article ND-5000, and Section V. 3.8.3.6.2.3 Materials Testing The biological shield outer liner plate is ultrasonically tested in accordance with ASTM A-578-75, including supplemental requirements 5 through 8. 3.8-35 HCGS-UFSAR Revision 0 April 11, 1988

3.8.3.6.2.4 Tolerances The specified erection tolerances include the following:

1. Each of the two concentric cylinders of the biological shield is plumb within 1:500 of the height.

2. The radial dimension to any point on the biological shield plates does not vary by more than ~1/4-inch from the centerline established by the design.

3. The clear distance between the two steel biological shield inner and outer plates does not vary more than ~1/4-inch from the theoretical distance at any point.

4. The penetration sleeve centerlines are within ~1/4-inch of specified elevations and azimuths of the RPV nozzles.

5. The elevation of the top of the biological shield is within

             ~1/4 inch of that shown on the design drawings.

Actual deviations from the above are handled in accordance with procedures covered in Section 17. 3.8.3.6.3 Drywell Platforms 3.8.3.6.3.1 Materials Materials used in construction of the drywell platforms include the following standard specifications: Item Specification Structural shapes (less than ASTM A36 30 pounds per linear foot) 3.8-36 HCGS-UFSAR Revision 0 April 11, 1988

Item Specification Structural shapes (more than ASTM A441 or 30 pounds per linear foot) ASTM A588 Box beams and built-up wide ASTM A537, Class 1. flange beams 3.8.3.6.3.2 Welding The drywell platforms are fabricated using welding procedures in accordance with the American Welding Society (AWS) Structural Welding Code D1.1. (See Table 3.8-7). 3.8.3.6.3.3 Nondestructive Examination Nondestructive examination of welds for the drywell platforms, including radiographic examination, magnetic particle examination, ultrasonic examination, and liquid penetrant examination, is in accordance with Sections 6 and 8 of AWS D1.1. 3.8.3.6.3.4 Erection Tolerances Erection tolerances for the drywell platforms are in accordance with the AISC specification. Actual deviation from the specification is evaluated in accordance with procedures covered in Section 17. 3.8.3.6.4 Quality Control Quality control requirements during construction are discussed in Section 17. 3.8.3.7 Testing and Inservice Inspection Requirements The internal structures are not directly related to the functioning of the containment concept. Therefore, no testing or inspection is required. 3.8-37 HCGS-UFSAR Revision 0 April 11, 1988

3.8.4 Other Seismic Category I Structures This section discusses all Seismic Category I structures, except the primary containment and its internals, which are described in Sections 3.8.2 and 3.8.3. This section also describes certain related non-Seismic Category I structures that could affect safety-related systems, components, or structures. Specific structures included are:

1. Seismic Category I structures - Reactor Building; auxiliary Building, including control/diesel generator area and radwaste/service area; Station Service Water System (SSWS) intake structure; plant cancelled area, the former Unit 2 Reactor Building; and condensate storage tank dike.

2. Non-Seismic Category I structures - Turbine building; and administration facility, the former Unit 2 turbine building.

All of these structures and their physical interrelationships are shown on Figure 3.8-35. 3.8.4.1 Description of Structures 3.8.4.1.1 Reactor Building The Reactor Building, as shown on Plant Drawings P-0014-1 and P-0042-1 through P-0047-1, is a reinforced concrete enclosure that consists of a cylindrical containment structure topped by a toroid spherical dome, with a rectangular lower section enclosing the base of the cylinder. The cylindrical portion completely encloses both the reactor and the pressure suppression primary containment system. It also houses fuel storage and handling facilities and engineered safety features (ESFs). It is located in the southwest quadrant of the power 3.8-38 HCGS-UFSAR Revision 20 May 9, 2014

complex adjacent to the Auxiliary Building, which is to the north and east. The Reactor Building bearing/shear walls are designed to resist lateral loads and transmit them to the reinforced concrete foundation mat, where all loads are dissipated into the Vincentown Formation. The reinforced concrete floors are generally supported by structural steel framing systems that are in turn supported by the walls. Floor systems are designed to act as diaphragms that transmit lateral loads to the shear walls. Radial framing is used within the cylindrical portion, while framing in the rectangular area is laid out on east-west and north-south lines. At the north wall of the Reactor Building, where it interfaces with the auxiliary building control/standby diesel generator (SDG) area, a seismic separation joint extends from the foundation mat through the roof. The steel primary containment is isolated from the reinforced concrete drywell shield wall by an air gap. The refueling facility is located above the primary containment. This facility is supported by steel girders and by the reinforced concrete slabs and walls of the pools that span between the drywell shield wall and the cylindrical wall. Interior surfaces of walls and slabs of the spent fuel pool, cask loading pit, reactor well, and steam dryer and separator storage pool are lined with stainless steel plate. The entire refueling facility meets radiation shielding requirements, as discussed in Section 12.3.2. All reinforced concrete walls and floors meet both structural and radiation shielding requirements, as discussed in Section 12.3.2. There are no concrete masonry unit walls used in the reactor building. 3.8-39 HCGS-UFSAR Revision 16 May 15, 2008

The Reactor Building foundation mat, described in Section 3.8.5, extends eastward beyond the Reactor Building to support the southern section of the auxiliary building radwaste/service area. The 150 ton capacity polar crane, as described in Section 9.1.5, is supported by a continuous, circular corbel constructed integrally with the cylindrical wall. 3.8.4.1.2 Auxiliary Building Control/Standby Diesel Generator Area The control/SDG area, as shown on Plant Drawings P-0051-0 through P-0057-0, is located in the Auxiliary Building. The control area houses the controls for both the reactor and the balance of plant (BOP) elements that constitute HCGS. The SDG area houses systems that provide operating power for HCGS in case of loss of the primary power source. The control/SDG area is separated from the Reactor Building and the plant cancelled area by seismic separation joints, extending in the east-west direction from the bottom of the foundation mats through the roofs, at their respective interfaces. The area is bounded on the east by the radwaste/service area reinforced concrete isolation wall, and on the west by an exterior reinforced concrete wall. The area is separated into individual utility areas by interior reinforced concrete walls, the eastern areas of which constitute the control area and the western SDG area. The reinforced concrete foundation mat, described in Section 3.8.5, extends eastward beyond the control/SDG area to support the central section of the radwaste/service area. The control/SDG area is a structurally integrated reinforced concrete structure that has bearing/shear walls designed to resist lateral loads and transmit them to the foundation mat, where all loads are dissipated into the Vincentown Formation. The reinforced 3.8-40 HCGS-UFSAR Revision 20 May 9, 2014

concrete floors are supported by structural steel framing systems that are in turn supported by the walls and structural steel columns. All floor systems are designed to act as diaphragms that transmit lateral loads to the shear walls. All reinforced concrete walls and floors meet both structural and radiation shielding requirements, as discussed in Section 12.3.2. There are no concrete masonry unit walls in the control/SDG area. 3.8.4.1.3 Auxiliary Building Radwaste/Service Area The Auxiliary Building radwaste/service area, as shown on Plant Drawings P-0031-0 through P-0037-0, houses radwaste treatment and storage facilities, cable tray runs, main steam line tunnels, heating and ventilating equipment, machine shops, decontamination equipment, and personnel facilities. The Auxiliary Building radwaste/service area is separated into three sections by seismic separation joints extending in the east-west direction from the bottom of the foundation mats through the roofs. A similar north-south seismic joint separates the east interface of the radwaste/service area from the Turbine Building and administration facility. The west side of the radwaste/service area is bounded by the Reactor Building, the Auxiliary Building control area, and the plant cancelled area. The northern section of the radwaste/service area is structurally continuous with the plant cancelled area, the central section with the Auxiliary Building control/SDG area, and the southern section with the reactor building. The structural foundations consist of the eastern portions of three separate reinforced concrete mats, isolated by seismic separation joints. Each foundation continuously projects to the west as founding support for the reactor building, the control/SDG area, and the plant cancelled area, described in Sections 3.8.4.1.1, 3.8.4.1.2, and 3.8.4.1.4, respectively. 3.8-41 HCGS-UFSAR Revision 20 May 9, 2014

The radwaste/service area is a reinforced concrete structure that has bearing/shear walls designed to resist lateral loads and transmit them to the reinforced concrete foundation mat, where all loads are dissipated into the Vincentown Formation. The reinforced concrete floors are supported by structural steel beam and column framing systems and are designed as diaphragms to resist lateral loads and transmit them to the shear walls. All reinforced concrete walls and floors meet both structural and radiation shielding requirements, as discussed in Section 12.3.2. There are no concrete masonry unit walls in the radwaste/service area. 3.8.4.1.4 Plant Cancelled Area The plant cancelled area, formerly a portion of the Unit 2 Reactor Building, is shown on Plant Drawings P-0001-0 through P-0004-0, and P-0011-0. It is a reinforced concrete enclosure that is rectangular in shape and is located in the northwest quadrant of the power complex, adjacent to the auxiliary building, which is to the south and east. The facility does not house any safety-related equipment and is not occupied, except for periodic surveillance. The plant cancelled area bearing/shear walls are designed to resist lateral loads and transmit them to the reinforced concrete foundation mat, where all loads are dissipated into the Vincentown Formation. The reinforced concrete floors are supported by structural steel framing systems that are in turn supported by the walls. Floor systems are designed to act as diaphragms that transmit lateral loads to the shear walls. Radial framing is used within the cylindrical portion, while framing in the rectangular area is laid out on east-west and north-south lines. The central portion of the roof consists of cellular metal decking and built-up roofing material. A seismic separation joint extends from the foundation mat through the roof at the south wall of the facility, where it interfaces with the Auxiliary Building control/SDG area. The plant cancelled area foundation mat, described in Section 3.8.5, extends eastward beyond 3.8-42 HCGS-UFSAR Revision 20 May 9, 2014

the facility to support the northern section of the Auxiliary Building radwaste/service area. 3.8.4.1.5 Station Service Water System (SSWS) Intake Structure The Station Service Water System (SSWS) intake structure, as shown on Plant Drawings P-0071-0 and P-0072-0, houses four service water pumps and associated equipment, such as ice barriers, trash racks, traveling screens, and oil skimmer walls. The SSWS intake structure is a reinforced concrete structure supported on a reinforced concrete foundation mat, as described in Section 3.8.5. The mat is founded on top of a tremie concrete plug, which is in turn founded on, and keyed into, the Vincentown Formation. Bearing walls are designed as shear walls to resist and transfer lateral loads to the foundation mat, and thus through the tremie plug into the Vincentown Formation. All floors and the roof of the intake structure are of reinforced concrete and are designed to act as diaphragms that transmit lateral loads to the shear walls. There are no concrete masonry unit walls in the SSWS intake structure. 3.8.4.1.6 Condensate Storage Tank Dike The condensate storage tank dike, as shown on Figure 3.8-36, is located in the yard adjacent to the Reactor Building. It is designed to contain the total volume of the condensate storage tank. The dike walls and foundation slab are provided with waterstops to prevent spillage from infiltrating into the surrounding soil. 3.8.4.1.7 Non-Seismic Category I Structures 3.8.4.1.7.1 Turbine Building The Turbine Building design is shown on Plant Drawings N-1011 and P-0012-1 through P-0016-1. 3.8-43 HCGS-UFSAR Revision 20 May 9, 2014

The building houses the turbine generator unit and its attendant auxiliary equipment, including condensers, condensate pumps, moisture separators, air ejectors, feedwater heaters, reactor feed pumps, motor generator sets for reactor recirculation pumps, recombiners, interconnecting piping and valves, and switchgear. Two 220 ton overhead cranes, described in Section 9.1.5, are provided above the operating floor to service the turbine generator unit. The building enclosure consists of exterior walls of reinforced concrete to Elevation 102 feet. Except where shielding is required, the enclosure above Elevation 102 feet is accomplished with precast concrete panels to Elevation 125 feet 6 inches and with insulated metal siding from Elevation 125 feet 6 inches to the roof. The roof has a nominal Elevation of 200 feet and consists of cellular metal decking, insulating board, and built-up roofing material. Vertical loads are supported by reinforced concrete walls and structural steel columns. Generally, interior reinforced concrete walls and structural steel columns extend from the top of the base mat to Elevation 137 feet. Floor slabs are reinforced concrete supported by structural steel framing. They are designed to act as diaphragms to resist lateral loads and transfer them to the shear walls. The reinforced concrete shear walls transfer the lateral loads to the reinforced concrete foundation mat, which dissipates them into the Vincentown Formation. In the turbine generator bay, structural steel rigid frames spanning the east-west direction support roof loads, east-west lateral loads, and crane loads. North-south lateral loading is generally resisted by steel bracing and transferred into the shear walls at elevation 137 feet. The turbine generator is supported by a free standing, reinforced concrete pedestal founded on the base mat and flush with the operating floor at Elevation 137 feet. The operating floor framing is supported on vibration damping pads that are in turn supported by 3.8-44 HCGS-UFSAR Revision 0 April 11, 1988

the pedestal. Separation joints are provided between the pedestal and walls and other Turbine Building floors to prevent transfer of vibration to the building. The Turbine Building is isolated from the auxiliary building radwaste/service area by a seismic separation joint extending from the basemat through the roof in the north-south direction, and from the administration facility by a similar seismic separation joint extending in the east-west direction. Some interior walls, required for separation, radiation shielding, or fire protection, are constructed of fully grouted, reinforced concrete masonry units. 3.8.4.1.7.2 Administration Facility The administration facility, formerly the Unit 2 Turbine Building, is shown on Plant Drawings P-0001-0 through P-0005-0, and P-0010-0. The building houses the administrative offices and warehouse facility in support of plant operation. In addition, the former Unit 2 Turbine Building operating floor is accessible from the adjacent operating floor for use as a laydown area. The two overhead cranes provided to service the turbine generator unit can also operate over this laydown area. The facility enclosure consists of exterior walls of reinforced concrete to Elevation 102 feet. The enclosure above elevation 102 feet is accomplished with precast concrete panels and window walls to Elevation 125 feet 6 inches, and with insulated metal siding and window walls from Elevation 125 feet 6 inches to the roof. The roof has a nominal Elevation of 200 feet and consists of cellular metal decking, insulating board, and built-up roofing material. Vertical loads are supported by reinforced concrete walls and structural steel columns. Generally, reinforced concrete walls and structural steel columns extend from the top of the base mat to Elevation 137 feet. 3.8-45 HCGS-UFSAR Revision 20 May 9, 2014

Floor slabs are reinforced concrete supported by structural steel framing. They are designed to act as diaphragms to resist lateral loads and transfer them to the shear walls. The reinforced concrete shear walls transfer the lateral loads to the reinforced concrete foundation mat, described in Section 3.8.5, which dissipates them into the Vincentown Formation. In the laydown area, structural steel rigid frames spanning the east-west direction support roof loads, east-west lateral loads, and crane loads. North-south lateral loading is generally resisted by steel bracing and transferred into the shear walls at elevation 137 feet. The administration facility is isolated from the Auxiliary Building radwaste/service area by a seismic separation joint, extending from the basemat through the roof in the north-south direction, and from the Turbine Building by a similar seismic separation joint extending in the east-west direction. Some interior walls, required for radiation shielding, area isolation, or fire protection, are constructed of fully grouted, reinforced concrete masonry units. 3.8.4.2 Applicable Codes, Standards, and Specifications Table 3.8-7 lists the codes, standards, and specifications used in designing, fabricating, and constructing non-Seismic Category I structures discussed in Section 3.8.4.1, and Seismic Category I structures other than the primary containment and its internals, which are discussed in Sections 3.8.2 and 3.8.3. Applicable regulatory guides are discussed in Section 1.8. 3.8.4.3 Loads and Load Combinations The following loads and load combinations are considered in the design of non-Seismic Category I structures discussed in Section 3.8.4.1, and Seismic Category I structures other than the 3.8-46 HCGS-UFSAR Revision 0 April 11, 1988

primary containment and its internals. Structures that directly affect the integrity of the reactor coolant pressure boundary (RCPB), the capability to shut down the reactor and maintain it in a safe shutdown condition, or the capability to prevent or mitigate the consequences of accidents that could result in potential offsite exposures comparable to the guideline exposures of 10CFR50.67, are designed to withstand the effects of these loads and load combinations. 3.8.4.3.1 Definition of Loads 3.8.4.3.1.1 Normal Loads Normal loads are those encountered during normal plant startup, operation, and shutdown. They include dead loads, live loads, operating thermal loads, and operating pipe reaction loads. 3.8.4.3.1.1.1 Dead Loads (D) Dead loads include the weight of framing, roofs, floors, walls, partitions, platforms, and all permanent equipment and materials. The vertical and lateral pressures of groundwater and liquids are also treated as dead loads. Floors are designed for major equipment loads. For permanently attached small equipment, piping, conduit, and cable trays, a minimum of 50 psf is added. Where piping is supported from platforms or walkway beams, actual loads are determined and used. After pipe hanger locations and loads for main piping are fully established, all structural members, including those already designed, are reviewed for structural adequacy and, if loads exceed design allowables, the members are reinforced to withstand the established loads. 3.8-47 HCGS-UFSAR Revision 17 June 23, 2009

3.8.4.3.1.1.2 Live Loads (L) and Operating Live Loads (L ) o Live loads include any movable equipment loads and other loads that vary with intensity and occurrence, such as soil pressures, snow loads, pressure difference due to variation in heating and cooling, outside atmospheric changes, and the dynamic effects of operating equipment. The design live loads designated as "L" include floor area loads, laydown loads, nuclear fuel and fuel transfer cask loads, equipment handling loads, and lateral earth pressure loads. The floor area live load is omitted from areas occupied by equipment whose weight is specifically included in dead load. Live load is not omitted under equipment where access is provided. In load combinations including earthquake motions, the live loads are limited to the designation "L ," which is defined as the live load expected to be o present when the plant is operating. The L loads are applied simultaneously o with the seismic forces. In the laydown areas, the actual weight of the equipment, as spread out on the floor, is considered L . o 3.8.4.3.1.1.3 Operating Thermal Loads (T ) o Operating thermal loads are based on the most critical transient or steady state condition to occur during normal operation. 3.8.4.3.1.1.4 Operating Pipe Reaction Loads (R ) o Operating pipe reaction loads are based on the most critical transient or steady state condition. 3.8.4.3.1.2 Severe Environmental Loads Severe environmental loads are those that could infrequently be encountered during the plant life and include operating basis earthquake seismic loads and severe wind loads. Components are 3.8-48 HCGS-UFSAR Revision 0 April 11, 1988

designed to remain within appropriately defined allowable stress limits when subjected to severe environmental loads. 3.8.4.3.1.2.1 Operating Basis Earthquake Seismic Loads (E ) o The free field ground acceleration at the bottom of the foundation mat for the OBE is 0.1g. Refer to Sections 3.7.1, 3.7.2, and 3.7.3 for a detailed discussion of seismic requirements. 3.8.4.3.1.2.2 Severe Wind Loads (W) Severe wind loads are as described in Section 3.3. 3.8.4.3.1.3 Extreme Environmental Loads Extreme environmental loads are those that are credible but highly improbable and include safe shutdown earthquake seismic loads, tornado loads, and extreme wind and flood loads. 3.8.4.3.1.3.1 Safe Shutdown Earthquake Seismic Loads (E ) s The free field ground acceleration at the bottom of the foundation mat for the SSE is 0.2g. Refer to Sections 3.7.1, 3.7.2, and 3.7.3 for a detailed discussion of seismic requirements. 3.8.4.3.1.3.2 Tornado Loads (W ) t Tornado loads include wind velocity pressure loads (W ) and differential tq pressure loads (W ) as described in Section 3.3, and tornado generated missile tp impact loads (W ), as described in Section 3.5.3. tm 3.8.4.3.1.3.3 Extreme Wind and Flood Loads (W ) e Loads under extreme wind conditions are based on the probable maximum hurricane (PMH) and concurrent flood resulting from wind and tidal action, as discussed in Sections 2.4.2 and 3.3.1. 3.8-49 HCGS-UFSAR Revision 0 April 11, 1988

3.8.4.3.1.4 Abnormal Loads Abnormal loads are those generated by a postulated high energy pipe break. 3.8.4.3.1.4.1 Abnormal Pressure Loads (P ) a Abnormal pressure loads within or across a compartment and/or structure result from postulated pipe rupture. The time dependent nature of the load and the ability of the structure to deform beyond yield is considered in establishing the structural capacity necessary to resist the effects of P . a 3.8.4.3.1.4.2 Abnormal Thermal Effects (T ) a Abnormal thermal effects result from thermal conditions generated by the postulated pipe rupture. T includes the effects of T . a o 3.8.4.3.1.4.3 Abnormal Pipe Reaction Loads (R ) a Abnormal pipe reaction loads result from the thermal conditions generated by the postulated pipe rupture and include R . o 3.8.4.3.1.4.4 Abnormal Local Effects (R ) r Abnormal local effects on structures are due to postulated pipe rupture. The local effects include the following:

1. R - Load on the structure generated by the reaction of a rr ruptured high energy pipe during the postulated event. The time dependent nature of the load and the ability of the structure to deform beyond yield is considered in establishing the structural capacity necessary to resist the effects of R .

rr

2. R - Load on the structure generated by the jet impingement from rj a ruptured high energy pipe during the 3.8-50 HCGS-UFSAR Revision 0 April 11, 1988

postulated event. The time dependent nature of the load and the ability of the structure to deform beyond yield is considered in establishing the structural capacity necessary to resist the impact.

3. R - The energy resulting from the impact of a ruptured high rm energy pipe on a structure or pipe restraint during the postulated event. The type of impact, together with the ability of the structure to deform beyond yield, is considered in establishing the structural capacity necessary to resist the impact.

The jet forces used to evaluate R are determined using methods and procedures discussed in Section 3.6.2. 3.8.4.3.2 Load Combinations Tables 3.8-8 through 3.8-11 list the load combinations, applicable load factors, and allowable limits used in the design of the applicable structure. Table 3.8-12 summarizes the symbols used in the load combinations. Maximum effects of P , T , R , and R are combined, unless a time history a a a r analysis is performed to justify lower combined values. In addition to the combinations listed in Tables 3.8-8 through 3.8-11, the following combinations for W and R are also a design requirement, where t r applicable, for Seismic Category I structures:

1. Tornado effects W :

t

a. W , W or W acting independently tq tp tm

b. W + 0.5 W tp tp

c. W + W tq tm 3.8-51 HCGS-UFSAR Revision 0 April 11, 1988

d. W + 0.5 W + W tq tp tm

2. Local effects of pipe rupture R :

r

a. R or R acting independently rj rr

b. R + R rr rm

c. R + R + R rr rm rj The central portion of the roof of the plant cancelled area is not designed to withstand the tornado effects of item 1. above.

3.8.4.4 Design and Analysis Procedures 3.8.4.4.1 Seismic Category I Structures The Seismic Category I structures described in Section 3.8.4.1 are designed to maintain elastic behavior for the loads and load combinations described in Section 3.8.4.3, except for dynamic loads generated by abnormal pressure and abnormal local effects. All reinforced concrete components of the structure are designed by the strength method per ACI 318, as listed in Table 3.8-7. Generally, all structural steel components are designed by the working stress method per AISC specifications listed in Table 3.8-7, except for dynamic loads generated by abnormal pressure and abnormal local effects. For dynamic loads generated by abnormal pressure and abnormal local effects, the structural members are allowed to exceed the yield strain and displacement values, since the impulse loads are short term and missile impact has a defined input energy limit. Seismic design of structures is described in Sections 3.7.1, 3.7.2, and 3.7.3. The structures are analyzed dynamically. Design of structures for missile protection is covered in Section 3.5.3. 3.8-52 HCGS-UFSAR Revision 0 April 11, 1988

There are no concrete masonry unit walls in Seismic Category I structures. Appendix 3F discusses the design and analysis procedures for the fuel pool liner and slab. 3.8.4.4.2 Non-Seismic Category I Structures The non-Seismic Category I structures described in Section 3.8.4.1 are designed to maintain elastic behavior for the loads and load combinations described in Tables 3.8-9 and 3.8-11. In addition, the Turbine Building and administration facility are checked to verify that they do not collapse on, or interact with, adjacent Seismic Category I structures for certain abnormal and extreme environmental conditions, as described in Tables 3.8-9 and 3.8-11. All reinforced concrete components of the structure are designed by the strength method per ACI 318, as listed in Table 3.8-7. Structural steel components are designed by the working stress method per AISC specifications listed in Table 3.8-7. The Turbine Building and administration facility are designed in accordance with the criteria established by the UBC, as listed in Table 3.8-7, for structures in Seismic Zone No. 1, together with any additional requirements stated herein. To provide assurance that the turbine building and administration facility will not collapse due to SSE ground motions, they are analyzed using dynamic techniques. These structures are designed to accommodate an SSE event by the following methods:

1. Reinforced concrete elements are designed for ductile behavior in accordance with UBC or for elastic-plastic behavior provided its ductility factor does not exceed 3 and structural resistance is based on Section Strength (U) for concrete.

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2. Structural steel elements are designed by the working stress method or for elastic plastic behavior provided its ductility factor does not exceed 3.

Concrete masonry unit walls in the non-Seismic Category I turbine building and administration facility are used only for radiation shielding, fire separation, and miscellaneous supports, and are designed for vertical loading and seismic loading in accordance with the UBC, as listed in Table 3.8-7. 3.8.4.4.3 Computer Programs Computer programs used in the design and analysis of the Seismic Category I and non-Seismic Category I structures described in Section 3.8.4.1 are discussed in Appendix 3A. 3.8.4.5 Structural Acceptance Criteria 3.8.4.5.1 Reinforced Concrete The reinforced concrete structural components are designed by the strength method in accordance with ACI 318, as listed in Table 3.8-7, for loads and load combinations described in Section 3.8.4.3. The margins of safety are contained in the capacity reduction factors (u) specified in the code. Table 3.8-18 provides the allowable ductility ratios used in design for impactive and impulsive loading. A review of the design of flexural beams and slabs indicates that the actual ductility ratios are less than the allowable ductility ratios in Regulatory Guide 1.142. 3.8.4.5.2 Structural Steel Generally, structural steel components are designed by the working stress method in accordance with AISC specifications, as listed in Table 3.8-7, for loads and load combinations described in Section 3.8.4.3. The allowable stresses for different load combinations are also indicated in Tables 3.8-10 and 3.8-11. The 3.8-54 HCGS-UFSAR Revision 0 April 11, 1988

margins of safety are contained in the allowable design stresses. Table 3.8-19 provides the allowable ductility used for impactive and impulsive loading. 3.8.4.5.3 Concrete Masonry Unit Walls Concrete masonry unit walls are used only for radiation shielding, fire separation, or miscellaneous supports in the non-Seismic Category I Turbine Building and administration facility. They are not shear walls and are designed to the working stress method of UBC, as listed in Table 3.8-7. 3.8.4.6 Materials, Quality Control, and Special Construction Techniques Materials, quality control, and special construction techniques are discussed in Section 3.8.6. 3.8.4.7 Testing and Inservice Inspection Requirements Testing and inservice inspection are not required for Seismic Category I structures other than the primary containment and its internals. 3.8.4.8 SRP Rule Review 3.8.4.8.1 Concrete Design Acceptance Criteria II.2 of SRP 3.8.3 and 3.8.4 requires that Category I structures be designed in accordance with Specification ACI 349 as augmented by Regulatory Guide 1.142. The HCGS design was based on the requirements of Specification ACI 318-71. The Category I structures concrete design for HCGS began prior to the issue of Specification ACI 349 (1976). As a result, all concrete design is based on using Specification ACI 318-71 with the following clarifications: 3.8-55 HCGS-UFSAR Revision 0 April 11, 1988

A review of the design of the HCGS Seismic Category I structures indicates that there is no impact due to differences in the structural acceptance criteria between ACI 318-71 and ACI 349-76 as augmented by Regulatory Guide 1.142. The load combinations used are in conformance with the following SRP sections except that the 0.9 load factor on dead load as required by ACI 349-76 was not used: Structures SRP Section Primary Containment 3.8.3.II.3.b. Internal Concrete Structures Other Seismic Category I 3.8.4.II.3.b. Concrete Structures Based on parametric analyses, an adequate design margin exists to compensate for the effects of the reduced dead load factor. Table 3.8-18 provides a comparison of the allowable ductility ratios used for design of the concrete structural components subjected to impactive and impulsive loadings and the criteria outlined in Appendix C of ACI 349 as modified by Regulatory Guide 1.142. The criteria in Appendix C of ACI 349 as modified by Regulatory Guide 1.142 is referenced in Appendix A of NUREG-0800, SRP Section 3.5.3. Except for flexural beams and slabs subjected to impactive loads, the allowable ductility ratios used in the design are less than or equal to those in the Regulatory Guide. The allowable ductility ratios for beams and slabs used in design are based on the evaluation of test data reported in References 3.8-5 and 3.8-6 and tests performed by the Architect/Engineer. The test results consistently demonstrate that actual ductility ratios in excess of 50 are reached prior to failure. Therefore, by limiting the values to 10 for beams and 30 for slabs, the design is 3.8-56 HCGS-UFSAR Revision 0 April 11, 1988

conservative. Furthermore, the flexural members are designed to meet additional reinforcing requirements (See Table 3.8-18) to ensure ductile behavior. A review of the design of flexural beams and slabs indicates that the actual ductility ratios are less than the allowable ductility ratios in Regulatory Guide 1.142. 3.8.4.8.2 Structural Steel Design Table 3.8-19 provides a comparison of the allowable ductility ratios used for design of structural steel subjected to impactive and impulsive loading, and the criteria outlined in Appendix A of NUREG-0800, SRP Section 3.5.3. Except for flexure in beams subjected to impactive loads (other than the tornado missiles) and axial tension members subject to impulsive loads, the ductility ratios are essentially identical. Based on the recommendations provided in References 3.8-5 and 3.8-6 and tests performed by the Architect/Engineer, it has been demonstrated that steel members under flexural loads can sustain higher ductility ratios (on the order of 30) without collapse. Therefore, a limiting value of 20 used in the design is conservative. Furthermore, additional design and fabrication features (such as box sections, lateral bracings, NDE, etc.) are incorporated in the flexural members to preclude buckling and to ensure material quality. As a follow-up of the NRC Structural Audit, all flexural beams subjected to impactive loads (other than tornado missiles) have been reevaluated utilizing final design parameters. This reevaluation revealed that the actual ductility ratios are less than or equal to the allowable ductility ratios in Appendix A of NUREG-0800, SRP Section 3.5.3. Regarding the ductility ratio for axial tension members subject to impulsive loads, the HCGS limit of 3 is always conservative for the types of steel used. 3.8-57 HCGS-UFSAR Revision 0 April 11, 1988

3.8.4.8.3 Spent Fuel Rack Design Acceptance Criterion II.4.f requires that the spent fuel racks be designed in compliance with Appendix D of SRP 3.8.4, which requires that construction materials should conform to Section III, Subsection NF of the ASME Code. The design, analysis and fabrication of the spent fuel racks conforms with the applicable provisions of Subsection NF. See Appendix 9B for a description of the design, analysis and construction of the racks. The spent fuel racks are constructed of ASTM A-240 and ASTM A-564 stainless steel. The A-240 and A-564 material specifications are identical to the ASME SA-240 and SA-564 material specifications. All rack steel is supplied with certified material test reports. The rack materials are procured under a Q.A. Program that is intended to comply with:

1. 10CFR50, Appendix B, "Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants".

2. ANSI/ASME N45.2, "Quality Assurance Program Requirements for Nuclear Facilities", and

3. ANSI/ASME NQA-1, "Quality Assurance Program Requirements for Nuclear Power Plants".

3.8.5 Foundations Foundations for all Seismic Category I structures and the turbine building and the administration facility, which are non-Seismic Category I structures, are described in this section. 3.8-58 HCGS-UFSAR Revision 0 April 11, 1988

3.8.5.1 Description of the Foundations The configuration of the foundation mats for the various structures is shown on Figure 3.8-37. Reinforced concrete mat foundations are provided for all structures. Except for the Station Service Water System (SSWS) intake structure, the mats rest either on the Vincentown Formation or on engineered structural backfill placed on the Vincentown Formation. The mat and the lean concrete leveling course for the intake structure rest on a tremie concrete plug supported by the Vincentown Formation. Bearing walls of the structures are rigidly connected to the foundations. Steel columns are attached to the foundation by base plates and anchor bolts. The bearing walls and the steel columns carry all the vertical loads from the structure to the mat. Horizontal shears due to wind, tornado, and seismic loads are transferred to the shear walls by roof and floor diaphragms. The shear walls in turn transfer the horizontal shears to the foundation mats. The mats transfer all loads to the Vincentown Formation through friction and/or direct bearing. All mats, except that for the SSWS intake structure, are 14 feet thick and are constructed in two lifts. Additional shear reinforcement is provided at the horizontal joints where necessary. The thickness of the mat for the SSWS intake structure varies between 6 feet and 4 feet 6 inches and is constructed in one lift. Each concrete pour is placed in a "checkered-board" pattern to minimize the effects of concrete shrinkage and heat of hydration. In the power block area, a leveling mud mat, an unreinforced concrete layer, is provided beneath the concrete topping mat to facilitate construction and installation of the waterproofing membrane. A multiple waterproofing membrane is provided on the leveling mat and on the outside face of the peripheral walls below grade. In the case of the SSWS intake structure, the exterior walls 3.8-59 HCGS-UFSAR Revision 0 April 11, 1988

and the bottom of the structural mat are protected with a waterproofing system. Each main foundation mat is separated from the others by a seismic joint at least 2-inches wide. Piping and conduit crossing seismic joints are provided with sufficient flexibility to accommodate a 3/4-inch post-earthquake differential settlement. The basis for estimating post-earthquake differential settlement, as indicated in Section 2.5.4.8.3, is based on analytical procedures developed by Lee and Albaisa (Reference 2.5-110). This settlement is considered to have an insignificant effect on the structural design of the base mat. Piping which crosses a seismic joint is analyzed for building settlement effects assuming a 3/4 inch relative vertical displacement between the first vertical rigid support on both sides of the seismic joint. The stresses generated in the pipe as a result of differential settlement is evaluated against ASME B&PV Section III code allowables equal to 3S (Ref: NC/ND-3652.3) where S is the basic material allowable stress value at room temperature. The loads on supports are accounted for in the design of pipe supports. Electrical conduit crossing a seismic joint are provided with flexible couplings and fittings as shown in Figures 3.8-45 and 3.8-46. Peripheral subterranean walls are designed to resist lateral pressures due to backfill, groundwater, flood, and surcharge loads in addition to dead loads, live loads, and seismic loads. Figures 3.8-38 through 3.8-43 show details and Table 3.8-13 summarizes descriptions of the foundations. 3.8.5.1.1 Reactor Building and Southern Section of the Radwaste/Service Area of the Auxiliary Building The foundation mat for the Reactor Building and the southern section of the radwaste/service area is poured to act as a single slab, as 3.8-60 HCGS-UFSAR Revision 0 April 11, 1988

shown for Mat 3 on Figures 3.8-37 and 3.8-40. The mat is typically reinforced with No. 18 bars at 26-inch centers on the top, and No. 18 bars at 13-inch centers on the bottom. A second layer of the same reinforcement is provided in the area supporting the primary containment. Vertical shear reinforcement is provided with No. 10 bars typically located in a 26-inch by 52-inch grid pattern. 3.8.5.1.2 Auxiliary Building Control/Diesel Generator Area and Central Section of the Radwaste/Service Area The foundation mat for the control/diesel generator area and the central section of the radwaste/service area is poured to act as a single slab, as shown for Mat 5 on Figures 3.8-37 and 3.8-42. The mat is typically reinforced with No. 18 bars at 26-inch centers at both the top and the bottom. No. 11 bars are provided for additional reinforcement, where required. Vertical reinforcement is provided by No. 10 bars, where required. 3.8.5.1.3 Plant Cancelled Area and Northern Section of the Auxiliary Building Radwaste/Service Area The foundation mat for the plant cancelled area and the northern section of the radwaste/service area is poured to act as a single slab, as shown for Mat 4 on Figures 3.8-37 and 3.8-41. The mat is typically reinforced with No. 18 bars at 26-inch centers on both top and the bottom in multiple layers. Vertical shear reinforcement is provided with No. 10 bars typically located in a 26-inch by 52-inch grid pattern. 3.8.5.1.4 SSWS Intake Structure The foundation mat for the SSWS intake structure is 4 feet 6 inches thick on the waterfront side and 6 feet thick on the landward side. It is placed in four blocks to act as a single slab, as shown for Mat 6 on Figures 3.8-37 and 3.8-43. Typical reinforcement consists 3.8-61 HCGS-UFSAR Revision 0 April 11, 1988

of No. 10 bars at 12-inch centers. No. 7 bars are provided for additional reinforcement, where required. 3.8.5.1.5 Turbine Building and Administration Facility The foundation mat for the Turbine Building is shown as Mat 1 and the administration facility as Mat 2 on Figure 3.8-37, and on Figures 3.8-38 and 3.8-39, respectively. Both mats are typically reinforced with No. 18 bars at 26-inch centers on both top and bottom. No. 11 bars are provided for additional reinforcement, where required. 3.8.5.2 Applicable Codes, Standards, and Specifications Codes, standards, and specifications used in the design, fabrication, and construction of foundations of the structures are listed in Table 3.8-15. 3.8.5.3 Loads and Load Combinations Loads and load combinations used in the foundation mat design are described in Section 3.8.4. In addition, the following load combinations are considered in order to determine the factor of safety against sliding and overturning due to winds, tornadoes, seismic loads, and against flotation due to groundwater and design basis flood:

1. D + H + W

2. D + H + W t

3. D + H + E o

4. D + H + E s

5. D + F where D, E , W, E and W are defined in Section 3.8.4, and H and F are the o s t lateral earth pressure and buoyant force due to design basis flood, respectively.

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3.8.5.4 Design and Analysis Procedures The foundations are designed to maintain elastic behavior under different loads and load combinations. Loads and load combinations are described in Sections 3.8.4 and 3.8.5.3. The design and analysis of the reinforced concrete foundations are carried out in accordance with ACI 318. Appendix 3D contains critical sections, loads, and a discussion of how these loads are accommodated in the Reactor Building and the southern section of the radwaste/service area, and the Auxiliary Building control/diesel generator and central section of radwaste/service area basement designs. Bearing walls and steel columns carry all the vertical loads from the structure to the foundation mat. Lateral loads are transferred to the shear walls by the roof and floor diaphragms. The shear walls then transmit the loads to the foundation mat. The loads on the mats are determined using finite element analysis program BSAP, as discussed in Appendix 3A. The adjacent mats, the supporting and surrounding soils, and the stiff load bearing walls are included in the model to determine their effects. Settlement of the foundations of the Seismic Category I structures is considered in the design. Estimated settlement is discussed in Section 2.5.4.10. Stability against sliding is ensured by dead weight of the structures, the subgrade soil friction, and lateral soil resistance to the foundations. The SSWS intake structure is provided with additional anchorage by having a shear key installed at the bottom of the tremie concrete. Stability against overturning is ensured by the dead weight and lateral soil resistance. Appendix 3G contains a discussion of the intake structure stability analysis. 3.8-63 HCGS-UFSAR Revision 0 April 11, 1988

A detailed description of the foundation bearing stratum is given in Section 2.5. The calculated bearing pressure is within allowable limits, as discussed in Section 2.5.4.11. Summaries of stability calculations are provided in Appendixes 3G and 3H. 3.8.5.5 Structural Acceptance Criteria The foundations of all Seismic Category I structures are designed to meet the same structural acceptance criteria as the structures themselves. These criteria are discussed in Section 3.8.4. In addition, for the additional load combinations a. through e. delineated in Section 3.8.5.3, the calculated factor of safety against overturning, sliding, and flotation exceeds the following minimum values: Load Combination Minimum Factors of Safety Overturning Sliding Flotation

1. D + H + W 1.5 1.5 -

2. D + H + W 1.1 1.1 -

3. D + H + E 1.5 1.5 -

4. D + H + E 1.1 1.1 -

5. D + F - - 1.1 3.8.5.6 Materials, Quality Control, and Special Construction Techniques 3.8.5.6.1 Materials and Quality Control The foundation mats of the Seismic Category I structures are constructed of reinforced concrete. Concrete and reinforcing steel materials are discussed in Section 3.8.6. The concrete design strength is generally 4000 psi, except for the 2500 psi tremie concrete fill beneath the base mat of the SSWS intake structure.

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3.8.5.6.2 Construction Techniques 3.8.5.6.2.1 Power Block Complex In the general area where the reactor building, the control/diesel generator area and radwaste/service area of the Auxiliary Building, the administration facility, and the Turbine Building are located, an open cut excavation is made by the hydraulic dredge method to a depth where competent Vincentown Formation is exposed. The excavation is controlled so that the integrity of the bearing stratum is maintained. Because of the high water table, a dewatering system is installed and operated to facilitate excavation. The groundwater level is maintained below the water level in the excavation pool at all times so there is never an upward flow of groundwater within the excavated area. Groundwater levels and dewatering discharge are monitored periodically to ensure proper functioning of the dewatering system. Upon completion of the excavation, the excavated area is dewatered, and final cleanup is performed. Adequate protection of the foundation stratum from frost and construction equipment is provided by engineered backfill and/or lean concrete cover. To reach the base mat construction level, engineered backfill, as required, is placed on the Vincentown Formation. Material descriptions and the placing requirements for engineered backfill are given in Section 3.8.6. Requirements for decommissioning the dewatering system are shown in Table 3.8-

14. The dewatering system is decommissioned, since sufficient dead load is provided to protect the structure under construction from the effects of overturning, sliding, or flotation.

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3.8.5.6.2.2 SSWS Intake Structure The SSWS intake structure is constructed by installing a steel sheet cofferdam around the perimeter of the required structural excavation. The soil within the cofferdam is excavated underwater to predetermined elevations and line. Upon completion, the excavation is inspected by a diver trained in geology. Finally, a tremie concrete plug is placed in the cofferdam up to the bottom levels of the structural base mat. Following the placement and curing of the tremie concrete, the cofferdam is dewatered and the superstructure is constructed. 3.8.5.7 Testing and Inservice Inspection Requirements Foundation testing and inservice inspection involves monitoring the structures to detect any settlement that might occur. During construction, the base mats are checked periodically for any settlement. They are also checked for settlement when significant loads are added to the mats. Actual settlement readings must compare reasonably with predicted values. Settlement is monitored periodically during operation of the plant unless settlement is stabilized prior to startup. 3.8.6 Materials of Construction This section discusses the materials of construction, workmanship, and quality control used to construct the Seismic Category I structures of HCGS. 3.8.6.1 Engineered Backfill The engineered backfill is installed adjacent to and underneath Seismic Category I structures. These backfill areas and related cross sections are shown on Figure 3.8-44. The engineered backfill 3.8-66 HCGS-UFSAR Revision 0 April 11, 1988

also supports the Seismic Category I service water pipes above the Kirkwood Formation, located outside the main excavation area. 3.8.6.1.1 Material Selection The material used for engineered backfill consists of pit run sand, silty sand, sandy gravel, or gravelly sand with not more than 20 percent by weight passing the No. 200 U.S. standard sieve size. The particles of the backfill material consist of sound, dense, and durable material. The sources of backfill material are the Oldman's Pit and Hitchner Borrow. Representative samples of the material from each source are tested prior to use, to determine both static and dynamic properties. The results of testing are reported in:

1. Dames and Moore Report - Additional Site Stability Evaluation, Hope Creek Generating Station, Appendix IV-B, Evaluation of Structural Backfill - Oldman's Borrow Source, December 1976.

2. Dames and Moore Report - Liquefaction Potential Analysis for Backfill, Power Block Area, Hope Creek Generating Station, April 1977.

3. Supplementary Borrow Area Investigation for Structural Backfill, October 1980.

A program of testing and inspection is carried out prior to and during placement to confirm that backfill material is in conformance with the approved borrow material and placement requirements. 3.8.6.1.2 Installation and Compaction The engineered backfill is spread in uniform lifts not exceeding 8 inches in loose thickness and compacted to an average of 3.8-67 HCGS-UFSAR Revision 0 April 11, 1988

98 percent and a minimum of 95 percent of the maximum dry density, as determined by ASTM D 1557, Method D. Test embankments are constructed and tested for use in establishing final placing, compaction procedures, and techniques for the backfill operation. A new test embankment is constructed for each new type of equipment and/or different source of borrow material. The test embankment is used to establish the lift thickness, moisture conditioning procedure, and the number of passes for each type of compaction equipment required to achieve the specified degree of compaction. The type of equipment used for the backfill is the same type used in the test embankment. In areas where field density test results are less than the required degree of compaction, the backfill is replaced and/or recompacted to attain the required degree of compaction. Similarly, any areas that are previously accepted and later become disturbed or loosened, are replaced and/or recompacted to the required degree of compaction. The excavated subgrade is thoroughly proof rolled prior to the installation of the initial backfill lift to recompact any areas of its surface that have become disturbed during construction operations. Successive lifts of backfill are not installed upon frozen subgrade or backfill soils. Any such frozen material is removed and suitably thawed or broken up before it is considered for reuse. The moisture content of the backfill is adjusted as required to facilitate compaction. All backfill areas are appropriately graded during installation to facilitate surface drainage and to prevent any local ponding. 3.8-68 HCGS-UFSAR Revision 0 April 11, 1988

3.8.6.1.3 Testing of Backfill Material 3.8.6.1.3.1 Field Density Tests The degree of compaction attained during backfill operations is verified by performing field density tests in accordance with ASTM D 1556 and/or ASTM D 2922. If nuclear methods are employed for the above test procedures, the ratio of density tests performed in accordance with ASTM D 2922 procedures to ASTM D 1556 procedures is a maximum of three to one. For self-propelled vibratory compactors, the minimum number of tests is one for every 250 cubic yards of backfill placed, or one test per lift covering 10,000 square feet of surface area, or one test for every day of compaction operation, whichever is more frequent. For hand compactors, the minimum number of tests is one for each day of backfill placement, or 50 cubic yards in-place, whichever is more frequent. 3.8.6.1.3.2 Laboratory Tests A minimum of one Proctor test in accordance with ASTM D 1557, Method D, is performed for every 1000 cubic yards of backfill placed. Material for this test is obtained from the field density test performed to ASTM D 1556. 3.8.6.1.3.3 Gradation Tests Gradation tests for the backfill material are performed in accordance with ASTM D 422, with the exception of the hydrometer test (Paragraph 9, ASTM D 422 and ASTM D 1140) at the minimum rate of one test for every 1000 cubic yards, or one test per day during backfilling operations, whichever is more frequent. 3.8-69 HCGS-UFSAR Revision 0 April 11, 1988

3.8.6.2 Concrete and Concrete Materials The codes, standards, and recommendations used for construction are listed in Table 3.8-15. Some of these documents are modified to suit the particular conditions of design and construction associated with nuclear power plants without compromising structural adequacy. The extent of application and the principal exceptions are indicated herein. 3.8.6.2.1 ACI 301 ACI 301 is modified as follows:

1. Section 8.3.4 - ACI 309 is used in lieu of Section 8.3.4.

2. Section 8.4.3 - ACI 305 and ACI 306 are used in lieu of Section 8.4.3.

3. Section 12.2.1 is revised to state:

             "For concrete surfaces not in contact with forms, one of the following    procedures    shall   be   applied   immediately    after completion of placement and finishing, except that the curing process for a localized area may be interrupted as necessary, for a period not to exceed 8 hours provided that requirements for weather protection are maintained.       Such curing process may be interrupted provided that the local surface area has received a minimum   of    48 hours   of   continuous   curing   prior   to   the interruption."

4. Section 12.2.3 is revised to state:

             "Curing  in   accordance with Section 12.2.1 or 12.2.2 shall be continued for at least 7 days in the case of all concrete, except high early strength concrete, for which the period shall be at least 3 days. Alternatively, if 3.8-70 HCGS-UFSAR                                                      Revision 0 April 11, 1988

tests are made of cylinders kept adjacent to the structure and cured by the same methods, moisture retention measures may be terminated prior to 7 days when test results indicate that the average compressive strength has reached 70 percent of the specified strength, f' . The required period of initial curing c need not be greater than the lesser of the two periods. If one of the curing procedures of Sections 12.2.1.1 through 12.2.1.4 is used initially, it may be replaced by one of the other procedures of Section 12.2.1 any time after the concrete is 1 day old, provided the concrete is not permitted to become surface dry during the transition. Curing during periods of cold weather shall be in accordance with Section 12.3.1."

5. Section 12.3.1 is replaced with:

          "Initial curing and protection measures for the concrete during periods  of   cold   weather    shall   be   in   accordance   with  the recommendations of ACI 306."

6. Section 14.4.1 is replaced with:

          "The slump of the concrete as placed shall be 3 inches or less, unless indicated otherwise, except that a tolerance of up to 2 inches  above  this    maximum   shall   be  allowed   for  occasional batches,  provided    that  the   concrete   supplier   is  notified  to reduce the slump. Failure to comply shall be cause for rejection of the concrete. Concrete of lower than usual slump may be used provided that it is properly placed and consolidated."

7. Section 14.4.3 The first sentence is revised to state:

          "Concrete   shall   be   placed   in   layers   approximately   24 inches thick."

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8. Section 14.5.1 is revised to state:

             "The minimum curing period shall be 14 days after the concrete has been placed, when the mean daily air temperature is 50F or more. During cold weather, the curing period shall be 7 days."

9. Section 14.5.4 is replaced with:

             "The requirement for controlled cooling at the conclusion of the specified  heating   shall  be   accomplished  by  leaving  the  cold weather protection in place at least 24 hours after heating is discontinued."

3.8.6.2.2 ACI 318 ACI 318 is modified as follows:

1. Section 3.5.1(a) is revised as follows:

             "Specification   for   Deformed   Billet-Steel   Bars  for   Concrete Reinforcement" (ASTM A 615).      No. 14 and No. 18 bars shall be subject to the bend test of supplementary requirement, S1 of ASTM A 615. Full section bars shall be bent 90 degrees, at a minimum  temperature   of  60F,  around  an  eight-bar-diameter  pin without cracking transverse to the axis of the bar."

2. Section 5.4.4 is revised as follows:

             "Starter mixes, defined as concrete with 3/4-inch maximum size aggregate and a slump of 6 to 8 inches, shall be used as an alternative to mortar."

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3. Section 5.5 is modified by the addition of a new section:

          "5.5.3. The curing requirements described in Sections 5.5.1 and 5.5.2 may be interrupted, as necessary, for a period not to exceed 8 hours, provided that requirements for weather protection are maintained. Such curing may be interrupted, provided the local surface has received a minimum of 48 hours of continuous curing prior to the interruption."

4. Section 6.3.2.4 is replaced with:

          "Embedded piping joints, temporary or permanent, except as noted in Section 6.3.2.5, shall be leak tested prior to the placement of  concrete. Leak-testing   shall  be  in  accordance with  the requirements of the code governing that piping system e.g., ASME Boiler  and  Pressure  Vessel  Code,  ANSI  B31.1,  state  or local plumbing codes, etc.

5. Section 6.3.2.5 is replaced with:

          "Drain pipes and other piping systems not governed by applicable codes and designed for pressures of not more than 1 psig need not be tested as required above."

6. Section 6.4.1 is replaced with:

          "Joints not indicated on the plans shall be made and located so as not to significantly impair the strength of the structure.

Where a joint is to be made, the surface of the concrete shall be thoroughly cleaned and all laitance and standing water removed. Vertical construction joints shall be cleaned and roughened by waterblasting, sandblasting, or bush hammering after the concrete reaches its final set. Prior to receiving additional concrete, vertical construction joints shall be wetted." 3.8-73 HCGS-UFSAR Revision 0 April 11, 1988

7. Section 7.3.2 and related sections are replaced with:

          "7.3.2    Tolerances - Reinforcement shall be placed within the following tolerances:

7.3.2.1 For clear concrete protection from the surface of the reinforcement to the concrete surface in flexural members, walls, and compression members where member thickness is: Reduction in Increase in Member Thickness Nominal Cover Nominal Cover Less than 12 inches 3/8 inch 3/8 inch 12 inches or more 1 inch 1 inch Base mat (nominal 1 inch 1-1/2 inch 14-feet thick) 7.3.2.2 For longitudinal location of bends and ends of bars:

          ~3 inches, provided that specified nominal cover at the ends of members shall not be reduced by more than 1/2 inch."

8. Section 7.4.1 is replaced with:

          "Bar spacing: ~4 bar diameters for No. 8 bars and less, ~2 bar diameters for other bar sizes, except that the minimum clear distance between parallel bars in a layer shall be not less than the nominal diameter of the bar, nor less than 1 inch.       Where parallel reinforcement is placed in two or more layers, the bars in the upper layer shall be placed directly above those in the bottom layer, with the clear distance between the bars not less than 1 inch, unless specifically shown otherwise on the design drawings. The total number of bars shall be maintained."

3.8-74 HCGS-UFSAR Revision 0 April 11, 1988

3.8.6.2.3 Cement Cement is Type II, Portland cement conforming to ASTM C 150. Certified copies of material test reports showing chemical composition of the cement and verification that the cement complies with requirements are furnished by the manufacturer for each load of cement delivered. For every 6000 bbl of cement delivered, or for each silo of cement certified at the mill, confirmatory tests consisting of complete chemical and physical analyses are performed by the concrete supplier. 3.8.6.2.4 Normal Density Aggregates Fine and coarse aggregates conform to ASTM C 33. Aggregate source acceptability is based on the following test requirements: Method of Test Designation Organic impurities in sands ASTM C 40 Effect of organic impurities in fine aggregate ASTM C 87 on strength of mortar Soundness of aggregates ASTM C 88 Materials finer than No. 200 sieve ASTM C 117 Specific gravity and absorption of coarse ASTM C 127 aggregate Specific gravity and absorption of fine ASTM C 128 aggregate L.A. abrasion ASTM C 131 3.8-75 HCGS-UFSAR Revision 0 April 11, 1988

Method of Test Designation Sieve or screen analysis of fine and coarse ASTM C 136 aggregates Clay lumps and friable particles ASTM C 142 Potential reactivity of aggregates ASTM C 289 Petrographic examination ASTM C 295 Coarse aggregate grading is for size numbers 2, 4, 8, and 67, as defined in ASTM C 33, and the quantity of flat and elongated particles is limited to 15 percent by weight in any nominal size group. Coarse aggregate loss from the L.A. abrasion test (ASTM C 131) using Grading A is limited to 40 percent by weight at 500 revolutions. 3.8.6.2.5 High Density Aggregates The requirements for high density aggregates are the same as for normal density aggregates, except as noted below. Fine and coarse aggregates conform to ASTM C 637, except that grading is as follows: 3/8-Inch Maximum Size Aggregate Sieve Size U.S. Std. Square Mesh Percentage Passing 3/8 inch 100 No. 4 75-95 No. 8 55-85 No. 16 30-60 3.8-76 HCGS-UFSAR Revision 0 April 11, 1988

Sieve Size U.S. Std. Square Mesh Percentage Passing No. 30 15-45 No. 50 10-30 No. 100 5-15 The fineness modulus is not less than 3.0, nor more than 3.8. 3/4-Inch Maximum Size Aggregate Sieve Size Percentage Passing U.S. Std. Fine Aggregate, Coarse Aggregate, Square Mesh Sand 3/4 inch 1 inch - 100 3/4 inch - 90-100 3/8 inch 100 20-55 No. 4 95-100 2-15 No. 8 75-100 0-8 No. 16 50-85 - No. 30 25-60 - No. 50 10-30 - No. 100 5-15 - The fineness modulus of the fine aggregate is not less than 2.4 nor more than 2.9. Certified test reports are prepared by an independent testing laboratory for each material shipment, attesting to aggregate conformance to cleanliness requirements when tested per ASTM C 117 and specific gravity requirements when tested per ASTM C 127 and C 128. 3.8-77 HCGS-UFSAR Revision 0 April 11, 1988

3.8.6.2.6 Pozzolan Pozzolan, when used, conforms to ASTM C 618 for Class F, except that the maximum loss on ignition is 6 percent. Prior to use, a minimum of one sample is taken and tested for physical and chemical properties listed in ASTM C 311, except for pozzolanic activity with lime, tests for air entrainment, and for alkalies. 3.8.6.2.7 Mixing Water and Ice Water and ice used in mixing concrete is free of injurious amounts of oil, acid, alkali, organic matter, or other deleterious substances. Such water and ice do not contain impurities that would cause either a change in the setting time of Portland cement of more than 25 percent, as determined in accordance with ASTM C 266, or a reduction in compressive strength of mortar of more than 10 percent, compared with results obtained with distilled water. The water and ice do not contain more than 250 ppm of chlorides as Cl, or more than 1000 ppm of sulphates as SO . The pH range is between 5.0 and 9.75. 4 3.8.6.2.8 Admixtures Air entraining admixtures, when used, conform to ASTM C 260. Water reducing and retarding admixtures, when used, conform to ASTM C 494 for types A and D. Types A and D are used in accordance with the manufacturer's recommendations. Certificates of conformance stating conformance to the applicable ASTM specification are furnished with each shipment. Use of calcium chloride is not permitted. 3.8-78 HCGS-UFSAR Revision 0 April 11, 1988

3.8.6.2.9 Concrete Properties Concrete properties required for each type of mix design are verified by testing for the applicable properties indicated below: Property Test Designation Compressive strength ASTM C 39 Unit weight ASTM C 138 Slump ASTM C 143 Air content ASTM C 231 The following additional properties of selected mix designs are determined to ascertain material compatibility with design assumptions: Property Test Designation Modulus of elasticity ASTM C 469 Modulus of rupture ASTM C 78 Heat content: Heat of hydration ASTM C 186 Specific heat (heat capacity) Density ASTM C 138 3.8-79 HCGS-UFSAR Revision 0 April 11, 1988

3.8.6.2.10 Concrete Mix Proportions Proportions of ingredients are determined and tests conducted in accordance with ACI 211.1, except as noted below, for combinations of materials established by trial mixes. These proportioning methods provide required concrete strength, durability, and unit weight while maintaining adequate workability and proper consistency to permit required consolidation without excessive segregation or bleeding. The design strength (f' ) of mixes that contain pozzolan is measured at 90 c days; for those that do not contain pozzolan, f' is measured at 28 days. Two c cylinders are tested for each mix design and age as follows: Pozzolan Mix Nonpozzolan Mix 7 days 7 days 28 days 28 days 90 days Concrete mixes for limited use, such as in radiation-sensitive facilities and high density concrete, do not contain pozzolan. All other concrete mixes have approximately 15 to 30 percent pozzolan by weight as cement replacement. Concrete mixes, except limited application use, such as high density concrete, are based on 3 to 6% air entrainment for both 3/4 and 1-1/2 inch nominal maximum size aggregate mixes. These measures provide a concrete with good freeze-thaw and sulphate resistance. In lieu of establishing limits on water-cement ratio, the concrete is proportioned and mixed so as to be placed at specified slumps. The average slump at the point of placement is less than the "working limit," which is the maximum slump for estimating the quantity of mixing water to be used in the concrete. An "inadvertency margin" is the allowable deviation from the "working limit" for such occasional batches as may inadvertently exceed the 3.8-80 HCGS-UFSAR Revision 0 April 11, 1988

"working limit." Jobsite tests have indicated that concrete with slumps at the inadvertency margin will produce acceptable quality concrete. 3.8.6.2.11 Construction Grout Construction grout for use at horizontal construction joints and similar applications is proportioned from the same materials as for concrete. Grout strength is determined in accordance with ASTM C 109. 3.8.6.2.12 Starter Mix Starter mixes are used in such applications as at the bottom of foundation slabs or in lieu of construction grout and are proportioned from the same materials as for concrete. These mixes are generally proportioned for "working limit" slump 3 inches greater than the associated concrete mix. Trial mixes are prepared and tested for strength as described for general concrete mixes. 3.8.6.2.13 Nonshrink Grout Nonshrink grout is prepared from proprietary materials. The grout is proportioned in accordance with the manufacturer's recommendations and is tested for expansion, compressive strength, and flow characteristics with maximum water content recommended by the manufacturer, prior to use. 3.8.6.2.14 Storage and Handling Storage and handling of aggregates, cement, pozzolan, and admixtures is in accordance with the recommendations of ACI 301, Chapters 2, 3, 7, and 14, and ACI 304, Chapters 1, 2, 3, 4, and 6. Additionally, storage of cement and admixtures is in accordance with ANSI N45.2.2, Section 6.2. 3.8-81 HCGS-UFSAR Revision 0 April 11, 1988

3.8.6.2.15 Batching, Mixing, and Delivering Concrete for principal structures is provided as central mixed concrete from a batch plant located on the jobsite. Some limited amounts of concrete are obtained from an offsite batch plant. All such batch plant facilities are certified by the National Ready Mix Concrete Association (NRMCA) and measuring devices are calibrated at required intervals and more frequently when deemed appropriate. Measuring of materials, batching, mixing, and delivering of all concrete conform to ASTM C 94, except as otherwise noted. 3.8.6.2.16 Conveying and Placing Conveying and placing of concrete is in accordance with the recommendations of ACI 301, Chapters 6 and 8 through 15, and ACI 304, Chapters 5 and 6. 3.8.6.2.17 Consolidation Consolidation of concrete is in accordance with the recommendations of ACI 309. 3.8.6.2.18 Curing Curing of concrete is in accordance with the recommendations of ACI 301, as modified herein. 3.8.6.2.19 Hot and Cold Weather Concreting Measures taken to mitigate the effects of hot and cold weather during each step of the concreting operation are in accordance with ACI 305 and 306, respectively. 3.8-82 HCGS-UFSAR Revision 0 April 11, 1988

3.8.6.2.20 Concrete and Concrete Materials-Construction Testing An independent concrete and concrete materials testing laboratory is established at the project site to monitor the quality of such work and materials and to promptly report any deviations from specified conditions. Such testing personnel are qualified to meet the requirements of ANSI N45.2.6. Procedures and tests for accomplishing such work are reviewed and accepted by Bechtel prior to use. Production testing for concrete and concrete materials is as shown in Table 3.8-16. Materials that do not meet test requirements are not used in the construction. If the measured concrete temperature, slump, unit weight, or air content falls outside the limits specified, a check is made. In the event of a second failure, the remaining concrete is not used in the construction. Concrete cylinder test results are reviewed for compliance with Section 4.3.3 of ACI 318 and are evaluated in accordance with ACI 214. 3.8.6.2.21 Formwork and Construction Joints Formwork is designed and constructed so that the final structure conforms within the specified tolerances to the shape, lines, and dimensions required by the design drawings. The design includes consideration of the following:

1. Rate and method of placing concrete

2. Density of concrete 3.8-83 HCGS-UFSAR Revision 0 April 11, 1988

3. Construction loads, including vertical, horizontal, and impact loads.

Prior to concrete placement, construction joints are cleaned to remove unsatisfactory concrete, laitance, coatings, debris, and other foreign material and to expose the aggregate. The joints are then saturated to produce a saturated surface dry condition. Horizontal construction joints are then covered with grout or a layer of starter mix which is approximately 4 to 6 inches deep. 3.8.6.3 Reinforcing Steel 3.8.6.3.1 Material Reinforcing steel for concrete structures conforms to ASTM A 615, Grade 60, including Supplementary Requirements S-1 for bar sizes 14 and 18. Certified copies of material test reports indicating chemical composition, physical properties, and dimensional compliance for each heat are furnished by the manufacturer. Each bundle of reinforcing steel is tagged to ensure heat traceability during production, while in transit, and into storage. During storage and installation, reinforcing steel is collectively traceable to the group of certified material test reports. Prior to installation, all reinforcing steel is subjected to a test program meeting the requirements of Regulatory Guide 1.15. Reinforcing steel that does not meet these requirements is not used. 3.8.6.3.2 Fabrication Hooks and bends are fabricated in accordance with ACI 318, Chapter 7.1. Bending of partially embedded bars is subject to the following conditions: 3.8-84 HCGS-UFSAR Revision 0 April 11, 1988

The minimum distance from concrete surface to the beginning of bend and the minimum inside diameter of bend is: Minimum Distance from Surface to Minimum Inside Bar Size Beginning of Bend Bend Diameter No. 3 through No. 8 3 bar diameters 6 bar diameters No. 9, No. 10, 4 bar diameters 8 bar diameters No. 11 No. 14, No. 18 5 bar diameters 10 bar diameters Bar sizes No. 3, 4, and 5 may be bent cold once. Heating is required for subsequent straightening or bending. Bar sizes No. 6 through 9 may be bent and straightened, provided that heating is used. These bars may be bent over and straightened once cold when the bend does not exceed 30 degrees. Heat is applied uniformly over a length of bar equal to 10 bar diameters, centered at the middle of the arc of the completed bend. The maximum bar temperature is maintained between 1100 and 1200F until bending is completed. Temperature measuring crayons or a contact pyrometer is used to determine the temperature. Heat is applied in such a way as to avoid damage to the concrete. Care is taken to prevent rapid cooling of heated bars. Straightened bars are visually inspected to determine whether they are cracked, reduced in cross section, or otherwise damaged. Any damaged portions are removed and replaced. Bar sizes No. 10 and larger are bent only if approved by the responsible field engineer. Heating is required except when bending of bars does not exceed an offset of 1:6 where required to put bars 3.8-85 HCGS-UFSAR Revision 0 April 11, 1988

in proper position. When only cold bend is applied, the distance between the beginning of the bend and the existing concrete may be decreased to a minimum of 0.5 bar diameter. 3.8.6.3.3 Splices Lapped splices, used for No. 11 and smaller bars, are in accordance with Sections 7.5, 7.6, and 7.7 of ACI 318. Mechanical (Cadweld) splices are used for all No. 14 and No. 18 splices. These bars are located in the basemat and fuel pool's walls and slab. Cadweld splices are also used locally on other bar sizes in lieu of standard hooks and to minimize rebar congestion at plate anchorages and construction openings. To obtain effective quality control, a qualification, inspection, testing, and acceptance program in accordance with NRC Regulatory Guide 1.10 is used (See Section 1.8.1.10). Welding of splice sleeves to liners, plates, and shapes is in accordance with AWS D1.1. Welded splices have not been used. The requirements of Regulatory Guide 1.136, Revision 2, are not implemented in the design, since significant concrete work using cadwelds was completed prior to issuance of this guide. As a result both sister and production splicing have been used for testing of cadweld splices. Where sufficient bar length exists future cadwelding will be in accordance with Regulatory Guide 1.136, Revision 2. 3.8.6.3.4 Placing Reinforcement Reinforcement is securely tied with wire and held in position by spacers, chairs, and other supports to maintain placement accuracy within the tolerances established for reinforcement protection and design requirements. 3.8-86 HCGS-UFSAR Revision 17 June 23, 2009

3.8.6.3.5 Spacing of Reinforcement Spacing of reinforcement is in accordance with Sections 3.3.2 and 7.4 of ACI 318, except as modified herein. 3.8.6.3.6 Surface Conditions of Reinforcement Surface conditions of reinforcement at the time of concrete placement are in compliance with Section 7.2 of ACI 318. 3.8.6.3.7 Reinforcement Placing Tolerance The section strength for reinforced concrete is based on the strength design method of ACI 318 and on the reduced effective depth (d) resulting from specified rebar placing tolerances in excess of those specified in ACI 318, Section 7.3.2.1. The effective depth is reduced by an additional 1/2 inch for all members greater than 12 inches but not greater than 24 inches and by an additional 1 inch for all members greater than 24 inches. The cover used in calculating the effective depth is the "nominal cover" as set forth in Table 3.8-17. The above design considerations allow the reinforcement placing tolerances, as defined in Section 3.8.6.2.2. 3.8.6.4 Structural Steel 3.8.6.4.1 Materials The various structural steel components conform to the following ASTM specifications: Item ASTM Specification Beams, girders, and plates A 36 or A 441 Structural tubing A 500 3.8-87 HCGS-UFSAR Revision 0 April 11, 1988

Item ASTM Specification Anchor bolts A 36 or A 307 High strength bolts A 325 or A 490 3.8.6.4.2 Fabrication and Erection The fabrication and erection of structural steel conforms to the AISC specifications. 3.8.6.4.3 Welding and Nondestructive Testing Welding and nondestructive testing is performed in accordance with either AWS D1.1 or Section IX of the ASME B&PV Code, as shown in Table 3.8-15. 3.8.7 References 3.8-1 K.R. Wichman, A.G. Hopper, and J.L. Mershon, "Local Stresses in Spherical and Cylindrical Shells Due to External Loadings," Welding Research Council Bulletin 107, August 1965, third revised printing, April 1972. 3.8-2 General Electric, "Mark I Containment Program Load Definition Report," Revision 2, November 1981. 3.8-3 General Electric, "Mark I Containment Program Plant Unique Load Definition, Hope Creek Generating Station: Unit 1," Revision 1, January 1982. 3.8-4 Bechtel Power Corporation, "Design for Pipe Break Effects," BN-TOP-2, Revision 2, May 1974. 3.8-5 N.M. Newmark, et al., "Air Force Design Manual Principles and Practices for Design of Hardened Structures," December, 1962 3.8-88 HCGS-UFSAR Revision 8 September 25, 1996

3.8-6 Norris, Hansen, Holley, Biggs, Namyet and Minami, "Structural Design for Dynamic Loads" 3.8-7 Bechtel Power Corporation, "Containment Building Liner Plate Design Report," BC-TOP-1, Revision 1, December, 1972. 3.8-89 HCGS-UFSAR Revision 0 April 11, 1988

• TABLE 3.8-1 IX>DES, STANDARDS, AND SPECIFICATIONS USED IN DESIGN AND CX)NSTRliCI'lON OF 'IHE PRIMARY CX)NTAINf':IBNT Designation Title Edition American SocietY of Mechanical Erutineers tASME I ASME A.SME B&PV Code

a. Section III, Subsection NA, General Requirements 1974 with Winter 1974 Addenda

b. Section III, Subsection NE, Class t£ (:apponents 1974 with Winter 1974 Addenda

c. Section III, Subsection NF, Canponent Supports 1974 with Winter 1974 Addenda

d. Code Case 1567, Testing Lots of Carbon and Low Alloy Steel Approved by Council Covered Electrodes, Section III March1973

e. Code Case 1557, Steel Products Refined by Seco.ndary Approved by Council Remelting. Section III and VIII, Divisions 1 and 2 December 17, 1973

f. Code Case 1644, Additional Materials for Component Approved by Council Supports and Alternate Design Requirements for Bolted March 3, 1976 Joints, Section III, Division 1, Subsection NF, Class 1, 2, 3 and r£ ConstrtK}tiOn

g. Code Case 1648, SA537 Plates for Section III, Class 2, Approved by Council 3 and 1'1::: Components August 12, 1974

h. Code Case N-236, Repair and Replacement of Class 1'1::: Approved by Council Vessels, Section XI, Division 1 January 21, 1982

i. Code Case N-242, Material Certification, Section III, Approved by Council Division 1, Class 1, 2, 3, I£ and CS ConstrtK}tion April_ 12, 1979

j. Code Case N-252, Law Energy Capacitive Discharge Approved by Council Welding Method for Temporary or Permanent Attachments November 19, 1979 to Components and Supports, Section III, Division 1, and Section XI

k. Code Case N-284, Metal Contairunent Shell Buckling Approved by Council Design Methods, Section Ill, Division 1, Class r<<:: August 25, 1980

1. Code Case N-308, Documentation of Repairs and APProved by Council Replacement of Components in NuclearPower Plants September 30, 1981

m. Code Case N-313. Alternative Rule for Half-coupling Approved by Council Branch Connections, Section III, Division 1 May 11, 1981 1 of 2 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3. 8-1 ICont) Desisnation F.d.ition

n. Section IX, Welding and Brazing Qualification 1974 with Winter 1974 Addenda

o. Section XI, Rules for Inservice Inspection of 1980 with Winter 1981 Nuclear Power Plant Components, Division 1 Addenda

p. Code Case N-362-2, PressureTesting of Containment Approvaldate:

Items, Section III , Division 1, Classes 1 , 2 and ~ July 12, 1984 American Concrete Institute (ACI) ACI 318 Building Code Requirements for Reinforced Concrete 1971 The Institute of Electrical ard Electronic Engineers, Inc CIEEE) IEEB 317-72 IEEE Standard for Electric Penetration Assemblies in Containment 1972 Stn10tures for Nuclear Power Generating Stations IEEE 383-74 IEEE Standard for Type Test of Class lE Electric Cables, 1974 Field Splices, and Connections for Nuclear Power Generating Stations American National Standards Institute tANS!) ANSI A58 .1-1972 Building Code Requirements for Mininn.m Design Loads in 1972 Buildings and other StnJCtures ANSI N45.4-1972 Leakage Rate Testing of Containment Stn10tures for 1972 Nuclear Reactors ANSI N45.2 Quality Assurance ProgramRequirements for Nuclear Power Plants 1971 American Society of Testing and Materials

          !AS'IM)

AS1M A 572 Standard Specification for High Strength Low Alloy 1973 Colunbiun-Vanadiun Steels of Structural Quality 2 of 2 HCGS-UFSAR Revision 0 April 11, !988

TABLE 3.8-2 LOADING CCf!1BINATIONS AND AI...U)WABLE STRESSES FOR IRIMARY CONTAINMENT ASME Section III 1~}8.1 12 ) Primary i:(Z) Table l ParagraJlh General ( 2 J Local( 2 ) Membrane Secondary Combination ( 1 ) Region Membrane Membrane &. Bending Stresses sm or S sy sc p pl pl + p p + p + Q Buckling( 3 ) m 1b D+L+Pt+Tt+E 1-2.0 NE-3133 All 0.85 8 1.25 sy 1.25 s7 1.25 8c 1 D+L+F tT +Ro I-10.0 NE-3133 All 1.5 8m Greater Greater 1.20 s0 1 0 of t.s 8Y of 1.5 8Y or 1.8 sm or 1.8 Sm D+L+T + R I-10.0 NE-3133 All sm 1.5 sm 1.5 sm 3.0 8(4) 8 0 0 c D+L+T +R +E+P 0 0 0 D+L+T +R +P +E a a a I-10.0 NE-3133 All 8 m 1.5 sm 1.5Sm s0 D+L+Te +R e +Pe +E D+L+T +R8 8+P +E 8 D+L+Ta+R +Pa+E' a I-10.0 NE-3133 Nonintegral A: s 1.5 s 1.5S s0 D+L+Te +R e e +P +E' noncontinuous D+L+T8 8+R 8

                  +P +E'           I-10.0    1-2.0    NE-3133   Integral &         Greater       Greater     Greater                    1.28 0

continuous of S y or of 1.5 Sy of 1.5 s 1 1.2 sm or 1.8 Sm or 1.8 Sm D+L+Ta+Ra+P +Yr +Y.+Y +E' 1-10.0 1-2.0 NE-3133 Nonintegral & Greater Greater Greater 1.28 a J m c D+L+T +R +P +Y +Y.+Y +E' ss r J m noncontinuous of Sy or of 1.5 s of 1.58y 8 1 1.2 s m or 1.8 sm or 1.8 sm D+L+Ta +Ra+Pa +Yr +Y.+Ym+E' F-1324 NE-3133 Integral & 0.85 s 1.28 s 1.28 s 1.28 sc J D+L+T8 8+R +P +Yr +Y.+Ym+E' continuous 8 J D+L+F +E +T +R I-10.0 1.2.0 NE-3133 All 1.5 8 m Greater Greater 1.2 sc of 1.5 s of 1.5 Sy 1 or 1.8 sm or 1.8 s m 1 of 3 HCOS-UFSAR Revision 0 April 11, 198t3

TABLE 3.8-2 (Cont)

11) Load definitions:

D Dead loads L Live loads Test pressure Test temperature Thermal effects arid loads during startup, normal operating, or shutd.O'wn conditions, based on the most critical transient or steady state condition Pipe reactions during startup, normal operating, or shutdown conditions, based on the most critical transient or steadystate condition Pressure loads during startup, normal operating, or shutdown conditions Design external pressure Thermal loads under thermal conditions during event causing external pressure Pipe reactions under thermal condi tiona during event causing external pressure Loads generated by the operating basis earthquake, including sloshing effects, if applicable E' Loads generated by the safe shutdown earthquake, including sloshing effects, if applicable Pressure equivalent static load !:.!enerated by the postulated design basis accident, including P , pool swell, and 0 subsequent hydrodynamic loads Thermal loads under thermal conditions generated by the postulated pipe break accident, including T , pool swell, 0 and subsequent hydrodynamic reaction loads R Pipe reactions under thermal conditions generated by the postulated pipe break accident, including R , pool swell, a 0 and subsequent hydrodynamic reaction loads All pressure loads which are caused by the actuation of safety/relief valve discharge* All thermal loads which are generated by the actuation of safety/relief valve discharge All pipe reaction loads which are generated by the actuation of safety/relief valve discharge Equivalent static load on the structure generated by the reaction on the broken pipe during the design basis accident 2 of 3 HCGS-UFSAR Revision 0 April 11 , 1988

TABLE 3.8-2 (Cont) Jet impingement equivalent static load on the structure generated by the broken pipe during the design be..sis accident Missile impact equivalent static load on the structure generated by or during the design be..sis accident, such as pipe whipping F Loads generated by the post-LDCA flooding of the pri.mary containment, if any (2) For definitions of Pm' P , Pb and Q, see FigureNE-3222-1 of the ASMB B&PV Code. 1 ( 31 A factor of two shall exist between the critical buckling stress and the applied stress where a rigorous buckling analysis is performed that considers inelastic behavior. (4) Fatigue analysis shall be performed for loading oanbinations listed, except post-ux::A flooding. 3 of 3 HCGS-UFSAR Revision 0 April ll, 1988

TABLE 3.8-3 Plate and Shell Type Component ASME Section III Supports Table I Paragraph Notes Combination( 4 ) s sc Tension Comp (1) D+L+Pt+Tt+E I-7.0 or 1-8.0 NC-3133 s 1.58 D+L+T + R or I-12.0 or or 0 0 D+L+T +R +E+P Code Case 1644 ND-3133 0 0 D+L+T +R +P +E Or aaa D+L+Te +Ree

                       + P +E                             NE-3133 D+L+T +R +P +E sss (2)

D+L+Ta +Ra a +P +E' I-7.0 or 1-8.0 NC-3133 or 1.2 s 1.2 s0 1.88 D+L+Te+Re+Pe+E' or 1-12.0 or ND-3133 or D+L+T +R +P + E' Code Case 1644 NE-3133 8 ss (3) D+L+Ta +Ra a +P r +Y +YJ.+Ym+E' I-7 .0 or 1-8.0 NC-3133 or 2.0 s 1.28 sc 2.4 s D+L+T +R +P +Y.+Y +Y +E' or I-12.0 or ND-3133 or ssr J m D+L+T0 +R0 +F1+E Code Case 1644 NE-3133 ( 1) Linear type component supports - Stress limits given by Appendix XVII ( 2) Linear type component supports - Appendix XVII allowables increased by a factor of 1. 33 ( 3) Linear type component supports - Paragraph F-1370, Appendix F (4) Load definitions: D Dead loads L Live loads Pt Test pressure Tt Test temperature 1 of 3 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.8-3 (Conti Plate and Shell Type Component ASME Section III Supports Table I Paragraph Notes Combination( 4 ) s Tension Camp T Thermal effects and loads during startup, normal operating, or shutdown 0 conditions, based on the most critical transient or steady state condition Pipe reactions during startup, normal operating, or shutdown conditions, based on the most critical transient or steady state condition Pressure loads during startup, normal operating, or shutdown conditions Design external pressure Thermal loads tmder thermal conditions during event causing external pressure Pipe reactions under thermal COildi tions during event causing external pressure E Loads generated by the operating basis earthquake, including sloshing effects, if applicable E' Loads generated by the safe shutdown earthquake, including sloshing effects, ifapplicable Pressure equivalent static load generated by the postulated design basis accident, including P , pool swell, and subsequent hydrodynamic loads 0 Thermal loads under thermal condi tiona generated by the postulated design basis accident, incluiing T , pool swell, and subsequent hydrodynamic reaction loads 0 Pipe reactions under thermal conditions generated by the postulated design basis accident, including R , pool swell, and subsequent hydrodynamic reaction loads All pressure loads wich are caused by the actuation of safety/relief valve discharge All thermal loads which are generated by the actuation of safety/relief valve discharge All pipe reaction loads which are generated by the actuation of safety/relief valve discharge Equivalent static load on the structure generated by the reaction on the broken pipe during the design basis accident Y. Jet impingement equivalent static load on the structure generated by the broken pipe during J the design basis accident 2 of 3 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.8-3 (Cont) Missile im.pact equivalent static load on the structure generated by or during the design basis accident, such as pipe whipping Loads generated by the post-LOCA flooding of the primary containment, i f any 3 of 3 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.8-4 LOAD COMBINATIONS FOR REINFORCED CONCRETE SEISMIC CATEGORY I STRUCTURES IN THE PRIMARY CONTAINMENT

a. For normal and severe environmental conditions, the following load combinations and allowables(l) are considered:

U- 1.4D + 1.7L U- 1.4D + 1.7L0 + 1.9E 0 When thermal stresses due to T and R are present, the 0 0 following combinations are considered: U- (0.75) (1.4D + 1.7L + 1.7T0 + 1.7R) 0 U- (0.75) (1.4D + 1.7L0 + 1.9E0 + 1.7T0 + 1.7R0 )

b. For extreme environmental, abnormal, abnormal/severe environmental, and abnormal/extreme environmental conditions ,

the following load combinations and allowables(l) are considered: U -D + L0 + T0 + R0 + E' U -D + L + Ta a + R + 1.5P U- 1.4D + 1.7L + F U -D + Lo a+a T a r o + R + 1.25P + R + 1.25E U -D + L0 + E0 + F1 U -D ar + R

              + Lo a+a T           +P    +R      + E' (1)   Symbols used in load combinations:

D Dead loads Eo Operating basis earthquake loads E' Safe shutdown earthquake loads F Post-accident containment flooding loads L Live loads

• HCGS-UFSAR 1 of 2 Revision 0 April 11, 1988

TABLE 3.8-4 (Cont)

• L 0

Operating live loads (combined with seismic .loads) - The live load expected to be present when the plant is operating, established requirements. in accordance These loads with may the vary, layout and mechanical depending upon the function of a specific area P Abnormal pressure loads a T Abnormal temperature loads a T Operating thermal loads 0 R Abnormal pipe reaction loads a R Operating pipe reaction loads 0 R r Abnormal local effects, including reactions from pipe rupture, jet impingement, pipe whip, or any nonmechanistic - break inside the bioshield U The section strength, based on the strength design method of ACI-318 (2) Both cases of L (or L ) , having its full value or being 0 completely absent, are checked .

• HCGS-UFSAR 2 of 2 Revision 0 April 11, 1988

TABLE 3.8-5 LOAD COMBINATIONS FOR DRYWELL STRUCTURAL STEEL SEISMIC CATEGORY I STRUCTURES

1. For normal and severe environmental conditions, the following load 1

combinations and allowables{ ) are considered: S D + L S D+L +E 0 0 When thermal stresses due to T and R are present, the following 0 0 combinations are considered: 1.58 D+ L + T + R 0 0 1.58 D+ L + T + R + E 0 0 0 0 I

2. For extreme environmental, abnormal, abnormal/severe environmental, and abnormal/extreme environmental conditions, the following load combinations 1

and allowables( ) are considered: 1.68 D+L + T0 + R0 + E' 0 1.68 D + L + Ta a+a R + P S == D + L + FL

1. 6S D+ L 0

                         + Ta + Ra + p a + Rr + E0

1. 6S D + L + E0 + FL 0

1.78 D + L + T + R + p + R + E' 0 a a a r (1) Symbols used in load combinations: D Dead loads E Operating basis earthquake loads 0 E' Safe shutdown earthquake loads FL Post-accident containment flooding loads L Live loads 1 of 2 HCGS-UFSAR Revision 17 June 23, 2009

TABLE 3.8-5 (Cont) L Operating live loads (combined with seismic loads) - The live 0 load expected to be present when the plant is operating, established in accordance with the layout and mechanical requirements. These loads may vary, depending upon the function of a specific area. p Abnormal pressure loads T Abnormal temperature loads T Operating thermal loads R Abnormal pipe reaction loads a R Operating pipe reaction loads 0 R Abnormal local effects, including reactions from pipe rupture, jet impingement, and pipe whip. In load combinations involving R , the corresponding structural acceptance criteria (1.6S or 1.78) is first satisfied without considering the effect of R . When considering the effects 1 of R , local section strength capacities may be exceeded provided that there will be no loss of function of any safety related system. The local effects are evaluated in accordance with Bechtel Topical Report BN-TOP-2 (Reference 3.8-4). s The section strength, determined as the allowable set forth in the AISC Specification for the Design, Fabrication, and Erection of Structural Steel for Buildings, Part I. (2) Both cases of L (or L ) , having its full value or being 0 completely absent, are checked .

• HCGS-UFSAR 2 of 2 Revision 0 April 11, 1988

TABLE 3.8-6 ALLOWABLE STRESSES FOR SUPPRESSION CHAMBER INTERNAL STRUCTURES OUTSIDE THE SCOPE OF THE ASME CODE(l) Combination( 2 ) Allowables D + L + Pt + Tt D+L+F 1 D+L+T +R Stress limits in accordance with 0 0 the AISC Code D+ L +T + R0 + E 0 D+L+ T +R + p + E aaa D + L + T e +Re e+ p + E

• D+L+Ts s+R s + p + E D + L + T + R + P + E' aaa D + L + T + R + Pe + E' 1.5 times the stress limits in ee accordance with the AISC Code.

D + L + F1 + E D + L + Ts s+s R + P + E' (1) The allowable stresses for the structures within the scope of the ASME B&PV Code are given in Table 3.8-2. (2) For the definition of symbols used in the load combinations, see Table, 3.8-2 . 1 of 1 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.8-7 LIST OF APPLICABLE CODES, STANDARDS, RBCC.fotiENDATIONS, AND SPECIFICATIONS Desisnation Edition 11 ) ACI American Concrete Institute: 318 Building Code Requirements for Reinforced Concrete 1971, with the 1974 supplement, including 1973 and 1974 revisions 531 Building Code Requirements for Concrete Masonry 1979 Structures AISI American Iron and Steel Institute: Specification for the Design of Light Gauge 1968 Cold-Fonned Steel Structural Members AISC American Institute of Steel Construction: February 12, 1969 with: Specification for the Design, Fabrication, and SUpplement 1 of Nov 1, 1970 Erection of Structural Steel for Buildings SUpplement 2 of Dec 8, 1971 and Supplement 3 of June 12, 1974 ANSI American National Standards Institute: A58.1 Building Code Requirements for MiniDun Desisn Loads 1972 in Buildings and Other Structures AREA American Railway Engineering Association: Manualfor Railway Engineering (for possible future March 1972 railway) ASME American Society of Mechanical Engineers: Boiler and Pressure Vessel Code Section II Materials Specifications 1974 with Winter 1974 Addenda Section III Nuclear Power Plant Components 1974 with Winter 1974 Addenda Section V Nondestructive Examination 1974 with Winter 1974 Addenda Section IX Welding and Brazing Qualifications 1974 with Winter 1974 Addenda Section XI Inservice Inspection 1974 with Winter 1974 Addenda AWS American Welding Society: D 1.1 Structural Welding Code !See NCIG-01) 1975 NML Nuclear Mutual Limited: Property Loss Prevention Standards 1 of 2 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.8-7 (COntJ Designation Edition(!) NCIG-01 Nuclear Construction Issue Group 5/7/1985, Rev 2 Visual Weld Acceptance Criteria PCA Portland Cement Association: Design. of Multistory Reinforced Concrete Buildings 1961 for Earthquake Motions J.A. Blune, N.M. Newmark, and L.H. Corning UBC International Conference of Building Officials: Uniform Building Code 1973 ( 1} Principle editions used are listed; later editions may be applied in specific cases. 2 of 2 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.8-8 LOAD COMBINATIONS FOR REINFORCED CONCRETE SEISMIC CATEGORY I STRUCTURES OTHER THAN THE PRIMARY CONTAINMENT AND ITS INTERNALS

1. For normal and severe environmental conditions, the following load combinations and allowables are considered:

U - 1.4D + 1.7L U- 1.4D + 1.7L + 1.9E 0 0 U- 1.40 + 1.7L + 1.7W If the thermal stresses due to T and R are present, the 0 0 following combinations are considered: u- (0.75) (1.40 + 1.7L + 1.7T + 1.7R) 0 0 u- (0.75) (1.40 + 1.7L + 1.9E + 1.7T + 1.7R) 0 0 0 0 u- (0.75) (1.4D + 1.7L + 1.7W + 1.7T 0

                                                              + 1.7R) 0 In addition, the following combinations are considered:

U - 1. 2D + 1 . 9E 0 U - 1.2D + 1.7W

2. For extreme environmental, abnormal, abnormal/severe environmental, and abnormal/extreme environmental conditions, the following load combinations and allowables are considered:

U-D+L +T +R +E 0 0 0 s U-D+L+T +R +W 0 0 t U-D+L+To o+R e

                                      +W U- D + L + T + R +                1.5P aaa U -D + L + oTa+a R aro
                          +              1.25P + R +      1.25E U-D+Lo .+T     a a a r+R s       +P +R +E

• HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

TABLE 3.8-9 LOAD COMBINATIONS FOR REINFORCED CONCRETE

• NON-SEISMIC CATEGORY I STRUCTURES (l)

1. U- 1.4D + 1.7 L

2. U- 0.75 (1.4 D + 1.7 L + 1.87 E)+ 1.0 R ( 2 )

0 u 0

3. U- 0.75 (1.4 D + 1.7 L + 1.7 W) + 1.0 R ( 2 )

0

4. U- 0.9 D + 1.3 W + 1.0 R ( 2 )

0

5. U- 0.9 D + 1.43 E + 1.0 R ( 2 )

u 0 In addition to the requirements above, the structures are checked to verify that they do not collapse on, or interact with, adjacent Seismic Category I structures for the following load combinations under abnormal and/or extreme environmental conditions: 2)

6. U -D + L + E + T + R (

0 s 0 0

7. U -D + L + W +T + R ( 2) t 0 0

8. U -D + L + W+ T + R ( 2) eoo

9. U- D + L + Ra a+a 1.5 P + T 1 10. U -D + L0 + Ra + Rr + Pa s+a E + T (1) The Turbine Building and the administration facility.

(2) R , which produces the most critical combination loading, is 0 used .

• HCGS-UFSAR 1 of 1 Revision 0 April 11,1988

TABLE 3.8-10 LOAD COMBINATIONS FOR STRUCTURAL STEEL SEISMIC CATEGORY I STRUCTURES OTHER THAN THE PRIMARY CONTAINMENT AND ITS INTERNALS(!)

1. For normal and severe environmental conditions, the following load combinations and allowables are considered:

S- D + L S-D+L0 +E 0 S D+L+W If thermal stresses due to T and R are present, the following 0 0 combinations are also considered: l.SS - D + L + T0 + R0 l.SS - D + L0 + T0 + R0 + E0 l.SS - D + L + T0 + R 0+ W

2. For extreme environmental, abnormal, abnormal/severe environmental, and abnormaljextreme environmental, the following load combinations and allowables apply:

1.6S D+L+T+R+ E 0 0 0 s 1.68 D + L + T0 + R0 + Wt 1.6S - D + L + T +o o e R + W 1.6S -D + L + T a a+a R + P 1.68 - D + Lo a+a aTr o+ R + P + R + E 1.7S- D + Lo a+a T a r s+ R + P + R + E (1) Also applicable to composite (structural steel and concrete) construction .

• HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

TABLE 3.8-11 LOAD COMBINATIONS FOR STRUCTURAL STEEL AND CONCRETE MASONRY NON-SEISMIC CATEGORY I STRUCTURES (l) S- D + L 1.33S - D + L + E + R ( 2) 0 u Q 1

• 33S - D + L + W + R 0 (~)

S- D + L + E + R ( 2 )( 3 ) 0 u 0 In addition to the requirements above, the structures are checked to verify that they do not collapse on. or interact with, adjacent Seismic Category I structures for the following load combinations for structural steel structures under abnormal and/or extreme environmental conditions: l.SS D+L+T+R( 2) 0 0 0 1.6S D + L + E + T + R ( 2) 0 s 0 ~ 1.65 D + L + W + T + R 2) t 0 0 1.6S -D + L + W + T + R. ( 2 ) eoo 1.6S -D + L + Ra a+a P + T 1.7S- D + L + R + R + P + E + T 0 arasa (1) The Turbine Building and the administration facility. (2) R , which produces the most critical combination of loading, is 0 used. (3) This load case is used only for structural elements carrying mainly earthquake forces, e.g., struts and bracings .

• HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

TABLE 3.8-12 SYMBOLS USED IN LOAD COMBINATIONS Symbol Description D Dead loads E Operating basis earthquake loads 0 E Safe shutdown earthquake loads s E UBC seismic zone 1 loads u H(l) Lateral earth pressure L Live loads L Operating live loads (used with seismic loads) 0 p Abnormal pressure loads a R a -- Abnormal pipe reaction loads Ro Operating pipe reaction loads R Abnormal local effects of pipe rupture r R See Section 3.8.4.3.1.4.4(1) rr Rrj -- See Section 3.8.4.3.1.4.4(2) R See Section 8.3.4.3.1.4.4(3) rm

• HCGS-UFSAR 1 of 2 Revision 0 April 11, 1988

TABLE 3.8*12 (Cont)

• Symbol s

Description Section strength for structural steel determined as the allowable set forth in the AISC specifications, as listed in Table 3.8-7. T Abnormal temperature loads a T Operating thermal loads 0 u Section strength for reinforced concrete based on the strength design method of ACI 318 as listed in Table 3.8-7, and a reduced effective depth (d), resulting from specified rebar placing tolerances in excess of those specified in ACI 318. Severe wind loads we Extreme wind and flood loads Tornado loads See Section 3.8.4.3.1.3.2 See Section 3.8.4.3.1.3.2 See Section 3.8.4.3.1.3.2 (1) Combinations including this load are described in Section 3.8.5

• HCGS-UFSAR 2 of 2 Revision 0 April 11, 1988

TABLE 3.8-13

SUMMARY

OF STRUCTURAL FOUNDATIONS Elev, Top of Elev, Bottom Vincentown Type of Structure of Base Mat(l) Formation( 2 ) Foundation PSE&G CGS PSE&G Datum Datum Datum Reactor +40.0 -49.0 +36.0 Base mat bearing on Building~ engineered backfill Mat 3 and/or concrete fill on Vincentown Formation Auxiliary +40.0 -49.0 +36.0 Base mat bearing on Building, engineered backfill Mat 5, and and/or concrete fill on parts of Vincentown Formation Mats 3 and 4 Turbine +40.0 -49.0 +36.0 Base mat bearing on Building, engineered backfill Mat 1 and/or concrete fill on Vincentown Formation ssws +65.5 -22.0 +25.0 Direct bearing of intake* slab on the Vincentown structure, Formation by placing Mat 6 a tremie concrete plug between the top of the Vincentown Formation and the bottom of the base slab . 1 of 2 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.8-13 (Cant)

• (1)

(2) Grade level at +101.5 PSE&G datum or +12.5 CGS datum Elevations shown are average .

• HCGS-UFSAR 2 of 2 Revision 0 April 11, 1988

TABLE 3.8-14 GROUNDWATER TABLE RESTRICTIOOS FOO POWER BlOCK ca1PLEX 1 Area (See Key Plan - FiKUre 3. 8-37 ) ( ) Auxiliary Building Control/Diesel Reactor Building and Generator Area and Southern Section of Plant Cancelled~ and Central Section of Maximum Allowable Rad.waste/Service Area Northern Section of the Radwaste/Service Water Table Elevation Turbine Building of Auxiliary Building Rad.waste/Service Area Area Mat 1 Mat3 Mat4 Ma.t5 (Same for Administration Facility - Mat 2) Natural water table all concrete walls All floors to El 132; Selected floors to All to El 155 Bl 96 ft and floor slabs to floors and cylinder El 102; Cylinder (dewatering discontinued) El 137; walls to El 145; walls to El 132; Turbine pedestal drywell shield to El 98; Drywell shield to El 98; concrete complete exterior walls to Exterior walls to El 132 i selected El 132; selected interior walls to interior walls to El 102 Bl 102 77 ft (dewatering) All walls to El 77; Cylinder wll to El 77 ; Cylinder wall to El 77; All to Bl 102 floor slab to El 77; drywell shield to drywell shield to turbine pedestal El 71 ft 8 in.; El 71 ft 8 in. ; complete except for exterior walls to exterior walls to center portion of El 102; interior walls El 102; interior walls top deck to Bl 77 to El 77 52 ft (dewatering) Entire base slab Entire base slab Entire base slab Entire base slab {1 )There is no dewatering for Mat 6, SSWS intake structure, mtil the tremie concrete plug is placed and cured. 1 of 1 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.8-15 LIST OF APPLICABLE CODES, STANDARDS, RBO:M1J'fiDATICl>iS, AND SPECIFICATIONS Designation Title Edition American Concrete Institute ACI 211.1 Recorrmended. Practice for Selecting Proportions for Normal 1974 and Heavyweight Concrete ACI 214 Recommended Practice for Evaluation of COmpression Test 1965 Results of Field Concrete ACI 301 Specifications for Structural Concrete for Buildings 1972, 1973 ACI 304 Recoulnended Practice for Measuring t Mixing, Transporting, and 1973 Placing Concrete ACI 305 Recortmended Practice for Hot Weather Concreting 1972 ACI 306 Reooumended Practice for Cold Weather Concreting 19~6 ACI 309 Recommended Practice for Consolidation of Concrete 1974 ACI 315 Manual of Standard Practice for Detailing Reinforcing 1974 Concrete Structures ACI 318 Building Code Requirements for Reinforced Concrete 1971 American Welding Society AWS Dl.l Structural Welding Cede (See NCIG-0 1) 1975 AWS Dl2.1 Reconmended Practice for Welding Reinforcing Steel and 1975 Connections in Reinforced Concrete Construction U.S. Nuclear Regulatory Ccmnission RG 1.10 Mechanical (Cs.dweld) Splices in Reinforcing Bars of Revision 1 Category I Concrete Structures Jan 1973 RG 1.15 Testing of Reinforcing Bars for Category I Concrete Revision 1 Structures Dec 1972 RG 1.18 Structural Acceptance Test for Concrete PrimaryReactor Revision 1 Containments Dec 1972 1 of 6 HCGS-UFSAR Revision 0 April 11 , 1988

TABLE 3.8-15 (Cont) Designation Title Edition RG 1.19 Nondeatructi ve Examination of Primary Containment Liner Revision 1 Welds Aug 1972 RG 1.54 Quality Assurance Requirements for Protective Coatings June 1973 Applied to Water Cooled Power Plants RG 1.55 Concrete Placement in category I Structures June 1973 RG 1.57 Design Limits and l.Dading Combinations for Metal Primary June 1973 Reactor Containment SystemComponents RG 1.58 Qualification of Nuclear Power Plant Inspection, Aug 1973 Examination, and Testing Personnel RG 1.69 Concrete Radiation Shields for Nuclear Power Plants Dec 1973 RG 1.94 Quality Assurance Requirements for Installation, Inspection, Revision and Testing of Structural Concrete and Structural Steel Apr 1976 During the Construction Phase of Nuclear Power Plants American Society for Testing and Materials AS'IM A 36 Structural Steel 1970, 1974, 1975, 1977, 1981 AS'IM A 307 Carbon Steel Externally and Internally Threaded Standard 1968, 1974, 1976, 1978 Fasteners AS1M A 325 High Strength Bolts for Structural Steel Joints, Including 1971, 1974, 1976, 1978 Sui table Nuts and Plain Hardened Washers AS'IM A 441 High Strength, Low Alloy Structural Manganese VanadiumSteel 1970 AS'IM A 490 Quenched and Tempered Alloy Steel Bolts for Structural 1971, 1974, 1976 Steel Joints AS'lMA 500 Cold Formed Welded and Seamless Carbon Steel Structural 1973, 1977 Tubing in Roundsand Shapes AS'IM A 615 Deformed and Plain Billet Steel Bars for Concrete 1975 Reinforcement AS'IM c 31 Making and CUring Concrete Test Specimens in the Field 1969, 1975 AS'lM c 33 Concrete Aggregates 1977 2 of 6 HCGS-UFSAR Revision 0 April 11 , 1988

TABLE 3.8-15 (Cont) Desi£m!!tion Edition AS'lM c 39 Compressive Strength of Cylindrical Concrete Specimens 1972 AS'IM C 40 Organic Impurities in Sands for Concrete 1973 AS'IM c 78 Flexural Strength of Concrete 1975 AS'IM c 87 Effect of Organic Impurities in Fine Aggregate on 1969 Strength of Mortar AS'IM c 88 Soundness of Aggregates by Use of SoditiDSulfate or 1973 Magn.esi1.111. Sulfate AS'IM C 94 Ready* Mixed Concrete 1973, 1974 AS'IM c 109 Compressive Strength of Hydraulic Cement Mortars 1975 AS'lM c 117 Materials Finer than No. 200 Sieve in Mineral Aggregates 1969 by Washing AS'lM c 127 Specific Gravity and Absorption of Coarse Aggregate 1973 AS'IM c 128 Specific Gravity and Absorption of Fine Aggregate 1968 AS'lM c 131 Resistance to Abrasion of Small Size Coarse Aggregate 1969 by Use of the Los Angeles Machine AS'lM c 136 Sieve or Screen Analysis of Fine and Coarse Aggregates 1971 AS'IM C 138 Unit Weight, Yield, and Air Content of Concrete 1973, 1975 AS'IM C 142 Clay Lumps and Friable Particles in Aggregates 1971 AS'IM C 143 Slump of Portland Cement Concrete 1974 AS'lM c 150 Portland Cement 1973, 1974 AS'IM c 156 Water Retention by Concrete Curing Materials 1971 AS'IM C 111 Sheet Materials for Curing Concrete 1969 AS'lM c 172 Sampling Fresh Concrete 1971 AS'IM C 186 Heat of Hydration of Hydraulic Cement 1973 AS'IM c 192 Making and Curing Concrete Test Specimens in the 1969 Laboratory 3 of 6 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.8-15 tCont) Desisnation Edition AS'IM C 231 Air Content of Freshly MixedConcrete by the Pressure 1975 Method AS'lM C 260 Air Entraining Admixtures for Concrete 1973 AS'lM C 266 Time of Setting of Hydraulic Cement by Gillmore Needles 1971 AS'IM C 289 Potential Reactivity of Aggregates 1971 AS'lM c 295 Petrographic Examination of Aggregates for Concrete 1973 AS1M c 311 Sampling and Testing Fly Ash or Natural Pozzolans for 1977 Use as a Mineral Admixture in Portland Cement Concrete AS'lM C 469 Static Modulus of Elasticity and Poisson's Ratio for 1965 Concrete in Canpression AS'lM C 494 Chemical Admixtures for Concrete 1971 AS'lM C 618 Fly Ash and Raw or Calcined Natural Pozzolans for Use 1978 as a Mineral Admixture in Portland Cement Concrete AS'IM C 637 Aggregates for Radiation Shielding Concrete 1973 AS'IM c 845 Bxpansive Hydraulic Cement 1980 ASTM D 75 Sampling Aggregates 1971 AS'lM D 422 Standard Method for Particle Size Analysis of Soils 1972 AS'IM D 1140 Standard Method of Test in Soils Finer Than the 1971 No. 200 Sieve AS'lM D 1556 Standard Method of Test for Density of Soil in Place 1974 by the Sand Cone Method AS'lM D 1557 Standard Methods of Test for Moisture Density Relations 1970 of Soils Using 10-lb. Ranmer and 18-in. Drop (Method D) AS'IM D 2922 Standard Test for Density of Soil and Soil Aggregate 1971 in Place by Nuclear Methods tShallow Depth) 4 of 6 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.8-15 (Cont) Designation American National Sta:ndards Institute ANSI N45.2.2 Packaging, Shipping, Receiving, Storing 1 and Handling 1972 of Items for Nuclear Power Plants. ANSI N45.2.5 Supplementary QA Requirements for Installation, Inspection, 1974 and Testing of Structural Concrete and Structural Steel During the Construction Phase of Nuclear Power Plants ANSI N45.2.6 Qualifications of Inspection, Examination, and Testing 1973 Personnel for the Construction Phase of Nuclear Power Plants ANSI B31.1 Power Piping 1973 American Institute of Steel Construction AISC Specification for the Design, Fabrication, and Erection 1969 of Structural Steel for Buildings and Supplement Nos. 1, 2 and 3 AISC Code of Standard Practice for Steel Buildings and Bridges 1972 AISC Specification for Structural Joints Using ASTM A 325 1966, 1972, and 1976 or A 490 Bolts American Society of Mechanical Engineers ASME Boiler and Pressure Vessel Code, Sections II, III, 1971 with Addenda V, VIII, and IX through Summer 1972 International Conference of Building Officials UBC Uniform Building Code 1973, 1976 Building Officials and Code Administrators Basic Plumbing Code 1975 5 of 6 HOJS-UFSAR Revision 0 April 11, 1988

TABLE 3.8-15 (Cant) Designation Title Edition Nuclear Construction Issue Group NCIG-01 Nuclear Construction Issue Group 5/7/1985 Visual Weld Acceptance Criteria (Rev. 2) 6 of 6 HCGS-UFSAR Revision 0 April 11, J 988

           ~Rterial                     Reauirement                          fTI-......"'"

J.'C:i::)l.. Freauencv (;.ement Sta.'ldard ph.:vsical a'1d che.-nical "A.SLN.! c 150 Each 6000 bbl of cement delivered or properties each silo of camcnt certified nt the mill Po::::::;~olwl Chemical a~d ~~ysical properties P...STii c ~l.l R~ch shipment of Pozzola~ of 400 Lo~~

per 1\SL"'i C 618 or less AS~1

                                                                                  '"tV ASL.~     c    88       Cnce every 6 months J\Blli c ! J !          ()nee every 6 !!YJI!ths P..S7:-r1 c 136 Gradation Coarse aggregate V'l.lt,.;.C

_ dail~~ ~~-- J.VL CQ.UJ..l

                                                                                                                                                          &... kf\i\

vVV UUlJ.J..\,.,.

                                                                                                                                                                                                 .. ,..,..,.......,.i_
                                                                                                                                                                                                 .,.YO..I.UO UJ.

Jlr-.:*:lt*Jti on Fine aggregate C1!lcetini lv ...__...._........_~, for each 500 cubic yards of

                                                                                           ---~             .. ~+~-.....
                                                                                           }-'.1."--"i.A.\..ol'l.-\.o.LV.LA.

iioistt!!"e Coarse aggregate G~ce daily- for each 500 cubic '1:TO't"¥'"fC! J'-"".L~ of prcx:luction OI*Jc.e(.l.aily for- e.e.~~h 500 :ettl:*ie ~rt=i.,rd.~s of prcctuct1on Water a.""ld Ice Qtlali ty of h~ter to be used in Lnce each 3 monL~s concrete Ito meet ~~e requirements herei11l Air entrainir~ agent Lniforw~ty testir~ U¥Cn occasion at jol:>>Si t.e or Sl.q..pl i ~:r fm-,i 1 i t~~ll' Wa:ter reducir'J: a..~d retardir.g ASL.'r1 C 4 9 4 L~iformity testir~ upon occagion at agentc.s.t jobsite or sujpplier facility Concrete Mixer ~~iformity Initially aa~d as required to waintain t~~A certification

                        ~~ump;    air content,    a~d temperature                          First batch a~ every ou cubic yarrl-S per class of concrotc produced each day, except for grout ard starter mix every 50 cubic yav~~ prryJ~~~l Unit weight                                AS'IM C        lt.JU J.<JU    Laily per class of concrete produced l of 2 llCGS-IJFSAR                                                                                                                                                                                                                       P\.vision 0 Apr~l. 11;   1988

                                     'tABLE3.8=16 tContJ t1a.terial             P..eauiremcnt.                                       Frenuert,-.v C:om.pressi ve                                    f)nP. Ret of two               testir...g at
                                                                                        ~t*!~!J.KlA!

for eac~ 100 cuo1c yards of production 2 of 2

                                                                                                               .RfJ!" .LL 11 t l98R

TABLE 3.8-17 CXJNCRE'TE COVER OF REINFORCING STEEL ( l) Minimum Reduction Increase Clear Nominal in Nominal in Nominal Cover Cover Cover Cover Type of Placement Member linches! iinches! iinches) !inches) Formed exposed to earth, Members more than 24 in. thick weather, or water No. 14 and 18 bars 2 3 1 1-1/2 All other bars 1-l/2 2-1!2 1 1-l/2 Members 12 to 24 in. thick 1-1/2 2-1/2 1 1 Formed not exposed to earth, Members more than 24 in. thick weather, or water No. 14 and 18 bars 1-1/2 2-1/2 1 1-1/2 All other bars 1 2 1 1-112 Members 12 to 24 in. thick 1 2 1 1 Members less than 12 in. thick 5/8 1 3/8 3/8 ( 1) Nominal cover for reinforcing steel is the Bl.ID of minimlln clear cover plus the allowable reduction in nominal cover. 1 of 1 lRXlS-UFSAR Revision 0 April 11, 1988

TABLE J.M-1~ ALLOWABLE DUCTILITY RATIOO I J1. I FOR REINFORCED CONCRETE SUBJECTED TO IMPACTIVE AND IMrulSIVE LOADINGS ACI-349 as Modified Member Type and Load Condition HOGS - Structural Design Criteria by Reg. Guide 1.142 IMPACTIVE lDADINGS IMPULSIVE lDADINGS Flexure: Beams 0.10 .i 10 3.0 0.05 i 10 P-P P-P' Slabs 0.10 ~ 30 3.0 0.05 i 10 P-P P-P' f' A _£_ .i ~ Beams and slabs shall also satisfy the 60f bd Ditto y following requirements: A -A' f' _!L_!! .i .25 __Q Ditto bd f y Axial compression: Wall and columns 1.3 1.0 1.3 Shear, concrete beams and slabs in region controlled by shear: Shear carried by concrete only 1.0 1.0 1.0 Shear carried by concrete and stirrups 1.3 1.0 1.3 Shear carried completely by stirrups 3.0 1.5 3.0 l of 2 HCUS-UFSAR Revision 0 April 11, 1988

TABLE 3.8-18 (Cont) Notation: f' Concrete compressive strength (psil c f ~ Reinforcing yield strength (psi) y 2 A s Area of tensile reinforcement (in ) I 2 A' Area of compressive reinforcement (in ) s b Effective width of the member (in) d Distance from the extreme compression (in) fiber to the centroid of the tension reinforcement 2 of 2 HCGS-UFSAR Revision 17 June 23, 2009

TABLE 3.8-19 AIJJ)WABLE DlK)TILITY RATIOS FOR STRUCTURAL STEEL SUBJECTED 'IO IMPACTIVE AND I.MFU..SIVE WADING HCGS STRUC'IURAL DESIGN CRITERIA NUREG 0800 MemberType And LoadCombination Impa.cti ve Loading Impulsive Loading Appendix A BEAMS IN FLEX.URE 10 (Tension Due To Flexure)

1. Tornado missiles 10

2. Other loads 20( 1 ) 3 (Proportioned to preclude buckling)

OOLUMNS 1.3 l ~ 20' p, ~ }. 3 CProportioned to 1 r preclude buckling) l > 20, p, .i 1.0 r AXIAL TENSION o. 5 ...ll!.. 3 0.5 ~ y y (l) Actualductility ratios are less thanor equal to 10. 1 of 1 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.8-20 TYPE A TRIPLE FLUED HEAD CONTAINMENT PENETRATIONS Penetra-tion Process Scope Assembly Nom. Pipe of Number Elev. Size Supply P-1A 107'-0 11 Main Steam 26 11 NSSS P-18 107'-0 11 Main steam 26 11 NSSS P-1C 107 1 -0 11 Main Steam 26 11 NSSS P-lD 107'-0 11 Main Steam 26" NSSS P-2A 113'-2 11 Feed Water 24 Non-NSSS P-28 113'-2 11 Feed Water 24 11 Non-NSSS P-3 106 1 -0 11 RHR Shutdown Cooling From RPV 20 11 Non-NSSS P-4A 106'-0 11 RHR Shutdown Cooling Return 12 11 Non-NSSS P-4B 1061 -orr RHR Shutdown cooling Return 12 11 Non-NSSS P-SA 108 1 -9 11 Core Spray to Reactor 12 11 Non-NSSS P-5B 108 1 -9" . Core Spray to Reactor 121! Non-NSSS P-6A 106 1 -0 11 LPCI 12 11 Non-NSSS P-68 106 1 -0 11 LPCI 12 n Non-NSSS P-6C 106'-0 11 LPCI 12 11 Non-NSSS P-60 106'-0 11 LPCI 12" Non-NSSS P-7 106 1 -0 11 HPCI Turbine Steam Supply 10 11 Non-NSSS P-BA 114 1 -0 11 Chilled Water From Drywell Coolers 8" Non-NSSS P-8B 114 1 -0 11 Chilled Water to Drywell Coolers 811 Non-NSSS P-9 150 1 -6" RWCU Supply 611 Non-NSSS P-10 P-11 148'-0 11 106'-0 11 SPARED* RCIC Turbine Steam Supply 611 4" Non-NSSS Non-NSSS I P-12 103'-9 11 Main Steam Drains3" Non-NSSS P-38A 110'-0 11 Chilled Water to Drywell Coolers 8" Non-NSSS P-38B 114 I -Q11 Chilled Water from Drywell Coolers 8" Non-NSSS I

• Process piping capped inside and outside containment.

Flued head remains in place. 1 of 1 HCGS-UFSAR Revision 14 July 26, 2005

FOIJR .l.IFTINlS LtJ~S@ a~ <<;)*, 180". ~ e70* - - - I

   .                                    Dli'Y'W"fLL HliAO I

I

EX.PAN510N 1

aeLL.O!NS L_ J

                                                - j                  1. NOTES:

A CLEARAIR GAP IS PROVIDED BETWEENTHE DRYWELLSHELL& SHIELDWALL FROM EL. 86'*11" 70 LFACE or CRYNELL EL 174'.0*'. BELOWEL. 100'..0" A i 5HIELO ~u. . (TrP) FEW VERY LOCALIZEDAREAS EXISTWITHCLEARAREAGAP REDUCEDTO AS NARROWAS Y:z". OR1'fVEI.t.. I I

                                                                ~

REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION PRIMARYCONTAINMENT ELEVATION UPDATEDFSAR FIGURE3.8-1

[LI't.? 7

                                                                  ':It 0"

I li'-1 1.5. RAp. SECitON A*A n

         /80°                                                                                     REVISION0 APRIL 11, 1988

.1 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION PlAN OF PRYW&l.L HEAP .

DRVWELLHEAD bETAil A UPDATEDFSAR FIGURE3.8-2

-135"AZIMUTH REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION EQUIPMENTHATCHC-1 UPDATEDFSAR FIGURE3.8-3

Ai!/M(.ITH

315 C>

13 ~ 2 <I'CcVII',Ir( R. ( INIJOMO I9N/J tW TSDI'l!<O

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-,;.p <:>F .li/fVIP

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                                                                                                                                                                                                                     £"-E v...,T.Io;v IZ-'o                                                                               Ert.#tPMetvr    1114T&.~        c-z REVISION 0 APRIL* 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION EQUIPMENTHATCHC-2 AND PERSONNELAIR LOCK UPDATEDFSAR                      FIGURE3.8-4

                        ~

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             !  I REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GU!ERATING STATION C.R.D. REMOVAL HAl'CHC-3 UPOATED FSAR                 FIGURE3.8-5

• EXTENT Or SHIELDING

                                                                    *I. \. .

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TRIPLE FLUEDHEAD

                                                         ;             ---~-                       --~

TYPF-r EXTENT OF SHIELDING_ ___j . * *coNCRETE _ . ~

"' "" \_ . I REVISION0 APRIL11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION TYPICAL DRVWELL PROCESS PIPING PENETRATIONS TYP£-8 UPDATEDFSAR FIGURE 3.8*6

SECTIONA-A

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                                                                                                             *~----------------------------~

PUBLIC SERVICE ElECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION TYPICALDRYWELL INSTRUMENTATION PENETRATION UPDATEDFSAR FIGURE3.8-7

• I L...,___ __J I

 ). :::__PRYWELL SHELL.

REVISION0 APRIL11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION TYPICALDRYWELL ELECTRICAL PENETRATION UPDATEDFSAR FIGURE3.8*8

• -SLEEVE REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION TYPICALDRYWELL T.I.P.SYSTEMPENETRATION UPDATED FSAR FIGURE3.8-9

REVISION0 APRIL11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION PLAN-SUPPRESSIONCHAMBER UPDATEDFSAR FIGURE3.8-10

• 4$P2.A..YI-IE.AbE-2..

MOt.J012.A.IL-SUPPHE~!ON SHELL, 1' THK. CHAMBER INTE'-?JtJA.\.... PiPil'-J~ C:,UPPOGaT VENT HeAPER RING Pt..ArE.

                                                                       /XJWNCOMER VEf.JT SYSTeM C.OI..WMf<J C:..OI..UMN C.OtJNe(..'TIO~ A~'SY. -......:::::::==*=~-

COLUMN BA.'SE. PLATE. ASSEMBLY REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION SUPPRESSIONCHAMBER SECTIONAT MIDCYLINDER-NON*VENTBAY UPDATEDFSAR FIGURE3.8*11

• SF'f2 P...Y HE.A.OE.I2 MOt-JO~Afl...

REVISION0 APRIL*11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION SUPPRESSIONCHAMBER SECTIONATMITERED JOINT UPDATEDFSAR FIGURE3.8-12

SUPf'RE,.SION CH.A.MBER SHiU.. t I I 1

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SUPPRESSIONCHAMBER-PLAN VIEW REVISION0 APRIL 11, 1988 PUBLICSERVICEELECTRICAND GAS COMPANY

I HOPE CREEK NUCLEARGENERATINGSTATION SUPPRESSIONCHAMBER PElJJ!L A HORIZONTAL SEISMICRESTRAINT UPDATED FSAR FIGURE3.8*13

PLAN VIEW SECTION I REVISION0 APRIL11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION SUPPRESSIONCHAMBER ACCESSHATCH UPDATEDFSAR FIGURE3.8~14

• SUPPRESSJOt-...1CHAMBER SHE:LL----~

JO"'¢ TRUSS MEMBERS-.,-------, 4'-3" ID VEI\JT HEADER-----. 6'-2." ID

                                             - - I Yz.. THICK VE."-JT HEADER R.l t-JG PLATES
 .3THICK END PL.ATE 2.4-" OD.

DOW~ COMER++---- ~~~----,_~r- 4H¢ BRACI~c;, 10 ¢ 11 SUPPORT COLUMNS -t-t-------::;::;~:---~. REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION ELEVATIONOF VENTSYSTEM UPDATEDFSAR FIGURE3.8-15

• , - - - - - - VEI'JTHEADER J5/a" THICK OUTER GUSSET PLATE tS/s THICK DOWJIJCOMER R I"-J6 PLATE.

lo/aTHICK CROTCH PLATE I J DO\A/N-COMERS 2.'fOD o/6'" THICK

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                 +     lf'-0 11
                                   *I REVISION0 APRIL11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION DETAILOF VENTHEADER-DOWNCOMERINTERSECTION UPDATEDFSAR                 FIGURE3.8~16

VENT LINE-I VEJ.JT VACUUM BRE:AKER SUPPORT SRV PIPING PENETRATION -* 10"¢ SUPPORT COLUM}-J REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION SUPPRESSIONCHAMBER SECTIONAT MIDCYLINDER-VENTLINEBAY UPDATEDFSAR FIGURE3.8-17

segment Are Lenqth Mesh Pta. l 151.4466 28 2 38.00 10 3 63.32 25 4 38.00 lO 5 12.00 s

                                                  -6     "T5"3 ;;-8143        29
                                                   -,-     2~-00              10 E!...Z%1!'!0                                      8      155.9559            30 9      675.5139            so 10        84.1002           -1.1 ll        sa.oo              14 fL..ZOR.OO                                      12       186.525             43 13        53.1875            14 l4       88.0345            14 15      119.50              25 16       76.9817            10 17      167.2740            10 Total                         374
 -L~~~~~==~~---------+~'='~~~u.~~~~
                                         .!5!.!:!!.:

l. All dimensions are in i~hea.

2. Segments are shown as ~ *

3. Thicknesses examined are iiven in the corroded condition. (Note that no corrosion J!:..l7l'T. ~'MoQ.I. )\ is specified for the bottom 7ts* ' 1 l/2w plate since they are buried in concrete.)

2.81~"\'MK 4. The number of mesh points used in BOSOR4 model is specified above. S. The drywall sphere is vertically stiffened with 64-l*xs" bars from approximately elevation 1023.00 to elevation 1101.00.

u. 1100..53&!53 Detail A

                                                                          /

lL.IO'l,~

  "'- .1020. ISO II Detail B
 ~~~~~~;.~~~--~~~~
      . 13!..,...

Q..O.OO R I Detail C REVISION 0 APRIL11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION BOSOR4 MODELOF DRYWELLSHELL UPDATEDFSAR FIGURE3.8-18

A ( 464.0" RAO. 428.2283. RAD. 181 DET~JL A__ (TYPICAL) 689 2436" 22.50*(TYP} I

                                                             ~-J
                                                               ~
                                                                      /    - -. 34 676.0"                                       li25.(TYP) .

REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY Wt.TE.RMASS HOPE CREEK NUCLEAR GENERATING STATION ( iYP AT E'IERY JC!NT) 182 iZ2 MODELOF SUPPRESSIONCHAMBER UPDATED FSAR FIGURE3.8-19

REVISION0 APRIL'11. 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION MODELOF SUPPRESSIONCHAMBER 1/32 SEGMENT-ISOMETRICVIEW UPDATED FSAR FIGURE3.8-20

REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION MODELOF VENTSYSTEMAND SUPPAESSIONCHAMBER 1/16SEGMENT-ISOMETRICVIEW UPDATEDFSAR FIGURE3.8~21

REVISION0 ~ APRIL 11, 1988* PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION NORTH MODELOF VENTSYSTEM UPDATEDFSAR FIGURE3.8-22

y X REVISION0 APRIL 11, 1988 0~'<41N I~ LOCATED ALo~ THE PUBLIC SERVICE ELECTRIC AND GAS COMPANY 4: OF THE VENT L1NE.. AT TI-n::. HOPE CREEK NUCLEAR GENERATING STATION t CF THE VENT HEADER.. MODELOF VENTLINE-VENTHEADERINTERSECTION-ISOMETRICVIEW UPDATED FSAR FIGURE3.8-23

~------------------------~-------*--**---.-----------~ ORIGIN 1$ LOCATED ON THE VENT HEADER <t_ AT THE <t:. OF THE DOWJ-.JCOM EJ<5. REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION MODELOF VENTHEADER-DOWNCOMERINTERSECTION-ISOMETRICVIEW UPDATED FSAR FIGURE3.8*24

 ...131
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T ---.,0'

        "---***l-f3:~'"

- lr-REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEARGENERATINGSTATION RPV PEDESTAL FLOOR REINFORCING UPDATED FSAR FIGURE3.8-25

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SECUON---@ 4.!"

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                                                                                                                                                                                                                                                                                                     .5ECTION PUBliC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION RPV PEDESTAL REINFORCING UPDATED FSAR                FIGURE 3.8*27

   ;,:s**                                                       _____ #_70 0.</CAP.SAI'I"?

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11 I' 1 REVISION0 APRIL11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEARGENERATING STATION RPV PEDESTAL REINFORCING UPDATED FSAR FIGURE3.8-28

TO VERTICAL 6TiFF.

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REVISION0 I APRIL 11, 19881 PUBLIC SERVICE ELECTRIC AND GAS COMPANY \ HOPE CREEK NUCLEAR GENERATING STATION BIOLOGICAL SHIELD LYPL(Ai SE(FW_& GemOYAJ- P/..AN PLAN& ELEVATION 6/Ptt'/h.t:At 5HJEtP WAI.L 8ASE. _____________________________________________________________________________________________________________________ _Ji__________________________ UPDATEDFSAR FIGURE3.8-29___

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REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION DRVWELLPLATFORM AT EL 100'-2" UPDATEDFSAR FIGURE3.8*31

    ~**

£/O* PLATFORM DRYWELL 121'*7W' ATEL. *--~-----

I REVISION0 APRIL 11, 1988 PUBLIC SERVICE ElECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION LATERALTRUSS UPDATED FSAR FIGURE3.8-33

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REVISION0 APRIL 11, 1988 PUBliC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUClEAR GENERATING STATION FINITE-ELEMENT MODEL OF RPV PEDESTALAND BIOLOGICAL SHIELD UPDATEDFSAR FIGURE3.8-34

ADMIN FACILITY TURBINE BUILDING

                                                          ' 1 NON-SEISMIC CAT I STRUCTURES n

Ji  ;; AUXBLDG  !! RADWASTE/SERVICE AREA

                .. f           1.

1--_ _ _ _ ..,.11_ - - - _11.__ _ _---1 SEISMICCAT I AUX iBLDG STRUCTURES PLANT CONTROL/ REACTOR CANCELLED AREA DIESEL GEN AREA BLDG [Q] 7 CONDENSATESTORAGE TANKDIKE ssws INTAKE STRUCTURE (SEISMIC CATEGORYI) DELAWARE.RIVER REVISION0 APRIL' 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION OTHER SEISMIC CATEGORYISTRUCTURESAND RELATED NON*SEISMIC CATEGORY I STRUCTURES UPDATED FSAR FIGURE3.8*35

26'-6"

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2"SEISMICJOINT .~* 1-----1*0' f .. 1-----1 STEELCONDUIT EXPANSIONAND DEFLECTIONFITTING TYPICALSECTION REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION TYPICALDETAIL FOR EMBEDDEDSTEELCONDUIT CROSSINGSEISMICJOINT UPDATEDFSAR FIGURE3.8-46

3.9 MECHANICAL SYSTEMS AND COMPONENTS 3.9.1 Special Topics for Mechanical Components 3.9.1.1 Design Transients This section describes the transients that are used in the design of ASME Boiler and Pressure Vessel (B&PV) Code, Section III Class 1 components, the core support structures, the reactor internals, and the hydraulic control units. The number of cycles or events for each transient is included. These transients are included in the design specifications and/or stress reports for the components. Transients selected for fatigue evaluation include conservative estimates of magnitude and frequency of temperature and pressure conditions resulting from the design transients. Transients or combinations of transients are classified with respect to the component operating condition categories identified as "normal," 11 Upset," "emergency," "faulted," or "testing" in the ASHE B&PV Code, as applicable. 3.9.1.1.1 Control Rod Drive Transients The normal and test service load cycles used for design purposes for the 40*year life of the control rod drives (CRD) are as follows: Transient Category Cycles Reactor startup/shutdown Normal/Upset 120 Vessel pressure tests Normal/Upset 130 Vessel overp-.:essure Normal/Upset 10 Scram test plus startup scrams Normal/Upset 300 Operational scrams Normal/Upset 300 Jog cycles Normal/Upset 30,000 Shim/drive cycles Normal/Upset 1000 In addition to the above cycles, the following cycles were considered in the design of the CRDs: 3.9-1 HCGS*UFSAR Revision 0 April 11, 1988

Transient Category Cycles Scram with inoperative buffer Normal/Upset 10 Scram with stuck control blade Normal/Upset 1 Operating basis earthquake Upset 10 Safe shutdown earthquake Faulted 1 The frequency of occurrence of the operating basis earthquake (OBE) indicates the emergency category. However, for conservatism, the OBE was analyzed as an upset condition. All ASME B&PV, Section III, Class 1 components of the CRD have been analyzed according to Section III of the ASME B&PV Code. The capability of the CRDs to withstand other emergency and faulted conditions is verified by test rather than by analysis. 3.9.1.1.2 Control Rod Drive Housing and In-core Instrument Housing Transients The number of transients, their cycles, and classifications, as considered in the design and fatigue analysis of the CRD housing and in-core instrument housing, are as follows; Transient Cateaoa Cycles Normal startup/shutdown Normal/upset 120 Vessel pressure/overpressure tests Normal/upset 130 Interruption of feedwater flow Normal/upset 80 Scram Normal/upset 200 OBE(l) Normal/upset 10 2 Safe shutdown earthquake (SSE)( ) Emergency 1 CRD Housinc Only Stuck rod scram Normal/upset 1 Scram without buffer Normal/upset 10 3.9-2 HCGS-UFSAR Revision 0 April 11, 1988

(1) The frequency of an OBE indicates an emergency category. However, for conservatism, this OBE condition is analyzed as an upset. {2) SSE is a faulted condition. However, in the stress analysis report, it is treated as emergency with lower stress limits. I 3.9.1.1.3 Hydraulic Control Unit Transients The transients used in the design and analysis of the hydraulic control unit (HCU) and its components are as follows: Transient Category Cycles Reactor startup and shutdown Normal/upset 120 Scram tests Normal/upset 300 Operational scrams Normal/upset 300 Jog cycles Normal/upset 30,000 Scram with stuck scram discharge emergency 1 valve OBE Normal/upset 10 SSE Faulted 1 3.9.1.1.4 Core Support Structures and Reactor Internals Transients The cycles listed in Table 3. 9-1 are considered in the design and fatigue analysis for the core support structures and the reactor internals. 3.9.1.1.5 Main Steam System Transients The following transients are considered in the stress analyses of the main steam piping: Transient Category Cycles Startup normal 120 3.9-3 HCGS-UFSAR Revision 17 June 23, 2009

Transient Category Cycles Loss of feedwater pumps, isolation Upset 10 valves closed Scram Upset 180 Shutdown normal 111 Reactor overpressure delayed scram Emergency 1 Single safetyjrelief valve (SRV) Upset 8 blowdown Automatic blowdown Emergency 1 Hydrotest Test 130 OBE Upset 50 Turbine ma-in stop valve (MSV) closure Upset 40 Safety/relief valve lift Upset 5,000 3.9.1.1.6 Recirculation System Transients The following transients are considered in the stress analyses of the recirculation piping: Transient Cate&ory Cycles Startup Normal 120 Turbine roll and increase to power Normal 120 Loss of feedwater heater Upset 10 Partial feedwater heater bypass Upset 70 Scrams Upset 180 Shutdown Normal 111 Loss of feedwater pumps, isolation Upset 10 valves closed Reactor overpressure with delayed Emergency 1 scram Single SRV blowdown Upset 8 Automatic blowdown Emergency 1 Hydro test Test 130 OBE Normal/upset 50 3.9-4 HCGS-UFSAR Revision 0 April 11, 1988

3.9.1.1.7 Reactor Assembly Transients The reactor assembly includes the reactor pressure vessel (RPV), support skirt, and shroud support, including legs, cylinder and plate. The cycles listed in Table 3.9-1 are spe~ified in the reactor assembly design and fatigue analysis except for feedwater nozzles. The cycles listed in Table 3.9-la are specified in the feedwater nozzle stress and fatigue re-analysis. 3.9.1.1.8 Main Steam Isolation Valve Transients The main steam isolation valves (MSIVs) are designed for the following service

 *conditions and thermal cycles:

Transient Category Cycles Preoperational at 100°F/h Normal/upset 150 Startup (heating at 100°F/h), Normal/upset 120 Pressure o to 1000 psig Shutdown: Cooling cycles at 100°F/h, 540 to Normal/upset 120 375°F, Pressure 1000 psig to 0 psig Cooling cycles at 270°F/h 1 375 to Normal/upset 120 330°F, Pressure 1000 psig to 0 psig Cooling cycles at 100°F/h, 330 to Normal/upset 120 100°F 1 Pressure 1000 psig to o psig Scram cooling cycles at 100°F/h, Normal/upset 180 Pressure 1000 psig increasing to 1125 psig, then decreasing to 240 then increasing to 1000 psig Emergency and faulted transients:

• HCGS-UFSAR 3.9-5 Revision 14 July 26, 2005

                                                  -----~---

Transient Categoxy Cycles 1000 psig and 546*F to 35 psig Emergency/faulted 1 and 28l*F in 15 s 546°F to 375*F in 3.3 min, Emergency/faulted 1 375*F to 28l*F at 300*F/h, pressure 1000 to 35 psig 546*F to 375*F in 10 min, Emergency/faulted 8 375*F to 28l*F at lOO*F/h, pressure 1000 to 35 psig 546 F to sa3*F in 2 s, 01 Emergency/faulted 1 583*F to 538°F in 30 s, 538°F to 400*F then return to 546°F at loo*F/h, pressure 1000 to 1350 then to 240 then 240 then to 1000 psig 56l°F to soo*F in 7 min, soo*F Emergency/faulted 10 to 400°F then to 546°F at 100°F/h, pressure 1000 to 1180 then to 240 then to 1000 psig 3.9.1.1.9 Safety/Relief Valve Transients The transients used in the analysis of the SRVs are as follows: Transient Cate&ory Cycles Preoperational and inservice testing Normal/upset 150 (lOO.F/h) Startup (100°F/h) and pressure Normal/upset 120 increase (0 to 1000 psig) HCGS-UFSAR Revision 0 April 11. 1988

Transient Category Cycles Shutdown 540 to 375°F and 330 Normal/upset 120 to 100°F at lOO.Ffh, (270°F/h between 375 and 330°F) pressure decrease to 0 psig Scram. Temperature change greater Normal/upset 180 than 3o*r will be at lOO.Ffh. Pressure increasing from 1000 to 1125 psig than decreasing to 240 psig then returning to normal operating pressure of 1000 psig. System pressure and temperature Emergency/ 1 decay from 1000 psig, 546°F to faulted 35 psig and 281*F within 15 s System temperature change from 546 to Emergency/ 1 375*F within 3.3 min, and from 375* faulted to 2s1*F at a rate of 300°F/h; pressure change from 1000 to 35 psig System temperature change from 546 Emergency/ 8 to 375*F within 10 min, and from 375 faulted to 2s1*F at a rate of 100°F/h; pres-sure change from 1000 to 35 psig System temperature change from 546 Emergency/ 1 to 583*F within 2 s, from 583 to faulted SJS*F within 30 s, and from 538* to 400*F and return to 546°F at a rate of lOO*F/h; pressure change from 1000 to 1350 psig, then to 240 psig and return to 1000 psig 3.9-7 HCGS-UFSAR Revision 0 April 11, 1988

System temperature changes greater Emergency/ 10 than 30°F, from 561 to soo*F within faulted 7 min, and from 500 to 4oo*F and return to normal operating tempera-ture of 546°F at a rate of loo*Ffb; pressure change from 1000 to 1180 to 240 psig, and return to normal operating pressure of 1000 psig Paragraph NB-3552 of the ASHE B&PV Code, Section III, excludes various transients and provides means for combining those that are not excluded. Review and approval of the equipment supplier's certified calculation ensures proper accounting of the specified transients. 3.9.1.1.10 Recirculation Pump Transients The following transients are listed in the design specification as a requirement for design considerations. However, a submitted certified analysis considering thermal stresses was not required. The vendor was required to submit a certification of compliance. The submitted certified design calculations only considered pressure transient. Nozzle piping loads were considered in accordance with:

     "The  pump   case   shall  be  designed   to   withstand   secondary stresses    due    to   piping   reactions     in  accordance     with paragraph 452.4b of the ASME Standard Code for Pumps and Valves for Nuclear Power (1968 Draft)."

Transient Cate"ory Cycles Heatup and cooldown at lOO.F/h Normal/upset 300

     -29*F temperature changes                  Normal/upset      600
     -so*p temperature changes                  Normal/upset      200 HCGS-UFSAR                                             Revision 0 April 11, 1988

Transient Category Cycles RPV pressure transients to Normal/upset . 1 100 percent design pressure SRV blowdowns, 546 to 375°F Normal/upset 30 in 10 min Improper pump startup 1 130 to 546°F Emergency 1 in 15 s Cooling transient, 546 to 281°F in Emergency 2 15 s Hydrotest to 1300 psig Testing 130 Hydrotest to 1670 psig Testing 3 3.9.1.1.11 Recirculation Gate Valve Transients The following transients are considered in the design of the recirculation gate valves: Transient Cycles 50 to 575 to 50°F at 100°F/h 300

          -29°F between limits of 50 to 575°F, instantaneous        600
          -SOF between limits of 50° and 546°F, instantaneous       200 546 to 375°F, in 10 minutes                                30 546 to 281°F, in 15 seconds                                 2 130 to 546°F, in 15 seconds                                 1 3.9-9 HCGS-UFSAR                                                      Revision 0 April 11, 1988

Transient Cycles 110 percent design pressure at 575°F l 1300 psi at 100°F installed hydrostatic test 130 1670 psi at 100°F installed hydrostatic test 3 3.9.1.2 Computer Programs Used in Analyses The following sections discuss computer programs used in the analyses of specific NSSS components. Computer programs were not used in the analyses of all components; thus, not all components are listed. Sections 3.9.1.2.1 through 3.9.1.2.4 and 3.9.1.2.6 reference computer programs used by GE, its vendors and Structural Integrity Associates for analyzing NSSS components. These NSSS programs can be divided into three categories:

1. GE computer programs - Verification of the following GE computer programs has been performed in accordance with the requirements of 10CFRSO, Appendix B. Evidence of the verification of the input, output, and methodology of the programs is documented in GE design record files:

a. PISYS

b. ANSI 7

c. RVFOR

d. TSFOR

e. PDA

f. SAP-4 3.9-10 HCGS-UFSAR Revision 14 July 26, 2005

g. ED-6

h. ED-8

i. EZPYP

j. DYSEA

k. SPECA04

1. GEAPLOl

m. PIPST01

2. Hitachi computer programs - Verification of the following Hitachi computer programs is assured by the contractual requirements, such that the quality assurance governing these programs used in the of N-stamped equipment is in full compliance with the requirements of 10CFR50, Appendix B:

a. TERESS

b. FEMR

c. FEASEL

d. TSCHOCK

e. AS SAL

f. S-3, S-5, and S-7

g. FLAHDERS and JESPO

h. TEDS

3. Structural Integrity Associates computer program - The Structural Integrity computer program was developed and in accordance with the Structural Integrity QA Program, which is in with the requirements of 10CFR50, Appendix B and ANSI/ASME NQA-1-1989, and meets the intent of of ANSI N45.2. The Structural Integrity implementation of the QA Program has been audited and accepted by many nuclear utilities.

Structural Integrity's Quality Assurance Program is controlled by Structural Integrity's Quality Assurance Manual.

a. VESLFAT 3.9-11 HCGS-UFSAR Revision 18 10, 2011

3.9.1.2.1 Reactor Vessel Assembly The programs used by Hitachi in the of the reactor vessel stress are identified and their use summarized in the following paragraphs. 3.9.1.2.1.1 TERESS This program is used for the of stresses and deflections in shell elements of axial symmetry, i.e., shells of revolution, due to thermal loadings. to this program consists of dimensions of shell elements, material and temperature distribution. Output consists of stresses, rotations, and deflections of each shell. These rotations and deflections are used, in turn, for other programs, such as FLAHDERS for flange stress analysis. 3.9.1.2.1.2 FEMR This program, based on an ordinary finite element method, is used for calculating stresses and deformations of axisyrrunetrical and plane stres.s fields. It is also of dealing with thermal stress and body force. 3.9.1.2.1.3 FEASEL This program is a finite element method program including plane stress and axisymmetrical fields. The program can deal with elements that have no circumferential stress and have arbitrary thickness in the axisymmetrical problem. 3.9.1.2.1.4 TSCHOCK This program is used for the of stress in a due to the loading by a radial distribution caused by a of surface temperature owing to sudden contact with a fluid of different temperature. The time when the maximum peak stress occurs is also obtained. I 3.9-12 HCGS-UFSAR Revision 18 May 10, 2011

3.9.1.2.1.5 ASSAL This program is for calculating the stresses and deformation of a rotationally shell subject to symmetrical and nonsymmetrical loads. The program is based on the theory of A. Kalnins, which reduces fundamental equations of shell to first order differential equations, including the linear theory of shell The results yield a the direct (boundary condition and finite difference methods. 3.9.1.2.1.6 S-3, S-5, and S-7 These programs are general finite element analysis programs using the well known methods of quadratic shape displacement functions. They calculate elastic stresses and deformation of two and three-dimensional problems. The S-3 program is used for a plane stress field, and S-5 can be used for an field. For three-dimensional the S-7 program is 3.9.1.2.1.7 FLAHJERS and JESPO These programs are used to compute discontinuity stresses in discontinuity a method described in the ASME B&PV Code, Section III. FLAHDERS is used for stress of stresses due to bolt internal pressure, and temperature distribution loads. The JESPO program is used for the stress analysis of the shroud support, considering stresses due to internal pressure, vertical force, and distribution loads. Structural Associates program PIPX-TS2 was used to calculate the thermal transient and stress response for the alternate 3.9.1.2.1.8 TEDS This program is used to calculate and variable transient distributions in any odd shaped body in two-dimensional and three-dimensional fields, respectively. TEDS accommodates variations of boundary temperature and internal heat in both position and time. The program is useful in obtaining a temperature distribution for the evaluation of thermal stresses in any part of the reactor vessel. This program uses the of internal nodes of triangle, square, and in two-dimensional fields; therefore, the internal node input data agree with the element data of the FEMR computer program for the finite element stress HCGS-UFSAR 3.9-13 Revision 18 May 10, 2011 I

3.9.1.2.1.9 Reactor Internals 3.9.1.2.1.9.1 Core-Plate Beam Buckling- PIPSTOl PIPST01 is a computer program which calculates approximate potential for core plate beam buckling. It uses the Rayleigh-Ritz energy method to determine the applied moment needed to initiate yielding and then finally to buckle a given tee beam. The tee beam model covers a segment of a BWR/2-5 core plate with a stiffener beam. The pressure differential across the plate that would have created this moment is calculated for a given length of beam or size of core Generic dimensions and material properties are all input by the user. 3.9.1.2.1.9.2 Structural Analysis Program- SAP 4 SAP 4 is a structural program for static and dynamic analyses of linear, elastic complex structures. The finite element displacement method is used to solve the displacements and to compute the stresses of each element of the structure. The structure can be composed of unlimited numbers of three dimensional truss, beam, , shell, solid, strain plane stress, brick, thick shell, or elements. The program can treat thermal and various forms of mechanical loading, as well as internal element loading. The dynamic analysis includes mode superposition, time history, and response spectrum Earthquake loading, as well as time varying pressure, can be treated. The program is very versatile and efficient in large and complex structural systems. The output contains displacements of each nodal point, as well as stresses at the surface of each element. 3.9.1.2.1.9.3 Other Programs Other computer codes used for the analysis of the internal components are described in detail in Section 4.1. 3.9.1.2.1.10 Feedwater Nozzle Re-analysis Structural Integrity's re-analysis of the feedwater nozzles utilized the ANSYS finite element computer program. Thermal cycles for pre-extended power uprate (Pre-EPU} and extended power uprate {EPU) conditions were analyzed. Each of the thermal cycles was applied to the Hope Creek feedwater nozzle finite element model (FEM) to a thermal stress analysis using the ANSYS finite element software. The thermal stresses are added to pressure stresses and attached piping load stresses to obtain stress . The ANSYS stress output was used in a subsequent ASME Code stress and fatigue analysis using Structural s VESLFAT computer program. 3.9-14 HCGS-UFSAR Revision 18 May 10, 2011

Structural Integrity's VESLFAT program performs fatigue usage calculations in accordance with ASME code, Section III, Sub article NB-3222.4 (e) for Service Levels A and B conditions. The VESLFAT program computes the primary-plus-and total stress ranges for all events and a correction for elastic-plastic analysis (Ke), if necessary. The program evaluates the stress ranges for primary-plus-secondary and stresses based on all six components of stress (3 normal and 3 shear stresses). The maximum for both states of a load set pair is used to establish the Sm calculations from the user-defined values. When more one stress set is defined for either of stress differences are determined for all of stress the maximum for the event based on producing the alternating total stress (Sa1d, including any effects of Ke. The stress intensities for the event are reordered in decreasing order of a correction for the ratio of modulus of (E) from the curve divided by E from the material evaluated at the maximum This allows a table to be created to eliminate the number available for each of the transient events. This table is based on a worst-case pairing of events in order of the most severe alternating stress to the least severe, allowing determination of a usage per NB-3222. 4 (e) . For each load set in the fatigue table, the allowable number of cycles is determined based on Salt and a cumulative usage factor (CUF) is calculated. 3.9.-1.2.2 3.9.1.2.2.1 Piping Analysis Program- PISYS PISYS is a computer code for piping load calculations. It uses selected stiffness matrices standard piping components, which are assembled to form a finite element model of a piping system. The technique relies on dividing the pipe model into several discrete substructures, called pipe elements that are connected to each other via nodes, called pipe joints. It is through these joints that the model interacts with the environment and loading of the structure becomes possible. PISYS is based on the linear classical the resultant deformation and stresses are and the superposition of loading is valid. 3.9-15 HCGS-UFSAR Revision 18 May 10, 2011

PISYS has a full range of static and dynamic analysis options, which include distributed weight, thermal expansion, differential support motion modal extraction, response spectra, and time history analysis by modal or direct integration. The PISYS program has been benchmarked against five Nuclear Regulatory commission piping models for the option of response spectrum analysis, and the results are documented in Reference 3.9 1. 3.9.1.2.2.2 Component Analysis -ANSI 7 The ANSI 7 computer program determines stress and accumulative usage factors in accordance with NB-3600 of the ASME B&PV Code, Section III. The program was written to perform stress analysis in accordance with the ASME sample problem, and has been verified by reproducing the results of the sample problem analysis. 3.9.1.2.2.3 Safety/R~lief Valve Discharge .Pipe Forces-RVFOR The safety/relief valve {SRV) discharge pipe connects the SRV to the suppressio~ pool. When the valve is opened, the transient fluid flow causes time dependent forces to develop in the pipe wall. This computer program computes the transient fluid mechanics and the resultant pipe forces using the method of characteristics. See Section 3.9.1.2.5.4 for descriptions of the non-NSSS computer programs used to analyze relief valve discharge pipe forces. 3.9.1.2.2.4 Turbine Main Stop Valve Closure - TSFOR The TSFOR program computes the time history forcing function in the main steam piping due to turbine main stop valve closure. The program uses the method of characteristics to compute fluid momentum and pressure loads at each change in pipe section or direction. 3.9.1.2.2.5 Piping Dynamic Analysis - PDA The pipe whip analyses use the PDA computer program. PDA is used to determine the response of a pipe subjected to the thrust force occurring after a pipe break. The program treats the situation in terms of a generic pipe break configuration, which involves a straight, uniform pipe fixed at one end and subjected to a time dependent thrust force at the other end. A typical restraint used to reduce the resulting deformation is also included at a location between the two ends. Nonlinear and time dependent stress strain relations are used to model the pipe and the I 3.9-16 HCGS-UFSAR Revision 14 July 26, 2005

restraint. Similar to the popular elastic hinge concept, bending of the pipe is assumed to occur only at the fixed end and at the location supported by the restraint. Shear deformation is also neglected. The pipe bending moment deflection (or rotation) relation used for these locations is obtained from a static, nonlinear, cantilever beam analysis. Using moment-rotation relations and energy considerations, nonlinear equations of motion are formulated and the equations are numerically integrated in small time steps to yield the time history of the pipe motion. 3.9.1.2.2.6 Piping Analysis Program - EZPYP EZPYP links the ANSI-7 and SAP programs together. The EZPYP program can be used to run several SAP cases by making user specified changes to the basic SAP pipe model. By controlling files and SAP runs, the EZPYP program makes it possible to perform a complete piping analysis in one computer run. 3.9.1.2.3 Pumps and Motors SAP is a general structural analysis program for static and dynamic analysis of linear elastic complex structures. The finite-element displacement method is used to solve the displacements and compute the stresses of each element of the structure. The structure can be composed of unlimited numbers of three dimensional truss, beam, plate, shell, solid, plane strain plane stress, brick, thick shell, spring, and axisymmetric elements. The program can treat thermal and various forms of mechanical loading as well as internal element loading. The dynamic analysis includes mode superposition, time history, and response spectrum analyses. Earthquake types of loading, as well as time varying pressure, can be treated. The program is very versatile and efficient in solving large and complex structural systems. The output contains displacements of each nodal point, as well as stresses at the surface of each element. 3.9-17 HCGS-UFSAR Revision 0 April 11, 1988

3.9.1.2.4 Residual Heat Removal Heat Exchangers The following are the computer programs used in dynamic and static analysis to determine structural and functional integrity of the residual heat removal (RHR) heat exchangers: 3.9.1.2.4.1 Support Load Seismic Analysis - ED-6 This computer program computes the total loads at the upper and lower supports of the RHR heat exchanger. It takes into account the heat exchanger flooded weight, seismic loads (either OBE or SSE) , and the allowable nozzle loads, and sets up the worst combination of these loads. By maximizing seismic loads together with nozzle loads, maximum conservative moments and forces at the upper and lower supports are calculated. 3.9.1.2.4.2 Stress Analysis of Supports - ED-8 This program performs a full stress analysis of the upper and lower supports of the RHR heat exchanger. The stresses in the supports, both upper and lower, caused by loads resulting from seismic and nozzle loads, are computed in support load program ED-6 and are used as input values for this program. This program computes the membrane stresses on the shell of the heat exchanger by the use of the Bijlaard's analysis, as well as the net section stresses (shear, tensile, bearing) on the lower support plate and upper lugs. It also computes the stresses on the welds that hold the supports to the shell of the heat exchanger. 3.9.1.2.5 Non-NSSS Seismic Category I System Components The following sections discuss computer programs developed and/or owned by Bechtel, and programs that are recognized and widely used in industry. These computer programs are used in the analysis of non-NSSS Seismic Category I system components. 3.9-18 HCGS-UFSAR Revision 0 April 11, 1988

The Bechtel developed, and/or owned, computer programs are documented, verified, and maintained by Bechtel, and meet the requirements of 10CFRSO, Appendix B. A brief description of each of these Bechtel programs is provided in the following paragraphs. 3.9.1.2.5.1 MElOl-Linear Elastic Analysis MElOl is a finite element computer program that performs linear elastic analysis of piping systems using standard beam theory techniques. The input data format is specifically designed for pipe stress engineering. ME101 performs a thorough check of the input prior to analysis. In addition, the program automatically modifies the geometry to improve the finite element model. The output may be used directly for piping design, for conformation to Code, and for other regulatory requirements. Two piping codes, ASME B&PV Code, 1974, and ANSI 831.1, Summer 1973 Addenda, are incorporated in ME101 to the extent of computing flexibility factors, stress intensification factors, and stresses. ME101 performs static and dynamic load analysis of piping systems, effective weight calculations, and ASME B&PV Code, Section III Class 2 and 3 and ANSI 831.1 Code stress checks. Static analysis considers one or more of the following: thermal expansion, dead weight, uniformly distributed loads, and externally applied forces, moments, imposed displacements and rotations, individual force loads, static seismic (uniform directional acceleration) loads, or seismic anchor movement analysis. Dynamic analysis is based on the standard normal superposition techniques. The input excitation may be in the form of seismic response spectra or time-dependent loading functions. In the single or multiple response spectrum analysis, the user may request modal synthesie by square root of the sum of the squares (SRSS) method or by NRC Regulatory Guide 1.92 closely spaced mode 10 percent 3.9-19 HCGS-UFSAR Revision 8 September 25, 1996

(Equation 4) method. ME101 can consider further differential damping for large and small pipe according to NRC Regulatory Guide 1 .. 61. Various methods of eigenvalue solution are available. Determinant search or subspace iteration considers all data points as mass points. In the time history analysis, the excitation may be in the form of arbitrary nodal forces, support displacements, rotations, or support accelerations that are not necessarily in phase. ME101 checks stresses from design loads versus allowable stresses according to ASME/ANSI Code equations. The user may request design load checks for sustained loads, occasional loads, multimode thermal expansion and pipe break, except for time history load cases. The MElOl restraint load summary report prints the support load results from several load cases together in the same report, except for time history load cases. The general loading combinations capability for MElOl can combine the results of several load cases together, according to certain algebraic rules, to form a new load case. The new load case resulting from this may be used in stress comparisons or restraint load summaries, except for time history load cases. MElOl has the capability of saving load case results on a tape and using these results in late runs for stress checks, restraint load summary reports, and general loading combinations, except for time history load cases. For piping configurations with optional node numbering, MElOl generates isometric plots. The user may obtain plots on ZETA or CALCOMP plotters, on a Tektronix 4014 graphics terminal, or on an RMS-600 printer/plotter. ME101 uses out-of-core techniques for both static and response spectra analysis and has no practical limitations to the number of equations or band width. However, the use of very large systems may become prohibitive due to cost of computation. The maximum number 3.9-20 HCGS-UFSAR Revision 0 April 11, 1988

of mode shapes allowable for response spectra analysis is currently 125. This program considers the zero period acceleration effect in seismic response analysis. It accepts coordinate and keyword data in English or metric units. The various versions of ME101 used in piping analysis for HCGS are C2, El, Gl, G3, Hl, H3, Il, I2, Jl, J2, J3, J4, J5, Kl, K2 and K3. Bechtel began this piping program's development in July 1975, and has continuously supported MElOl. The program has been used by various Bechtel projects. The ASME Benchmark Problem 1 demonstrates the solution for natural frequencies of a three dimensional structure, as described in Reference 3.9-2. Natural frequencies, in hertz, from ME101 and Reference 3.9-2, are as follows:

    ~          Reference 3,9- 2 1                   110               112 2                   117               116 3                   134               138 A total of 26 test problems were used for the verification of the MElOl results. These verification problems have      been compared against one of the following:

1. ME632, Computer Program, "Seismic Analysis of Piping Systems," VERB MODS, 1976, Bechtel International Corporation, San Francisco, California 3.9-21 HCGS-UFSAR Revision 0 April 11, 1988

2. "Pressure Vessel and Piping 1972 Computer Programs Verification," The American Society of Mechanical Engineers

3. Hand calculations

4. EDS Superpipe, EDS Nuclear, San Francisco, California

5. NUPIPE*IIM, Nuclear Services Corporation Piping Analysis Program, Campbell, California

6. TPIPE, A Computer Program for Analysis of Piping Systems, PMB Systems Engineering, San Francisco, California

7. ADINA, A Computer Program, Massachusetts Institute of Technology, Boston, Massachusetts

8. MSC/NASTRAN Program, McNeal Schwendler Corporation, Los Angeles, California

9. EASE2 Program, Engineering/Analysis Corporation, San Francisco, California

10. ANSYS, Swanson Analysis Systems, Inc, 1975, Elizabeth, Pennsylvania.

The Jl version of ME101 also includes seven NRC benchmarked problems, as referenced in NUREG/CR-1677, dated August 1980. 3.9.1.2.5.2 ME912-Thermal Stress In ME912, a finite difference representation of the heat diffusion equation is used for the pipe or component wall section in contact with fluid of a specified temperature and flow rate time histories. The program is quasi two dimensional, accounting for the reduction of severity of a given transient with distance from inlet. 3.9-22 HCGS-UFSAR Revision 0 April 11, 1988

Thermal properties of water, stainless steel, and carbon steel are built in the program. Film transfer coefficients for water are computed by the program for each time step and pipe section. For other fluids, such as steam, the program is used on a one dimensional basis with user supplied film coefficients. Sequential computations are done for pipe lengths of different diameters or wall thicknesses. Fluid outlet temperature data from one pipe length are stored for use as the inlet to the length downstream. Average temperature differences, Ta-Tb, are thus calculated for structural discontinuity. The ME912 program has been used by Bechtel on various projects. A Univac 1100 computer is used to run the program. The ME912 program was developed from References 3.9-3, 3.9-4, and 3.9-5 by Bechtel. It has been used extensively since 1975 for Class 1 component design on the Fast Flux Test Facility (FFTF) project. For local gradients, the program has been compared with analytical flat plate data of Reference 3.9-4 and numerical results by in-house program ME643. The results are acceptable. Table 3. 9-2 shows the comparison of ME912 with ME643 and analytical results from Reference 3.9-4 for axial variations of fluid and wall temperatures; the program agrees closely with the analytical solution of Reference 3.9-5. The ME643 program was developed from References 3.9-6 and 3.9-7 by Bechtel. The results of ME643 transient temperature responses on both inside and outside surfaces of a sample pipe are compared with the chart of Reference 3.9-8 and plotted on Figure 3.9-1. 3.9-23 HCGS-UFSAR Revision 0 April 11, 1988

3.9.1.2.5.3 ME913MNuclear Class 1 Piping Stress Analysis ME913 can determine stress intensity levels for Class 1 nuclear power piping components (see equations 9 through 14 of subarticle NB-3650, Analysis of Piping Components, ASME B&PV Code, Section III). Prior to using this program, the following information external to the program is required:

1. Piping configuration

2. Piping and piping component properties

3. Moment reactions due to:

a. Thermal expansion loads

b. Weight loads

c. Earthquake loads and other dynamic loads

4. Thermal response of the piping system due to the specified transients is as follows:

DT , DT and the (T Tb) values for the key points 1 2 8 during system life. ME913, Revision 4, is used by Bechtel. A Univac 1100 computer is used to run the program. ME913 is the revised and expanded version of the LOTEMP program, originally developed by Bechtel and made available for use through the CDC 6600 computer. The LOTEMP program has been used extensively by the Bechtel FFTF systems analysis group since 1972 in the preliminary design of FFTF Class 1 piping. The ME913 program has 3.9-24 HCGS-UFSAR Revision 0 April 11, 1988

been used to analyze Class 1 piping for Bechtel nuclear power plant projects. The Grand Gulf project feedwater line was selected as a test problem. Hand calculations of a selected component in the piping system were performed in accordance with the sample problem discussed in Reference 3. 9-9. The results were compared with the computer output for equations 9 through 14 in ME913. Table 3. 9-3 shows the comparison between the ASME sample problem, Reference 3.9-9, and ME913 results. 3.9.1.2.5.4 Relief Valve Discharge Line Dynamic Forces Computer Program (NE805) Following an actuation of a relief valve, the incoming steam pressurizes the discharge line, forcing the water leg (which could be at the normal water level, as in a first actuation of the relief valve, or an elevated level which is possible for subsequent actuation) out of the discharge line. Following water clearing, steam is discharged into the suppression pool. The water clearing and steam blowdown cause dynamic forces on the relief valve discharge line. Bechtel computer code RVCL (NE805) is used for analysis of discharge transients following a relief valve opening. NE805 is capable of modeling a discharge line of changing cross-sectional area. The code predicts the time dependent forces on the various segments of the relief valve discharge line. It models the steam flow through the relief valve and the steam air flows in the line. It also models the w~ter flow in the discharge line during water clearing. The options for the exit device are a straight pipe, a ramshead, or a quencher model in a reservoir. The quencher model considers sequential uncovering the quencher holes during air/water* clearing. NE805 uses the method of characteristics and allows for heat transfer through the pipe wall. It calculates 3.9-25 HCGS-UFSAR Revision 0 April 11, 1988

flow parameters, pressure, velocity, and density as functions of time and the distance along the discharge line. Using these calculated values, the code computes the dynamic forcing functions induced on various pipe segments of the relief valve discharge line. The force output can be used directly for piping stress analysis in codes such as MElOl, as described in Section 3. 9 .1. 2. 5 .1. NE805 generates plots of flow parameter histories and/or force time histories, an option specified by the user. The plots can be obtained on both CALCOMP 1036 and the Tektronix plotters. Development of the RVCL (NE805) program began in 1975 and is being continuously supported by Bechtel Power Corporation. It has been used by various Bechtel projects. The NE805 program has been verified against Monticello Mark I T~quencher test. Karlstein Mark II T-quencher test, and Caorso X-quencher test. Comparison with test data was found to be reasonable. The current NE805 version is being used by Bechtel Power Corporation. A UNIVAC 1100 computer is used for executing the NE805 program. 3.9.1.2.5.5 ME210 - Local Stress in Cylindrical Shells due to External Loads This standard presents a method of analyzing and determining local stresses in cylindrical shells due to external moments and forces acting on rigid attachments of circular or rectangular shape. This program is based on a paper 'Local Stresses in Spherical and Cylindrical Shells due to External Loadings' by Wichman, Hopper & Mershon, published in Welding Research Council Bulletin No. 107, August 1965 and March 1979 Revision. Values from Bij laard curves are obtained by interpolation procedures. This program also calculates piping stress intensity due to internal pressures and moments in accordance with the pressure and moment 3.9-26 HCGS-UFSAR Revision 0 April 11, 1988

stress calculations specified in EQ. 9 and EQ. 10 of ASME Section III NB-3650. The local stress intensity and piping stress intensity are summed and printed out if the required information for piping stress calculation is specified in the input. If no information for piping stress calculation is given, only the local stresses including primary plus secondary stress intensity and primary membrane stress intensities are printed out. ME210 is executed on the UNIVAC 1100 Mainframe Computer (System B). This program has been utilized by Bechtel on various projects. 3.9.1.2.5.6 ME602 - Spectra Merging and Simplified Seismic Analysis ME602 performs the seismic analysis of small diameter piping systems (2 inch and under) using the modified response spectrum method described in BP-TOP-1, Rev. 3. The program generates a set of tables of seismic spans, support reactions and stresses for various pipe sizes. This program performs response spectrum curve merging along with the calculation of the seismic span. The program can be also used independently for the sole purpose of merging spectrum curves and storing the combined spectrum data for MElOl analysis. A neutral plot file of the "RAW" or "COMBINED" spectrum curves can be generated for plotting on RMS, TEKTRONIX, CALCOMP or any neutral file compatible plotter. ME602 is executed on the UNIVAC 1100 Mainframe Computer (System B)

• This program has been utilized by Bechtel on various projects.

3.9.1.2.5.7 MA099 - ME101 Interactive Program The ME101 Interactive Program operates on three types of data. The first type is an ME101 image deck. In this case the deck can be transferred from the Univac to the Chromatics (typically CADME (ME099) deck from CAD file) then converted by the Chromatics into an 3.9-27 HCGS-UFSAR Revision 8 september 25, 1996

MElOl Interactive Random I/O access data base. The second type is created directly on the ME101 workstation using the Data Manager and Input/Modify program modules. Any ME101 Interactive data (Random I/O access) file can be converted back into MElOl image file by going through "FORMAT" in "RUN" module. ME101 results from the Univac are the third type, and must be converted into MElOl Interactive data base in order to display results in tables or graphic plots. These three types of data file can be saved on the Chromatics internal hard disk or stored on 8-inch single double density floppy disk. The data stored on floppy disk, which provides inexpensive storage, can be used on any other MElOl workstation. The ME101 Interactive Program uses a Chromatics CGC7900 color graphics microcomputer. 3.9.1.2.5.8 CE798 - ANSYS Program The ANSYS program is a self-contained general purpose finite element program developed and maintained by Swanson Analysis Systems, Inc. The program contains many routines, all interrelated, and all for the main purpose of achieving a solution to an engineering problem by the finite element method. The ANSYS program is designed to be user oriented. It does not require special knowledge of system operations or computer programming in order to be used. The basic input is straightforward and easily learned. In addition, the program flexibility allows various methods of arriving at the same solution. The flexibility, capabilities, and options have been developed over many years, at the request of a worldwide user community, such that the ANSYS program can be applied to a wide variety of engineering applications. CE798 is executed on the UNIVAC 1100 Mainframe Computer (System B). 3.9-28 HCGS-UFSAR Revision 8 september 25, 1996

3.9.1.2.5.9 ME351

• Pipe Rupture Analysis Program This program performs nonlinear elastic plastic analysis of three dimensional piping systems subjected to concentrated static or dynamic time history forcin& functions. These forces may result from fluid jet thrust at the location of a postulated rupture of high energy piping. PIPERUP is an adaptation of the finite element method to the specific requirements of pipe rupture analysis.

Straight and curved beam (elbow) elements are used to mathematically represent the piping and axial and rotational springs are used to represent restraints. The stiffness characteristics of piping and restraints can reflect elastic/linear strain hardening material properties, and gaps between piping and restraints can be modeled. ME351 is executed on the UNIVAC 1100 Mainframe Computer (System B). Various Bechtel projects utilize this program. 3.9.1.2.5.10 ME632 - Piping System Analysis ME632 performs stress analysis of 3 dimensional piping syseems. The effects of thermal expansion, uniform load of the pipe, pipe contents and insulation, concentrated loads, movements of the piping system supports, and other external loads, such as wind and snow, may be considered. A response spectrum analysis may be performed to analyze the effect of earthquake forces on the piping system, and transient effects of water hammer, steam hammer, or other impulsive type dynamic loading are also handled by the program. ME632 is executed on the UNIVAC 1100 Mainframe Computer (System B). 3.9.1.2.5.12 ME909

• Spectra Curves Merging This program merges individual response spectra curves, makes a neutral plot file of these curves, and produces data cards for MElOl seismic analysis.

3.9-29 HCGS-UFSAR Revision 0 April 11, 1988

The test data to validate this conversion program is available upon request from the Program Manual Library in San Francisco or the Library in Gaithersburg. ME909 is executed on UNIVAC 1100 Mainframe Computer (System B) and has been utilized by Bechtel on various projects. 3.9.1.2.5.12 BASEPLATE II (CE-035) BASEPLATE II consist of a pre- and a post-processor for the STARDYNE structural analysis system, with the specific purpose of analyzing flexible baseplates on a geometrically non-linear foundation. The pre-processor program automatically creates a finite element model of the prescribed structure and generates the appropriate STARDYNE input data and control cards. The capabilities include multiple attachments specification, standard library attachments and non-library attachments, integral framed structure, mixed support conditions and several load cases. The post-processor program sorts the STARDYNE output and tabulates the relevant results. CE-035 utilizes the CDC computer. 3.9.1.2.5.13 BASEPLATE (ME-035) The finite element method is used to analyze the baseplate response. The EAL (Engineering Analysis Language) is employed for solution of the problem and for post-processing of results, special pre-processor was written for model generation. The model generation is controlled through input parameters by the user. The plate elements are based on mixed formulation which allows computation of stresses in nodal points, the contact between the baseplate and the concrete or deactivated depending on the negative or positive displacement. Bolts are considered as combination of general stiffness matrix and one dimensional elements. Iterative solutions are used to find the final configuration starting with the assumption that all bolt springs are active. 3.9-30 HCGS*UFSAR Revision 0 April 11, 1988

ME-035 utilizes the UllOO computer, system B. 3.9.1.2.5.14 BOLT Program (CE-050) CE-050, "BOLTS", is a FORTRAN computer program which will determine concrete expansion and grouted-in anchor loads and interaction values for baseplates anchored with symmetrical 4, 6, or 8 bolt patterns which incorporate the effects of the base plate flexibility and bolt stiffness. The program resides on the Bechtel Univac System under the EXEC 8 operating system. BOLTS is intended to be executed interactively from a remote terminal thus providing immediate results for design/analysis problems. The program is well suited to the evaluation of base plates commonly used in pipe, conduit, HVAC, cable tray, and other small equipment supports. Empirically generated relationships are employed to analyse centrally loaded, symmetrical, unstiffened plates. CE-050 utilizes the UllOO computer, system B. 3.9.1.2.5.15 WELD Program (ME-120) This program presents a method of determining fillet weld size for the connecting structural member based on the approach described in "Design of Welded Structures" by O.W. Blodgett, and "Solutions to Design of Weldments" by O.W. Blodgett. The main objective of this program is to minimize the total weld length. ME-120 utilizes the UllOO computer, system B. 3.9.1.2.5.16 FAPPS (ME-150) "FAPPS" (Frame Analysis Program for Pipe Support) is an interactive computer program specifically developed for the analysis and design of 18 standard frames ("easy input") as well as any non-standard 3.9-31 HCGS*UFSAR Revision 0 April 11, 1988

frame for pipe support. It optimizes member sizes, welds, base plates and embedments based upon various user specified design limitations. ME~l50 utilizes the UllOO computer, system B. 3.9.1.2.5.17 Anchor Plate (ME-225) This program presents a method of analyzing plate type piping anchors. The program determines the following:

1. Thickness of anchor plate

2. Thickness of guide plate

3. ~elds joining the plate and process pipe

4. ~elds joining the supporting structure

5. Take-out dimensions of the anchor plate and the guide plate ME-225 utilizes the UllOO computer, system B.

3.9.1.2.5.18 Pipe Clamp (ME-226) This theory is developed for a program which computes the minimum required thickness and the stresses at two critical sections, for six special cases of pipe support clamps. The forces and resultant stress in the clamp bolts are also computed. The program will also compute the forces and stress in the stanchion, welds, and the base plate if applicable. Finally, the program will compute certain clamp dimensions and the total weight of the clamp and its associated hardware. This theory uses linear elastic analysis. 3.9-32 HCGS-UFSAR Revision 0 April 11, 1988

ME*226 utilizes the UllOO computer, system B. 3.9.1.2.5.19 ICES STRUDL II (CE-901) STRUDL is a broad, extensive and general program for solving problems in Structural Engineering. CE-901 utilizes the UllOO computer, system B. 3.9.1.2.5.20 SI Yeld (ME-799) This program presents a method of determining fillet weld size for the connecting structural member based on the approach described in "Design of Welded Structures" by O.W. Blodgett, and "Solutions to Design of Yeldments" by O.Y. Blodgett. ME-799 utilizes the UllOO computer, system B. 3.9.1.2.5.21 EZPLOT (UE-170) EZPLOT is an interactive program installed on service bureaus which have CDC NOS 175 and NOS 176 computers. It plots structural analysis data written for the following programs: STARDYNE SACS (By special request: EASE 2 STRAN FLUSH, STRUDL, BSAP) NASTRAN In the case of STARDYNE, EZPLOT can create post processor plots of deflected shapes resulting from static or dynamic analyses. EZPLOT will read data for these programs and plot it directly on the screen of a plotting terminal, or it can create a neutral plot file which can be directed to any type of supported plotting device including pen plotters, VERSATEC, etc. Plotting terminals include TEKTRONIX (e.g., 4014) or TEKTRONIX compatible terminals. \....***1 HCGS-UFSAR Revision 0 April 11, 1988

UE*l70 utilizes the CDC computer. 3.9.1.2.5.22 UNIPLOT (UE-188) UNIPLOT (UE-188) was developed at Bechtel to provide the users with a device independent computer graphics library. The neutral plot file, generated by UE-188 subroutines, can be directed to any one of Bechtel's graphics devices (e.g., Calcomp, Tektronix, RMS, Versatec, etc.), located at both the home and area offices. UE-188 operates on UNIVAC, IBM, and VAX, and can be used with programs written in FORTRAN (either the FOR or FTN compilers). All subroutines in the UE-188 library are Calcomp compatible. Therefore, any program written for the Calcomp plotters can be mapped with UE-188 to take advantage of its device independence. This includes programs that use the DISSPLA (UE-188) subroutines. UE-188 utilizes the UllOO computer, system B. 3.9.1.2.5.23 STARDYNE (CE-991) The STARDYNE Analysis System consists of a series of compatible digital computer programs designed to analyze linear elastic structural models. The system encompasses the full range of static and dynamic analyses. These programs provide the analyst with a sophisticated, cost effective, structural dynamical analysis system. CE-991 utilizes the CDC computer. 3.9.1.2.5.24 Hydraulic System Transient Analysis Computer Program (NE820) Bechtel's computer code HSTA (Hydraulic System Transient Analysis, NE820) is a code that can be used to analyze flow transients in 3.9-34 HCGS-UFSAR Revision 0 April 11, 1988

liquid systems. These transients are commonly referred to as water hammer and are a result of a rapid interruption of flow, filling of an empty line or collapsing of a void, etc. While the code can be considered as a general water hammer computer code, the specific needs that arise in the analysis of various nuclear power plant systems have received considerable attention. The code primarily calculates the pressure and velocity changes with time for various locations in the piping network. These variables can then be used to compute the dynamic forces for various pipe segments of the system. These forces represent the dynamic forcing function to be utilized in the structural analysis of the piping system and can be used directly in codes such as ME101. The code enables analysis of transients resulting from valve closure, valve opening, pump failure, pump startup, rapid depressurization, etc. It can model the liquid (water) column separation phenomenon (encountered in transients where pressures drop to the vapor pressure of the liquid). The code can also be used in the analysis of startup transients in'cases where the piping system is initially not full of liquid. The code can be applied to analyze steam or gaseous flow systems under situations having no significant changes in fluid density during the transient. To solve one dimensional unsteady flow problems, the mass and momentum conservation equations (along the pipe axis) are utilized to obtain pressure and velocity as functions of time and distance. The solution is based on the finite difference solution of the method of characteristics (MOC). The numerical scheme uses a constant time step constant distance grid. The solution starts from steady initial conditions and progresses to the desired time level. It allows for compressibility of the fluid and takes into account the elasticity of the pipe walls. Pipe frictional losses are also considered. Hydraulic devices are treated as boundary conditions. Several options of the HSTA code have been verified. In this verification effort, emphasis was placed on comparison with 3.9-35 HCGS-UFSAR Revision 0 April 11, 1988

experimental or test data; however, in some instances comparisons were made to independent numerically predicted results. The code verification incorporates comparison with test data or independently calculated data for valve closure, branching, pump failure, open surge vessel (with one way check valve), air tank (for suppression of pressure surge), positive displacement pump, liquid (water) column separation in a horizontal line and in a siphon system and finally for line filling case. The current NE820 version is being extensively used by Bechtel Power Corporation. A UNIVAC 1100 Computer is used for executing the NE820 program. 3.9.1.2.5.26 GAFT - Program (NE810) GAFT (Gaseous Fluid Transients NE810), is a computer code that can be used to analyze flow transients in gaseous systems. When the fluid is ste8111 these transients are commonly referred to as ste8111 hammer. GAFTPLOT, designated as program number NE811, is a post processor plot program that allows the plotting of flow variables and force time histories that are calculated by GAFT. This code has been developed by Bechtel Power Corporation over the last several years. While it can be considered as a general computer code for gaseous fluid transients, the specific needs that arise in the analysis of nuclear power plant systems have received considerable attention. The code primarily calculates the pressure, velocity, density and sonic speed changes with time for various locations in the piping network. These variables can then be used to compute the dynamic forces for various pipe segments of the system. These forces represent the dynamic forcing functions to be utilized in the structural analysis of the piping system and can be used directly in codes such as ME101. The code enables analysis of transients resulting from valve closure, valve opening, pipe break, rapid depressurization, etc. As an example of the code application, the main steam piping system of 3.9*36 HCGS-UFSAR Revision 0 April 11, 1988

a nuclear power plant can be modeled on GAFT. Events such as the turbine stop valve closure or a break in the main steam line, can then be analyzed to calculate the dynamic forcing functions for pipe segments in the main steam piping. An assumption in such an analysis would be that steam behaves as an ideal gas. To solve one dimensional unsteady flow problems, the mass, energy, momentum and conservation equations (along the pipe axis) are utilized together with an equation of state to obtain pressure. velocity, density and sonic speed as functions of time and distance. The solution is based on the finite difference solution of the method of characteristics {MOC) . The numerical scheme uses a constant time step constant distance grid. The solution starts from steady initial conditions and progresses to the desired time level. It allows for compressibility of the fluid but assumes inelastic pipe walls. Pipe frictional losses are also considered. Hydraulic devices such as valves, restrictions, branching, etc. are treated as boundary conditions. Several options of the GAFT code have been verified. In the GAFT verifications endeavors, emphasis was placed on comparison with experimental or test data; however, in some instances comparisons were made to independent numerically predicted results. The present version incorporates comparisons between the code results and either measured or independently calculated data for valve closure, branching, pipe break and dead end hydraulic boundary devices. The current NE810/NE811 versions are being used extensively by Bechtel Power Corporation. A UNIVAC 1100 Computer is used for executing the NE810/NE811 Programs. 3.9.1.2.5.26 REPIPE

• Program (NE565)

Program REPIPE (NE565) computes the loading time history on a piping network from the Program RELAP hydrodynamic analysis of the contained fluid. 3.9-37 HCGS-UFSAR Revision 0 April 11, 1988

Complex piping networks experience a variety of forces generated by the fluid flow within them. These forces can be simply classified as steady state and transient. Steady state forces are those which are present during the normal operation of the system. Initial design efforts recognize these forces and compensate for them with appropriate support. However, in abnormal situations, such as inadvertent valve operation, pipeline rupture, or a pump malfunction within the network, the fluid forces change rapidly. These momentary or transient forces can be quite large, particularly in a power plant where the fluid is initially at high pressure and temperature. Determining the distortion of a piping network during a transient usually becomes a three step process. First. the time history behavior of the fluid within the pipe is calculated (the hydraulics programs). Second, the force time histories are calculated from the fluid behavior. Third, the piping network stresses over time are determined (the stress program). The transient hydraulic analysis employs either RE1AP4 or REIAPS. The RELAP series of computer programs compute time varying pressure, momentum flux and energy states throughout a fluid system containing water, steam, and/or a two phase mixture. The programs utilize a one dimensional fluid flow solution, and are particularly useful and efficient for transient flow in piping networks. REPIPE is the intermediate processor which operates on the output of the hydraulic program to produce force time histories for input to the stress program. 3.9.1.2.5.27 Thermal Hydraulic Transient Analysis Program (NE458) Program RELAPS/MODl (NE458) is an advanced thermal hydraulics program intended for the analysis of complex transients in nuclear reactors and piping networks. Equations of conservation of mass, energy, and momentum are solved in one dimension for steam and/or 3.9-38 HCGS*UFSAR Revision 0 April 11, 1988

water flow. The equations assume a non-homogenous mixture of steam and liquid, and non-equilibrium between phases can be modeled. The effects of noncondensible gas on steam/liquid flow are considered in the equations. Models are available to simulate pump, valve, and heat exchanger components, as well as complex control systems. RELAPS is expressly written for the analysis of both small and large break reactor loss-of-coolant accidents, but can be used to analyze many power plant operational transients. The program is frequently coupled with the post processor REPIPE to generate hydrodynamic loads on power plant piping. The current NE458 version is on the CDC computer system. 3.9.1.2.6 Dynamic Loads Analyses 3.9.1.2.6.1 Program for Dynamic/Seismic Responses of Three Dimensional Members - DYSEA The DYSEA program embodies the spatial finite element method together with temporal model superposition and response spectrum analysis features. The timewise solutions of the decoupled modal equations were obtained by using the Newmark-[Sb] integration scheme. The program permit one to predict the dynamic and/or seismic responses of structural systems that may be composed of three dimensional truss. beam, and spring members. The material properties are restricted to the linear, elastic stress strain behavior range. The program can handle dynamic systems having mass coupling such as through the hydrodynamic mass matrix, which may arise from the hydrodynamic interaction effect of the structure submerged in a potential fluid field. The structural system may be subjected to externally applied time dependent mechanical forces, earthquake excitations, and/or multiple support excitations. 3.9.1.2.6.2 Acceleration Response Spectrum Program - SPECA04 The SPECA04 computer program generates acceleration response spectrum, consistent with the requirements of Regulatory Guide 1.122 3.9-39 HCGS-UFSAR Revision 0 April 11, 1988

for an arbitrary input of the time history of piecewise linear accelerations, i . e. 1 to compute the maximum acceleration responses for a series of single degree of freedom systems subjected to the same input. It can accept acceleration time histories from a random file. It also has the capability of generating the broadened/enveloping spectra in conformance with Regulatory Guide 1.122 when the spectral points are generated equally spaced on a logarithmic axis of period/frequency. This program is also used in seismic and safety/relief transient analyses. 3.9.1.2.6.3 Forces and Moment Time Histories Program - GEAPL01 The GEAPL01 computer program converts distributed asymmetric pressure time histories over a area into time nodal forces and moments for use as input to perform dynamic of a system. The overall resultant forces and moment time histories at specified of resolution can also be obtained from GEAPLOl. 3.9.1.2.6.4 Dry Storage Cask Dynamic Loading- Visual Nastran The freestanding cask configurations are modeled using ldnematic computer program Visual Nastran as an assemblage of rigid bodies (of approximate size and mass) interconnected by spring and damping elements. The acceleration time histories in HI-2043145 are applied to the model as the input. 3.9.1.2.6.5 Generation of 3-D Acceleration Time Histories for Dry Storage Casks The time histories are developed in accordance with the applicable USNRC requirements (i.e., SRP 3.7.1) using the Holtec computer code GENEQ, which is a derivative of the commercially available code SIMQKE. This method of generation has been used by Holtec and approved by the NRC on numerous dockets in spent fuel rack 3.9-40 HCGS-UFSAR Revision 16 May 15, 2008

3.9.1.2.6.6 Reactor Building Structural Analysis for Dry Storage Casks The forces and moments in concrete slab and the underlying steel beams are solved using the finite element code ANSYS. The model is comprised of 4-noded shell elements representing the.concrete slab and 2-noded linear beam elements representing the steel I-beams. A response spectrum analysis is performed within ANSYS to obtain the f0rce and moment distribution in the slab due to its self-weight excitation under the OBE and SSE loading. The live loads and cask induced loads are solved by static linear analysis. The factored load combinations are assembled in ANSYS and the results are compared with the allowable load and stress limits in accordance with ECGS Design Criteria Document 10855-D2.1. 3.9.1.3 Experimental Stress Analyses No experimental stress analyses were utilized. 3.9.1.4 Considerations for the Evaluation of Faulted Conditions Each Seismic category I component is evaluated for the faulted loading conditions. In all cases, calculated stresses are within the allowable limits. The following paragraphs show examples of the treatment of faulted conditions for the major components on a component-by-component basis. Elastic-plastic analyses have not been used in evaluating the HCGS Seismic Category I systems and components for compliance with service level D limits. The stress levels of these components are below the stresses allowed by the ASME B&PV Code. Additional discussion of the faulted event and analyses can be found in Sections 3.9.3 and 3.9.5, and Tables 3.9-1 and 3.9-4. 3.9-40a HCGS-UFSAR Revision 16 May 15, 2008

THIS PAGE INTENTIONALLY BLANK 3.9-40b HCGS-UFSAR Revision 16 May 15, 2008

Seismically designed piping is separated from non-Seismic Category I piping by seismic boundary anchors. These anchors are designed for the combined load generated from both sides of the boundary anchor. The loads from the Seismic Category I side are actual calculated loads, and the loads* from the non-Seismic Category I side are determined by one of the following:

a. Loads determined by the plastic capability of the piping,

b. If the loads calculated by item a. are excessively high, then seismic loads for the non-seismic Category side are calculated using dynamic seismic analysis or equivalent static seismic analysis,

c. Actual calculated loads if the non-seismic side piping is isolated by a combination of anchor and restraints. This combination is designed to a simplified seismic design criteria (e.g., by simplified span method such as those used for the design of small piping).

See Section 3.7.3.13. Sections 3. 9. 2. 3 and 3. 7 discuss the treatment of dynamic loads resulting from the postulated SSE. Section 3. 9. 2. 7 discusses the dynamic analysis of loads on NSSS equipment resulting from blowdown. Deformations under faulted conditions were evaluated in critical areas. and no cases are identified where design limits, such as clearance limits, are exceeded. 3.9.1.4.1 Control Rod Drive System Components 3.9-41 HCGS-UFSAR Revision 0 April 11, 1988

3.9.1.4.1.1 Control Rod Drives The major CRD components that were analyzed for the faulted conditions are the ring flange, and the indicator tube. The maximum stresses for these components, and for various plant operating conditions, including faulted conditions, are given in Table 3.9*4w. The ASME B&PV Code, Section III components of the CRD have been analyzed for scram with an inoperative buffer and for a scram with a stuck control blade conditions shown in Section 3. 9 .1.1.1. The loads and stresses are within the elastic limits of the material. No analysis was made for the non-Code components of the CRD for the abnormal condition. The design adequacy of non-Code components of the CRD has been verified by extensive testing programs on both component parts, specially instrumented prototype drives, and production drives. The testing has included postulated abnormal events , as we 11 as the service life cycles listed in Section 3.9.1.1.1. 3.9.1.4.1.2 Hydraulic Control Unit The hydraulic control unit (HCU) was analyzed for the faulted condition. The analysis of the HCU under faulted condition loads establishes the structural integrity of the system. Section 3.9.2.3.2.4 discusses the dynamic qualification of the HCU. 3.9.1.4.2 Standard Reactor Internal Components 3.9.1.4.2.1 Control Rod Guide Tube The maximum calculated stress on the control rod guide tube occurs in the base during the faulted condition. The faulted limit is the lesser of 2. 4 S or 0. 7 S at the design temperature, per ASME B&PV Code, Section III, Table Fl322*1. Per ASHE B&PV Code, 3.9-42 HCGS-UFSAR Revision 0 April 11, 1988

Section III, Table I*l.2, S equals 57,500 psi and Sm equals 16,000 psi at 575°F, and the results are summarized in Table 3.9-4aa. 3.9.1.4.2.2 In-core Instrument Housing The maximum calculated stress on the in-core instrument housing occurs at the outer surface of the vessel penetration during the faulted condition. The calculated and allowable stresses are shown in Table 3.9-4bb. 3.9.1.4.2.3 Jet Pump The elastic analysis for the jet pump faulted conditions shows that the maximum stress occurs at the jet pump riser. The stress analysis results are summarized in Table 3.9-4y. 3.9.1.4.2.4 Low Pressure Coolant Injection Coupling The stresses on the low pressure coolant injection (LPCI) coupling are very low during a faulted event, due to its flexibility. The maximum stress due, to faulted loads. and the allowable stress are given in Table 3.9*4z. 3.9.1.4.2.5 Orificed Fuel Support See Section 3.9.1.3.2. 3.9.1.4.2.6 CRD Housing The SSE is classified as a faulted condition. The maximum stress on the CRD housing during an SSE is 22,030 psi. The maximum design stress limit for this event is 2.4 S which equals 40,000 psi, and m the ultimate strength of the material is 57,000 psi. 3.9-43 HCGS-UFSAR Revision 0 April 11, 1988

The CRD housing was analyzed for a faulted condition, including an SSE. Table 3.9-4x shows the loading conditions, load combinations, analytical methods, and allowable and calculated stress values for the highly stressed areas of the CRD housing. 3.9.1.4.3 Reactor Pressure Vessel Assembly For the faulted conditions, the RPV and shroud support were evaluated using elastic analysis methods. Ultimate strength allowable values were not used since the emergency allowable stress limits of ASME B&PV Code, Section III, were used for the faulted stress cases. Table 3.9-4b lists the calculated and allowable stresses for the various loading combinations. 3.9.1.4.4 Core Support Structure The evaluations for faulted conditions for the core support structure are discussed in Section 3.9.5. The calculated and allowable stresses are summarized in Tables 3.9-4b and 3.9-4c. 3.9.1.4.5 Main Steam Isolation, Recirculation Gate, and Safety/Relief Valves Tables 3.9*4i, 3.9-4j, and 3.9-41 provide a summary of the analyses of the safety/relief, main steam isolation, and recirculation gate valves, respectively. Standard design rules, as defined in applied codes, are used in the analysis of pressure boundary components of Class 1 active valves. Conventional elastic stress analyses are used to evaluate components not defined in the ASME B&PV Code. The allowable Code stresses are applied to determine acceptability of the structure under applicable loading conditions, including the faulted condition. HCGS-UFSAR Revision 0 April 11, 1988

3.9.1.4.6 Main Steam and Recirculation Piping For main steam and recirculation system piping, elastic analysis methods are used for evaluating faulted loading conditions. The equivalent allowable stresses using elastic techniques are obtained from the ASME B&PV Code, Section III, Appendix F, Rules for Evaluation of Faulted Conditions, and these are above elastic limits. Additional information on the main steam and recirculation piping is presented in Tables 3.9-4e through 3.9-4h. 3.9.1.4.7 Nuclear Steam Supply System Pumps, Heat Exchangers, and Turbine The recirculation, Emergency Core Cooling System {ECCS), reactor core isolation cooling (RCIC), and standby liquid control {SLC) pumps; the residual heat removal (RHR) heat exchangers; and the RCIC turbine were analyzed for the faulted loading conditions identified in Section 3.9.3.1. In all cases, stresses are within the elastic limits. The analytical methods, stress limits, and allowable stresses are discussed in Sections 3.9.2.3 and 3.9.3.1. 3.9.1.4.8 Control Rod Drive Housing Supports Examples of the calculated stresses, and the allowable stress limits for the faulted condition for the CRD housing supports, are shown in Table 3.9-4cc. 3.9.1.4.9 Fuel Storage Racks Examples of the calculated stresses and stress limits for the faulted conditions for the new fuel storage racks are shown in Table 3.9-4u. 3.9.1.4.10 Fuel Assembly (Including Channel) GE boiling water reactor (BWR) fuel assembly (including channel} design bases, analytical methods, and evaluation results, including 3.9-45 HCGS-UFSAR Revision 0 April 11, 1988

those applicable to the faulted conditions, are contained in References 3.9-10 and 3.9-11. The acceleration profiles are summarized in Table 3.9-4ee. I Specific analysis of ABB fuel is performed to demonstrate compliance with applicable design criteria. The ABB fuel Assembly (including channel} design bases and analytical methods are described in Reference 3.9-24 and 3.9-25. 3.9.1.4.11 Refueling Equipment Refueling and servicing equipment important to safety are classified as essential components, per the requirements of 10CFRSO, Appendix A. This equipment, and other equipment whose failure would degrade an essential component, are defined in Section 9.1 and are classified as Seismic Category I. These components are subjected to an elastic, dynamic, finite element analysis to generate loadings. This analysis uses appropriate seismic floor response spectra and combines loads at frequencies up to 33 hertz in three directions. Imposed stresses are generated and combined for normal, upset, and faulted conditions. Stresses are compared, depending on the specific safety class of the equipment, to industrial codes; ASME, ANSI or industrial standards, or AISC allowables. The calculated and allowable stresses are summarized in Table 3.9-4u. 3.9.1.4.12 Non-NSSS Seismic Category I System Components The stress allowables of Appendix F of the ASME B&PV Code, Section III, in effect at the award of each purchase order, were used for Code components. For non-Code components, allowables were based on tests or accepted standards consistent with those in Appendix F of the Code. Dynamic loads for components loaded in the elastic range were calculated using dynamic load factors, time history analysis, or any other method that assumes elastic behavior of the component. The limits of the elastic range are defined in paragraph 1323 of Appendix F of the ASME B&PV Code, Section III for the Code components. The local yielding due to stress concentration is assumed not to affect the validity of the assumptions of elastic behavior. The stress allowables of Appendix F for 3.9-46 HCGS-UFSAR Revision 11 November 24, 2000

elastically analyzed components were used for Code components. For non-Code components, allowables were based on tests or accepted material standard consistent with those in Appendix F for elastically analyzed components. The methods used in evaluating the pipe break effects are discussed in Section 3.6. 3.9.1.4.13 Piping Branch Connection Design All branch design branch connections for ASHE Section III Class 1, 2, and 3 piping allow only the use of integrally reinforced fittings. Design drawings supplied to the piping fabrication stipulate the type of branch connection to be used based on run pipe size, branch pipe size and piping class, temperature and pressure. The piping fabricator is required to perform reinforcement calculations for all branch connections except where the ASHE Section III excludes such calculations. For Class 1 piping, reinforcement calculations are included in the stress report. At the branch connection, appropriate stress intensification or stress indices are used to determine the maximum. stresses due to mechanical loads. Moments from three legs are considered in evaluation of branch connection. NSSS: All branch connections are designed to meet the requirements of paragraph NB-3643. 3 of Section III of the ASHE B&PV Code for the reinforcement of openings. For branch connections, the stress indices of NB-3681 are used to compute the stresses resulting from internal pressure and mechanical loadings. Compliance with the B&PV Code stress criteria is documented in the piping design reports. Branches with nominal diameters less than one-fourth of the diameter of the pipe run are decoupled from the large pipe models and HCGS-UFSAR Revision 0 April 11, 1988

analyzed separately. The small branch pipes are not in the General Electric scope of supply; however, to ensure they have a negligible effect on the large piping runs, the mechanical loadings from the small pipe are provided by the organization responsible for the small pipe (Bechtel Power Corporation). 3.9.2 Dynamic Testing and Analysis Dynamic testing and analysis are performed for the purpose of verifying the capacity of mechanical systems and components to satisfy dynamic design requirements under plant operating conditions. Depending on the components, the operating event, and the feasibility of either analysis or testing, the design for dynamic performance normally rests generally upon analytical calculations. In this context, testing generally serves to verify the dynamic calculations of the system dynamic performance. In some cases, due t~ either the unpredictability of loads or the complexity of structural response, primary design verification results from testing. An example of this latter case occurs in the steady state vibration evaluation of piping systems. In general, dynamic testing and analysis are organized in two parts:

1. Nuclear Steam Supply Systems (NSSS) Systems

2. Non-NSSS, Balance Of Plant {BOP) Systems.

3.9.2.1 Tberma1 Expansion. Pipin& Vibration. and Qynamic Effects in NSSS Pipin& The test progr~ is divided into three phases: thermal expansion, piping vibration, and transient dynamic effects. 3.9-48 HCGS-UFSAR Revision 0 April 11, 1988

3.9.2.1.1 Thermal Expansion Testing of Main Steam and Recirculation Piping The thermal expansion preoperational and startup testing program is performed through the use of potentiometer sensors and verifies that normal thermal movement occurs in the piping systems. The main purpose of this program is to ensure the following:

1. The p~ping system during system heatup and cooldown is free to expand, contract, and move without unplanned obstruction or restraint in the x, y, and z directions.

2. The piping system is working in a manner consistent with the assumptions of the stress analyses.

3. There is adequate agreement between calculated and measured values of displacement~

4. There is consistency and repeatability in thermal displacements during heatup and cooldown of the systems.

Thermal expansion displacement limits are established before the start of testing. The meas~red displacements are compared with these limits to determine the acceptability of the measured motion. If the measured displacement is shown to be within the acceptance limits, the piping system is moving in a manner consistent with the stress analyses. On that basis, the pipe thermal expansion behavior is acceptable. Two levels of displacement limits criteria, level 1 and level 2, are described in Section 3.9.2.1.4. 3.9.2.1.2 Piping Vibration 3.9.2.1.2.1 Preoperational and Startup Vibration Testing of Recirculation Piping The purpose of the vibration test phase is to verify that the operating vibration level in the recirculation piping is within 3.9-49 HCGS-UFSAR Revision 0 April 11, 1988

acceptable limits. This phase of the test uses visual observation and, if necessary, hand held instrumentation to supplement remote measurements. If, during steady state operation, visual observation indicates that vibration is significant, measurements are made with a hand held vibrograph. Testing is done during the following steady-state conditions:

1. Minimum flow

2. 50 percent of rated flow

3. 75 percent of rated flow

4. 100 percent of rated flow

5. With RHR in the shutdown cooling mode at rated RHR shutdown cooling loop flow.

3.9.2.1.2.2 Preoperational Vibration Testing of Small Attached Piping During visual observation of each of the above test conditions, 1. through 5., attention is given to small attached piping and instrument connections to ensure that they are not in ~esonance with the recirculation pump motors or flow induced vibrations. If the operating vibration acceptance criteria are not met, corrective action such as modification of supports is taken. 3.9.2.1.2.3 Operating Transient Loads on Main Steam and Recirculation Piping The purpose of the operating transient test phase is to verify that pipe stresses are within ASME B&PV Code limits. The amplitude of displacements and number of cycles per transient of the main steam and recirculation piping are measured and displacements compared with acceptance criteria. The deflections are correlated with stresses to verify that the pipe stresses remain within ASME B&PV 3.9-50 HCGS-UFSAR Revision 0 April 11, 1988

Code limits. Remote vibration and deflection measurements are taken during the following transients:

1. Recirculation pump start

2. Recirculation pump trip at 100 percent of rated flow

3. Turbine main stop valve closure at 100 percent power

4. Manual discharge of each safety/relief valve (SRV) at 1000 psig and at planned transient tests that result in SRV disc~arge.

3.9.2.1.3 Dynamic Effects Testing of Main Steam and Recirculation Piping Systems To verify that snubbers are adequately performing their intended function during the plant operation, a program for dynamic testing as a part of the initial startup operation testing is conducted. The main purpose of this program is to ensure the following:

1. The vibration levels from the various dynamic loadings during transient and steady state conditions are below the predetermined acceptable limits.

2. Long term fatigue failure does not occur due to underestimating the dynamic effects caused by cyclic loading during plant transient operations.

The purpose of dynamic testing is to account for the acoustic wave due to the SRV lift (RVl), SRV loads resulting from air clearing (RV2). and turbine main stop valve closure loads (TSVC). The maximum stress developed in the piping from the RVl, RV2, and TSVC transients is used as a basis for establishing criteria that ensure proper functioning of the snubbers. If field measurements are within criteria limits, snubbers are assumed to be functioning properly. Snubbers are tested to allow free piping movements at low 3.9-51 HCGS-UFSAR Revision 0 April 11, 1988

velocity. During plant startup, the snubbers are checked for proper settings and for any evidence of hydraulic fluid leakage. The above testing was performed with the original Target Rock 2-Stage SRVs installed at original plant startup. Subsequently, Target Rock 3-Stage SRVs have been evaluated and approved for installation at Hope Creek. Results from the above testing remain valid because the 3-Stage SRVs have the same set pressures, capacities, and response times as the 2-Stage SRVs. 3.9.2.1.4 Test Evaluation and Acceptance Criteria for Main Steam and Recirculation Piping Systems The piping response to test conditions is considered acceptable if the organization responsible for the stress report reviews the test results and determines that the tests verify that the piping responded in a manner consistent with the predictions of the stress report and/or that the tests verify that piping stresses are within limits of the ASME B&PV Code, Section III, NB-3600. Acceptable deflection and acceleration limits are determined after the completion of piping systems stress analyses and are provided in the startup test specifications. To ensure test data integrity and test safety, criteria are established to facilitate assessment of the test while it is in progress. These criteria, designated level 1 and level 2, are described in the following paragraphs. The criteria for vibration displacements are based on an assumed linear relationship between displacements, snubber loads, and magnitude of applied loads for any function and response of the system. Thus the magnitude of the limits of displacements, snubber loads, and nozzle loads, are all proportional. Maximum displacements, level 1 limits, are established to prevent the maximum stress in the piping systems from exceeding the normal and upset primary stress limits and/or the maximum snubber load from exceeding the maximum load to which the snubber has been tested. Based on the above criteria, level 1 displacement limits are established for all instrumented points in the piping system. These limits are compared with the field measured piping displacements. The methods of acceptance are explained in the following paragraphs. 3.9.2.1.4.1 Level 1 Criteria Level 1 criteria establish the maximum limits for the level of pipe 3.9-52 HCGS-UFSAR Revision 23 November 12, 2018

motion, which, if exceeded, would make a test hold or termination mandatory. If the level 1 limit is exceeded, the plant will be placed in a satisfactory hold condition; and the responsible piping design engineer will be advised. Following resolution, applicable tests will be repeated to verify that the requirements of the level 1 limits are satisfied. 3.9.2.1.4.2 Level 2 Criteria If the level 2 criteria are satisfied for both steady state and operating transient vibrations, there will be no fatigue damage to the piping system due to steady state vibration; and all operating transient vibration will be bounded by the values in the stress report. If the pipe motions specified by level 2 criteria are exceeded, the responsible piping design engineer will be advised. Plant operational and startup testing plans will not necessarily be altered. Investigations of the measurements, criteria, and calculations used to generate the pipe motion limits will be initiated. An acceptable resolution must be reached by all appropriate and involved parties, including the responsible piping design engineer. Detailed evaluation will be needed to develop corrective action or to show that the measurements are acceptable. Depending upon the nature of the resolution, the applicable tests may or may not be repeated. 3.9.2.1.4.3 Acceptance Limits For steady state vibration, the pipe break stress due to vibration only (neglecting pressure) will not exceed 10,000 psi for level 1 criteria and 5,000 psi for level 2 criteria. These limits are below the piping material's fatigue endurance limits as defined by the 6 design fatigue curves for 10 cycles in Appendix I of the ASME B&PV Code. 3.9-53 HCGS-UFSAR Revision 0 April 11, 1988

For operating transient vibration, the piping bending stress (zero to peak) due to an operating transient only will not exceed 1.2S or pipe support loads will not exceed the service level D ratings for level 1 criteria. The 1.2S limits ensures that the total primary stress, including pressure and dead weight, will not exceed l.SS , m the new service level B limit. Level 2 criteria are based on pipe stresses and support loads not exceeding design basis predictions. Design basis criteria require that operating transient stresses and loads not exceed any of the service level B limits including the primary stress limits, the fatigue usage factor limits, and the allowed loads on snubbers. 3.9.2.1.5 Corrective Actions for Main Steam and Recirculation Piping Systems During the course of the tests, the remote measurements are regularly checked to determine compliance with level 1 criteria. If trends indicate that level 1 criteria may be exceeded, the measurements are monitored at more frequent intervals. The tests are* placed on hold or terminated as soon as level 1 criteria are exceeded. As soon as possible after the test hold or termination, the following corrective actions are taken:

1. Installation inspection

• A walkdown of the piping and suspension is made to identify any obstruction or improperly operating suspension components. Snubbers are installed to about the midpoint of their total travel range at operating temperature. Hangers are in their operating range between the hot and cold settings. If vibration exceeds criteria, the source of the excitation is identified to determine if it is related to equipment failure. Action is taken to correct any discrepancies before repeating the test.

2. Instrumentation inspection The instrumentation installation and calibration are checked and any 3.9-54 HCGS-UFSAR Revision 0 April 11, 1988

discrepancies correcte~. Additional instrumentation is added, if necessary.

3. Repeat test If actions 1. and 2. above identify discrepancies that could account for failure to meet level 1 criteria, the test is repeated after correction of the discrepancies.

4. Resolution of findings If the level 1 criteria are violated on the repeat test or no relevant discrepancies are identified in actions 1. and 2. above, the organization responsible for the stress report reviews the test results and criteria to determine if the test can be safely continued.

If the test measurements indicate failure to meet level 2 criteria, the following corrective actions are taken after completion of the test:

1. Installation inspection

• A walkdown of the piping and suspension is made to identify any obstruction or improperly operating suspension components. If vibration exceeds limits, the source of vibration is identified.

Action, such as suspension adjustment, is taken to correct any discrepancies.

2. Instrumentation inspection The instrumentation installation and calibration are checked and any discrepancies corrected.

3. Repeat test

• If actions 1. and 2. above identify a malfunction or discrepancy that could account for failure to comply with level 2. criteria, and appropriate corrective action has been taken, the test may be repeated.

3.9-55 HCGS-UFSAR Revision 0 April 11, 1988

4. Documentation of discrepancies If the test is not repeated. the discrepancies found under actions 1. and 2.

above are documented in the test evaluation report and correlated with the test condition. The tests are not considered complete until the test results are reconciled with the acceptance criteria. 3.9.2.1.6 Measurement Locations for Main Steam and Recirculation Piping Remote shock and vibration measurements are made in the three orthogonal directions near the first downstream SRV on each steam line and in the three orthogonal directions on the piping between the recirculation pump discharge and the first downstream valve. During preoperational testing prior to fuel load, visual inspection of the recirculation piping is made. and any visible vibration is measured with a hand held instrument. For each of the selected remote measurement locations, level 1 and 2 deflection limits are prescribed in the startup test specification. The exact location of measuring devices and visual inspection points will be supplied in the test program. Measurements taken at these points will show if the stress and fatigue limits are within acceptable levels. 3.9.2.2 Preoperational and Startup Testins of Non-NSSS Pipin& 3.9.2.2.1 Scope The test program is organized on the basis of three of the main types of non-NSSS pipe loads: thermal expansion, steady state pipe vibration, and dynamic transient pipe vibration. Testing under earthquake or postulated accident conditions is not included. The scope of piping to be considered in testing includes:

1. All ASME B&PV Code Class 1, 2, and 3 piping systems, other than NSSS piping

3. 9-56.

HCGS-UFSAR Revision 0 April 11, 1988

2. Other high energy piping within Seismic Category I structures and selected piping systems in the turbine building

3. High energy portions of any system whose failure could reduce the functioning of any Seismic Category I system to an unacceptable safety level

4. Seismic Category I portions of moderate energy piping systems located outside primary containment.

A list of all non-NSSS piping systems* within this scope is provided in Table 3.9-5. This table identifies the preoperational or power ascension test category applicable for each system. Where appropriate, remarks indicate the reasons for including or excluding testing. A test specification covers test activities. It provides, in detail, the test scope, the purpose, the exact location of measuring devices and visual inspections points, and the instrumentation requirements. Criteria for acceptance of test measurement data are also provided in the specification. Cognizant design personnel familiar with the systems to be tested develop the test plans, witness the test, and evaluate the test results. The data acquired from the tests are compared with the expected results to determine the acceptability of the system response. 3.9.2.2.2 Thermal Expansion Testing of Non-NSSS Piping Piping thermal expansion tests are performed for safety related piping systems with a normal operating temperature that exceeds 3QO*F. Operating experience has shown that piping systems with an operating temperature of less than Joo*F do not warrant thermal expansion tests. Engineering review of all Seismic Category I piping systems is performed .after completion of construction and prior to fuel load. Supports, restraints, and snubbers are reviewed to ensure that normal thermal movement is not restrained as a result 3.9-57 HCGS-UFSAR Revision 0 April 11. 1988

of interferences or obstructions. In the tests, pipe thermal movements are monitored to confirm that restraint does not occur as a result of interference or obstruction at locations other than at the designed restraint locations. Free thermal expansion movement at snubbers is verified in the tests by data evaluation for remotely monitored piping, and by monitoring compression or extension travel of snubbers for visually checked piping. Acceptance crite*ria for thermal expansion tests are based on two requirements:

1. Restraint of thermal expansion movement must be compatible with design restraint conditions

2. Thermal expansion movements must agree with calculated movements within the tolerance band prescribed in the test specification.

Corrective actions to be taken in instances where thermal expansion acceptance criteria are not satisfied are:

1. Identification of t;he location and cause of the abnormal restraint of thermal movement

2. Initiation of administrative procedures to eliminate the abnormal restraint

3. Repetition of the test for demonstration of compliance with acceptance criteria.

Non~NSSS piping systems included in preoperational and startup testing for thermal expansion movement are listed in Table 3.9-5. 3.9.2.2.3 Steady State Vibration Testing of Non*NSSS Piping Systems Pipe vibration is the result of periodic application of forces induced by fluid flow oscillations or by equipment vibration. Such 3.9-58 HCGS-UFSAR Revision 0 April 11, 1988

vibration, if prolonged and at a high level, contributes to reduction of the fatigue life of the pipe system. Steady state vibration level is categorized according to whether it is negligible or questionable. Negligible vibration amplitude is small enough that the judgement of the qualified test engineer is sufficient to determine that it is clearly acceptable. the acceptability of a questionable vibration is determined on the basis of one of the three acceptance procedures noted below. The acceptance criterion for steady state vibration is that the maximum vibratory stress in the pipe does not exceed one-half the 6 endurance limit for 10 cycles of vibration. Within that limit, vibration does not contribute to reduction of piping fatigue life. Compliance with the acceptance criterion is judged on the basis of criteria obtained from one of the following sources:

1. Prior operating experience with identical systems

2. General acceptance data based on operating experience with similar systems and/or generalized stress analysis calculations

3. Specific and detailed stress calculations based on computer model representation of the system operation with the vibration modes identified from the test data.

Vibration test evaluations are made under three different conditions:

1. When piping is inaccessible during power ascension, but operating conditions are duplicated under preoperational test conditions

2. When piping is accessible during power ascension testing 3.9-59 HCGS-UFSAR Revision 0 April 11, 1988

3. When piping is inaccessible during power ascension testing and the operating conditions are not duplicated under preoperational test conditions.

3.9.2.2.3.1 Preoperational Testing of Inaccessible Non-NSSS Piping for Steady State Vibration The purpose of this preoperational vibration testing is to verify acceptable vibration of piping that is inaccessible during startup testing but that can be tested, before fuel load, under the same operating conditions that occur after fuel load. Amplitude and frequency measurements, if required, are obtained by hand held or rigidly" attached instrumentation capable of the required accuracy over the expected range of frequency. The measurement system incorporates filtering devices capable of resolution of multiple mode vibrations. The piping is visually examined by a qualified test engineer familiar with the structural design and operation of the piping. The test engineer makes a judgement as to whether the vibration observed during the visual examination is negligible. If it is not negligible, it is considered questionable and requires further measurement and interpretation. Further testing consists of such vibration measurements as the test engineer determines necessary to ensure that the vibration amplitude is within acceptable limits. 3.9.2.2.3.2 Power Ascension Testing of Accessible Non-NSSS Piping for Steady State Vibrations This piping is accessible to the test personnel during plant operating conditions. The purpose of startup testing of accessible piping is to verify that the steady state vibration during any operating mode does not exceed the acceptable limits. The piping is visually examined by a qualified test engineer familiar with the structural design and operation of the piping. Vibration that, based on this visual examination, the test engineer 3.9-60 HCGS-UFSAR Revision 0 April 11, 1988

does not judge negligible. is further examined. Further testing consists of such vibration measurements as the test engineer determines necessary to ensure that vibration amplitude is within acceptable limits. Amplitude and frequency measurements, if required, are obtained by hand held or rigidly attached instrumentation capable of the required accuracy over the expected range of frequency. The measurement system incorporates filtering that enables the resolution of multiple mode vibrations. 3.9.2.2.3.3 Power Ascension Testing of Inaccessible Non-NSSS Piping for Steady State Vibrations Piping is not always accessible to personnel during plant operation due to prohibitive radiation conditions. The purpose of startup testing of inaccessible piping is to verify that the steady state vibration during any operating mode does not exceed acceptable limits. Because this piping is not always accessible to test engineers during startup testing, only limited, if any, walkdown visual survey is made. Remote readout instrumentation is rigidly installed at selected locations on the piping to provide vibration measurements during all startup test conditions and within the frequency and amplitude range of any expected vibration mode. Qualified design and stress analysis personnel select the instrument locations needed to monitor vibration. They determine acceptable limits of maximum measured vibration for each system, and later evaluate the acceptability of questionable instrument vibration test measurements. Qualified instrumentation specialists design the instrumentation installation hardware, to ensure that spurious vibration is not generated in *operation. They select signal conditioning, calibration, and recording equipment capable of producing vibration 3.9-61 HCGS-UFSAR Revision 0 April 11, 1988

test records of the accuracy and range prescribed in the test specification. Qualified test engineers perform the test measurements in conformance with the test procedures, making determinations of vibration as either negligible or questionable. Design engineers familiar with the piping system dynamics and with the acceptance criteria make determinations of questionable vibration as either acceptable or unacceptable, recommending specific corrective actions to reduce or eliminate excessive vibration. 3.9.2.2.4 Startup Dynamic Transient Tests of Non-NSSS Piping During plant startup, dynamic transient tests are performed for the following piping systems and the indicated modes of operation:

1. Main steam piping outside the primary containment for main steam turbine trip at 25 percent, 75 percent, and 100 percent power

2. Main steam bypass piping for main stop valve closure

3. Main steam SRV discharge piping for main steam SRV opening

4. High pressure coolant injection (HPCI) turbine steam supply piping for HPCI turbine trip

5. Feedwater piping for reactor feed pump tripjcoastdown.

From past experience, the dynamic transients in other piping systems are not s~gnificant. Dynamic transient analysis of the subject lines is performed to determine the response of the system to 100 percent of the design condition loads. Pipe stress and deflection as well as the restraint design maximum load are determined. 3.9-62 HCGS-UFSAR Revision 0 April 11, 1988

During the test, a time history record of the load at selected restraints is obtained. Pipe dynamic pressure is measured at selected locations, and valve opening or closure time history is also measured. Pipe acceleration is measured at selected locations. Acceptance criterion for dynamic transient testing is that the restraint maximum load measured in the test does not exceed the design calculated maximum load. Valve opening/closing stroke time is for information only, to be correlated with the piping design calculation. Pipe acceleration is not to exceed the design calculated maximum acceleration. A test *specification describes in detail the pipe system scope and objectives of the test. Instrumentation requirements and the acceptance limits for restraints and pipe acceleration are provided. 3.9.2.2.4.1 Corrective Action for Unacceptable Steady or Transient Vibration Non-NSSS piping systems having vibration in excess of the acceptance limits are modified in accordance with plant procedures adopted to:

1. Modify the dynamic response of the piping system by addition, modification, or deletion of vibration restraints

2. Suppress the vibration by means of damping devices

3. Eliminate or reduce the source of the vibration.

Following adoption of any corrective measure, the piping system is again tested under the same conditions and evaluated for compliance with the acceptance criteria. 3.9-63 HCGS-UFSAR Revision 0 April 11, 1988

3.9.2.3 Seismic Qualification of Safety-Related NSSS Mechanical Eguipment This section describes the criteria for seismic qualification of safety- related mechanical equipment and the qualification testing and/or analyses applicable to this plant for all the major components on a component by component basis. In some cases, a module or assembly of mechanical and electrical equipment is qualified as a unit, e.g., the Emergency Core Cooling System (ECCS) pumps. These modules are generally discussed in this section. Seismic qualification testing for active pumps and valves is also discussed in Section 3.9.3.2. Electrical supporting equipment, such as control consoles, cabinets, and panels, that are part of the NSSS, are discussed in Section 3.10. The seismic test and/or evaluation results for safety-related mechanical equipment are maintained in a permanent file by GE and are readily auditable in all cases. 3.9.2.3.1 Tests and Analysis Criteria and Methods The ability of equipment to perform its safety-related function during and after an earthquake is demonstrated by tests and/or analyses. Selection of testing, analysis, or a combination of the two is determined by the type, size, shape, and complexity of the equipment being considered. When practical, the safety-related operations are performed simultaneously with vibratory testing. Where this is not practical, operability is demonstrated by mathematical analysis. The NSSS seismic qualification program for HCGS utilizes seismic data generated over a number of years. Since it was not a licensing requirement at the time, most of these data were developed in earlier years without pre-aging or sequential testing of the equipment. However, NSSS equipment located in harsh environments that has been qualified in recent years has generally been pre-aged and sequentially tested in accordance with the guidelines of IEEE 323-1974. 3.9-64 HCGS-UFSAR Revision 0 April 11, 1988

NSSS equipment on HCGS is being seismically evaluated using pre-aged and sequential testing data where it is available. Otherwise, the earlier data without pre-aging and sequential testing are being used. The aging requirement is described in Section 3.11.2.7.2. Maintenance ,and surveillance program requirements given in Section 3.11.2.7.6 incorporate the results of testing, as applicable. Equipment that is large, simple, and/or consumes large amounts of power is usually qualified by analysis or static test to show that the loads, stresses, and deflections are less than the allowable maximums. Analysis and/or testing are also used to show there are no natural frequencies below 33 hertz. If a natural frequency lower than 33 hertz is discovered, dynamic tests may be conducted and, in conjunction with mathematical analysis, used to verify operability and structural integrity at the required seismic input conditions. When the equipment is qualified by dynamic test, the response spectrum or the time history of the attachment point is used in determining input motion. Natural frequency may be determined by running a continuous sweep frequency search using a sinusoidal steady state input of low magnitude. Seismic conditions are simulated by testing using random vibration input or single frequency input within equipment capability at frequencies up to 33 hertz. Whichever method is used, the input motion during testing envelops the actual input motion expected during earthquake conditions. The equipment being dynamically tested is mounted on a fixture that simulates the intended service mounting and causes no dynamic coupling to the equipment. Equipment having an extended structure, such as a valve operator, is analyzed by applying static equivalent seismic safe shutdown 3.9-65 HCGS-UFSAR Revision 0 April 11, 1988

earthquake (SSE) loads at the center of gravity of the extended structure. In cases where the equipment structural complexity makes mathematical analysis impractical, a static bend test is used to determine spring constant and operational capability at maximum equivalent seismic load conditions. RPV and attached piping and pipe-mounted equipment are analyzed for annulus pressurization loads in the range of 60 to 100 Hz frequency depending on the dynamic characteristics of the equipment and its installation. The effect of hydrodynamic loads is limited to the torus and torus attached piping in accordance with the Mark I Containment Long-Term Program (NUREG 0661). The qualification test frequencies, in general, range up to 50 Hz, which is the upperbound hydrodynamic loading frequency. Non-ASME B&PV code components are qualified by tests that address the "strong motion" phase of seismic (and, if applicable, SRV) dynamic motion sufficient to generate the maximum equipment response. This testing generally consists of five OBE tests and one SSE test of 30 seconds each. Non-ASME B&PV code components are also qualified by analyses that have not considered vibration fatigue-cycle effects. Some equipment is shown to be qualified by single axis andjor single frequency testing. However, all essential equipment is reevaluated for seismic qualification according to the requirements or recommendations of IEEE 344-1975, Regulatory Guides 1.92 and 1.100, and Standard Review Plans 3. 9. 2, 3. 10, and HCGS specific requirements. In most instances, use of single axis test data is restricted to equipment with a response that shows a predominant single mode of vibration in each direction with minimal cross coupling. In some cases, if the response shows a single mode of vibration in each direction but also has cross coupling, the existing single axis test data are still used if the test response spectra (TRS) can be shown 3.9-66 HCGS-UFSAR Revision 0 April 11, 1988

to exceed the required response spectra (RRS) by a factor of 1.4 over all frequencies. In most instances, use of single frequency test data is restricted to cases where the required input motion is dominated by one frequency, where response of the equipment is adequately represented by one mode, or where the input motion has sufficient intensity and duration to produce sufficiently high levels of stress to assure structural integrity where structural integrity is the determinant requirement. In some cases, if the input motion is sufficiently high so as to excite secondary modes, such that modal responses can be shown to occur out of phase and at high enough levels, existing single frequency test data are also used to demonstrate operability. The determination of which dynamic loads to address in a qualification program is made on the basis of both load evaluations made on similar designed facilities and on plant specific assessments. From this basis, those loads which are considered to be significant are then selected and used in the qualification demonstration program. As described in the NRC approved NEDE-24326*1-P operational aging, vibration aging for pipe mounted equipment, applicable dynamic event aging, etc, are all considered. Specific loads, such as those generated for the sudden closure of valves, have been considered when they are determined to be critical (i.e., loads from the closing of the SRVs and turbine stop valve are considered, but loads from the closure of a MSIV are not because of the relatively slow closure time of the MSIV). Vibration fatigue cycle effects for NSSS equipment designed to ASME B&PV Code requirements are evaluated in a manner found satisfactory to NRC consultants. The approach taken encompasses OBE, SRV where applicable, thermal, and pressure cycles (see References 3. 9-18, 3.9-19 and 3.9-20). Table 3. 9-25 (SQRT devices) provides a listing of typical NSSS equipment showing the methods used for their qualification. 3.9-67 HCGS-UFSAR Revision 0 April 11, 1988

3.9.2.3.1.1 Random Vibration Input When random vibration input is used, the actual input motion envelops the appropriate floor input motion at the individual modes. However, single frequency input, such as sine waves, can be used provided one of the following conditions are met:

1. The characteristics of the required input motion are dominated by one frequency

2. The anticipated response of the equipment is adequately represented by one mode

3. The input has sufficient intensity and duration to excite all modes to the required magnitude, such that the testing response spectra envelops the corresponding response spectra of the individual modes.

3.9.2.3.1.2 Application of Input Motion When dynamic tests are performed, the input motion is applied to one vertical and one horizontal axis simultaneously. However, if the equipment response along the vertical direction is not sensitive to the vibratory motion along the horizontal direction, and vice versa. then the input motion is applied to one direction at a time. In the case of single frequency input, the time phasing of the inputs in the vertical and horizontal directions is such that a purely rectilinear resultant input is avoided. 3.9.2.3.1.3 Fixture Design The fixture design simulates the actual service mounting and causes no dynamic coupling to the equipment. 3.9-68 HCGS-UFSAR Revision 0 April 11, 1988

3.9.2.3.1.4 Prototype Testing Testing is conducted on prototypes of the equipment installed in this plant. 3.9.2.3.2 Seismic Qualification of Specific NSSS Mechanical Components The following sections discuss the testing or analytical qualification of NSSS equipment. Seismic qualification is also described in Sections 3.9.1.4, 3.9.3.1, and 3.9.3.2. 3.9.2.3.2.1 Jet Pumps A static analysis of the jet pumps is performed assuming 3.0g horizontal acceleration and l.Sg vertical acceleration. The stresses resulting from the analysis are below the design allowables. Static analysis with an appropriate amplification factor is used in lieu of dynamic analysis since the jet pump is a simple component with a natural frequency of slightly less than 33 hertz. 3.9.2.3.2.2 Control Rod Drive and Control Rod Drive Housing The seismic qualification of the control rod drive (CRD) housing, with the CRD enclosed, for an operating basis earthquake (OBE) and a safe shutdown earthquake (SSE), is done analytically, and the stress results of the analyses establish the structural integrity of these components. Preliminary tests were conducted to verify the operability of the CRD during a seismic event. A simulated test, imposing a static bow in the fuel channels, was performed to show the CRD function satisfactorily. 3.9.2.3.2.3 Core Support - Fuel Support and Control Rod Guide Tube No dynamic testing of the control rod guide tube is conducted. However, a detailed analysis imposing dynamic effects due to seismic 3.9-69 HCGS-UFSAR Revision 0 April 11, 1988

events shows that the maximum stresses developed during these events are much lower than the maximum allowed for the component material. 3.9.2.3.2.4 Hydraulic Control Unit The seismic loads adequacy of the hydraulic control unit (HCU), for the faulted condition, is demonstrated by test and analysis. With the HCUs mounted on a seismic support structure, the dynamic loads are 1.8g vertical at the natural frequency of 7 to 30hz, and 1.75g horizontal at 2 to 6 hz and 4g horizontal at 10 hz. At these frequencies, the maximum HCU capability (by test) for dynamic loads is 20g vertical at 7 to 30 hz, and greater than 4g horizontal at 2 to 6 hz and 8g horizontal at 10 hz. 3.9.2.3.2.5 Fuel Assembly (Including Channel) Refer to Section 3.9.1.4.10. 3.9.2.3.2.6 Recirculation Pump and Motor Assembly Calculations are made to ensure that the recirculation pump and motor assembly is designed to withstand the specific static equivalent seismic forces. The flooded assembly is analyzed as a free body supported by constant support hangers from the brackets on the motor mounting member with hydraulic snubbers attached to brackets located on the pump case and the top of the motor frame. Primary stresses due to horizontal and vertical seismic forces are considered to act simultaneously and are conservatively added directly. Horizontal and vertical seismic forces are applied at mass centers and equilibrium reactions are determined for the motor and pump brackets. 3.9.2.3.2.7 Emergency Core Cooling System Pump and Motor Assembly The qualification of ECCS pump and motor assemblies as a unit, while operating under SSE conditions, is provided in the form of a static 3.9-70 HCGS-UFSAR Revision 0 April 11, 1988

earthquake acceleration analysis. The maximum specified vertical and horizontal accelerations are constantly applied simultaneously, and the worst case combination in the results of the analysis indicate the pump is capable of sustaining the above loading without overstressing the pump components. A similar motor design is seismically qualified via a combination of static analysis and dynamic testing. The complete motor assembly is seismically qualified via dynamic testing, in accordance with IEEE 344~1975. The qualification test program includes demonstration of startup and shutdown capabilities. as well as no-load operability during seismic loading conditions. For static analysis on a similar motor design. the seismic forces of each component or assembly are obtained by concentrating its mass at the center of gravity of component or assembly, and multiplying by the seismic acceleration, the earthquake coefficient. The magnitude of the earthquake coefficients are 0.14g vertical and l.Sg horizontal for the SSE condition. 3.9.2.3.2.8 Reactor Core Isolation Cooling Pump Assembly The reactor core isolation cooling (RCIC) pump construction is of a barrel type on a large cross section pedestal. Qualification by analysis is performed. The seismic design analysis is based on l.Sg horizontal and 0.14g vertical accelerations. Results are obtained by using acceleration forces acting simultaneously in two directions: one vertical and one horizontal. The pump mass, support system, and accessory piping are shown, by analysis, to have a natural frequency greater than 33 hertz. The RCIC pump assembly is analytically qualified by static analysis for seismic loading as well as the design operating loads of pressure, temperature, and external piping loads. The results of this analysis confirm that the stresses are substantially less than 90 percent of the allowable. 3.9-71 HCGS-UFSAR Revision 0 April 11, 1988

The RCIC pump has been analyticallY. qualified by static analysis. The following operability statement appears as Note 2 on Table 3.9-4t. Static analysis on a similar type pump, for the emergency or faulted conditions, shows that the maximum shaft deflection is 0.002 in. with 0.006 in. allowable; shaft stresses are 3080 psi with 25,000 psi allowable; and, bearing loads for the drive end are 98 lb, with 7670 lb allowable. Bearing loads for thrust end are approximately 765 lb, with 17,600 lb allowable. The RCIC pumps were installed in the pump manufacturer's closed test loop and subjected to an hydraulic performance test. The pump was driven with an electric motor in the test speed range of 3585 to 3590 rpm. All test setups, test procedures, and instrumentation were in accordance with the standards of the Hydraulic Institute and the ASME Power Test Code 8.2. Several points of data were taken to accurately determine the performance of the pump and to satisfy all the requirements listed in the HCGS pump data sheets. 3.9.2.3.2.9 Reactor Core Isolation Cooling Turbine Assembly The RCIC turbine is seismically qualified by static analysis. The turbine assembly and its components are considered to be supported as designed, and horizontal/vertical accelerations are applied to the mass centers of gravity. .The magnitude of the acceleration coefficient is 1.5g horizontal and 0.48g vertical. The results of the analysis indicate the turbine assembly is capable of sustaining the above loadings without overstressing any components. 3.9.2.3.2.10 Standby Liquid Control Pump and Motor Assembly The standby liquid control (SLC) positive displacement pump and motor assembly is mounted on a common base plate and is qualified by static analysis. 3.9-72 HCGS-UFSAR Revision 1 April 11, 1989

The seismic design analysis is based on l.Sg horizontal and 0.14g vertical accelerations. Results are obtained by using acceleration forces acting simultaneously in two directions: one vertical and one horizontal. The pump/motorjbase assembly is shown by static analysis to have a natural frequency greater than 33 hertz. The SLC pump and motor assembly is analytically qualified by static analysis for seismic loading as well as the design operating loads of pressure, temperature, and external piping loads. The results of this analysis confirm that the stresses are substantially less than 90 percent of the allowable. The SLC pump has been qualified by static analysis. Coefficients used included 1.5g horizontal and 0.14 g vertical for safe shutdown earthquake (SSE)

• A subsequent seismic analysis for the SLC pump and motor has been accomplished using coefficients of 1.75g for both horizontal and vertical loads. Although these analyses are not specifically applied to the HCGS SLC pump and motor, the results are applicable due to equipment similarity, which is based on physical configuration, materials of construction, weight of equipment, base plate size, model number, allowable nozzle loads, and operating functions. A comparison evaluation showed the equipment to be alike in all respects.

An SLC motor, dimensionally identical to the HCGS SLC motors, has been subjected to dynamic testing in the no*load condition. The test*motor insulation materials differ from those used in the HCGS motors, but this difference was not sufficient to change the loads evaluation. With the test motor bolted to a vibration excitation table, a resonance search was performed in a frequency range of 10-80*10 Hz with a sweep of 10 Hz per minute. Input acceleration for the resonance search was 0.2g peak. There was no detectable resonant frequency within the frequency range tested. The test motor was also subjected to an operational basis earthquake (OBE) test with the test motor in the operational no-load mode. The OBE test consisted of a minimum of 20 seconds of applied vibratory 3.9-73 HCGS-UFSAR Revision 0 April 11, 1988

motion at a frequency of 33 Hz with an acceleration level of 1.4g peak for periods of 20 seconds each at zero-degree and 180-degree phases. Testing was completed with no adverse effects noted: A simulated SSE test was performed at an applied frequency of 33 Hz and an acceleration leved of 2.0g peak. Tests were performed with the vertical and horizontal axes in phase and then 180 degrees out of phase at each of the following conditions:

a. a 15-second run was performed in each axis configuration with the test specimen in the nonoperating mode.

b. The seismic vibration was started for two seconds, and then the test specimen was energized for a period of 15 seconds in each axis configuration.

c. At the same time, the seismic vibration was started and the specimen was energized, and the test was continued for 15 seconds in each axis configuration.

d. The test specimen was energized and after three seconds, the seismic vibration was started and run for 15 seconds.

An operational test was performed for 125 minutes with the specimen loaded to 40 horsepower using a dynamotor. Operational .data was recorded every 10 minutes. The 125-minute operating time complies with the maximum period required by the system design specification for the HCGS. The SLC pump was installed in the pump manufacturer's closed test loop and subjected to a hydraulic performance test. Testing was in accordance with the reciprocating pump section of the Hydraulic Institute standards. With the pump speed relatively constant, data were accurately taken at six points to determine the performance of the pump and to satisfy all the requirements listed in the HCGS pump data sheet. 3.9-74 HCGS-UFSAR Revision 0 April 11, 1988

3.9.2.3.2.11 Residual Heat Removal Heat Exchangers A dynamic analysis is performed to verify that the RHR heat exchanger withstands seismic loadings in accordance with its seismic classification. Seismic testing is an impractical method to verify the seismic adequacy of equipment when predictable seismic loads can be determined by dynamic and static analysis. The heat exchanger, including its appurtenances and supports, is designed to withstand the effects of pressure, dead weight, nozzle loads due to attached piping, and seismic accelerations. The heat exchanger is analyzed for these loads using finite element techniques. The seismic accelerations used in the analyses are in the form of HCGS unique response spectra. The spectra are used as direct input to the dynamic finite element analyses. 3.9.2.3.2.12 Standby Liquid Control Tank The SLC storage tank is a cylindrical tank 9 feet in diameter and 12-feet high, bolted to the concrete floor. Stresses are calculated readily by conventional methods. The magnitude of the earthquake coefficients for the SSE are 1. Sg horizontal and 0 .14g vertical. The SLC tank has been qualified by analysis for:

1. Stresses in the tank bearing plate

2. Bolt stresses

3. Sloshing loads imposed by an earthquake sloshing natural frequency of 0.58 hertz

4. Minimum wall thickness

5. Buckling.

3.9-75 HCGS-UFSAR Revision 0 April 11, 1988

3.9.2.3.2.13 Main Steam Isolation Valves The main steam isolation valves (MSIVs) are qualified for operability by analysis and tests for seismic loading. 3.9.2.3.2.14 Main Steam Safety/Relief Valves Due to the complexity of this structure and the performance requirements of the valve, the total assembly of the 2-Stage main steam SRV (including electrical and pneumatic devices) was dynamically tested at seismic accelerations equal to or greater than the SSE levels determined for this plant. Satisfactory operation of the valves is demonstrated during and after the test. Tests and analysis satisfy operability criteria, as defined in Section 3.9.2.3. Seismic qualification of the 3-Stage SRVs was performed by analysis, by the manufacturer. The model used for analyses was benchmarked against actual testing performed for the Limerick 3-Stage SRV. The analysis was independently verified by a third party. 3.9.2.3.2.15 High Pressure Coolant Injection Turbine Assembly The HPCI turbine is seismically qualified by static analysis. The turbine assembly and its components are considered to be supported as designed, and horizontal/vertical accelerations are applied to the mass centers of gravity. The magnitude of the acceleration coefficients is 1.5g horizontal and 0.48g vertical. The results of the analysis indicate the turbine assembly is capable of sustaining the above loadings without overstressing any components. 3.9.2.3.2.16 High Pressure Coolant Injection Pump Assembly The HPCI pump assembly consists of a main pump, a gear reducer, and a booster pump. Both pumps are split body type, mounted on a common base plate. The assembly is seismically qualified by dynamic analysis using the response spectrum modal analysis technique. The structure's response at each of the lowest 60 modes is determined due to SSE seismic input in each of the three global directions. The total SSE seismic response (loads and deformations) is then determined by superposition, using the method of Regulatory 3.9-76 HCGS-UFSAR Revision 23 November 12, 2018

Guide 1.92, Revision 1. The pump mass support system and accessory piping have been shown by analysis to have a natural frequency greater than 60 hertz. The HPCI pump assembly has been seismically qualified by a dynamic analysis performed by Byron Jackson Pump Company. A three dimensional, finite element model was developed and dynamically analyzed using the response spectrum method. Static nozzle loads, pump thrust loads and dead weight were considered. Critical location stresses were evaluated and compared with the allowable stresses based on Section III of the ASME Code. The HPCI and RCIC pumps were installed in the pump manufacturer's closed test loop and subjected to a hydraulic performance test. The pump was driven with an electric motor in the test speed range of 3585 to 3590 rpm. All test setups, test procedures, and instrumentation were in accordance with the standards of the Hydraulic Institute and the ASME Power Test Code 8. 2. Several points of data were taken to accurately determine the performance of the pump and to satisfy all the requirements listed in the HCGS pump data sheets. 3.9.2.4 Seismic Qualification Testin& of Safety-Related Non-NSSS Mechanical Equipment 3.9.2.4.1 Seismic Qualification Criteria All non-NSSS Seismic Category I mechanical equipment is designed to withstand the simultaneous horizontal and vertical accelerations caused by the OBE and the SSE in conjunction with other normal operating loads. 3.9-77 HCGS-UFSAR Revision 1 April 11, 1989

Seismic qualification criteria used for the Seismic Category I mechanical equipment, with the exception of pumps and active valves, are in compliance with Regulatory Guide 1.100 and IEEE 344-1975. The seismic qualification of pumps and active valves is discussed more fully in Section 3.9.3.2. Where applicable, all equipment is pre-aged prior to seismic testing as part of the test sequence. The aging requirement is described in Section 3.11.2.7.2. Maintenance and Surveillance program requirements given in Section 3.11.2.7.6 incorporate the results of testing, as applicable. The criteria for selecting a qualification method, by analysis and/or by test, is based on the practicality of the method for the function, type, size, shape, and complexity of the equipment. Table 3. 9-7 list all non-NSSS Seismic Category I mechanical equipment, equipment locations and qualification methods. 3.9.2.4.2 Methods and Procedures for Qualifying Non-NSSS Mechanical Equipment Seismic Category I equipment is shown to be capable of withstanding the horizontal and vertical accelerations of five OBEs and one SSE by dynamic analysis, dynamic testing, or a combination of dynamic analysis and testing. The seismic qualification methods and procedures are in compliance with the requirements of IEEE 344-1975 and Regulatory Guide 1.100. Pipe mounted equipment is qualified by analysis and/or testing to the acceleration levels allowed for piping systems. These levels include gravity and operation loading, as well as loading that is due to seismic or any other accident related excitation, if applicable. 3.9-78 HCGS-UFSAR Revision 0 April 11, 1988

The plant operating vibration loads are insignificant compared to seismic loads considered for equipment qualification. However, applicable transient loads caused by sudden valve actuation (e.g., main steam turbine trips, HPCI turbine stop valve closure, MSSRV discharge, etc.) are considered in the design loading of non-NSSS ASME components as specified in Table 3.9-8. Force time histories of transient loads are developed using one of the computer codes referenced in Section 3. 9 .1. 2. These forcing functions are then input to the finite element piping analysis along with the applicable seismic response spectra. The combined seismic and transient piping responses are evaluated against the equipment allowables specified for the appropriate service level. Selected systems are subsequently subjected to inplant dynamic transient testing to confirm the acceptability of the analysis. All pipemounted valve operators and accessories are qualified by using a single axis, single frequency testing (required input motion (RIM) test). This is justified on the ground that the seismic floor motion is filtered through the piping system, which generally has one predominant* structural mode. Thus the resulting motion that reaches the linemounted equipment is predominantly a single frequency and singleaxis motion. The test is performed by using RIM in each of the three axes, independently. In accordance with the Mark I Containment Long-Term Program (NUREG-0661), non-NSSS equipment attached to the torus has been evaluated for appropriate hydrodynamic loads, including fatigue effects. Wetwell to drywell vacuum breakers inside the torus are also qualified for hydrodynamic loads for frequencies up to 50 hz. 3.9.2.4.2.1 Dynamic Analysis Dynamic analysis without testing is used if structural integrity alone ensures the intended design function. Included is mechanical 3.9-79 HCGS-UFSAR Revision 0 April 11, 1988

equipment such as tanks and vessels, ductwork, heat exchangers, filters, and inactive valves. The methods and procedures for the seismic analysis of Seismic Category I equipment are discussed in Section 3.7.3. For equipment such as pumps, rotational analysis is used to qualify heavy rotating machinery items, where it must be verified that deformations due to seismic loading will not cause binding of the rotating element to the extent that the component cannot perform its intended design function. 3.9.2.4.2.2 Dynamic Testing Dynamic testing is used for equipment that requires confirmation of operability during and after seismic events. Loadings include the OBE, the SSE, and all static and dynamic loads. Included is mechanical equipment such as fans, pumps, and valve actuators. Dynamic testing is performed by subjecting equipment to vibratory motions that conservatively simulate the required response spectrum or the required input motion at the equipment-mounting location. Equipment is tested in the operational condition. Operability is verified during and/or after the testing, as applicable to the equipment being tested. The requirements of testing procedures and methods are in accordance with Section 6 of IEEE 344-1975. The test results have demonstrated that the test response spectrum closely resembles and envelops the required response spectrum over the critical frequency range. 3.9.2.4.2.3 Combined Analysis and Testing Equipment that cannot be qualified practically by analysis or testing because of its size and/or complexity is qualified by combined analysis and testing. Combined analysis and testing methods are in accordance with Section 7 of IEEE 344-1975. 3.9-80 HCGS-UFSAR Revision 0 April 11, 1988

3.9.2.4.3 Methods and Procedures of Analysis or Testing of Supports of Mechanical Equipment Analysis or testing of supports of Class lE equipment and instrumentation is discussed in Section 3.10.3.2. The design of supports of mechanical equipment is confirmed by analysis or test to ensure their structural capability to withstand dynamic excitation. In general, equipment is tested or analyzed with equipment supports and base connections simulating the actual installation. Therefore, the seismic qualification methods and procedures for supports are similar to those for mechanical equipment, as discussed in Section 3.9.2.4.2. When the equipment and support are seismically qualified separately. the required response spectrum curves at the location of the equipment are produced to account for the possible seismic amplification between support and equipment. 3.9.2.4.4 Operating License Review Qualification documents containing results of qualification tests and analyses for non-NSSS mechanical equipment are maintained by PSE&G in a centrally located, readily auditable, permanent file. 3.9.2.5 Dynamic Response of Reactor Internals Under Operational Flow Transients and Steady State Conditions The major reactor internal components within the vessel are subjected to extensive testing coupled with dynamic system analysis to describe properly the resulting flow induced vibration phenomena incurred from normal reactor operation and from anticipated operational transients. In general, the vibration forcing functions for operational flow transients and steady state conditions are not predetermined by detailed analyses. Special analyses of the response signals 3.9-81 HCGS-UFSAR Revision 0 April 11, 1988

measured for the reactor internals of many similar designs are performed to predict amplitude and modal contributions. Parametric studies, useful for extrapolating the results from tests of internals and components of similar designs, are also performed. This vibration prediction method is appropriate where standard hydrodynamic theory cannot be applied due to the complexity of the structure and flow conditions. Elements of this vibration prediction method are as follows:

1. Dynamic analyses of major components and subassemblies are performed to identify natural vibration modes and frequencies. The analysis models used for Seismic Category I structures are similar to those outlined in Section 3.7.2.

2. Data from previous plant vibration measurements are assembled and examined to identify predominant vibration response modes of major components. In general, response modes are similar, but response amplitudes vary among BWRs of differing size and design.

3. Parameters are identified that are expected to influence vibration response amplitudes among the several reference plants. These include hydraulic parameters such as velocity and steam flow rates, and such structural parameters as natural frequency and significant dimensions.

4. Correlation functions of the variable parameters are developed that, when multiplied by response amplitudes, tend to minimize the statistical variability between plants. A correlation function is obtained for each major component and response mode.

5. Predicted vibration amplitudes for components of the prototype plant are obtained from these correlation functions, based on applicable values of the parameters 3.9-82 HCGS-UFSAR Revision 0 April 11, 1988

for the prototype plant. The predicted amplitude for each dominant response mode is stated in terms of a range, taking into account the degree of statistical variability in each of the correlations. The predicted mode and frequency are obtained from the dynamic analyses from paragraph 1. above. The dynamic modal analyses also form the basis for interpretation of the prototype plant preoperational and initial startup test results, as discussed in Section 3.9.2.6. Modal stresses are calculated and relationships are obtained between sensor response amplitudes and peak component stresses. The allowable amplitude is that which produces a peak stress of -10,000 psi. 3.9.2.6 Preoperational Flow Induced vibration Testing of Reactor Internals Hope Creek Generating Station reactor internals are tested in accordance with the provisions of Regulatory Guide 1.20, Revision 2, for nonprototype Category I plants. The test procedure requires operation of the recirculation system at rated flow with internals important to safety installed, followed by inspection for evidence of vibration, wear, or loose parts. Blade guides, in-core instruments, neutron sources, steam dryer, and fuel are not installed. Control rods are either not installed or are fully withdrawn and prevented from being inserted. The test duration is 6 sufficient to subject critical components to at least 10 cycles of vibration during two loop and single loop operation of the recirculation system. Upon completion of the flow test, the vessel head and shroud head are removed, the vessel drained, and major components inspected on a selected basis. The inspection covers all components that were examined on the prototype design, including the shroud, shroud head, core support structures, the jet pumps, and the peripheral CRD and in-core guide tubes. Access is provided to the reactor lower plenum. 3.9-83 HCGS-UFSAR Revision 0 April 11, 1988

Reactor internals design configurations for the Hope Creek Generating Station are substantially the same as those that have been tested in prototype BWR/4 plants. Results of the prototype tests are presented in a licensing topical report, Reference 3.9-12. This report also contains additional information on the confirmatory inspection program. 3.9.2.6.1 Compliance With Regulatory Guide 1.20 GE supplied NSSS analyses, design, and equipment used in this facility are in compliance with the intent of Regulatory Guide 1.20, through the incorporation of the alternate approach cited below. Regulatory Guide 1.20 describes a comprehensive vibration assessment program for reactor internals during preoperational and initial startup testing. This regulatory guide is applicable to the core support structure and other reactor internals. The vibration assessment program meets the requirements of Criterion 1, Quality Standards and Records, of Appendix A to 10CFRSO and Section 50.34, Contents of Applications; Technical Information, of 10CFRSO. Vibration testing of reactor internals is performed on all GE BWR plants. At the time of the original issue of Regulatory Guide 1.20, test programs for compliance were instituted. The first BWR/4 plant of each size was considered a prototype and was instrumented and subjected to preoperational and startup flow testing to demonstrate that flow induced vibrations similar to those expected during operation do not cause damage. Subsequent plants that have reactor internals similar to those of the prototypes have also been tested, in compliance with the requirements of Regulatory Guide 1.20. GE is committed to confirm satisfactory vibration performance of reactor internals through preoperational flow testing, followed by inspection for evidence of excessive vibration, Extensive vibration measurements in prototype plants, together with satisfactory operating experience in all BWR/4 plants, have established the adequacy of BWR/4 reactor internals designs. 3.9-84 HCGS-UFSAR Revision 0 April 11, 1988

3.9.2.7 Dynamic System AQ&lysis of Beaetor Internals Under Faulted Conditions To ensure that no signifieant dynamie amplification of load occurs as a result of the oscillatory nature of the blowdown forces, a comparison is made of the periods of the applied forces and the natural periods of the core support atructures being acted upon by the applied forces. These periods are determined from a comprehensive dynamic model of the reactor pressure vessel (RPV) and its internals with 12 degrees of freedom. Only motion in the vertical direction is considered here; hence, each structural member (between two mass points) can only have an axial load. Besides the real masses of the RPV and core support structures, account is taken of the water inside the RPV. The accident analysis method is described in Sections 3.9.5.2 and 3.9.5.3. The time varying pressures are applied to the dynamic model of the reactor internals described above. Except for the nature and locations of the forcing functions and the dynamic model, the dynamic analysis method is identical to that described for seismic analysis and is detailed in Section 3.7.3.1. The dynamic components of forces from these loads are combined with dynamic force components from other dynamic loads (including seismic), all acting in the same direction, by the square root of the sum of the squares (SRSS) method. This resultant force is then combined with other steady state and static loads on an absolute sum basis to determine the design load in a given direction. The loads and load combinations acting upon the jet pumps and low pressure coolant injection (LPCI) coupling are listed on Tables 3.9-4y and 3.9-4z, respectively. Reactor asymmetric loads analysis is described in Appendix 3C. 3.9-85 HCGS-UFSAR Revision 9 June 13, 1998

3.9.2.8 Correlations of Reactor Internals Vibration Tests With the Analytical Results ...-., Prior to initiation of the instrumented vibration test program for the prototype plant, extensive dynamic analyses of the reactor and internals were performed. The results of these analyses were used to generate the allowable vibration levels during the vibration test. The vibration data obtained during the test were analyzed in detail. The results of the data analysis, vibration amplitudes, natural frequencies, and mode shapes were then compared to those obtained from the theoretical analysis. Such comparisons provide the analysts with added insight into the dynamic behavior of the reactor internals. The additional knowledge gained is used in the generation of the dynamic models for seismic and loss-of-coolant accident (LOCA) analyses for this plant. The models used for this plant are the same as those used for the vibration analysis of the prototype plant, Browns Ferry-1. The vibration test data are supplemented by data from the forced oscillation tests of reactor internal components to provide the analysts with additional information concerning the dynamic behavior of the reactor internals. 3.9.3 ASME B&PV Code Class 1, 2, and 3 Components, component Supports, and Core Support Structures 3.9.3.1 Loading Combinations, Design Transients, and stress Limits This section delineates the criteria for selection and definition of design lLffiits and loading combinations associated with normal operation, postulated accidents, and specified seismic events for the design of safety-related ASME .B&PV Code components, except primary containment components discussed in Section 3.8. This section also lists the major ASME B&PV Code Class 1, 2, and 3 equipment and associated pressure retaining parts on a 3.9-86 HCGS-UPSAR Revision 0 April 11, 1988

component by component basis, and identifies the applicable loadings, calculation methods, calculated stresses, and allowable stresses. Design transients are covered in Section 3.9.1.1. Design transients for ASME B&PV Code Class 2 equipment are not addressed in this section. Seismic related loads are discussed in Sections 3.9.2.3 and 3.7. Table 3.9-4 presents the loading combination analytical methods (by reference or example), and the calculated stress or other design values for the most critical areas of the NSSS components, supports, and core support structures. These values are also compared to applicable allowable values in the ASME B&PV Code. 3.9.3.1.1 Plant Conditions All events that the plant might credibly experience during a reactor year are evaluated to establish a design basis for plant equipment. These events are divided into four plant conditions. The plant conditions described in the following paragraphs are based on event probability, i.e., frequency of occurrence, and correlated design conditions defined in the ASME B&PV Code, Section III. 3.9.3.1.1.1 Normal Conditions Normal conditions are any conditions in the course of system startup, operation in the design power range, normal hot standby (with the main condenser available), and system shutdown other than upset, emergency, faulted, or testing conditions. 3.9.3.1.1.2 Upset Conditions Upset conditions are any deviations from normal conditions anticipated to occur often enough so that design should include the capability to withstand the conditions without operational impairment. The upset conditions include those transients that result from any single operator error or control malfunction, transients caused by a fault in a system component requiring its 3.9-87 HCGS-UFSAR Revision 0 April 11, 1988

isolation from the system, and transients due to loss of load or power. Vibratory motions due to an operating basis earthquake (OBE) are conservatively treated as an upset condition. Hot standby with the main condenser isolated is an upset condition. 3.9.3.1.1.3 Emergency Conditions Emergency conditions are those deviations from normal conditions that require shutdown for correction of the conditions or repair of damage in the reactor coolant pressure boundary (RCPB). The conditions have a low probability of occurrence but are included to provide assurance that no gross loss of structural integrity will result as a concomitant effect of any damage developed in the system. Emergency condition events include, but are not limited to, transients caused by one of the following:

1. A multiple safety/relief valve blowdown of the reactor vessel

2. Loss of reactor coolant from a small break or crack, which does not depressurize the reactor system, nor result in leakage beyond normal makeup system capacity, but which requires the safety functions of isolation of primary containment and reactor shutdown

3. Improper assembly of the core during refueling

4. Vibratory motions of an OBE in combination with associated system transients.

3.9.3.1.1.4 Faulted Conditions Faulted conditions are those combinations of conditions associated with extremely low probability, postulated events whose consequences are such that the integrity and operability of the system may be impaired to the extent that considerations of public health and safety are involved. Faulted conditions encompass events that are 3.9-88 HCGS-UFSAR Revision 0 April 11, 1988

postulated because their consequences would include the potential for the release of significant amounts of radioactive materiaL These postulated events are the most drastic that must be designed against, and thus represent limiting design bases. Faulted condition events include, but are not limited to the following:

1. A control rod drop accident

2. A fuel handling accident

3. A main steam line break

4. A recirculation loop break

5. The combination of any pipe break plus the seismic motion associated with a safe shutdown earthquake (SSE) plus a loss of offsite power (LOP), and

6. An SSE.

3.9.3.1.1.5 Correlation of Plant Conditions with Event Probability The range of probabilities of events occurring associated with the plant conditions are listed below. These correlations can be used to identify the appropriate plant condition for any hypothesized event or sequence of events. Event Encounter Probability Plant Conditions Per Reactor Year Normal (planned) 1 Upset (moderate probability) 1 > p > 10- 2 Emergency (low probability) 10- 2 > p > 10- 4 Faulted (extremely low 10- 4 > p > 10- 6 probability} 3.9-89 HCGS-UFSAR Revision 0 April 11, 1988

3.9.3.1.2 Reactor Pressure Vessel Assembly, Core Support Structures, and Reactor Internals The reactor pressure vessel (RPV) assembly consists of the RPV, support skirt, and shroud support. The RPV assembly is constructed in accordance with Section III of the ASME B&PV Code. The shroud support consists of the shroud support plate and the shroud support cylinder and its legs. The RPV is an ASME B&PV Code Class 1 component. Complete stress reports on these components have been prepared in accordance with ASME B&PV Code requirements. Table 3.9-4b summarizes stress criteria, loading combinations, and calculated and allowable stresses for each category of plant conditions. The stress analyses performed for the reactor vessel assembly, including the faulted condition, were completed using elastic methods. The stress load combinations and stress analyses for other core support structures and reactor internals are discussed in Section 3.9.5. 3.9.3.1.3 Main Steam Piping The main steam piping discussed in this paragraph includes that piping extending from the RPV to the outboard main steam isolation valve (MSIV). This piping is designed in accordance with the ASME B&PV Code, Section III, Subsection NB-3600. The load combinations and stress criteria are shown in Table 3.9-4e. 3.9.3.1.4 Recirculation Loop Piping The recirculation system piping that is bounded by the RPV nozzles is designed in accordance with the ASME B&PV Code, Section III, Subsection NB-3600. The load combinations and allowables are shown in Table 3.9-4g. 3.9-90 HCGS-UFSAR Revision 0 April 11, 1988

3.9.3.1.5 Recirculation System Valves The recirculation system suction and discharge gate valves are designed in accordance with the ASHE B&PV Code, Section III, Class 1, Subsection NB-3500. Loading combinations and other stress analysis information are presented in Table 3.9*41. 3.9.3.1.6 Recirculation Pumps In the design of the recirculation pumps, the ASHE B&PV Code, Section VIII, Division 1, with edition and addenda as specified in Table 3.2-2, is used as a guide in calculations made for determining the thickness of pressure retaining parts and in sizing the pressure retaining bolting. The pump supplier's calculations for the design of the pressure retaining components include the determination of minimum wall thickness, allowable stress and pressures, and calculations for pressurized bolted flange covers and for sizing of bolting. Pertinent examples of these calculations are shown in Table 3.9-4k. 3.9.3.1.7 Standby Liquid Control Storage Tank The loads considered in the design of the standby liquid control (SLC) storage tank and the categorization of these loads are as follows:

1. Pressure (atmospheric) - Normal/upset

2. Temperature (200°F) - Normal/upset

3. OBE (1/2 SSE) - Upset

4. Piping nozzle loads - Upset/faulted

5. SSE - Faulted.

3.9-91 HCGS-UFSAR Revision 0 April 11, 1988

The stress limits allowed by the ASME B&PV Code for the normal and upset conditions are 1.0 S for general membrane and 1.5 S for bending plus local membrane. The stress limits allowed by the ASME B&PV Code for the faulted conditions are 1.2 S for general membrane and 1.8 S for bending plus local membrane. A summary of the design calculations and methods used is given in Table 3.9*4o. 3.9.3.1.8 Residual Heat Removal Heat Exchangers The loading combinations and other stress analysis information for the residual heat removal (RHR) heat exchangers is presented in Table 3.9-4q. The design of the RHR heat exchanger is discussed in Section 3.9.2.3.2.11. 3.9.3.1.9 Reactor Core Isolation Cooling Turbine Although not under the jurisdiction of the ASME B&PV Code, the Reactor Core Isolation Cooling (RCIC) System turbine is designed and fabricated following the basic guidelines for an ASHE B&PV Code, Section III, Class 2 component.

1. The operating conditions for the RCIC turbine include:

a. Surveillance testing - Monthly operation with reactor pressure at 1000 psia (nominal) and saturated temperature; turbine exhaust pressure at 25 psia (peak) and saturated temperature

b. Auto-startup 30 cycles per year with reactor pressure at 1150 psia (nominal) and saturated 3.9-92 HCGS-UFSAR Revision 0 April 11, 1988

temperature; turbine exhaust pressure at 25 psia (peak) and saturated temperature.

2. The design conditions for the RCIC turbine include:

a. Turbine inlet - 1250 psig at saturated temperature

b. Turbine exhaust - 165 psig at saturated temperature.

c. The upset conditions that control the turbine design include:

(1) Design pressure (2) Design temperature (3) OBE (4) Inlet and exhaust piping nozzle loads. The stress limits for the pressure boundary are the ASME B&PV Code allowable stresses, 1.0 S for general membrane and 1.5 S for bending plus local membrane.

d. The faulted or emergency conditions include:

(1) Design pressure (2) Design temperature (3) SSE (4) Inlet and exhaust piping nozzle loads. The stress limits for the pressure boundary are 120 percent of the ASME B&PV Code allowable stresses, 3.9-93 HCGS-UF 'AR Revision 0 April 11, 1988

1.2 S for general membrane, and 1.8 S for bending plus local membrane. Table 3.9-4s contains a summary of the calculated and allowable loads for the RCIC turbine components. 3.9.3.1,10 Reactor Core Isolation Cooling Pump The RCIC pump is designed and fabricated to the requirements for an ASME B&PV Code, Section III 1 Class 2 component.

1. The operating conditions for the RCIC pump are surveillance tested in conjunction with the RCIC turbine. A monthly operational test is performed, during which the RCIC pump takes condensate from the condensate storage tank and, at design flow, discharges condensate back to the condensate storage tank via a closed test loop.

2. The design conditions for the RCIC pump include:

a. Required net positive suction head (NPSH) - 20.3 feet

b. Total head - High speed: 3052 feet

                              - Low speed! 525 feet

c. Constant flow rate - 625 gpm

d. Ambient room conditions can be found in the Hope Creek Environmental Design Criteria (EDC), Document no. 07.5.

e. The normal plus upset conditions that control the pump design include:

(1) Design pressure 1500 psig (2) Design temperature 40 to 140°F (3) OBE 2/3 of SSE

3. 9-94 HCGS-OFSAR Revision 15 October 27, 2006

(4) Suction nozzle loads F 0

                                                    - 1940 pounds, M     2460 foot-pounds 0

(5) Discharge nozzle loads F 3715 pounds, 0 M - 4330 foot-pounds 0 where: F and M are as defined in Table 3.9-4t. 0 0 The stress limits for the pressure boundary are the ASME B&PV Code allowable stresses, 1.0 S for general membrane and 1.5 S for bending plus local membrane.

f. The faulted or emergency conditions include:

(1) Design pressure 1500 psig (2) Design temperature 40 to 140°F {3) SSE Horizontal - 1.5 g Vertical - 0.14 g (4) Suction nozzle loads F - 2325 pounds, 0 M 2950 foot-pounds 0 (5) Discharge nozzle loads F 4450 pounds, 0 M - 5200 foot-pounds 0 The stress limits for the pressure boundary are 120 percent of the ASME B&PV Code allowable stresses, 1.2 S for general membrane and 1.8 S for bending plus local membrane. Table 3. 9-4t contains a summary of the design calculations and nozzle loads for the RCIC pump components. 3.9.3.1.11 Emergency Core Cooling System Pumps This section discusses the RHR and core spray pumps. The High Pressure Coolant Injection (HPCI) System pump is discussed in a later section. 3.9-95 HCGS-UFSAR Revision 0 April 11, 1988

The design conditions for the RHR and core spray pumps are as follows: Core Spray Design pressure Suction 220 psig 125 psig Discharge 500 psig 500 psig Design temperature 360 *F 148°F

1. Normal/upset condition:

The design pressures are as tabulated above. The OBE seismic accelerations are 0.75g horizontal and 0.07g vertical. The stress limits for the pressure boundary are the ASME B&PV Code allowable stresses, 1. 0 S for general membrane, and 1.5 S for bending plus local membrane.

2. Faulted or emergency condition:

Design pressures are as tabulated above. The SSE seismic accelerations are 1.5g horizontal and 0.14g vertical. The stress limits for the pressure boundary are 120 percent of the ASME B&PV Code allowable stresses, 1. 2 S for general membrane, and 1.8 S for bending plus local membrane. Table 3.9~5p summarizes the design calculation for the RHR and core spray pumps. 3.9.3.1.12 Standby Liquid Control Pumps The SLC pumps are designed and fabricated following the requirements for ASME B&PV Code, Section III, Class 2 components.

1. The operating conditions for each SLC pump and motor are functionally tested by pumping demineralized water through a closed test loop. Each SLC pump is capable of HCGS-UFSAR Revision 0 April 11, 1988

injecting the net contents of the SLC tank into the reactor in not

          'less than 50 minutes and not more than 125 minutes.              Each pump is of               flow into the reactor              a pressure of zero          up   to  the   initial             pressure   of   the  reactor safety/relief valves (SRVs) .

2. The design conditions for each SLC pump include:

a. Flow rate: 43 gpm

b. Available NPSH, maximum: 12.9

c. Maximum pressure: 1255 psig

d. AITbient room conditions can be found in the Creek Environmental Design Criteria (EDC), Document no. D7.5.

e. The normal plus upset conditions which control the pump include:

(1) Design pressure 1400 psig (2) Design temperature 150°F (3) OBE 0.75 g (Horiz.} 0.07 g (Vert. l The stress limit for the pressure boundary is the ASME B&PV Code allowable stress, 1.0 S for membrane.

f. The faulted or emergency conditions include:

(1) Design pressure 1400 psig (2) temperature 150°F 3.9-97 HCGS-UFSAR Revision 19 November 5, 2012

( 3) SSE Horizontal ~ 1.5 g Vertical - 0.14 g The stress limits for the pressure boundary are 120 percent of ASME B&PV Code allowable stresses,

1. 2 S for general membrane, and 1. 8 S for bending plus local membrane.

A summary of the design calculations and nozzle loads for the SLC pump components is contained in Table 3.9-4n. 3.9.3.1.13 Main Steam Isolation and Safety/Relief Valves Load combination analytical methods, calculated stresses, and allowable limits are shown for the SRVs and the MSIVs in Tables 3.9-4i and 3.9-4j, respectively. 3.9.3.1.14 Safety/Relief Valve Discharge Piping See Section 3.9.3.1.20. 3.9.3.1.15 High Pressure Coolant Injection Turbine Although not under the jurisdiction of the ASME B&PV Code, Section III, the HPCI turbine is designed and fabricated following the basic guidelines for an ASME B&PV Code, Section III, Class 2 component.

1. The operating conditions for the HPCI turbine include:

a. Surveillance testing - Monthly operation with reactor pressure at 1000 psia (nominal) and saturated temperature; turbine exhaust pressure at 65 psia (peak) and saturated temperature

b. Auto-startup 30 cycles per year with reactor pressure at 1150 psia (nominal) and saturated 3.9-98 HCGS-UFSAR Revision 0 April 11, 1988

temperature; turbine exhaust pressure at 65 psia (peak) and saturated temperature.

2. The design conditions for the HPCI turbine include:

a. Turbine inlet - 1250 psig at saturated temperature

b. Turbine exhaust - 185 psig at saturated temperature

c. The upset conditions that control the turbine design include:

(1) Design pressure (2) Design temperature (3) OBE (4) Inlet and exhaust piping nozzle loads. The stress limits for the pressure boundary are the ASME B&PV Code allowable stresses, 1.0 S for general membrane, and 1.5 S for bending plus local membrane.

d. The faulted or emergency conditions include:

(1) Design pressure (2) Design temperature (3) SSE {4) Inlet and exhaust piping nozzle loads. The stress limits for the pressure boundary are 120 percent of the ASME B&PV Code allowable stresses, 3.9-99 HCGS-UFSAR Revision 0 April 11. 1988

1.2 S for general membrane, and 1.8 S for bending plus local membrane. A summary of the design calculations for the HPCI turbine components is shown in Table 3.9-4dd. 3.9.3.1.16 High Pressure Coolant Injection Pump The HPCI pltmp is designed and fabricated following the requirements for an ASME B&PV Code, Section III, Class 2 component.

1. The operating conditions for the HPCI pump are surveillance tested in conjunction with the HPCI turbine. A monthly operational test is performed, during which the HPCI pump takes condensate from the condensate storage tank {CST) and, at design flow, condensate back to the CST via a closed test loop.

2. The Design conditions for the HPCI pump include:

a. The required NPSH of the HPCI Booster Pump at speed 2093 rpm and flow 5920 gpm is 19.7 feet. [Reference Calculation BJ-0002, Rev. 6, Section 7.3]

b. Total head - High speed: 3162 feet

                               - Low speed: 1038 feet

c. Constant flow rate 5600 gpm

d. Ambient room conditions can be found in the Hope Creek Environmental Design Criteria (EDC), Document no. D7.5.

e. The normal plus upset conditions that control the pump design include:

(1) Design pressure 1500 psig (2) Design temperature 40 to 140°F (3) OBE 2/3 of SSE 3.9-100 HCGS-UFSAR Revision 16 May 15, 2008

(4) Suction nozzle loads F0 - 5570 pounds, M 15,370 foot-pounds 0 (5) Discharge nozzle loads F - 7850 pounds, 0 M - 15,385 foot-pounds 0 where: F and M are as defined in Table 3.9-4v. 0 0 The stress limits for the pressure boundary are the ASME B&PV Code allowable stresses, 1.0 S for general membrane, and 1.5 S for bending plus local membrane.

f. The faulted or emergency conditions include:

(1) Design pressure 1500 psig (2) Design temperature 40 to 140°F (3) SSE Horizontal - 1.50 g Vertical - 0.14 g (4) Suction nozzle loads F 6680 pounds, 0 M 18,450 foot-pounds 0 (5) Discharge nozzle loads F- 9420 pounds*, 0 M0 - 18,465 foot-pounds where: F0 and M0 are as defined in Table 3.9-4v. The stress limits for the pressure boundary are 120 percent of the ASME B&PV Code allowable stresses,

1. 2 S for general membrane, and 1. 8 S for bending plus local membrane.

The calculated stress values are compared with allowable stresses for critical components in Table 3.9-4v. 3.9-101 HCGS-UFSAR Revision 0 April 11, 1988

3.9.3.1.17 Reactor Water Cleanup System Pumps The Reactor Water Cleanup (RWCU) System pumps are not part of a safety system and are not required to meet Seismic Category I requirements. The static analysis considers static equilibrium forces on the equipment including the effect of OBE loads. This analysis considers piping loads as well as torsional moment produced by the rotating assembly. The design loading combinations and limits for each RWCU pump include the following:

1. Normal plus upset loads include the simultaneous effect of normal operating loads, design pressure, temperature, nozzle loads, dead weight loads including seismic due to OBE loads, plus torsional load due to rotation of the component assembly.

2. The pump and its supports are designed to withstand the OBE loads applied at the mass center, assuming that the pump is flooded.

3. Stresses in the supports and the anchor bolts due to OBE loads are combined with the stresses due to other live and dead loads and operating loads. The allowable stress for this combination of loads is based on the allowable stresses set forth in the applicable codes.

4. The ASME B&:PV Code, Section III, is used as a guide in calculating the thickness of the pressure retaining parts and for sizing the pressurized cover bolting.

5. Transient analysis is not required for Class 3 components operating in the 70 to 545°F temperature range.

3.9-102 HCGS-UFSAR Revision 0 April 11, 1988

Table 3.9-Sr shows the calculated stress values and allowable stress limits for the pumps. 3.9.3.1.18 Fuel Pool Cooling and Cleanup System Heat Exchangers See Section 3.9.3.1.20. 3.9.3.1.19 Reactor Water Cleanup System Heat Exchangers The RYCU regenerative and nonregenerative heat exchangers are not part of a safety system and are not required to meet Seismic Category I requirements. However, a static seismic analysis is done on these heat exchangers. Static seismic forces of 0.2 g horizontal and 0 g vertical are used in this analysis. The loadings considered in the design of the heat exchangers include:

1. Normal plus upset loads include the simultaneous effect of normal operating loads, design pressure, temperature, nozzle loads, and dead weight loads.

2. The heat exchangers and their supports are designed to withstand the static seismic forces applied.

3. Stresses in the supports and the anchor bolts due to seismic loads are combined with the stresses due to other live and dead loads and operating loads. The allowable stress. for this combination of loads is based on the allowable stresses set forth in the applicable codes.

4. The allowable shear on anchor bolts set in concrete are in accordance with Table Number 26-1 of the Uniform Building Code.

Table 3.9-4d shows the calculated stress values and allowable stress limits for the heat exchangers. 3.9-103 HCGS-UFSAR Revision 0 April 11, 1988

3.9.3.1.20 Non-NSSS ASME B&PV Code Constructed Items The design loading combinations categorized with respect to plant operating conditions identified as normal, upset, emergency, and faulted for the non-NSSS ASME B&PV Code constructed items are presented in Table 3.9-7. The design criteria and stress limits associated with each of the plant operating conditions for each type of ASME B&PV Code constructed item are presented in Tables 3.9-8 through 3.9-14. The component operating condition is the same as the plant operating condition, except for active pumps or valves, for which the emergency or faulted plant condition is considered normal. 3.9.3.2 NSSS Pump and Valve Operability Assurance The NSSS active pumps are listed in Table 3.9-15 and the NSSS active valves are listed in Table 3.9-16. Table 3.9-26 lists examples of PVORT NSSS equipment qualification methodology. Active mechanical equipment classified as Seismic Category I is designed to perform its function during the life of the plant under postulated plant conditions. Equipment with faulted condition functional requirements include active pumps and valves in fluid systems such as the RHR system and the core spray system. Active equipment must perform a mechanical motion during the course of accomplishing a safety function. Periodic inspection and operational testing is performed as per the requirements in Section 16. See Section 3.9.6 for operational testing outline. The only NSSS active valves subjected to hydrodynamic loads are the safety/relief valves (B21-F013) and the main steam isolation valves (B21-F022). Both of these valve types are being dynamically qualified by test up to 100 hz. HCGS-UFSAR Revision 0 April 11, 1988

The load and conditions considered in the qualification of safety-related pumps and valves are given in Tables 3.9-4 and 3.9-4(a). Deflections due to piping loads and dynamic loads are addressed for active essential pumps and valves by several methods depending on the situation. Methods used include static deflection analysis, dynamic deflection analysis, and dynamic seismic testing. Operability is ensured by satisfying the requirements of the following programs. Safety-related active valves are qualified by prototype testing and analysis, and safety-related active pumps by analysis with suitable stress limits and nozzle loads. The content of these programs is detailed below. 3.9.3.2.1 Emergency Core Cooling System Pumps All active ECCS pumps are qualified for operability by first being subjected to rigid tests, both prior to and after installation in the plant. The in-shop tests include:

1. Hydrostatic tests of pressure retaining parts to 125 percent of the design pressure (times the ratio of material allowable stress at room temperature to the allowable stress value at the design temperature)

2. Seal leakage tests

3. Performance tests, while the pump is operated with flow, determines total developed head, minimum and maximum head, and NPSH requirements.

3.9-105 HCGS-UFSAR Revision 16 May 15, 2008

Also monitored during these operating tests are bearing temperatures (except water cooled bearings) and vibration levels. Both are shown to be below specified limits. After the pump is installed in the plant, it undergoes the cold hydro tests, functional tests, and the required periodic inspection and operational testing per the requirements in Chapter 16. These tests demonstrate reliability of the pump for the design life of the plant. In addition to these tests, the safety-related active pumps are analyzed for operability during an SSE condition by ensuring that the pump is not damaged during the seismic event, and that the pump will continue operating despite the SSE loads. 3.9.3.2.1.1 Analysis of Loading, Stress, and Acceleration Conditions To avoid damage during the faulted plant condition, the stresses caused by the combination of normal operating loads, SSE, and dynamic system loads are limited to the material elastic limit, as indicated in Section 3.9.3.1 and Table 3.9-5. The average membrane stress (0[16]fm) for the faulted condition loads is limited to 1.20[16]fm. The maximum stress in local fibers (0[16]fm + bending stress (0[16]fb)) is limited to 1.8 S. The qualification of the pump and motor as an integral unit while operating under OBE and SSE conditions is provided in the form of a static earthquake-acceleration analysis. Under this criterion, the unit is considered to be supported as designed, and the maximum specified vertical and horizontal accelerations are constantly and simultaneously applied in the worst case combination. The maximum seismic nozzle loads from the attached piping system are also considered in an analysis of the pump support to ensure that there is no geometrical/dimensional deformation of the pump components. HCGS-UFSAR Revision 0 April 11, 1988

3.9.3.2.1.2 Pump Operation During and Following Safe Shutdown Earthquake Loading Active pump/motor rotor combinations are designed to rotate at a constant speed under all conditions. Motors are designed to withstand short periods of severe overload. The high rotary inertia in the operating pump rotor, and the nature of the random, short duration loading characteristics of the seismic event, prevent the rotor from becoming seized. In actuality, the seismic loadings cause only a slight increase, if any, in the torque, i.e., motor current, necessary to drive the pump at the constant design speed. Therefore, the pump does not shut down during the SSE and operates at the design speed, despite the SSE loads. The functional ability of the active pumps after a faulted condition is ensured since only normal operating loads and steady state nozzle loads exist. For the active pumps, the faulted condition is greater than the normal condition due to seismic SSE loads on the equipment itself. The SSE event is infrequent and of relatively short duration compared to the design life of the equipment. Since it is demonstrated that the pumps are not damaged during the faulted condition, the post-faulted condition operating loads will be no worse than the normal plant operating limits. This is ensured by requiring that the imposed nozzle loads (steady state loads) for normal conditions and post-faulted conditions are limited by the magnitudes of the normal condition nozzle loads. The ability of the pumps to function under these applied loads for post-faulted conditions is proven during the normal operating plant conditions for active pumps. 3.9.3.2.2 Standby Liquid Control Pump and Motor Assemblies and Reactor Core Isolation Cooling Pump Assembly These equipment assemblies are small, compact, rigid assemblies with natural frequencies well above 33 hertz. With this fact verified, each equipment assembly is seismically qualified via static analysis only. This static qualification verifies 3.9-107 HCGS-UFSAR Revision 0 April 11, 1988

operability under seismic conditions and ensures that structural loading stresses are within ASME B&PV Code limitations. 3.9.3.2.3 Emergency Core Cooling System Motors Qualification of the Class lE motors used for the ECCS motors is in compliance with IEEE 323-1974. The qualification of all motor sizes is based on completion of a type test, followed with review and comparison of design and material details and seismic analysis of production units, ranging from 500 to 3500 Bhp, with the motor used in the type test. All manufacturing, inspection, and routine tests by motor manufacturer on production units are performed on the test motor. The type test was performed on a 1250 hp vertical motor, in accordance with IEEE 323-1974. First normal operation during the design life was simulated; then the motor was subjected to a number of seismic events; and then subjected to the abnormal environmental conditions possible during and after a LOCA. The type test plan was as follows:

1. Thermal aging of the motor electrical insulation system (which is a part of the stator only) was based on extrapolation, in accordance with the temperature life of the characteristic curve from IEEE 275-1966 for the insulation type used on the ECCS motors. The amount of aging equals the total estimated operation days of maximum insulation surface temperature.

2. Radiation aging of the motor electrical insulation equals the maximum estimated integrated gamma dose during normal and abnormal conditions.

3. The normal induced current vibration effect on the insulation system was simulated by a 1. 5 g horizontal vibration acceleration for one hour at current frequency.

3.9-108 HCGS-UFSAR Revision 0 April 11, 1988

4. Motor bearings were selected and their operating life established on the basis of bearing manufacturer's tests and operating data using the loads calculated to act on the bearings.

5. The dynamic load deflection analysis on the rotor shaft, performed to ensure adequate rotation clearance, is verified by static loading deflection of the rotor for the type test motor.

6. Dynamic loading aging and testing were performed on a biaxial test table in accordance with IEEE 344-1975. During this type test, the shake table was activated, sLmulating the maximum design limit of the SSE loads with motor starts and operation combination, as may possibly occur during the life of the plant.

7. An environmental test simulating a LOCA condition was performed for 100 days with the test motor fully loaded, simulating pump operation. The test consists of startup and six hours of operation at 212°F ambient temperature, and a 100 percent steam environment. After one hour standstill in the same environment, another startup and operation of the test motor was followed by sufficient operation at high humidity and temperature. This was based on extrapolation in accordance with the temperature life characteristic curve from IEEE 275-1966 for the insulation type used on the ECCS motors.

3.9.3.2.4 High Pressure Coolant Injection Pump Assembly Operability of the HPCI pump assembly is demonstrated by a combination of analytical stress calculations, pump manufacturer's operating experience, and testing. The stress definitions and the allowable stress criteria are based on the ASME B&PV Code, Section III. The Code is directly applicable to the stamped pressure boundary components of the pump. 3.9-109 HCGS-UFSAR Revision 8 september 25, 1996

The witnessed hydrostatic and performance tests, as performed at the pump manufacturer's plant, demonstrate that the pump, as designed, meets the ASME B&PV Code, section III, requirements and the parameters of the design specification. A three dimensional, finite element model was developed and dynamically analyzed using the response spectrum analysia method. The model was analyzed using static nozzle loads, pump thrust loads, and dead weight. Critical location stresses were evaluated and compared with the allowable stress based on the ASME B&PV Code, section III. Shaft deflections and accelerations were analyzed to ensure that the rotating parts have no contact with the stationary parts, except at engineered wear points based on the pump manufacturer's operating experience. The above considerations provide adequate assurance that the pump will remain operable during the SSE load condition. 3.9.3.2.5 NSSS ASME B&PV Code Class 1 Active Valves Each of the Class l valves is designed to perform its mechanical motion in conjunction with a design basis accident (DBA). Seismic qualification for operability is unique for each valve type. Each method of qualification is detailed individually below. 3.9.3.2.5.1 Main Steam Isolation Valves The MSIVs are evaluated for operability during a seismic event by analysis and testing as follows:

1. First, the design of the valve body is evaluated in accordance with the applicable code that limits deformations in the operating area of the valve body to be within the elastic limit of the material, by limiting pressure and pipe reaction input loads, including seismic, thereby ensuring no interference with valve operability.

3.9-110 HCGS-UFSAR Revision 0 April 11, 1988

2. An analysis is completed on the actuator structure to determine component stresses and actuator deflection at loads under faulted conditions, including seismic acceleration loads. Component stresses of the actuator structure are limited to be within the material's elastic limit.

3. A dynamic test is conducted to qualify the control components and the safety-related limit switches for seismic condition loadings.

To ensure that design limits are not exceeded for both piping input loads and actuator dynamic loads, the MSIV is mathematically modeled in the main steam line system analysis. The valve's actual input loads, amplified accelerations, and resonance frequencies are determined based on site excitation input to the system as a part of the overall steam line analysis. Pipe anchors and restraints are applied as required to limit pipe system resonance frequencies and amplified acceleration to be within acceptable limits for the MSIVs. MSIV operability during seismic acceleration is addressed in Sections 3.9.2.3.1 and 3.9.2.3.2.13. MSIV operability during LOCA conditions has been demonstrated, as defined in Reference 3.9-13. The test specimen was a 20-inch valve of a design representative of the MSIVs. Qualification testing of sensitive electrical/pneumatic equipment to meet performance requirements is completed. 3.9.3.2.5.2 Safety/Relief Valves The SRVs are qualified by test for operability during a seismic event. Structural integrity of the configuration during a seismic event is demonstrated by both analysis and test. The test includes the following steps:

1. Each valve is designed for the maximum moments that may be imposed when installed in service with inlet and outlet conditions of 400,000 inch-pounds and 300,000 inch-pounds, respectively. These moments are resultants of dead weight plus seismic loading (3g horizontal and 1g vertical) of both valve and connecting pipe, thermal expansion of the connecting pipe, and reaction forces from valve discharge.

3.9-111 HCGS-UFSAR Revision 23 November 12, 2018

2. A production 2-Stage SRV demonstrated its operability during a dynamic qualification (shake table) test when moment and seismic loads were applied that were greater than the required design limit loads and conditions for this equipment.

A mathematical model of this valve is included in the main steam piping system analysis along with one for the MSIVs. This analysis ensures that the equipment design limits are not exceeded. Seismic tests were conducted on the SRVs, and the natural frequencies were determined to be greater than or equal to 33 hertz. The tests also determined that the equipment remains functional during application of the specified seismic loads. In addition to the testing described above, and in Section 3.9.2.3, the sensitive electrical/pneumatic equipment of the SRVs were qualified to perform during and after emergency environmental conditions. The SRV analytical qualifications results are shown in Table 3.9-4i. The original SRVs at Hope Creek were the 2-Stage Target Rock SRVs. Target Rock 3-Stage SRVs have been evaluated and approved for installation at Hope Creek. The 3-Stage SRVs were qualified as follows: The original NSSS vendor evaluated that the use of the 2-Stage Required Response Spectrum for seismic testing (in the original product qualification specification) remained appropriate for the 3-Stage SRV. Target Rock document TR 9384, Seismic Qual. Report" (VTD 432427) documents the seismic qualification of the 3-Stage SRV by analysis that was benchmarked against actual testing for the Limerick 3-Stage SRV. An independent third party verified that the seismic qualification performed by Target Rock met the requirement of original 2-Stage SRV. The natural frequencies of the 3-Stage SRVs were also demonstrated to be greater than 33 Hz. The 3-Stage SRVs were analyzed in accordance with the ASME Code (ASME Boiler and Pressure Vessel Code, Section III, Division 1, Class A, 1968 Edition with Addenda thru Winter 1970) in VTD 432428, to the same values of moment (300,000 in-lb and 400,000 in-lb, and greater values of acceleration (two horizontal accelerations of 4.5g, and one vertical acceleration of 4.5g). 3.9-112 HCGS-UFSAR Revision 23 November 12, 2018

3.9.3.2.5.3 Check Valves for the Residual Heat Removal and Core Spray Systems GE scope of supply includes eight air operable and testable check valves: six for the RHR system, and two for the Core Spray System. Operability of these check valves is ensured by design calculations and sufficient structural margins, so that movement of the diskfhinge pin is not impaired under any loading conditions. 3.9.3.2.6 NSSS ASME B&PV Code Class 2 and 3 Active Valves 3.9.3.2.6.1 Control Rod Drive Valves GE scope of supply for the Control Rod Drive (CRD) system includes four ASME B&PV Code Class 2 active valves, but no Class 3 valves. The four Class 2 active valves in the CRD scram discharge volume vent and drain lines are air operated. However, the valves are designed to be fail-safe; the safety operation of the valve closure does- not depend upon the plant air supply or on electrical operation of the controlling solenoid valves. In the event that the solenoid valves that control the globe valves are deenergized, or the plant air supply is interrupted for any reason, the yoke springs held in tension are capable of closing the valve. The valves are analyzed and type tested per IEEE 344*1975 to ensure operability during and after the dynamic loadings due to an earthquake. 3.9.3.2.6.2 Standby Liquid Control Valve (Explosive Valve) The standby liquid control explosive valves are qualified to IEEE 344*1975. The qualification test included a demonstration of the absence of natural frequencies below 33 hertz, and the ability to remain operable under a horizontal seismic coefficient of 6. Sg and a vertical seismic coefficient of 4.5g at 33 hertz. 3.9-113 HCGS-UFSAR Revision 0 April 11, 1988

3.9.3.2.7 Non-NSSS Pump and Valve Operability Assurance 3.9.3.2.7.1 Non-NSSS Active Pumps The non-NSSS active pumps are tabulated in Table 3.9-17. Non-NSSS active pumps are subjected to testing both in the manufacturer, s shop and following their installation to verify that they meet the criteria required by the design specifications. Table 3. 9-27 provides examples of Non-NSSS active pumps, indicating their qualification method and the industry standards met. During manufacture, nondestructive test procedures including liquid penetrant examination, radiographic examination, magnetic particle inspection, and ultrasonic inspection are applied to the pumps. All of these procedures are performed :Ln accordance with the ASME B&PV Code, Section III. After the pumps have been assembled, they are and performance tested in the manufacturer s1 shop in accordance with Hydraulic Institute standards. After the pumps are installed, they undergo functional tests. Provisions are made for inspection and operational testing per the requirements in Section 16. See Section 3. 9. 6 for operational testing outline. All of these test;s demonstrate that the pumps are reliable and will function as specified. In addition to the tests and procedures referred to above, the pumps are seismically analyzed to ensure that they will be capable of operating both during and after OBE and SSE events. Information on loading combinations 1 system operating transients, and stress limits for pumps is given in the response to Question 210.52. 3.9-114 HCGS-UFSAR Revision 16 May 15, 2008

In performing these analyses, conservative seismic accelerations and stress criteria are used; this ensures that critical parts of the pump are not damaged during a seismic event, and that the pump still operates following such an event. Deflection due to piping loads and dynamic loads is addressed for active essential pumps by several methods depending on the situation. Methods used include static deflection analysis, dynamic deflection analysis, static bend testing, and dynamic seismic testing. These methods account for pump deflection due to the application of nozzle allowable loadings and demonstrate component operability. Each pump/motor combination is designed to rotate at a constant speed under all conditions, unless the rotor becomes completely seized, i.e. , fails to rotate at all. Motors are designed to withstand short periods of severe overload and, typically, the rotor can be seized a short period of time before a circuit breaker shuts down the pump. However, the high rotary inertia in the operating pump rotor and the nature of the random, short duration loading characteristics of the seismic event, will prevent the rotor from becoming seized. In actuality, the seismic loadings will cause only a slight increase in the torque, i.e., motor current, necessary to drive the pump at the constant design speed. Therefore, the pump will not shut down during the event and will operate at the design speed, despite the seismic loads. From previous discussions, it is evident that the pump/motor units will withstand seismic loadings and perform their intended functions. These proposed requirements take into account the complex characteristics of the pump, and they are sufficient to demonstrate and ensure the seismic operability of these pumps. Post-seismic condition operating loads will be no worse than the normal plant operating limits. 3.9-115 HCGS-UFSAR Revision 0 April 11, 1988

3.9.3.2.7.2 Non-NSSS Active Valves Non*NSSS active valves are tabulated in Table 3. 9-18. See Sections 3.9.3.2.5 and 3.9.3.2.6 for a discussion of operability assurance of active valves supplied by the NSSS vendor. Table 3.9-27 provides examples of non-NSSS active valves, indicating their qualification method and the industry standards met. Safety-related non-NSSS active valves are subjected to a series of stringent tests prior to service and during the plant life. Before installation, the following tests are performed: the shell hydrostatic test, in accordance with ASME B&PV Section III requirements; backseat and main seat leakage tests; the disc hydrostatic test; functional tests which verify that the valve opens and closes within the specified time limits; and the operability qualification of motor, air, and hydraulic operators for environmental conditions over the installed life, i.e., aging, radiation, accident environment simulation, etc, in accordance with IEEE 382-1972. It is the intent of PSE&G to review the qualification reports of all *safety-related non-NSSS active valve operators (electric, air, and hydraulic) using the requirements of IEEE 382-1980. The intent of IEEE 382-1980 has been met to the maximum degree possible. without embarking on a completely new qualification program. This has been done by reviewing the existing qualification reports using the IEEE 382-1980 requirements and supplementing these original tests with additional test and/or analyses, as applicable, to demonstrate the upgraded qualification. After installation, cold hydrostatic tests, functional tests (in accordance with the requirements of Section 14), and periodic inservice operation (in accordance with the requirements of Section 16) are performed to verify and ensure the functional ability of the valve. See Section 3. 9. 6 for operational testing outline. 3.9-116 HCGS-UFSAR Revision 0 April 11, 1988

The method of qualification for soft parts of safety-related valves is addressed in Section 3 .11. 2. 6. In addition, maintenance and surveillance program requirements are given in Section 3.11.2.7.6. The valves are designed using either stress analyses or pressure containing minimum wall thickness requirements. For all active valves with extended topworks, an analysis is also performed for static equivalent SSE loads applied at the extended structure's center of gravity. The maximum stress limits allowed in the analyses demonstrate structural integrity and are equal to the limits recommended by ASME for the particular ASME class of valve analyzed. The loads and conditions considered in the qualification of Class 1 valves are given in Table- 3.9-9. The loads and conditions considered for Class 2 and 3 valves are given in Table 3.9-14. In addition to the foregoing, a representative valve of each type is factory tested to verify operability during a simulated seismic event. The factory qualification testing procedures are as described below. Deflection due to piping loads and dynamic loads are addressed for active essential valves by several methods depending on the situation. Methods used include static deflection analysis, dynamic deflection analysis, static bend testing, and dynamic seismic testing. The valve is mounted in a manner that conservatively represents typical valve installations. The valve unit includes the actuator and all appurtenances normally attached to the valve in service. The operability of the valve during an SSE is demonstrated by satisfying the following criteria:

1. All active valves with topworks must have a first natural frequency greater than 33 hz. This is proven by analyses.

For valves mounted on lines connected directly or 3.9-117 HCGS-UFSAR Revision 0 April 11, 1988

indirectly to the RPV or the biological shield, resonant frequencies up to 100 hertz are determined. Such frequencies are used as input to the dynamic analysis of the piping systems for annulus pressurization effects. Because of the unique and heavier loads imposed by hydrodynamic forces on piping attached to the suppression chamber, active valves installed in such *piping subjected to hydrodynamic loads are additionally analyzed to determine all resonant frequencies between 0 and 100 hertz. These valves are listed in Table 3.9-30. Such frequencies are used as input to the dynamic analysis of these piping systems.

2. While in the shop and installed in a suitable test rig, the extended topworks of the valve are subjected to a statically applied equivalent seismic load. The load, specified as 4.5g times the weight of the topworks, is applied at the center of gravity of the topworks in the direction of the weakest axis of the yoke. The design pressure of the valve is simultaneously applied to the valve during the static load tests.

3. The valve is then operated at the minimum specified actuation supply voltage or air pressure, with the equivalent seismic static load applied. The valve must perform its safety related function within the specified operating time limits.

4. Valve operators (motor, air, and hydraulic)* are independently qualified as operable during the SSE prior to their installation on the valve.

The equivalent seismic and hydrodynamic static load, which is used for the static valve qualification, is the maximum load which the valve is designed to withstand. .The piping designer maintains the valve operator accelerations within these levels. 3.9-118 HCGS-UFSAR Revision 0 April 11. 1988

The valve is leaktested following the test described above, to show that the valve has not been damaged. The leak rates must not exceed the original allowable leakage rate specified for the valve. The above factory testing program applies only to valves with overhanging structures, e.g., the motor operator, air, or hydraulic actuator assembly. The testing is conducted on a representative number of valves, a representative valve being selected as described below. The valves requiring operability qualification are divided into different groups by valve manufacturer, valve type, size, pressure class, material type (carbon steel, stainless steel, and alloy steel), and actuator type (ac electric, de electric, air, hydraulic, etc). Valve sizes that cover the range of sizes in service are qualified by tests, and the results are used to qualify all valves within the intermediate range of sizes, as shown in Table 3.9-19. A tabulation is made of the weight of the valve actuator, the actuator thrust margin (a ratio of the maximum thrust available from the actuator divided by the design thrust required for the valve), and the yoke configuration, as it relates to stiffness, for each valve assembly. For a range of qualified valve sizes, as defined by the qualification table, the valve assembly with the heaviest actuator, lowest thrust margin, and least stiff yoke is picked as the test unit. In those cases where a test unit is not readily apparent, more than one unit is tested to provide a conservative test position. This procedure is repeated within each group until "-"' all listed units are represented by a test unit, and for each group until all the necessary valves are represented by a test unit. Additionally, the stress calculations for each valve assembly are reviewed, and a tabulation is made for all qualified valve assemblies comparing the yoke stress for all valve classes, the yoke flange to body, and the yoke flange to actuator bolting 3.9-119 HCGS-UFSAR Revision 0 April 11, 1988

stresses, as applicable, for all classes of valves, and the body stress for Class 1 valves. This is done to provide further analytical justification for the qualification of nontested valves by tested valves. Because of their compact configuration, check valves are not adversely affected by seismic acceleration. They have no extended structures to distort the bodies and cause malfunctions. Their discs are designed to allow sufficient clearance within the body to prevent binding or interference due to distortions from nozzle or other imposed loads. They are qualified by a combination of the following factory tests and analysis:

1. Stress analysis of critical areas and parts for SSE loads, in accordance with the allowables specified in Tables 3.9-9 and 3.9-14.

2. In-shop hydrostatic test

3. In-shop seat leakage test

4. Periodic valve exercise and inspection to ensure the functional ability of the valve, in accordance with the requirements of Section 16.

Seismic operability testing is not performed for vacuum relief valves. Due to the particularly simple characteristics of these valves, and the lack of extended structures, they are qualified by a combination of the following tests and analysis:

1. Stress analysis, including seismic loads where applicable

2. In-shop hydrostatic test

3. In-shop seat leakage test

4. Performance tests

5. Periodic in situ valve inspection, as applicable, and periodic valve removal, refurbishment, performance testing, and reinstallation 3.9-120 HCGS-UFSAR Revision 23 November 12, 2018

The above testing and analysis is sufficient to ensure the functional capability of the valve. The following applies to 2-Stage SRVs: SRVs that have an extended structure go through a similar qualification procedure as the vacuum relief valves, with the addition of a seismic operability qualification test, as described below. The SRVs are type tested. A random valve is selected from a lot of valves of similar design and size. The valve is tested at operating pressure and at ambient temperature conditions. The test is a four-part procedure that consists of:

1. Verifying the operability of the valve before the simulated seismic event

2. Applying a static coefficient seismic load to the valve superstructure and verifying its operability during the event

3. Removing the load and verifying its operability after the event

4. Subsequent inspection after the test.

The seismic test demonstrates that SRVs can open within a specific pressure band to protect vessels and equipment from abnormal pressure, and that they are able to reseat, preventing a further flow of fluid after normal pressure conditions have been restored. The original SRVs at Hope Creek were the 2-Stage Target Rock SRVs. Target Rock 3-Stage SRVs have been evaluated and approved for installation at Hope Creek. The 3-Stage SRVs installed at Hope Creek were qualified as follows: The original NSSS vendor evaluated that the use of the 2-Stage Required Response Spectrum for seismic testing (in the original product qualification specification) remained appropriate for the 3-Stage SRV. Target Rock document TR 9384, Seismic Qual. Report" documents the seismic qualification of the 3-Stage SRV by analysis that was benchmarked against actual testing for the Limerick 3-Stage SRV. An independent third party verified that the seismic qualification performed by Target Rock met the requirement of original 2-Stage SRV. The natural frequencies of the 3-Stage SRVs were also demonstrated to be greater than 33 Hz. 3.9-121 HCGS-UFSAR Revision 23 November 12, 2018

During a seismic event, it is anticipated that the seismic acceleration imposed upon the valve may cause it to open momentarily and discharge under system conditions that otherwise would not result in valve opening, but this is considered to be of no real safety or other consequence. Using the methods described, the safety-related active valves in the systems are qualified for operability during the seismic event. These methods conservatively simulate the seismic event and ensure that the active valves will perform their safety functions when necessary. 3.9.3.2.7.3 Extent of Pump and Valve Qualification/Operability per Draft Standards ANSI/ASME QP-1 (NSS1.1), QP-2 (NSS1.2), QP-3 (NSS1.3), QP-4 (NSS1.4), and Issued ANSI Standards N41.6 and Bl6.41-1983 The subject standards are not included in the Acceptance Criteria of NRC Standard Review Plan (SRP) 3.10. However, these standards are identified in the review procedure. The extent to which these draft standards are used in the qualification of pumps and valves is given below: Valves: ANSI Std. N 41.6 is the same as IEEE Std. 382-1972. This standard is complied fully in the qualification of all the valves. The extent of qualification of one 18" motor operated valve has been reviewed against the requirements of ANSI Std. B16.41-1983. Essentially the ...._, requirements of this standard are met in the qualification of 18" motor operated valves. Pumps and Motors: The qualifications of Safety Auxiliaries cooling System pumps and valves has been reviewed per the requirements of Draft Standards QP-1, QP-2, QP-3, QP-4. Some additional information was obtained from the manufacturer recently in this connection. 3.9-122 HCGS-UFSAR Revision 8 September 25, 1996

Essentially, the requirements of these standards are met, except for that of QP-3 (Shaft Seal Assemblies). The detailed response was provided by PSE&G Letter to NRC, R. L. Mittl to W. Butler, dated September 18, 1985. 3.9.3.3 Design and Installation of Pressure Relief Devices 3.9.3.3.1 NSSS Safety/Relief Valves The original SRVs at Hope Creek were the 2-Stage Target Rock SRVs. Target Rock 3-Stage SRVs have been evaluated and approved for installation at Hope Creek. Because the 2-Stage and 3-Stage SRVs have the same set pressures, capacities, and response times, the following discussion is applicable to both 2-Stage and 3-Stage SRVs. An SRV lift results in a transient that produces momentary unbalanced forces acting on the discharge piping system, for the period from opening of the SRV until a steady discharge flow from the RPV to the suppression pool is established. This period includes clearing of the water slug from the end of the discharge piping submerged in the suppression pool. Pressure waves traveling through the discharge piping following the relatively rapid opening of the SRV, cause the SRV discharge piping to vibrate. This in turn produces forces that act on the main steam piping. The analysis of the relief valve discharge transient consists of a sequential time history solution of the fluid flow equation to generate a time history of the fluid properties at numerous locations along the pipe. The fluid transient properties are calculated based on the maximum set pressure specified in the steam system specification and the value of the ASME B&PV Code flow rating increased by a factor to account for the conservative method of establishing the rating. Simultaneous discharge of all valves is assumed in the analysis, because simultaneous discharge is considered to induce maximum stress in the piping. Reaction loads on the pipe are determined at each location corresponding to the position of an elbow. These loads are composed of pressure times area, momentum change, and fluid friction terms. 3.9-123 HCGS-UFSAR Revision 23 November 12, 2018

The method of analysis applied to determine piping system response to relief valve operation is time history integration. The forces are applied at locations on the piping system where fluid flow changes direction, thus causing momentary reactions. The resulting loads on the SRV, the main steam line, and the discharge piping are combined with loads due to other effects, as specified in Section 3.9.3.1. The ASME B&PV Code stress limits corresponding to load combinations classified as normal, upset, emergency, and faulted are applied to the main steam lines and to the SRV discharge piping. The drywall SRV piping system for HCGS consists of 14 individual Schedule 40, SA~l06, Grade B piping lines. The nominal pipe size of the piping is 10" Schedule 40 at the outlet flange of the SRV, changing to 10" Schedule 80 immediately before the vent pipe jet deflector and 10" Schedule 160 at the vent pipe penetration (VPP). Figure 3. 9-7 shows the routing, support locations, and support types, for a representative SRV line in the drywell. The 14 SRV lines initiate at the 4 main steam lines and are grouped in sets of three and four, as shown schematically in Figure 3.9-8. The lines are routed from the drywall area through the vent lines and into the suppression chamber. The 14 SRV lines are attached to the 4 main steam lines in the drywall at the safety-relief valves, as shown in Figure 3.9-9. Each SRV line passes through a vent pipe jet deflector and is supported at an intermediate location in the vent pipe. Beyond this support, the SRV line turns go* and exits the vent pipe at the VPP. This arrangement is shown in Figure 3.9-10. The wetwell SRV piping system for HCGS consists of fourteen 10" diameter, Schedule 80, SA-106 Grade B piping lines. Figure 3.9-11 shows a typical wetwell SRV line and support locations. 3.9-124 HCGS-UFSAR Revision 0 April 11, 1988

The support system for the wetwell SRV piping consists of a stiffened penetration support at the VPP, vertical and horizontal struts attached to the ring girder, and a lateral strut attached to the vent header. Details of the strut supports attached to the ring girder and vent header are shown in Figure 3.9-12. At the lower end of each SRV line is a 12" diameter T-quencher device. The T-quencher is supported by a 14" diameter pipe beam located directly below the T-quencher arms. The T-quencher arms are connected to the support beam by plate-type supports as shown in Figure 3.9-15. The T-quencher ramshead support assembly consists of the ramshead saddle plate and two attached pin plates with stiffeners. The assembly pin plates are connected to pin plates on the mitered joint ring girder by a 2-1/2 in. diameter pin as shown in Figures 3.9-13 through 3.9-15. The imbalanced thrust load on the last vertical SRVDL segment in the wetwell is shown on Figure 3. 9-16. The reaction loads at the ramshead support are contained in Table 3.9-29. 3.9.3.3.2 Design and Installation Details for Mounting of Pressure Relief Devices in ASME B&PV Code Class 1 and 2 Systems (Non-NSSS) The design of pressure relieving devices can be grouped into two categories: open discharge and closed discharge.

1. Open discharge There are no open discharge pressure relieving devices mounted on ASME B&PV Code Class 1 and 2 systems.

3.9-125 HCGS-UFSAR Revision 12 May 3, 2002

2. Closed discharge A closed discharge system is characterized by piping between the valve and a tank or some other terminal end. Under steady state conditions, there are no net unbalanced forces. The inftial transient response and resulting stresses are determined by using either a time history computer solution or a conservative equivalent static solution. In calculating initial transient forces, pressure and momentum terms are included. Water slug effects are also considered.

Time history dynamic analysis is performed for the discharge piping and its supports. The effect of the loading on the header is also considered. The design loading combinations for a given transient are shown in Table 3.9-7, and the design criteria and stress limits are shown in Tables 3.9-8 and 3.9-12. 3.9.3.4 Component Supports For GE and Bechtel designed pipe supports, the reactions produced by primary and secondary pipe loads are categorized as primary. The primary and secondary loads are summed and compared to the load rating to ensure that the rating is not exceeded. Since no distinction is made between primary and secondary loads, and load rated components are designed to primary limits or they are qualified by testing; the supports meet primary stress criteria for the combination of the primary and secondary loads. 3.9.3.4.1 Piping (NSSS) Piping supports are designed in accordance with Subsection NF of the ASME B&PV Code, Section III. Supports are either designed by load rat~ng, per Subsection NF-3260, or to the stress limits for linear supports, per Subection NF- 3231. To avoid buckling in the component supports, Appendix F of the ASME B&PV Code requires that 3.9-126 HCGS*UFSAR Revision 0 April 11, 1988

the allowable loads be limited to two-thirds of the critical buckling loads. The critical buckling loads for Class 1 component supports in the NSSS scope subjected to faulted loads that are more severe than normal, upset, and emergency lo*ads, are determined by the supplier, using the methods discussed in Appendix F of the ASME B&PV Code. In general, the load combinations for the conditions correspond to those used to design the supported pipe. Design transient cyclic data are not applicable to piping supports, since no fatigue evaluation is necessary to meet the ASME B&PV Code requirements. The design criteria and dynamic testing requirements for component supports are given below:

1. Component supports

• All component supports are designed, fabricated, and assembled so that they cannot become disengaged by the movement of the supported pipe or equipment after they are installed. All component supports are designed in accordance with the rules of Subsection NF of the ASME B&PV Code (Table 3.2-3). For the NSSS scope of supply, all valve operators that are mounted on Class 1 piping are not used as component supports.

2. Hangers - The design load on hangers is the load caused by dead weight. The hangers are calibrated to ensure that they support the design load at both their hot and cold load settings. Hangers provide a specified down travel and up travel in excess of the specified thermal movement.

3. Snubbers

a. Required load capacity and snubber location - The entire piping system, including valves and the suspension system between anchor points, is mathematically modeled for complete structural HCGS-UFSAR Revision 1 April 11, 1989

analysis. In the mathematical model, the snubbers are modeled as a spring with a given spring stiffness depending on the snubber size. The analysis determines the forces and moments acting on each component and the forces acting on the snubbers due to all dynamic loading conditions defined in the piping design specification. The design load on the snubbers includes those loads caused by seismic forces (OBE and SSE), system anchor movements, and reaction forces caused by SRV discharge, main stop valve closure, etc. The snubber location and loading direction are first decided by estimation so that the stresses in the piping system have acceptable values. The snubber locations and direction are refined by performing the computer analysis on the piping system, as described above. The spring constant required by the suspension design specification for a given load capacity snubber is compared against the spring constant used in the piping system model. If the spring constants are not in agreement, they are brought into agreement, and the system analysis is redone to confirm the snubber loads. If the stiffness of the backup structure for the snubber is not large compared to that of the snubber, the reduced effective snubber stiffness {spring constant) is used in the analysis to account for the backup structure flexibility. 3.9-128 HCGS-UFSAR Revision 0 April 11, 1988

b. Design specification* requirements - To ensure that the required structural and mechanical performance characteristics and product quality are achieved, the following requirements for design and testing are imposed:

(1) The snubbers are required by the suspension design specification to be designed in accordance with all of the rules and regulations of the ASME B&PV Code, Section III, Subsection NF (Table 3. 2*3}. This design requirement includes calculation of the stresses in the snubber component parts under normal , upset, emergency, and faulted loads. These calculated stresses are then compared against the allowable stresses of the material, as given in the ASME B&PV Code, Section III, to make sure that they are below the allowable limits. (2) The snubbers are tested to ensure that they can perform as required during OBE and SSE events, and under anticipated operational transient loads or other mechanical loads associated with the design requirements for the plant. The test requirements include: (a) Snubbers are subjected to loading of force or displacement versus time loading at frequencies within the range of significant modes of the piping system. (b) Displacements are measured to determine the performance characteristics specified. 3.9-129 HCGS*UFSAR Revision 1 April 11, 1989

(c) Tests are conducted at various temperatures to ensure operability over the specified range. (d) Peak test loads in both tension and compression are verified to be equal to or higher than the rated load requirements. (e) The snubbers are also tested for various abnormal environmental conditions. Upon completion of the abnormal environmental transient test, the snubber is tested dynamically at a frequency within a specified frequency range. The snubber must operate normally during the dynamic test.

c. Snubber installation requirements - An installation instruction manual is required by the suspension design specification. This manual must contain instructions for storage, handling, erection, and adjustments (if necessary) of snubbers. Each snubber has an installation location drawing that contains the installation, location of the snubber on the pipe and structure, the hot and cold settings, and additional information needed to install the particular snubber.

The suspension design specification requires that snubbers be provided with position indicators to identify the rod position. This indicator facilitates the checking of hot and cold settings of the snubber, as specified in the installation manual, during plant preoperational and startup testing. 3.9-130 HCGS-UFSAR Revision 0 April 11, 1988

d. Inspection, testing, repair, and/or replacement of snubbers The suspension design specification requires that the snubber supplier prepare an installation instruction manual. This manual must contain complete instructions for the testing, maintenance, and repair of the snubber. It must also contain inspection points and the period for inspection.

The suspension design specification requires that hydraulic snubbers be equipped with a fluid level indicator so that the level of fluid in the snubber can be ascertained easily.

e. Struts ~ The design load on struts includes those loads caused by dead weight, thermal expansion, primary seismic forces (OBE and SSE), system anchor displacements, and reaction forces caused SRV discharge, main stop valve closure, etc.

Struts are designed in accordance with NF-3000 of the ASME B&PV Code to be capable of carrying the design load for all conditions (Table 3.2-3).

f. 1. Equipment Anchorage Equipment anchorage is not in the NSSS scope.

2. Component Support Bolting The following bolting design limits are typical of components mounted directly on base plates.

3.9-131 HCGS-UFSAR Revision 1 April 11, 1989

RWCU Pump ......., The support bolting of this pump, which is not safety-related. is designed for the effects of pipe load and SSE loads to the requirements of the ASME B&PV Code, Section III, Appendix XVII. The stress limits of

0. 41 Sy for tension and 0.15 Sy for shear are used.

RCIC/SLC Pumps and RCIC Turbine The equipment-to-base-plate bolting satisfies the following design criteria: For normal and upset conditions, 1.0 S is used for primary membrane (or tension), and 1.5 S for primary membrane plus bending (if applicable), where S is the allowed stress limits from the ASME B&PV Code, Section III, Appendix I, Table I-7.3. For emergency and faulted conditions, stresses shall be less than 1. 2 times the allowed limits for normal and upset conditions. The allowed stress limits used for bolting in pipe supports and pipe mounted equipment supports are as per ASME B&PV Code, Section III, Subsection NF. For service level A and B, the bolts meet the criteria of Paragraph NF-3280. For service level C and D, Article 2460 of Appendix XVII, with the factors indicated in Article 2110 of Appendix XVII, is the applicable design 3.9-132 HCGS-UFSAR Revision 0 April 11, 1988

requirements for bolting. The stresses calculated under these criteria do not exceed the specified minimum yield stresses at temperature.

3. Flanged Connections Flanged connections are not in the NSSS scope.

g. Expansion Anchor Expansion anchors are not in the NSSS scope.

3.9.3.4.2 Emergency Core Cooling System Pumps The core spray and RHR pumps are tested in the shop and tested as defined in Section 3.9.3.2. These tests prove the adequacy of the support structure for the pump assembly under operating conditions. Furthermore, the stress calculation summary provided in Section 3. 9. 3 .1 defines the stress levels in the critical support areas; namely, the pressure boundary parts and nonpressure boundary parts. The stress level margins prove the adequacy of the equipment. 3.9.3.4.3 Reactor Core Isolation Cooling and High Pressure Coolant Injection Turbines The RCIC and HPCI turbine assemblies are analyzed as defined in Section 3.9.3.1. The analyses verify the adequacy of the supports under various operating conditions. In all cases, the calculated stresses in the critical support areas are within the stresses allowed by the ASME B&PV Code. Tables 3.9-4s and 3.9-4dd give the summary of the design calculations for RCIC and HPCI turbine components, respectively. 3.9-133 HCGS-UFSAR Revision 0 April 11, 1988

3.9.3.4.4 Reactor Water Cleanup Sys~em Pump {NSSS) The pump pedestal bolts are analyzed as discussed in Section 3.9.3.1. Loads from seismic, dead weight, connecting pipes, and temperature are considered. 3.9.3.4.5 Reactor Pressure Vessel Support Skirt and Stabilizer The RPV support skirt is designed as an ASME B&PV Code Class 1 plate and shell type component support, per the requirements of the ASME B&PV Code, Section III. The loading conditions, stress criteria, calculated stresses, and the allowable stresses in the critical support areas for various plant operating conditions are summarized in Table 3. 9*4b. The stress level margins prove the adequacy of the RPV support skirt. The RPV stabilizer is designed as a Class 1, linear type component support, per the requirements of the ASME B&PV Code, Section III, Subsection NF. The stabilizer provides a reaction point near the upper end of the RPV to resist horizontal loads due to effects such as earthquake and pipe rupture. The design loading conditions, stress criteria, calculated stresses, and the allowable stresses in the critical areas are summarized in Table 3.9-4bb. A generic BWR 4/5 study was conducted using the design of the Limerick 1 and 2 cylindrical support skirts, which have the smallest ratio of thickness to radius. The study examined the skirt buckling under axial compression, hoop stress, and transverse sheer (see Reference 3.9-21) and showed that under each of these types of loads the critical buckling stress is much greater than the yield stress. Since this study showed that inelastic stability limits the skirt's integrity, the permitted critical buckling stress should be less than 90 percent of the stress from a compressive load that would produce a yield stress, and the permitted buckling stress divided by 1.125 to provide margin for the variations of fabrication or HCGS-UFSAR Revision 1 April 11, 1989

eccentricity. Analyses have shown that the loads on the HCGS support skirt will not produce stresses that exceed two- thirds of the at-temperature critical buckling stress, prescribed by paragraph F-1370(e) of Section III of the ASME B&PV Code. 3.9-134a HCGS-UFSAR Revision 1 April 11, 1989

THIS PAGE INTENTIONALLY BLANK HCGS-UFSAR Revision 1 April 11, 1989

3.9.3.4.6 Non-NSSS Component Supports Piping supports are designed in accordance with Article 3000 of Subsection NF of the ASME B&PV Code, Section III. In general, the loading combinations for supports for ASME B&PV Code Class 1, 2, and 3 components, categorized with respect to plant operating conditions identified as normal, upset, emergency, and faulted are given in Table 3.9-20. The stress limits are those given in Article 3000 of Subsection NF of the ASME B&PV Code, Section III, 1974 Edition, including Addenda through Winter of 1975. In addition, the design of such supports also conforms to Subsection NF-3280, NF-3290, N~-3380, and NF-3390 of Section III of the ASME B&PV Code, 1980 Edition. The nondestructive examination of welds for NF support elements shall be performed using the requirements noted in Subsection NF-5200 of Section III of the ASME B&PV Code, 1977 Edition, including Addenda through Winter of 1978. For component supports of essential systems, emergency stress limits are used in lieu of the faulted condition limits. This is to ensure that, under all loading conditions, their stresses are contained within the yield stress. The allowable stress limits used for bolting in equipment anchorage and in pipe support components is 0.5 Su but shall not exceed 0.9 Sy under all service levels. For flanged connections, the bolt allowable stress used in the piping analysis is ASME Subsection III, 1979 Summer Addenda, Subsections NB, NC, and ND for Classes 1, 2 and 3, respectively. The capacities of concrete expansion anchors are based on actual testing of anchors to failure. The failure loads are divided by the factor of safety (typically 4 in accordance with NRC Bulletin 79-02) to establish the allowable design loads. Baseplate flexibility is considered in the design of concrete expansion anchor bolts in accordance with IE Bulletin 79-02. 3.9-135 HCGS-UFSAR Revision 1 April 11, 1989

3.9.3.4.6.1 Snubbers Snubbers are used in Seismic Category I & II systems. For both inside and outside primary containment, snubbers are of the mechanical and hydraulic type. The mechanical snubbers are purchased from Pacific Scientific Corporation and hydraulic snubbers from Lisega with loading ratings appropriate for the design conditions and load combinations. The snubbers are designed in accordance with ASME B&PV Code, Section III, Subsection NF (see Table 3.2.-3). The effective stiffness of the snubber is considered in evaluating the piping system response. A summary of the types and sizes of snubbers at HCGS is provided in the ISI Snubber Tracking Program. Functional tests for hydraulic and mechanical snubbers are required: The snubber functional test shall verify that: (1) Activation (restraining action) is achieved within the specified range in both tension and compression; ( 2) Snubber in bleed, or release rate where required, is present in both tension and compression, within the range (hydraulic snubbers only); (3) For mechanical snubbers, the force required to initiate or maintain motion of the snubber is within the specified range in both directions of travel; and (4} For snubbers specifically required not to displace under continuous load, the ability of the snubber to withstand load without Technical Specification LCO 3. 0. 8 allows snubbers to be inoperable without declaring the affected supported LCO(s) not met for 72 hours if the inoperable snubber affects one or 12 hours if it affects subsystems. The following Tier 2 restrictions from Reference 3.9-29 apply to the use of LCO 3.0.8 and have been incorporated into the TS Bases: 3.9-136 HCGS-UFSAR Revision 18 May 10, 2011

1. For BWR plants, one of the following two means of heat removal must be available when LCO 3.0.8a is used:

• At least one high pressure makeup path {e.g., using high pressure coolant ection (HPCI) or reactor core isolation cooling (RCIC) or equivalent) and heat removal capability (e.g.,

suppression pool cooling), including a minimum set of supporting equipment required for success, not associated with the inoperable snubber(s), or

• At least one low pressure makeup path (e.g., low pressure coolant injection (LPCI) or core spray ( CS) ) and heat removal capability(e.g., suppression pool cooling or shutdown cooling),

including a minimum set of supporting equipment required for success, not associated with the inoperable snubber(s).

2. When LCO 3.0.8b is used at BWR , it must be verified that at least one success path exists, using equipment not associated with the inoperable snubber(s), to provide and core cooling needed to LOOP accident sequences.

3. Every time the provisions of LCO 3.0.8 are used licensees will be required to confirm that at least one train (or subsystem) of systems supported by the inoperable snubbers would remain capable of performing their required safety or support functions for postulated design loads other than seismic loads. LCO 3.0.8 does not apply to non-seismic snubbers. In addition, a record of the function of the inoperable snubber (i.e., seismic vs. non-seismic), implementation of any applicable Tier 2 restrictions, and the associated plant configuration shall be available on a recoverable basis for staff inspection.

LCO 3.0.8 only to snubber support functions that are seismic related. In OPERATIONAL CONDITIONS 4 and 5, snubbers only perform seismic functions. In OPERATIONAL CONDITIONS 1, 2, and 3, some snubbers also perform non-seismic support functions (e.g., hydrodynamic loads, turbine trip loads, etc.) . When LCO

3. 0. 8 is used, confirm that at least one train (or subsystem) of systems supported by the snubbers would remain capable of performing their or support functions for postulated design loads other than seismic loads.

3.9-137 HCGS-UFSAR Revision 18 May 10, 2011

3.9.3.5 SRP Rule Review Acceptance Criterion II.l, of SRP Section 3.9.3, requires that the combination '-' of design and service loadings applicable to the design of Class 1, 2 and 3 components be in agreement with positions stated in Appendix A of SRP Section 3.9.3. At HCGS, Appendix A was not used as a design basis requirement. However, Bechtel used representative industry practice at the time of design, procurement, and manufacturing, and is in agreement with the general intent of this appendix. The actual loading combinations are specified in the component purchase specifications. 3.9.4 control Rod Drive System This plant is equipped with a hydraulic Control Rod Drive (CRD) system. The discussion in this section includes the CRDs, the hydraulic control units (HCUs), the condensate Supply System, and the scram discharge volume and extends to the coupling interface with the control rods. 3.9.4.1 Desgriptive Information on the Control Rod Drive Descriptive information on the CRDs, as well as the entire control and drive system, is contained in section 4.6. 3.9.4.2 Applicable Control Rod Drive System Desian Specifications The CRD system is designed to meet the functional design criteria outlined in section 4.6 and consists of the following:

1. Locking piston eROs

2. HCUs 3.9-138 HCGS-UFSAR Revision 8 September 25, 1996

3. Hydraulic power supply (pumps)

4. Interconnecting piping

5. Flow and pressure control valves

6. Instrumentation and electrical controls.

Those components of the CRD forming part of the reactor coolant pressure boundary are designed in accordance with the ASME B&PV Code, Section III. The quality group classification of the CRD hydraulic system is outlined in Table 3.2-1. The components are designed in accordance with the codes and standards governing the individual quality groups. Quality group classification is not applicable to the nonpressurized parts of the CRDs. Pertinent aspects of the design and qualification of the CRD components are discussed in the following sections: transients in Section 3.9.1.1, faulted conditions in Section 3.9.1.4, seismic testing in Section 3. 9. 2. 3, and loading combinations and stress limits in Table 3.9-4w. 3.9.4.3 Design Loads. Stress Limits. and Allowable Peformations The ASME B&PV Code, Section III components of the CRDs have been evaluated analytically. The design load combinations and stress limits are listed in Table 3. 9-4w. For the non-Code components, experimental testing is used to determine the CRD performance under all possible conditions, as described in Section 3.9.4.4. Deformation has been compared with the allowable limits, and is not a controlling factor, based upon numerous tests performed on CRDs. 3.9-139 HCGS-UFSAR Revision 0 April 11, 1988

3.9.4.4 Control Rod Drive System Performance Assurance Program The CRD system test program consists of the following tests:

1. Development tests

2. Factory quality control tests

3. Five-year maintenance life tests

4. l.SX design life tests

5. Operational tests

6. Acceptance tests

7. Surveillance tests.

All of the above tests. except 3. and 4., are discussed in Section 4.6.3. Tests 3. and 4. are discussed below: Test 3. Five-Year Maintenance Life Tests Four CRDs are normally picked at random from the production stock each year and subjected to various tests under simulated reactor conditions and approximately one-sixth of the cycles specified in Section 3.9.1.1. Upon completion of the test program, the CRDs must meet, or surpass, the minimum specified performance requirements. Test 4. l.SX Design Life Tests

    'When a significant design change is made to the components of the CRD. the CRD is subjected to a series of tests equivalent to 1.5 times the life test cycles specified in Section 3.9.1.1.

3.9-140 HCGS-UFSAR Revision 0 April 11, 1988

Two CRDs underwent such testing in 1976. Upon completion of the test program, these CRDs met or surpassed the minimum specified performance requirements. 3.9.5 Reactor Pressure Vessel Internals This section identifies and discusses the structural and functional integrity of the major re~ctor pressure vessel (RPV) internals. 3.9.5.1 Desien Arrangements The core support structures and RPV internals (exclusive of fuel, control rods, control rod drives (CRDs), and in-core nuclear instrumentation) are identified below: la. Core support structures

a. Shroud

b. Shroud support {cylinder, plate, and legs)

c. Core plate and holddown bolts

d. Top guide

e. CRD housings

f. Fuel supports

g. Control rod guide tubes.

2. Reactor internals

a. Feedwater spargers

b. Initial startup neutron sources 3.9-141 HCGS-UFSAR Revision 0 April 11, 1988

c. Surveillance sample holders

d. In-core instrument housings

e. Steam dryer assembly

f. Shroud head and steam separator assembly

g. Guide rods

h. Jet pump assemblies and instrumentation

i. Deleted

j. Core plate differential pressure sensing lines

k. In-core flux monitor guide tubes

1. Core spray lines and spargers

m. Low pressure coolant injection (LPCI) lines

n. CRD thermal sleeves.

A general assembly drawing of the important reactor components is shown on Figure 3.9-2. The floodable inner volume of the RPV is shown on Figure 3.9-3. This is the volume inside the core shroud up to the level of the jet pump suction inlet. The design arrangement of the reactor internals, such as the jet pumps, steam separators, and guide tubes, is such that one end is unrestricted and thus free to expand. HCGS-UFSAR 3.9-142 Revision 14 July 26, 2005

The LPCI lines include couplings with slip joint sleeves to allow free thermal expansion. 3.9.5.1.1 Core Support Structures The core support structures consist of those items listed in Section 3.9.5.l.a. These structures form partitions within the reactor vessel, to sustain pressure differentials across the partitions, to direct the flow of coolant, and to laterally locate and support the fuel assemblies. Figure 3. 9-3 shows the reactor vessel internal flow paths. 3.9.5.1.1.1 Shroud The stainless steel shroud with shroud support makes up a cylindrical assembly that provides a partition to separate the upward flow of coolant through the core from the downward recirculation flow. This partition separates the core region from the downcomer annulus, thus providing a floodable region following a recirculation line break. The volume enclosed by this assembly is characterized by three regions. The upper portion surrounds the core discharge plenum, which is bounded by the shroud head on top and the .top guide grid below. The central portion of the shroud surrounds the active fuel and forms the longest section of the assembly. This section is bounded at the top by the top guide grid and at the bottom by the core plate. The lower portion, surrounding part of the lower plenum, is welded to the RPV shroud support. 3.9.5.1.1.2 Shroud Support The shroud support is furnished as a completed assembly by the RPV manufacturer and is designed, analyzed,. and built as an integral part of the RPV. The shroud support is designed to support the shroud and to support and locate the jet pumps. The shroud support provides an annular baffle between the RPV and the shroud. The jet 3.9-143 HCGS-UFSAR Revision 0 April 11, 1988

pump discharge diffusers penetrate the shroud support to introduce the coolant to the inlet plenum below the core. The loading conditions, stress criteria, and calculated and allowable stresses are summarized in Table 3.9-4b. 3.9.5.1.1.3 Core Plate The core plate . is a circular stainless steel plate with bored holes, which is stiffened with a rim and beam structure. The plate provides lateral support and guidance for the control rod guide tubes, in-core flux monitor guide tubes, peripheral fuel supports, and startup neutron sources. The last two items are also supported vertically by the core plate. The entire assembly is bolted to a support ledge on the lower portion of the shroud. 3.9.5.1.1.4 Top Guide The top guide is formed by a series of stainless steel beams joined at right angles to form square openings and fastened to a peripheral rim. Each opening provides lateral support and guidance for four fuel assemblies or, in the case of peripheral fuel, for less than four fuel assemblies. Sockets are provided in the bottom of the beam intersections to anchor the in-core flux monitors and the startup neutron sources. The rim of the top guide rests on a ledge between the upper and central portions of the shroud. The top guide has alignment pins that engage and bear against slots in the shroud that are used to correctly position the assembly before it is secured. Lateral restraint is provided by wedge blocks between the top guide and the shroud wall. The loading conditions, stress criteria, and calculated and allowable stresses are summarized in Table 3.9-4c. 3.9-144 HCGS-UFSAR Revision 0 April 11, 1988

3.9.5.1.1.5 Fuel Supports The fuel supports, shown on Figure 3.9-4, are of two basic types; namely, peripheral fuel supports, and four-lobed orificed fuel supports. The peripheral fuel supports are located at the outer edge of the active core and are not adjacent to control rods. Each peripheral fuel support holds one fuel assembly and contains a single orifice assembly designed to ensure proper coolant flow to the peripheral fuel assembly. Each four lobed orificed fuel support holds four fuel assemblies and is provided with four orifice plates to ensure proper coolant flow distribution to each rod controlled fuel assembly. The four lobed orificed fuel supports rest in the top of the control rod guide tubes, which are supported laterally by the core plate. The control rods pass through slots in the center of the four-lobed orificed fuel support. A control rod and the four adjacent fuel assemblies represent a core cell. See Section 4.2. 3.9.5.1.1.6 control Rod Guide Tubes The control rod guide tubes, located inside the vessel, extend from the top of the CRD housings up through holes in the core plate. Each tube is designed as the guide for a control rod, as well as being the vertical support for a four lobed orificed fuel support and the four fuel assemblies surrounding the control rod. The bottom of the guide tube is supported by the CRD housing, which in turn transmits the weight of the guide tube, fuel support, and fuel assemblies to the reactor vessel bottom head. A thermal sleeve is inserted into the CRD housing from below and is rotated to lock the control rod guide tube in place. A key is inserted into a locking slot in the bottom of the CRD housing to hold the thermal sleeve in position. 3.9.5.1.2 Reactor Internals The reactor internals consist of those items listed in Section 3.9.S.l.b. Those that involve coolant flow paths are described in the following paragraphs. ~. 3.9-145 HCGS-UFSAR Revision 0 April 11, 1988

3.9.5.1.2.1 Jet Pump Assemblies The pump assemblies are located in two semicircular groups in the downcomer annulus between the core shroud and the RPV wall. The design and performance of the jet pumps are discussed in References 3.9-14 and 3.9-15. Each stainless steel jet pump consists of a driving nozzle, a suction inlet, a throat or mixing section, and a diffuser, as shown on Figure 3.9-5. The driving nozzle, suction inlet, and throat are joined together as a removable unit, and the diffuser is permanently installed. High-pressure water from the recirculation pumps is supplied to each pair of jet pumps through a riser pipe welded to the recirculation inlet nozzle thermal sleeve. A riser brace consists of cantilever beams welded to a riser pipe and to pads on the RPV wall. The nozzle entry section is connected to the riser by a metal to metal, spherical to conical seal joint. Firm contact is maintained by a holddown clamp. The throat section is supported laterally by a bracket attached to the riser. There is a slip fit joint between the throat and diffuser. The diffuser is a gradual conical section changing to a straight cylindrical section at the lower end. The preload on the hold down beams will be reduced from 30 to 25 kips in accordance with General Electric recommendations. This will increase the expected life of the beams to 19-40 years. The need for inservice inspection will be based on a lead plant experience and GE testing, and will be conducted such that any initiation will be detected prior to beam failure. Repairs were made to Jet Pumps 8, 9 and 15 where cracks have been found in the welds that attach the jet pump flow instrument pressure sensing lines to brackets on the jet pump diffusers. The repair involves installation of a semi-circular clamp on each jet pump diffuser to hold the sensing line against the jet pump. Consequently, the clamp in effect augments or replaces the function of the weld attachment. A repair was made to Jet Pump 16 where excessive gap was found at the vessel side setscrew. The repair involved installation of auxiliary spring wedge assembly against the jet pump. This assembly functionally replaces the restrainer bracket setscrew and re-establishes the lateral three-point support. In addition, on Jet Pump 9, the shroud side setscrew tack welds were found cracked. This setscrew was staked to prevent back but of the setscrew and an auxiliary spring wedge assembly was installed in case a gap developed at the setscrew location. 3.9-146 HCGS...;.UFSAR Revision 17 June 23, 2009

3.9.5.1.2.2 Steam Dryer Assembly The steam dryer removes moisture from the wet steam leaving the steam separators. The extracted moisture flows down the vanes to the collecting troughs, and then flows through tubes into the downcomer annulus. A skirt extends from the bottom of the dryer vane housing to the steam separator standpipe 1 below the water level. This skirt forms a seal between the wet steam plem.un and the dry steam flowing from the top of the dryer .to the st.eam outlet nozzles. The steam dryer and shroud head are positioned in the vessel installation with the aid of vertical guide rods. The dryer assembly rests on steam support brackets attached to the RPV wall. Upward movement of the dryer assembly, which may occur under accident conditions, is restricted by steam dryer holddown brackets attached to the RPV top head. 3.9.5.1.2.3 Feedwater Spargers The feedwater spargers are stainless steel headers located in the mixing plenum above the downcomer annulus. A sparger is fitted to each feedwater nozzle and is shaped to conform to the curve of the vessel wall. To conform with NUREG*-0619 the design of the feedwater nozzles and spargers follow the issue resolution in Reference 3.9-17. Sparger end brackets are pinned to vessel brackets to support the spargers. Feedwater flow enters the center of the spargers and is discharged radially inward, mixing the cooler feedwater with the downcomer flow from the steam separators and steam before it contacts the vessel wall. The feedwater also serves to condense the steam in the above the downcomer annulus and to subcool the water flowing to the jet pumps and recirculation pumps.

3. 9. 5: 1. 2. 4, Core Spray Lines and Spargers The core spray lines and spargers distribute coolant to the reactor core during accident conditions. Two core spray lines enter the reactor vessel the two core spray nozzles. The lines divide inside the reactor vessel. The two halves are routed to 3.9-147 HCGS-UFSAR Revision 16 May 15, 2008

opposite sides of the reactor vessel and are supported by clamps attached to the vessel wall. The lines are then routed downward into the downcomer annulus, passing through the upper shroud immediately below the flange. The flow divides again as it enters the center of the semicircular sparger, which is routed halfway around the inside of the upper shroud. The two spargers are supported by brackets designed to accommodate thermal expansion. The line routing and supports are designed to accommodate. differential movement between the shroud and vessel. The other care spray line is identical, except that it enters the opposite side of the vessel, and the spargers are at a slightly different elevation inside the shroud. The correct spray distribution pattern is provided by a combination of distribution nozzles pointed radially inward and downward from the spargers. 3.9.5.1.2.5 Deleted 3.9.5.1.2.6 Core Plate Differential Pressure sensing Lines These lines are used to sense the differential pressure across the core plate. The lines enter the reactor vessel at a point below the 3.9-148 HCGS-UFSAR Revision 14 July 26, 2005

core shroud as two concentric lines. In the lower plenum, the two lines separate. The inner line terminates near the lower shroud, below the core plate. It is used to sense the pressure below the core plate during normal operation. The outer line terminates immediately above the core plate and senses the pressure in the region outside the fuel assemblies. 3.9.5.1.2.7 In-core Flux Monitor Guide Tubes These guide tubes provide a means of positioning fixed detectors in the core, as well as providing a path for calibration monitors of the Traversing In-core Probe {TIP) System. The in-core flux monitor guide tubes extend from the top of the in-core flux monitor housings in the lower plenum to the top of the core plate. The power range detectors for the power range monitoring units. and the dry tubes for the source range monitoring {SRM) and intermediate range monitoring (IRK) detectors, are inserted through the guide tubes. A latticework of clamps, tie bars, and spacers gives lateral support and rigidity to the guide tubes. The bolts and clamps are welded, after assembly, to prevent loosening during reactor operation. 3.9.5.1.2.8 Surveillance Sample Holders The surveillance sample holders are welded baskets containing impact and tensile specimen capsules. The baskets hang from the brackets that are attached to the inside wall of the RPV and extend to mid height of the active core. The radial positions are chosen to expose the specimens to the same environment and maximum neutron fluxes experienced by the RPV itself, while avoiding jet pump removal interference or damage. 3.9-149 HCGS-UFSAR Revision 0 April 11, 1988

3.9.5.1.2.9 Shroud Head and Steam Separator Assembly The shroud head and steam separator assembly is bolted to the top of the shroud, forming the top of the core discharge plenum. This plenum provides a mixing chamber for the steam water mixture before it enters the steam separators. Individual, stainless steel, axial flow steam separators are attached to the top of standpipes that are welded into the shroud head. The steam separators have no moving parts. In each separator, the steam water mixture rising through the standpipe passes vanes that impart a spin that establishes a vortext separating the water from the steam. The separated water flows from the lower portion of the steam separator into the downcomer annulus. 3.9.5.1.2.10 Low Pressure Coolant Injection Lines The LPCI lines penetrate the core shroud through separate LPCI nozzles. Coolant is discharged inside the core shroud. 3.9.5.2 Desizn Loadin& Conditions 3.9.5.2.1 Events to be Evaluated Examination of the spectrum of conditions for which the safety design basis must be satisfied, by core support structures and other engineered safety feature (ESF) reactor internals, reveals three significant faulted events:

1. Recirculation line break accident A break in a recirculation line between the RPV and the recirculation pump suction

2. Steam line break accident - A break in one main steam line between the RPV and the flow restrictor, resulting in significant pressure differentials across some of the structures within the reactor 3.9-150 HCGS-UFSAR Revision 0 April 11, 1988

3. Earthquake Subjects the core support structures and reactor internals to significant forces as a result of ground motion.

Analysis of other conditions existing during normal operation, abnormal operational transients, and accidents shows that the loads affecting the core support structures and other ESF reactor internals are less severe than these three postulated events. The faulted conditions for the RPV internals are discussed in Section 3. 9. 1. 4. Loading combinations and analyses for the RPV internals are discussed in Section 3.9.3.1 and Tables 3.9-1 and 3.9.5.2.2 Pressure Differential During Rapid Depressurization A digital computer code is used to analyze the transient conditions within the RPV following the recirculation line break accident and the steam line break accident. The analytical model of the vessel consists of nine nodes, connected to the necessary adjoining nodes by flow paths having the required resistance and inertial characteristics. The program solves *the energy and mass conservation equations for each node, giving the depressurization rates and pressures in the various regions of the reactor. Figure 3.9-6 shows the nine reactor nodes. The computer code used is *the GE Short-Term Thermal-Hydraulic Model described in Reference 3.9-16. This model has been approved for use in Emergency Core Cooling System {ECCS) conformance evaluation under 10CFR50, Appendix K. To adequately describe the blowdown pressure effect on the individual assembly components, three features are included in the model that are not applicable to the ECCS analysis and are, therefore, not described in Reference 3.9-16. These additional features are discussed below:

1. The liquid level in the steam separator region and in the annulus between the steam.dryer skirt and the vessel wall 3.9-151 HCGS-UFSAR Revision 0 April 11, 1988

is tracked to more accurately determine the flow and mixture quality in the steam dryer and in the steam line.

2. The flow path between the bypass region and the shroud head is more accurately modeled since the fuel assembly pressure differential is influenced by flashing in the guide tubes and in the bypass region for a steam line break. In the ECCS analysis, the momentum equation is solved in this flow path, but its irreversible loss coefficient is conservatively set at an arbitrary low value.

3. The enthalpies in the guide tubes and in the bypass region are calculated separately since the fuel assembly pressure differential is influenced by flashing in these regions.

In the ECCS analysisj these regions are lumped. 3.9.5.2.3 Recirculation Line and Steam Line Break 3.9.5.2.3.1 Accident Definition Both a recirculation line break (the largest liquid line break) and a main steam line break (the largest steam line break) are considered in determining the design basis accident (DBA) for the ESF reactor internals. The recirculation line break is the same as the design basis loss-of-coolant accident (LOCA) described in Section 6.3. A sudden, complete, circumferential break is assumed to occur in one recirculation loop. The pressure differentials on the reactor internals and core support structures are in all cases lower than for the main steam line break. The analysis of the steam line break assumes a sudden, complete, circumferential break of one main steam line between the RPV and the main steam line flow restrictor. A steam line break upstream of the flow restrictors produces a larger blowdown area, and thus a HCGS-UFSAR Revision 0 April 11, 1988

faster depressurization rate, than a break downstream of the restrictors. The larger blowdown area results in greater pressure differentials across the reactor internal structures. The steam line break accident produces significantly higher pressure differentials across the reactor internal structures than does the rec'irculation line break. This results from the higher reactor depressurization rate associated with the steam line break. Therefore, the steam line break is the design basis for internal pressure differentials. 3.9.5.2.3.2 Effects of Initial Reactor Power and Core Flow The maximum internal pressure loads can be considered to be composed of two parts: steady state and transient pressure differentials. For a given plant, the core flow and power are the two major factors that influence the reactor's internal pressure differentials. The core flow essentially affects only the steady state part. For a fixed power, as the core flow increases, so do the steady state pressure differentials. The core power affects both. the steady~state and the transient parts. As the power is decreased, there is less voiding in the core, and consequently the steady state core pressure differential is less. However, less voiding in the core also means that less steam is generated in the RPV and the depressurization rate and the transient part of the maximum pressure load is thus increased. As a result, the total loads on some components are higher at low power. To ensure that the calculated pressure differentials bound those that could be expected if a steam line break should occur, an analysis is conducted at a low power, high recirculation flow condition, in addition to the standard safety analysis condition at a high power, rated recirculation flow condition. The power chosen for analysis is the minimum. value permitted by the recirculation system controls at rated recirculation drive flow, i.e. , the drive flow necessary to achieve rated core flow at rated power. 3.9-153 HCGS-UFSAR Revision 0 April 11, 1988

This condition maximizes those loads that are inversely proportional to power. It must be noted that this condition, while possible, is unlikely, because the reactor generally operates at or near full power, and because high core flow is neither required, nor desirable, at such a reduced power condition. 3.9.5.2.4 Earthquake The seismic loads acting on the structures within the RPV are based on a dynamic analysis, as described in Section 3. 7. The seismic analysis is performed by coupling the lumped mass model of the RPV and internals, as described in Section 3. 7, with the building model, to determine the system natural frequencies and mode shapes. The acceleration and load response are then determined by either the time history method or the response spectrum method. In the time history method, the dynamic response is determined for each mode of interest and added algebraically for each instant of time. Resulting response time histories are then examined, and the maximum value*s of acceleration, shear, and moment are used for **._I design calculations. In the response. spectrum method, the accelerations, shea~s, and moments are determined for each mode of interest. The square roots of the sum of the squares (SRSS) of these individual responses are then used for design calculations. The detailed descriptions of the earthquake analysis are given in Section 3.7. The detailed description of the dynamic response analysis to these forcing functions is given in Section 3.9.2.5. 3.9-154 HCGS-UFSAR Revision 0 April 11, 1988

3.9.5.3 Desi&n Bases 3.9.5.3.1 Safety Design Bases The reactor core support structures and internals meet the following safety design bases:

1. They are arranged to provide a floodable volume, in which the core can be adequately cooled in the event of a breach in the nuclear system process barrier external to the RPV

2. Deformation is limited to ensure that the control rods and the ECCS can perform their safety functions

3. Mechanical design of applicable structures ensures that safety desigri bases 1. and 2., above. are satisfied, so that safe shutdown of the plant and removal of decay heat are not impaired.

3.9.5.3.2 Power Generation Design Bases The reactor core support structures and internals are designed to the following power generation design bases:

1. They provide the proper coolant distribution during all anticipated normal operating conditions, up to full power operation of the core, without fuel damage

2. They are arranged to facilitate refueling operations

3. They are designed to facilitate inspection.

3.9-155 HCGS-UFSAR Revision 0 April 11, 1988

3.9.5.3.3 Design Loading Categories Loading combinations for the core support structures are shown in Table ~.9*5. The basis for determining faulted loads on the reactor internals is shown for seismic loads in Section 3. 7, and for pipe rupture loads in Sections 3.9.5.2.3 and 3.9.5.3.4. Table 3.9-4c shows loading combinations, analytical methods, and allowable and calculated stress values for highly stressed areas of selected reactor internal components. Table 3.9-4aa provides this same type of information for the control rod guide tubes. The stress limits for core support structures and other ESF reactor internals are consistent with the ASME B&PV Code, Section III, Subsection NA-2140, and associated stress limits contained in ASME Addenda dated through Summer 1976. Level A, B, C, and D service limits defined in the ASME Winter 1976 Addenda (which replace normal, upset, emergency, and faulted condition limits) are not reflected in design documents for core support structures and other ESF reactor internals for this reactor. However, for these components, level A, B, C, and D service limits are judged to be equivalent to the normal, upset, emergency, and faulted loading condition limits. Therefore, for clarity, both sets of nomenclature are retained herein. Stress intensity and other design limits are discussed in Sections 3.9.5.3.5 and 3.9.5.3.6. The core support structures that are fabricated as part of the RPV assembly are discussed in Section 3.9.3.1.2. Subsection NG of Section III of the ASME B&PV Code was not issued at the time the core support structures for this plant were designed. The criteria presented in Section 3. 9. 5. 3.6 were used in lieu of Subsection NG. 3.9-156 HCGS-UFSAR Revision 0 April 11, 1988

The design requirements for equipment classified as "other i.e., non-ESF, internals" e. g., steaDl dryer and shroud head, are specified by the designer with appropriate consideration of the intended service of the equipment and the expected plant and environmental conditions under which it operates. Where possible, design requirements are based on applicable industry codes and standards. If these are not available, the designer relies on accepted industry or engineering practices. Section 3.9.5.3.5 presents criteria for the ESF reactor internals. 3.9.5.3.4 Response of Internals Due to Steam Line Break Accident The maximum pressure loads acting on the reactor internal components result from a steam line break upstream of the flow restrictor. On some components, the loads are maximum when operating at the minimum power associated with the maximum core flow. This has been substantiated by the analytical comparison of liquid line versus steam line breaks and by the investigation of the effects of core power and core flow. It has also been pointed out that, altt:'ough possi-ble, it is not probable that the reactor would be operating at minimum power and maximum core flow. More realistically, the reactor would be at ot ne.ar a full power condition, resulting in a lessening of the maximum pressure loads acting on the internal components. 3.9.5.3.5 Stress, Deformation, and Fatigue Limits for Engineered Safety Feature Reactor Internals (Except Core Support Structure) The stress, deformation, and fatigue criteria listed in Tables 3.9-21, 3.9-22 3.9-23, and 3.9-24 are used as design limits for the ESF reactor internals. Other criteria established by applicable codes and standards for similar equipment, by manufacturers' standards, or by empirical methods based on field 3.9-157 HCGS-UFSAR Revision 0 April 11, 1988

experience and testing may also be used. For the quantity SF . (minimum mln safety factor) appearing in the tables, the following values are used: Service Design SF , mln Level Condition A Normal 2.25 B Upset 2.25 c Emergency 1.5 D Faulted 1.125 Components inside the RPV, such as control rods, that must move during an accident condition, have been examined for adequate clearances during emergency and faulted conditions. No mechanical clearance problems have been identified. The forcing functions applicable to the reactor internals are discussed in Section 3.9.2.5. 3.9.5.3.6 Stress, Deformation, and Fatigue Limits for Core Support Structures Stress, deformation, and fatigue criteria discussed in Section 3. 9. 5. 3. 3 and presented in Table 3.9-4 are used as design limits for the core support structures. These criteria are supplemented, where applicable, by the criteria for the reactor internals in Section 3.9.5.3.5. However, in no case are the criteria presented in Table 3. 9-4 exceeded in the design of the core support structures. 3.9.5.4 SRP Rule Review 3.9.5.4.1 Acceptance Criterion II.b Acceptance Criterion II. b of SRP Section 3. 9. 5 provides that the design and construction of the core support structures should conform to the requirements of the ASME B&PV Code, Section III, Subsection NG. 3.9-158 HCGS-UFSAR Revision 17 June 23, 2009

The HCGS core support structures were designed and purchased in 1971, prior to the 197 4 issue of Subsection NG of the ASME B&PV Code. However, during the design of the HCGS core supports, an earlier draft of the ASME B&PV Code, Section III, Subsection NB was used as a guide in developing the design criteria. These criteria are presented in Section 3.9.5.3. Subsequent to the issuance of Subsection NG of the Code, comparisons were made to assure that the pre-NG design meets the equivalent level of safety as presented by Subsection NG. 3.9.5.4.2 Acceptance Criterion !I.e Acceptance Criterion II.c of SRP Section 3.9.5 provides that the design basis for reactor internals should meet guidelines of the ASME B&PV Code, Section III, Subsection NG-3000, and should not adversely affect the integrity of core support structures, as described in Subsection NG-1122 of the ASME B&PV Code, Section III. Guidelines similar to Subsection NG-3000 of the ASME B&PV Code, Section III were used in the design of the reactor internals because Subsection NG-1122 was not written at the time the HCGS reactor internals were procured and designed. As part of a generic study, assurance was obtained to demonstrate that failure of the nonsafety-related or nonsafety-graded reactor internals will not impair the function of other safety-related reactor internals. 3.9.5.5 Steam Dryer Structural Integrity A plan of steam dryer monitoring, evaluation and inspection is established as part of the implementation of License Amendment No. 17 4. The three main elements of the plan related to steam dryer structural integrity are: (1) a slow and deliberate power ascension with defined hold points and durations; {2) a detailed power ascension monitoring and analysis program to trend steam dryer performance; and (3) a long term inspection/monitoring program to verify steam dryer performance at EPU conditions. I 3.9-159 HCGS-UFSAR Revision 17 June 23, 2009

3.9.5.5.1 Power Ascension Power above 3,339 MWt is initially increased at a rate of about 1 percent of 3, 339 MWt per hour. Main steam line (MSL} strain gage and accelerometer vibration data are collected hourly during power ascension. At every 2. 5 percent of 3, 339 MWt step, MSL strain gage and accelerometer data 1 reactor pressure vessel water level instrumentation, and moisture carryover data, are evaluated against acceptance criteria. At every 5 percent CLTP plateau, the data is evaluated against the acceptance criteria; plant walkdowns are conducted; and information is forwarded to the NRC. The durations of certain hold points are defined in the Facility Operating License. For all other hold points, the duration is determined by the time required to obtain the specified data, complete the evaluation, and obtain the required level of approval to proceed. 3.9.5.5.2 Power Ascension Monitoring and Analysis Level 1 and Level 2 acceptance criteria is established for MSL strain gage and accelerometer data and for moisture carryover data, where Level 1 requires that power be reduced to a previous acceptable level and Level 2 requires that power be held at that level with a re-evaluation of the data. The Level 1 limit curves for MSL strain gages are based on not exceeding the ASME allowable alternating stress value on the dryer's limiting component. The 'Level 2 limit curves are based on not exceeding 80 percent of the allowable alternating stress value on the dryer. MSL strain gage limit curves are developed as follows:

• Collect in-plant MSL strain gage data.
• Calculate the stress ratio at the limiting steam dryer locations (loads are based on Acoustic Circuit Model (ACM) Rev. 4, and stresses are determined using the HCGS harmonic domain finite element model methodology}.
• Generate revised limit curves based on the lowest calculated alternating stress ratio.

Reference 3.9-28 provides greater detail on the methodology for developing the strain gage limit curves including the NRC-accepted biases and uncertainties that must be applied. 3.9-160 HCGS-UFSAR Revision 17 June 23, 2009

3.9.5.5.3 Long Term Inspection/Monitoring Station operating procedures are used to monitor operating moisture carryover conditions. Results are reviewed I evaluated on a defined basis to monitor moisture carryover conditions. Steam dryer inspections are tracked, planned, and scheduled via normal commitment and planning processes already in place at the station. Steam dryer inspections and monitoring of plant parameters potentially indicative of steam dryer failure are conducted as recommended in Electric Power Research Institute (EPRI) Technical Report 1011463, "BWR Vessel and Internals Project, Steam Dryer Inspection and Flaw Evaluation Guidelines (BWRVIP-139) ." 3.9.6 Inservice Testing of Pumps and Valves Inservice testing of certain safety-related pumps and valves is accomplished in accordance with the requirements of 10CFR50, Appendix A, GDC 37, 40, 43, 46, 54, and 10CFR50.55a(g), using the date of commercial operation for determining the test interval. The design includes access provisions for pre-service operational readiness testing of valves that comply, at the minimum, with the 1974 ASME B&PV Code, Section XI, with Addenda through Summer 1975. The pumps and valves that require testing and the tests performed are determined in accordance with the 1983 ASME B&PV Code, Section XI, with Addenda through Summer 1983 (hereafter referred to as ASME XI, 83S83), Subsections IWP and IWV, to the extent practical. Tests conducted during each 120-month inspection interval comply with the requirements of the latest edition and addenda of the ASME B&PV Code incorporated or modified by reference in 10CFR50.55a, 12 months prior to the start of the 120-month inspection interval. The testing program verifies that the pumps and valves required for safety remain in a state of operational readiness to perform their safety-related functions throughout the lifetime of the plant. HCGS-UFSAR 3.9-160a Revision 17 June 23, 2009 I

Pumps required for safety, and provided with an emergency power source, are inservice tested, where applicable, in agreement with the requirements of the ASME B&PV Code, Section XI, Article IWP-1000. The reference values and periodic testing schedule for the inservice testing program are derived in accordance with the inservice testing procedures of IWP-3000. The surveillance requirements are defined by the Inservice Testing Program, as described in Section 6. 0 of the Technical Specifications. Methods of measuring reference values and inservice values for pump parameters are in agreement with IWP-4000. 3.9-160b HCGS-UFSAR Revision 21 November 9, 2015

The pump test schedule, test method, and procedures for testing are presented separately from the FSAR in the HCGS inservice pump testing program. See Reference 3.9-22 for the Hope Creek IST program. 3.9.6.2 Inseryice Testin& of Valyes The inservice testing programs for valves whose function is required for safety are in the valve testing list, as required by IYV-1100. The program does not include those valves exempted by IWV-1200. The valves required to be tested in accordance with the rules of Subsection IWV are listed by type, identification number. ASME B&PV Code Class, and Section XI, Article IW-2000 valve category. The initial periodic inservice valve testing complies with the provisions of IWV-3000 of ASME XI, 83883. Included in the valve testing list are valves in the normal or alternate flow path of the main process piping of systems required for safety. These valves are not required to change position to perform their safety-related function and are included in the list for administrative control to verify valve position quarterly or each time the valve is cycled. The valve testing list and relief requests for valve testing are presented separately from the FSAR in the HCGS inservice valve testing program. See Reference 3.9-22 for the Hope Creek IST program. See Reference 3.9-23 regarding leak rate testing reactor coolant boundary valves at Hope Creek. 3.9.6.3 Relief Request Where pump or valve testing proves to be impractical to meet the requirements of the inservice testing program of the ASHE B&PV Code, Section XI, relief requests are submitted on a case by case basis to the NRC staff for review and approval. 3.9-161 HCGS-UFSAR Revision 4 April 11, 1992

3.9.7 References 3.9-1 General Electric, "PISYS Analysis of NRC Benchmark Problems," NED0-24210, August 1979.

3. 9-2 "Pressure Vessel and Piping 1972 Computer Programs Verification," The American Society of Mechanical Engineers.

3.9-3 T.K. Tung, and C.Y. Chern, "DELTAT, a Quasi-Two-Dimensional Program for Pipe Thermal Transients, ASHE PVP-36," June 1979. 3.9-4 D.R. McNeil, and J.E. Brock, "Charts for Transient Temperatures in Pipes," "Heating/Piping/Air Conditioning," pp. 107-119, November 1979. 3.9-5 H.S. Carslaw, and J.C. Jaeger, "Conduction of Heat in Solids," Oxford University Press, pp. 392-394, 1959. 3.9-6 E. Wilson, and S .R. Nickell, "Application of the Finite Element Method to Heat Conduction Analysis,"

              "Nuclear Engineering and Design, 4," 1966.

3.9-7 E. Wilson, "Structural Analysis of Axisymmetric Solids, ** "AIAA Journal, 3" (112), December 1965. 3.9-8 P .J. Schneider. "Temperature Response Charts," John Wiley and Sons, Inc., 1963. 3.9-9 "Sample Analysis of a Class I Piping System," prepared by the Working Group on Piping (SDG, Sell!) of the ASHE Boiler and Pressure Vessel Code, December 1971. 3.9-162 HCGS-UFSAR Revision 0 April 11, 1988

3.9-10 General Electric, "BWR Fuel Channel Mechanical Design and Deflection,n NEDE-21354-P, September 1976 . 3.9-11 General Electric, 11 BWR Fuel Assembly Evaluation of Combined Safe Shutdown Earthquake (SSE) and Loss-of-Coolant Accident (LOCA) LoadingS 1 11 NEDE-21175-P, November 1976 and NEDE-21175-3-P, July 1982. 3.9-12 General Electric, "Assessment of Reactor Internals Vibration in BWR/4 and BWR/5 PlantS 1 11 NEDE-24057-P (Class III) and NED0-24057 (Class I), November 1977. 3.9-13 General Electric, "Design and Performance of General Electric Boiling Water Reactor Main Steam Line Isolation Valves, 11 APED 5750, March 1969. 3.9-14 General Electric, Atomic Power Equipment Department, "Design and Performance of GE BWR Jet Pumps," APED-5460, July 1968 . 3.9-15 H.H. Moen, nTesting of Improved Jet Pumps for the BWR/6 Nuclear system," NED0-10602, General Electric, Atomic Power Equipment Department 1 June 1972. 3.9-16 General Electric, "Analytical Model for Loss-of-Coolant Analysis in I Accordance with 10 CFR 50, Appendix K," NEDE-20566-P-A, September 1986. 3.9-17 General Electric, 11 Boiling Water Reactor Feedwater Nozzle/Sparger Final Report, 11 NED0-21821, March 1978. 3.9-18 Letter from W. G. Gang (GE) to R. Bosnak (NRC) dated January 15, 1981 on the subject of "GE Position on Fatigue Analysis.n

• HCGS-UFSAR 3.9-163 Revision 14 July 26, 2005

3.9-19 Letter from R. J. Bosnack (NRC). to W. G. Gang {GE) dated February 19, .1981 on the subject of* "Fatigue .Anal*ysis." 3.9-20 Letter from R.B. Johnson (GE} to R. Bosnak {NRC) dated June 29, 1981 on the subject of .'!GE Position on Fatigue Analysis." 3.9-21 G. and H. Becker, "Handbook of Structural Stabili.ty - Part III, Buckling of Curved Plates and Shells," NACA Technical Note 3783, Washington DC, 1957. 3.9-22 R.L. Mitt!, PSE&G, to W. NRC, Hope Creek IST Program - Revision 0", dated July 12, 1985. 3.9-23 C. McNei-ll, PSE&G, to E. Adensain, NRC, "Leak Rate Testing Reactor

          . Coolant Boundary Valves", dated January 8, 19~6.

3.9-24 ABB Combustion Engineering Nuclear Power, "Fuel Assembly Mechanical Methodology*for'Boiling*Water Reactors"~ CENPD'-287-:-P-A, July 1996. 3.9""-25 ABB Combustion Eng1-neering Nuclear Povler*, "ABB Seismic I LOCA Evaluation Methodology for Boiling. Water Fuel",

• CENPD-288-P-A, July 1996.

3.9-26 "EPU Power :Ascension* Test Plan *overview-* {Attachment 23 to PSEG letter LR-N06-0286, 09/18/2006) 3.9-27" "Power- Ascension Test Plan (Attachment 8 *to PSEG -letter LR-N07-0099, 04/30/2007) 3.9-28 C. o*. I. TeChnical* Note 07-29P, Revision 2, "Limit Curve Anaiysis with ACM' Rev. 4 for Power Ascension* at Hope Creek Unit 1" (Attachment 2 to PSEG letter LR-NOB-0123, 05/19/2008) 3.9-29 Federal Register Notice, "Notice of Availability of Model Application Concerning Technical Specification Improvement To Modify Requirements Regarding the Addition of Limiting Condition for Operation 3. 0. 8 on the Inoperability of Snubbers Using the Consolidated Line Item Improvement Process," published M,ay 4, 2005 ( 70 FR 2 3 52 2 ). 3.9-164 HCGS-UFSAR Revision: 18 May 10, 2011

TABLE 3.9-1 PLANT EVENTS Normal, Upset,and Testing Conditions Number of Cycles

1. Bolt-up (l) 123

2. Design hydrostatic test 130

3. Startup (100°F/h heatup rate) ( 2 ) 117 (1)

4. Daily reduction to 75% power 10,000 (1)

5. Weekly reduction 50% power 2000 (1)

6. Control rod pattern changes 400

7. Loss of feedwater heaters 80

8. OBE 10/SO(J)

9. Scram:

a. Turbine generator trip, feedwater on, 40 isolation valves stay open

b. Other scrams 140

10. Reduction to 0% power, hot standby, shutdown 111 2

(100°F/h cooldown rate) ( ) lOa. Alternate Flood-Up Event 53 (60-year plant life) 28 (40-year plant life)

11. Unbolt 123

12. Preoperational blowdown** 10 1 of 3 HCGS-UFSAR Revision 14 July 26, 2005

TABLE 3.9~1 (Cont)

• 13. Natural circulation startup Number of Cycles 3

14. Loss of ac power, natural circulation restart 5 Emergency Conditions

15. Scram:

a. Reactor overpressure with delayed scram, feedwater stays on, isolation valves stay open

b. Automatic blowdown

c. Loss of feedwater pumps, isolation valves 5 closed

d. Single safety/relief valve blowdown 8

16. Improper start of cold recirculation loop

17. Sudden start of pump in cold recirculation loop

18. Improper startup with reactor drain shut off Faulted Condition

19. Pipe rupture and blowdown, including annulus pressurization

20. SSE at rated operating conditions

• HCGS-UFSAR 2 of 3 Revision 0 April 11, 1988

TABLE 3.9-1 (Cont)

• (1) Applies to RPV only.

(2) Bulk average vessel coolant temperature change in any consecutive one-hour period. ( 3) 50 peak OBE cycles for NSSS piping; 10 peak OBE cycles for other NSSS equipment and components. (4) The annual encounter probability of the one cycle events is

          -2       .               -4                      -
      <10    for emergency and <10    for faulted events .

• HCGS-UFSAR 3 of 3 Revision 0 April 11, 1988

TABLE 3.9-la PLANT EVENTS - FEEDWATER NOZZLES NUMBER OF TRANSIENT CATEGORY CYCLES 1 Bolt up Normal/upset 44 2 Design Hydrostatic Test Testing 44 3 Startup Normal/upset 117 4 Turbine Roll & Increase Normal/upset 117 to Rated Power 5 Daily Reduction to 75% Power Normal/upset 6,667 6 Weekly Reduction to 50% Power Normal/upset 7 Loss of Feedwater Heaters, Turbine Normal/upset 3 Trip with 100% Steam Bypass 8 Loss of Feedwater Heaters, Partial Normal/upset 20 Feedwater Heater Bypass 9 SCRAM, Turbine Generator Trip, Normal/upset 136 Feedwater On, Isolation Valves Open, all other SCRAMs 10 Reduction to 0% Power Normal/upset 111 11 Hot Standby Normal/upset Normal/upset 666 12 Initial Shutdown, Vessel Normal/upset 111 Flooding, Final Shutdown 13 Hydrostatic Test Testing 1 14 Unbolt Normal/upset 44 15 Pre-Op Blowdown Normal/upset 10 16 Loss of AC Power, Natural Normal/upset 5 Recirculation Re-Start 1 of 1 HCGS-UFSAR Revision 14 July 26, 2005

TABLE 3.9-2 COMPARISON OF ME912 YITH ME643 AND ANALYTICAL RESULTS Temperature Gradients(l) 6T 6T T -T (l) 1 2 ab Case Program 450 to 553°F step ME643 79.0 38.0 24.0 3-inch Sch 160, stainless ME912 79.7 40.6 24.3 Thicknesses 1.50:1 Ref 3.9-4 82.0 41.0 408 to 100°F step ME643 136.2 40.1 83.0 12-inch Sch 80 carbon ME912 134.4 41.9 81.6 steel thicknesses Ref 3.9-4 139.0 43.0 1.69:1 (1) Defined in the ASME B&PV Code, Section III, Subsection NB-3650 .

• HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

TABLE 3.9*3 COMPARISON BETWEEN ASME SAMPLE PROBLEM AND COMPUTER PROGRAM ME913 RESULTS(l) ME 913 Sample Problem( 2 ) Equation 9 20,810 psi 20,825 psi Equation 10 65,567 psi 65,596 psi Equation 11 128,950 psi 128,920 psi Equation 12 39,536 psi 39,564 psi Equation 13 23,152 psi 23,155 psi Total usage factor 0.3439 0.3699 (1) Comparison made for butt welding tee, location 10. (2) See Reference 3.9-9 .

• HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

TABLE 3.9-4 INDEX

a. Loading Combinations and Criteria for NSSS ASME B&PV Code Class 1, 2, and 3 Piping and Components

b. Reactor Pressure Vessel and Shroud Support Assembly

c. Reactor Vessel Internals and Associated Equipment

d. Reactor Water Cleanup Heat Exchangers

e. ASME B&PV Code Class 1 Main Steam Piping and Pipe Mounted Equipment

• Highest Stress Location

f. ASME B&PV Code Class 1 Main Steam Piping and Pipe Mounted Equipment

• Highest Stressed Equipment

g. ASME B&PV Code Class 1 Recirculation Piping and Pipe Mounted Equipment - Highest Stress Location

h. ASME B&PV Code Class 1 Recirculation Piping and Pipe Mounted Equipment

• Highest Stressed Equipment

i. Main Steam Safety/Relief Valves

j. Main Steam Isolation Valve

k. Recirculation Pump

1. Reactor Recirculation System Gate Valves

m. ASME B&PV Code, Class 3 Safety/Relief Valve Discharge Piping n* Standby Liquid Control Pump 1 of 2 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.9-4 (Cont)

o. Standby Liquid Control Tank

p. ECCS Pumps

q. RHR Heat Exchanger

r. RWCU Pump

s. RCIC Turbine

t. RCIC Pump

u. Fuel Storage Racks

v. High Pressure Coolant Injection Pump w.

Control Rod Drive

x.

• Control Rod Drive Housing

y. Jet Pumps

z. LPCI Coupling aa. Control Rod Guide Tube bb. In-core Instrument Housing cc. Reactor Vessel Support Equipment CRD Housing Support dd. HPCI turbine ee. Fuel Assembly (Including Channel)

~ 2 of 2 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.9-4a LOADING COMBINATIONS AND CRITERIA FOR NSSS ASME B&PV CODE CLASS 1, 2, and 3 PIPING AND COMPONENTS Load ASME B&PV Code Case Events(l) Service Limit 1 N A 2 N+OBE+SOT( 2 ) B 3 N+SBA ( 3 ) c 4 N+LOCA D 5 N+LOCA+SSE D (1) Key to load definitions: N Normal load consisting of pressure, dead weight, and thermal loads. OBE Operating basis earthquake. SOT - Systems operating transients. SBA Small break accident LOCA - Loads associated with the design basis loss-of-coolant accident (LOCA). The LOCA analysis considers the effects of a break in the main stream, recirculation, or feedwater line. SSE - Safe shutdown earthquake. (2) The effects of pool dynamic loads due to LOCA and SRV have been assessed by the Mark I Owner's Group to be negligible on the NSSS vessel, internals, components, piping, and floor mounted and pipe mounted equipment .

• HCGS-UFSAR 1 of 2 Revision 0 April 11, 1988

TABLE 3.9-4a (Cont)

• (3) Other than the effect on long term containment temperature, SBA has negligible effects on vessel, supports, internals, piping, and floor mounted and pipe mounted equipment .
• HCGS-UFSAR 2 of 2 Revision 0 April 11, 1988

TABLE 3.9-4aa CONTROL ROD GUIDE TUBE HISTORICAL INFORMATION Allowable Calculated Criteria Loading Stress, psi Stress, psi Control rod guide tube Primary Stress Limit The allowable primary membrane stress, plus bending stress, is based on the ASME B&PV Code, Section III, for type 304 stainless steel tubing and SA351 Type era casting (base) s = 16,000 psi 575"F m For normal and upset condition: 1. External pressure Applying vertical seismic 24,000 16,340

2. Vertical seismic and loads plus dead weight 1.5 s 24,000 psi weight under normal and upset

3. Horizontal seismic conditions, the maximum

4. Lateral flow impingement stress occurs at the

5. Vibration guide tube base For faulted'condition: 1. External pressure 38,400 21, 763

2. Vertical seismic and s = 2.4 s 38,400 psi weight limit m

3. Horizontal seismic the maximum stress occurs

4. Lateral flow impingement at the guide tube base

5. Vibration of 1 HCGS-UFSAR Revision 18 May 10, 2011

TABLE 3.9-4b REACTOR PRESSURE VESSEL AND SHROUD SUPPORT ASSEMBLY (l) Maximum ASME B&PV Code Section III Allowable Calculated Primary Stress Limit Criteria Load Case Number Primary Stress Type Stress, psi Stress, psi Vessel Support Skirt"' (Material: SA533 Gr B CLl) Normal & upset condition: P. s s. Normal & upset condition loads: Primary membrane 26.700 15,110 sm = 26,700 575°F 1. Normal loads

2. Upset pressure

3. OBE 4 SRV Primary membrane plus 40,050 28,700 26,700 57S"F bending (2)

Emergency condition P,..::; s, Emergency condition loads: Primary membrane 42,600 18,460 S, ~ 42,600 547"F 1. Normal 1 oads

2. Upset pressure

3. OBE

4. SRV Primary membrane plus 63.900 34,820 s,. 42,600 54;*p bending (2)

Faulted condition Faulted condition loads: Primary membrane 42,600 16,680 s, 42,600 547"F 1 . Normal loads

2. Accident pressure

3. Jet reaction

4. Annulus pressurization

5. Safe shutdown earthquake Primary membrane plus 63,900 44,754 bending I

Maximum cumulative usage factor: 0.2087 skirt knuckle 1 of 4 HCGS-UFSAR Revision 14 July 26, 2005

TABLE 3.9-4b {Cont) Maximum ASME B&PV Code Section III Allowable Calculated Primary Stress Limit Criteria Load Case Number Stress, psi Stress, psi Shroud Support ! 41 (Material SB-168) I Normal & upset condition: Normal & upset condition loads: Primary membrane 23,300 21,958

1. Normal loads

2. Upset pressure

3. OBE Primary membrane plus 34,950 22,663 bending Emergency condition !Zl :

Emergency condition loads: Primary membrane 28,400 23,026 28,400 @ 547"F 1. Normal loads

2. Upset pressure

3. OBE

4. Chugging Primary membrane plus 42,600 25,056 28,400 @ 547°F bending Faulted condition m :

P., $ 2Sy Faulted condition loads:

1. Normal loads Primary membrane 46,600 39,485 I

2. Accident pressure

3. Safe shutdown earthquake I

4. Acoustic pressure PL + pb ::; 1.5 Sy 3 s,. Primary membrane plus 69,900 41,617 s.. Sy = 23,300 @ 547°F bending Maximum cumulative usage factor is 0.672 At shroud cylinder 2 of 4 HCGS-UFSAR Revision 17 June 23, 2009

TABLE 3.9-4b {Cont) Maximum ASME B&PV Code Section I I I Allowable Calculated Primary Stress Limit Criteria Load Case Number Primary Stress Type Stress, psi RPV Feedwater Nozzle 131 (Material: SA508 CL safe-end) Normal & upset condition: Normal & upset condition loads: Primary membrane 17,700 16,220 17,700 @ 575"F 1. Normal loads

2. Upset pressure

3. Operating basis earthquake

4. SRV Primary membrane plus 26,550 22,930 17,700@ 575"F bending Emergency condition 121 :

Emergency condition loads: Primary membrane 25,900 21,420

1. Normal loads

2. Upset pressure

3. Chugging

4. SRV-ADS Primary membrane plus 38,900 22,400 bending Faulted condition 121 :

Faulted condition loads: Primary membrane 42,480 28,300 17,700@ 575"F 1. Normal loads

2. Accident pressure

3. Chugging

4. SRV-ADS

5. Safe shutdown earthquake Primary membrane plus 63,720 33,740 bending Maximum cumulative usage factor: 0.12149 @ safe end 3 of 4 HCGS-UFSAR Revision 18 May 10, 2011

TABLE 3.9-4b (Cent) Maximum ASME B&PVCode Section III Allowable calculated Primary Stress Limit Criteria Load Case Number Primary Stress TYpe Stress, psi Stress, psi CRD Penetration{ 3 ) (Material: SA-312, 304SS) Normal & upset condition: p <s Normal & upset condition loads: Primary membrane 14,150 8,840 m- m Sm = 14,150 ~ 575°F 1. Normal loads

2. Upset pressure

3. OBE Emergency condition( 2):

p < 1.2 s Emergency condition loads: Primary membrane 16,980 13,090 m- m S  : 14,150@ 575°F 1. Normal loads m

2. Upset pressure

3. Safe shutdown earthquake Faulted condition( 2 )

pm i 2.4 sm Faulted cond.i tion loads: Primary membrane 33,960 Sm = 14,150 575°F 1. Normal loads

2. Upset pressure

3. Safe shutdown earthquake.

Maximum cumulative usage factor: 0.021 ~ CRD housing (1) The vessel, support skirt, and shroud support, including legs, cylinder, and plates are furnished as a completed assembly by the vessel manufacturer. (2) Value of S or S is shown depending upon the controlling criteria (e.g., 1.8 S or 1.5 S formemerg~ncy or faulted condition). m (3) In eatly 1984, a revised seismic input 'H8.S generated to accOIIIDOdatethe effects of Unit 2 cancellation. The new seismic building basemat time histories were compared to the inputs used in the original calculation. The comparisons indicated no need to recalculate the maximum stresses, since the im}ll'lCt of the revised input 'H8.S judged to be insignificant. (4) Maximum calculated stresses as shown were generated based on the revised seismic building basemat time histories. 4 of 4 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.9-4bb ( 1) IN-CORE INSTRUMENT HOUSING HISTORICAL LON Allowable Calculated Loading Stress, psi Stress, psi

                        - The membrane stress is Code, Section III for Class I vessels, for type 304 austenitic stainless steel S       16,660 psi@ 575°F m

For normal and upset conditions: 1. Design pressure Maximum membrane stress 16,660 16,660

2. OBE occurs at the outer s s 16,660 psi surface of the vessel limit m penetration For faulted condition: 1. Design pressure Naximum membrane stress 19,920 19,920

2. SSE occurs at the outer s 1.2 s 19,920 psi 3. Static weights surface of the vessel Jim .it m penetration (1) Analyzed to emergency condition limits.

1 of 1 HCGS-UFSAR Revision 18 May 10, 2011

TABLE 3.9-4c REACTOR INTERNALS AND ASSOCIATED EQUIPMENT Maximum ASME B&PV Code Section III Allowable Calculated Primary Stress Limit Criteria Load Case Number Primary Stress Type Stress psi Stress, psi Top Guide Highest Stressed Beam (Material: 304 SS) Normal & upset condition: Pl Normal & condition loads: Primary membrane plus 25,350 24,916

1. Normal bending

2. Normal pressure

3. Operating basis earthquake

4. SRV Sm 16,900 @ 550"F Emergency conditionu 1 :

loading condition: Primary membrane plus 38,025 24,338

1. loads bending

2. Upset pressure

3. Chugging

4. SRV Faulted conditionu 1 :

Faulted condition loads: Primary membrane plus 50,700 27,842

1. Normal loads bending

2. eaulted pressure

3. Safe shutdown earthquake

4. SRV

5. Chugging Maximum cumulative usage factor: 0.435 at beam slot 1 of 3 HCGS-UFSAR Revision 18 May 10, 2011

TABLE 3.9-4c (Cont) HISTORICAL Maximum ASME B&PV Code Section III Allowable Calculated Primary Stress Limit Criteria Load Case Number Primary Stress Type Stress, psi Stress, psi 12 Core Plate (Ligament in Top Plate) l (Material: 304 SS) Normal & upset condition: Normal & upset condition loads: Primary membrane plus 25,350 10,190

1. Normal loads bending

2. Upset pressure

3. Operating basis earthquake

4. SRV PL + pb :::;; 1 . 5 s,.

Sm 16.9@ SSO"F Emergency condition Ol Emergency condition loads: Primary membrane plus 38,025 10,190

1. Normal loads bending

2. Upset pressure

3. Operating basis earthquake

4. SRV PL + pb s 2 . 2 5 S,.

S., 16. 9 @ 550°F ( 1) Faulted condition Faulted condition loads: Primary membrane plus 50,700 12,170

1. Normal loads bending

2. Accident pressure

3. Safe shutdown earthquake

4. Chugging

5. SRV PL + Pb S 3 Sm Sm 16.9 @ 550"F 2 of 3 HCGS-UFSAR Revision 18 May 10, 2011

TABLE 3.9-4c (Cont) Vl~ Maximum ASME B&PV Code Section III Allowable Calculated Primary Stress Limit Criteria Load Case Number Primary Stress Type Stress, psi Stress, psi Differential Pressure Sensing Lines! 21 (Material: 304 SS) Normal & upset condition: Normal & upset condition loads: Primary membrane plus 41,850 29,830 13,950 @ 550°F 1. Normal loads bending

2. Normal pressure

3. OBE Emergency condition w:

Emergency condition loads: Primary membrane plus 31,390 21,440

1. bending 2.

3.

4. Annulus pressurization

5. Safe shutdown earthquake Faulted condition!l 1 Faulted condition loads: Primary membrane plus 41,850 21,440

1. Normal loads bending 2.

3. 4. 5. (1) Value of Sm or Sy is shown depending upon the controlling criteria, e.g., 1.8 Sm or 1.5 Sy for emergency or faulted condition. (2) In early 1984, a revised seismic input was to accommodate the effects of Unit 2 cancellation. The new seismic building basemat time were compared to the inputs used in the calculation. The comparisons indicated no need to recalculate the maximum stresses, since the impact revised input was judged to be (3) Maximum calculated were generated based on the revised seismic building basemat time histories, 3 of 3 HCGS-UfSAR Revision 18 May 10, 2011

TABLE 3. 9-4cc REACTOR PRESSURE VESSEL SUPPORT EQUIPMENT Allowable Calculated Criteria Loading Location Stress, psi Stress, psi RPV Support (ring girder) Primary stress limit: AISC specification for the design, fabrication, and erection of structural steel for buildings For normal & upset conditions: Normal and upset condition: Top flange 22,000 fb 10,000 AISC allowable stresses, but without the usual increase for 1. Dead loads Bottom flange 22,000 fb = 10,000 earthquake loads 2. Operating basis earthquake Vessel to girder bolts 54,000 ft

3. Loads due to scram 14,000 fv For emergency conditions: Emergency condition: Top flange 33,000 fb 22,000 1.5 x AISC allowable stresses Bottom flange 33,000

1. Dead loads Vessel to girder bolts 81,000 fb 20,000

2. Safe shutdown earthquake 21,000

3. Loads due to scram ft 70,400 fv 8,900 For faulted conditions: Faulted condition: Top flange 36,800 flo - 28,000 1.67 x AISC allowable stresses for structural 1. Dead loads Bottom flange 36,800 fb 23,400 steel members 2. Safe shutdown earthquake

3. Jet reaction load Vessel to girder bolts 125,000 ft 94,000 72,000 fv 9,650 RPV Stabilizer Primary stress limit:

Section III, Subsection NF of the ASME B&PV Code - linear type support For emergency conditions: Emergency condition: Bracket 30,200 f, 18,800 (1) 1.3 x NF allowable stresses

1. Spring preload Bracket 18,300 fv = 5,500

2. Safe shutdown earthquake Rod (stress index) 1.0 0.97 Fouled condition: Bracket

1. Annulus Pressurization Loads 12,800 Pm 75,505 I

2. Safe shutdown earthquake 63,900 Pm + PlJ 38,761 1 of 3 HCGS-UFSAR Revision 17 June 23, 2009

TABLE 3. 9-4cc (Cont) Allowable calculated Criteria Loading Location Stress, psi Stress, psi CRD Housing ( 2 ) Supports - Beams Based on AISC specification for the design, fabrication, and erection of structural steel for buildings f y

           @ 150~   = 36,000 psi For normal and upset condition:         Normal and upset loads: ( 3 )

fa = 0.60 f (tension) (Negligible) fb = 0.66 f (bending) fv = 0.40 f (shear) For emergency condition: Emergency loads: (J} (negligible) For faulted condition: Faulted loads: fa(limit) = 1.5 x 0.60 x f (tension) 1. Weight of structure Top chord 33,000 fa = 12,200

2. Impact force from Top chord 33,000 fb(limit) : 1.5 X 0.60 X f (bending) failure of CRD housing fb = 16,500 fv(limit) = 1.5 x 0.40 x f (shear)

CRD Housing Supports - Grid Structure Based on AISC specification for the design, fabrication, and erection of structural steel for buildings f y

           @ 150~    = 46,000  psi For normal and upset condition:          Normal and upset loads:   (J) fa   =0.60    f (tension}                (negligible) fb   = 0.66   f (bending}

fv =0.40 f (shear) For emergency condition: Emergency loads: ( 3 ) (negligible) 2 of 3 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3. 9-4cc ( Cont) Allowable calculated Criteria. Location Stress, psi Stress, psi For faulted condition: Faulted loads: fa( limit) = 1.5 X 0.60 X f (tension) 1. Weight of structure 46,000 fb = 40,700 fb(limit) = 1.5 X 0.66 X f (bending) 2. Impact force from failing 27,600 fv = 11,100 of CRD housing fv(limit) = 1.50 x 0.40 x f (shear) ( 1 ) The emergency condition provides the least margin and, therefore, is the only case analyzed. (2) f = Material yield strength. ( 3) ~ad weights and earthquake loads are very small compared to impact force. 3 of 3 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.9*4d REACTOR WATER CLEANUP HEAT EXCHANGERS Minirrun Thickness Actual Criteria toac:lins Conponent Required. in. Thickness, in. Regenerative Heat Exchangers Closure bolting Bolting requirements are Design basis loads consisting Bolting NA 1.25 dia calculated per rules of of: - channel to ASHE B&PV Code, Sect ion Ill shell flange

1. Design pressure Primary stress limit for SA-193-87, 2. Design temperature s :: 20,000 psi 3. Design gasket load Wall thickness Wall thickness requirements 1. Design pressure Shell 0.858 0.938 are calculated per rules of 2. Design temperature Shell head 0.704 1.00 ASME B&PV, Section II[, Chamel shell 0.858 1.00 Class 3, and TEMA class c Chamel cover 3.53 3.75 Tl.besheet 2.87 2.875 Primary stress limit for: Ttbes 0.084 0.095 Carbon steel, s = 17,500 psi Austenitic stainless steel, s = 15,900 psi Nozzle loads The maxinun forces and moments Design basis loads consisting Nozzle N1 F0 =3760 lb F = 1474 lb due to pipe reactions shall not of: (tube inlet) M0 = 15,100 in.-lb M=40,920 in.-lb exceed the allowable limits 1. Design pressure

2. Design temperature Nozzle N2 F0 =3760 lb F = 198 lb

3. Dead weight (tube outlet) M0 = 15,100 in.-lb F = 10,498 in.-lb

4. Thermal expansion

5. Seismic (Class II basis> NozzleN3 F0 =3760 lb F =56 lb (shell inlet) H0 = 15,100 in.-lb M = 1808 in.*lb NozzleN4 F0 = 3760 lb F =3453 lb (shell outlet) M0 = 15,100 in.-lb M=44,268 in.-lb 1 of 3 HCGS*UFSAR Revision 2 April 11, 1990

TABLE 3.9-4d (Cont) Minimum Thickness Actual Criteria Loading Coop2nent Required, in. Thickness, in. Nonregenerative Heat Exchangers Closure bolting Bolting requirements are Design basis loads consisting Bolting NA 1.25 dia calculated per rules of of: - channel to ASME B&PV Code, Section III 1. Design pressure shell flange

2. Design temperature Primary stress limit for 3. Design gasket load SA-193-87, s = 20,000 psi Wall thickness Wall thickness requirements 1. Design pressure Shell 0.118 0.375 are calculated per rules of 2. Design temperature Shell head 0.104 0.375 ASME 8&PV, Section III, Class 3, Channel shell 0.917 1.00 and TEMA Class C Channel cover 3.53 3.75 Tlbe sheet 2.87 2.875 Primary stress limit for: Tubes 0.056 0.065 Carbon steel, s = 17,500 psi Austenitic stainless steel, s = 15,900 psi Nozzle loads The maxirrum forces and 1. Design pressure Nozzle Nl F0 = 654 lb F ,.. 126 lb moments due to pipe 2. Design temperature (tube inlet) M0 = 2620 in.-Lb M = 2206 in.-lb reactions shall not 3. Dead weight exceed the allowable limits 4. Thermal expansion Nozzle N2 F0 = 654 lb F "' 268 lb

5. Seismic (Class II basis) (tube outlet) M0 = 2620 in.-lb H = 4276 in.-lb Nozzle N3 F0 = 654 lb F = 396 lb (shell inlet) M0 = 3920 in.-lb M = 4281 in.-lb Nozzle N4 F0 = 654 lb F = 126 lb (shell outlet) M0 = 3920 in.-lb M = 2206 in.-lb 2 of 3 HCGS-UFSAR Revision 2 April 11, 1990

TABLE 3.9-4d (Cont) Allowable resultant nozzle force, lb. F , F , F X Y Z

                          = Actual orthogonal nozzle forces in x, y, and z directions.
          ..J FX + Fy + FZ2 must be equal to or less than F0 2    2 M0   =Allowable resultant nozzle moment, in.-lb.

M, M,M = Actual orthogonal nozzle moments in x, y, and z directions. VMX2 + My 2 + MZ2 must be equal to or less than M0

• X l Z -

{2) calculated loads were evaluated and accepted by General Electric per letter GB-86-27 dated 1!31/86. 3 of 3 HCGS-UFSAR Revision 0 April 11 , 1988

TABLE 3.9-4dd

• Turbine Part HPCI TURBINE DESIGN CALCULATIONS Calculated Allowable Pressure boundary castings Stop valve 8,975 psi 14,000 psi Turbine inlet {high press) 6,550 psi 14,000 psi Turbine wheel case (low press) 6,000 psi 14,000 psi Pressure boundary bolting Stop valve 17,600 psi 20,000 psi Turbine flange 18,290 psi 20,000 psi Nonpressure boundary components Turbine shaft 5,000 psi 50,000 psi Thrust bearing 4,400 lbf 5,600 lbf Journal bearing 2,680 lbf 19,500 lbf Stop valve yoke 13,500 psi 33,000 psi Pedestal dowel pins 29,800 psi 61,100 psi Pedestal bolts 11,400 lbf 28,300 lbf
• HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

(Historical Information) TABLE 3.9-4e ASME CODE CLASS 1 MAIN STEAM PIPING AND PIPE-MOUNTED EQUIPMENT - HIGHEST STRESS LOCATION Identification of Locations of Calculated Ratio Stress Limiting Stress(l) or Allowable Actual/ Node Acceptance Criteria Stress Type Usage Factor Limits Allowable Loading ASME B&PV Code Section III, NB-3600 Design condition: 1. Pressure Loop B (009)

2. weight Lug, Riser Eg. 9 ~ 1.5 S Primary 24,064 psi 26,500 psi 0.91 3. OBE m

Service levels A & B 1. Pressure Line D (039 F) (normal & upset) condition: 2. Weight Elbow - end

3. Thermal Eg. 12 ~ 3.0 S Secondary 51,854 psi 53,100 psi 0.98 expansion m

4. SRV (Pedestal, Acc:ln:)

Service levels A & B 28,772 psi 53,100 psi 0.54 1. Pressure Line c (051) (normal & upset) condition: 2. weight Elbow - end Eg. 13 <': 3.0 S thermal m expansion) Service levels A & B (normal and uDset) condition: Cumulative usage factor NA 0.05 1.0 0.05 Line D (039 F) Elbow - end ASME B&PV Code Section III NB-3600 Service level B (upset) 1. Pressure Line D condition: 2. Weight Lug Riser

3. OBE Eq. 9 ~ 1.8 S & 1.5 S Primary 25,778 psi 31,860 psi 0.81 4. Turbine MSV m Y closure (TSVC)

Service level C (emergency) 1. Pressure Line B (009) condition: 2 Lug Riser

3. (acoustic Eq. 9 2: 2 . 25 S & 1. B s Primary 25,464 psi 39,825 psi 0.64 wave) m Y THIS TABLE CONTAINS HISTORICAL DATA ONLY AND IS NO LONGER UPDATED.

FOR CURRENT INFORMATION, SEE THE LATEST APPLICABLE STRESS CALCULATIONS. 1 of 2 HCGS-UFSAR Re*.rision 16 May 15, 200B

(Historical Information) TABLE 3.9-4e (Cant) Identification of Calculated Ratio Limiting Stress(ll or Allowable Actual/

                            .S-.:ress TYPe   Usage Faccor             Allowable Service level D (faulted)                                                             1. Pressure      Line B (0091 condition,                                                                            2                Lug Riser 3.

Eq. 9 ;;: 3.0 s Primary 26,030 psi 53,100 psi 0.49 4. LOCA (AI?l m (1) Appropriate loading combinations of Table 3.9-Sa were considered, and the calculated stresses or loads are reported for the governing load combinations. THIS TABLE CONTAINS HISTORICAL DATA ONLY AND IS NO LONGER UPDATED. FOR CURRENT INFO~MATION, SEE THE LATEST APPLICABLE STRESS CALCULATIONS. 2 of 2 HCGS-tJFSAR Revision 16 May lS, 2008

TABLE 3.9-4ee FUEL ASSEMBLY (INCLUDING CHANNELl Calculated 12, 3) Peak Evaluation Basis Acceptance Criteria Loading Primary Load Type Acceleration Acceleration (1, 3) Acceleration Envelope Horizontal Direction: Horizontal Acceleration 2.5G Profile

1. Peak Pressure

2. Safe Shutdown Earthquake

3. Annulus Pressurization Vertical Direction: Vertical Accelerations 0.3G (1, 3)

I

1. Peak Pressure

2. Safe Shutdown Earthquake (1) Evaluation Basis Accelerations and Evaluations are contained in NHDH-21175-P and NHDH-21175-3-P.

(2) For the most limiting load combination, the fuel assembly gap opening for Hope Creek is expected to be negligible. This ia baaed on an assessment comparing the positive net hold down forces to those of other plants for which the calculated fuel assembly gap opening is found to be negligible. (Jl Calculated peak acceleration values apply to GH fuel. Bvaluation basis and acceptance limits for ABB fuel are contained in Reference 3.9*25. I 1 of 1 HCGS-UFSAR Revision 11 November ~4. 2000

(Historical Information) TABLE 3.9-4f ASME CODE CLASS 1 MAIN STEAM PIPING AND PIPE MOUNTED EQUIPMENT - HIGHEST STRESSED EQUIPMENT Highest Ratio Calculated Calculated/ Identification of Equipment Component/Load Type Load(l! Allowable Load Allowable Loading With Highest Loads service level B 21,682 lb 50,000 lb 0.434 l . OBE Main steam line c

2. Turbine MSV snubber ssca closure (TSVC)

Service level D 23,151 lb 75,000 lb 0.309 L SSE Main steam line c

2. LOCA (AP) snubber SSC8 Safety/Relief Valve 2.92 g 8.0 g 0.37 1. SRV (acoustic Main steam line D

- horizontal wave SRV Inlet (306) acceleration 2. SSE Service level D Valve 2.23 g 6.0 g 0.37 1. SRV {acoustic Main steam line B wave SRV Inlet (303) acceleration 2. SSE Sez;.*ice level D Main Steam 7,802 psi 13,280 psi 0.59 1. Normal loads Main steam line D Isolation Valve - 2. Turbine MSV OUtlet (063) inlet/outlet Axial closure (TSVC) Service level A 3. SSE Main Steam 9,550 psi U,280 psi 0.72 1. Normal loads Main steam line B isolation Valve - 2. Turbine MSV Inlet (070) Inlet/outlet-Bending closure (TSIV) Service level D 3. SSE Main Steam 610,529 in.-lb 1,618,000 in.-lb 0.38 1. Normal loads Main steam line A Isolation Valve - 2. LOCA (APJ MSIV Bonnet (073) bonnet moment 3. SSE Service level D (1) loading combinations of Table 3.9-Sa were considered, and the calculated or loads are prepared for the governing loading combinations. THIS TABLE CONTAINS HISTORICAL DATA ONLY AND IS NO LONGER UPDATED. FOR CURRENT INFO~~TION, SEE THE LATEST APPLIC~BLE STRESS CALCUL~TIONS. 1 of 1 HCGS-\JFSAR Rev-ision 16

                                                                                                                            ~.ay 15, 2008

TABLE 3.9-4g ASME CODE CLASS 1 RECIRCULATION PIPING AND P!PE MOUNTED EQUIPMENT - HIGHEST STRESS LOCATION Identification of Locations at Calculated Highest Stress Limiting Stress~ll or Allowable Actual/ Points Node AcceEtance Criteria Stress Type Usage Factor Limits Allowable Loading Point Numbers ASHE B&PV Code Section III, NB-3600 Design condition:  !.Pressure Lug suction - 2.Weight Loop B (006) Eq. 9 :?! 1. 5 s.. Primary 15,650 psi 25,013 psi 0.62 3.0BE Service levels A & B 1.Pressure RHR tee - (normal & upset) condition: 2.Weight Loop B (601) 3.Thermal expansion Eq. 12 ~ 3.0 s.. Secondary 30,417 psi 50,025 psi 0.61 4.0BE Service levels A & B Primary plus 30,296 psi 50,025 psi 0.61 l.Pressure Sweepolet (normal & upset) condition: secondary 2.Weight discharge (except 3.0BE header - Eq. 13 ~ 3.0 s.. thermal Loop A (108) expansion) Service levels A & B (normal and upset) condition: Cumulative usage factor NA 0.02 1.0 0.02 RHR tee Loop B (601) Service level B (upset) l.Pressure RHR tee - condition: 2.Weight Loop A (601) Eq. 9 :?! 1.8 S,.& 1.5 Sy Primary 19,863 psi 213,596 psi 0.69 3.0BE Service level c (emergency) Lug suction - condition:  !.Pressure Loop B (006) Eq. 9 <: 2.2s s.& 1.8 s. Primary 17,527 psi 34,315 psi 0.51 2 .Weight Service level D (faulted) l.Pressure RHR tee condition: 2.Weight Loop A (601) 3.SSE Eq. 9 :?! 3.0 s.. Primary 20,316 psi 38,128 psi 0.53 4.LOCA (AP) I combinations of Table 3.9-Sa were considered and the calculated NOTE: TillS TABLE CONTAINS HISTORICAL DATA ONLY AND IS NO LONGER UPDATED. FOR CURRENT INFORMATION, SEE THE LA TEST APPLICABLE STRESS CALCULATION. 1 of I HCGS-UFSAR Revision 12 May 3, 2002

TABLE 3.9-4h ASME CODE CLASS 1 RECIRCULATION PIPING AND PIPING MOUNTED EQUIPMENT - HIGHEST STRESSED EQUIPMENT Ratio Calculated/ ComEonent/Load T~Ee Load (lJ .Allowable Load Allowable Loa dins Service level B 33,244 lb 100,000 lb 0.332 1. OBE snubber SAll - loop A Service level D 44,310 lb 150,000 lb 0.295 1. LOCA (AP) Snubber SAll - loop A

2. SSE Discharge valve:

Moment 101,543 in-lb 2, 067, 952 ln-lb 0.05 1. Normal loads Loop A Level B 2. OBE Flange Moment 268,036 in-lb 2,067,952 in-lb 0.13 1. Normal loads Loop A Service Level D 2. LOCA (AP)

3. SSE suction valve; Loop A Moment Level B 97,366 in-lb 2,067,952 in-lb 0.05

                                                                   .., Normal Loads 1.

L. OBE Moment 263,858 in-lb 2,067,952 in-lb 0.13 1. Normal loads Loop 8 Level D 2. LOCA (AP)

3. SSE Recirculation pump/

motor: Horizontal 0.86 g 2.7 g 0.32 1. Normal loads Loop A pump motor e.G. acceleration - 2. SSE Level D 3. AP Vertical 0.42 g 2.7 g 0.16 Loop B pump C.G. acceleration Level D {ll Appropriate loading combinations of Table 3.9-Sa were considered and the calculated stresses are for the governing loading combinations. NOTE: THIS TABLE CONTAINS HISTORICAL DATA ONLY AND IS NO LONGER UPDATED. FOR CURRENT INFORMATION, SEE THE LATEST APPLICABLE STRESS CALCULATION. HCGS-UFSAR 1 of 1 Revision 12 I May 3, 2002

(Historical Information) TABLE 3.9-4i MAIN STEAM SAFETY/RELIEF VALVES (PILOT-OPERATED) ASME Code, Section III, 1968, Including Addenda through Summer 1970 Method of Analysis Target Rock 7567F Analvsis Allowable Value Calculated o-c.tlet fMo PB flange stresses + < 1. 5 Srn PD {target rock) P (codes) 1.5 s,. 29,100 psi Inlet: 4go s., = 1.2 s.,

                                                                                                                          =   0.77 (allowable)

(4teI 3 + l)Mo Note for Topics 1 and 2: SR < 1. 5 Sm Design pressures: s. P 0 = 1375 psig (inlet)

                                                                                                                               = 0.35 (allowable) sT   1.2 s~

Pb ~ 625 psig (outlet) = 0.76 (allowable) all s.= o. 36 s~ tions. Analyses include = 0.24 (allowable) moments of: where: Body material: Al05 Gr. II 400,000 in.~lb s. = Longitudinal hub {inlet} and wall stress, psi sm = 19,400 psi s. o.s s~ M 300,000 in.-lb 0. 33 (allowable) (outlet) s. Radial "flange* (500°F, equivalent inlet Actual tested capability stress, psi and outlet s.,. 1. 36 (including accelerations temperature l = 0.91 and moments) is as des- ~ Tangential *flangew cribed in Topic No. 11 stress, psi The analyses also include consideration of seismic, operational, and flow re-action forces. Allowable vs. tested are .1-'.I.UV.LU.CU. 12 No. THIS TABLE CONTAINS HISTORICAL DATA ONLY AND IS NO LONGER UPDATED. FOR CURRENT INFORMATION, SEE THE LATEST APPLICABLE STRESS CALCULATIONS. 1 of 6 HCGS-U?SAR Revision 16 May 15, 2008

(Historical Information) TABLE 3.9-4i (Cant) Topic Method of Analysis Target Rock 7567F Analysis Allowable Value Calculated

2. Inlet and outlet stud Total cross-sectional area area requirements shall exceed the greater Of! Am (:>Am J~Am (actual areal 12 See above note.

                                                                                                      = l.72   Am 2

8 02 in (required rninl Aml or Aml Sb

                                                                  }*

Wm2 Sn 2 Am = 4. 73 in A 2. 04 Am b THIS TABLE CONTAINS HISTORICAL DATA ONLY AND IS NO LONGER UPDATED. FOR CURRENT INFORMATION, SEE THE LATEST APPLICABLE STRESS CALCULATIONS. la of 6 HCGS-UFSAR Revision 16 May 15, 2008

{Historical Information) TABLE 3.9-4i (Cant) Tooic Method of Analysis Target Rock 7567F FL~alysis Allowable Value Calculated where: Bolting material: SA193 Gr B7 total required bolt *Where Am (required minimum) is (stud) area for the of Aml and A"'ll2 operating condition and (actual bolt area) must Am.

                        ~~2     total required bolt (stud) area for gasket seating

3. Body wall thickness 1. Valve wall thickness Section at inlet:

criterion: where: Section at middle of body t 0.67 in. tmin minimum calcu- Actual thickness lated thickness at tA Actual wall thickness (Note: This tmin is tm per notation of the codes. l

2. Cyclic rating:

It = L Nri It L Nri (1=1,2, &3l It (max) 1.0 It 0.33 Ni Ni 0.33 (allowable) Na calculation as Na calculation as based on Na 2000 cycles Na (based on Ss2l based on Sa, where Sa Sa = Sa2 l >Sol) , where "' 1. 8 X 10 - is defined as the (Target Rock) Sa cycles: larger of: satisfies Spl=(2/3)Qp+peb+QT2+130r1 [Uses same notation as codes} criterion 2 THIS TABLE CONTAINS HISTORICAL DATA ONLY AND IS NO LONGER UPDATED. FOR CURRENT INFORMATION, SEE THE LATEST APPLICABLE STRESS CALCULATIONS. 2 of 6 HCGS-UFSAR Revision 16 May 15, 2008

(Historical Information) TABLE 3.9-4i (Cont) Topic Method of Analysis Target Rock 7567F Analysis Allowable Value Calculated or SP,=0.4 Qp+!;: (Peb+2Q,.3) 2 where: S 01 Fatigue stress inten-sity at inside sur-face of crotch, psi. s., Fatigue stress inten~ sity at outside sur-face of crotch, psi

4. Bonnet flange stresses Sl<l ~ m:b 6M H, S,. < 1.5 Sm 1.5 Sm 29,100 psi s,. = 0.82 Srn

!body sidel                      ltg, + ltR,R,

s. <: 1.5 Sm ~ 0.55 (allowable)

{longitude hub stress 0.5 Sm adjacent to flange) 0.3 3 (allmvable) (Target Rock) P (codes) E + B 0.075

                                 +                      +

B1 ST "' 0.27 Sm

                                                                                                                          = 0.18 (allowable)

(circumferential stress Material: AlOS Gr II. in hub adjacent to flange) sm 1.\!,400 psi ( soo*F) (@ bolt circle} Q + pl 6M 7 B1 t _f 7r B1 t adjacent to hub) EtB 1. 8

                                                 ----R +  --~~~

7r Br 7r B1 THIS TABLE CONTAINS HISTORICAL DATA ONLY AND IS NO LONGER UPDATED. FOR CURRENT INFORMATION, SEE THE LATEST APPLICABLE STRESS CALCULATIONS. 3 of 6 HCGS-UFSAR Revision 16 May 15, 2008

(Historical Information) TABLE 3.9-4i (Cont) Method of Analysis Target Rock 7567F Analysis Allowable Value Calculated vsing Roark's formulas J..S Sm 29, 100 psi s, for stress and strain, Table X, 4th. Edition, S,-<1.55., iJ.8 5 (allowable J of cases 2

                                       -3W 2 wmt 2  [

m + (m + ll log~- ra (m - 1)

                                                                                                 ]

2

                                       -3W (m- 1)       + (m + 1) log a
                                                                                        - (rn- 1) - -

2 a2 ] Material: AlOS Gr II Sm 19,400 psi (@ SOO,F) 2

6. Bonnet stud area Total cross-sectional area = Wm Am 9. 839 in. =Am Ab (actual) =

                                                             ~1                               1 requirements            shall exceed:                                                                               1.044Am (required minimum)

Wm

                             ~1 where:                            Bolting material: SA 193 Gr B7 Am, = Total required bolt (stud) area tm    0.119 in.          ta    3. 75 t

7. 3onnet wall thickness Using Roark's formulas t~ c: t.

for stress and strain, Table XIII, case 35, con-the circumferential stress, (the governing stress), and setting equal to Sm: where: p a b outside diameter 4 of 5 HCGS-UFSAR Revision 16 May 15, 2.008

(Historical Information) TABLE 3.9-4i (Cont) Topic Target Rock 7567F Analysis Allowable Value Calculated

8. Pilot valve housing SR flange s .. < 1.5 Sm 1.5 Sm = 29,100 psi s. = 0.54 Sm 0.36 (allowable) s~ (4t a 3+ ll Jill Lt~B S;. 0.36 Srr>

ST TMo - z s. Material Al05 Gr II 0.24 (allowable) t2B Sm = 19,400 psi (@ SOO"F) s, 0.30 Sm where: 0.20 (allowable) S~ = Longitudinal "hub" wall stress, psi SR = Radial wflange* stress, psi ST = Tangential "flange" stress, psi

9. Pilot valve body using Roark's formulas for s. Sm 19,400 Sn ST = 0.34 sm flange stress stress and strain, 4th o. 34 (allowable) edition, Table X, Case 2, Material: AlOS Gr II Sm = 19,400 psi

(@500"F)

                                          -3W                            a
                                        - - - [m    + (m    +  1} log       - (m    1) 2n- m                           r:o where:

W applied load m reciprocal of Poisson's ratio a = radius of r.= radius of load

10. Main disc stress Using Roark's formulas for S~ < S~ s. 13,600 psi Smax 0.68 stress and strain. 4th edition, page 250, 2

s = BWa Material: SA.1B2 max +.2 S,.= 13,600 psi (@ SOO"F) THIS TABLE CONTAINS HISTORICAL DATA ONLY AND IS NO LONGER UPDATED. FOR CURRENT INFORMATION, SEE THE LATEST APPLICABLE STRESS CALCULATIONS. 5 of 6 HCGS-UFSAR Revision 16 May :iS, 2008

{Historical Information) TABLE 3.9-4i (Cont) Tonic Method of Analysis Target Rock 7567F Analysis Allowable Value calculated where: f3 L63 W load a cf disc t thickness at center 0

11. Seismic Capability: Stresss analysis uses F = (mass of valve) x (2.0g) and F = (mass of valve) x vertical horizontal (3.0g}, with concurrent 400,000 in.-lb and 300,000 in.-lb applied at the inlet and outlet, respectively. Valve operability has been verified by test, with applied moments of BOO,OOO in.-lb and 600,000 in.-lb at the inlet and outlet, respectively, and at actual acceleration levels of vertical= 6g and horizontal= 8g. Tests are per IEEE 344 (1975).

12. A table is included in Table 3.9-Sf that provides a comparison between the calculated valve valve loadings (acceleration levels and moments), as based on the piping stress analysis, and the allowable values.

THIS TABLE CONTAINS HISTORICAL DATA ONLY AND IS NO LONGER UPDATED. FOR CURRENT INFORMATION, SEE THE LATEST APPLICABLE STRESS CALCULATIONS. 6 of 6 HCGS-UFSAR Revision 16 May 15, 2008

{Historical Information) TABLE 3. 9-4j MAIN STEAM ISOLATION VALVE Allowable Stress Calculated Stress or Minimum or Actual Criteria Thickness, in. Thickness. in. Design of pressure retaining parts Body minimum Reference paragraph NB 3543, nonstandard pressure-rated valve, wall thickness Tables NB 451.3, 451.4, and 452.1 For design condition of 1250 psig and 575°F. The primary service rating 655 based on a core diameter of 23 in. t = 1.925 in. {including a corrosion allowance of 0.12 in.) 1.925 1.937 m Body shape rule Reference articles 452.2 and 452.2a(l), body shape rules Radius of crotch Reference Article 452.3, radius of crotch criterion r ~ 0.3 t as r 1 in., 2 m 2 t 1.8125 + 0.12 ~ 0.3 x 1.935 = 0.58 criterion satisfied m Longitudinal Reference article 452.2f, longitudinal curvature curvature criterion ---~---- + ___1__ ~ ~ is met 3d m THIS TABLE CONTAINS HISTORICAL DATA ONLY AND IS NO LONGER UPDATED. FOR CURRENT INFORMATION, SEE THE LATEST APPLICABLE STRESS CALCULATIONS. 1 of 7 HCGS-UFSAR Revision 16 May 15, 2008

{Historical Information) TABLE 3.9-4j (Cont) Allowable Stress Calculated Stress or Minimum or Actual Criteria Thickness. in. Thickness, in. Flat wall Reference article 452.2g, flat wall limitation. limitation Since no flat sections were built into the valve body design, the requirements of this article are satisfied. Primary crotch Stress due to Reference article 452.3 internal pressure criterion Pm + 0. 5 J Ps < Sm, 2 2 where Af 504 in , Am= 58 in , P = 1375 psig, 19,400 12,650 5 P = 12,650 psi, S 19,400 psi, since S > P m m mm criterion satisfied Valve body Reference article 452.4 secondary stress Primary plus Reference article 452.4a secondary stress due to internal pressure Qp te Cp [ ri + 0.5 ] Ps Ca, where c = 3, r 11.625 in, P 1375 psi, t 2.75 p i e e for wye-type valve C ~ 1.33 + Q ~ 25,965 psi a p THIS TABLE CONTAINS HISTORICAL DATA ONLY AND IS NO LONGER UPDATED. FOR CURRENT INFORMATION, SEE THE LATEST APPLICABLE STRESS CALCULATIONS. 2 of 7 HCGS-UFSAR Revision ~6 May 15, 200B

(Historical Information) TABLE 3.9-4j (Cont) Allowable Stress Calculated Stress or Minimum or Actual _(J,j_ Criteria Method of Analysis Thickness, in. Thickness 'n. Secondary stress Reference article 452.4b, Figure 452.4b(3) due to pipe reaction 2 2 Direct or axial where S 30,750, 30 in , 183 in 19,400 5040 load effect P 5040 psi ed 3 Bending load c F S, where s 30,750 F 340 in , b b b effect i.d. 23.25 in, r 11.625 t 2.75 o.d 27.8125 i e c 19,400 9940 as r 0.197

                                             "  0 .1.9 +

b 1 4 G _ _I _ , where 15,121 in r 11.625 in, b i r +t i e 3 t 2.75 in + 10.52 in e p 1!)40)!30,750) 9940 psi eb 1052 THIS TABLE CONTAINS HISTORICAL DATA ONLY AND IS NO LONGER UPDATED. FOR CURRENT INFOfu~TION, SEE THE LATEST APPLICABLE STRESS CALCULATIONS. 3 of 7 HCGS-t>"FSAR Revision 15 May 15, 2008

(Historical Information) TABLE 3.9-4j {Cont) Allowable Stress Calculated Stress or Minimum or Actual Criteria Thi ck..J.e ss , in .. Torsion load Reference article 452.4b effect 3 p "' where F 340 in , S 30,750 psi et b G t 3 G = 2162 in 19,400 9670 t P = 9670 psi et Thermal secondary Reference article 452.4c and Figures 452.4c{4) and 452.4c(S) stress at crotch region Q = Q + Q T Tl T 2 where T 3 in, Q el T = 1100, 1 Q ~ C C 8T where C = 0.21, C = 220, and = 5.6 T2 62 2 2 6

                         = 260     psi, Q   = 1360      psi T

criterion =Q + p  ::; 3 s p em where Q 25,965, P = 9940, Q = 1360, 58,200 38.625 p e T2 THIS TABLE CONTAINS HISTORICAL DATA ONLY AND IS NO LONGER UPDATED. FOR CURRENT INFORMATION, SEE THE LATEST APPLICABLE STRESS CALCULATIONS. 4 of 7 HCGS-UFSA.Tt Revision 16 May 15, 2008

(Historical Information) TABLE 3.9-4j (Cont) Allowable Stress Calculated Stress or Minimum or Actual jJJ_ Criteria Method of Analysis Thickness. in. Thickness. in. as 38,625 ~ 58,200, criterion satisfied Normal duty valve Reference article 452.5 fatigue requirements criterion N 2 2000 cycles a Spl ~3 Q' p ++ 2 QT3 + L3 QTl' whe:ce Q' 25,965, p 9942 K-2, 260, 1100 psi p eb s 23,970, s 20,845 S equal to the larger of S and S pl p2 a pl p2 s 23,970 a N 55,000 2 2000, criterion satisfied a Disk design Reference I-1120, Section III of ASME B&PV Code; Roark, 4th Ed., calculation Pages 198, 200, 201 THIS TABLE CONTAINS HISTORICAL DATA ONLY AND IS NO LONGER UPDATED. FOR CURRENT INFORMATION, SEE THE LATEST APPLICABLE STRESS CALCULATIONS. 5 of 7 HCGS-UFSAR Revision 16 May 15, 2008

(Historical Information) TABLE 3.9~4j [Cant) P~lowable Stress Calculated Stress or Minim~~ or Actual

                                                       .Lll Criteria                           Method of Analysis                                     Thickness, in. Thickness, in.

0 Disk design conditions, P = 1756 psi at 500 F, s Case No. 13, St = 1) - 222 4 a -4(m+l)a b (ln(a/b))], m where W ~ 1250 psi, m 10, t 5.875 in, a= 10.75 in, 3 b = 1.75 in, S = 9489 psi t Case No. 14 , St -. - ~ [2a2(m+l) 1 n( a I b) + (m 2 2 2a -b 2m:u:c where W = 59,044 t = 5.875 in, m = 10, 3 a= 10.75 in, b = 1.75 in., s = 4531 psi t 14,020(S +S J tl t2 THIS TABLE CONTAINS HISTORICAL DATA ONLY AND IS NO LONGER UPDATED. FOR CURRENT INFORMATION, SEE THE LATEST APPLICABLE STRESS CALCULATIONS. 6 of 7 HCGS-UFSAR Revision 16 May 15, 2008

(Historical Information) TABLE 3.9-4j [Cont) Allowable Stress Calculated Stress or Minimum or Actual Method of nn, 1 "".,* Thickness. in. Thickness in. 3W [4a 4(m + l)ln(a I b)a 4(m + 3) + b4(m - 1) + 4a 2 b 2 ] Case No. 21, Sr a 2(m + 1) + b2(m - 1) where W = 1,375, m = 10/3, t = 3.188 in, a 10.75 in, b 7.25 in. S 6090 psi r S = 3W [2a 2(m + l)ln(a I b) + a2 (m - 1) . b 2 (m - 1)] Case No. 22

                               '       2nt 2                 a2 (m + 1) + b 2 (m 1) where 1*1  252.755, m     10/3, t   3.125, a     10. 75, b = 7.25 S   = 10,740 psi p

Note: (1) All references are made to ASME B&PV Code for Pumps and Valves for Nuclear Power, dated November 1968. Reference the same code for explanation of the symbols used. THIS TABLE CONTAINS HISTORICAL DATA ONLY AND IS NO LONGER UPDATED. FOR CURRENT INFORM~TION, SEE THE LATEST APPLICABLE STRESS CALCULATIONS. of 7 HCGS-UFSAR Revision 16 Hay 15, 2008

TABLE 3. 9-4k RECIRCULATION ruMP Normal and Upset Allowable Stress or Criteria Condition Analytical Results Actual Thickness

1. Casing minirm.un wall thickness loads: Design pressure & t = 2.69 in. sallow = 15,075 psi temperature t: PR +C SE - 0.6P  ::: 3.00 in.

where: t = min. req'd thickness, in. P =design pressure, psig R =max. internal radius, in. S = allowable working stress, psi E ; joint efficiency C =corrosion allowance, in. Primary membrane stress limit: Allowable working stress per ASME Section III, Class C

2. Casing cover minimum thickness loads: Design pressure & Ss = 3380 psi sallow = 8750 psi temperature Ss - = F A = 3.5 in.

F = force A = area at shear point s = Kga2 b -- b2 q = pressure load a = radius of o.d. b = radius of i.d. h = plate thickness Primary bending & shear stress limit: sb = 5950 psi Stallow : 1.5 X 15,075 psi 1.5 S per ASME Code for pumps and valves for nucle~r power Class I act = 7 in. 1 of 4 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.9-4k (Cont) Normal"andUpset Allowable Stress or Criteria Condition Analytical Results Actual Thickness

3. Cover and seal flange bolt areas loads: Design pressure &. For cover flange bolts:

temperature Bolting loads, areas, and stresses shall be Design gasket load sact = 19,400 psi sallow = 20,000 psi calculated in accordance with "Rules for Bolted Flange Connections" - ASME Section VIII, Paragraph UA-49. Am = 90.2 sq in. Aact = 101 sq in. For seal flange bolts: Bolting stress limit: Allowable working sact = 18,000 psi sallow = 20,000 psi stress per ASME Section III, Class C Am =9.85 sq in. Aact = 11.1 sq in.

4. Cover clamp flange thiclmess loads: Design pressure&. For flange thickness temperature stress:

Flange thickness and stress shall be calculated Design gasket load in accordance with "Rules for Bolted Flange Design bolting t = 8. 9 in. tact = 9.25 in. Connections" - ASME Section VIII, Para UA-51 load Tangential flange stress limit: Sallow = 17 , 500 psi Allowable working stress per ASME Section III, Class c.

5. Seal cover loads: Design pressure &. ~ = 2870 psi sallow = 15,075 psi tempez:ature S = KP b +2 t = 1.10 in. tact = 2.56 in.

P = bolt load due to pressure t = thickness, in. K = constant or shape factor

6. Seal chamber minimun wall thickness loads: Design pressure & t =0.741 in. Sallow  : 1.5 X 17,075 psi temperature t= PR +C Piping reactions SE - 0.6P duri~ normal operation tact = 1.375 in.

2 of 4 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.9-4k (Contl Normal and Upset Allowable Stress or Condition Analytical Results Actual Thickness where: t min req'd thickness, in. p design pressure, psig R max internal radius, in. S allowable working stress, psi E joint.efficiency C corrosion allowance, in. Combined stress limit: 1.5 Sm per ASME Code for pumps and valves for nuclear power Class I

7. Mounting bracket combined stress loads: 1.5 s., 25,013 psi seismic force ft 1.07 g DBE vertical seismic force

                                                = 0.67 g Bracket vertical loads shall be determined by                        Lug No. 1, Sc = 20,857 psi summing the equipment and fluid weights and vertical seismic forces. Bracket horizontal loads shall be determined by applying the specified seismic force at mass center of                            Lug No. 2, Sc    11,393 psi pump-motor asserr~ly (flooded).

Horizontal and vertical loads shall be applied Lug No. 3, Se 7,380 psi simultaneously to determine tensile, shear and I bending stresses in the brackets. Tensile, shear and bending stresses shall be combined to determine max. combined stresses. Combined stress limit: 1.5 Sm per ASME Code for pumps and valves for nuclear power Class I 3 of 4 HCGS-UFSAR Revision 17 June 23, 2009

• Normal and Upset TABLE 3.9*4k (Cont)

Allowable Stress or Criteria Condition Analytical Results Actual Thickness

8. Stresses due to seismic loads: Operation pressure For motor bolt tensile and temperature stress:

The flooded pump*motor assembly shall be analyzed OBE horizontal as a free body supported by constant support seismic force S = 21,300 psi s 30,800 psi hangers from the pump brackets. Horizontal and = 2.05g act allow vertical seismic forces shall be applied at mass DBE vertical For pump cover bolt l center of assembly and equilibrium reactions seismic force tensile stress: shall be determined for the motor and pump brackets. = 1.61g Loads, shear, and moment diagrams shall be constructed S act

                                                                               = 20,000 psi Sallow      = 32,000 psi brackets. Loads, shear, and moment diagrams shall be constructed using live loads, dead loads, and                        For motor support calculated snubber reactions. Combined bending,                         barrel combined stress:

tension, and shear stresses shall be determined for each major component of the assembly, including s act

                                                                               = 2830 psi     s allow
                                                                                                        = 22,400  psi motor support barrel, bolting, and pump casing.

The maximum combined tensile stress in the cover bolting shall be calculated using tensile stresses determine from loading diagram plus tensile stress from operating pressure Combined stress limit: Yield stress 4 of 4 HCGS*UFSAR Revision 7 December 29, 1995

TABLE 3.9*4l REACTOR RECIRCULATION SYSTEM GATE VALVES STRUCTURAL ANO MECHANICAL LOADING CRITERIA Component/ Loads/ Design Design Procedure Required Design Value Actual Design Value

1. Body and Bonnet

1.1 loads

design pressure, Vendor*s design 1525 psi 1525 psi design tempera* calculations ture 1.2 Pressure rating, Used Draft ASME Code, P = 800 psi P = 800 psi

                               .        {3)       r                                  r psi                Sectton 452.1 1.3     Minimum wall       Used Draft ASME Code, t m

!:2.1164in. t m

                                                                                        = 2.5 min.

thickness,

                               .5 Sectton 4 2.1 (3) in.

1.4 Primary membrane Used Draft ASME Code, P ~ S (500°F) mm 19,600 psi P = 11,068 psi

                               .        (3)                                          m stress, psi        Sect1on 452.3 1.5     Secondary stress   Used Draft ASHE Code, P e
                                                     ~  greatest value of P ed P

ed

                                                                                        = 5,580  psi
                               .        (3) due to pipe        Sect1on 452.4 reaction                                 P band P ~ 1.5 S (500°F)          P = 12,702 psi e         et        m              eb 1.5 (16,800) = 25,200 psi         P = 12,277 psi et P ~ P b = 12,702 psi ee 1.6     Primary plus       Used Draft ASHE Code, See 1.8 below                     Q p
                                                                                        = 24,284  psi 3

secondary stress Section 452.4( ) due to internal pressure 1.7 Thermal secondary Used Draft ASME Code, See 1.8 below Q = 5409 psi 3 T stress Section 452.4( ) 1.8 Sum of primary Used Draft ASME Code, S n

                                                    ~  35 (500°F)  = 58,800  psi  s n
                                                                                        = Qp + pe  + 2Q T

plus secondary Section 452.4(l) stress s = 47,804 psi n 1 of 7 HCGS*UFSAR Revision 7 December 29, 1995

TABLE 3.9*41 (Cont) Component/ loads/ Design Design Procedure Required Design Value Actual Design Value 5 1.9 Fatigue Used Draft ASME Code, N  :!: 2000 cycl es N > 10 cycles

                           .           (3)    a                                     a requirements     Sect1on 452.5 1.10  Cyclic rating    Used Draft ASME Code, t    :S                               I    = 0.111 3     t                                     t Section 454.2( )

2. Body to Bonnet Bolting 2.1 loads : des i gn Used ASME B&PV Code, (1) pressure & tern- Section VIII perature, gasket Paragraph UA*47 thru loads, stem UA-51 operational load, seismic load (design basis earthquake) 2.2 Bolt area Used ASME B&PV Code,

                           .         ( 1)

Sect! on Vlll Paragraph UA-47 thru UA-51 2.3 Body flange Used ASME B&PV Code,

                           *        ( 1) stresses         sectl on VII I ,

Paragraph UA-47 thru UA-51 2.3.1 Operating Used ASME B&PV Code, s H

S 1.5 s {575°F) = 28,837 psi S H

                                                                                      = 27,260  psi
                          .(           1) condition        Sect1on VIII        ,

Paragraph UA*47 thru s :S 1.5 s (575°F) = 14,225 psi s = 8004 psi UA-51 R R s :s 1.5 s (575°F) = 19,285 psi s = 9031 psi T T 2 of 7 Revision 7 December 29, 1995

TABLE 3.9*4l (Cont) Component/ Loads/ Design Design Procedure Reguired Design Value Actual Design Value 2.3.2 Gasket Used ASME B&PV Code, s :s: 1.5 s (100°f) = 30,000 psi SH= 29,981 psi

                              .(       1)               H seating           Sect1on VIII     ,

condition Paragraph UA-47 thru s s 1.5 s (100°F) = 30,000 psi SR= 11,671 psi UA-51 R s :: 1.5 S (100°F) T

                                                                              = 30,000 psi   s 1
                                                                                                 = 12,972  psi

3. Stresses in Stem

3.1 Loads

operator thrust and torque 3.2 Stem thrust Calculate stress due s :s s = 43,675 psi T m s T

                                                                                                = 6344   psi stress            to operator thrust in critical cross section 3.3     Stem torque       Calculate shear stress       s s

S 0.6 ST = 26,205 psi s s

                                                                                                  = 7732  psi stress            due to  operator torque in critical cross sec*

tion 3.4 Buckling on stem Calculate slenderness ratio. max. allowable= 38,800 lb Slenderness ratio = 60 If greater than 30, calcu* Actual load on stem = 31,842 tb late allowable load from Therefore, no buckling Rankine's formula using safety factor of 9.

4. Disc Analxsis

4.1 loads

maximum differential pressure(2) 4.2 Maximum stress Calculate maximum stress s max

                                                               ~ 1.5 S (500°F) m
                                                                                = 28,500 ps1 Max stress    =22  1 885 psi in the disc       according to Table 10 of Roark's "Formula for Stress and Strain 11 3 of 7 HCGS-UFSAR                                                                                                     Revision 7 December 29, 1995

Discharge Valves TABLE 3.9*41 (Cont) Component/ Loads/ Design Design Procedure Reguired Design Value Actual Design Value

5. Yoke and Yoke Connect ions

5.1 Loads

stem Calculate stresses in the operational load yoke and yoke connections to acceptable structural analysis methods 5.2 Stress S ~ s 28,800 psi (500°F) Max. stress= 5,134 psi in yoke legs bolts max m 5.3 Stress s max :s 1.5 S = 19,480 psi (500°F) S m max = 7,213 psi of yoke Legs 5.4 Stress of s ~ s = 19,225 psi (575°F) s max m max = 8,190 psi yoke * ?????? connection 4 of 7 Revision 7 December 29, 1995

Suction Valves TABLE 3.9*4l (Cont) Component/ Loads/ Design Design Procedure Required Design Value Actual Design Value

1. Body and Bonnet

1. 1 Loads:

Design pressure, Vendor 1 s design 1275 psi design tempera* calculation 575°F ture 1 .2 Pressure rating, Used Draft AS~§)Code, P r

                                                  = 668   psi                     P r
                                                                                       = 668 psi psi              Section 452.1     ,

Figure NB-3545.1*2 1.3 Minimum wall used Draft AS~)Code, t m

                                                  ~ 1 . 7724 in .                 t m
                                                                                       = 2.5  minimum thickness, in. Section 452.1     ,

Paragraph N8*1542 1.4 Primary membrane used Draft AS~§)Code, P ~ S (500°F) 19,600 psi P = 9,275 psi stress, psi section 452.3 , mm m Paragraph NB*3545.1 1.5 Secondary used Draft AS~§)Code, Pe = greatest value of Ped P = 5318 ps1 stress due to Section 452.4 Peb and Pet s1.5 s ped = 11,980 psi pipe reaction 1.5 (16,800) = 25,!oo psi peb = 11,575 psi pet e

                                                                                        = Peb  = 11,980 psi 1.6     Primary plus     Used Draft AS~§)Code, See 1.8 below                       Q     = 20,580 psi secondary stress Section 452.4                                               p due to internal pressure 1.7     Thermal          used Draft AS~§)Code, See 1.8 below                       Q t
                                                                                       = 5484  psi secondary stress section 452.4 1.8     Sum of primary   Used Draft AS~§>Code, Sn  s3   S (500°F) m
                                                                    = 58,800 psi  S n
                                                                                       =Op + Pe + 2Qt plus secondary   section 452.4 stress                                                                     S r
                                                                                       = 43,538  psi 1.9     Fatigue          Used Draft ASHE Code, Na  ~ 2000 cycles                   N6
                            . 45 2*s(l)                                             a  = 10  cycles requirements     Section 1.10    Cyclic rating    Used Draft AS~§)Code, r s                                 I    = 0.111 Section 454.2           t                                   t 5 of 7 HCGS-UFSAR                                                                                                   Revision 7 December 29, 1995

Suction Valves TABLE 3.9-4l (Cont) Component/ Loads/ Design Design Procedure Required Design Value Actual Design Value

2. Body to Bonnet Bolting

                                                                         .      (1}

2.1 Loads

design Used ASME Section VIII pressure & Paragraph UA~47 thru UA-51 temperature, Gasket loads, Stem operational load (design basis earthquake)

                                         .(        1)                 .2                                    2 2.2     Bolt area        Used ASME Section VIII          \   ~ 37.53 ln.                    \   = 55.86 in.

Paragraph UA-47 thru UA-51 sb ~ 27,975 psi (575°f) sb = 19,470 psi

                                         *       ( 1) 2.3     Body flange      Used ASME Section VIII stresses         Paragraph UA~47 thru UA-51
                                         .(        1) 2.3.1   Operating        Used ASME Sectlon VIII          s K
                                                             ~ 1.5 s <575°F) m
                                                                             = 28,837 psi   s K
                                                                                                = 24,456 psi condition        Paragraph UA-47 thru UA-51 S ~

R 1.5 S C575°F) m

                                                                             = 19,225 psi   SR :: 6539 psi s

T

                                                             ~ 1.5 S (575°F) = 19,225 m

psi S T

                                                                                                = 8718 psi ed           .      (1)

S i 1.5 S (100°f): 30,000 psi 2.3.2 Gasket seating Us ASME Sect1on VIII SH: 28,945 psi condition Paragraph UA-47 thru UA-51 H m s s 1.5 s C100°F) = 30,000 psi SR= 10,253 psi R m s ~ 1.5 s C100°F) = 30,000 psi sr= 13,619 psi T m

3. Stress in stem

3.1 Loads

operator thrust and torque 3.2 Buckling on stem Calculate slenderness Maximum allowable load= 37,750 lb Slenderness ratio= 61 ratio. If greater than Actual Load on stem = 31,842 lb 30, calculate allowable Therefore, no buckling. load from Rankine's formula using safety factor of 9. 6 of 7 tfCGS*UFSAR Revision 7 December 29, 1995

TABLE 3.9*4l {Cont) Suction Valves Component/ Loads/ Design Design Procedure Required Design Value Actual Design Value 3.3 Stem thrust Calculate stress due to s ~ s = 43,675 psi s = 6461 psi stress operator thrust in TT T critical cross section 3.4 Stem torque Calculate shear stress s ~ 0.6 s = 26,205 psi s= 7947 psi stress due to operator torque sm s in critical cross section

4. Disc Analysis

4.1 loads

maximum (4) differential pressure 4.2 Maximum stress Calculate maximum stress S max

                                                         ~ 1.5 S (500°F) m
                                                                            = 28,500 psi   Max stress   = 19,418 psi in the disc     according to table 10 of Roark*s Formula for stress and strain

5. Yoke and Yoke Connections

5.1 Loads

stem Calculate stresses in the operational yoke and yoke connections load to acceptable structural analysis methods 5.2 Stress in yoke smax ~ sm = za,aoo psi csoo~F) Max stress = 5053 psi legs bolts 5.3 Stress at s max ~ S = 19,400 psi (500aF) s m max = 7092 psi yoke legs 5.4 Stress at yoke* s max s s = 19,225 psi C575°F) s m max = 8052 psi bonnet conn. (1) ASME B&PV Code Section VIII, 1968 Edition only. (2) Valve differential pressure = 200 psid. (3) Draft, ASME Code for Pumps and Valves For Nuclear Power. (4) Valve differential pressure = 50 psid. 7 of 7 Revision 7 December 29, 1995

TABLE 3.9-4m ASME B&PV CODE CLASS 3 SAFETY/RELIEF VALVE DISCHARGE PIPING See Tables 3.9-8 and 3.9-13

• HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

TABLE 3.9-4n STANDBY LIQUID (X)N'l'OOL PUMP Pressure boundar~ narts:

1. Fluid cylinder - sy = 3o,ooo psi SA182-F304

2. Discharge valve stop sy = 30,000 psi stuffing box and cylinder head extension, SA 479-304

3. Discharge valve cover, sy = 30,000 psi cylinder head & stuffing box flange plate, SA 285 GR. C

4. Stuffing box gland, sy = 9o,ooo psi AS'IM A461 GR. 630

5. Studs, SA 193-B7 sy = 105,000 psi

6. Dowel pins ( 2 ) alignment, sa = 117 ,ooo psi SAE 4140

7. Studs, cylinder tie, sa = 105,000 psi SA 193-B7

8. Pump holddown bolts, T = 15,000 psi a

SAE GR. 1 Qa = 12,000 psi

9. Power frame, foot area, sa = 15,000 psi cast iron

10. Motor holddown bolts, SAE GR. 1 Ta = 15,000 psi Qa = 12,000 psi

11. Motor frame, foot area, sa = 15,000 psi cast iron 1 of 3 HCGS-UFSAR Revision 0 April 11 , 1988

TABLE 3. 9-4n (Cont) Allowable Calculated Limiting Stress, Stress, Cri terialLoa.ding ( l} ComPOnent Stress TYDe m!i ~i Normal and u~et condition loads:

1. Design pressure 1. Fluid cylinder General membrane 17,800 (4)

See note{ 4 )

2. Design temperature 2. Discharge valve stop General membrane 17,800 See note( 4 )

3. Operating ~~f earthquake 3. Cylinder head extension General membrane 17,800 See note( 4 )

4. Nozzle loads 4. Discharge valve cover General membrane 17,800 See note( 4 )

5. Dead weight 5. Cylinder head General membrane 17,800 See note( 4 )

6. Thermal expansion 6. Stuffing box flange plate General membrane 17,800 See note( 4 )

7. SRV discharge 7. Stuffing box gland General membrane 35,000 See note( 4 )

8. Cylinder head studs Tensile 25,000 See note( 4 )

9. Stuffing box studs Tensile 25,000 See note Emergencz condition loads:

1. Design pressure 1. Fluid cylinder General membrane 21,360 4450

2. Design temperature 2. Discharge valve stop General membrane 21,360 13,600

3. Weight of structure 3. Cylinder head extension General membrane 21,360 13,600

4. Thermal e~ton 4. Discharge valve cover General membrane 21,360 8150

5. Nozzle loads 5. Cylinder head General membrane 21,360 8150

6. Stuffing box flange plate General membrane 21,360 10,390

7. Stuffing box gland General membrane 42,000 11,420

8. Cylinder h{f( studs Tensile ( 2) 25,000 18,820

9. Dowel pins Shear oy~f 23,400 19,400

10. Studs, cylinder tie Tensile 25,000 8685

11. Pump holddown bolts . Shear 12,000 9415

12. Pump holddown bolts Tensile 15,000 12,675

13. Power frame-foot area Shear 15,000 1850

14. Power frame-foot area Tensile 15,000 11,390

15. Motor holddown bolts Shear 12,000 3020

16. Motor holddown bolts Tensile 15,000 5290

17. Motor frame-foot area Shear 15,000 2070

18. Motor frame-foot area Tensile 15,000 4125 Nozzle load: Allowable nozzle loads are given in the form of the following equation and must be satisfied to prevent excessive shear stress in the pump holddown bolts.

Units: Forces - lb 0.78Fsx + 1.32Fsz + 1.32Fdz + 0.146Fdx + 0.0412Msy + 0.0412M~UA.

                                                                                                                         .. -< 2315 Moments - in.-lb where:

F8 x = Force on suction nozzle flange in x direction. Fsz = Force on suction nozzle flange in z direction. 2 of 3 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3. 9-4n ( Cont) Allowable Calculated Limiting Stress, Stress, Criteria/Loading (l) Component Stress TYpe psi psi Fdz = Force on discharge nozzle flange in z direction. Fdx = Force on discharge flange in x direction. M sy = Moment on suction flange about y axis. Mdy = Moment on discharge flange about y axis. y z

                                                        *Same axis orientation applies to discharge nozzle.

( 1) Based on ASME B&PVCode. Section III. (2) Dowel pins take all shear. (3) Nozzle loads produce shear loads only. (4) Calculated stresses for emergency or faulted condition are less than the allowable stresses for the normal and upset condition stresses; therefore, the normal and upset condition is not evaluated. ( 5) Operability: The sum of the plunges and rod assembly, poundsmass times 1. 75, acceleration is much less than the thrust loads encountered during normal operating conditions. Therefore, the loads during the faulted condition have no significant effect on pump operability. 3 of 3 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.9-4o STANDBY LIQUID OONTROL TANK Allowable Stress of Min. Actual Stress or Criteria Method of Analysis Thickness Reg'd or Load Thickness Reg' d or Load

1. Shell thickness Loads: normal & upset design Brownell & Young pressure and temperature "Process Equipnent Design" t :: PR 0.01542 in. 0.1875 in.

SE - 0.6 P Stress limit ASME Section III 30,000 psi 1602 psi

2. Nozzle loads Loads: nonoal & upset design The maximum moments due to pressure and temperature pipe reaction and maximum forces shall not exceed Fo (lb) Mo (ft-lb) F(lb) M(ft-lb) the allowable limits.

Overflow nozzle 440 300 78 169 Discharge nozzle 440 300 Noz 1:151 142 Nez 2:171 136 Loads: faulted dead weight, The maximum moments due to thermal expansion, and SSE pipe reaction and maximum forces shall not exceed Fo (lb) Mo (ft-lb) F(lb) M(ft-lb) the allowable limits Overflow nozzle 530 360 78 205 Discharge nozzle 530 360 Noz 1:234 200 Noz 2:253 180

3. Anchor bolts ASME Section III 18,750 psi 9617 psi 1 of 1 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.9-4p ECCS PUMPS Actual Minimli'D Loading Condition Thiclmess, in. Thickness, in. Residual heat removal J?.!!!!!E Discharge head Faulted condition ASME B&PV Code, Section VIII, 0.750 0.526 shell Design pressure Division 1, Paragraph UG-32 Nozzle loads SSE loads Discharge nozzle Faulted condition ASME B&PV Code, Section VIII, 0.562 0.328 Design pressure Division 1, Paragraph l.Kl-27 Nozzle loads Shell Faulted condition ASME B&PV Code, Section VIII, 0.750 0.376 Design pressure Division 1, Paragraph UG-27 Nozzle loads SSE loads Core SJ2rro£ P.!!!!!H Discharge head Faulted condition ASME B&PVCode, Section VIII, 0.500 0.268 shell Design pressure Division 1, Paragraph l.Kl-32 Nozzle loads SSE loads Discharge nozzle Faulted condition ASME B&PVCode, Section VIII, 0.365 0.228 Design pressure Division 1, Paragraph UG-27 Nozzle loads Shell Faulted condition ASME B&PV Code, Section VIII, 0.500 0.185 Design pressure Division 1, Paragraph UG-27 Nozzle loads SSE loads (1) Operability demonstrated by analysis. 1 of 1 HCGS-UFSAR Revision 0 April 11 , 1988

TABLE 3.9-4q RHR HEAT EXCHANGER Allowable Stress or Calculated Stress Loadinsi/Component Criteria/Location Min. Thickness Rea'd. or Thickness

1. Closure boltins Bolting loads and stresses calculated per "Rules for Loads: normal Bolted Flange Connections" ASME Section VIII, App II Design pressure and a. Shell to tube sheet bolts 25,000 psi 24,230 psi temperature, design b. Channel to tube sheet bolts 25,000 psi 24,230 psi gasket load c. Channel to comer bolts 25,000 psi 24,230 psi

2. Wall thickness Shell side, ASME Section III, Class c, and TEMA, Class C Loads: normal Design pressure and 'fube side, ASME Section VIII, temperature Div. 1, and TEMA, class c

a. Shell 0.736 in. 0.750 in.

b. Shell cover 0.728 in. 1.0 in. min

c. Channel ring 0.736 in. 1.0625 in.

d. 'lUbes 0.047 in. 0.049 in.

e. Channel cover 6.2069 in. 6.25 in.

f. Tube sheet 6.2859 in. 6.3125 in.

Allowable Nozzle ActualNozzle ( ) Criteria Forces and Moments Forces and Moments1

3. Nozzle The maximum moments due to See below *(a) *(o) pipe reaction and the maximum *(b)

Loads: faulted forces shall not exceed the allowable limits Design pressure and temperature, Primary stress smaller of dead weight, thermal 0.75 su or 2.4 sm expansion, safe shutdown earthquake (ASME Section III allowable) 1 of 3 HCGS-UFSAR Revision 0 April 11 , 1988

TABLE 3.9-4q (Cont) Allowable Stress or Calculated Stress Loading/Component Criteria/Location Min. 'Ibiclmess Reg'd. or 'Ihickness

     *(a)                              Allowable limits (design bases)

N1 N2 N3 F = 9041 lb 9041 lb 40,738 lb 20,325 lb X Fy  :: 20,325 lb 20,325 lb 18,122 lb 20,325 lb F  :: 20,325 lb 20,325 lb 40,738 lb 9041 lb z M X

              = 627,621 in.-lb            627,621 in.-lb                        246,774 in.-lb           121,927 in.-lb M

y = 121,927 in.-lb 121,927 in.-lb 1,230,600 in.-lb 121,927 in.-lb M z = 121,927 in.-lb 121,927 in.-lb 246,774 in.-lb 627,621 in.-lb

     *(b) Forces and moments are given in global ooordina.te system defined on heat exchanger
     *(c) Calculated Nozzle Forces and Moments (design bases)

Nl N2 N3 N4 FX = 4547 lb 3297 lb 6604 lb 2779 lb Fy = 4233 lb 3671 lb 5912 lb 3524 lb Fz = 1922 lb 4697 lb 4432 lb 2777 lb M X = 58,716 in.-lb 94,032 in.-lb 241,752 in.-lb 145,080 in.-lb M = 116,376 in.-lb 120,120 in.-lb 306,967 in.-lb 105,636 in.-lb y M = 226,524 in.-lb 114,792 in.-lb 236,574 in.-lb 117,036 in.-lb z Canponent/Loadins Criteria/Location Allowable Stress 1 P:§i Actual Stress. P:§i

4. Support brackets & Stress allowables as per attachment welds ASME B&PV Code, Section III, Subsection NT (upset condition).

Loads: faulted Lower bracket welds Design pressure and temperature, dead - Bending stress 14,437.5 7,153.9 weight, nozzle loads, SSE - Shear stress 14,437.5 13,998 2 of 3 HOOS-UFSAR Revision 0 April 11 , 1988

TABLE 3.9-4q (Cont) Allowable Stress or Calculated Stress LoadiDSlComoonent Criteria/Location Min. Thickness Rea'd. or Thickness

5. Anchor bolts Stress allowable as per ASME B&PVOode, Section III, Loads: faulted Appendix XVII Lower support bolting Design pressure and temperature, dead - Tension stress 52,500 42,494 weight, nozzle loads, SSE - Shear stress 21,700 10,358

6. Shell adjacent to Shell stress allowables as per suPPOrt brackets ASME Section III, SUbsection NC (upset condition)

Loads: faulted Design pressure and 1. Maximum principe.l stress temperature, dead adjacent to upper support 28,875 14,667 weight, nozzle loads, SSE 2. Maximum principal stress 19,550 adjacent to lower support

7. Shell a~ from Stress allowable as per ASME discontinuities Section III, SUbsection NC (upset condition)

Loads: faulted Principa.l stress 19,250 19,620 Design pressure and temperature, dead weight, nozzle loads, SSE Note: ( 1} calculated nozzle forces and moments are enveloped values of RHR Ht. Exchanger AE205 a. BK205. calculated loads were eValuated and accepted by General Electric per letter GB-86-27 dated 1/31/86. outline drawings OE VPF 13239-97-4. 3 of 3 HOOS-UFSAR Revision 0 April 11, 1988

Table 3.9-4r Reactor Water Cleanup Pump Component Design Margin Safety Factor (S F ) 1 Safet y Fa c t or (SF) 1 1AP-221 1BP-221 Motor Case Flange t o 1.105 1.1 03 Pump Case Bolting Suction Nozzle Max Loading Faulted 1. 7 62 1.762 Upset 1.138 1. 138 Normal 1. 099 1. 099 Seismic 4.173 4.210 Discharge Nozzle Max Loading Faulted 3 .3 79 3 .54 0 Upset 2.204 2 . 331 Normal 2.242 2 . 994 Seismic 15.447 15.300 Suppor t Skirt Bolt Seismic Loading Ax ial 7.954 7 . 683 Shear 32. 755 89 . 3 14 1 Designed to ASME Sect ion III, Clas s 3, 2004 Edition 1 of 1 HCGS-UFSAR Revision 21 November 9 , 20 15

TABLE 3.9-4s RCIC 'ltlRBINE Limiting Allowable calculated Criteria Loading Component Stress Type Stress, psi Stress, psi The highest stressed sections of the various components of the RCIC turbine assembly are identified. Allowable stresses are based on ASME B&PV Code, Section III, for: Nonnal and upset condition: Pressure boundary castings SA216-NCB: S8 (general membrane} = O.SS, S = 17,500 psi S8 (bending) = 1.5 x 0.8 x s, s = 17,500 psi Pressure boundary bol tings, SA193-B7 @ 500°F S a

          = LOS                        s  = 25,000 psi Alignment dowel pins: AISI4037, PC28-35 Ta = 61,100 psi sa  = 106,000 psi Nonna.l and !:.!mlet condition loads:      Castings:   1) Stop valve          General membrane 14,000

2) Governor valve General membrane 14,000

l. Design pressure ( 1)

3) Turbine inlet Localbending 21,000

2. Design temperature 4) Turbine case Local bending 21,000

3. Operating basis earthquake Pressure containing bolts Tensile 25,000

4. Inlet nozzle loads Structure alignment pins Shear 61,100

5. Exhaust nozzle loads Faulted condition loads: Castings: 1) Stop valve General membrane 16,800 9800

2) Governor valve General membrane 16,800 13,200

1. Design pressure 3) Turbine inlet Local bending 25,200 15,300

2. Design temperature 4) Turbine case Local bending 25,200 18,000

3. Safe shutdown earthqualm Pressure containing bolts Tensile 25,000 20,100

4. Inlet nozzle loads Structure alignments pins shear 61,100 46,880

5. Exhaust nozzle loads

6. Safety/relief valve discharge

7. U::CA l of 3 HCGS-UFSAR Revlsion 0 April 11 , 1988

TABLE 3. 9-4s (Cont) Limiting Allowable Calculated Criteria Loading Component Stress Type Load Criteria Loads Nozzle load definition: Turbine vendor has defined allowable Inlet: nozzle loads for the turbine assembly. F = (2620-M) F = 390 The above calculated stresses assume 3 M :: 1419 these allowable nozzle loads have been satisfied Normal condition loads: 1* Design pressure Exhaust:

2. Design temperature =

F (6000-M) F = 219

3. Weight of structure 3 M = 2398

4. Thermal expansion where:

F = resultant force (lb) M =resultant moment ( ft-lb) Upset, emergency, or faulted condition loads:

1. Design pressure Inlet!

2. Design temperature F :: (7000-M) Inlet:

3. Weight of structure 4.7 Upset: F=1050;

4. Thermal expansion M:l743

5. Safe shutdown earthquake/operating basis earthquake Exhaust: Emerg: F=1066;

                                                                                            =

F (8500-M) M=l806 0.34 Faulted: F=585; but less than M=1651 7000 F = resultant Exhaust: force (lb) Upset: F=1860; M=3487 M =resultant Emerg: F=l718; moment (ft-lb) M=4006 Faulted: F=3076; M=4999 2 of 3 HCGS-UFSAR Revision 0 April 11 , 1988

TABLE 3. 9-4s ( Cont) (l) Calculated stresses for the faulted condition are lower than the allowable stresses for the normal plus upset condition; therefore, the normal, upset, and emergency conditions are not evaluated. (2) Operability: Analysis indicates that shaft deflection with faulted loads is 0.006 inch (this is fully acceptable) and maximum bearing load with faulted condition is 80 percent of allowable. Furthermore, as indicated in Paragraph 3.9.2.3.2.9, the turbine assembly has been seismically qualified via dynamic testing. This qualification included demonstration of startup and shutdown capabilities, as well as no load operability during seismic loading conditions. 3 of 3 HCGS-UFSAR Revision 0 April 11 , 1988

TABLE 3.9-4t RCIC roMP Limiting Allowable Calculated Criteria/Loading Component Stress 'l'ype Stress, psi Stress. psi Pressure bcnmdarystress limits of the various components for the RCIC pump assembly are basedon the ASME B&PV Code, Section III, for pressure boundary part @ 140°F

1. Forged barrel, SA105 GR. II sy = 36,000 psi

2. End cover plates, SA105 GR. II sy =36,000 psi 3, Nozzle connections, SA105 GR. II sy = 36,000 psi

4. Aligning pin, SA105 GR. II sy =36,000 psi

5. Closure bolting, SA193-B7 sy = 125,ooo psi

6. Pump holddown bolting, SA 325 sy = 81,000 psi

7. Taper pins, SA108 GR Bl112, sy =7o,ooo psi Normal and upset condition loads:

1* Design pressure 1* Forged barrel General membrane (1) (1) See note(l) See note(l)

2. Design temperature 2. End cover (suction) General membrane , See note(l) See note{l)

3. Operating basis earthquake 3, End cover (discharge) General membrane See note(l) See note( 1 )

4. Suction nozzle loads 4. Nozzle reinforcement Tensile, shear See note(l} See note( l)

5. Discharge nozzle loads 5. Alignment pin Tensile See note(l) See note(l)

6. Closure bolting See note See note 1 of 3 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.9-4t lCont) Limiting Allowable Calculated Criteria/Loading Component Stress Type Stress. osi Stress, psi ( 1) ( 1) 7* Taper pins See note(!) See note( l)

8. Pump holddown bolts See note See note Emergency or faulted condition loads:

1. Design pressure 1. Forged barrel General membrane 21,000 8100

2. Design temperature 2. End cover (suction) General membrane 21,000 10,660

3. Safe shutdown earthqualte 3. End cover {discharge) General membrane 21,000 17' 115

4. Suction nozzle loads 4. Nozzle reinforcement General membrane 21,000 5340

5. Discharge nozzle loads at barrel

5. Alignment pin Shear 25,200 15,000

6. Closure bolting Tensile 30,000 20,740

7. Taper pins Shear 25,200 1220 (bearing housing)

8. Pump holddown bolts Tension 38,880 12,450 Nozzle load definition:

Units: Forces = lb Moments ; ft-lb The allo1.-able combinations of forces and momr.nts are as follows: where:

~ M1 Mo Fi = Largest absolute value of the three actual external orthogonal forces (Fx, Fy, Fz) that may be imposed by the interface pipe Ni = Largest absolute value of the three actual external orthogonal moments (~Jx, My, Mz) permit ted from the interface pipe when they are combined simultaneously for a specific condition 2 of 3 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.9-4t (Cont) Limiting Allowable Calculated Load(3) Criteria/Loading Comoonent Stress Type Loads Normal and upset condition loads: Fo : Allowable value Suction: of Fi when all

1. Design pressure moments are zero Fo = 1940 F2 :: 1745

2. Design temperature (lbs) Mo :: 2460 M2 = 1436

3. Weight of structure Mo =Allowable value

     *l. Thermal expansion                                                     of Mi when all

5. Operating basis earthquake forces are zero Discharge:

(ft.-lbs) Fo = 3115 F2 :: 816 Mo = 4330 M2 = 880 F2 =Maximum of the three orthogonal forces (lbs) Emergency or faulted condition loads: Suction:

1. Design pressure Fo = 2325 F2 = 2556

2. Design temperature M2 = Maximum of the Mo = 2950 M2 = 1659

3. Weight of structure three orthogonal moments (ft.-lbs)

4. Thermal expansion Discharge:

5. Safe shutdown earthquake Fo = 4450 F2 = 949 Mo = 5200 M2 = 896 (1) Calculated stresses for emergency or faulted condition are less than the allowable for normal plus upset condition; therefore, the normal and upset condition is not evaluated.

(2) Operability: Static analyses for emergency or faulted condition show that the maximum shaft deflection is 0.002 in. with 0.006 in. allowable; shaft stresses are 3080 psi with 25,000 psi allowable; and bearing loads for drive end are 98 lb, with 7670 lb allowable. Bearing loads for thrust end are 765 lb, with 17,600 lb allowable. (3) Calculated loads were evaluated and accepted by General Electric per letter GB-86-27 dated 1/31/86. 3 of 3 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3. 9-4u FUEL STORAGE RACI{S Primary Allowable Calculated.(a) Loading Stress Type Stress. psi Stress, ps1. The allowable primary bending stress is based on ~m Section for type AS'H'tB221 6061-TB aluminum alloy. Fu = 38,000 psi Fy = 35,000 psi( 1 ) For normal condition: For normal condition:

0.66 F 1. Normal pressure Bending 23,100 15,230 y

2. Weight For emergency condition:< 2 > For emergency condition:

slimit = 0.88 F 1. Normal loads Bending 30,800 30,800

2. OBE

3. SRV

4. LOCA For faulted condition: For faulted condition:

1. Normal loads Bending 30,800 30,800

2. Safe shutdown earthquake

3. SRV

4. LOCA

( 1} Operability assurance is demonstrated by analysis. (2) Normal and upset condition allowable is used to. evaluate the emergency condition. (3) Above values are talten from the generic analysis using La Salle's equipnent/fuel storage raclts which envelope all other storage racks. llope Creek's storage fuel pool is snk~ller than LaSalle's; however, the rack system for both are comprised of identical components. Calculated stresses for Hope Creek will be lm.:er than shown above because of the size and lesser loadings. 1 of 1 IICGS-UFSAR Revision 0 April 11, 1988

TABLE 3.9-4v HIGH PRESSURE COOLANT INJECTION PUMP Component and Allowable Calculated Criterion Loading Controlling Stress Stress, psi Stress, psi Pressure limits of components for the HPCI pump assembly are based on the ASME B&PV Code Sections III and VIII. Design temperature 140°F, design pressure 1500 psig. Pressure Boundary Parts Pump case - A216 Gr.WCB - (SEE THE FOLLOWING PAGES FOR DETAILED INFORMATION) s 30,000 psi (main & pumps) Case bolting - A193 Gr.B7 - s 25,000 psi (main & pumps) Component Parts Holddown bolts (main A325, (Yield Stress is on A307 allowable values which is conservative) Holddown bolts (booster pump) A325, (Yield Stress is based on A307 allowable values which is conservative) Pump pins (main) A193Gr.B7 Pump pins (booster) A193Gr.B7 For the normal plus upset Normal plus upset ( 1) condition loads include: 1 of 4 HCGS-UFSAR Revision 21 November 9, 2015

TABLE 3.9-4v (Cont) Component and Allowable Calculated Criterion Loading Controlling Stress Stress, psi Stress, psi Pump casings: SA 17,500 Design pressure and temperature, Pump casings, gen. memb. 14,000 x .8 ~ 14,000 psi dead weight and thermal expansion, operating basis Case bolting (main) SA earthquake (OBE), and suction Case bolting (main) tensile 24,000 ~ 20,000 x 1.2 ~ 24,000 psi and discharge nozzle loads Case bolting (booster) SA Case bolting (booster) 24,000 ~ 20,000 x 1.2 ~ 24,000 psi tensile Holddown bolts (main) SA Holddown bolt (main) tensile 30,000 See Note 1 ~ 25,000 x 1.2 ~ 30,000 psi Holddown bolts (booster) SA Holddown bolt (booster) 30,000 ~ 25,000 X 1.2 30,000 psi tensile Pump pins (main) SA Pump pins (main) shear 30,000 ~ 25,000 x 1.2 ~ 30,000 psi Pump pins (booster) SA Pump pins (booster) 30,000 ~ 25,000 x 1.2 ~ 30,000 psi shear For the Emergency or Faulted faulted condition Conditions: Pump case, SA (general Design pressure and temperature, Pump case (main) gen. memb. 14,000 12,050 membrane) ~ 1.2 x 14,000 dead weight and thermal 16,800 psi expansion, LOCA load and design basis earthquake (SSE), and sA (-M or n1 + n, ~ 1. 8 emergency and faulted nozzle Pump case (booster) gen. 14,000 3' 630 x 14,000 ~ 25,200 psi loads. memb. Case bolting (main) SA Case bolting (main) tensile 24,000 10,100 20,000 x 1.2 ~ 24,000 psi Case bolting (booster) SA Case bolting (booster) tensile 24,000 17,400 20,000 X 1.2 24,000 psi Holddown bolts (main) SA ~ Holddown bolts (main) tensile 25,000 20,240 25,000 x 1.2 ~ 30,000 psi 2 of 4 HCGS-UFSAR Revision 21 November 9, 2015

TABLE 3.9-4v (Cont) Component and Allowable Calculated Criterion Loading Controlling Stress Stress, psi Stress, psi Holddown bolts (booster) SA Holddown bolts (booster) tensile 25,000 14,870 25,000 x 1.2 ~ 30,000 psi Pump pins (main) SA ~ 25,000 x 1.8 ~ 45,000 psi Pump pins (main) shear 30,000 23,180 I Pump pins (booster) SA ~ Pump pins (booster) shear 30,000 19' 7 60 I 25,000 x 1.8 ~ 45,000 psi Nozzle Load Definition: Forces are in (lb) and moments upset condition F0 ~ Allowable value of F are in (ft-lb) the allowable when all moments are zero (lbs). combination of forces and moments are as follows: Design pressure and tempera- M 0 ~Allowable value of M ture, dead weight and thermal when all forces are zero. expansion, and operating basis (ft.-lbs)

                        ~+      M 1 <    earthquake.

Fo - M~ Suction nozzle: F0 ~ 5,570 F2~2998 SEE HARD COPY M o ~ 15,370 M2~4899 FOR DIAGRAM Discharge nozzle: F0 ~ 7, 850 F2~4700 M 0 ~ 15,385 M2~13191 Suction nozzle: F0 ~ 6, 680 F2~4829 M 0 ~ 18,450 M2~4019 Design and temperature, dead thermal nozzle: expansion, and safe shutdown F2~4813 earthquake. M2~13792 Where Fi (lb) is the maximum of the three orthogonal forces Fx, Fy, F, and M i (ft.-lbs) is the maximum of any of the three orthogonal moments M x, MY' M,) for the same reference coordinates. F 0 and M 0 for upset and faulted conditions are base values given above. 3 of 4 HCGS-UFSAR Revision 21 November 9, 2015

TABLE 3.9-4v (Cont) Note: ( 1) 'Ibe calculated stresses for the emergency or faulted conditions are less than their corresponding allowable stresses for the normal plus upset condition; therefore, normal plus upset cond.i tion is not evaluated. (2) Calculated loads were evaluated and accepted by General 'Electric per letter GB-86-27dated l/31/86. 4 of 4 HCGS-UFSAR Revision 0 April 11 , 1988

TABLE 3.9-4w CONTROL ROD DRIVE Primary Allowable Calculated Stress Type Stress, psi Stress, psi Rins Flange Allowable primary membrane stress plus bending stress is based on ASME B&PV Code, Section III, for type 304 stainless steel @ 250°F: sm = 20,000 psi For normal and upset condition: For normal &. upset condition: General membrane &. 30,000 8285 bending

1. Normal loads(l)

2. Scramwith OBE For emergency condition: For emergency condition: General membrane &. 36,000 1370 bending

1. Normal loads(l)

2. Scramwith accumulator at overpressure For faulted condition: For faulted condition: General membrane & 71,925 3563 bending Sallow =0.80 Su for gen. memb. 1. Normal loads(l)

2. Scramwith SSE

                 = 2.16  S for gen. memb. 3. Scramwith stuck rod
                   &. bend!ng Indicator Tube Allowable primary membrane stress plus bending stress is based on ASHE B&PV Code, section IIIfo5 type 316 stainless steel @ 250 F:

sm = 20, ooo psi For normal and upset condition: For normal & upset condition: General membrane & 30,000 15,242 bending Sallow : l.S X Sm 1. Normal loads(l)

2. Scramwith OBE 1 of 2 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3. 9-4w (Cont) Primary Allow.ble Calculated Loadirui ( 1) Stress Type Stress, psi Stress. psi For emergency condition: For emergency condition: General membrane & 31,028 20,795 bending

1. Normal loads( 1 )

2. Failure of pressure regulating system

3. Scramwith accumulator at overpressure For faulted condition: For faulted condition: General membrane & 72,000 25,700 bending

1. Normal loads(l)

2. Scramwith SSE

3. Scramwith stuck rod

( 1 ) Normal loads include pressure, temperature, weight, and mechanical loads. 2 of 2 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.9-4x CONTROL ROD DRIVE HOUSING Primary Allowable Calculated Criteria Loading Stress Type Stress, psi Stress, psi Primary Stress Limit - The Normal and upset condition Maximum membrane 16,660 141 480 allowable primary membrane loads: stress intensity stress is based on the ASME occurs at the B&PV Code, Section III, for 1. tube to tube weld Class I vessels, for type 2. loads near the center of 304 stainless steel 3. OBE with lateral the housing for support normal, upset and emergency For normal and upset condition: s = 1.0 s limit m s = 16,660 psi@ 575°F m ( 1) For faulted condition: Faulted condition loads: 40,000 22,030 s 2.4 s 1. Design pressure limit m

2. Stuck rod scram loads

3. SSE with housing lateral support installed (1) Analyzed to emergency conditions limits.

1 of 1 HCGS-UFSAR Revision 18 May 10, 2011

TABLE 3.9-4y JET PUMPS HISTORICAL INFORMATION Allowable Calculated Criteria Stress Type Stress, psi Stress, psi Primary membrane plus bending stress based on ASME B&PV Code, Section III. For service levels A & B 1. Dead weight 50,700 19,346 (normal and upset) condition: 2. Pressure

3. SRV For type 30488: 4. OBE membrane S 16,900 psi@ S50°F m

3.0 s m For service level C 1. Dead weight Primary membrane 30,420 19,346 (emergency) condition: 2. Pressure plus bending

3. SRV For type 304SS: 4. OBE s 16,900 psi@ 550°F m

2.25 s rn For service level D (faulted) 1. Dead weight Primary membrane 60,840 34,417 condition: 2. Pressure plus bending

3. Chugging For type 304SS: 4. SRV

5. SSE S 16,900 psi@ 550°F m

s 3.6 s limit m (1) Maximum stress occurs at the jet pump riser brace. 1 of 1 HCGS-UFSAR Revision 18 May 10, 2011

TABLE 3.9-4z ( 1) LPCI COUPLING HISTORICAL INFORMATION Allowable Calculated Criteria Loading Combinations Stress Type Stress, psi Stress, psi Primary membrane plus bending stress based on ASME B&PV Code Section III for type CFJ for service levels A & B NL + 6P + OBE + SRV Primary membrane 25,350 3839 (normal & upset) condition: & bending s 25,350 psi limit For service level C (emergency) NL + 6P +Chugging+ SRV Primary membrane 38,025 Negligible condition: & bending S = 38,025 psi limit For service level D (faulted) NL + 6P + AP + SSE Primary membrane 60,840 15,174 condition: & bending s 60, 840 psi limit (1) Highest stressed region is attachment ring. 1 of 1 HCGS-UFSAR Revision 18 May 10, 2011

TABLE 3.9-5 NON-NSSS PIPING SYSTEMS STARTLP TESTING C<xle(s)/ Steady S.C./H.E. Temp Thermal Dynamic State PiJ2i!Y{ S~tem M.E. (1) >300°F Exl:lansion( 2 ) Transient( 3 ) Vibration( 4 ) Remarks Main steam (Bechtel- ASME III - Yes Yes Yes Yes Main stop valve closure supplied) 1,2,3; B3l.l/ and SRV opening transient sc 1 &. Non-SC 1/ HE Extraction steam 831.1/ Yes N/R(5) N/R(5) N/R(5) Non-SC 1/HE Condensate transfer ASME III - No N/R(5) N/R N/R and storage 2, 3; B3l.l/ sc 1 &. Non-SC 1/ HE &. ME Feed:water ASME III-1,2; Yes Yes(B} Yes Yes Power ascension test B31.l/ for safety-related piping sc 1 &. portion only Non-SC 11 HE Liquid radwaste ASME III-2; No N/R N/R N/R Piping between containment B31.1/SC 1 & isolation valves Non-SC 1/ ME Condenser air removal B31.1/ Yes N/R(5) N/R N/R Non-SC 1/ HE Service water ASME III-3; No N/R N/R N/R B31. 1 ; AWWA/ sc 1 &. Non-SC 1/ ME Lube oil and diesel fuel ASME III-3; No N/R N/R N/R oil storage and transfer B31.1/ sc 1 & Non-SC 1/ ME Auxiliary steam 831.1/ Yes Yes(B) N/R N/R Non-SC 1/ HE& ME 1 of 5 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.9-5 {Cont) Code I Steady s.c. Temp Thermal Dynamic State !?i~ing S:tstem M.£.Ul >300"F EXE:ansion lZJ Transient 131 Vibration 1 ~ 1 ~ Fire protection ASME III-3; No N/R N/R N/R B31.1; NFPA/ sc 1 & Non-SC 1/ ME Flow instrument lines ASME III-1/ Yes N/R N/R Yes Portion from steam SC 11 HE line to pene-tration Instrument compressed air 831.1; Yes N/R151 N/R N/R ASME III-3/ sc 1 & Non-SC 1/ ME Primary containment ASME 3; No N/R N/R N/R instrument gas 831.1/SC &. Non-SC 1/ ME Reactor feed pump 831.1/ Yes Yes 1e1 N/R N/R turbine steam NOn-SC 1/ HE Breathing air ASME III-3; No N/R N/R N/R 831.1/ sc 1 & Non-SC 1/ ME Diesel engine auxiliaries ASME III-3; Yes Yes 1" 1 N/R Yes Steady state vibration for 831.1/ sc 1 diesel starting air only.

                         &. Non-SC 1/ HE Safety and turbine        ASME III-3;        NO     N/R                  N/R           N/R auxiliaries cooling       831.1/ sc 1 I
                         & Non-SC 1/ ME Torus water cleanup       ASME III-2,3;      No     N/R                  N/R           N/R 831.1/  sc 1
                         &  Non-SC 1/ ME 2 of 5 HCGS-UFSAR                                                                                                         Revision 12 May 3, 2002

TABLE 3. 9-5 (Cont) Codels)/ Steady S.C./li.E. Temp Thermal Dynamic State PiQi!Yl S;rstem M.E.(l) >300°F Exoonsion(Z) Transient( 3 ) Vibration( 4 ) Remarks High pressure coolant ASME III-1 ,2; Yes Yes(S) Yes Yes HPCI turbine stop valve injection (HPCI) 831.1/ sc 1 closure (TSVC) transient.

                                  & Non-SC 1/                                                           Steady state vibration HE&ME                                                                 for steam supply, turbine exhaust, and HPCI pump suction and discharge lines Reactor core isolation  ASME III-I ,2;  Yes        Yes{B)         N/R              Yes        Steady state vibration for cooling (RCIC)          831.1/ sc 1                                                           RCIC steamsupply, turbine
                                  & Non-SC 1/                                                           exhaust, and RCIC pump HE&ME                                                                 suction and discharge piping Reactor water cleanup   ASME III-1,3;   Yes        Yes(B)         N/R              Yes(S)     Steady state vibration (RWC:U)                 831.1/ sc 1                                                           for RWCU from recirculating
                                  & Non-SC 1/                                                           loops A and B and RPV to HE&ME                                                                 CE 207, and from CE 207 to the feedwater tie-in.

Residual heat removal ASME III-1 ,2, Yes Yes(S) N/R Yes(G) (RHR) 3; 831.1/ sc 1 & Non-SC 1/ HE&ME Control rod drive (CRD) ASME III-3; No N/R N/R N/R 831.1/ sc 1

                                  & Non-SC 1/

ME&HE Standby liquid control ASME III-1 1 2; No N/R N/R N/R (SLC) 831.1/ sc 1

                                  & Non-SC 1/

HE&ME Core spray ASME III-1,2; Yes Yes(7)(S) N/R Yes(S) Steady state vibration for 831.1/ sc 1 & core spray pump suction and Non-SC 1/ HE & discharge ME Plant steam leak ASME III-2; No N/R N/R N/R detection 831.1/ sc 1 & Non-SC 1/ ME 3 of 5 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.9-5 (Cant) Code(s)/ Steady s.c./H.E. Temp Thennal Dynamic State Piping System r-t.E.(1) >300~ Expa.nsion(Z) Transient(J) Vibration ( 4 ) Remarks F'uel pool cooling, ASME III-2,3; No N/R N/R N/R cleanup, and demineralizer 831.1/ SC 1

                                       & Non-SC 1/ ME Containment atmosphere       ASME III-2;    Yes                        N/R             N/R control                      B31.1/sc 1
                                       &. Non-SC 1/

ME&HE Offgas recombiner B31.1/ Yes N/R N/R Non-SC 1! HE Chilled water ASME III-2,3; No N/R N/R N/R B31.1/ SC I

                                       & Non-SC 1/ ME (1)  Codes: ASME III; B&PV Code, Section 1, 2, or 3 denotes nuclear Class 1, 2, or 3 piping.

SC 1 or Non-SC 1 denotes Seismic Category I or II. B31.1 denotes ANSI B31.1. AWWA denotes American Water Works Association NFPA denotes National Fire Protection Association HE denotes high energy piping system, i.e., pressure l_275 psi or temperature _t200°F during normal plant operation. ME denotes moderate energy piping system. (2} Thermal expansion tests for the indicated Sj~tems correspond to the test boundaries and requirements stated in the vendor test specification. (3) Dynamic transient tests for the indicated systems correspond to the test boundaries and requirements stated in the vendor test specification. (4) Steady-state vibration tests for the indicated systems correspond to the test boundaries and requirements stated in the vendor test specification.

J of 5 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3. 9-5 (Cont) ( 5) N/R denotes not required by the criteria of SRP 3. 9. 2 and Regulatory Guide 1

• 70, and means the test is not performed. for the reasons listed below. Bechtel exercises judgement to include other piping systems in the testing program on a prudent engineering basis.

a} For thermal expansion tests: the system is not safety-related, or the normal operating temperature is less than 300°F. b) For dynamic transient test: the system is not safety-related, or does not experience any significant transients. c) For steady state vibration tests: the system is not safety-related, or no significant vibration is expected, basedon previous experience with similar systems. (6) Test to be done during preoperationa.l test program. ( 7) For the effect of RPV expansion only. No flow in the core spray line, ( 8) 'Th.ermal expansion testing is required only for those portions of the system that have an operating temperature of 300°F or higher per the line index. 5 of 5 HCCS-lfFSAR Revision 0 April llt 1988

TABLE 3.9-6 SEISMIC ANALYSIS FOR Nall-NSSS MECHANICAL ~IMENT Equipment Identification Equipnent Qualification Desori:etion Nunber ~ Elevation Vendor _IQ_ Method(!) Standard( 2 ) Containment hydrogen lA, 1B-C633 Aux 137' 0" Rockwell M047A DT A,I recombiner control panel RHR blowout panel lA, 1B-S284 Reac 54' 0" W.J. Woolley M177 SA A, I to torus compartment RCIC blowout panel 1C-S284 Reao 54' 0" w.J. Woolley M177 SA A,I to torus compartment HPCI blowout panel 1D-S284 Reac 54 1 ou W.J. Woolley Ml77 SA A, I to torus oompe.rtment Diesel generator lA, 1B-G400, Aux 102' 0" Colt/FMED M018 DA A,F,I lC, 1D-G400 Service water lA, 1B-Q515, Intake 107' 0" Royce M020 JJl' A, I traveling screen lC, 1D-C515 struct control panel Service water lA, 1B-F509, Intake 93' 0" Zurn Ind. Inc M076 SA A, I strainer lC, 1D-F509 struct Station service lA, 1B-P502, Intake 93' 0" HaywardTyler M080 SA A,F,I water pump lC, 1D-P502 struct Spray water booster lA, 1B-P507' Intake 79' 0" HaywardTyler M082 SA A,F,I pump lC, 1D-P507 struct Service water lA, lB-8501, Intake 114' 0" Royce M020 DA A, I traveling screen 1C, lD-8501 struct Service water pump 1~T543 Intake 122 1 0" CVI M707 SA A,F,I lubrication water l~T544 struct 122' 0" CVI M707 SA tank SACS heat exchanger !AlE, 1A2E 201, Reac 102' 0" Graham M069 DA A, I lBlE, 1B2E 201 1 of B HOOS-UF'SAR Revision 0 April 11 , 1988

TABLE 3. 9-6 (Cont) Eguicment Identification Equipnent Qualification Descri:etion Nunber ~ Elevation Verdor 1?0 Method(!) Standard( 2 ) SACS pump lA, 1B-P210, Reac 102' 0" Ingersoll Rand M070 SA A,F,I lC, 1D-P210 SACS expansion tank lA, 1B-T205 Reac 201' 0" CVI M707 DA A,F,I Diesel generator lA, 1B-E404, Aux 102' 0" Colt/FMED M018 DA F lube oil heat lC, 1D-E404 exchanger Diesel generator lA, 1B-E405, Aux 102' 0" Colt/FHIID M018 DA F jacket water heat lC, 1D-E405 exchanger Diesel generator lA, 1B-C420, Aux 102' 0" Colt/FMED M018 I11' A, I exciter panel lC, 1D-C420 Diesel generator lA, 1B-C421, Aux 102' 0" Colt/FMED M018 I11' A, I local engine lC, 1D-C421 control panel Diesel generator lA, 1B-C422, Aux 130' 0" Colt/FMED M018 A, I remote central lC, 1D-C422 generator panel Diesel generator lA, 1B-C423, Aux 130' 0" Colt/FMED M018 I11' A,I remote engine tc, 1D-C423 control panel Diesel generator lA, 1B-C428 Aux 130' 0" Consolidated J810 00' A, I load sequencer panel lC, 1D-C428 Control Diesel fuel oil lA, IB-F405, Aux 102' 0" Colt/FMED MOI8 DA F filter lC, 1D-F405 Diesel fuel oil lA, 1B-F406, Aux 102' 0" Colt/FMED M018 DA F strainer lC, ID-F406 Diesel fuel oil lA, 1B-P401, Aux 54' 0" Crane-Ghempuup M092 SA A,F,I transfer pump lC, 1D-P401, IE, 1F-P401, lG, 1H-P401 2 of 8 HCGS-UFSAR Revision 0 April 11 , 1988

TABLE 3. 9-6 (Cont) gguinment Identification Location Equipnent Qualification Descri:Qtion Nunber .J!!.Qs_ Elevation Vendor ~ Method(!) Standard( 2 ) Motor driven fuel lA, 1B-P402, Aux 102' 0" Colt/liMED M018 SA F oil punp tc, 1D-P402 Engine driven fuel IA, 1B-P404, Aux 102' 0" Colt/liMED M018 SA F oil p.mp lC, 1D-P404 Diesel fuel oil lA, 1B-T403, Aux 54' 0" Buffalo Tank H105 SA A,F,I storage tarlk lC, 1D-T403, lE, 1F-T403, lG, 1H-T403 Diesel fuel oil lA, 1B-T404 Aux 102' 0" Colt/FMED M018 SA F day tarlk lC, 1D-T404 Jacket l-lB.ter lA, 1B-E407, Aux 102' 0" Colt/liMED M018 SA F keep warmheater lC, 1D-E407 Combustion air lA, 1B-E408, Aux 102' 0" Colt/liMED M018 SA F intercooler lC, 1D-E408 Combustion air lA, 1B-F413, Aux 130' 0" Colt/liMED M018 DA F intake filter lC, 1D-F413 Intake silencer IA, 1B-F414, Aux 102' 0" Colt/FMED M018 DA F lC, 1D-F414 Diesel generator lA, 1B-F415, Aux 102' 0" Colt/FMED H018 DA F exhaust silencer tc, 1D-F415 Diesel engine jacket lA, 1B-P408, Aux 102' 0" Colt/FMED MOtS DA F l-lB.ter punp lC, 1D-P408 Jacket l-lB.ter lA, 1B-P410, Aux 102' 0" Colt/FMED M018 F keep-l-lB.rm punp 1C, 1D-P410, Lube oil keep warm lA, 1B-E406, Aux 102' 0" Colt/FMED M018 SA F heater lC, 1D-E406 Rocker arm lube lA, 1B-F403, Aux 102' 0" Colt/FMED H018 DA F oil filter lC, 1D-F403 3 of 8 HCX38-UFSAR Revision 0 April 11 I 1988

TABLE 3.9-6 (Cont) Eauioment Identification Location Hquipnent Qualification DesoriEtion Number .J!!Qs_ Elevation Vendor ro Method( l) Standard ( 2 ) Lube oil filter lA, 1B-F404, Aux 102' 0" Colt/FMED M018 DA F lC, 1D-F404 Lube oil strainer lA, 1B-F407, Aux 102' 0" Colt/FMED M018 DA F lC, 1D-F407 Rocker arm lA, 1B-P403, Aux 102' 0" Colt/FMIID M018 SA F lube oil punp lC, 1D-P403 Engine driven lube lA, 18-'P405, Aux 102' 0" Colt/FMED M018 SA F oil punp lC, 1D-P405 Rocker arm lA, 1B-P406, Aux 102' 0" Colt/FMHD M018 SA F motor driven lC, 1D-P406 prelube pump Lube oil keep warm lA, lB-P407, Aux 102' 0" Colt/FMED M018 SA F punp lC, 1D-P407 Lube oil makeup lA, 1B-T406, Aux 102' 0" Colt/FMED l<<ll8 SA F tank lC, 1D-T406 Start air receiver lA, 1B-T408, Aux 102' 0" Colt/FMED M018 DA F tank lC, 1D-T408, lE, 1F-T408, 1G, 1H-T408 SRV control air lA, 1B-T210, Reac 102' 0" CVI H707 SA A,F,I supply acclllllll.ator 1C, 1D-T210, 1E, lF-T2lO, lG, 1H-T210, lJ, 1K-T210, lL, 1M-T210, lP, 1R-T210 MSIV control air lA, 1B-T211, Reao 102' 0" CVI M707 DA A,F,I supply accunulator 1C, 1D-T211, 1A, 1B-T212, Reac 102' 0 CVI M707 DA A,F,I lC, 1D-T212 ECX:;s jockey pump lA, 1B-P228, Reao 54' 0" Hayw.rd. Tyler M082 SA A,F,l lC, 1D-P228 4 of 8 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.9-6 (Cont)

          §gyi~nt      Identification                                  Location Equipnent                                               Qualification DescriRtion          Nunber        ...ill:Qs_ Elevation       Vendor   .J:Q_  Method( I)   ~tand.ard(2)

Fuel pool heat lA, 1B-E202 Reac 162' 0" Alfa-Laval M071 DA A, I exchanger Fuel pool cooling lA, 1B-P211 Reac 162' 0" HaywardTyler M082 SA A,F,l pump High density spent lo-8287 Reac 168' 0" OCA Ml78 DA J fuel storage rack Air accunulator for lA, lB-'1'277 Reac 77' 0" CVI M707 SA A,F,I torus isolation vacuum relief valve Insttunent gas IA, 1B-S934 Reac 132' 0" CVI M048 DT A, I compressor skid Insti'llllent gas lA, 1B-T201 Rea.c 132' 0" CVI M048 SA A, I receiver Control room return lA, 1B-V415 Aux 155' 0" Buffalo M719 SA A,I air fan Technical support OQ-V314 Aux 153' 0" Buffalo M713 DA A,I center emergency filter fan Technical support OQ-VH313 Aux 153' 0" AAF M786 DA A,I center emergency filter unit Technical support OQ-VH314 Aux 153' 0" AAF M711 DA A, I center s~y unit Service area air OQ-VH316 Aux 137' 0" AAF M711 DA A, I handling unit Traveling screen OA, OB-V558 Intake 114' 0" Joy M719A SA A, I fans struct Reactor Building lA, 1C-V213 Reac 132' 0" Buffalo M713 rrr A, I FRVS recirculation lB, 1F-V213 Reac 178' 0 Buffalo M713 IJl' A, I system fan lD, IE-V213 Reac 162' 0" Buffalo M713 rrr . A,I 5 of 8 HrnS-UFSAR Revision 0 April 11, 1988

TABLE 3. 9-6 (Cont)

           ~i~nt     Identification                            Location Equipnent                                        Qualification Descrintion       Number         ~    Elevation        Vendor _BL    Method(!)    Standard ( 2 )

RCIC pump room lA, 1B-VH208 Reac 54' 0" AAF M711 DA A, I unit cooler HPCI PliDP room lA, 1B-VH209 Reac 54' 0" AAF M711 DA A, I unit cooler mm pump room lA, 1B-VH210, Reac 54' 0" AAF M711 DA A, I unit cooler lC, 1D-VH210, Reac 54'-0" DA A, I lE, 1F-VH210, Reac 77'-0" DA A, I lG, 1H-VH210 Reac 54'-0" DA A, I Core spray punp lA, 1B-VH211, Reac 54' 0" AAF M711 DA A, I room unit cooler lC, 1D-VH211, A, I lB, 1F-VH211, A,I IG, 1H-VH211 A, I Reactor Building 1A-VH213 Reac 132' 0" AAF M786 DA A,I FRVS recirculation 1B-VH213 Reac 178' 0" AAF M786 DA A, I filter system 1C-VH213 Reac 132' 0" AAF M786 DA A, I ID, 1E-VH213 Reac 162' 0" AAF M786 DA A, I 1F-VH213 Reac 178' 0" AAF M786 DA A, I SACS pump room lA, 1B-VH214, Reac 102' 0" AAF M711 DA A, I unit cooler !C, 1D-VH214 Emergency area lA, 1B-C281 Reac 102' 0" Comsip M780A DA A, I cooling system lC, 10-G281 Reac 77'-0" Comsip M78 DA A, I cooler control panel Reactor Building IA, tc-c2as, Aux 178' 0" Comsip M780A DA A,I FRVS control panel lB, ID-c285 Aux 124'-0" Reactor Building IA, 1B-VH206 Reac 145' 0" AAF M786 DA A,I FRVS vent filter RCIC pump room to-VB-259 Reac 54' 0" AAF M786 DA A, I duct heater HPCI pump room to-VB260 Reac 54' 0" AAF M786 DA A, I duct heater 6 of 8 HCG'3-UFSAR Revision 0 April 11, 1988

TABLE 3. 9-6 (Cont) Eguianent Identification Location Equipnent Qualification Descri:gtion Nl.lnber ~ Elevation Vendor _fQ_ Method( 1) Standard( 2 ) Standby liquid lA, 1B-VEZ61 Reac 162' 0" AAF M786 DA A, I control roam duct heater Diesel generator 1A, 1B-C483, Aux 178' 0" Comsip M780A DA A, I area HVAC lC, 1D-C483 Diesel area battery lA, 1B-V406, Aux 163' 6" Buffalo M713 ur A,I room exhaust fan lC, 1D-V406 Diesel generator lA, 1B-V412, Aux 77' 0" Buffalo M719 DA A, I room recirculation lC, 1D-V412, fan lE, 1F-V412, lG, 1H-V412 Diesel generator lA, 1B-VE412, Aux 77' 0" Trane M731 DA A, I room cooling coil lC, 1D-VE412, lE, 1F-VE412, lG, 1H-VE412 SWitchgear roan lA, 1B-VH401, Aux 163' 6" AAF M711 Dr A, I unit cooler lC, 1D-VH401 Class lE panel room !A, 1B-VH408 Aux 163' 6" AAF M711 DA A, I supply air unit Battery room duct !A, 1B-VE420, Aux 146' 0" AAF M786 SA A, I heater lC, 1D-VE420 Control room lA, 1B-V400 Aux 155' 3" Buffalo M713 Dr A, I emergency air supply fan Control area battery lA, 1B-V410 Aux 178' 0" Buffalo M713 DT A,I room heat exchanger fan Control room lA, 1B-VH400 Aux 155' 0" AAF M786 DA A, I emergency supply unit Control room supply 1A, 1B-VH403 Aux 155' 0" AAF M711 DA A,I unit 7 of 8 HCGS-UFSAR Revision 0 April 11 , 1988

TABLE 3. 9-6 (Cont)

         §guinment Identification                                Location Equipnent                                              Qualification Descri:Qtion      *Number       ...1llQg_ Elevation        Vendor   __FQ_  Method(!)    Standard ( 2 )

Control equipnent lA, 1B-VH407 Aux 178' 0" AAF M711 DA A, I room supply unit Control room water lA, 1B-K400 Aux 155' 0" Carrier M723 DA A,I chiller Control roomchilled lA, 1B-T410 Aux 178' 0" CVI M707 DA A,I,F water system head tank Control room chilled lA, 1B-P400 Aux 155' 0" HaywardTyler M082 SA A,I,F water circulation JUDP Control roomwater chiller pumpout unit Control room chilled lA, 1B-T413 Aux 178' 0" CVI M707 DA A,I,F water head tank Intake structure lA, 1B-V503, Intake 122' 0" Joy M719A SA A, I supply fan lC, 1D-V503 struct Intlke structure lA, 1B-V504, Intake 122' 0" Joy M719A SA A, I exhaust fan lC, 1D-V504 Sti'I.X)t Class 1E channel lA, 1B-G403, Aux 102' 0" Colt/FMED M018 Dr F diesel generator 1C, lD-0403 grotmding transformer Chilled water 1A, 1B-P414 Aux 178' 0" HaywardTyler M082 DA A,I,F circulation pump (1) DA - dynamic analysis. Dr - dynamic testing. SA - statio analysis (2) A - IEEE 344-1975 F - ASME Code, Section III I - NHC R.G. 1.100, Rev. 1 J - Appendix D of SRP 3.8.4 8 of 8 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.9-7 DESIGN LOADING COMBINATIONS FOR ASME B&PV CIDE CLASS 1, 2 AND 3 NON-NSSS COMPONENTS Condition Design Loading Combinations(l)( 2 )())( 4 } Design {a) PD Normal (a} PD + DW Upset (a) PO + DW + (OBE 2 + RVC 2 ) 1/ 2 (b) PO + DW + OBE + RVO (c) PO+ DW + FV Emergency (a) PO + DW + (OBE2 + FV2 ) 1/ 2 Faulted (a) PO + DW + SSE + RVO (b) PO + DW + (SSE 2 + RVC 2 ) 1/ 2 (c) PO + DW + (SSE2 + DBA2 ) 1/ 2 (1) As required by the appropriate subsection, i.e., NB, NC, or ND, of the ASME B&PV Code, Section III, Division I, other secondary loads, such as thermal expansion, thermal transient, thermal gradients, and anchor point displacement portion of the OBE, may require consideration in addition to the primary stress producing loads listed. (2) For torus attached piping, the loading combinations used in the piping analysis are those given in the Plant Unique Analysis Application Guide (PUAAG) (NED0-24583-1, October 1978, Table 5-2) *

• HCGS-UFSAR 1 of 2 Revision G April 11, 1988

TABLE 3.9-7 (Cont)

• (3) Definition of symbols used:

PD PO design pressure operating pressure DW dead weight OBE operating basis earthquake (inertia portion) SSE safe shutdown earthquake (inertia portion) FV transient response of the piping system associated with fast valve closure time less than 5 seconds RVC transient response of the piping system associated with relief valve opening in a closed system RVO transient response of the piping system associated with relief valve opening in an open system DBA design basis accident. (4) For components other than Bechtel supplied piping, the pressure load for the normal condition may be either PD or PO depending upon the requirements of the ASME Code in effect for that component or whichever is more conservative .

• HCGS-UFSAR 2 of 2 Revision 0 April 11, 1988

TABLE 3.9-8 DESIGN CRITERIA FOR ASME B&PV CODE CLASS 1 NON-NSSS PIPING Applicable Code Condition Paragraph(l)( 2 ) Primary Stress Limits Design NB-3221 and NB-3652 1.5 sm Normal NB-3222 and NB-3653 1.5 s m Upset NB-3223 and NB-3654 1.8 Sm but not greater than 1.5 s y Emergency NB-3224 and NB-3655 2.25 Sm but not greater than 1.8 sy Faulted NB-3225 and NB-3656 3.0 sm (1) As specified by the ASME B&PV Code, Section III, 1977 through Summer 1979 Addenda. (2) Functional capability of essential piping is ensured per NED0-21985, September 1978 .

• HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

TABLE 3.9*9 DESIGN CRITERIA FOR ASME B&PV CODE CLASS 1 NON-NSSS VALVES Design Loading Plant Condition Combinations( 4 ) Stress Limits{l) Design PD The valve shall conform to the requirement of Normal POn + Bn Paragraph NB-3500 (Standard Design Rules) Upset (3) POu + OBE + Bu Emergency( 2 ) POe + Be NB-3526 Faulted( 2 ) POf + SSE + Bf NB-3527 (1) As specified by the ASME B&PV Code, Section III, 1974 through Winter 1974 Addenda. (2) Where valve function must be ensured (active valves) during emergency or faulted conditions, the specified emergency or faulted conditions for the plant is considered the normal condition for the valve. (3) As required by subsection NB of ASME Section III, other loads such as thermal transient and thermal gradients may require additional consideration in addition to those primary stress producing loads listed. -* HCGS-UFSAR 1 of 2 Revision 0 April 11, 1988

TABLE 3.9-9 (Cont)

• (4) Definition of symbols used:

PD Design pressure PO Operating pressure at noted plant condition OBE - Operating Basis Earthquake loads (inertia portion) excluding loads from attached piping SSE - Safe Shutdown Earthquake loads (inertia portion) excluding loads from attached piping B Piping end loads at noted plant condition n Normal f Faulted e Emergency u Upset

• HCGS-UFSAR 2 of 2 Revision 0 April 11, 1988

TABLE 3.9-10 DESIGN CRITERIA FOR ASME B&PV CODE CLASS 2 AND 3 NON-NSS VESSELS DESIGNED TONC-3300 AND ND-3300 Condition Stress Limits( 1 ) Design and normal The vessel conforms to the requirements of NC-3300 and ND-3300 Upset, emergency, and faulted The vessel conforms to the requirements of ASME Code Case 1607-1 (1) As specified by the ASME B&PV Code, Section III, 1974 through Winter 1974 Addenda .

• HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

TABLE 3.9-11 DESIGN CRITERIA FOR ASME B&PV CODE CLASS 2 NON-NSSS VESSELS DESIGNED TO ALTERNATE RULES OF NC-3200 Condition Stress Limits(l)( 2 ) Design and normal The vessel conforms to the requirements of NC-3200 Upset( 3) p !S 3 s e m p !S 1.1 s m m (Pm or PL ) + Pb s 1.65 Sm Emergency P !S greater of 1.2 S or 1.0 S m m y (Pm or PL ) + PB !S greater of 1.8 Sm or 1.5 sy Faulted( 4 ) P !S greater of 1.5 S or 1.2 S m m y but not to exceed 0.7 S u (Pm or PL } + Pb s 2.4 sm (1) Definition of symbols: p general primary membrane stress intensity. This m stress intensity is derived from the average value across the solid section under consideration. It excludes discontinuities and concentrations. It is produced only by pressure and other mechanical loads. PL local primary membrane stress intensity. It is the same as P except that discontinuities are m considered . 1 of 2 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.9-11 {Cont)

• primary bending stress intensity.

primary stress from the centroid of the solid section. discontinuities and concentrations. A component of intensity proportional to distance It excludes It is produced only by pressure and other mechanical loads. p secondary stress intensity range. Developed by e constraint of adjacent parts or by self-constraint of a structure. It considers discontinuities but not concentrations. Produced by mechanical loads and by thermal expansion. sm design stress intensity value, Appendix I. Table 1*1.0 of the Code . S yield strength value, Appendix I, Table I-2.0 of the y Code . su Ultimate tensile strength. {2) These limits do not take into account either local or general buckling that might occur in thin wall vessels. Such buckling must be considered for upset conditions, but need not be considered for emergency or faulted conditions unless required by the design specification. (3) Fatigue analysis requirements of NC-3219 and Appendix XIV of the Code must also be considered. (4) As an alternative to satisfying these limits, the faulted condition stress limits of Appendix F of the Code may be applied, provided that a complete analysis in accordance with NC-32ll.l(c) is performed . 2 of 2 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.9-12 DESIGN CRITERIA FOR ASME B&PV CODE CLASS 2 AND 3 NON-NSSS PIPING Applicable Code Primary Stress Condition Paragraph (l){ 2 ) Limits Design: Sustained Loads NC, ND-3652.1 Occasional Loads NC, ND-3652.2 Normal and Upset NC, ND*3652.2 & 1.2Sh 3611 Emergency NC, ND-3611 1.8Sh Faulted Code Case 1606-1 2.4Sh (1} As specified by the ASME B&PV Code, Section III, 1974 through Winter 1974 Addenda, except for Class 2 and 3 flanges, which are designed to 1979 Summer Addenda, Paragraph NC and ND-3658, and CRD piping which is designed to ASME B&PV Code Section III. 1980 Edition through Winter 1981 addenda, Section 3650. (2) Functional capability of essential piping is ensured per NED0-21985, September 1978 .

• HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

DESIGN CRITERIA FOR ASHE B&PV CODE CLASS 2 AND 3 NON-NSSS PUMPS Condition Stress Limits(l) Design and normal The pump conforms to the requirements of Section III, Paragraphs NC-3400 and ND-3400 Upset, emergency, and faulted( 2 } The pump conforms to the requirements of ASME Code Case 1636-1 {1) As specified by the ASME B&PV Code, Section III, 1974 through Winter 1974 Addenda * (2) Where pump function must be ensured (active pumps) during emergency or faulted conditions, the pumps nozzle loads due to the specified emergency or faulted plant conditions are considered in satisfying the normal condition stress limits for the pump .

• HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

TABLE 3.9-14 DESIGN CRITERIA FOR ASME B&PV CODE CLASS 2 AND 3 NON-NSSS VALVES Design Loading Combination Stress Limits (1)(4) (1)(2)(3) Plant Condition Design PO The valve shall conform to the requirements of Section III, 1974 Paragraphs NC-3500 or ND-3500, as applicable Normal POn + Bn S :s l.OS m (Sm or SL) + Sb :s l.SOS Upset POu + OBE + Bu Sm :s l.lS (Sm or SL) + sb :s 1.658 Emergency POe + Be Sm < 1.5 S (Sm or SL) + Sb :s 1.8S Faulted POf + SSE + Bf Sm :s 2.08 (Sm or SL) + sb :s 2.4S (1) Definition of symbols: s stress m - General membrane SL - Local membrane stress sb - Bending stress s - Allowable stress PD - Design pressure PO - Operating pressure at noted plant condition n- Normal u - Upset e - Emergency f - Faulted 1 of 2 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.9-14 (Cont)

• OBE - Operating basis earthquake loads (inertia portion) excluding loads from attached piping SSE - Safe shutdown earthquake loads (inertia portion) excluding loads from attached piping B- Piping end loads at noted plant condition (2) As specified by the ASME B&PV Code, Section Ill, 1974 through Winter 1974 Addenda.

(3) Where valve function must be ensured (active valves) during emergency or faulted conditions, the specified emergency or faulted plant conditions are considered as the normal condition for the valve. (4) As required by subsection NC, ND of ASME Section III, other loads such as thermal transient and thermal gradients may require additional consideration in addition to those primary stress producing loads listed .

• HCGS-UFSAR 2 of 2 Revision 0 April 11, 1988
• Component Name NSSS ACTIVE PUMPS Identification as Shown on Applicable Fieures RHR pump 1A-P202 1B-P202 1C-P202 1D-P202 RCIC pump 10-P203 HPCI main pump l0-P204 Core spray pump 1A-P206 1B-P206 1C-P206 1D-P206 Standby liquid control 1A*P208 pump 1B-P208 HPCI auxiliary oil pump l0*P213 (10-S21l)(l}

HPCI booster pump 10-P217 RCIC turbine main oil pump 10-P271 (10-8212) HPCI turbine main oil pump l0-P272 (10-S211) (1) Pump is located on skid noted in parenthesis

• HCGS .. UFSAR 1 of 1 Revision 0 April 11, 1988

TABLE 3.9-16 NSSS ACTIVE VALVES Valve Size, S~tem TYpe(l) Qua.ntitl ...!!h._ Actuation(!) Valve Identification Nunber Main steam GB 8 26 AO F022A-D & F028A-D Main steam PSV 14 8 Self F013A-H, J-M, P&R Core spray TCK 2 12 AO F006A, B Control rod drive GB 4 1 AO FOlO, FOll, F180, F181 hydraulic supply sv 2 112 Sol (Dual) F009A 1: B, F182A & B sv 2 1 Sol Fl60A & B GT 6 1 Sol F163A A B, Fl62A-D CRD - HCU GB 2 0.5 AO 126, 127 GB 1 0.5 AO/Sol (Dual) 139 Standby liquid control GT 2 1-1/2 (2) F004A, B RCIC - turbine steam OB 1 3 ID HV: 4282 RCIC - turbine steam GB 1 3 HO FV: 4283 Neutron monitoring BL 5 .375 Sol J004A-1 thru -5 Neutron monitoring GT 5 .375 (2) J004B-1 thru-5 Residual heat removal TCK 6 12 AO F041A-D & F050A, B HPCI - turbine steam GT 1 10 M:) FV: 4880 HPCI - turbine steam GT 1 10 HO FV: 4879 (1) Definition of symbols: BL - ball valve ID - motor operator BF - butterfly valve HO - hydraulic operator GB - globe valve Sol - solenoid operator GT - gate valve DIA - diaphragm valve TCK - testable check valve B/H - electro hydraulic PSV - pressurerelief or safety valve SV - solenoid valve way AO - air operator (2) Explosive valve. 1 of 1 HCGS-UFSAR Revision 0 April 11, 1988

NON-NSSS ACTIVE PUMPS Identification as Shown on Component Nmpe Appliqable FiJUres SACS pump 1A-P210 1B*P210 1C-P210 1D-P210 Fuel pool cooling pump 1A-P211 1B-P2ll ECCS jockey pump 1A-P228 1B-P228 1C-P228 1D-P228 Control room chilled water 1A-P400 circulation pump 1B-P400 Diesel fuel oil transfer 1A*P401 pump 1B-P401 1C-P401 1D-P401 1E-P401 1F-P401 1G-P401 1H-P401 Motor driven diesel fuel oil 1A-P402 (1A-G400)(l) pump 1B-P402 (1B-G400) 1C-P402 (1C-G400) 1D-P402 (1D-G400) 1 of 4 HCGS-UFSAR. Revision 0 April 11, 1988

TABLE 3.9*17 (Cont)

• Compopent Name Rocker arm motor driven Identification as Shown on Applicable Figures 1A-P406 {1A-G400) prelube pump 1B-P406 (1B-G400) 1C-P406 (1C-G400) 1D*P406 (1D-G400)

Lube oil keepwarm pump 1A-P407 (1A-G400) 1B-P407 (1B-G400) 1C-P407 (1C-G400) 1D-P407 (1D-G400) Jacket water keepwarm 1A-P410 (1A-G400) pump 1B-P410 (1B-G400) 1C*P410 (1C-G400) 1D-P410 {1D-G400) Water chiller oil pump 1A-P412 (1A-K400) 1B-P412 (1B-K400) Water chiller pumpout pump 1A-P413 (1A-K400) 1B-P413 (1B-K400) lE panel room chilled 1A-P414 water pump 1B-P414 Water chiller oil pump 1A-P416 (1A-K403) 1B-P416 {1B-K403) Water chiller pumpout pump 1A-P417 (1A-K403) 1B-P417 (lB-1<403)

• HCGS-UFSAR 2 of 4 Revision 0 April 11, 1988

TABLE 3.9*17 {Cont)

• Component Name Station service water Identification as Shown on Applicable Figures 1A*P502 pump 1B*P502 1C*P502 1D-P502 Spray water booster pump 1A*P507 1B*P507 1C-P507 1D*P507 Rocker arm lube oil 1A*P403 (1A-G400) engine driven pump 1B-P403 {1B-G400) 1C-P403 (1C-G400) 1D-P403 (1D-G400)

Engine driven diesel fuel 1A-P404 (1A-G400) oil pump 1B-P404 (1B-G400) 1C-P404 (1C-G400) 1D-P404 (1D-G400) Engine driven fuel oil 1A*P405 (1A-G400) pump 1B-P405 (1B-G400) 1C*P405 (1C-G400) 1D-P405 (1D-G400) Engine driven jacket water 1A-P408 (1A-G400) pump 1B-P408 (1B-G400) 1C-P408 (1C-G400) 1D-P408 (1D-G400) 3 of 4 HCGS*UFSAR Revision 0 April 11, 1988

TABLE 3.9-17 (Cont}

• Component Name Identification as Shown on Applicable Fieures Engine driven cooling water 1A-P411 {1A-G400) pump 1B-P411 (1B-G400) 1C-P411 {1C-G400) 1D-P411 {1D-G400)

{1) Pump is located on skid noted in parenthesis .

• HCGS-UFSAR 4 of 4 Revision 0 April 11, 1988

TABLE 3.9-18 NON-NSSS ACTIVE VALVES Valve Size, (1) (1) S:t:stem ~-- QuantitJ:: in. Actuation-- Valve Identification Number Main steam GB 1 2 MO F071 Main steam GT 2 3 MO F016, F019 Main steam CK 22 1 Self V043 thru VOSS; V109 thru V114 Main steam PSV 28 6 Self F037A-H, J-M, P&R; 4500A-H 1 J-M, P&R Feedwater CK 1 4 MO F039 Feedwater CK 2 24 MO F032 A, B Feedwater CK 2 24 AO F074 A, B Feedwater CK 2 24 Self V003, V007 Feedwater TCK 2 4 Self Vl27, Vl2B Condensate transfer and storage GT 1 10 MO FOll Condensate transfer and storage TCK 8 3 Self V036, V037, V039, V040, voso, V051, V060, V061 Condensate transfer and storage TCK 9 4 Self V005, V042, V043, V045, V046, V054, voss, V057, voss Condensate transfer and storage TCK 1 10 Self V003 Reactor recirculation CK 2 .75 Self V043, V047 RHR BF 2 18 MO F048A, B RHR CK 10 1 Self V089, V090, V194, V195, V206, V207, V208, V210, V211, V260 RHR CK 5 2 Self V308, V309, V312, V313, V423 RHR CK 4 18 Self V002, V008, V099, V105 I RHR GB/SV 6 2 .AQ F122A, B; Fl46A-D RHR GB 1 4 MO F040 I RHR GB 2 6 MO F027A, B RHR GB 2 12 MO F015A, B RHR GB 6 18 MO F003A, B; FOlOA, B; F024A,B RHR GT 6 4 MO F007A-D; F049, 4439 RHR GT 1 6 MO F075 I RHR GT 4 12 MO F017A-D RHR GT 4 16 MO F016A, B; F021A, B RHR GT 4 18 MO F006A, B; F047A, B RHR GT 2 20 MO F008, F009 RHR GT 4 24 MO F004A-D RHR TCK 4 4 self V030, V033, Vl27, V130 RHR TCK 1 6 Self V038 1 of 6 HCGS-UFSAR Revision 14 July 26, 2005

TABLE 3.9-18 (Cont) Valve Size, Type(1) Quantit;r Actuation(!) Valve Identification Number S~tem ~ RCIC CK 2 1 Self V028, V029 RCIC CK 2 2 Self V006, V023 RCIC CK 1 6 Self V010 RCIC GB 2 2 m F019, F046 RCIC GB 1 4 m F022 RCIC GT 4 6 r-D FOlO, F012, F013, F031 RCIC TCK 2 6 Self V002, V004 Core spray CK 4 12 Self V013, V014, V015, V016 Core spray GB/SV 2 2 AD F039A, B Core spray GB 2 4 m F031A, B Core spray GB 2 10 K) F015A, B Core spray GT 4 12 K) F004A, B, F005A, B Core spray GT 4 16 I'll FOOl A-D Core spray TCK 4 3 Self V028, V030, V032, V034 Control rod drive hydraulic supply GB 2 2 m 3800 A, B Reactor water cleanup GT 2 6 K) FOOl, F004 Reactor water cleanup CK 1 4 M) F039 Standby liquid control CK 3 1 1/2 Self V004, V005, V029 Standby liquid control GCK 2 2 m F006A, B I:IK:I CK 2 1 Self V014, V023 I:IK:I CK 1 2 Self V027 I:IK:I CK 1 14 Self V003 1m:I GB 5 2 I'll F059, 4803, 4804, 4865, 4866 I:IK:I GB 1 4 m F012 HPCI GB 1 10 K) F008 tm:I GT 1 8 M) 8278 I:IK:I GT 2 14 m F006, F007 HFCI GT 2 16 00 FOOtl, F042 I:IK:I TCK 1 4 Self V015 HFCI TCK 2 16 Self V006, VOOB Station service water BF 2 3 MJ 2234, 2236 Station service water BF 6 6 00 F073, 2197A-D, 2238 Station service water BF 2 20 MJ 2356 A, B Station service water BF 5 24 ID 2355A, B; 2371A, B; 2207 Station service water BF 4 28 00 2198 A-D Station service water BF 2 30 ill 2203, 2204 Station service water CK 3 2 Self V543, V556, V557 Station service water CK 4 2 Self V544 thru V547 2 of 6 HCGS-UFSAR Revision 0 April 11 , 1988

                                                                                                           )

TABLE 3.9-18 (Cont) Valve Size, St:stem Quantity in. Valve Identification Number Station service water CK 4 28 Self V359, V361, V363, V365 Fuel pool cooling and cleanup CK 2 6 Self V007, V040 Fuel pool cooling and cleanup CK 1 8 Self V015 Fuel pool cooling and cleanup GB 2 2 MO 4647, 4648 Fuel pool cooling and cleanup GB 2 6 MO 4689A, B Fuel pool cooling and cleanup GT/SV 3 8 AO 4676A, B; 4678 RACS GT 4 4 MO 2553, 2554, 2555, 2556 Torus water cleanup GT 4 6 MO 4679, 4652, 4 680, 4681 SACS BF 8 8 MO 2314A, B; 7921A, B; 2317A, B; 7922A, B SACS BF/SV 4 8 AO 2395A-D SACS BF 4 20 MO 2512A, B; 2457A, B I SACS BF 8 30 MO 2491A, B; 2494A, B; 2496A-D SACS BF/SV 4 30 HO 2522A-D SACS CK 4 2 Self V704, V705, V706, V707 SACS CK 4 20 Self VOlO, V013, V016, V019 SACS CK 2 30 Self V029, V031 SACS GB/SV 6 2 AO 2293A, B; 2520A-D SACS BL/SV 18 3 AO 2325A-H, 2290A-H, 2292A,B SACS BL/SV 6 4 AO 2302A-F SACS BL/SV 8 6 AO 2398A...:.H SACS GB 10 2 MO 2452A,B; 2320A, B; 2453A,B; 2321A,B 2446; 2447 Station service water screen wash BF 4 6 MO 2225A-D Station service water screen wash CK 4 6 Self V003, VOlO, V016, V023 RCIC turbine steam CK 1 2 Self V010 RCIC turbine steam GB 2 2 MO F060, F076 RCIC turbine steam GB/SV 3 2 AO F004; F025; F026 RCIC turbine steam GB 1 4 MO F045 RCIC turbine steam GT 2 3 HO F062; F084 RCIC turbine st:eam GT 2 4 HO F007; F008 RCIC turbine steam GT 1 10 HO F059 RCIC turbine steam TCK 1 10 Self V003 RCIC turbine steam sv 1 1 SOL F054 HPCI turbine steam CK 2 2 Self V032,. V038 HPCI turbine steam GB/SV 3 2 AO F026, F028, F029 HPCI turbine steam GB 1 2 MO F100, 4922 HPCI turbine steam GT 2 3 MO F075, F079 HPCI turbine steam TCK 1 20 1 Self V004 3 of 6 HCGS-UFSAR Revision 19 November 5, 2012

TABLE 3.9-18 (Cont) Valve Size, (1) (1) system ~- Quantity in. Actuation-- Valve Identification Number Chilled water GT 88 MO 9531A-l thru -4; 9531B-1 thru -4 Containment atmosphere control BF/SV 1 6 AO 4978 Containment atmosphere control BF/SV 6 24 AO 4958, 4962, 4964, 4980, 5029, 5031 Containment atmosphere control BF/SV 4 26 AO 4950, 4952, 4956, 4979 Containment atmosphere control CK 6 1 Self V054, voss, V081, V093, Vl38, Vl39 Containment atmosphere control GB 25 2 MO 4951, 4955A, B; 4983A, B; 5019A, B; 4984A, B; 4959A, B; 4965A, B; 4966A, B; 5022A, B; 4974; 4963; 5055A, B; 5057A, B. Containment atmosphere control GT 4 4 MO 50SOA, B; 5052A, B Containment atmosphere control GT 4 6 MO 5053A, B, 5054A, B Containment atmosphere control CK 8 24 Self 4946 A-H FRVS CK 2 1 Self V032 Liquid R/W GT 4 3 MO F003; F004; F019; F020 Liquid R/W GT 2 4 MO 5262, 5275 Solid radwaste GT 13 MO 5551 Diesel fuel oil transfer CK 16 2 Self VOOl thru VOOB; V095 thru V098; V121 & storage thru V124 Primary containment CK 21 Self voos, V006 instrument gas Primary containment CK 4 2 Self V023, V024, V217, V219 instrument gas GB 13 2 MO 5147; 51413, 5160A, B; 5126A, B; 5152A, B; 5162; 5124A, B; 5172A, B; Primary containment GT 7 2 AO 5156A,B; 5154; 5155; I instrument gas CK 2 1/2 Self V223, V224 Neutron monitoring Neutron monitoring GB/SV CK 1 1 2

                                                 .375 AO Self 5161 V006 I

Steam leak detection GB 42 MO 5018, 4953, 4957, 4981 Reactor recirculation GB 2 .75 Sol SV-4310, 4311 4 of 6 HCGS-UFSAR Revision 12 May 3, 2002

TABLE 3.9-18 (Cont} Valve Size, (1)

                              ~-       Quantity RRR                            GB       1           1       Sol  SV-F074 RRR                            GB       4           .75     sol  SV-F079A, B; F080A, B RRR                            BF       2           18      MO   F048A, B Station service water          GB       7           1       Sol  SV-2235, 2237, 2239, 2247A-D, station service water          GB       4           2       sol  SV-2367A-D Safety and turbine auxiliaries BF/SV    2           20      AO   TV-2517A, B cooling Safety and turbine auxiliaries GB       4           1       Sol  2281-1, -2; 2288-1, -2 cooling RCIC turbine steam             GB/SV    1           1       AO   LV-F005 RCIC turbine steam             GB       1           2       Self PCV-F015 HPCI  turbine steam            GT       3           10      MO   FOOl, F002, F003 HPCI turbine  steam            GT       1           20      MO   F071 HPCI turbine  steam            GB/SV    1           1       AO   LV-F025 HPCI  turbine steam            SV       1           1       Sol  F054 I

HPCI turbine steam GB 1 2 Self PCV-F035 I Primary Cent-Instrument Gas GT 2 2 Sol 5157A,B Aux. Building Chilled Water sv 4 4 E/H TV-9637A,B; TV-9667A,B Aux. Building Chilled Water SV 2 6 E/H TV-9634A,B Aux. Building Chilled Water GT 2 1 1/2 E/H TV-9768A,B Aux. Building HVAC sv 8 1 Sol 9588AA, AB, BA, BB; 9589A,B; 9598A,B FRVS GT 1 8 MO 9451 FRVS SV 10 1 Sol 9370A,B; 9372A,C; 9395A,B; 9414A,B; 9450A,B Standby Diesel Engines GB 20 1 Sol 6615A-D; 7534A-D; 7535A-D; 7536A-D; 7537A-D 5 of 6 HCGS-UFSAR Revision 12 May 3, 2002

( ( TABLE 3.9-18 (Cont) (1) Definition of symbols used: Bf - butterfly valve CK

• check valve GB - globe valve GCK - globe (stop check) valve GT - gate valve TCK - testable check valve AO
• air operator HO -hydraulic operator MO - motor operator SOL - solenoid operator.

SV - solenoid valve way E/H- electro-hydraulic BL - ball valve 6 of 6 HCGS-UFSAR Revision 9 June 13, 1998

• EXTRAPOLATION OF TESTED Size of Qualified Valve NON~NSSS VALVE TO OTHER SIZES Qualification Extends *To:

v 0.5 1 1.5 23468 10 12 14 16 18 20 22 24 26 28 30 36 1 XXX 15XXX 2 XXX 3 XXX 4 XXX 6 XXX 8 XXXX 10 XX X X 12 XXXXX 14 XXXXXX 16 XXXXXX 18 XXXXXX 20 XXXXXXXX 1 of 2 HCGS~UFSAR Revision 0 April 11, 1988

TABLE 3.9-19 (Cont)

• l Size of Qualified Valve v 0.5 1 1.5 23468 Qualification Extends 10 12 14 16 To~

18 20 22 24 26 28 30 36 22 X X X XX XXX 24 X X X XX XX 28 XXXX X X X 30 X X X X X X 36 XXXX

• HCGS-UFSAR 2 of 2 Revision 0 April 11, 1988

TABLE 3. 9-20 DESIGN LOADING COMBINATIONS FOR SUPPORTS FOR ASME B&PV CODE CLASS 1, 2 AND 3 NON-NSSS COMPONENTS Design Loading Condition Combinations (l)( 2 ) Allowable Stress Hydrostatic test (a) HTDW 0.8 sy Normal and upset 2 2 1 2 (a) DW+TH+(OBE +RVC ) / ASME Section III, Appendix XVII (b) DW+TH+OBE+RVO (c) DW+TH+FV Emergency ASME Section III, Appendix XVII Faulted (a) DW+TH+SSE+RVO ASME Section III, Appendix F( 4 ) (1) Loads due to OBE, SSE, and DBA include both inertia portion and anchor movement portion when spectra method is used. The loads from the inertia portion and anchor movement portion are combined by the SRSS method. (2) For torus attached piping, the loading combinations used in evaluating the pipe support loads are those given in the Plant 1 of 2 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.9-20 (Cont)

• Unique Analysis Application Guide (PUAAG) (NED0-24583-1, October 1979 (Table 5-2)).

(3) Definition of symbols used: HTDY - piping dead weight due to hydrostatic test TH reaction at the support due to thermal expansion of the pipe DY - dead weight OBE - operating basis earthquake(l) RVC - transient response of the piping system associated with relief valve opening in a closed system RVO - transient response of the piping system associated with relief valve opening in an open system FV - transient response of the piping system associated with fast valve closure time less than 5 seconds SSE - safe shutdown earthquake(!) DBA - design basis accident(!) (4) For essential safety-related (ESR} systems allowable stress not to exceed S . , y

• HCGS-UFSAR 2 of 2 Revision 0 April 11, 1988

TABLE 3.9-21 DEFORMATION LIMIT (FOR ESF REACTOR INTERNALS ONLY} l Either One of (Not Both) General Limit

1. Permissible deformation. DP 0.9 l

Analyzed deformation SFm~n [ causing loss of functiont D~

2. Permissible deformation, DP (l) 1.0 Experimental deformation SFm~n

[

          ~ausing  loss of function, DE where:

DP - permissible deformation under stated conditions of service levels A, B, C, or D (normal, upset, emergency, or faulted) DL - analyzed deformation that could cause a system loss of function{ 2 ) DE - experimentally determined deformation that could cause a system loss of function SF

• minimum safety factor (see Section 3.9.5.3.5) m~n (1} Equation b. is not used unless supporting data are provided to the NRC by General Electric.

(2) "Loss of function" can only be defined quite generally, until attention is focused on the component of interest. In cases of interest, where deformation limits can affect the function of equipment and components, they are specifically delineated . 1 of 2 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3.9-21 (Cont)

• From a practical viewpoint, it is convenient to interchange some deformation condition at which function is assured with the loss of function condition if the required safety margins from the functioning conditions can be achieved. Therefore, it is often unnecessary to determine the actual loss of function condition, because this interchange procedure produces conservative and safe designs. Examples where deformation limits apply are: control rod drive alignment and clearances for proper insertion; core support deformation causing fuel disarrangement, or excess leakage of any component .
• HCGS-UFSAR 2 of 2 Revision 0 April 11, 1988

TABLE 3.9-22 PRIMARY STRESS LIMIT (FOR ESF REACTOR INTERNALS ONLY) Any One Of (No More Than One Required) General Limit 1. Elastic evaluated primary stresses. PE

s; 2.25 Permissible primary stressesJ PN SFm1n.

2. Permissible load. LP

[ Largest low~r bound limit load, CL ] :S 1.5 SF . mJ.n

3. Elastic evaluated primary stresses. PE < 0.75 Conventional ultimate strength SF .

mJ.n at temperature, US

4. Elastic plastic evaluated nominal primaty stress. EP < 0.9 Conventional ultimate strength SF .

mJ.n at temperature, US

5. Permissible load, LP :s; 0.9

[ Plastic instability load, PL SF . mJ.n (1)

6. Permissible load, LP :s; 0.9 Ultimate load from fracture SF .

mJ.n analysis, UF

7. Permissible load, LP :s; 1. 0 Ultimate load or loss of function SF .

[ m1n load from test, LE 1 of 4 HCGS-UFSAR Revision 0 April llJ 1988

TABLE 3.9-22 (Cont) where: PE- primary stresses evaluated on an elastic basis. The effective membrane stresses are averaged through the load carrying section of interest. The simplest average bending, shear, or torsion stress distribution that support the external loading are added to the membrane stresses at the section of interest. PN - permissible primary stress levels under service level A or B (normal or upset) conditions under ASME B&PV Code, Section III LP - permissible load under stated conditions of service levels A, B, C, or D (normal, upset, emergency, or faulted) CL - lower bound limit load with yield point equal to l.SS m, where S is the tabulated value of allowable stress at temperature as m contained in ASME B&PV Code, Section III. The "lower bound limit load" is defined as that produced from the analysis of an ideally plastic (nonstrain hardening) material, where deformations increase with no further increase in applied load. The lower bound load is one in which the material everywhere satisfies equilibrium, and nowhere exceeds the defined material yield strength, using either a shear theory or a strain energy of distortion theory to relate multiaxial yielding to the uniaxial case. US - conventional ultimate strength at temperature or loading, whichever is more limiting, causing a system malfunction EP- elastic plastic evaluated nominal primary stress. Strain hardening of the material may be used for the actual monotonic stress strain curve at the temperature of loading. An approximation to the actual stress strain curve that everywhere

• HCGS-UFSAR 2 of 4 Revision 0 April 11, 1988

TABLE 3.9-22 (Cont)

• has a lower stress for the same strain as the actual monotonic curve may also be used. Either the shear or strain energy of distortion flow rule is used.

PL - plastic instability load, defined here as the load at which any load bearing section begins to diminish its cross-sectional area at a faster rate than the strain hardening can accommodate the loss in area. This type of analysis requires a true stress true strain curve, or a close approximation based on monotonic loading at the temperature of loading. UF - ultimate load from fracture analyses. For components that involve sharp discontinuities (local theoretical stress concentration <3), the use of a "fracture mechanics" analysis, where applicable, using measurements of plane strain fracture toughness, may be applied to compute fracture loads. Correction for finite plastic zones and thickness effects, as well as gross yielding, may be necessary. The methods of linear elastic stress analysis may be used in the fracture analysis, where its use is clearly conservative or supported by experimental evidence. Examples of where fracture mechanics may be applied are: for fillet welds; for end of fatigue life crack propagation. LE - ultimate load or loss of function load as determined from experiment. In*using this method, account is taken of the dimensional tolerances that may exist between the actual part and the tested part, or parts, as well as differences that may exist in the ultimate tensile strength of the actual part and the tested parts. In each of these areas, the experimentally determined load uses adjusted values to account for material property and dimensional variations, each of which has no greater probability than 0.1 of being exceeded in the actual part . 3 of 4 HGGS-UFSAR Revision 0 April 11, 1988

TABLE 3.9-22 (Cont) SFm1n

     . -minimum safety factor (see Section 3.9.5.3.5)

(1) Equations 5. , 6. , and 7. are not used unless supporting data are provided to the NRC by General Electric .

• HCGS-UFSAR 4 of 4 Revision 0 April 11, 1988

TABLE 3.9-23 BUCKLING STABILITY LIMIT (FOR ESF REACTOR INTERNALS ONLY) Any One of (No More Than Qne Required) General Limit

1. *[ Permissible load. LP :S2.25 Service level A (normal) permissible ] SF .

m~n load, PN

2. [Permissible load. LP Stability analysis load, SL ] :s~

SF . mJ.n l 1

3. [ Permissible load. LP :S!..JL.

Ultimate buckling collapse load from SF . mJ.n test, SE where: LP - permissible load under stated conditions of service levels A, B, C, or D (normal, upset, emergency, or faulted) PN - applicable service level A (normal) permissible load SL - stability analysis load. The ideal buckling analysis is often sensitive to otherwise minor deviations from ideal geometry and boundary conditions, These effects are accounted for in the analysis of the buckling stability load. Examples of this are: ovality in externally pressurized shells; eccentricity in column members. SE - ultimate buckling collapse load as determined from experiment. In using this method 1 ~ccount is taken of the dimensional tolerances that may exist between the actual part and the tested part. In each of these areas, the experimentally 1 of 2 HCGS-FSAR Revision 0 April 11, 1988

TABLE 3.9-23 (Cont)

• determined load is adjusted to account for material property and dimensional variations, each of which has no greater probability than 0.1 of being exceeded in the actual part.

SF i -minimum safety factor (see Section 3.9.5.3.5) mn (l) Equation 3. is not used unless supporting data are provided to the NRC by General Electric .

• HCGS-FSAR 2 of 2 Revision 0 April 11, 1988

TABLE 3.9-24 FATIGUE LIMIT (FOR ESF REACTOR INTERNALS ONLY) Summation of fatigue damage usage with design and operation loads following Miner hypotheses(!) Limit for Service Level A and B (Normal and Upset) Cumulative Damage in Fati&Ue Design Conditions Design fatigue cycle usage from :Sl.O analysis using the method of ASME Code

• (1) M.A. Miner, "Cumulative Damage in Fatigue,n Journal of Applied Mechanics, Vol. 12, ASME, Vol. 67, pp A159-Al64, September 1945 .
• HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

TABLE 3.9-25 TYPICAL NSSS SQRT EQUIPMENT QUALIFICATION METHODOLOGY MPL Qualification Number Equipment Methodology Ell-BOOl RHR heat exchanger Response spectrum dynamic analysis Ell-C002 RHR pump motor Response spectrum dynamic analysis E21-C001 Reactor core spray pump Response spectrum dynamic analysis C41-C001 Standby liquid control pump Static analysis/Dynamic test - IEEE 344-1975 C41-A001 E41-C002 SLC tank HPCI turbine Static analysis to 1.75 g Dynamic test I E51-C002 RCIC turbine Dynamic test 145C3103 Thermometer Static analysis 145C3224 Temperature element Multi frequency, multi-axis test 159C4361 Level switch Single axis, single frequency test 163C1303 Limit switch Single frequency - multi axis test 1 of 1 HCGS~UFSAR Revision 17 June 23 1 2009

TABLE 3.9-26 EXAMPLES OF NSSS PVORT EQUIPMENT QUALIFICATION METHODOLOGY MPL Qualification Number Equipment Methodolos:y E91-C001 HPCI pump Static analysis for dynamic analysis C51-J004 Guide tube valve Single frequency - static analysis B21-F013 SRV Static analysis. comparison to other B21-F022/ MSIV Single axis/multiaxis test F028 Cll-F009/ CRD solenoid valve Single axis/multiaxis test Fl82

• HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

TABLE 3.9-27 EXAMPLES OF NON-NSSS PVORT EQUIPMENT QUALIFICATION METHODOLOGY Equipment Qualification Number Description Method Standards(l) lA, 1B-P210 SACS Pump Static A, F, I lC, 1D-P210 Analysis lA, 1B-P211 Fuel Pool Static A, F, I Cooling Pump Analysis lA, 1B-P402 Motor Driven Static F lC, 1D-P402 Diesel Fuel Analysis Oil Pump lA, 1B-P228 ECCS Jockey Static A, F, I lC, 1D-P228 Pump Analysis lA, 1B-P414 Chilled Water Dynamic A, F, I Circulation Pump Analysis lA, 1B-P408 Engine Driven Dynamic F lC, 1D-P408 Jacket Water Pump Analysis lA, 1B-P507 Spray Yater Static A, F, I lC, 1D-P507 Booster Pump Analysis 1-BC-HV-F047A 18"-GBB-GT-MO Static Analysis A, E, F, I

                                         & Dynamic Testing
                                         & Pull Test l-BE-HV-F031A    4"-GBB-GB-MO         Static Analysis     A, E, F, I
                                         & Dynamic Testing
                                         & Pull Test 1 of 3 HCGS-UFSAR                                          Revision 0 April 11, 1988

TABLE 3.9-27 (Cont)

• Equipment Number l-FC-HV-F059 Description 10"-HBB-GT-MO Qualification Method Static Analysis Standards(l)

A, E, F, I

                                     & Dynamic Testing
                                     & Pull Test 1-EE-HV-4655   6"-HBC-GT-AO         Static Analysis     A, E, F, I
                                     & Dynamic Testing
                                     & Pull Test l-AB-HV-F019   3"-DBA-GT-MO          Static Analysis     A, E, F, I
                                     & Dynamic Testing
                                     & Pull Test l-AE-HV-F074A  24"-DIA-CK-AO         Static Analysis     A, E, F, I
                                      & Dynamic Testing
                                      & Pull Test l-BD-HV-F046   2"-CBA-GB-MO          Static Analysis     A, E, F, I
                                      & Dynamic Testing
                                      & Pull Test l*EG-HV-2522A 30"-HBC-BF-HYDRAU     Static Analysis     A, E, F, I
                                      & Dynamic Testing
                                      & Pull Test 1-EG-HV-2395A 8"-HBC-BF-AO          Static Analysis     A, E, F, I
                                      & Dynamic Testing
                                      & Pull Test l-EA-HV-2356A  20"-HEC-BF-MO        Static Analysis     A, E, F, I
                                      & Dynamic Testing
                                      & Pull Test 2 of 3 HCGS-UFSAR                                        Revision 0 April 11, 1988

TABLE 3.9-27 (Cont)

• (1) Standards A- IEEE-344-1975 F - ASME B&PV Code, Section III I - NRC Regulatory Guide 1.100, Rev. 1 E - IEEE 382, 1972
• HCGS-UFSAR 3 of 3 Revision 0 April 11, 1988

TABLE 3.9-28 NON-NSSS VALVES SUBJECTED TO HYDRODYNAMIC LOADS 1-BE-HV-FOOlA to D 1-FC-HV-F059 1-BJ-HV-F042 1-FD-HV-F071 1-EE-HV-4680 1-EE-HV-4681 1-BD-HV-F031 1-BC-HV-F004A to D 1-EE-HV-4652 1-EE-HV-4679 1-GS-HV-4958 1-BE-HV-F015A and B 1-BC-HV-F024A and B 1-BC-HV-4421 1-BC-HV-4420A and B 1-BE-HV-F031A 1-BJ-HV-F012 1-FD-HV-F079 1-FD-HV-F075 1-BC-HV-F007C 1-AB-PSV-F037A to H 1-AB-PSV-F037J to M 1-AB-PSV-F037P, Q, R 1-AB-PSV-4500A to H 1-AB-PSV-4500J to M 1-AB-PSV-4500P, Q, R l-BD-SV-F019 l-GS-PSV-4946A to H 1-BJ-HV-4865 1-BJ-HV-4866 1-BJ-HV-4804 1-FC-HV-F060 1 of 1 HCGS-UFSAR Revision 0 April 11, 1988

TABLE 3. 9-2 9 SRV WATER CLEARING REACTION LOADS ON RAMSHEAD SUPPORT Reaction Loads Value (kips) Horizontal load perpendicular to the plane 10.4 of the ring girder Horizontal load parallel t:o the plane 18.59 of the ring girder Vertical load 83.12

• HCGS-UFSAR 1 of 1 Revision 0 April 11, 1988

80 M

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8 0 0 0 co CD REVISION0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION TRANSIENT TEMPERATURE RESPONSE UPDATEDFSAR FIGURE3.9-1

STEAMSEPARATOR}SHROUDHEAD-STEAM STEAMSEPARATOR SEPARATORASSEIVfSLV STAN_DPIPE . SHROUDHEAD

                                                                                 ,,__ _ FEEDWATERINLETNOZZLE POWER RANGEDETECTOR                             .....;,.__..;'IIIL..-......rl'I1~-H--t----- FUELASSEMBLY OR SRM/IRMDRY TUBE-----1+++       ........- .....

JETPUMPDRIVINGNOZZLEASSEMBLY W-.1*-t+-+----; JETPUMPSUCTIONINLET RECIRCULATING WATER INLET NOZZLE---(;;:::~,..11 VESSELWALL----.! RECIRCULATING WATER IN-COREFLUXMONITORGUIDE 114----- OUTLETNOZZLE CONTROLROD GUIDETUBE- - - - t r t ' 7 REACTORVESSEL V - l l i - - - - -SHROUDSUPPORT JETPUMPBELLOWSSEAL

                                                                            ~----- CONTROLROD DRIVEHOUSING REVISION0 APRIL 11. 1988 IN*COREFLUXMONITOR.HOUSING- -....*                                        PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORVESSELCUTAWAY UPDATEDFSAR                     FIGURE3.S.2

• REACTORCORE SPRAY COOLINGSPARGERS CORE SHROUD NOZZLE DOWNCOMERFLOW FLOODABLE SUCTIONCHAMBER 'VOLUME THROAT (MIXINGSECTION)

REVISION 0 APRIL 11. 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION REACTORINTERNALS FLOWPATHS UPDATEDFSAR FIGURE3.9-3

• FUELASSEMBLY PERIPHERALFUELSUPPORT (NONREMOVABLE)

ORIFICEGUIDE CORE PLATEASSEMBLY ORIFICEDFUELSUPPORT (ONE ORIFICESHOWN) ORIFICE SPRING COOLANTFLOW PERIPHERALFUELSUPPORT ORIFICE FUELASSEMBLY ORIFICED.FUEL SUPPORT GUIDETUBE AND FUELSUPPORTALIGNMENT PIN CORE PLATE ORIFICE(1 OF 4) COOLANTFLOW

                     ~-------           CONTROLROD GUIDETUBE REVISION0 APRIL 11. 1988
 .-.------CENTER        LINEOF F.UELSUPPORT PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION FUELSUPPORTS UPDATEDFSAR                  FIGURE3.9-4

DRIVE N$)ZZLE SUCTION INLET THROAT INLET RISER PIPE INJ..ET DIFFUSER 0 OUTLET...__ ___, PUBi.JCSERVICEELECTRICAND GAS COMPANY HOPECREEKNUCLEARGENERATING STATION JETPUMP Note:JetPumpa8,9, and15have ctamps lmstaled aroundthe diffuser the instrument to support UpdatedFSAR Sheet1 of 1 sensing lne bNer bracket. Revision

9. June13. 1998 Figure3.9-5

UPPER SHROUD I I COllE SUPPORT ASSEMBLY Ow

              ~~

ow

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0 LOWER PLENUM 8" REVISION 0 APRIL 11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK NUCLEAR GENERATING STATION PRESSURENODESUSED FOR DEPRESSURIZATION ANALYSIS UPDATEDFSAR FIGURE3.9-6

I< lr'.

 ~.Y'      28"STEAMLINE"B" LEGEND FOR LARGE PIPE SUPPORTS
                            ~   HANGERNO.

RIGIDHANGER SPRINGHANGER ANCHOR

                         --{    RESTRAINT
                         ...o{  SNUBBER VENTPIPEPENETRATION REVISION 0 APRIL11, 1988 PUBLIC SERVICE ELECTRIC AND GAS COMPANY HDPE CREEK NUCLEAR GENERATING STATION REPRESENTATIVE     SRV PIPING SYSTEMIN THE DRYWELL UPDATEDFSAR

REACTOR PRESSURE VESSEl. PSV*F013E MAINSTEAM}}