LR-N17-0034, Salem Generating Station, Units 1 & 2, Revision 29 to Updated Final Safety Analysis Report, Section 10.4 Other Features of the Steam and Power Conversion System
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10. 4 OTHER FEATURES OF THE STEAM AND POWER CONVERSION SYSTEM 10.4.1 Main Condensers 10.4.1.1 Design Basis The condenser for each turbine generator unit consists of three single pass rectangular shells equipped with divided waterboxes and interconnected steam spaces for added flexibility of system operation. Each condenser is of the shell and tube design and arranged within the circulating water circuit for single pressure operation with the aix-flow, tandem compound steam turbine. The design parameters for the condenser are as follows: Steam Loading, Btu/hr Circulating Water, gpm Inlet Water Temp., °F Condensing Surface, sq ft Tube Material Tubes, O.D. x M.W.C. X Eff. Length Tube Quantity Design Pressure, in. Hg. abe.
- 7.636 X 109 1,110,100 61.8 800,000
- Al 6x 1" X 19 X 44" -9 3/4" 68,001 1.3 Unit 2 condensers contain some tubes which are AL6xN material. 10.4.1.2 System Description The triple shell condenser is mounted beneath the low pressure turbine exhausts with the condenser tubes oriented perpendicular to the turbine shaft and are designed to accept up to 40-percent 10.4-1 SGS-UFSAR Revision 15 June 12, 1996 instantaneous turbine load rejection. Four 10-inch diameter turbine bypass steam inlets per shell provide ample means of exhausting the rejected load into the steam lanes without any detrimental effects to the condenser internals. The condenser hotwell is designed for 5 minutes' storage capacity (approximately 120,000 gallons at maximum load) and to maintain 0.005 cc/1 of dissolved oxygen in the effluent condensate. The condensers are equipped with bolted, bonnet-type steel waterboxes and include Cathodic Protection System. Both waterboxes and tubesheets are coated with a high performance epoxy polymer. Fiberglass ladders are included in the waterboxes to provide access for maintenance purposes. Safety grids shield the waterbox nozzle openings for the protection of personnel during inspection or maintenance periods. Each condenser shell is connected to the turbine exhaust via a continuous rubber belt (dog bone) type expansion joint located in the condenser neck. Two low pressure feedwater heaters are mounted in each condenser shell neck with their channel heads extending through the inlet end of the condenser. Steel flexure plates mounted in individual heater closures accommodate any differential expansion between the condenser and heater. The vacuum system is capable of performing inleakage detection tests on the condenser shells without interruption of service. 10.4.2 Main Condenser Evacuation System The Condenser Air Removal and Primary System is shown on Plant Drawing 205208. There are eight rotary-type vacuum pumps provided, four for each unit. Three pumps (12, 13 & 14/22, 24 & 25) for each Unit are used for condenser vacuum and one pump (11/23) per Unit is used for waterbox priming tank vacuum. Each condenser vacuum pump has an individual holding capacity of 15 scfm of free dry air at a suction pressure of 1 in. Hg. absolute. Each condenser vacuum pump's hogging capacity is 1500 scfm at 15 in. Hg. absolute. Each vacuum pump requires 144 gpm of seal water cooling which is furnished by the Turbine Auxiliaries Cooling System. Seal water makeup 10.4-2 SGS-UFSAR Revision 27 November 25, 2013 is provided by the Demineralized Water System by means of a float control valve. Air and other noncondensable gases removed from the condensers are continuously analyzed by a radiation monitor located in the pump discharge piping prior to release into the atmosphere (See Section 11). Nonradioactive effluent is routed to the plant vent alongside each containment dome for release at an elevated point. The vacuum pumps are of the centrifugal displacement type employing a rptating ring of water to form a seal between its elliptically shaped casing and its curved radial bladed rotor. Centrifugal force causes the water to follow the contour of the casing, thereby changing the volume of the air space at the stationary suction and discharge ports resulting in air pumping. Each condenser vacuum pump suction line is so valved as to permit automatic changeover from a direct tie to the condenser to a tie having an air ejector which serves as the primary stage when an absolute pressure of less than 5 in. Hg absolute is realized. The air ejector uses atmospheric air as the motive fluid. The waterbox priming tank vacuum pump (No. 11/23) is a single stage pump which does not require an air ejector. Each vacuum pump is provided with a seal water pump which circulates water to the vacuum pump for the separator tank via a seal water cooler. The cooling water for the seal water cooler is supplied by the Demineralized Water System. Seal water cooling is provided to minimize flashing of the pump seal. The sealing water temperature affects the capacity of the vacuum pump. As the temperature increases, there is a reduction in vacuum pump capacity. It is therefore essential that the cooler be kept in a clean condition on both the tube side and water side, with the total temperature difference kept at less than 15° F. The seal water heat exchanger supplied with each vacuum pump utilizes stainless steel tubes and tube sheets. Exhausted air from each vacuum pump separating tank discharges to a common header and then to atmosphere via the plant vent. The flow is measured at the common header. 10.4-3 SGS-UFSAR Revision 20 May 6, 2003 The common discharge header is provided with radiation monitoring instrumentation to alarm in the Control Room if radioactivity is sensed at the vacuum pump discharged. 10.4.3 Turbine Gland Sealing System The Turbine Shaft Sealing System uses steam to seal the annular openings where the shaft emerges from the casings, thereby preventing steam outleakage and air inleakage along the shaft. The Turbine Gland Sealing Stearn and Leakoff System is shown diagrammatically on Plant Drawing 205207. 10.4.4 Turbine Bypass System 10.4.4.1 Stearn Dump Control System The Stearn Dump Control System serves to remove heat stored in the Reactor Coolant System (RCS). The full load average coolant temperature is significantly greater than the saturation temperature corresponding to the pressure setting of the steam generator safety valves. This, together with the fact that the thermal capacity of the primary system is greater than that of the steam system, requires that a heat sink be available to prevent lifting of the steam generator safety valves following a reactor turbine trip. The Turbine Bypass System provides the capability to dump up to 40 percent of full load steam flow directly to the condenser. This enables the plant to accept a step load decrease of 50 percent of full load from full load without reactor trip (the remaining 10 percent of the 50 percent is an inherent capability of the Nuclear Stearn Supply System (NSSS) to accept a 10 percent step load change) . Twelve bypass valves are required ( 4 per condenser shell) as there is a limitation on the maximum flow permissible through any one valve of 1,100,000 lb/hr should it fail in the open position. 10. 4-4 SGS-UFSAR Revision 27 November 25, 2013
*---------------After a reactor turbine trip, the stored heat in the primary* system is removed by the combination of steam dump to the condenser and atmospheric relief. Should the condenser not be available as a heat sink, the steam generator safety valves and power operated relief valves (PORVs) will open to dump steam to the atmosphere. When the steam generator safety valves are reseated, the PORVs are used to remove residual heat and control steam pressure. The Auxiliary Feedwater System is used to maintain steam generator level. The Stearn Dump System also acts as a supplemental heat sink for a load reduction of up to 50-percent of rated load, including the 10-percent step load change capability of the NSSS, without a reactor trip. Should a load drop in excess of 50 percent of full load occur, or should it be necessary to close the MSIVs with the plant under load, safety valve capacity equal to 100 percent of full load flow is provided on the piping just upstream of the MSIVs. This capacity is provided by five main steam safety valves on each main steam line with setpoints of 1070, 1100, 1110, 1120, and 1125 psig. The valves are located in the penetration area and are vented via umbrella-type vents to atmosphere through the roof of the penetration area. Additionally, a power operated main steam relief valve (MSIO) is provided on each main steam line upstream of the MSIVs (total relief capacity for 4 valves equals 10 percent of full load flow}. These valves, with a remotely variable pressure setpoint, can be used to bleed off reactor decay heat during cooldown. 10.4.4.2 System Evaluation The atmospheric dump capacity of the steam generator safety valves is 100 percent of full load flow and the PORVs can pass an 10.4-5 SGS-UFSAR Revision 16 January 31, 1998 additional 10 percent of full load flow. 'I'he number of turbine trips per year has been estimated to be 1.36, based on data from 60 plant-years of operating experience compiled by the Edison Electric Institute. HISTORICAL NOTE The 1:adiological exposure values contained in this section were originally calculated in response to SNGS-FSAR Question 10.1.1. (Historical Information) In the event that the PORVs in the secondary failed to open when required, secondary system pressure would increase to the setpoint of the first of the f:i.ve main steam safety valves. The five safety valves are set at 1070, 1100, 1110, 1120 and 1125 psig, respectively, and have a total relief capacity of 100 percent of full load flow to the atmosphere. The radiological consequences of this discharge to the atmosphere are calculated as described below. The maximum postulated total steam release is 3,356,100 lb (1.52 x 109 g). The postulated amount of steam released in the f:Lrst two hours :Ls 654,600 lb (2.97 8 X 10 g)
- The maximum perrni t ted concentration of speci £ ic activity in the secondary system is 0.10 of dose equivalent I-131. The calculated offsi te exposure from the postulated release to the atmosphere of secondary coolant equivalent to the amount of steam released in the first two hours due to a net load rejection wj.th loss of offsite power is less than 1.5 rem to the thyroid (whole body doses are negligible) . This was calculated from the equation: Dose(rem) c M B(t) X/Q DCF SGS-UFSAR C x M X B(t) X X/Q x DCF s0condary coolant specific activity, 0.10 amount of steam released in the f:i..r.st two hours, 2.97 x 108g breathing rate, -4 3 3.47 x 10 m-/sec atmospheric dispersion factor, 1.30 x 10-4 sec/m3 1.08 dose equivalent I-131 inhaled 10.4-6 Revision 23 October 17, 2007 * * *
(Historical Information) Anticipated secondary system iodine concentration is at least a factor of 10 less than the 0.10 value used in the above calculation. Additionally, -5 3 the estimate" atmospheric dispersion factor is 3.00 x 10 sec/m . Using the more realistic values for these parameters reduces the calculated thyroid exposure for this potential release path to less than 35 mrem. The condenser air removal gas monitors and the steam generator blowdown liquid monitors are described in Section 11.2.3.1. These monitors can be checked for proper operation by means of a check source. The range of detection selected for these monitors is based on the anticipated range and maximum activity to be measured. 10.4.5 Circulating Water System The Circulating Water System furnishes the main steam condenser with cooling water from the Delaware River and is shown on Plant Drawings 205209 and 205309. The Circulating Water System is a separate entity apart from the seismically designed Service Water System, which is covered in Section 9.2. 10.4.5.1 System Description The siphon recovery Circulating Water System supplies 1,110,000 gpm of Delaware River water to each unit's triple-shell condenser. are single pass with divided waterbox circulation. is 10.4-7 SGS-UFSAR The three condenser shells Each condenser shell half Revision 27 November 25, 2013 185,000 gpm and 27-foot total dynamic head (TDH}. Driven by 2000 hp induction motors, the six circulators per unit are mounted in individual pump cells in the intake structure, which is common to Units 1 and 2. The circulating water pumps are powered from their respective unit's 4160-V circulating water distribution system. Remote control of all pumps is maintained by the operator in the respective unit's control room. The 500-foot offshore circulating water system discharge is arranged to prevent recirculation while limiting the overall temperature rise of the river to 4°F or less in the vicinity of the outlet. The system is constructed of prestressed concrete, embedded steel cylinder pipe. Subaqueous piping is employed in the portion of the discharge piping submerged in the river. The inlet velocity to the intake screen wall is 1 fps at mean low tide which is compatible with local marine life. The intake includes 2-foot wide fish escape passages immediately in front of the traveling screens. The traveling water screens extend the full length and height of the 12-bay structure. The circulating water pumps are of the pullout-type design to operate at the lowest recorded river elevation of 81. 0 feet. All electrical components associated with the intake are mounted above the highest recorded water elevation for flood protection. An 8-foot high concrete wall is provided to protect the equipment from wave runup. A full depth heavy duty trash rack is located at the entrance to each pump cell to protect the circulating pumps and traveling screens from damage by large debris. Two mobile mechanical rakes are included to remove debris from the face of the trash racks. Refuse pits with removable bins are provided at each end of the intake structure for collecting the debris raked off of the trash rack and traveling screens for offsite disposal. Each circulating water pump is provided with a pump "READY TO START" circuit with associated pushbutton and "READY TO START" indicating light. Prior to a pump start, the "READY TO START" pushbutton is depressed. The "READY TO START" indicating light will flash while the pump permissives are being met and go solid when the pump is ready for starting. If the waterbox is under a vacuum of > 2. 5" Hg vacuum then the "READY TO START" circuit will open the pump's associated waterbox vacuum breakers allowing the waterbox to fill with air and reduce the vacuum to < 1" Hg. After the pump is started and SGS-UFSAR 10.4-8 Revision 16 January 31, 1998 brought up to design speed, the valve in the condenser discharge line is opened, the pump bypass valve is then closed and full circulating water flow is established. The circulating water circuit can be primed after the circulating pumps are put in operation. This eliminates the hydraulic surges encountered with conventional startup practices. Any entrapped air will be self-vented continuously through the water box bypass line. This will ensure that the water boxes are full for plant operation and will eliminate accumulated dissolved air which may be released under siphon conditions. Each circulating water circuit is equipped with quick opening vacuum breaker valves designed to admit air into the circuit in the event of a circulator trip out. The arrangement of the circulating water intakes is shown on Plant Drawing 208997. This area is served by temporary cranes, as required. The circulating water intake contains vertical, turbine-type auxiliary service pumps which supply the traveling screen spray wash system. There are four pumps per unit, each with automatic strainers in their discharge line. Two bearing lubrication pumps and strainers provide river water to the circulating water pump bearing and motor coolers for each unit. A standby backup line from the screen wash header to the lubrication system is provided for use during emergency and/or maintenance situations. 10.4.5.2 Performance Analysis All six circulating water pumps are normally in service. The condenser steam spaces are interconnected to permit operation with less than the full complement of circulating water pumps. For performance analysis, the Circulating Water System is equipped with test connections to evaluate flow conditions. In addition, 10.4-9 SGS-UFSAR Revision 27 November 25, 2013 the discharge pressure of each pump is monitored at the intake structure. 10.4.6 Condensate Polishing System 10.4.6.1 Design Bases The Condensate Polishing System (CPS) was designed to perform the following functions: 1. Removes the low levels of dissolved solids present in the feedwater or 2. secondary system and feedwater path. filter to remove suspended matter. The CPS also acts as a high rate Provides the plant with a feedwater system cleanup capability. The CPS together with the Condensate Bypass System allows for the flushing of feedwater lines and recirculation back to the condenser during startup to ensure that the water quality is within specification prior to its admission to the steam genera tor. Heater drains may also be recycled back to the condenser to permit feedwater cleanup. 10.4.6.2 System Description From the hotwells, condensate is directed through a full flow, high pressure, deep bed dernineralizer CPS by three condensate pumps. The primary purpose of the polisher is to reduce, by ion exchange, the level of the dissolved solids in the Stearn Generator Feed and Condensate System. The polishing system also filters out scale and particulate matter which may be present either as construction debris or as a result of corrosion products generated in the system. Secondary system cleaning may also be done by the Stearn Generator Blowdown System, and the Condensate Polishing System may be bypassed. The CPS is of the full flow, deep bed type and is designed to handle condensate at temperatures from 50°F to 130°F at pressures to 700 psig. Normal operating pressure will be about 475 psig. The CPS is designed to handle a normal and a maximum continuous flow of 22,000 gprn and 24,000 gprn, respectively, with five of the six dernineralizers operating in parallel. 10.4-10 SGS-UFSAR Revision 28 May 22, 2015 A feedwater pH range of 8. 8 amine chemistry (ethanolamine) . 9.6, is recommended for Salem with alternate While using ammonia only for pH control a range of 8. 8 9. 2 is recommended by EPRI. However, sodi urn levels in the feedwater become extremely critical in this pH range since sodium may be converted to sodi urn hydroxide. Sodi urn hydroxide, if carried over into the steam generators, will increase the possibility of caustic ernbri ttlernent of steel and stress corrosion cracking of Inconel components of the steam generator. Ammonium chloride is used for Molar Ratio Control (MRC) . MRC is the control of cations to anions. Sodium minimization is the primary control. Ammonium chloride injection can also be used to achieve the cation to anion balance, if sodium concentrations have been minimized, as ammonium already exists in large quantities and is volatile. The goal of MRC is to achieve near neutral crevice pH by controlling the molar ratio of cations and anions in the steam generator blowdown, thereby controlling steam generator corrosion. When the Condensate Polishing System is in full flow operation, the operator is alerted to (partial) bypass of the CPS when valve 1(2)CN-109 is open and either valve 11(21)CN-108, 12(22)CN-108 or 13(23)CN-108 are not fully shut (valves are shown on Plant Drawings 205202 and 205302). 10.4.7 Condensate and Feedwater Systems 10.4.7.1 Main Condensate and Feedwater System 10.4.7.1.1 System Description The Stearn Generator Feedwater and Condensate System is shown on Plant Drawings 205202 and 205302. Condensate is withdrawn from the condenser hotwells through a common suction header by three motor-driven, multi-stage, vertical centrifugal condensate pumps rated at 8000 gprn and 57 5 psi TDH. These pumps discharge into a common header which carries the condensate into the first five stages of feedwater heating. 900 gprn comes off of this line to supply the steam generator blowdown heat exchanger. This 900 gprn comes back into the condensate header after the first feedwater heater. A low flow recirculation line is provided on the discharge of each condensate pump to maintain a minimum flow of 1800 gprn for pump protection. The vertical motors are located at an elevation above the highest recorded river water level. 10.4-11 SGS-UFSAR Revision 28 May 22, 2015 Two, one-half capacity, high speed, barrel-type feed pumps take suction from a common header receiving feedwater from the discharge of the No. 5 heater. These feed pumps discharge into a common header, through the No. 6 high pressure feedwater heater and into a collecting header. Feedwater then flows through one line into the steam generator inlet header which is located outside the containment. Feedwater enters the containment vessel through four lines the containment wall, one line each steam generator. Feedwater flow control valve, motor-operated stop check valve, and isolation valves are installed in each steam generator feedwater line outside the containment. Each feedwater control valve is positioned by its own three-element control of feedwater flow to maintain steam generator level during startup and low power operation. All feedwater piping downstream from, and including, the isolating motor operated stop check valve is designed to meet Class I seismic requirements. A low flow recirculation line is provided on the discharge of each steam generator feed pump to maintain a minimum flow of 2300 gpm at design conditions for pump protection. Each steam feed pump is designed for a of 18, 600 gpm and total developed head of 8 8 4 psi. These design conditions were based on the maximum calculated turbine load plus allowance for pump wear and steam generator blowdown. Each steam generator feed pump is driven by a variable speed steam turbine with throttle steam supplied from the reheater outlet for normal two pump operation and from the Main Steam System during periods of low load. During startup, steam is supplied from the station heating steam system. Each steam generator feed pump turbine exhausts separately into one of the three condenser shells. The Feedwater Heating System utilizes six stages of closed feedwater heaters. All feedwater heaters are horizontal "U" tube, one-third size units, (three strings) with each heater string capable of satisfactory operation at 150 percent of its design feedwater flow. The feedwater heaters and piping are arranged to allow balanced turbine operation resulting from forced load limitation due to heater system outages. following sources: 10.4-12 SGS-UFSAR Bleed steam is provided from the Revision 24 May 11, 2009 Heater No. Extraction Source 6 High-pressure (HP) turbine bleed 5 HP turbine exhaust 4 Low-pressure (LP) turbine bleed 3 LP turbine bleed 2 LP turbine bleed 1 LP turbine bleed Drains from heaters No. 5 & 6 go to the drain tanks. Three heater drain pumps take suction from the drain tanks and discharge to the feed pump suction. Drains from the four LP heaters cascade in sequence to the condenser. The Bleed Stearn and Heater Drains System is shown on Plant Drawings 205205 and 205305. Design parameters of equipment in the Main Condensate and Feedwater System are listed in Table 10.4-1. The design codes for the Safety Related portion of the feedwater piping are ANSI B31.1.0 (1967) (see also Section 3.6.5.3). The design codes for the Non-Safety Related portion of the feedwater piping are ANSI B31.1.0 (1967) and later editions of B31.1 and alternate ASME codes/code cases. The design code for the condensate system is as defined in Reference 7 utilizing reduced ANSI B31.1.0 (1967) code allowables. Feedwater piping fabrication, installation welding, and examination involved in installing the Unit 2 replacement Stearn 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. The possible effects of a postulated rupture of a feedwater line have been minimized by judicious pipe routing and adequate pipe whip restraint. To ensure their integrity, the main and auxiliary feedwater lines inside the containment (out to their respective isolation valves) were constructed with materials, fabrication, inspection, and quality control in accordance with Nuclear Class 1 standards. Group bus undervol tage protection ( 68 percent of nominal) will automatically trip the condensate pump 4-kV breaker upon sensing an undervoltage (i.e., loss of voltage) condition on its respective 4-kV group bus (1E, 1F, 1G, and 1H) using 1/1 logic taken once. 10.4-13 SGS-UFSAR Revision 27 November 25, 2013 10.4.7.1.2 Feedwater Piping Integrity The AREVA NP Model 61/19T steam generator feedwater distribution system (shown in Figures 10.4-7 and 10.4-8) is a ring design connected via a T-section to a "helix" assembly welded to the thermal sleeve in the feedwater piping. The feedwater ring is supported by the thermal sleeve/helix weld interface and by sliding supports around the ring circumference attached to the internals. The ring supports are vertical structures that restrain motion in the vertical direction, while allowing thermal growth in the horizontal plane. This provides a support system that accommodates thermal motions and pump pressure pulses as well as all operational, seismic, and pipe break loads. The J-tube discharge is oriented to preclude direct impingement of feedwater on internal surfaces. This reduces the possibility of erosion. (J-tube arrangement is shown in Figures 10.4-7 and 10.4-8). Feedwater distribution system materials are selected to optimize resistance to erosion/corrosion, thermal and corrosion cracking. The austenitic stainless steel used for all the internal feedwater distribution system erosion resistance. Feedwater is distributed 50 percent to the cold side and 50 to the hot side. The Model 61/19T steam generator a "helix" between the feedwater pipe and feedring (Figures 10.4-7) to minimize the for thermal stratification. The helix allows the upstream of the feedwater piping to rapidly fill even during feeding with cold feedwater at low flow. This reduces temperature distributions and stresses in the pipe wall. The feedwater distribution design, equipped with the helix, minimizes the risk of thermal stratification damage. feedwater line break. The helix also helps to minimize blowdown during a The design of the Salem Unit 2 RSGs feedwater distribution system (J-tubes, all welded thermal sleeve/ring assembly and anti-stratification device) fully satisfies the design recommendations provided in BTP ASB 10.2. The Water Hammer Prevention Report, Reference 10, justifies that water hammer is not expected to occur inside the feedwater distribution system of the Salem Unit2 RSG during anticipated feedwater transients to the steam generator. This conclusion is confirmed by ( 1) mock-up tests representing or bounding all plant operational modes, ( 2) review of the limiting operational and design transients such as LOFW, (3) AREVA NP on-site tests and and (4) previous specific tests for water hammer performed at Unit 2. 10.4-14 SGS-UFSAR Revision 24 May 11, 2009 Feedring and J-Nozzle Modifications -(Unit 1 only) The Model-F steam generators were designated for service at Seabrook Unit 2 originally. The steam generators were originally furnished with a carbon steel feedring and carbon steel J-nozzles installed on the top of the feedring. Service at Salem and other stations has shown that the carbon steel J-nozzles are subject to accelerated erosion and corrosion. Design changes have been made and were implemented before the four steam generators were removed, from the Seabrook site. The carbon steel J-nozzles were removed by mechanical machining operations, and new J-nozzle assemblies, similar to Unit 2, welded in place. The new J-nozzle design in made of Inconel with a transition sleeve of carbon steel that is shop welded and examined to assure the integrity of the dissimilar weld. The inlet side of the carbon steel transition sleeve is buttered with Inconel to reduce the potential of erosion. The new J-nozzle assemblies are re-installed by welding the carbon steel sleeve to the carbon steel feedring. In normal operation, the feedring is filled with water. When this condition exists, there is no mechanism for initiation of water hammer. With the J-nozzles on top, the large vented area makes it very difficult to trap a bubble of steam in the feedring. Also, with the J-nozzles on top, the feedring fills first, and any refilling or recovering will not cause depressurization inside the feedring. Therefore, with the new J-nozzle installation, there are no expected operating occurrences that would allow steam to become trapped in the feedring and feedwater piping following a drop in steam generator water level below the feedring. The feedring configuration is shown in Figure 10. 4-Ba. This is a typical arrangement and each steam generator has a slightly different arrangement of J-tubes. Isometric diagrams of feedwater piping to the Salem Unit 1 steam generators are shown in figures 10.4-9 through 10.4-12. Feedwater Pipe Cracking Circumferential cracks were found in Unit 1 feedwater piping as a result of inspections pursuant to I and E Bulletin 79-13. These cracks were evaluated by the Westinghouse Research Center where the cause was attributed to cyclic stress assisted or accompanied by corrosion. The detailed evaluation of this matter, including corrective action taken, is contained in a report transmitted 10.4-15 SGS-UFSAR Revision 18 April 26, 2000 to the NRC by letter dated August 24, 1979. Action on Unit 2 is being taken as outlined in a letter dated September 18, 1979. The Unit 1 modifications to address the feedwater pipe cracking involved a replacement of the reducers adjacent to the nozzles. These replacements were performed with essentially a replacement-in-kind approach. Subsequent inspections of the Unit 1 feedwater piping and steam generator feedwater nozzle thermal sleeves identified additional cracking at piping welds and flaw indications on the thermal sleeves. This cracking has been attributed to cyclic stresses resulting from stratification loads due to cold feedwater injection into hot steam generators. The Unit 2 modifications to address the feedwater pipe involved a replacement of two of the four reducers adjacent to the nozzles. These replacements were also with essentially a replacement-in-kind approach. This like Unit 1, has also been attributed to stresses resulting from stratification loads due to cold feedwater injection into hot steam generators. During the Unit 2 Steam Generator replacement, all removed piping and fittings, including the one flued were replaced with erosion/corrosion resistant pipe and Enhancements were made to the Unit 2 steam to mitigate thermal stratification. As described in Section 3.6.5.3, one flued forging pieces have been attached to the Unit 1 steam feedwater nozzles to minimize the potential for thermal fatigue cracking concerns at the nozzle and inlet pipe locations. The one design the various fitting and fitting welds on the inlet piping thus eliminating the welds in the stratification zone. These forging pieces have integral thermal sleeves and are constructed of erosion/corrosion resistant materials to minimize the effects of erosion/corrosion on the existing steam generator thermal sleeves. The circumferential location of the feedwater nozzles for the replacement Unit 1 steam generators differs by approximately 900 from the The feedwater piping in the vicinity of the steam generators was rerouted to accommodate the new locations considering existing structural interferences and thermal stratification. There is no significant change to the likelihood of thermal stratification with the revised piping layout. 10.4-lSa SGS-OFSAR Revision 24 May 11, 2009 10.4.7.2 Auxiliary Feedwater System 10.4.7.2.1 Design Basis The AFW System serves as a backup system for supplying feedwater to secondary side of the steam generators at times when the Main Feedwater System is not available. The AFW System is relied upon to prevent core damage and system overpressurization in the event of accidents such as a loss of normal feedwater or a secondary system pipe rupture, and to provide a means for plant cooldown. 10.4-15b SGS-UFSAR Revision 24 May 11, 2009 The AFW System is capable of functioning for extended periods, allowing time either to restore normal feedwater flow or to proceed with an orderly cooldown of the plant to design temperature of the Residual Heat Removal (RHR) System. The AFW System flow and the water supply capacity is sufficient to remove core decay heat, reactor coolant pump heat, and sensible heat during the plant cooldown. Provisions are made to lirni t or terminate auxiliary feedwater flow to the affected loop 1) in the case of feedwater line break to ensure adequate flow to the effective steam generators and 2) in the case of a steam line break inside containment, to also limit the containment pressure. Plant conditions which form the basis for AFW System performance requirements are the following: 1. Loss of main feedwater transient (with and without offsite power) 2. Feedline rupture 3. Stearnline rupture 4. Loss of all ac power 5. Loss-of-coolant accident (LOCA) 6. Plant cooldown 10.4.7.2.2 System Description The AFW System, shown on Plant Drawings 205236 and 205336, supplies water to the steam generators for reactor decay heat removal if the normal feedwater sources are unavailable due to loss of outside power or other malfunction. Each unit is equipped with one turbine-driven and two rnotor-dri ven auxiliary feed pumps. Stearn for the 10.4-16 SGS-UFSAR Revision 27 November 25, 2013 turbine-driven pump is taken from two of the four main steam lines upstream of the MSIVs. Separate isolation valves are provided for these connections. The motor driven pumps receive power from the 4 KV vital buses. Feedwater System is designed as a Class 1E Safety Grade System. The Auxiliary The turbine-driven auxiliary feed pump, nominally rated at 880 gpm (plus 100 gpm continuous recirculation flow) and 1550 psid at 3840 rpm, and the motor-driven auxiliary feed pumps, nominally rated at 440 gpm and 1300 psid*, receive suction from the 220,000-gallon auxiliary feedwater storage tank. The minimum performance limits required for the auxiliary feedwater pumps to satisfy the design bases analyses, as verified during Technical Specification Inservice Testing, are included below. Note that these values account for test instrumentation uncertainties.
- 11 motor-driven AFWP 160 gpm and 1361 psid
- 12 motor-driven AFWP 160 gpm and 1361 psid
- 13 turbine-driven AFWP 400 gpm and 1395 psid at 3450 rpm
- 21 motor-driven AFWP 160 gpm and 1369 psid
- 22 motor-driven AFWP 160 gpm and 1389 psid
- 23 turbine-driven AFWP 400 gpm and 1506 psid at 3600 rpm Each motor-driven pump discharges to two steam generators with a normally isolated cross-connect line joining the motor-driven pump discharge headers. The turbine-driven pump feeds all four steam Feedwater flow is controlled from the Control Room by remotely operated flow control valves in the supply lines to each steam generator. For Units 1 and 2, reduced capacity trim has been installed on all eight flow control valves and AF21) to limit the maximum flow under certain plant conditions. Safety grade indication of auxiliary feedwater flow to each steam generator is provided in the Control Room. The AFW System circuits and initiation signals receive power from unit vital buses. testing. System initiation signals and circuits are designed for complete The AFW pumps are capable of being started in either the manual or automatic mode. Manually, the pumps can be started at their local control panel or from the main Control Room. Manual start circuits are for single failure, and of the automatic initiation signals or circuits will not affect the capability for manual starting. Automatic initiation signals and circuits are designed to prevent system malfunction for a single failure.
- No. 22 motor driven auxiliary feedwater pump rated at 450 gpm and 1175 psi. 10.4-17 SGS-UFSAR Revision 26 May 21, 2012 The motor-driven auxiliary feedwater pumps are started automatically by any of the following conditions: loss of offsite power, loss of main feedwater system, safeguards sequence signal, or low-low level signal from any one steam generator. When either of these pumps are started automatically, a signal is sent to close Steam Generator Slowdown and Sampling Systems' isolation valves. The isolation signal to the Sampling System isolation valves can be bypassed by the use of a keylock switch located on the control room console. This bypass capability allows control* room to open the Sampling System isolation valves when* sampling is required by the EOPs in the event.that a faulted steam generator with a low-low level condition is experienced. For the pumps to start in automatic mode, the REMOTE-LOCAL "MANUAL switch located on the local panel must be in the REMOTE position. The motor-driven auxiliary feedwat*er pumps are among the loads included in the diesel generator's automatic loading sequence. The turbine-driven auxiliary feedpump is started automatically by any of the following conditions: low-low level in two of the four steam generators or undervoltage on the reactor coolant pump group buses using 1/2 twice logic. For the pump to start in the automatic mode, the REMOTE-LOCAL MANUAL switch located on the local panel must be in the REMOTE position. When the turbine-driven pump is started automatically, Steam Generator Slowdown System valves and Sampling System valves are automatically closed. The isolation signal to the Sampling System isolation valves can be bypassed by the use of a keylock switch located on the control room console. This bypass capability allows control room operators to open the Sampling System isolation valves when sampling is required by the EOPs in the event that a faulted steam generator with a low-low level condition is experienced. The steam supply line up to the stop-start valve is continuously warmed by main steam. Traps and/or strainers/orifices are provided to ensure that condensate is removed from turbine steam piping. The turbine is a single inlet, single stage unit of rugged design such that water impingement will not its operation. Each of the two motor-driven pumps is provided with a minimum flow recirculation system to prevent damage to the pumps from low flow. In order to prevent a runout of the motor-driven pumps the steam generator level control valves (AF21s) are throttled back when pump discharge pressure drops below 1350 psig and are closed at 10.4-18 SGS-UFSAR Revision 17 October 16, 1998 1150 psig*. This runout protection feature can be overridden in the Control Room. The steam turbine driven pump is protected from operation with insufficient flow by a continuous recirculation flow. 100 gpm is built into the pump rated flow. The required margin of All auxiliary feed pumps normally take suction from the auxiliary feed storage tank. The tank is adequately protected from the effects of earthquakes, tornado wind loads, and floods. A safety grade, automatic low pressure trip is provided as backup protection for each pump in the event that tornado missile damage to the auxiliary feedwater storage tank results in loss of suction pressure. To protect against spurious activation, this trip will be made operable only during "tornado warnings" issued by the National Weather Service. The tank has sufficient capacity to allow residual heat removal for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. Backup water sources for the auxiliary feed pumps are the two demineralized water storage tanks (500, 000 gallons capacity each), the two fire protection and domestic water storage tanks (350,000 gallons capacity each) and the station Service Water System, which must first have a spectacle flange rotated into place. The quality of water from these sources is lower and is therefore intended for use only in the event of emergency situations. See Section 10.4.7.2.4 for an evaluation of service water usage in the AFW System. The Unit 1 & Unit 2 auxiliary feedwater storage tanks are provided with a nitrogen purge/blanket system in order to control the dissolved oxygen concentration in the water. Each nitrogen purge/blanket system is provided with a dedicated nitrogen source. The AFW tank has low and low-low level alarms which alert the operator to align pump suction to an alternate source. An alarm is also received when AFW Storage Tank level is approaching the minimum required volume by the Technical Specifications. Plant emergency instructions caution the operator to monitor the AFW water supply while in use. The low level alarm sounds at a level of 100,000 gallons and the low-low level alarm sounds at 30,000 gallons. The AFW tank has redundant channels of level indication. In addition, the demineralized water makeup
- Setpoints for the control valves for No. 22 motor driven pump (Valves 21 & 22AF21) are 1200 psig and 1000 psig, respectively. For No. 21 motor driven pump (Valves 23AF21 & 24AF21) setpoints are 1285 and 1085, respectively. 10.4-19 SGS-UFSAR Revision 28 May 22, 2015 supply valve to the AFW storage tank can be opened from the Control Room. In order to provide assutance that inadvertent failure (or closure) of the suction valve from the AFW storage tank will not result in a degraded condition of the AFW :system, the valve was first radiographed to ensure an open flow path and the yoke bushing and stem were then drilled and pinned in the open position. The ,handwheel was removed with the valve stern left in place to provide visual indication that the valve is open. There is adequate redundancy in the AFW System to provide reactor cooldown capability when necessary. During normal plant cooldown, each pump has the capacity to remove heat from the steam generators at a sufficient rate to prevent over-pressurization of the RCS and to maintain steam generator *levels to prevent thermal -cycling. . Once the normal steam generator level is re-established the AFW System can cool* down the RCS at a rate of 50°F/hr. Feedwater flow can be stopped when the reactor coolant has been cooled to approximately 350°F and 400 psig at which time the RHR System is used to continue the cool down For mitigation of a design basis event (small break LOCA, loss..:.of-offsite-power, loss of normal feedwater, feedwater line* break, main steam line break}, two pumps are required. The pumps, drives, valves, tanks; piping and appurtenances within the AFW System have been designed as Seismic Category I components. The 'AFW System piping and components are designed to the following codes and standards: Aux. Feed System Piping Aux. Feed Storage Tank Aux .. Feed Pump (except No 22 Aux Feed Pump} No. 22 Aux. Feed Pump Aux.' Feed System Valves
- ANSI 831.1 ASME Section III, sub-section N.D. ASME Section III Hydraulic Institute ASME Section III At the AFW System seismic boundary, valves AF-71 and AF-72 are not anchored with three orthogonal restraints. These valves are, however, anchored to the Seismic Category I Auxiliary Building wall. A stress review has sh-own that the anchors meet the intent o'f the system boundary definition given in NRC Generic Lett'er 81-14. In addition, the valves are protected from debris by a steel structure mounted to the Seismic Category I wall. This protective also provides seismic guides for additional protection of the seismic boundary valves. 10.4_;20 SGS-UFSAR Revision 21 December 6, 2004 * * *
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- The AFW System is periodically tested in accordance with the Technical Specifications . 10.4.7.2.3 System Evaluation Deta'iled thermal-hydraulic analyses have been conducted to verify that the AFW system design is adequate to meet design objectives. The results of these analyses satisfy the AFW flow requirements included in the Chapter 15 analyses, as surrunarized in References 1, 2 and 8. The single failure analysis, which is summarized in Table 10. 4-2, verified that the flow required to meet system performance objectives *will be delivered with two pumps, considering a single failure of a pump. The AFW System has*also been shown to deliver adequate flow to the two intact steam generators following a rupture in the steam line to the turbine pump and assuming the failure of a single motor-driven pump. In addition, the AFW flow rates are sufficiently small to avoid overpressurizing the containment following a steam line or feedwater line break. 10.4.7.2.4 Assumptions Potential Effects *of Salt Water as a Long-Term Source of Auxiliary Feedwater The use of service water for a long-term makeup source to the AFW System is evaluated based on the scenario described in Section 5.5 (in response to Branch Technical Position RSB 5-l} and on the following assumptions: 1. Following plant trip and loss of offsite power, auxiliary feedwater is initially provided from the 220,000 gallon AFW storage tank (AFST) . When the supply of water in the AFST has been d.epleted, AFW pump suction is transferred to the Service Water System (SWS). 2. River water has a total dissolved solid (TDS) value of 35,000 ppm as sodium chloride. 3. Decay heat removal is achieved using three of the four steam generators and the normal working level i's maintained throughout the major part of the scenario. 10.4-21 SGS-UFSAR Revision 21 December 6, 2004 I I ---------------------------------------4. Following the loss of offsite power the unit is held at the hot standby for 4 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> at which time cooldown is initiated. After 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> of cooldown, the RHR System is placed in operation. Salt Water Concentration Approximately 600, 000 gallons of water are to maintain the plant at the no load condition for 43 hours4.976852e-4 days <br />0.0119 hours <br />7.109788e-5 weeks <br />1.63615e-5 months <br /> followed by a 5-hour cooldown to 350°F. Thus the salt water requirement during this period is 600,000 gallons minus 220,000 gallons or 380,000 gallons for Unit 1. Unit 2 was based on 410,000 gallons, which includes 30,000 of additional volume for conservatism. Based upon the assumption that this salt water will contain 35,000 ppm TDS as sodium chloride, then the weight of salt introduced into the three available steam generators will be 51 tons for Unit 1 and 61.2 tons for Unit 2. At 350°F, the three Unit 1 steam generators will contain 259 tons of water and the concentration of salt in the steam generator water will be 0.2 t/t. At 350°F, the three Unit 2 steam generators will contain 259.3 tons of water and the concentration of salt in the steam generator water will be 0.236 t/t. From standard solubility tables, and using the same notation as above, the of sodium chloride at room temperature is 0. 36 t/t, increasing to 0.58 t/t at the no load temperature. Salt water would be first admitted to the steam generators 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after the loss of offsite power. By this time the thermal flux at the steam generator tube wall will be relatively low, and there will be no to hide out normally soluble ionic species. It is anticipated that steam release from the PORVs will tend to be increasingly intermittent as decay heat decreases. Thus, the net effect would be similar to bulk boiling, rather than the superheat-driven mode of boiling normally associated with steam generation for power purposes. SGS-UFSAR 10.4-22 Revision 24 May 11, 2009 In addition, the concentration of salt in the bulk steam generator water is well below the solubility limit of sodium chloride throughout the range of temperatures encountered. Therefore, no decrease in heat transfer capability due to the deposition of salt on the steam generator tube surfaces is expected for either Onit 1 or Onit 2 steam generators. Clogging of Steam Generator Flow Paths by Salt Accumulation I For both Unit 1 and Unit 2, the concentration and solubility of sodium chloride I indicate that the internals of the steam generator totally immersed in the bulk liquid phase would not be subject to salt precipitation and clogging. Similar consideration of the steel surfaces at the water/steam interface suggests that although some salt deposition is likely, the deposition will not be at a fixed boundary because of level changes caused by intermittent steam release via the PORVs. In addition, any rewetting will be carried out with water which has considerable salt solubilization capability. It is therefore unlikely that salt bridging will occur at the water I steam interface. Zones above this interface are not expected to become clogged with salt, since the evaporation purified the solvent phase. Thus any salt carried upward by liquid phase entrainment should be washed back down into the bulk liquid by relatively pure water (condensed steam). The corrosion of carbon steels in hot concentrated sodium chloride solutions is controlled by the metal alloying constituents, solution flow rate, oxygen concentration, temperature, and solution pH. Literature values for carbon steel corrosion rates at steam generator operating temperatures vary from 0.012 inch/week (3} to 0.21 inch/ week (4). Tests carried out on ASTM SA 285 Grade C steel show that a corrosion rate of approximately 0.015 inch/week can be expected when this material is exposed to concentrated sea water at 540°F (5). Based upon these data, some corrosion must be expected for carbon steels present in the steam generator due to the hot concentrated sea water. The condition of these carbon steel internals under hot standby conditions does not compromise the integrity of the primary to secondary steam generator boundary during normal power operation. 10.4-23 SGS-OFSAR Revision 24 May 11, 2009 I The materials of the tube support for both the Unit 1 and Unit 2 steam and anti-vibration support systems generators are stainless steel or Inconel. Calculation of general corrosion rates of stainless steel materials, based on a 58% NaCl solution at steam generator , vary from 0.0002 inch/week to 0.0413 inch/week (9). Therefore, for 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> exposure, the general corrosion would be 0. 0089 inch. F'or longer exposure periods, the material most affected by the NaC.l solution is 3041 stainless steel, which is used for the Unit 2 RSG cyclones and dryer vanes and would be subject to potential pitting. However, due to the base material thickness of these components, there is no concern for the integrity of the and dryer vanes, i.e., to have any structurally significant Data generated in single tube model boiler tests performed by Westinghouse indicate that Inconel 600 will pit at about 0.005 inch/week in hot concentrated sea water environments. Corroborative information of this behavior is contained in Reference 6. generators is 0. 050 inch. Nominal tube wall thickness in the Salem steam Thus only shallow tube wall should be as a result of 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> of operation at hot with concentrated sea water in the steam generators. No of tube wall is Corrosion data for Inconel 690 indicates that it can also pitting at a conservative rate of 0. 0002 inch/week in hot concentrated sea water environments (9). The nominal tube wall thickness in the Salem Unit 2 replacement steam generators is 0.043 inch and in 36 hrs the maximum depth is considered to be 4.3 x 10-5 inch. Thus, only shallow tube wall penetration should be anticipated as a result of 3 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> of operation at the postulated conditions with concentrated sea water. Like Inconel 600, no perforation of tube wall is Both primary circuit integrity and heat removal capability would be maintained and no provisions are necessary to attenuate the effects of service water addition to the steam generators. 10.4-24 SGS-UFSAR Revision 24 May 11, 2009 10.4.8 Steam Generator Blowdown System 10.4.8.1 Design Basis The Steam Generator Blowdown System is designed to be operable in all normal
operating modes. During periods of primary to secondary leakage, operation is controlled to ensure compliance with effluent regulations. To accomplish this, t hree possible blowdown paths are provided: (1) a blowdown path which utilizes a conventional blowdown system that discharges the effluent to the chemical waste basin for neutralization and disposal; (2) a blowdown path which utilizes a flash tank, a heat exchanger, a filter, a demineralizer, and then to the condenser; and (3) a blowdown path which discharges the blowdown to condenser. Operating conditions dictate which path should be used.
10.4.8.2 System Design and Operation The system flow diagram and operational logic are shown on Plant Drawings
205225 and 205325 and Figure 10.4
-19, respectively.
Operation of the Blowdown System is initiated remotely from the Control Room.
The blowdown rate of each steam generator is indicated on and controlled from
the main console.
During startup (as well as up to 20 percent power, if required) the blowdown is directed to the No. 12 (22) steam generator blowdown tank. As soon as possible once the unit is online, the blowdown is transferred to the No. 12 (22)
condenser.
When blowdown is directed to the steam generator blowdown tank, a portion of the water, which is at saturated conditions, flashes to steam. The steam is vented to the atmosphere through a rooftop vent and the remaining water is gravity drained to the chemical waste basin. The water is treated and then discharged to the Delaware River through the Circulating Water System discharge lines. It is anticipated that this blowdown path will only be used intermittently at those times when the condenser is not available.
When the blowdown is directed through the heat recovery system, the water passes through a flash tank, a heat exchanger, a filter (in which the iron particles, suspended in solution by polyacrylic acid are removed), a demineralizer, and then enters the condenser. A portion of the blowdown flashes to steam in the flash tank and is vented to the feedwater heaters 4. The liquid from the tank transfers its heat to the portion of the condensate that bypasses feedwater heater number 1.
10.4-25 SGS-UFSAR Revision 29 January 30, 2017
If a steam generator should develop a primary to secondary leak in excess of the radiation monitor setpoint while the Blowdown System is discharging to the condenser No. 12(22), 13(23) or the chemical waste basin, high radiation signal from any of the blowdown sample radiation rnoni tors will close the isolation valves and terminate blowdown. 10.4.8.3 Design Evaluation If a steam generator should develop a primary to secondary leak while the blowdown system is discharging to the condenser or the chemical waste basin, the blowdown radiation monitor will alarm. The radiological warning, alarm and isolation functions of the steam generator blowdown system are described in section 11.4. Stearn generator water chemistry will be rnoni tored to ensure chemistry conditions are maintained as described in section 10.3.5.2. Blowdown and sampling line piping fabrication, installation, welding, and examination involved in installing the Unit 2 Replacement Stearn Generators utilized ASME Section XI (1998 Edition with 2000 Addenda) and ASME BPVC,Section III, Division I, Subsection NC, (1995 Edition with 1996 Addenda). Both of these later codes are NRC endorsed per 10 CFR 50.55a and were reconciled to the original construction codes. 10.4-26 SGS-UFSAR Revision 28 May 22, 2015 (This text has been deleted) 10.4.9 References for Section 10.4 1. E.S. Rosenfeld to J.R. Gasperini, "Salem Units 1 and 2, Final Definition of AFW Flow Assumptions To Be Used In Fuel Upgrade/Margin Recovery Project and Steam Line Break Analyses," NFU-93-083, February 11, 1993. 2. E. S. Rosenfeld to J. Huckabee, "Salem Units 1 and 2, Steam Line Break Analyses Assumptions," NFU-93-303, May 28, 1993. 3. Potter and Tease, Corrosion Science Vol. 12, No. 4, April 1972. 4. Huijbregts, W. M., VGB Speiswassertagung 1970. 5. Wootton, M. J., Westinghouse Class 2 Research Report 77-IB6-DENTS-R1. 6. Roberts, D. J., et al., AEC Research and Development Report GA-9299. 7. PSE&G Report S-C-CN-MEE-1073, "Condensate System Design Pressure Reconciliation," Revision 1. 8. Nuclear Fuels Letter NFS-00-264, "Salem Units 1 and 2 -Reduced AFW Flow Evaluation", dated 12/12/00. 9. VTD 900031, AREVA NP Document No. 12-9018620-002, "Salem Unit 2 -Effect of Seawater Intrusion on Salem 2 RSG Corrosion." 10. VTD 900175, AREVA NP SAS Document No. NFPMG DC 0019 Revision C, "Salem Unit 2 RSG-Water Hammer Prevention (ASB-BTP 10-2)." 10.4-27 SGS-UFSAR Revision 24 May 11, 2009