LR-N17-0034, Salem Generating Station, Units 1 & 2, Revision 29 to Updated Final Safety Analysis Report, Section 3.6, Protection Against Dynamic Effects Associated with the Postulated Rupture of Piping

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Salem Generating Station, Units 1 & 2, Revision 29 to Updated Final Safety Analysis Report, Section 3.6, Protection Against Dynamic Effects Associated with the Postulated Rupture of Piping
ML17046A289
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3.6 PROTECTION AGAINST DYNAMIC EFFECTS ASSOCIATED WITH THE POSTULATED RUPTURE OF PIPING 3.6.1 Systems In Which Design Basis Piping Breaks Occur Design basis piping breaks are postulated to occur in the following systems: 1. Reactor Coolant Loop, as limited by the NRC's approval of Leak-Before-Break (Reference 6 in Section 3.6.6). 2. Pressurizer Surge Line 3. Main Steam System 4. Feedwater System 5. CVC Letdown Line 6. Stearn Generator Blowdown Line 7. Steam Supply to Auxiliary FW Pump Turbine 8. CVC Charging and RC Pump Seal Injection (Onit 2 Only) 9. Heating Steam (Unit 2 Only) 10. Heating Water (Unit 2 Only) 3.6.2 Design Basis Piping Break Criteria The criteria for postulating design basis piping breaks are discussed for each system in Sections 3. 6. 4 and 3. 6. 5 where the analysis and protection of the various systems are presented. Salem Unit 1 was designed and constructed in the time frame of September, 1968 through August, 1976. The NRC's Giarnbusso letter, issued in 1972, imposed HELB 3.6-1 SGS-UFSAR Revision 24 May 11, 2009 I criteria on systems outside containment after the plant had already been designed, and major rework was required to meet these new (and changing) criteria. The guidance and criteria noted are those that evolved over time. The Main Steam (MS) and the Main Feedwater (MFW) high energy line breaks (HELBs} discussed in UFSAR Section 3.6 are for breaks containment, but rather containment. Given the above background information, explicit Salem criteria for HELBs inside containment were determined1 including the Steam Generator Blowdown (SGBD) lines. Based on this information, the criteria used for Salem MS1 MFW, and SGBD HELBs inside containment are given below. The current NRC guidance for HELBs is provided in Generic Letter 87-11 and in the latest revision to BTP MEB 3-1, attached to that Generic Letter. During the Steam Generator Replacement Project (SGRP), which the original Westinghouse Model 51 steam (SGs) with Model F SGs, the current NRC guidance was used to postulate breaks inside containment for the portions of piping modified by the SGRP. As evidenced by Generic Letter 87-11 and as noted in the "Background" discussions in MEB 3-1, the latest NRC positions are intended to utilize the available piping design information by postulating pipe ruptures at locations having relatively higher potential for failure, such that an adequate and practical level of protection may be achieved. The current HELB of the MS, MFW, and SGBD piping and the criteria used for HELBs inside containment are below. These Positions the current and basis for the Salem MS, MFW1 and SGBD lines inside containment replaced or modified by the SGRP. Note that any corresponding conformance to the BTP MEB 3-1 Sections related to pipe breaks/cracks does not constitute a commitment to conform to all the positions of the Branch Technical Position. Position I: 1) Circumferential breaks are postulated in pipe size of 1 inch. This conforms B.3.a(l) .Refer to Positions III and IV. 3.6-la SGS-UFSAR piping exceeding a to BTP MEB nominal Section Revision 24 May 11, 2009

2) Longitudinal (slot) breaks are postulated in piping 4 inches nominal pipe size and larger. This conforms to BTP MEB Section B.3.b(1). Also see Position V. 3) Leakage cracks are postulated in piping exceeding a nominal pipe size of 1 inch. This conforms to BTP MEB 3-1, Section 8. 3. c ( 1) . Refer to Position VII. Position II: A reconciliation, of the differences between the original design of the MS piping system and the as-designed for construction configuration, has been prepared in accordance with NCIG-05, Revision 1 (Guidelines for Piping System Reconciliation). Based on this reconciliation, there is no new break postulated for the MS lines inside containment. Based on these evaluations, it is concluded that no changes are required to any of the existing in-situ protective features provided for protection from a MS pipe break inside containment. Position III: Circumferential Breaks at SG Nozzle (for see Position V) breaks, Circumferential breaks are postulated at the steam generator nozzle for the MS, MFW, and SGBD (i.e., blowdown and drain) piping modified by the SGRP. This conforms to BTP MEB 3-1, Section B.l.c(2) (a). Also see the discussions in Position VI. Position IV: 0.8 (for longitudinal breaks see Position V) --1) Circumferential breaks are postulated to occur at locations where the stresses exceed 0.8 (Sh + Sa). This corresponds to BTP MEB 3-1, Section B.l. c (2) (b) (ii) . 2) The stresses in the modified MFW/SGBD lines inside containment have been confirmed and documented to be below the 0.8 criterion. A reconciliation of the MS line inside containment (see Position II) has verified that the stresses are below the 0.8 criterion. Therefore, circumferential breaks in the MS, MFW, and SGBD lines (except at the SG nozzles) are not postulated to occur. Thus there are no MS, MFW, or SGBD intermediate breaks postulated, based on the 0.8 stress criterion. 3.6-lb SGS-UFSAR Revision 18 April 26, 2000
3) Based on the NRC Generic Letter 87-11, additional arbitrary (non-stress based) intermediate pipe breaks are NOT postulated to occur in any of the high-energy piping (MS, MFW, SGBD). Position V: 1) Longitudinal (slot) breaks in the SGBD piping are not assumed to occur, since this piping is less than 4 inches nominal pipe size. This is consistent with Position I and with BTP MEB 3-1, Section B.3.b(1). 2) Longitudinal breaks in the MS and MFW piping are not assumed to occur at the terminal ends, consistent with BTP MEB 3-1, Section B.3.b(2). 3) Other longitudinal breaks in the MS or the MFW piping are not assumed to occur, except where other circumferential breaks are assumed. This is consistent with BTP MEB 3-1, Section B.3.b, which states that: "The following longitudinal breaks should be postulated in high-energy fluid system piping at the locations of the circumferential breaks specified in B.3.a .... " (BTP MEB 3-1, Section B.3.a discusses locations of circumferential breaks. The circumferential break locations for Salem MS, MFW, and SGBD are those discussed in Positions III and IV, above. Since MS and MFW circumferential breaks are only required to be postulated at the steam generator nozzles, this removes longitudinal breaks from further consideration, and is consistent with NRC BTP MEB 3-1.) Position VI: 1) The MS piping modified by the SGRP is provided as a like-for-like modification in form, fit and function. The SGRP MS piping modification does not affect the existing in-situ provisions at the MS containment penetration. 3.6-lc SGS-UFSAR Revision 24 May 11, 2009
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  • 2! MFW line inside containment: The containmAnt penetration calculations were revised considering pipe loads from the revised stress analysis calculations affected by-the SGRP, as applicable. A re-analysis of the stresses for MFW demonstrates that stresses at the containment pene-tration anchor point inside containment do not exceed 0.25 (Sh +Sa)* 3) SGBD line inside containment: A seismic anchor point is located in the existing piping between the modified blowdown piping and the containment penetration. Thus the SGRP SGBD line does not affect the existing stress analysis for the containment penetration. Position VII: Leakage ("Critical") Cracks 1) Leakage cracks are postulated at axial locations where the calculated stresses exceed 0.4 (Sh + Sal. This is consistent with NRC BTP MEB 3-2) 3) 1, Section B.1.e(2). (Note that Equations (9) and (10) of NC/ND-3653 are equivalent to Equations 12a and 13a of ANSI B31.1, 1977 Edition.) The fluid flow from a leakage crack is based on a circular opening of area equal to that of a rectangle one-half pipe diameter (OD) in length and one-half pipe wall thickness in width. This conforms to BTP MEB 3-1, Section 8.3.c(3). Leakage cracks are not postulated to occur in the MS piping modified by the SGRP, since a reconciliation of the portion of the MS line inside containment modified by the SGRP has verified that the stresses are below the 0.4 criterion. For the rest of the MS piping inside containment (see Position II), the SGRP did not modify the adequacy of the in-situ design features previously provided. 4) The effects of leakage cracks in the MFW piping installed by the SGRP, where the stresses exceed 0. 4 !Sh .,. Sa), have been evaluated and the appropriate mitigating features have been provided, where required. 5) The effects of leakage cracks of the SGBD piping installed by the SGRP, where the stresses exceed 0. 4 (Sh + Sa), have been evaluated and the appropriate mitigating features have been provided, where required . 3.6-ld SGS-UFSAR Revision 18 April 26, 2000 3.6.2.2 Unit 2 Steam Generator Replacement Activities associated with NRC Generic Letter 87-11 Modifications to the Main Steam, Feedwater and Blowdown piping were performed in order to replace the Unit 2 steam generators in 2008. The effects of these modifications upon these systems with regard to NRC Generic Letter 87-11 and NRC Branch Technical Position MEB 3-1 (Reference 4, as cited in UFSAR Section 3.6.6), are as follows: Main Steam In reattaching the main steam piping to the steam generators, the main steam limit stop (MSLS-1) tie rods attached to each of the main steam pipe 90° elbows were not restored. With the application of NRC Generic Letter 87-11, Relaxation in Arbitrary Intermediate Pipe Rupture Requirements, this permitted. Following the installation of the RSG, main steam is restraint MSR-2, located closest to the RSG main steam nozzle, was restored to the original design condition. Therefore, the main steam piping is maintained functional by restraining the pipe whip loads from a postulated main steam nozzle circumferential break (terminal end break) without compromising the function of essential equipment. Feedwater The reattachment of the Feedwater piping to the RSGs resulted in no changes to the piping geometry, materials, or existing MFW rupture restraints. Therefore, the feedwater piping is maintained functional by restraining the pipe whip loads from a postulated feedwater nozzle circumferential break (terminal end break) without compromising the function of essential equipment. Blowdown Due to the relocation of the blowdown nozzles on the RSGs, the terminal ends of the blowdown piping were correspondingly relocated. No safety related equipment is located in the vicinity of the relocated RSG blowdown nozzles; therefore, no rupture restraints are required for the terminal end breaks of the re-routed blowdown piping. 3.6-2 SGS-UFSAR Revision 24 May 11, 2009 3.6.3 Design Loading Combination Loadings on protective structures, pipe whip restraints, and other components subsequent to a postulated piping break include pipe pipe whip, jet impingement, pressurization of compartments, water flooding, and steam flooding. They are combined directly as appropriate for each case. Their combination with other loadings generally categorized as faulted condition are included in other appropriate sections in this report; for instance, for Class 2 and 3 components, in Section 3.9.2; and for Class 1 components in Section 5.2. 3.6.4 Dynamic Analysis Dynamic analyses of the Reactor Coolant System (RCS) and other high-energy fluid systems are described below. 3.6.4.1 Reactor Coolant Loop System Analysis The reactor coolant loop analysis is described in Section 3.9.1.8. 3.6-3 SGS-UFSAR Revision 24 May 11, 2009 I I (THIS PAGE IS INTENTIONALL BLANK} 3.6-4 SGS-UFSAR Revision 20 May 6, 2003
  • In order to assure the safe shutdown capability of the Salem units in the unlikely event of an RCS pipe rupture, a detailed dynamic analysis of the RCS piping and equipment supports was performed. For the design analysis, a large number of discrete break locations were postulated in the piping in order to determine the design adequacy and structural integrity under the most critical loading condition. Time dependent loadings resulting from each of the postulated breaks were calculated and applied to lumped mass models of the piping and equipment supports. All piping and structures analyzed were shown to remain stable and functional. 3.6.4.2.1 Postulated Break Locations Postulated break locations are listed in Table 3.6-1 and shown on Figure 3.6-1. The current design basis break locations postulated for the reactor coolant loop utilize the application of leak-before-break (References 8 and 9). Circumferential breaks are postulated at the loop nozzles of the accumulator lines, RHR lines, and the pressurizer surge line. The breaks were assumed to have a one-millisecond opening time in order to analytically describe an instantaneous break . 3.6-5 SGS-OFSAR Revision 23 October 171 2007 Mathematical Several mathematical models were used in order to properly assess the consequences of the pipe ruptures described above. The reactor coolant loop piping and p.d.mary equipment were modeled for the Westinghouse computer program, WES'l'DYN. 'l'he reactor coolant loop model describes the spatial geometry, lumped mass locations, and other node points as shown on Figure 3. 6-2. Stiffness characteristics of the equipment support structures were as elastic restraints in the reactor coolant loop model. The WESTDYN program computes internal member support structure reacti.ons1 nodal point deflections, and stresses, and also determines natural and norma1 modes. Supports for the steam generator and the reactor coolant pump were modeled for the or S'l'ASYS computer programs. Geometry and topology o:f the structures, properties, and orientation of all members (including appropriate constraint releases), and all support conditions were accurately represented. A typical model for an equipment support is shown on Figure 3.6-3. For blowdown analysis, the entire primary system fs represented by a two-loop SA'l'AN-STHRUS'l' reactor coolant loop hydraulic model as shown on Figure 3. 6-4. In this model, one loop represents the broken loop and the other represents the three unbroken loops combined into one with appropriate scaling factors. The hydraulic model is used to define the space-time dependent hydraulic forcing functions generated by the fluid in the primary coolant during a basis LOCA. Hydraulic forcing functions are defined throughout the reactor coolant loop at locations where there is a change in either direction or area of flow as shown on Figure 3. 6-5. Typical plots of forcing function time histories are shown on Figure 3,6-6. 3.6-6 SGS-UFSAR Revision 23 October 17r 2007 * * *
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  • 3.6.4.2.3 Solution Method (Original Design Analysis) The time-history dynamic structural performed in the following manner: of the reactor coolant loop was 1. The initial deflected position of the reactor coolant loop model was defined by using pressure analysis. 2. Natural and normal modes of the loop were determined using the WESTDYN computer program. 3. The initial deflection natural frequencies, normal modes, and time-history forcing functions were input into the Westinghouse proprietary computer program, FIXFM, to determine the time-history dynamic deflection response of the lumped mass representation of the reactor coolant loop. 4. The forces imposed upon the supports by the were obtained by 5. multiplying the support stiffness matrix and the time-history of the displacement vector at the support point . The computer program, WESTDYN-2, treated the time-history dynamic deflections at mass as an imposed deflection condition on the reactor coolant loop model and computed internal forces, deflections, and stresses at each end of the members of the reactor coolant loop piping system. For the support structures modeled, stiffness analyses were performed using the STRUDL and STASYS computer programs to obtain support stiffness matrices. These support stiffness matrices were included in the reactor coolant loop model to represent their effects on the supported system . 3.6-7 SGS-UFSAR Revision 23 October 171 2007 Membc-1r influenCE) coefficients obtained from STRUDL, member properties, and support plane loads obtained from the reactor coolant loop analysis were used in the THESSE computer program to obtain maximum internal forces and stresses in each member of the support system. 3.6.4.2.4 Results of AnaJ.ysis (Original The resulting stresses from the above outlined were compared with the stress/strain limits for the 1.\CS piping and equipment supports. In all cases studied, .stresses in critical support: elements were within yield limits afte.r* load redistribution so that the supported equipment and piping was maintained within the Faulted Condition limits. 3.6.4.3 3.6.4.3.1 Introduction An has been completed which assesses the consequences of postulated :Ln high <-me:rgy f:lu.i.d piping systnrns. /-\lthough such breaks are considered highly improbable, they were postulated to occur at selected locations in the high energy piping systems outside of the conta:Lnment. 3.6.4.3.2 Criteria Used for Analysis The analysis was based upon the guidelines recommended in the document "General Information Required for Consideration of Effects of a Piping System Break Outside of Containment" ( 1) as clarified by Reference 3. Unless otherwise noted, break location criteria recommended in Reference 2 were used where applicable to the system being evaluated. Where the aforementioned criteria were not applicable, other criteria were used which resulted in an equivalent degree of SGS-OF'SAR 3.6-8 Revision 23 October 17, 2007 * *
  • Some additional assumptions and definitions beyond those provided by Reference 1 were required to define the bounds of the analysis. These and a sum.rnary of the criteria recommended by Reference 1 are as follows: 1. High energy piping systems for Unit 1 are those whose temperature operation. whose pressure exceeds 275 psig during normal reactor For Uni c: 2, high energy piping systems are those whose exceeds 200°F or whose pressure exceeds 275 psig during normal reactor 2. Except as discussed in Sections 3. 6. 5. 2 and 3. 6. 5. 3, high energy lines were assumed to fail circumferentially or longitudinally at the following locations: a. Terminal ends of piping runs b. All locations where the summation of stresses due to listed in Reference 1 or circumferential) calculated on an elastic basis exceeded 0. 8 ( Sh S ) , or the a expansion stresses receive seismic was applied exceeded 0. 8 S . a For piping which did not the thermal expansion criteria alone c. At the two most highly stressed points between terminal ends (if two such points were not required by b above) Subsequent to the original and construction of the Generic Letter 87-11, Relaxation in Intermediate was issued. The revised BTP 3-1 eliminated consider the dynamic effects and the environmental effects from arbitrary intermediate pipe ruptures that were original plant design. 3.6-9 NRC to in the SGS-UFSAR Revision 25 October 26, 2010 Design basis cracks were postulated to occur in heating steam and heating water high energy lines at selected locations having !tlaximum stress levels. At these locations of maximum stress, the piping was encapsulated and vented outside the Auxiliary Building to from the adverse environmental effects due to steam escaping from these of postulated failure. For Cnit 1 only, basis cracks were for those systems whose pressure is !tlore than 275 psig and whose temperature is more than 200°F. 3. A single component failure was assumed to occur within the combined to attain cold shutdown for those accidents that cause protection system actuation. An exception is that for a main steam line break in the exclusion zone of the penetration area, i.e., from the containment to the MSIV, a single active failure is not judged to be credible. The active or passive nature of the single failure assumed is subject to the stipulation that during recirculation phase, one active or passive failure must be accommodated, but not in addition to a failure in the ection (an design basis). Per the Salem basis, safe shutdown is hot standby. The Salem design is not required to meet the 36 hour4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> cool down to cold shutdown requirements of NRC BTP RSB 5-l as detailed in Section 5.5.7.3.4. The plant can be maintained in a safe hot standby condition while manual actions are taken to permit achieving cold shutdown conditions. Alignment for initiating RHR decay heat removal to commence cool down c.o cold shutdown conditions can be achieved in 36 to 4 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> post accident. For fire events, cold safe shutdown is within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. SGS-UFSAR 3.6-9a Revision 25 October 26, 2010 THIS PAGE INTENTIONALLY BLANK 3.6-9b SGS-UFSAR Revision 7 July 22, 1987
4. The analysis of the effects of pipe failure performed on each postulated rupture includes the following: a. Pipe whip b. Jet impingement and thrust reaction c. Water flooding d. Steam flooding e. Compartment pressurization 5. No other accident was assumed to occur concurrently with the pipe failure outside of containment. For high energy lines as defined in this section under item 2, analyses have been made to assure that occurrence of design basis cracks would not result in loss of plant safety functions. 3.6.4.3.3 Analytical Models and Techniques Several analytical models and techniques were utilized for the analyses. The principal models used were: 1. Pipe Stress Analysis Stress analysis for selection of pipe break locations was performed using the Franklin Institute Research Laboratory's PIPDYN program. The program provides automatic summation of longitudinal stresses due to dead weight, internal pressure, thermal expansion, and earthquake (where applicable) at all points of interest. Stress intensification and flexibility 3.6 10 SGS-UFSAR Revision 7 July 22, 1987 c effects were included in accordance with the provisions of ANSI B31.1. 2. Piping Slowdown Models Mass and ene:r:gy flow :r:atea fo:r: pure steam and eatu:r:ated water piping ruptures were calculated using the Moody blowdown model. For fluids aubcooled in excess of 30 atu/Lbm, isentropic incompressible fluid flow theory was utilized. A discharge coefficient of 1.0 was used for circumferential and full longitudinal breaks, and a discharge coefficient of 0.6 was used for crack-1 ike openinqs. Resultant environmental conditione were calculated assuming adiabatic expansions from the source pipes. Ho credit for local heat losses was taken. 3. Pipe Whip Model Pipe whip momentum thrust forces were calculated using the relationship: Fj where: Fj A K c SCS-UI'SAR "' --= jet reaction force (lbf) 2 break area (in ) thrust coefficient 1.26 for saturated ateam or saturated water = 2.0 for suhcooled water -discharge coefficient 3.6-11 Revision 7 July 22, 1987 1.0 for circumferential or full longitudinal breaks ... 0.6 for crack-like breaks p2 ... pressure of fluid in pipe, psiq p = local atmospheric pressure a 4. Jet Impingement Model Jet impingement forces were calculated using the relationship: FI = where: FI = F. = J CD = X = F. CD X ) Impingement force on the target total jet force calculated in 3 above drag coefficient, a function of target shape. fraction of jet intercepted by target, assuming a 10 degree jet divergence half-angle for gases, 0 degree divergence half-angle for liquids. s. Compartment Pressurization Analysis Model Steady state compartment pressures were calculated using the piping blowdown models described in 2 (above), for defining fluid influx rates, and isentropic flow models to define gas efflux rates. 3.6-12 SGS-UFSAR Revision 16 January 31, 1998 3.6.5 Protective Measures 3.6.5.1 Nuclear Components The arrangement of safety-related equipment for this plant was developed in accordance with Preliminary Safety Analysis Report commitments made at the time of the receipt of the Construction Permit. Even though there were no industry wide or governmental standards in effect at the time, due consideration was given to providing assurance that engineered safety features within the containment are adequately protected in the unlikely event of an accident. This protection is in the form of barriers, supports, restraints, and/or physical separation, as necessary. 3.6.5.1.1 Barriers The polar crane wall and the refueling floor serve as barriers between the reactor coolant loops and the containment liner. The 3 foot thick wall, which extends from Elevation 81 feet to 130 feet, acts as a barrier between the containment liner and the sources of jet forces, pipe whip, and missiles associated with a failure of the RCS. All "essential components" (safety-related components in the containment which are required for operation during an accident) are located behind these missile barriers and therefore, are not subject to damage resulting from the dynamic effects associated with a LOCA. The annulus between the reactor cavity and the missile barrier is subdivided into two compartments by the refueling cavity, one for each pair of reactor coolant loops, to prevent the proliferation of dynamic effects extending beyond a two loop compartment. The steam and feedwater lines are protected from LOCA associated dynamic effects throughout their length. Above Elevation 130 feet these lines are protected by their structural steel restraints. Below Elevation 130 feet the steam and feedwater lines are routed where possible behind barriers which protect the containment liner from the steam or feedwater lines as well as the steam or 3.6-13 SGS-UFSAR Revision 7 July 22, 1987 feedwater line from the reactor coolant loops. The steam and feedwater lines associated with a given steam generator separated. are A missile barrier has been installed around that portion of the pressurizer that extends above the loop compartment. This barrier will prevent potential missiles from reaching the containment liner, engineered safeguard pipes, or essential equipment which is located outside the reactor compartments. 3.6.5.1.2 Arrangement All safety injection lines have check valves located as close as possible to the reactor coolant loop connection. The check valves effectively shorten the reactor coolant pressure boundary and minimize pipe whip. All safety injection piping with the exception of the individual branch lines which feed a given reactor coolant loop is located outside the containment missile barrier. Check valves +on the Residual Heat lines and the normally closed motor Removal (RHR) pump discharge operated gate valve on the RHR pump suction line have been located as close as possible to the reactor coolant loop connections thereby shortening the length of pipe containing pressurized water. A check valve is located close to the connection to the main pressurizer spray to minimize length of pipe whose rupture would result in a LOCA. Size of line and routing prevent damage from pipe whipping. Two check valves on each reactor coolant pump seal water injection line are located inside the missile barrier close to the pump connections to minimize pipe whip. 3.6-14 SGS-UFSAR Revision 7 July 22, 1987 (

All sample lines have normally barrier. Whipping could result closed valves, located inside the missile if a rupture occurred between the reactor coolant loop and the closed valves. The size of the sample lines and the pipe routing are such that subsequent damage to other piping would not occur even if whipping occurred. Equipment located inside the containment which is required for operation during a LOCA1 such as the containment spray piping, containment isolation valves, containment fan cooling units, essential electrical cables and instrumentation are all located between the missile barriers. 3.6.5.1.3 Restraint Where physical arrangement and barriers were ascertained to be and/or to offer insufficient protection, physical restraint of provided on reactor coolant, main steam, and feedwater lines. impractical piping was In the original design, circumferential and longitudinal ruptures of the reactor coolant loop and surge line were postulated at of change in direction, and restraint has been provided to pipe whip from occurring (see Figure 3. 6-7). Note that for the reanalysis of the RCL, as a result of the application of leak-before-break, the breaks in the primary piping are eliminated. Breaks postulated for the RCL analysis are the accumulator line at the loop nozzle, RHR line at the loop nozzle, and the pressurizer surge line at the loop nozzle (see Table 3. 6-1). The reactor vessel and steam generator supports have been designed to prevent an initial rupture of a reactor coolant loop from causing the failure of another reactor coolant loop, or a steam or feedwater line. Also the steam support system prevents a reactor coolant hot leg rupture from causing the failure of the cold leg and vice-versa as well as a steam or feedwater rupture from damaging a reactor coolant line. All lines connected to the reactor coolant loop, wall. which penetrate the containment wall, have been anchored to the crane Each anchor has been designed to be stronger than the pipe. Should a reactor coolant loop rupture occur, the resulting jet force will therefore not be transferred to the containment wall through any branch lines. 3.6-15 SGS-UFSAR Revision 24 May 11, 2009 The charging and letdown lines are normally opened to the reac;:or and their rupture could result in whipping within a loop compartment. The lines are small, however, and therefore unable 1:0 damage the large reactor coolant lines. Both lines are anchored to the missile barrier to prevent containment damage from RCS break forces being transferred through the charging or letdown lines. Safety injection piping which penetrates the containment has either been anchored at the missile barrier wall to prevent a reactor coolant loop rupture from breaching the containment through the safety injection line or has been routed to assure that loop rupture forces cannot transfer sufficient loads back to the containment wall through the safety injection line to cause a breacr.. All RHR lines penetrating the missile barrier have been anchored to the missile barrier wall to prevent reactor coolant pipe rupture forces from being transferred the containment through the RHR branches. The portions of the steam and feedwater lines not routed within barriers are restrained to prevent pipe whip. Main steam and feedwater lines have been anchored at and restrained outside the containment so that rupture will not affect containment integrity. (See figures 3.6-8, 3.6-9, and 3.6-10.) 3.6.5.1.4 Protective Measures Evaluated for Salem Unit 1 Main Stearn, Main Feedwater, and Steam Generator Blowdown as a Result of the Steam ( Generator Replacement Project ll A deficiency has been resolved to include the effects of the MS terminal end break at the steam generator nozzle on the MS/MFW pipe whip restraint structure. 2! A MFW pipe whip restraint has been designed, analyzed, and provided to mitigate a circumferential rupture of the MFW line at the steam generator nozzle, including the effects of the jet impingement on the MFW pipe whip restraint. 3) The effects of a circumferential rupture of the MFW line at the steam generator nozzle have been evaluated, and the MS/MFW pipe whip rescrainc structure has been modified to mitigate this break. 4) The SGBD line has been evaluated to assure that, for* a circumferential rupture of the SGBD line at the steam generator nozzle, an unrestrained SGBD l1ne does not affect the safe shutdown capability of the unit for tha: assuming a loss of offsite power. 3.6-16 SGS-UFSAR Revision 18 April 26, 2000 C ...

3.6.5.2 Main Steam System The Main Steam System is illustrated on Figures 10.3-lA and B and is described in Section 10.3. The piping arrangement is shown on Figures 3. 6-10 through 3. 6-13. Each of the four 30-inch OD x 1. 007-inch wall main steam pipes runs from the nozzle on its respective steam generator inside the containment (Elevation 172 feet) vertically downward and then out of the containment through a separate penetration which also forms an anchor point in the system (Elevation 108 feet}. A 16-inch ID flow restrictor is located in the vertical run of each main steam line inside the containment at Elevation 135 feet. Two steam lines penetrate the containment and enter an enclosed penetration on the north side of the containment, while the two remaining steam lines penetrate the containment into an enclosed penetration area on the south side. Each steam line then changes to 32-inch OD x 1.5-inch wall thickness and is routed toward the turbine in a horizontal run. This horizontal* section within each penetration area contains the 34-inch 00 x 3.314-inch thick safety valve manifold and the 24-inch ID main steam isolation valves (MSIVs) . Downstream of the MSIVs, the steam lines were originally designed to return to 32-inch OD x 1.073-inch wall thickness, run vertically to Elevation 125 feet or 13 feet, exit the penetration through wall sleeves, and run horizontally to the mixing bottle, the four steam lines are manifolded to two pipes which then run to the high pressure turbine. The Main Stearn System has been conservatively designed in order to provide the in reliability of operation under normal conditions and improbability of failure under abnormal conditions. The piping, as originally designed, has been manufactured with a conservative wall thickness of 2.11 inches inside the penetration* wall sleeve, 1. 50 inches from the sleeve to the main steam safety valve manifold and 3.314 inches at the safety valve manifold, even though the code required wall thickness is less than 1 inch. This extra wall thickness serves the dual purpose of eliminating any "high stress" areas at the penetration anchor (thus making the anchor point no more likely to fail than any ather portion of the line) and providing added assurance of preservation of containment and main isolability. To further assure 1solability, maintenance of containment integrity and continued shutdown capability, an extensive network of steel limit stop columns and supports has been provided in the penetration area. This steel has been designed to withstand the fluid dynamic forces 3.6-17 SGS-UFSAR Revision 18 April 26, 2000 I associated with the postulated pipe breaks and thus prevents the imposition of excessive strains upon the piping upstream of the MSIVs or upon the containment pressure boundary as a result of such breaks. / Mechanical restraints have been installed at, and adjacent to, the MSIVs due to their criticality and proximity to the containment. Several types of restraints have been used, each serving a distinct function. As shown on Figure 3. 6-9, restraints are provided on the steam lines adjacent to the MSIVs. These restraints serve to limit pipe motion following a postulated rupture such that neither excessive moments nor physical impact can damage the containment, containment penetrations, or MSIVs. Supports are provided on the valve body to aid in supporting valve weight and supply restraint against undesired motion. Where necessary, the valve operator has also been restrained to limit seismically induced motions. The entire Main Steam Piping System outside the containment has been designed in accordance with the ANSI B31.1, Code for Pressure Piping Power Piping. The piping was purchased in accordance with ASTM Specification A155 Grade KC70 Class I, A155 Grade KCF70 Class I, AI06 Grade B, A106 Grade c, or substitutable chrome alloy, or stainless steel material depending upon the specific piece in question. The ASTM Al55 piping was subjected to supplementary tests Sl (check analysis on each length of pipe), S2 (Tension and Bend Tests), (Hardness Tests), and 54 (Magnetic Particle Examination) in addition to the 100 percent ultrasonic examination of the unformed plate required by the base ASTM Plate Specification. The ASTM Al06 piping was subjected to supplementary tests 52 (check analysis on each length of pipe), 54 (flattening test on each length of pipe)1 and 55 and 56 (etching test on each length of pipe). Radiographic examination has been performed on joints in piping of 3/4-inch wall thickness and over, and nozzle welds were subjected to magnetic particle examination. Welded joints in the main header downstream of the MSIVs and welded joints in all main steam piping upstream of the MSIVs were made utilizing the gas tungsten 3.6-18 SGS-UFSAR Revision 16 January 31, 1998 (

arc welding during the first pass, either with the consumable insert or open root with hand-fed filler metal technique. Additionally, that portion of the piping which runs outside the containment from the containment wall penetration to the MSIVa has been constructed in accordance with the materials, fabrication, fabrication inspection, and quality control requirements of ANSI B3l.7 for Nuclear Class 1 Piping. 3.6.5.2.1 Criteria for Determination of Location and Orientation of Postulated Breaks Critical evaluation of the criteria for postulation of pipe breaks presented in paragraph 2 of Reference 1 has shown them not to be applicable, in toto, to the main ste&Jll (or feedwater) piping in the Salem plant. This is a result of differences between the design concept utilized for this piping and the design concept utilized for the piping upon which the criteria were based. Reference l suggests three location criteria for postulation of pipe breaks: 1. At terminal points (anchor points) 2. At locations where stresses due to normal operational loadings are in excess of 0.80 of code-allowable stress 3. At a minimum of two locations between anchor points These locations appear to be baaed upon the technically justifiable premise that the probability of failure of a pressure boundary component is directly related to the stress level in that component. A well known and established theory of mechanical metallurgy, the Griffith Theory 2, has shown that propagation of a crack in metal is related to the square of the stress level in the metal. Hence, the square of the ratio of two given stress levels yields the relative probability of the propagation of a crack at those stress levels. 3.6-19 SGS-UFSAR Revision 16 January 31, 1998 Based on the above criterion, Reference 2 has proposed a "probabLlity of faLlure ratio"* of 0.64 (0.64 = 0.802) as a critical value, above which a localized pipe break must be considered "possible." Accepting the apparently arbitrary selection of the 0. 64 probability ratio as an engineering judgment, the criterion can be considered universally applicable in that it is using actual stress levels in the component under examination as the basLs for postulating failures of that component. No such universal applicability can be attributed to criterion 1, however. The suggestion of postulating pipe breaks at tenuinal points {criterion 1) appears to be based upon statistical evidence which indicates that, for piping systems designed to the minimum requirements of the applicable code and designed without special provisions for equalizing stresses within the system, there is a sLqnificantly higher stress level at tenuLnal points ( l. 39 times that encountered in straight runs), and hence a higher relative probability of failure at terminal points ( l. 392 = 1. 93 times that in straight runs)

  • If, however, the above phenomenon was taken into account during the design phase of a system and the piping was specifically designed such that stresses at terminal points are not significantly greater than stresses in straight runs, the increased probability of failure at terminal points does not exist, and applicatLon of criterion 1 is not justifiable in light of the minimal increase in factor of safety that could be achieved. Such is the case for the main steam (and feedwater) piping at the Salem plant. Any justification for the postulation of a tenuinal point break in the penetration area baaed upon amplification of stresses due to pipe support errors is also untenable, since the steam line is rigidly supported, not spring
  • 7.'he "probability of failure ratio'* is defined as the ratio of the probability of failure under stresses associated with normal operational loadings to the probability of failure permitted by code allowable stress levels. 3.6-20 SGS-UFSAR Revision 6 February 15, 1987
  • *
  • hung, adjacent to the penetration anchor (due to the absence of vertical thermal motion in this area) . Based upon the actual low stress levels present in the main steam (and feedwater) piping systems (see Tables 3.6-2 and 3.6-3) and their conservative anchor design, breaks have not been arbitrarily postulated at terminal points. Additionally, Reference 4 specifies that breaks and cracks need* not be postulated for the piping from the containment wall up to and including the isolation valves provided that break exclusion are satisfied. The main steam piping between the containment penetrations and main steam isolation valves was demonstrated to satisfy the following stress criteria for break in Reference 4: 1. The sum of stresses due to sustained loads, occasional loads and thermal expansion including a DBE do not exceed 0.8 (1.8 Sn 2. The stresses due to a break outside of the break exclusion area do not exceed the lesser of 2.25 Sh and 1.8 Sy. For those of high-energy fluid piping, preservice and subsequent inservice examinations are performed in accordance with the requirements specified in ASME Section XI. During each inspection interval, as defined in IWA-2400, an ISI is performed on all ASME Code Section XI circumferential and longitudinal welds contained within the break exclusion region for high-energy fluid system. piping as required per the approved risk informed break exclusion region (RI-BER) process. Breaks have been postulated, however, at locations where relative stress levels indicate them to be appropriate for protection. In order to provide a degree of protection equivalent to the recommended Refe:rence 1 criteria, the following were implemented: 1. The wall thickness of the main steam piping within the areas and in that portion that runs adjacent to the Auxiliary Building (Control Room) wall was increased to 1.5 inches. 2. During the initial plant design stresses in the main steam piping runs described in 1 above were limited to 0.25 + for the normal operational plus OBE ( 1/2 SSE) loading cases (or plus safety valve discharge loading cases) . 3.6-21 SGS-UFSAR Revision 21 December 6, 2004
3. Circumferential and longitudinal breaks were postulated at high stress locations in the steam line (point A and on Figure 3.6-10). 4. Critical cracks (as defined in Reference l) were postulated in the steam line both inside and outside the penetration areas. 5. For the break exclusion piping in the penetration areas, the following assumptions were made for performing equipment environmental qualifications: a. The largest main steam line break size between the containment penetrations and main steam isolation valves was assumed to be 1.0 ft2* This assumption satisfies the requirements of Reference 5 with regards to main steam and feedwater piping that meet break exclusion requirements, The purpose of this assumption is to ensure that, even though a break is not required to be postulated per Reference 4, essential equipment is qualified for the environmental effects of a nonmechanistic longitudinal break having a cross sectional area of at least one square foot. This provides added protection for essential equipment located in the penetration area. b. No single active failure was postulated to occur break. This assumption is applicable since no break is postulated per the break exclusion requirements and the sole purpose of the assumed nonmechanistic break is to provide protection of essential equipment. 3.6.5.2.2 Analysis of Postulated Pipe Breaks As stated in Section 3.6.5.2.1, main steam line pipe breaks were postulated at point A and on Figure 3.6-10 in both the circumferential and longitudinal directions. 3.6-2la SGS-OFSAR Revision 16 January 31, 1998 (

THIS PAGE INTENTIONALLY BLANK 3.6-2lb SGS-UFSAR Revision 16 January 31, 1998 The forcing function used for design of restraints was assumed to be a step function of magnitude 1. 26 PA, where P is the initial pressure in the pipe (conservatively assumed to be hot standby pressure) and A is the cross sectional flow area of the ruptured pipe. The 1.26 thrust factor is theoretically derivable from ideal gas laws, its conservatism is assured in that the Moody correlation a saturated steam thrust factor closer to 1. 20. Dynamic load factors were used where applicable to account for energy loadings in the static analysis of structural components. I In addition, the main steam (MS) lines of the Salem steam generators are subjected to postulated guillotine breaks. The pipe break points are near nozzle weld sections. The time history analysis is performed to determine the pipe whip restraint reaction forces and the the break point movements of the MS line. The pipelines from the nozzle break points to the wall anchorage points are modeled with plastic pipe and elbow elements. The pipe whip restraints are modeled with springs. Each directional restraint gap is considered. Pipe tie rods are modeled as slacks. The gap-spring combination element is used for the restraints. Pipe break force time histories are used for the break points and elbow tangent points. Unit area thick plates are used to carry the follower loads. The beam elements under the thick are used to stabilize the All of the and beams have no masses. The fontal solver of ANSYS Version 5.2 is used for dynamic analysis. The pipeline and its restraints are properly modeled in the finite element mode. Damping coefficients are considered proportional to the mass and stiffness. Seven (7) percent of critical damping is used for frequencies of 10 Hz and 100 Hz. The damping is lower between these frequencies and higher for other frequencies. The restraints had no damping associated with stiffness. The restraints are considered to have no masses; hence no damping is associated with masses either. restraint condition is to the anchorage sleeve for the cut-off point boundary conditions. The analysis results are time history plots and listings of designated response items. and time are also determined. The extreme response values The following items are both important to safety and are located near the postulated break locations in the main steam and feedwater lines: The The wall adjacent to the Control Room. wall. 1. 2. 3. The penetration area roof beneath the steam lines. 3.6-22 SGS-UFSAR Revision 24 May 11, 2009

4. The ventilation intake on the penetration area roof. 5. The inboard. penetration area north -south wall between columns CC and. DD at Elevation 100 feet. Calculation of the energy loading imposed upon the Auxiliary Building wall adjacent to the Control Room and. upon the penetration area wall (items 1 and. 5 above) by the postulated. ruptured linea showed that it was doubtful that the walls could remain abaolutely leaktight and impervious to steam after impact of the pipe. To preclude unacceptable damage, structural members were built up behind the main steam and feedwater pipes, as shown on Figures 3.6-10, 3.6-11, and 3.6-12. The design basis for these structural members, which were designed using a dynamic load. factor of 2, was to be able to withstand. the calculated. pipe break forces and. thus prevent pipe impact with the above mentioned walla following the postulated breaks. Fluid impingement due to design basis cracks will not compromise the integrity of the walls. The total resultant forces and unit impingement pressures can be easily withstood by the walla, and apalling due to induced thermal gradients will be minimal. The pipe support structure in the yard was reinforced to prevent pipe whip impact with the ventilation intake structure. The intake itself was raiaed to Elevation 170 feet and steel plate was added to the pipe support structure in order to prevent steam ingestion by the ventilation system. Pipe whip energy loadings on the containment wall were computed by assuming the pipe would undergo rigid body rotational motion about the nearest credible plastic hinge. consideration of jet force, pipe linear mass density, and rotational inertia then permits calculation of rotational velocity and linear energy density loadings on the building. For impact loading, the containment was checked for penetration depth under a low mass, high velocity impact, and deflection under 3.6-23 SGS-OFSAR Revision 16 January 31, 1998 a large mass, low velocity impact. Equivalent static loading was obtained from a pseudo-stress method by equating the product of load and displacement to the kinetic enerqy. The method of plastic collision was also used to account for enerqy absorption in the momentum transfer. The ductility factor of the structure was checked and held within limits to maintain structural stability. The wall was shown to remain intact, leaktight, and completely functional after impact. Breach of containment integrity by overstressing or distorting wall penetrations is precluded by providing reinforced piping at penetrations and local pipe restraints in the penetration area. No moments or forces of unacceptable magnitude resulting from the postulated main steam pipe breaks can be imposed upon the penetration assemblies. Details of the penetration area restraint steel are shown on Figures 3.6-11 through 3.6-13 and a typical restraint is shown on Figure 3.6-14. Barrier protection is provided for safety-related items to withstand the loadings caused by jet forces and all credible missiles resulting from the critical crack. Full jet impingement forces were taken to be 1.26 PA and 0.6 x 1.26 PA for open ended and crack-like breaks, respectively. Where barriers are not immediately adjacent to jet sources, a jet divergence half-angle of 10 degrees is used to calculate the portion of the jet intercepted. The Class I (seismic) structures housing the main steam and feedwater lines were ( designed baaed on ACI 318-63 "Working Stress Design* for normal operating load plus Operating Basia Earthquake, and *ultimate Strength Deaiqn" for normal loads plus Design Basis Earthquake or Tornado. In the working stress design under Operating Basis Earthquake loads, the allowable stresses are one-third above the normal applicable code working stresses. Wind stresses have been found to be less critical than those generated by an operating Basis Earthquake. Load factors of unity have been used in the ultimate design under Design Basis Earthquake or 3.6-24 SGS-UFSAR Reviaion 16 January 31, 1998 tornado loading. The design lilnit for tension members (i.e., the capacity required for the design load) is based upon the yield stress of the reinforcing steel. The stress in reinforcing steel for ultilnate strength design has been kept below 0.9 Py. The capacity reduction factor "e" for concrete stress is applicable to all Class I (seismic) structures. A coefficient "k" of 0.85 for 3500 psi concrete has been used in addition to "e" for equivalent rectangular concrete stress distribution. The capacity reduction factor *e* is provided for the possibility that small adverse variations in material strengths, workmanship, dimensions, and control (while individually within required tolerances and the limits of good practice) occasionally may combine to result in under-capacity. For tension members, the factor "e" is established as 0.95. The factor "e" is 0.90 for flexture and 0.85 for diagonal tension, bond, and anchorage. Steel members inside the Class I (seismic) structures are designed in accordance with the AISC Manual of Steel Construction (Sixth Edition) except for the main steam and feedwater limit atop steel and the containment liner which are designed with *e*
  • 0.95 for tension and 0.90 for compression and shear. The possibility of all load reversals was considered and analyzed. The design was predicated on the combination of loadings that caused the most severe conditions. Effects-of Postulated Breaks on Safety-Related Equipment The Class I (seismic) structures have been reviewed for their adequacy based on the postulated critical cracks of the main steam and feedwater lines. The walls and floors in the penetration areas have been designed for a dead load of 325 paf and a live load of 250 psf. The 3.6-25 SGS-tJFSAR Revision 6 February 15, 1987 I equipment loads are included in the dead loads. on the Working Stress Method. The above loadings are based The floors and walls in this area are of withstanding a 4. 0 pressure buildup plus a 4. 0 foot head of water on the Elevation 100 feet slab and the resultant water pressure distribution on the walls, using the ultimate stress method previously described. The use of reinforcing steel stress limits of yield strength and ultimate tensile strength as determined from mill test report data wi thm:t gives calculated internal pressure capabilities respectively, thus assuring continued structural during the postulated occurrence. capacity reduction factors of 5.1 psi and 7.6 psi, stability of the building Where must be sealed to prevent fluid flow between acent areas, steel dogged doors are used. These doors are capable of remaining leak-tight against the pressure loadings previously described. Roof-hatch covers in this area are steel encased, reinforced concrete "boxes" approximately 3 feet thick, bolted down to withstand tornado loadings. As such, they are unsuitable for use as pressure relief openings and no credit has been taken fur them. Failure of other non-Class I Class I (seismic) structures. structures will in no way the electrical and control systems have been engineered and designed to meet the Single Failure Criteria as required by IEEE Standard 27 9-1968, "Proposed, IEEE Criteria for Nuclear Plant Protection Systems." The following features are provided in the safety-related electrical and control systems: 1. Safety-related equipment is actuated from redundant protection system trains. 2. Power for redundant vital buses. SGS-UFSAR 3.6-26 have been from Revision 25 October 26, 2010
3. Air supply for pneumatic actuators is supplied through redundant air headers backed up by the two emergency air compressors. 4. Redundant safety-related equipment has been spatially isolated and mounted in separate seismically qualified enclosures. safety-related Figures 3.6-15 equipment located through 3.6-18 and in the penetration includes the steam areas is generator shown on pressure transmitters and the solenoid valves required for actuation of the main steam isolation valve -vent valves. These instruments are mounted in individual NEMA IV, Class I (seismic) qualified enclosures. The enclosures, with equipment installed, have been environmentally qualified for operation under the most adverse ambient conditions poatulated for an assumed nonmechanistic 1.0 ft2 longitudinal crack in a main steam line or a postulated crack in a feedwater line within the penetration area. In addition, the individual enclosures have been arranged for spatial separation within the penetration area to maintain the channel separation requirements and to meet single failure criteria. A Leak Detection System has been provided for the penetration area to supplement the steam break and feedwater break protection systems, which now include: 1. High steam line differential pressure 2. High steam flow 3. Low steam line pressure 4. Steam generator low water level s. Low feedwater flow 6. Steam flow/feedwater flow mismatch 3.6-27 SGS-UFSAR Revision 16 January 31, 1998 The penetration area Leak Detection Syatem includes monitoring of the ambient temperature in the penetration area by nonindicating temperature switches. A aet of four temperature monitors will alarm on temperature rise indicative of steam or feedwater leakage. 3.6.5.2.4 Analyais of Postulated Break on Unit Shutdown Capability Postulated main ateam line and feedwater line breaks outaide of the penetration area have been analyzed for adverse effects that would jeopardize the capability to effectively and aafaly ahutdown the reactor. The postulated steam line and feedwater line breaks cauae a transient which results in a number of automatic operations that trip the reactor, isolate the main steam and feedwater lines and bring the reactor to a shutdown condition. Subsequent cooldown of the RCS is accomplished according to plant emergency operating procedures. Detailed analyses of steam pipe ruptures and loss of normal feedwater are discussed in Section 15. These analyaea demonstrate that no significant effects result from the postulated line breaka which would prevent the cold shutdown of the reactor and protection of the core against cladding damage. A break of adequate aize in any of the four main steam lines is detected by steam line flow and pressure instrumentation. The main steam lines are automatically isolated upon receipt of high steam line flow signals from two of the four main steam lines (one out of two per line), in coincidence with either low main steam line pressure signals (two out of four linea) or low-low RCS average temperature (two out of four l6ops). small breaks outside containment may not receive an automatic isolation aiqnal and therefore require manual isolation by the operator. Isolation is assumed to occur 10 minutes after the steam line break. The po*tulated break reaulta in the lowering of the RCS temperature and pressure and aubsequently low pressurizer pressure and level. The Safety Injection System (SIS) is automatically actuated upon receipt of either coincident low pressurizer pressure and low preaaurizer level aiqnala {one of three), a steam line isolation signal, steam line differential pressure siqnala between a steam line and the remaining lines. The safety injection siqnal will also trip the reactor and main 3.6-28 SGS-UFSAR Revision 16 January 31, 1998 feedwater pumps, initiate feedwater isolation and start the auxiliary feedwater pumps. These automatic actions will shut down the reactor and mitigate the consequences of a steam line break. Operating personnel will verify that the preceding automatic actions have occurred and then proceed according to recovery procedures, which include: 1. Identifying and isolating the affected steam generator 2. Regulating auxiliary feedwater flow to the unaffected steam generators to maintain an indicated water level 3. Stopping the safety injection pumps once pressurizer level is restored and activating the pressurizer heaters to maintain a steam bubble in the pressurizer 4. Stabilizing reactor coolant temperature and steam generator pressure and level by steam dump through atmospheric relief valves When the RCS temperature has stabilized, operating personnel will commence boration of the RCS as necessary for cold shutdown. Cooldown will proceed within design limits according to plant operating procedures. When the RCS reaches the required temperature and pressure, RHR System operation will be initiated to bring the reactor to the cold shutdown condition. The electrical, control, and instrumentation equipment necessary for the automatic and manual operations described above are located in the containment, penetration area, and Auxiliary Building. Postulated steam line breaks outside the containment will not affect redundant safety-related controls and equipment required to bring the reactor to a cold shutdown condition. The control room will be available for the recovery and subsequent shutdown of the reactor following the postulated event. Access to the control room will be available and the equipment in the 3.6-29 SGS-t1FSAR Revision 6 February 15, 1987 control room will remain functional following a steam line or feedwater line rupture. Details of the Control Room design and ventilation system design are discussed in Sections 7 and 9, respectively. It is concluded that the capability to bring the unit to a cold shutdown condition is not jeopardized by the postulated main steam line rupture. 3.6.5.3 Steam Generator Feedwater System The Steam Generator Feedwater System is shown on Plant Drawings 205202 and 205302 and described in Section 10.4. The piping arrangement is shown on Figures 3.6-10 through 3.6-13. Each of the four feedwater pipes runs from its respective steam generator nozzle inside containment (Elevation 144 feet) vertically downward and then out of the containment through a separate penetration which also forms an anchor point in the system. Two feed lines penetrate the containment into an enclosed penetration area on the south side. Each line then turns toward the turbine (east) in a horizontal run. Downstream of the feedwater check valves, each line then rises to Elevation 130 feet (or 132 feet) before exiting the penetration area. The design philosophy and conservatism utilized in the design of the main steam piping (refer to Section 3. 6. 5. 2) has also been utilized for the feedwater piping. The increased wall thickness of the piping within the penetration sleeves (2.065 inches) and up to the isolation valves (Schedule 120) assures elimination of high stresses at the anchor, and preservation of containment integrity. Extensive restraint steel has been provided for the feedwater lines, as was done for the steam lines. The entire Feedwater System from the feed pumps to the steam generators has been designed in accordance with ANSI B31. 1. The piping was purchased in accordance with ASTM Specification A106 Grade B, A106 Grade C, A335 Grade P22 or substitutable stainless steel material, depending upon the specific piece in question. Mill inspection and test reports were obtained for this feedwater piping, and a check analysis and flattening test of one length of each pipe lot was required. For sections of this piping which are 8 inches nominal size and larger, supplementary etching tests were required. Welded joints in main headers were made using the consumable insert tungsten inert gas first pass technique. Welded joints for piping replaced under the Steam Generator Replacement Project were made using the open root, manual gas tungsten arc process for the root pass, and the automatic gas tungsten arc process for the balance of the weld. 3.6-30 SGS-UFSAR Revision 27 November 25, 2013

Radiographic examination or Ultrasonic Testing has been performed on welded joints in piping of 3/4-inch wall thickness and over, and nozzle welds have been subjected to magnetic particle examination. Additionally, piping from the steam generator inlet feedwater control valves to the feedwater isolation valves has been constructed in accordance with Section I of the ASME Boiler and Pressure Vessel Code, and piping from the feedwater isolation valves to the steam generators has been constructed in accordance with the materials, fabrication, fabrication inspection, and quality control of ANSI B31.7 for Nuclear Class 1 piping. To eliminate potential cracking and mitigate erosion corrosion concerns in the Unit 1 steam generator inlet feedwater piping, steam generator feedwater nozzle-piping transition forging pieces have been installed. The material for these forgings was purchased in accordance with ASME Section II, Part A, Specification SA-508, Class 2 quenched and tempered low alloy forging material. This forging material meets all ASME Section III, Class 1 fracture toughness requirements. Although installed in feedwater piping classified as Class 2 piping, these forging pieces are fabricated, inspected and installed to Nuclear Class 1 requirements. Additionally, these transition forging pieces are analyzed to meet the stress limits and requirements for cyclic operation of the ASME Code Section III, Sub-article NB-3200, for Class 1 piping. Feedwater piping installation welding, and examination involved in installing the Unit 2 replacement Steam Generators utilized ASME Section XI (1998 Edition with 2000 Addenda) and ASME Section III, Subsection NC (1995 Edition with 1996 Addenda). Both of these later codes are NRC-endorsed per 10CFR50.55a and were reconciled to the original construction codes. 3.6.5.3.1 Criteria for Determination of Location and Orientation of Postulated Break The Reference 1 criteria are not totally applicable to the feedwater piping for the same reasons discussed in Section 3.6.5.2.1 for the main steam piping. In order to provide a degree of protection equivalent to the recommended Reference 1 criteria, however, the following were implemented: 1. The wall thickness of the feedwater piping within the penetration areas and in the portion that runs adjacent to the Auxiliary Building (Control Room) wall were increased to Schedule 120. 3.6-31 SGS-UFSAR Revision 24 May 11, 2009

2. Stress in the feedwater piping runs described in (1) above was limited to 0.25 (Sh + ) for the normal operational plus OBE (1/2 SSE) loading cases. 3. Circumferential and longitudinal breaks were postulated at high stress locations in the feedwater line (points C, D, and F on Figure 3.6-10). 4. Critical cracks (as defined in Reference 1) were postulated in the feedwater line both inside and outside the penetration areas. 3.6.5.3.2 of Postulated Pipe Breaks As stated in Section 3.6.5.3.1 feedwater piping breaks were postulated at points C, D, and F on Figure 3. 6-10 in both the longitudinal and circumferential directions. The forcing function for design of restraints was assumed to be a step function of magnitude 2.0 PA, where P and A are as defined in Section 3. 6. 5. 2. 2. The 2. 0 thrust factor is theoretically derivable for nonflashing liquids, and is known to be conservative for saturated and subcooled liquids, whose thrust factor is closer to 1.20. Dynamic load factors were used where The consequences of feedwater pipe breaks are identical to those for steam line breaks in Section 3. 6. 5. 2. 2. Pipe whip restraints similar to those provided for the main steam lines were provided for the feedwater piping to prevent damage to the Auxiliary Building and penetration area walls discussed in Section 3.6.5.2.2. These restraints are shown on Figure 3.6-19. The discussion presented in Section 3. 6. 5. 2. 2 regarding the design of the restraints, fluid impingement effects, containment and is also to the feedwater line breaks. In addition, the Feedwater (FW) lines of the Salem steam generators are subjected to postulated guillotine pipe breaks. The pipe break points are near nozzle weld sections. The time history analysis similar to that described in Section 3.6.5.2.2 for the main steam line breaks is performed to determine the pipe whip restraint reaction forces and the pipe line displacements. 3.6.5.3.3 Effects of Postulated Breaks on The discussion Generator Feedwater SGS-OFSAR in Section 3.6.5.2.3 also 3.6-32 Equipment to the Steam Revision 24 May 11, 2009 3.6.5.3.4 Analysis of Postulated Break on Unit Capabqity Analysis of postulated main feedwater line breaks outside of containment demonstrates that the required equipment for safe shutdown of the reactor will be available and not damaged by such breaks. The postulated event will require automatic and manual operations in accordance with plant emergency operating procedures to bring the unit to a shutdown condition and then subsequent cool down. No significant effects result from the postulated breaks that would prevent cold shutdown of the reactor and protection of the core. A break in any of the four main feedwater lines results in loss of feedwater to the affected steam generator and causes the water level in the steam generator to drop rapidly. The three intact steam generators will also see a drop in water level. A reactor trip is initiated upon receipt of 2 out of 3 low water level signals from any steam generator or a coincident low feedwater flow signal (one out of two) and low steam generator water level signal (one out of two) from any steam generator. As the affected steam generator empties, the SIS will be actuated by steam line differential pressure signals between the steam line of the affected steam generator and the remaining steam lines. The safety injection signal will also trip the main feedwater pumps, initiate feedwater isolation, and start the auxiliary feedwater pumps. These automatic actions will shut down the reactor and mitigate the consequences of the feedwater line break. Once the operating personnel have verified that the preceding automatic actions have occurred, they will then initiate recovery operations. Recovery will be essentially the same as that described for the postulated steam line break in Section 3.6.5.2.4 and includes: 3.6-33 SGS-UFSAR Revision 6 February 15, 1987

1. Isolating the affected steam generator by closure of the steam line, feedwater line, and blowdown line isolation valves. 2. Directing auxiliary feedwater flow to the unaffected steam generators and regulating flow to maintain an indicated water level. 3. Stopping the safety injection pumps once pressurizer level is restored. 4. Stabilizing reactor coolant temperature and steam generator pressure and level in the remaining steam generators by steam dump to the condensers or through the atmospheric relief valves. Boration of the RCS as necessary for cold shutdown and subsequent cooldown will proceed according to plant operating procedures as described for the postulated steam line break in Section 3.6.5.2.4. Postulated feedwater line breaks outside of the containment will not affect redundant safety-related control and electrical equipment necessary to bring the reactor to a cold shutdown condition. The postulated events will not affect remote operation of the required equipment from the control room nor access to the control room. The capability to bring the unit to a cold shutdown condition is not jeopardized by the postulated main feedwater line ruptures. 3.6.5.4 Chemical and Volume Control Letdown Line The letdown line of the Chemical and Volume Control System (CVCS) is described in Section 9.3 and is shown on Plant Drawings 205228 and 205328. An isometric view of the piping arrangement is provided in Figure 3.6-20. The letdown line carries 300 psig, 300°F reactor coolant from the regenerative heat exchanger inside the containment through a containment penetration in the Elevation 78 foot piping penetration area. The pipe runs across the penetration area into the Elevation 84 foot pipe alley, where it bifurcates. One branch goes to normally closed valve 1CV8 in the safety injection pump room, while the other branch runs along the pipe alley wall until it turns into the letdown heat exchanger room. After it exits the letdown heat exchanger, it is no longer considered to be a high energy line. 3.6-34 SGS-UFSAR Revision 27 November 25, 2013 The letdown line is constructed to Nuclear Class 2, Seismic Class II standards, from ASTM-A312 TP 304 stainless steel pipe. Postulated break locations have been sleeved and restrained in accordance with the design criteria of Section 3.6.5.11. The section of piping located in the safety injection pump room has been totally encapsulated, as shown on Figure 3.6-21. The pipe alley and letdown heat exchanger room are fitted with watertight steel doors to contain the energy released by a postulated break. room is vented through the normal exhaust ducting. The letdown heat exchanger The pipe alley is vented to the mechanical penetration area and then through a vent penthouse to the atmosphere. With these modifications, postulated ruptures of this piping will have no detrimental effect on plant shutdown capability or safety systems. Emergency procedures in the event of rupture of this line consist of (a) identification of the break, and (b) remote manual isolation of the line. 3.6.5.5 Steam Generator Blowdown System The Steam Generator Blowdown System is described in Section 10.4 and is shown on Plant Drawings 205225 and 205325. The piping arrangement is shown on Figures 3.6-22 and 3.6-23. The steam generator blowdown piping which is encompassed by the definition of high energy lines contains 814 psig (Unit 1) and 885* psig (Unit 2) saturated water from the secondary side of the steam generators. The four 3-inch pipes, one from each steam generator, penetrate the containment wall into the Elevation 78 foot piping penetration area, then run immediately upward into the Elevation 100 foot piping penetration area. Here, each of the lines bifurcates with one branch of each line going to each of the No. 11 and 12 steam generator blowdown tanks. The steam generator blowdown lines are constructed to Nuclear Class 2, Seismic Class I standards upstream of the containment isolation valves, and non-nuclear, Seismic Class III standards downstream of the isolation valves. Postulated break locations have been restrained to prevent pipe whip damage to vi tal equipment. With these modifications, postulated ruptures will have no detrimental effect on plant shutdown capability or safety systems. Emergency procedures in the event of a rupture of these lines consist of (a) identification of the break, and (b) remote manual isolation of the line. Primary flow 82,500 gpm, no fouling, 0% tube plugging, Tave 577.9°F, full power 867.75 MWt. SGS-UFSAR 3.6-35 Revision 27 November 25, 2013 Modifications to the blowdown piping were performed in order to replace the Unit 2 steam generators in 2008. With regard to NRC Generic Letter 87-11 and NRC Branch Technical Position MEB 3-1 (Reference 4, as cited in UFSAR Section 3.6.6), the relocation of the blowdown nozzles on the RSGs resulted in the terminal ends of the blowdown piping being correspondingly relocated. However, since no safety related equipment is located in the vicinity of the relocated RSG blowdown nozzles, no rupture restraints are required for the terminal end breaks of the rerouted blowdown piping. The new blowdown pipe routing has been analyzed for intermediate breaks. 3.6.5.6 Steam Supply To The Auxiliary Feedwater Pump Turbine The steam lines to the auxiliary feedwater pump turbine are described in Section 10.3 and shown on Plant Drawings 205203 and 205303. An isometric view of the piping is shown on Figure 3.6-24. The two pipes carry 814 psig (Unit 1) and 885* psig (Unit 2) saturated main steam from the main steam lines in the Elevation 100 foot piping penetration area along the Auxiliary Building wall, joining together into one line before entering the Auxiliary Building. The steam line enters the Auxiliary Building in the waste evaporator room on Elevation 100 foot. It then passes down into the pipe alley and enters the auxiliary feedwater pump turbine room on Elevation 84 feet. The steam lines are constructed to Nuclear Class 2, Seismic Class I standards from ASTM-A106 Grade B carbon steel pipe or substitutable chrome alloy or stainless steel material. The piping was subjected to Supplementary S2 (check analysis), S4 (flattening test on each length of pipe), and S5 -S6 (etching test on each length of pipe) . Welds are made utilizing the consumable insert -tungsten inert gas first pass technique. The pipe alley and auxiliary feedwater pump turbine room are provided with watertight steel doors to contain the energy released by a postulated break. The compartments are connected by two blowout panels to allow venting through a common discharge path. Postulated break locations shown on Figure 3.6-24 have been sleeved and restrained to limit pipe break mass flow rates and preclude pipe whip damage to vital equipment. on Figure 3.6-25. Typical sleeve and restraint designs for this line are shown Primary flow 82,500 gpm, no fouling, 0% tube plugging, Tave power 867.75 MWt. SGS-UFSAR 3.6-36 Revision 27 November 25, 2013 Emergency procedures in the event of rupture of this line consists of (a) identification of the break, (b) manual isolation of the affected line(s) if the valves are accessible, and normal plant shutdown, irrespective of the results of (b). With these modifications, the only anticipated consequence is the possible loss of one of three auxiliary feedwater pumps, which does not affect unit shutdown capability. 3.6.5.7 Chemical And Volume Control Char&ing And Reactor Coolant Pump Seal Injection -Unit 2 Only Piping for the above system is located in the following Auxiliary Building areas: 1. Primary, Auxiliary Feed, and Refueling Water Tank Heater Area (Elevation 84 feet) 2. South Penetration Area (Elevation 78 feet) 3. Alley (Elevation 84 feet) 4. Safety Injection Pump Room (Elevation 84 feet) 5. Access Corridor (Elevation 84 feet) 6. Aisle No. 2 {Elevation 84 feet) 7. Access Corridor (Elevation 100 feet) 8. Boric Acid Evaporator Room (Elevation 100 feet) 9. Waste Evaporator Room (Elevation 100 feet) 10. Refueling Yater Purification Filter Room (Elevation 100 feet) 3.6-37 SGS-UFSAR Revision 7 July 22, 1987
11. Boric Acid Transfer Pump Room (Elevation 100 feet) 12. Emergency Diesel Rooms (Elevation 100 feet) 13. Control Room Air Conditioning Equipment Room (Elevation 122 feet)
14. Control Equipment Room (Elevation 122 feet)
15. Auxiliary Building Air Conditioning (Elevation 122 feet)
16. Boric Acid Batch Tank Area (Elevation 122 feet)

Normal pressure for the charging and seal injection lines is approximately 2520 psig at 127F. Design pressure for the piping is 2 825 psig. The system is constructed to Nuclear Class 2, Seismic Class I standards with austenitic Type 316, Schedule 160 material.

In the unlikely event of a postulated failure of the piping, water jet

impingement or pipe whip could adversely affect some safety-related components in the Elevation 84 foot pipe alley and south penetration area at Elevation

78 feet. Damage potential from jet impingement has been eliminated by use of pipe shrouds or impingement baffles at required points along the path of the piping. Damage potential from pipe whip has been resolved by the use of pipe restraints. At the first refueling outage, 33 pipe whip restraints were installed inside the containment and 21 pipe whip restraints were installed outside the containment.

3.6.5.8 Heating Steam System - Unit 2 Only Piping for the Steam Heating System is located in the same areas as described in Section 3.6.5.7. Steam for the system is supplied from an auxiliary boiler in the yard or from main turbine extractions. The heating steam system is considered to be a high energy piping system for Unit 2 but not for Unit 1 because the design pressure and temperature are 185 psig and 382 °F. Normal pressure in the system varies between 150 psig and 50 psig at saturated or slightly superheated conditions. Its purpose in the Auxiliary Building is to supply a heating medium for the following equipment.

3.6-38 SGS-UFSAR Revision 29 January 30, 2017

1. Boric Acid Evaporator and Feed Preheater 2. Waste 3. Boric Acid Batching Tank Heating steam piping is constructed in accordance with the ANSI B31.l, Power Piping Code. Material used is Schedule 40 carbon steel or substitutable chrome alloy or stainless steel material. The 316 stainless steel flex hose connections between the enclosed encapsulations and the vent piping are classified as related and Seismic Category I. The heating steam system encapsulations are rated for 174 psig and 378 °F design conditions. In the unlikely event of a postulated failure temperatures above normal, caused by steam escape, of this piping, ambient could possibly adversely affect: controls and electrical equipment in the of the break. To preclude this the following modifications were implemented: 1. Provided enclosed of the at selected of postulated failure in order to restrict steam flooding of the 84 ft elevation corridor and adjacent switchgear rooms. 2. The enclosed encapsulations are connected via flex hose connections to 1-1/2 inch piping that will vent any steam escaping from the points of postulated failure. The vent piping exhausts to atmosphere outside of the Building on the roof of the Main Steam whip restraints, sleeves, and a 1 1/2 inch vent line in the Auxiliary Building were installed at the first outage. 3.6.5.9 System-Unit 2 Only Piping for the Heating Water System is located in the same areas as described in Section 3.6.5.7. The Heating Water System provides the heating medium for the purposes: SGS-UFSAR 3.6-39 Revision 25 October 26, 2010
1. Room space heating 2. Primary, Auxiliary Feedwater, and Refueling Water Storage Tank Heating 3. Control Room and Auxiliary Building Vent Duct Heating This system operates as a pumped closed loop with each of the users having both a supply and return line. Piping is constructed in accordance with ANSI B31.1, Power Piping Code. Material used is Schedule 40 carbon steel or substitutable chrome alloy or stainless steel material. The heating water system is considered a high energy system for Unit 2 but not for Unit 1 because the design pressure and temperature for the system are 125 psig and 300 °F for the system supply side and 125 psig and 200 °F for the system return side. The normal pressure and temperature are the same as the design pressure and temperature ratings. Unlikely postulated failures of this piping present conditions similar to those specified for the Heating Steam System, except that the quanti ties of steam involved are less. To preclude the possibility of adverse effects of failures in this piping, enclosed vented encapsulations at selected points of postulated failure have been provided, the same as for the Heating Steam System. Pipe whip restraints, encapsulation sleeves, and vent lines in the Auxiliary Building were installed at the first refueling outage. Design basis cracks were not postulated at arbitrary locations in the Heating Steam and Heating Water Systems. Instead, specific failure points were determined based on maximum stress locations for which vented to atmosphere, enclosed encapsulations were provided to preclude steam flooding in the Auxiliary Building corridor and adjacent switchgear rooms. 3.6.5.10 Additional Protection Against Steam Flooding in the Auxiliary Building As shown on Plant Drawings 204805 and 204804, of items 3 thru 7 in Section 3.6.1, the following are plant areas where rupture of the piping could conceivably be undesirable: 1. Piping penetration area (Elevation 100 feet) 2. Piping penetration area (Elevation 78 feet) 3.6-40 SGS-UFSAR Revision 27 November 25, 2013
3. Waste evaporator room (Elevation 100 feet) 4. Pipe alley (Elevation 84 feet) 5. Safety injection pump room (Elevation 84 feet) 6. Auxiliary feedpump turbine room (Elevation 84 feet) 1. Letdown heat exchanger room (Elevation 84 feet) In order to preclude undeairable effects due to steam flooding, these seven areas were transformed into one environmentally isolated contiguous zone which is vented to the atmosphere via the penetration area pipe break vent penthouse. 'l'he bounds of this zone are ahown by shading on Figure 3.6-28. Normal ventilation of this zone is provided by ducting with backdraft-type dampers. These dampers are designed such that those pipe break induced steam flows which are significantly in excess of normal ventilation airflows will close the dampers, thus preventing steam flow into adjacent vital areas either through supply or exhaust ducting. The closure of the backdraft dampers will then force the pipe break induced steam flow to be vented to the atmosphere via the penetration area vent penthouse. Where steam flows were found to be in excess of the capabilities of available vent area, sleeving of selected break locations was employed to reduce pipe break mass flow rates to acceptable values. Normal and post-pipe break flow paths, as well as backclraft damper locations are shown on Figure 3.6-28. The Letdown Beat Exchanger Room, located on Elevation 84 feet, contains a portion of the high energy eves letdown line which ia described in Section 3.6.5.4. Pipe break locations, selected on the basis of the criteria in section 3.6.4.3.2, are sleeved and restrained in order to prevent whip and to limit the two phase water/steam mass flow rates from the postulated breaks. A leaktight door with an integral backdraft damper was added to the room in 3.6-41 SGS-UFSAR Revision 16 January 31, 1998 order to provide an inlet path for ventilation supply, but still prevent break induced steam flow from reaching vital equipment on Elevation 84 feat. calculation of steam and water mass flow rates showed that the normal ventilation exhaust ducting in the room ia adequate to handle the steam without significantly disrupting ventilation system balance, and that the floor drains already provided are adequate to prevent excessive water buildup in the room. Cable in the room was rerouted in conduit to protect vital cables from direct impingement and to permit leaktight seals at wall penetrations. The Auxiliary Faedwatar Pump Room, located on Elevation 84 feet, contains a portion of the high energy steam line to the No. 13 auxiliary feedwater pump turbine described in Section 3.6.5.6. Pipe break locations, selected on one basis of the criteria presented in Section 3.6.4.3.2, were sleeved and restrained in order to prevent pipe whip and limit the steam mass flow rates from the postulated breaks. In order to preclude steam induced environmental damage to the No. 11 and 12 auxiliary feedwater pump motors and adjacent vital control centers, the No. 13 auxiliary feedpump and its turbine were enclosed in a steel plate subroom with a drop ceiling as shown on Figure 3.6-29. The steam line was lowered several inches in order to facilitate installation of the new ceiling below presently installed vital piping and equipment. Normal ventilation and cooling of the subroom is accomplished through the Auxiliary Building Ventilation system and a pump room cooler. Two pressure relief panels in the wall opening located adjacent to the pipe alley provide a defined path to the atmosphere for steam flows resulting from postulated pipe ruptures. The Safety Injection Pump Room, located on Elevation 84 feet, contains a portion of the high energy eves letdown line which is described in Section 3.6.5.4. In order to protect adjacent safety-related piping from pipe whip impact and to protect the 3.6-42 SGS-UFSAR Revision 16 January 31, 1998 (

safety injection pump motors from the steam environment following a postulated rupture of this pipe, the pipe is entirely sleeved within this room. The sleeving design is shown on Figures 3.6-29 and 3.6-21. No modifications were required, other than the letdown line several inches to sleeve interference. The Waste Evaporator Room, located on Elevation 100 feet, contains a portion of the high energy steam line to the auxiliary feedwater pump turbine which is described in Section 3.6.5.6. Pipe break locations, selected on the basis of the criteria presented in Section 3. 6. 4. 3. 2, are sleeved and restrained in order to prevent whip and limit the steam mass flow rates from the postulated breaks. In order to preclude the detrimental effects of steam and jet a steel enclosure is provided around this where it passes through this room. A new vent opening in the floor of the room within the enclosure was provided to vent the steam flow from the breaks to the pipe alley below. These modifications are shown on Figures 3.6-28 and 3.6-29. The Pipe Alley, located on Elevation 84 feet, contains portions of both the high energy eves letdown lines and the steam line to the auxiliary feedwater pump turbine. Pipe break locations, selected on the basis of the criteria presented in Section 3.6.4.3.2, are restrained to prevent whip. Although the pipe does not contain any equipment, (or backdraft is to steam from entering any areas not specifically designed to accommodate the steam environment. A wall opening to the penetration area provides atmospheric venting via the penetration area vent penthouse. The Piping Penetration Areas (Elevations 78 feet and 100 feet) contain portions of all of the high energy systems listed in Section 3.6.1. Pipe break locations, selected on the basis of the criteria presented in Section 3.6.4.3.2 were restrained as necessary to prevent pipe whip and fluid impingement. In order to maintain the internal pressure of the areas within limits following the postulated main steam and feedwater system ruptures, the inboard and outboard penetration area venting panels were increased from 100 to 650 by raising their roofs to Elevation 141 feet. 3.6-43 SGS-UFSAR Revision 25 October 26, 2010 I However, certain venting panels have obstructions and are not fully operational. Considering all obstructions, the net available venting areas are: 337 ft2 for the inboard penetration area, and 391 ft2 for the outboard penetration area. calculations have confirmed that the net available area maintains the internal pressure of the areas within previously established Certain Elevation 100-foot and limits as discussed in section 3.6.5.2.2. 78-foot area walls and floor sections were sealed in order to confine the environmental effects of the postulated breaks, and some localized impingement protection was added in order to accommodate the postulated breaks. 3.6.5.11 In some instances, of of the high energy systems was used to limit break mass flow rates and, hence, preclude any effects of pipe rupture. As stated in Section 3.6.5.10, where steam flows were found to be in excess of the capabilities of the available vent area, sleeving of selected break locations was employed to reduce pipe break mass flow rates to acceptable values. Encapsulation sleeving was installed in the Letdown Heat Exchanger Room, the Auxiliary Feedwater Pump Room, the Safety Injection Pump Room and the Waste Evaporator Room. In these cases, the encapsulation sleeves are designed and installed in accordance with the following criteria: 1. 2. 3. The will not sleeves were introduce significant encapsulated section of piping. and strain in a manner which concentrations on the The piping beyond the encapsulation sleeves was provided with restraints or anchors which restrict its axial displacement and motion within the sleeves following a postulated circumferential pipe break. The encapsulation sleeves were forces of internal (a) to withstand the dynamic from the escape of high energy fluid at the postulated pipe break location, assuming complete pipe severance and axial to the extent by the pipe restraints, and (b) to restrict the flow at the open ends of the sleeve to a level required to preclude compartment pressurization beyond the allowable 3.6-44 SGS-UFSAR Revision 25 October 26, 2010 structure design limits or beyond the of features to accommodate resultant environmental effects. Some of t:he encapsulations are sealed closed at both ends and are vented via piping to the roof outside of the Auxiliary Building. 4. The stresses imposed on the encapsulation sleeve during dynamic pressurization are limited to the design limits associated with "emergency condition" as permitted by ASME Section III, Nuclear Power Plant Components Code, for Class 2 Components. 5. The encapsulation sleeves were constructed in accordance with the current revision of the ANSI Standard Code for Pressure Piping, ANSI B31.1. Material inspection, fabrication, quality control, and applicable installation conformed with the requirements of the current revision of the ANSI Standard Code for Pressure Piping, Nuclear Power Piping, ANSI B31.7, for Class II piping, with the provision that each layer of the final assembly weld shall be nondestructively examined by surface examination techniques (i.e., liquid penetrant or magnetic ) rather than radiography. 6. The non-vented encapsulation sleeves are provided with open nipples, which extend beyond the pipe insulation as a means of monitoring the encapsulated pipe section for any leaks, which might develop in service. 7. The design of the encapsulation sleeves permits removal by machinery or flame cutting techniques or the replacement of the encapsulated pipe sections in the event leaks develop which require repair or replacement of the piping. 3.6.5.12 Moderate Energy Pipe Failure Evaluations-Unit 2 Only Moderate energy fluid systems outside of containment as defined in Section 3.6.5.12.1, have been evaluated for the consequences of 3. 6-45 SGS-OFSAR Revision 24 May 11, 2009 through-wall leakage cracks. Components required for the safe shutdown of the reactor were evaluated and have been provided, as necessary, with measures to ensure operability. 3.6.5.12.1 Definitions Moderate Energy Lines (MEL) Moderate energy piping includes those systems where both of the following conditions are met: 1. The maximum is 200°F or less 2. The maximum operating pressure is 275 psig or less Hazard For purposes of this evaluation, postulated leakage shall be considered for the effects of resulting flooding or liquid spray on components required for safe unit shutdown. 3.6.5.12.2 Postulated Break Location Moderate energy piping that is located in areas containing systems and components important to safety were postulated to develop a through-wall leakage crack at the most adverse location to determine protection needed to withstand the effects of the resulting liquid spray and floodircg. Moderate-energy piping that is located in areas that communicate, either through a door, curb, hatch, sleeve or drain, with those areas containing systems and components to were to at the most adverse location to determine the withstand the effects of the resulting flooding. a crack if any, to Piping systems that are components important to isolated and physically separated from systems by plant arrangement and layout were and not considered for postulated leakage cracks. Moderate energy piping that is located in the same area as high energy fluid systems considered for cracks. SGS-UFSAR breaks was not considered for 3.6-46 Revision 25 October 26, 2010 3.6.5.12.3 Postulated Crack Size Through-wall leakage cracks were postulated in runs and branches over 1-inch nominal size. Crack size was assumed to be the diameter in length by 1/2 the pipe wall thickness in width. 3.6.5.12.4 Evaluation Procedure A review of the Auxiliary Building was made to determine those compartments or areas with components required for safe reactor shutdown. Each of the compartments or areas containing safe shutdown equipment was evaluated to determine the effects of flood and spray from cracks within the area and the effects from with it. from areas that could Crack postulated flow rates of the largest MEL in the given space were estimated on the basis of the Bernoulli Q=KA l/2 (2gh) where K, the orifice coefficient, was assumed to be 0. 6. An accumulation rate or flood level was then estimated based on a comparison between floor and the postulated leakage rate. If liquid a flood threat to components within a compartment, an evaluation was made to determine the possibility of damaging each component and the acceptability of such damage. If necessary, modification to the existing design was appraised and performed to correct any conditions found to be adverse. Fluid spray consequences were evaluated on the basis of between components in the pressure or most unfavorably oriented MEL. area or space and the If it was determined that liquid spray in a given compartment or space could interact with componem:s within that space, evaluation was made to determine acceptability of such interaction and, if necessary, modification to exlsting design was determined to correct the condition. 3.6-47 SGS-UFSAR Revision 25 October 26, 2010 3.6.5.12.5 Inspection Results and Required Modifications Flooding in the RHR pump rooms can occur as a result of either MEL breaks inside or outside the rooms. Breaks in the pipe alley on Elevation 84 feet can communicate with RHR pump rooms on Elevation 45 feet via a pipe chase. Flooding to the RHR pump rooms could also occur as a result of MEL fluid from breaks on upper elevations running down staircases and conceivably into both RHR pump rooms. To prevent this from occurring, curbs were installed on Elevation 55 feet above the RHR pump rooms such that fluid flow from MEL failures on elevations above can only flow to one RHR pump room, both rooms. Alarms in the control room from high RHR pump room sump level will alert the control room remote or manual valve realignment. who in turn will terminate flow by Water spray from component cool:.ng lines in the RHR pump rooms could affect safety-related equipment in those areas. A single postulated MEL failure however will only involve one of two redundant RHR pump trains because of the wall between the rooms. spray failures in this area do not j ze safe shutdown of the Piping located in this area includes an auxiliary feed suction line, a fire hose station, and a preaction sprinkler system. Preaction sprinkler systems replaced the o:d C02 fire suppression systems in the 4160 v and 460 V switchgear rooms and the electrical penetration area. The feed suction line is empty and is not considered for cracks. The fire hose station has been provided with a shroud to prevent spray on empty, and is an electric/electric interlock system that uses a detection system air in the piping. The of both a head and both a thermal and a smoke detector are required to open the deluge supply valve. The piping in the room is designed to Seismic I requirements and the sprinkler heads are also seismically qualified. In the event of a fire, one or two sprinkler heads are expected to open to provide water to U:e effected area. The room has two 4-inch floor drains that are piped to the sump tank on the 5l ft elevation. 3.6-48 SGS-UFSAR Revision 25 October 26, 2010

. For the worst case scenario, six sprinkler heads are assumed to supply approximately 393 gpm to suppress the fire. Flow restrictors (orifices) were added to the two drains in the room to drain flow from sump tank overflow line thus of other rooms on the 64 ft elevation due to backflow the interconnected floor drains. Area 3 -Electrical Penetration Area Elevation 78 Feet This area contains only the fire protection preaction sprinkler piping which is similar to installed in the 64 ft switchgear room that replaced the C02 fire suppression system. In a fire, the zed air that is in the line between the valve and the closed heads is released by the of a fusible link that opens the valve when other electric alarm have been received. When the deluge valve opens the dry preaction sprinkler piping is charged with water. The backpressure provided by the 20 psig air that is maintained in the dry preaction system piping helps prevent the occurrence of water hammer in the preaction systen when the deluge valve opens. Under the assumed worst case co:1di tions, the preaction system can supply approximately 382 gpm flowing to six sprinkler heads to suppress a fire. Because the 4-inch drain in the room is due to HELB considerations, a new 4-inch drain was added that to the RHR valve room on the 55 ft elevation. Check valves in the drain lines back£ low interaction with the two new drains added to 84 ft switchgear room that also empty to the RHR valve room. The drainage from the 84 ft switchgear room and the 78 ft elevation electrical penetration room combine and empty into the RHR valve room and from there drain to one RHR punp room on the 45 ft elevation. at access from adjacent areas. the C02 fire into these areas has been 'l'he 4 60 V room on system with an to prevent the 84 ft elevation also automatically interlocked, preaction sprinkler system that was designed and installed per the requirements in NFPA 13 (2002 Edition). The preaction sprinkler system the 4 60 V switchgear room operated the same as those in the 4160 V S1*'l'i tcr.gear Room and in the Electrical Penetration Room. 3.6-49 SGS-UFSAR Revision 25 October 26, 2010 The fire protection piping within the 460 V switchgear room meets Seismic Category I requirements. The fire protection tie-ins to the 6-inch fire header and isolation valves located outside the room in the on the 84 ft elevation meet Seismic II/I There are two 4-inch floor drains in the that drain to the waste holdup tanks on the 64 ft elevation. Two new 4-inch drains were added to remove water from the switchgear room should the sprinkler system discharge in the event of a fire. Assuming the worst-case scenario, six sprinkler heads in a tight area grouping would discharge 379 gpm in the event of a fire in the room. The drain lines, which are open-ended and equipped with check valves to prevent backup, empty to the RHR valve room on the 55 ft elevation. From there, the water drains via an floor drain to a RHR pump room sump on the 45 ft elevation. With of one RHR pump room that could one RHR pump, the other RHR pump located in the acent, separate, non-flooded RHR pump room would be available. No other design basis accidents are to occur coincidental with a fire. However, switchgear room fires may result in the loss of both onsite and offsite power to the vital buses, which could result in a total loss of the RHR system, making it temporarily unavailable for providing decay heat removal. Safe shutdown for Salem is defined as ho:: standby. procedures identify repairs to the components that are required for establishing one RHR loop as necessary for cold safe shutdown. I!!. R for remote of either RHR pump in the event of a fire. However, the maximt::m flood level in the RHR pump room 30 minutes after actuation of one of the systems added to the switchgear rooms and the electrical penetration room is calculated to be less than 13 inches, which is well below the elevation of an RHR pump. This area contains MEL Floor drainage prevent of the Water water could affect ection pump motors have been of a shroud. spray however is adequate to from service water or ection pump motors. The from overhead spray by means This area contains, service water fire protection MEL piping. Floor drainage capacity in the area is adequa-.::e to prevent flooding. Water spray from service water cracks could affect 22 and 23 component pump motors and associated controls. 3.6-50 SGS-OFSAR Revision 25 October 26, 2010 Component cooling pump 21, however, is isolated in another compartment and would not be affected by this fault. Therefore, spray failures in this area do not affect safe shutdown of the Area 9 -Auxiliary Feed Pump Room -Elevation 84 Feet This area contains service water, fire protection, component cooling, demineralized water, and refueling water storage tank piping. Floor drain capacity in the area as well as drain capacity in the corridor to which this area is open, is adequate to prevent local flooding. Water spray from the MEL piping in the area can affect safety-related motor control centers 2C west and 2A west as well as control panels 205, 206, 2C7, and 213. In addition, water spray can affect the auxiliary feed pump motors. To prevent water spray to these vital components, motor control centers and control have been to withstand the effects of spray. feed pump motors have been with a shroud to prevent spray These rooms contain fuel oil MEL piping. from fuel oil cracks could affect fuel oil transfer pump motors. However, 21 and 22 fuel oil transfer pumps are physically isolated from each other and local MEL failures in one room will not affect the other room. No modifications are required. The 10 Ten C02 Room, the Diesel Fuel Storage Tank areas, and the entrance to these areas contain service water, fuel oil, and carbon dioxide fire protection MEL piping in addition to diesel fuel oil storage and transfer system equipment. The areas do not contain floor drainage; hence service water or fuel oil piping failure could cause flooding of the areas and the adjoining fuel transfer pump rooms. Therefore, flooding of diesel fuel oil storage and transfer system equipment can occur. Spray damage can also occur. However, because loss of off-site power coincident with service water or fuel oil piping failure is not a design basis condition at Salem Generating Station, diesel fuel oil storage and transfer equipment are not required to function to mitigate the consequences of such piping failure. Protection against the effects of service water or fuel oil piping failure is not required for diesel fuel oil storage and transfer system equipment. 3.6-51 SGS-UFSAR Revision 25 October 26, 2010 This area contains service water, component cooling, and spent fuel cooling MEL piping. is adequate to prevent flooding in the area. Portions of the MEL piping have been provided with a baffle to prevent spray damage to the charging pump motors. Area 12 -Containment Spray Pump Area -Elevation 84 Feet This area contains refueling water storage MEL piping. Drainage in the area is adequate to prevent flooding. Shrouds over containment spray pump have been provided to prevent water spray damage from MEL piping. This area does not contain any MEL piping. No modifications are required. Area 14 -Electrical Penetration Area -Elevation 100 Feet This area contains service water MEL piping to the chiller condensers. Drainage capacity is adequate to prevent flooding from postulated cracks. Water spray in this area does not any safe shutdown hazards. No modifications are Area 15 -Emergency Diesel Rooms -Elevation 100 Feet These rooms contain service water, demineralized water, and fuel oil MEL piping. The rooms do not contain floor drainage, hence a postulated service water line failure could conceivably cause flooding in a single room. The individual emergency diesel engines however, are physically isolated from each other and hence local MEL failures in one room will not affect the other rooms. No modifications are in this area. Area 16 Control Room Elevation 122 Feet This area contains service water, chilled water, and heating piping. A pressure tight steel enclosure is provided to encase all the piping. A drainage path is provided to remove any liquid from the enclosure. This area contains chilled water and service water MEL piping. in the area is to prevent flooding. Water spray does not present any safe shutdown hazards. No modifications are required in this area. 3.6-52 SGS-OFSAR Revision 25 October 26, 2010 Postulated modifications are of piping in this area is discussed in Section 9. 2. No in this area. Switchgear Room A 12-inch Class I (Seismic) demineralized water line passes through the switchgear room at Elevation 64 feet. This line is a nonessential backup water supply to the Auxiliary Feedwater System and will remain dry during normal plant operation, thereby precluding any potential for accidents after intrusion into vital electrical areas. Equipment arrangement and floor drainage systems are adequate to prevent flooding serious enough to impair the operation of equipment necessary for safe shutdown. In the event of any Class I (Seismic) line failure of "critical crack" size on floor elevations 84 ft and above, the discharged effluent would likely spread out over a large floor area and be carried away via existing floor drains to the waste hold-up tanks or the RHR pump room sumps. Floor drains on the 64 ft elevation are piped to the sump tank in each Unit and from there are either pumped to the waste holdup tanks or overflow to an RHR pump room sump. In addition, from MEL cracks on the 64 ft elevation and below can gravity drain via stairwells and pipe chases to an RHR pump room sump. The RHR sumps each have two Class lE powered pumps that discharge to the waste hold up tanks. Curbs are installed between the RHR valve rooms on the 55 ft elevation to prevent fluid flow from MEL cracks on elevations above from flowing into both RHR pump rooms. RHR sump level alarms would alert the to take the necessary action to maintain the in a safe condition. To minimize effluent from tanks into the Building, a "critical crack" in a Class I (Seismic) pipe, steps could be taken in the yard area to reduce tank inventories or divert the inventory to other storage facilities. 3.6.5.12.6 Additional Modifications In addition to the installation of the required modifications identified in Section 3.6.5.12.5, the floor Elevation 100 feet and 84 feet and 84 feet 3.6-53 SGS-UFSAR in the switchgear rooms between Revision 25 October 26, 2010 and 64 feet were sealed so that liquid blowdown would be directed to the floor drains. 3.6.5.13 Section 1 contains elevation and arrangement drawings which show the Containment, Auxiliary, and Fuel Handling Buildings. The Turbine Building, designed for Class III (seismic) requirements, is a separate building from all Class I (seismic) structures. The has a membrane which will tend to equipment within the building confines. any from piping, tanks, or Failure of any piping or tanks within the Turbine Building would not hamper the operation of any safeguards systems. Investigations have been made as to the capability of operation of related equipment in the event of a of non-seismic Class I tanks which could cause extensive flooding in the A seismic verification using the SQUG GIP methodology of the large non-seismic tanks in the Auxiliary Building determined that none were likely to rupture due to a seismic event. The sudden catastrophic failure of these tanks that are constructed to industrial standards is not credible. Many of the large tanks are contained within berms to prevent the spread of their contents over a broad area in the Auxiliary Building should operator error cause them to be drained. Those without berms have wide bases and will not over a seismic event. The tanks in the Building, except for error, are not considered credible sources of flooding. The study indicated that rupture of any tank in these buildings would not interfere with operation of the reactor or safe shutdown of the reactor. Floor drains are provided in the vicinity of all tanks. The floor drains in the vicinity of tanks having a volume of 1,000 gallons, or less, are more than SGS-UFSAR to provide in the event of rupture of a tank. 3.6-54 Revision 25 October 26, 2010 In the unlikely event that one of the larger tanks without a dike or berm were to drain its contents, most likely due to operator error, the resulting flood would spread out over an extensive floor area in the Auxiliary Building which would limit the flood height and preclude damaging safe shutdown The waste holdup, waste and bottoms storage tanks are diked to contain the volumes within the tank area. The monitor tanks are not diked, but the failure of any of these tanks would not cause flooding serious enough to prevent Class I (seismic) safety-related equipment from operating satisfactorily. Aside from floor drainage systems, stairwells, and floor openings would prevent water from to levels that could be termed critical. A similar showed that equipment arrangement and floor drainage systerr.s design are adequate to prevent flooding in the event of a non-Class I (seisrr.ic) pipe rupture serious enough to prevent safeguards systems from operating satisfactorily. Fire Protection pipe systems have been demonstrated to be adequately supported to withstand seismic events without structural pipe failure. and hydrogen are located in the Building. Ruptures will not jeopardize the required operation of a Class I (seismic) system, since the tanks, located at Elevation 122 feet in corridors to the north and south of the drumming and baling area, are isolated from Class I (seismic) equipment by virtue of their location, as well as by concrete walls. Supplementing the Public Service Electric & Gas 1972 (response to Mr. R. C. DeYoung's letter (PSE&G) letter of November 2, of September 26, 1972), tje failure of carbon dioxide fire protection equipment will not affect of systems. Automatic systems are in the areas. Manual carbon dioxide fire is in the control and relay room areas. SGS-OFSAR 3.6-55 Revision 25 October 26, 2010 3.6.5.14 All electrical cable types which are used for equipment in areas subject to adverse environmental conditions from pipe ruptures have been qualified for continued operation in these environments. Qualification tests consisted of exposure of the cable samples to thermal aging (e.g. 250°F for 7 days) radiation exposure (e.g. 100 x 1 R equivalent air dose with a Co60 source) , and cyclic steam and chemical spray (e.g. 34 0°F, 105 psig steam, Boric Acid and Sodium Hydroxide, cycled for 14 ) . after exposure showed no significant detrimental in insulation insulation dielectric breakdown capability, or cable parameters. and 3.6.6 References for Section 3.6 1. Letter, A. Giambusso (AEC) to F. W. Schneider (PSE&G), dated December 18, 1972, with attachment "General Information Required for Consideration of the Effects of a System Break Outside 2. 3. 4. 5. 6. 7. "Letter, D. B. Vassallo (AEC) to F. W. Schneider (PSE&G), dated January 31, 1973, with attachment "Errata Sheet for 'General Information for Consideration of the Effects of a Piping System Break Outside Containment.'" A. A., "The Phenomena of Rupture and Flow Solids," Philosophic Transactions of the Royal Society of London, Vol. 221, pp. 163-198, 1920. Letter, R. C. De Young (AEC) to F. W. Schneider (PSE&G), dated May 21, 1973. Branch Technical Position MEB 3-1, "Postulated Locations ir. Fluid System Piping Inside and Outside Containment," attached to SRP Section 3.6.2, Rev. 2, June 1987. Branch Technical Position SPLB 3-1, "Protection Postulated Piping Failures in Fluid Systems Outside Cor.tainment," attached to SRP Section 3.6.1, Rev. 2, October 1990. Letter from Mr. James C. Stone, NRC, to Mr. Steven E. Miltenberger, PSE&G, dated May 25, 1994, "Leak-Before-Break Evaluation of Primary Loop Piping, Salem Nuclear Generating Station, Units 1 and 211* EPRI TR-1006937 "Extension of the EPRI Risk Informed ISI Methodology to Break Exclusion Region Programs," April 4, 2002. 3.6-56 SGS-UFSAR Revision 25 October 26, 2010

8. 9. SGS-UFSAR WCAP-13659, "Technical Justification for Eliminating Large Primary Loop Pipe Rupture as the Structural Design Basis for the Salem Station Units 1 and 2," May, 1993. NRC Letter, Stone (NRC) to Mittenberger (PSE&G), "Leak-Before-Break Evaluation of Primary Loop Piping, Salem Nuclear Units 1 and 2," May 25, 1994 3.6-57 Station, Revision 25 October 26, 2010
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