ML17226A101

5 to the Updated Safety Analysis Report, Chapter 10, Steam and Power Conversion System

ML17226A101
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Site:	River Bend
Issue date:	07/28/2017
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RBS USAR Revision 12 10.1-1 December 1999 CHAPTER 10 STEAM AND POWER CONVERSION SYSTEM 10.1

SUMMARY

DESCRIPTION The steam and power conversion system is designed to produce electrical energy through conversion of a portion of the thermal energy contained in the steam supplied from the boiling water reactor, to condense the turbine exhaust steam into water, and to return the water to the reactor as heated feedwater with a major portion of its gaseous, dissolved, and particulate impurities removed.

The major components of the steam and power conversion system are: turbine-generator-exciter complete with moisture separator/reheaters, main condenser, condensate pumps, condenser air removal system, turbine gland sealing system, turbine bypass steam system, condensate demineralizer system, heater drain pumps, reactor feed pumps, feedwater heaters, and drain coolers (Fig. 10.1-1). The heat rejected in the main condenser is removed by the circulating water system.

• 12 The saturated steam produced by the boiling water reactor is passed through the high-pressure turbine, where the steam is expanded, and then exhausted to the moisture separator/reheaters. The moisture separators reduce the moisture content of the steam, and the reheaters superheat the steam before it enters the low-pressure turbines. From the low-pressure turbine, the steam is exhausted into the main condenser, where it is condensed and deaerated, and then returned to the cycle as condensate. A portion of the main steam is fed to the reheaters. This main steam is condensed in the reheater and cascaded to the highest pressure heater. A small part of the main steam supply is continuously used by the air ejectors. The condensate pumps take suction from the condenser hotwell, discharge through the air ejector intercondensers, steam seal condenser, off gas condenser, condensate demineralizer ion exchangers, drain coolers, and five stages of low-pressure feedwater heaters to the suction of the reactor feed pumps. The reactor feed pumps supply feedwater through one stage of high-pressure feedwater heaters to the reactor. Steam and hot water for heating the feedwater in the heating cycle is supplied from turbine extractions and moisture separator/reheater drains, respectively (Fig. 10.4-7a - k).

12*

Normally, the turbine uses all the steam being generated by the reactor. However, an automatic pressure controlling turbine bypass system is provided to discharge excess steam, up to 10 percent of the design flow, directly to the main condenser. The turbine bypass system is designed to control reactor pressure by dumping excess steam during startup, shutdown, and transient periods during power operation when the reactor steam generation exceeds the turbine steam requirements.

• 12 Some steam valves 2 1/2 inches in diameter or larger located in the turbine and auxiliary buildings, not individually sealed by the turbine gland sealing system, have their seals vented back to the condenser to minimize steam leakage. Sources of radiation and airborne radioactivity, shielding requirements, radiation zones, and access procedures for the turbine building, and the demineralizer and off gas areas are discussed in detail in Chapter 12.

12*

The principal design and performance characteristics of the steam and power conversion systems are summarized in Table 10.1-1. The system heat balances for both rated flow for turbine guarantee and

RBS USAR 10.1-2 August 1987 valves-wide-open (VWO) flow are shown in Fig. 10.1-3 and 10.1-4, respectively. VWO, as it is used in this chapter, is defined as 105 percent of the rated steam flow delivered to the high pressure turbine.

RBS USAR 10.2-1 August 1987 10.2 TURBINE GENERATOR 10.2.1 Design Bases The turbine generator is designed in accordance with the following criteria:

1.

The turbine is a 1,800 rpm, tandem compound, 4-flow, reheat steam turbine with 43-in last stage buckets and a single stage of reheat. The maximum capability of the turbine is 1,031 MWe gross with valves wide open and inlet steam conditions of 965 psia and 99.6 percent quality while exhausting at 3 in Hg abs (81.1°F circulating water inlet temperature) with 0 percent makeup, and extracting for six stages of feedwater heaters. During faulted and emergency conditions the turbine is shut down.

2.

The generator is a

1,151,100-kVa, 1,800-rpm, direct-connected, 3-phase wye connected, 60-Hz, 22,000-V, liquid-cooled stator, hydrogen-cooled rotor, synchronous generator rated at 0.90 pf, 0.58 short circuit ratio, and a maximum hydrogen pressure of 75 psig.

3.

The compact Alterrex excitation system consists of a 60-Hz, 1,800-rpm air-cooled Alterrex generator and liquid-cooled rectifiers with static regulation equipment. The exciter is rated for a maximum output of 3035-kWt at 500-V.

4.

The turbine generator unit control is effected through an electrohydraulic control (EHC) system capable of controlling the speed, load, and steam flow under steady-state and transient conditions.

The turbine generator is normally base loaded; however, the design allows for the unit to operate in a reduced frequency mode of operation. Section 7.7 contains a complete description of the turbine-generator EHC control system.

5.

The turbine-generator unit, a General Electric Company (GE) design, is built in accordance with GE and industry standards and codes.

The moisture separators/reheaters are built in accordance with ASME Section VIII.

6.

The generator load can be changed at a rate of 2.22 percent/sec. The reactor's rate of load change is somewhat slower and, as such, becomes the controlling factor (Section 4.4.3.5).

7.

An assessment of the risk to essential plant systems and structures from potential turbine missiles is discussed in Section 3.5.1.3.

RBS USAR Revision 25 10.2-2 10.2.2 Description The turbine consists of one double-flow, high-pressure casing and two double-flow, low-pressure casings. It includes two moisture separator/reheaters connected between the high-pressure and low-pressure casings with chevron-type packing used for moisture separation. The turbine is equipped with extraction nozzles to provide extraction steam for six stages of feedwater heaters.

Each high-pressure main steam line to the high-pressure casing contains a main turbine stop valve plus an automatically controlled main turbine control valve. Combined intermediate valves (each composed of an intercept valve and an intermediate stop valve) are provided in the hot reheat steam lines from the moisture separator/reheaters to the low-pressure turbine casings A and B.

The Ovation TCPS control logic is designed such that the turbine power follows reactor power. The pressure control system acts to maintain constant reactor pressure at a preset value. Pressure management is achieved by tight coordination between the turbine control valve positioning and the bypass valve positioning algorithms. The combined control of the bypass valves and the turbine control valves act to maintain the system pressure at the desired set point, within its design capabilities.

The Ovation TCPS will perform the following major functions:

x Reactor pressure regulation x

Turbine speed and load control x

Turbine fault and overspeed protection Turbine Governor functions and turbine control functions are covered more fully in Section 7.7.

The main steam lines provide four parallel flow paths to the high-pressure turbine with each path containing a stop and a control valve in series. Steam exhausting from the high-pressure turbine passes through the moisture separator/reheaters and returns to the low-pressure turbines. There are two parallel steam flow paths to each of the two low-pressure casings. Thus there are a total of four steam flow paths. Each steam flow path contains a combined intermediate stop valve and an intercept valve arranged in series within a single valve body.

The turbine generator is equipped with a digital Turbine Control and Protection System (TCPS), consisting of a set of dual redundant controllers for turbine control system (TCS) and a set of dual redundant controllers for the Emergency Trip System (ETS). The TCS is a highly reliable system employing three active speed sensors for normal speed control and backup overspeed trip, load, and flow control, and three throttle pressure transmitters for throttle pressure control. The ETS utilizes three passive speed sensors in a diverse overspeed trip system. These systems protect the turbine-generator from destructive overspeed events.

RBS USAR Revision 25 10.2-3 12 In the event of an overspeed, the EHC system normal speed load control and power load unbalance function starts to close the main turbine control valves to reduce speed (Fig. 10.2-3) and at 105 percent the main turbine control valves are fully closed.

This completely blocks the flow of steam to both the high-and low-pressure turbines. At 105 percent overspeed, the intercept valves begin to close. At 107 percent overspeed, the intercept valves are fully closed. If speed reduces to 105 percent the intercept valves reopen. Closure times for the main turbine stop valves and control valves are 0.15 sec and 0.19 sec, respectively. Closure times for the intermediate stop valves and the reheat intercept valves are 0.17 sec and 0.20 sec, respectively.

12 Valve opening activation is provided by a 1600 psig hydraulic system. However, valve closure under emergency tripping is provided by powerful springs and aided by steam forces when the high-pressure hydraulic fluid is dumped from the piston by the tripping action.

12 12 8 To prevent steam entry into the turbine from extraction points, all such sources of serious overspeed potential are equipped with power-assisted swing check valves. The fifth and sixth point extraction lines and heaters do not possess a sufficient amount of unrestrained energy to cause turbine overspeed. Therefore, check valves are not

required, based on the turbine manufacturer's guidelines.

None of the remaining extraction steam lines to the feedwater heaters individually possess a sufficient amount of unrestrained energy to cause a significant turbine speed increase and, although check valves are required, power-assisted check valves are not

required, based upon the turbine manufacturers guidelines for overspeed protection. Nozzle check valves are included in the lines as an added level of protection against water induction damage as well as overspeed. Based on the unrestrained energy available and the turbine manufacturers guidelines, the only power-assisted check valves required are the power-assisted check valves in the extraction steam supply to the Turbine Gland Seal Evaporator System.

8

RBS USAR Revision 25 10.2-4 During normal overspeed protection system operation, the check valves are forced closed by the start of reverse flow through these lines thus shutting off these possible contributions to turbine overspeed. The closure times for the extraction steam check valves are 0.10 secs. Motor operated extraction steam stop valves are installed for isolation. The closure times of the extraction steam motor operated stop valves are a function of the closing speed (12 in/min) and the valve size. Closure times are as follows: first point extraction, 50 secs; second point extraction, 80 secs; third point extraction, 90 secs; and, fourth point extraction, 140 secs.

The extraction steam system is shown on Fig. 10.4-7. Stable turbine operation is assured by satisfying GE criteria on the number, location, and the closing times of the extraction steam check valves.

A failure of any component does not lead to destructive overspeed.

A multiple failure involving combinations of undetected electronic faults, mechanically stuck valves, and/or hydraulic fluid contamination, at the same time as load loss would be required to cause an overspeed. The probability of such joint occurrences is extremely low due to the inherent high reliability of the design of the components.

The TCS system of TCPS is organized into three major functions to minimize interactions. The speed control function compares actual turbine speed with the speed reference and the acceleration reference to control speed during turbine startup, a speed error to the speed regulator for the load control function.

The load control function combines the speed regulator output with the load reference signal and provides limits and biases to determine the desired steam flow signals for the main turbine stop and control valves and intercept valves. Finally, the valve flow control functions accurately position the appropriate valves to obtain the desired steam flows to the turbine.

The turbine generator overspeed protection system is not a safety-related system. Since the redundant speed control systems, electrical power, and hydraulic equipment are not necessary for the safe shutdown of the reactor, no protection is provided for the overspeed detection system from the effects of high or moderate energy pipe failure. Refer to Section 3.6 for further discussion of high and moderate energy pipe break effects. In the event of a high or moderate energy piping failure, it may be possible that the turbine could lose the electrical speed control system. Such a failure would not affect the hydraulic speed control system, because depressurization of the hydraulic piping would result in the closure of the main turbine stop and control valves. Details of the overspeed protection system and the related turbine valving are discussed below and in Reference 2.

RBS USAR Revision 25 10.2-5 The Ovation Turbine Control and Protection System (TCPS) provide the following overspeed protection features:

a. Normal speed control that closes the control valves at 105%

and the intercept valves at 107%.

b. Power-Load Unbalance (PLU) function that results in fast closure of the control valves and intercept valves.

c. Intercept Valve Trigger (IV Trigger) function that results in fast closure of the intercept valves.

d. Primary electronic overspeed protection system (DOPS), 110%

set point, 3 passive speed probes, 2 out of 3 channel trip and single failure proof, and on-line testable. DOPS is diverse and independent of the normal speed control system.

e. Backup overspeed trip, 111% set point, 3 active sensors, 2 out of 3 hardware channel trip independent of software and on-line testable.

f. Backup overspeed trip, 111% set point, trip logic in software.

g. Two testable dump manifolds (TDMs) to trip turbine, each arranged in 2-out-of-3 logic, and either TDM trip will trip the turbine.

TDM solenoids are testable on-line.

Furthermore, a cross trip feature also exists to trip each TDM solenoid to drain emergency trip system fluid resulting in fast closure of all turbine steam admission valves, tripping the turbine.

Upon occurrence of a turbine trip, a signal is supplied to the reactor protection system to trip the reactor as described in Section 7.2.1.

The purpose of the protection system is to detect undesirable or dangerous operating conditions of the turbine generator, take appropriate trip actions, and provide information to the operator about the detected conditions and consequent actions. Protective devices include exhaust hood high temperature alarm and trip, and a pilot dump valve for protective closing of extraction nonreturn valves.

RBS USAR Revision 12 10.2-6 December 1999

12 The turbine lubricating oil system supplies oil for lubricating the bearings. A bypass stream of turbine lubricating oil flows continuously through an oil conditioner to remove water and other impurities.

12

The hydrogen control system includes pressure regulators for control of the hydrogen gas and a circuit for supplying and controlling the carbon dioxide used in purging the generator during filling and degassing operations. To prevent hydrogen leakage through the generator shaft seals, a hydrogen seal oil system is provided. This system, which includes pumps, controls, and a storage tank, deaerates the oil before it is sent to the shaft seals.

Hydrogen is manually fed to the generator to maintain design pressure. A normally closed automatic shutoff valve is provided at the bulk storage facility, operable from the local hydrogen control panel. Another manual shutoff valve is provided in the turbine building. The operator must open both valves to obtain hydrogen feed to the generator. Refer to Section 9.5.9.3 for a discussion of these bulk storage facilities.

To avoid an explosive hydrogen-air mixture while charging the generator with hydrogen, carbon dioxide is used as the purging agent. While the generator is being filled with carbon dioxide, the percentage of carbon dioxide in the air/gas mixture is measured. Carbon dioxide is admitted to the generator until the percentage of carbon dioxide in the discharged gas is in excess of 70 percent. After purging the air from the generator, hydrogen is admitted.

The stator liquid cooling system is a closed water cooling system that operates as an independent subloop in the turbine-generator control system. Control and alarm devices are provided for automatic regulation of flow rate and temperature of clean, low-conductivity water to the stator winding.

The main loop of the system includes a storage tank, two pumps in parallel, two coolers in series with a bypass branch for temperature regulation, and a filter and strainer for flow through the generator. There is a bypass branch with a filter and deionizer for continuous purification of a small percentage of the total flow passing back to the storage tank. A second bypass branch provides filtered cooling water for the static rectifiers in the excitation system. Additional components promote reliable service and ease of maintenance.

The general arrangement of the turbine and associated equipment is shown in Fig. 1.2-33 through 1.2-37.

RBS USAR Revision 8 10.2-7 August 1996 10.2.3 Turbine Disc Integrity



The low pressure turbine rotors are of a monoblock design. The rotor and disc (wheel) are produced as a single forging. This design eliminates all wheel bore and keyway stresses and virtually eliminates the missile generation probability.

10.2.3.1 Materials Selection The monoblock rotors are made to a chemistry which is optimally balanced to have high hardenability, to achieve good fracture toughness at the required tensile strength, low tramp elements to minimize temper embrittlement, and low sulfur to minimize harmful segregation. This material is similar to ASTM A470 Class 6 (the nominal composition is 0.3C-3.5Ni-1.6Cr-0.5Mo-0.1V) but with more restrictive quality requirements.

The steel is melted in a basic electric furnace and is vacuum carbon deoxidized to eliminate any possibility of hydrogen flakes and to minimize the presence of nonmetallic inclusions which would be harmful to fracture toughness. The molten metal is poured into ingot molds with sufficient top and bottom material for optimum top and bottom discard practices in order to remove all segregated material.

After solidification, the forging is done under very stringent temperature limits using forge presses with adequate capacity to work the metal deep within the forging. The final heat treatment is optimized to achieve small grain sizes. Following the final austenitize, the rotors are quenched in water to optimize the micro structure and to ensure good deep seated fracture toughness so that a large critical crack size can be tolerated without concern for fracture.

After quenching, the rotor is tempered and cooled at a rate sufficiently fast to minimize temper embrittlement buy yet slow enough to insure freedom from high residual stress. After the rotor is heat treated, it is machined to near final dimensions and given a thorough NDT inspection.

Rotor (Disc) Material Properties:

SPECIFICATION SURFACE BORE Tensile Strength, Ksi 105/125 100 min.

0.02% Yield Strength, Ksi 80 min.

75 min.

Reduction of Area, %

50 min.

35 min.

Elongation, %

17 min.

14 min.

Charpy V-Notch @ Room Temp, ft-lbs 55 min.

40 min.

FATT, F 0 max.

+30 max.

8

RBS USAR Revision 12 10.2-8 December 1999 10.2.3.2 Fracture Toughness

12 

Suitable material toughness is obtained through use of materials described in Section 10.2.3.1 to produce a balance of adequate material strength and toughness in order to ensure safety while simultaneously providing high reliability, availability, efficiency, etc, during operation. Turbine operating procedures are employed to preclude brittle fracture at startup by ensuring that the metal temperature of rotors is adequately above the FATT. Details of these startup procedures are contained in Chapter 14.

8 12

10.2.3.3 High Temperature Properties The operating temperatures of the high-pressure rotor in turbines operating with light water reactors are below the creep rupture range. Creep rupture is therefore not considered to be a significant factor in assuring rotor integrity over the lifetime of the turbine.

Below the creep rupture temperature range, rupture failure is essentially a tensile phenomenon and characterized by the yield and tensile strength of the material. Thus, since the operation temperatures of the high pressure rotor are below the creep temperature range, the yield criterion (0.75 yield stress) governs the material behavior and defines the design limits.

10.2.3.4 Turbine Disc Design



The turbine assembly is designed to withstand normal conditions and anticipated transients including those resulting in turbine trip without loss of structural integrity(5). The design of the turbine assembly meets the following criteria:



1.

Turbine shaft bearings are designed to retain their structural integrity under normal operating loads and anticipated transients, including those leading to turbine trips.

2.

The multitude of natural critical frequencies of the turbine shaft assemblies existing between zero speed and 20 percent overspeed are controlled in the design and operation so as to cause no distress to the unit during operation.



3.

The maximum tangential stress in rotors resulting from centrifugal forces, and thermal gradients does not exceed 0.75 of the yield strength of the materials at 115 percent of rated speed. The location of these maximum stresses is at the base of the integral wheel/surface of the rotor.

8

RBS USAR Revision 12 10.2-9 December 1999



10.2.3.5 Preservice Inspection The following preservice inspection program is implemented:

1. Rotor forgings are rough machined with minimum stock allowance prior to heat treatment.

2. Each rotor forging is subjected to a 100 percent volumetric (ultrasonic) examination.

Each finish-machined rotor is subjected to a surface magnetic particle and visual examination. Results of the above examination are evaluated by use of acceptance criteria which are more restrictive than those specified for Class 1 components in the ASME Boiler and Pressure Vessel Code, Sections III and V, and which include the requirements that subsurface sonic indications are evaluated to assure that they do not grow to a size which compromises the integrity of the unit during the service life of the unit or that the defect is repaired.

3. All finish-machined surfaces are subjected to a magnetic particle examination.

No magnetic particle flaw indications are permitted in bores, holes, and other highly stressed regions.

4. Each fully bucketed turbine rotor assembly is spin tested at or above the maximum speed anticipated following a load rejection from full load.

12 6 5 1 10.2.3.6 Inservice Inspection

1. Turbine stop valves and reheat stop and intercept valves are exercised periodically by closing each valve and observing by the valve position indicator that it moves smoothly to a fully closed position. Turbine control valves are exercised periodically by closing each valve and observing by the valve position indicator that it moves smoothly to a fully closed position. Extraction steam power-assisted check valves required for protection against turbine overspeed are exercised at least once a week to verify that the closing mechanism travels in the closing direction in a free and positive manner. First through fourth point extraction steam check valves are nozzle check valves and do not require testing.

1 5  8 12

10.2.3.7 Design Standards The turbine generator is designed in accordance with GE design standards, which have evolved from years of design and operating experience. These design standards, in general, meet or exceed the intent of codes such as ASME, ASTM, ANSI, and IEEE where applicable.

RBS USAR Revision 8 10.2-10 August 1996 10.2.4 Evaluation The turbine-generator equipment shielding requirements (Section 12.3.2) and the method of access control (Section 12.5) for all areas of the turbine building ensure that dose criteria specified in 10CFR20 for operating personnel are not exceeded.

All areas in proximity to turbine-generator equipment are zoned according to expected occupancy times and radiation levels anticipated under normal operating conditions. Specification of the various radiation zones in accordance with the expected occupancy is listed in Section 12.4. If deemed necessary, during unusual operational occurrences, the occupancy times for certain areas may have to be reduced by administrative controls.

The design basis operating concentrations of N-16, iodine, and noble gas activity in the turbine cycle are indicated in Table 11.3-1. Actual concentrations are anticipated to average substantially below these values. A full discussion of gaseous radwaste management is provided in Section 11.3. Section 11.1 provides a discussion of carry-over factors.

Piping and equipment in the turbine building were not analyzed for protection against postulated piping failures because there are no safety-related components or systems in the turbine building except for selected instruments that are designed to fail safe in the event of piping failures.

In the event of a high or moderate energy piping failure, it is unlikely that both the electric speed control and the hydraulic speed control systems would be affected. Even so, the loss of control fluid pressure due to a pipe failure would result in closure of the turbine stop and control valves, thereby preventing the possibility of turbine overspeed (see Section IV of Reference 2).

10.2.5 Testing and Inspection Requirements The main turbine stop and control valves and the combined intercept and intermediate stop valves are exercised as discussed in Section 10.2.3.6 to detect possible valve stem sticking.

Mechanical and backup overspeed trip tests are performed periodically while carrying load without tripping the unit by using special test provisions.

10.2.6 Instrumentation Applications The instrumentation requirements of the turbine gland sealing system which supplies gland steam to the turbine shaft packing and valves are described in Section 10.4.3.5.

The instrumentation requirements for the turbine exhaust hood are described in Section 10.4.5.

8 Turbine/generator/exciter bearing vibration is monitored by the vibration monitoring system, and a high vibration alarm is provided in the main control room.

8

RBS USAR Revision 25 10.2-11 10.2.6.1 Turbine Trip System The turbine trip system shuts down the turbine by closing the main turbine stop and control valves, the combined intercept and intermediate stop valves, and extraction nonreturn valves. The following turbine trip signals are provided:

1.

Extreme high level in either moisture separator after a time delay (two out of three logic for each separator) 2.

Low turbine bearing oil pressure (two out of three logic) 3.

Low vacuum in either condenser (two out of three logic for each) 4.

Loss of stator coolant followed by load reduction not sufficiently reduced after a time delay (from generator protection system logic) 5.

Low turbine shaft oil pump discharge pressure (two out of three logic) with turbine speed above a certain level (two out of three logic) 7 7 6.

Low turbine hydraulic fluid supply pressure (two out of three logic) 7.

Excessive wear (axial movement) of the turbine thrust bearing (active or inactive) in either direction (two out of three probes or one out of three probes plus a probe fault logic) 8.

Electrical protection trip (from generator protection trip logic) 7 9.

Turbine backup overspeed trip or loss of active speed signals (two out of three logic) 9a. Turbine primary diverse) overspeed or loss of passive speed signals (two out of three logic) 10.

Extreme high turbine exhaust hood temperature 11.

Both turbine trip pushbutton controls in the main control room are actuated 12.

Low emergency trip system pressure 13.

Loss of EHC 125 VDC power supply to the trip solenoids of the testable dump manifolds 14.

Reactor vessel water level high - level 8 (two-out-of-three logic) from reactor feedwater control system.

Refer to Sections 7.7.1.3 and 10.4.7.5.1 for further discussion on feedwater system 14 13 15.

High Turbine Vibration (startup only).

7 13 14

RBS USAR Revision 25 10.2-11a 16.

Failure of the Ovation TCPS redundant emergency trip controllers.

17.

Both turbine trip pushbutton controls at the front standard are actuated.

RBS USAR Revision 25 10.2-12 The turbine trip signals are monitored by the Ovation TCPS.

Alarms are provided in the main control room for low turbine bearing oil

pressure, low turbine hydraulic fluid supply pressure, an Ovation major alarm, Ovation minor alarm, excessive turbine thrust bearing wear, and condenser low vacuum. An indication of the cause of a turbine trip is provided on the operator work stations in the Main Control Room.

10.2.6.2 Turbine Supervisory Instruments The following turbine supervisory instruments (TSI) are provided in the main control room:

1.

Turbine eccentricity

2.

Turbine vibration recorder

3.

Differential expansion (difference in expansion between turbine rotor and shell), turbine rotor expansion, and temperature (exhaust hood, first stage shell, valve chest, and crossaround pipe) recorder.

Alarms are provided in the main control room for the following:

1.

High turbine differential expansion

2.

Low turbine differential expansion 8

3.

Card out of file or TSI power supply failure

4.

TSI low voltage failure

5.

High turbine vibration

6.

Reactor vessel water level high 14

7.

Turbine Vibration Trip Enabled 8 14 Indicators are provided for the following:

1.

Turbine eccentricity

2.

Turbine shell expansion

3.

Turbine differential expansion

RBS USAR Revision 25 10.2-13 4.

Turbine rotor expansion 5.

Turbine vibration 6.

Turbine vibration phase angle The main generator stator winding temperatures are monitored by the temperature scanner in the main control room.

10.2.6.3 Generator Hydrogen and Carbon Dioxide Controls 14 Pressure control stations located in the hydrogen and carbon dioxide storage area outside the turbine building are provided for controlling the normal and reserve hydrogen supply pressures and the carbon dioxide supply pressure. A pressure regulator located inside the turbine building is provided for controlling the machine gas pressure. Machine gas purity and pressure are continuously monitored in the main control room.

14 Pushbutton controls are provided on the local hydrogen control panel for manual operation of the hydrogen supply shutoff valves.

The exciter alternator and hydrogen temperatures are maintained at their setpoints by modulating control valves in the normal service water lines to the exciter alternator cooler and hydrogen cooler, respectively.

10.2.6.4 Generator Seal Oil Controls Pushbutton controls are provided in the main control room for manual operation of the following pumps:

1.

Main seal oil pump 2.

Recirculating seal oil pump 3.

Seal oil vacuum pump.

Pushbutton controls are provided in the main control room for either automatic or manual operation of the emergency seal oil pump. When operating in the automatic mode, the emergency seal oil pump starts automatically when the main seal oil pump discharge pressure drops below 110 psig. An emergency seal oil pump trouble alarm is provided in the main control room. An alarm is also provided when the pump runs continuously for over 60 min.

11 The generator seal oil pressure is maintained at least 8 psi above the generator hydrogen pressure by modulating a generator seal oil pressure control valve.

11 A common annunciator in the main control room is activated when any abnormal condition exists in the generator hydrogen and cooling water systems. Individual alarms are provided on the local hydrogen control panel.

RBS USAR Revision 8 10.2-14 August 1996 References - 10.2

8

1. Deleted 8

2. General Electric Engineering Report, General Electric Turbine Overspeed Protection, April 9, 1975.

1

3. Deleted 1

6

4. Deleted 6

8

5. Letter from S.J. Coluccio (GE) to C.P. McNemar (GSU) dated February 18, 1994 transmitting River Bend Turbine S/N 170X662 Missile Analysis Statement. RBC-45208.

8

RBS USAR Revision 14 10.3-1 September 2001 10.3 MAIN STEAM SUPPLY SYSTEM The main steam supply system is designed to provide the required amount of steam at the required pressure and temperature to the turbine, reheaters, condenser air removal system, turbine gland sealing system, and radwaste steam reboiler. The main steam supply system also conveys steam to the turbine bypass system (Section 10.4.4). The main steam supply system is shown in Fig. 10.3-1a through 10.3-1c. The portion of the main steam supply system up to and including the second isolation valve is discussed in Section 5.4.

10.3.1 Design Bases The main steam supply system is designed in accordance with the following design criteria:

1.

The main steam supply system from the second isolation valve located on the outside of the shield building, up to and including the first weld outside the jet impingement wall located in the auxiliary building steam tunnel and all branch lines from branch point at the line, up to and including the first valve in the branch line, are classified ASME Section III, Safety Class 1, and Seismic Category I.

2.

The portion of the main steam supply system from, but not including, the first weld outside the jet impingement wall, up to and including the third isolation valve located in the auxiliary building steam tunnel and all branch lines from the branch point at the line, up to and including the first valve in the branch line, are classified Safety Class 2 and Seismic Category I.

• 4 3.

The portion of the main steam supply system from, but not including, the third isolation valve up to, but not including, the main turbine stop and control valves is classified Safety Class NNS and Seismic Category N/A, and designed in accordance with ANSI B31.1.

However, piping extending from the third isolation valve up to and including the main turbine stop and control valves is seismically supported, except when the piping is flooded during operational modes 4 & 5 (cold shutdown and refueling).

4*

4.

The portion of the main steam supply system from the main turbine stop and control valves and downstream, supplied by GE-LSTG, is classified Safety Class NNS and Seismic Category N/A, and designed in accordance with GE-LSTG standards. GE-LSTG standards are similar to and meet or exceed the requirements of ANSI B31.1. This portion of the main steam supply system is further discussed in Section 10.2.

5.

The main steam supply system is stress analyzed in accordance with ASME Code Section III and ANSI B31.1, using the load combinations and stress limits as described in Section 3.9.3.1.

• 14 6.

The design pressure drop in the main steam piping from the second isolation valve to the turbine stop valve is approximately 24.9 psi at a load of 1,086 MWe, valves wide open, for a steam flow of 12,530,761 lb/hr to the high-pressure turbine.

14*

7.

The design pressure of the main steam supply system downstream of the second isolation valve is 1,250 psig at 575°F.

RBS USAR Revision 22 10.3-2

8. A turbine trip actuates the steam bypass system (Section 10.4.4). Isolation signals that actuate the main steam isolation valves are summarized in Table 6.2-40.

9. Inservice inspection requirements for ASME Section III Class 1 and 2 components are provided in Sections 5.2.4 and 6.6, respectively.

10.3.2 Description

6 Steam from the four outboard main steam isolation valves flows through four 24-in carbon steel lines to the main steam header.

Steam from the header flows through four 24-in carbon steel lines to the four sets of main turbine stop and control valves and then to the high-pressure turbine. Main steam supply for the moisture separators and reheaters (Section 10.2), the steam jet air ejectors (Section 10.4.2),

the steam seal evaporator (Section 10.4.3), the radwaste steam reboiler (Section 11.2), and steam conveyed to the turbine bypass valves (Section 10.4.4) are all taken from the main steam header (Fig. 10.3-1). Steam line drains are provided which discharge condensate to the main condenser.

Section 5.2 discusses inservice inspection, materials, and environmental conditions for the safety-related portions of the system piping. A discussion of the measures provided to limit blowdown of the system in the event of a steam line break is presented in Section 5.4. The use of four main steam lines permits testing of the main turbine stop valves and main steam isolation valves during plant operation, with only a minimum of load reduction.

6

10.3.3 Evaluation The portions of the main steam supply system, including the main steam isolation valves, that are relied on to function during transients and accidents are classified Seismic Category I.

Section 3.2 includes other seismic classifications of the main steam supply system. Section 3.6A presents the analysis of postulated high-energy line failure. Section 6.2.4 describes the containment isolation system. The radiologic consequences of a steam release occurring outside containment are discussed in Section 15.6.4.

10.3.4 Inspection and Testing Requirements

12 These valves are also inservice tested periodically to ensure proper operation. All motor-operated main steam isolation valves in the main steam supply system can be tested for operability during unit outages.

12

The portion of the main steam system within the jurisdiction of ANSI B31.1 will be leak tested in accordance with ASME Boiler and Pressure Vessel Code, 1974 edition,Section III, subsection NB, requirement, with the exception of the portion that extends from the main turbine stop valves to the turbine inlet. This portion shall be examined, inspected, and leak tested in accordance with ANSI B31.1 requirements.

RBS USAR 10.3-3 August 1987 10.3.5Water Chemistry (PWR)

This section is not applicable to a BWR. Consideration for reactor coolant water chemistry is given in Section 10.4.6.

10.3.6 Steam and Feedwater System Materials 10.3.6.1 Fracture Toughness The main steam and feedwater system classification is described in Section 3.2. Class 1 and Class 2 main steam piping meets the fracture toughness requirements specified in ASME Section III, Articles NB-2300 and NC-2300, respectively. Class 1 feedwater piping meets the requirements of ASME Section III, Article NB-2300. Fracture toughness requirements are not specified for main steam piping built to ANSI B31.1 and feedwater piping built to ASME III, Class 2 and ANSI B31.1. However, SA-106, Grade B and SA-216, Grade WCB materials used in these systems are the same as those materials used in Class 1 piping.

10.3.6.2 Materials Selection and Fabrication All pressure-retaining materials used in the main steam and feedwater piping systems are listed in Appendix I to the 1974 edition of Section II of the ASME Code and in parts A, B, and C of Section II. These piping systems are constructed of carbon steel and to the following material specifications:

SA-106, Grade B SA-216, Grade WCB SA-508, Class 1.

Austenitic stainless steel is utilized only in the tubes in the high-pressure feedwater heaters of the feedwater system. The tubes are solution-annealed after U-bending. The feedwater heaters are constructed in accordance with Section VIII of the ASME code.

The material used for the ASME Code Class 1 and 2 portions of the piping is nondestructively examined in accordance with the requirements of NB-2500 and NC-2500 as applicable.

Fabrication and installation of these piping systems are in accordance with the applicable codes and Regulatory Guide 1.71 as discussed in Section 1.8. The carbon steel welds over 1 1/4-in thickness were preheated to 200°F. The welds 1 1/4 in thick and less were preheated to 50°F minimum. These preheat procedures are considered adequate since the carbon content of base material is less than 0.30 percent. Also, the weld joints are not heavily restrained. ASME Code Class 1 and Class 2 welds were radiographed which provides added assurance of the integrity of the piping systems.

The main steam and feedwater piping systems are cleaned and flushed in accordance with ANSI standard N45.2.1, Reg. Guide 1.37, and GE-LSTG Requirements.

10.3.7 Instrumentation Applications

RBS USAR 10.3-4 August 1987 Main steam header pressure is indicated in the main control room. Control of the turbine bypass valves is described in Section 10.4.1.5.

Steam flow measurement and its application to reactor level control are described in Sections 7.7.1.2 and 7.7.1.3. Steam pressure measurement and its application to turbine generator control is described in Section 7.7.1.4. Leakage detection in the event of a main steam line break is described in Section 7.6.1.2.

RBS USAR Revision 17 10.4-1 10.4 OTHER FEATURES OF STEAM AND POWER CONVERSION SYSTEM 10.4.1 Main Condensers The condenser is a two-shell, single-pass, divided waterbox, deaerating-type and provides the heat sink for the low-pressure turbine exhaust, turbine bypass system, and numerous other sources. It also provides deaeration and holdup capacity for the condensate to allow radioactive decay. Table 10.4-1 gives design and performance parameters.

10.4.1.1 Design Bases The main condenser is designed in accordance with the following criteria:

1.

The condenser is not safety-related and is furnished in accordance with Heat Exchanger Institute (HEI)

Standards for Steam Surface Condensers, with a maximum air inleakage of 40 scfm.

14

2.

The condenser is designed to remove 6.96 x 10 9 btu/hr from the turbine exhaust steam at valve wide open conditions and maintain a 4.8 in Hg abs back pressure with a circulating water inlet temperature of 96°F.

3.

The condenser is designed to accept greater than 9.5 percent of the rated main steam flow from the turbine bypass system.

10.4.1.2 Description During plant operation, steam from the low-pressure turbines exhausts directly downward into the condenser shells through exhaust openings in the bottom of the turbine casings. The condenser serves as a heat sink for several other flows, such as feedwater heater high-level drains, air ejector intercondenser drains, steam seal condenser drain, feedwater heater shell operating vents, main steam system piping drains, condensate pump suction and discharge vents, and equipment drains.

During abnormal conditions, the main condenser is designed to intermittently receive flow from the turbine bypass system, feedwater heater high level dumps, relief valve discharges such as crossover steam line, feedwater heater shells and drain coolers, turbine gland sealing system, etc.

14

RBS USAR Revision 17 10.4-2

14 The condenser is capable of accepting greater than 9.5 percent of the rated main steam flow from the turbine bypass system (Section 10.4.4). This steam flow is accommodated without increasing the condenser backpressure to the turbine trip set point or exceeding the allowable turbine exhaust temperature.

There also are other intermittent flows into the condenser, such as reactor feed pump minimum recirculation flow, feedwater line prestartup cleaning and recirculation, extraction steam line drains, condensate recirculation, and condensate makeup.

Each of two condenser shells has two waterboxes, which permit isolation of one-half of the shell while the other half remains in operation. Each waterbox supplies water to an upper and lower tube bundle for steam condensing.

The normal hotwell storage capacity is about 83,800 gal or 4.2 min of full flow. The condenser is located beneath the low-pressure casings of the main turbine. Condenser tubes are arranged transverse to the turbine-generator axis.

14

Flexible belt-type expansion joints are provided between the turbine exhaust connections and the condenser necks. Equalizing connections between the two condenser shells are provided for both the steam space and the hotwell.

A fifth and sixth point heater is installed in the neck of each condenser shell.

Circulating water leakage into the condenser hotwell is discussed in Section 10.4.6.2. The detection of circulating water leakage from the main condenser to the turbine building and its effects are addressed in Section 10.4.5.3. The inventory of radioactive contaminants during operation is discussed in Section 12.2.1.5.

Shielding for and controlled access to the main condenser are discussed in Section 12.3.2.

10.4.1.3 Safety Evaluation The condenser is designed for operation at all loads up to and including the maximum expected load.

The condenser is designed to maintain a maximum oxygen content of 0.005 cc/l with an air inleakage of 40 scfm. The noncondensable gases are concentrated in the air removal zones of the condenser

RBS USAR Revision 14 10.4-3 September 2001 and are removed by the air removal system (Section 10.4.2). The buildup of noncondensable gases, such as hydrogen, is precluded since the air removal system is in continuous operation.

During plant shutdown a significant hydrogen buildup to explosive levels is not possible because the main condenser is isolated from the reactor. On loss of condenser vacuum, the condenser and main turbine exhaust hood are protected from excessive steam pressure by atmospheric relief diaphragms on the low pressure turbine which pass full throttle steam flow at a safe pressure (see Section 15, Miscellaneous Devices, of the Turbine Manual).

The treatment of radioactive gases removed from the condenser by the air removal system is discussed in Sections 11.3.2 and 9.4.4.2.5. Since the condenser operates at a partial vacuum the possibility of gaseous outleakage is not considered during operation.

5 Some low level ionic impurities are normally present in the liquids entering the condenser. The condensate demineralizers (Section 10.4.6) are designed to remove these impurities.

Abnormal ionic inleakage is detected by conductivity elements located both in the condenser hotwell and upstream of the condensate demineralizers. The source of the abnormal ionic inleakage is then determined by a review of the systems discharging to the condenser. The system found to be causing the abnormal ionic inleakage is either diverted to the liquid radwaste system for processing or isolated from the condenser.

5

The retention pit located under the condenser collects liquid leakage out of the condenser and drains it to two sumps until the leakage can be stopped. Any liquid collected in these sumps is pumped directly to the liquid radwaste system for processing.

The sumps are provided with level alarms and controls for automatic level control.

The turbine building ventilation system is designed to control and monitor airborne radioactive contaminants (refer to Section 9.4.4 for further discussion).

RBS USAR 10.4-4 August 1987 Conductivity cells are provided in drip trays under the tube bundles to detect condenser tube leakage in any of the eight condenser bundles. The leaking tubes are identified and repaired, plugged, or replaced during a unit maintenance outage.

A motor-operated butterfly valve at each of four waterbox inlets and four waterbox outlets provides individual waterbox isolation while maintaining the station online at reduced capacity. The condenser hotwell contains two partitions parallel to the tubes to provide a minimum 5-min effective detention of the condensate for the decay of radioactivity in the condensed steam.

Condenser materials were chosen to maximize performance and minimize corrosion/erosion. The majority of condenser tubes are Admiralty metal, which is very corrosion-resistant. The air cooling sections and impingement sections of the tube bundles have 70-30 Cu-Ni tubes, chosen for hardness. The tube sheets are Muntz metal, chosen for both strength and ductility. The condenser shell is carbon steel ASTM A283 Gr. C.

The condenser design includes impingement plates, baffles, and spray headers where necessary to protect the condenser tubes and structure from high-energy discharges such as the turbine bypass blowdown.

The tube corrosion rate is estimated at 0.4 mils/yr. Impressed current cathodic protection systems are used in the water boxes to protect the condenser from galvanic corrosion.

10.4.1.4 Testing and Inspection Requirements Following erection, the condenser is checked for leakage by filling the shell with water to the upper steam inlet expansion joint. The waterboxes are shop hydrostatically tested to 75 psig. The condenser tube side is field hydrostatically tested to 75 psig.

The shell side is designed to withstand 1.10 in Hg abs and is field tested by a standing water hydraulic test.

The condenser shell, hotwell, and waterboxes are provided with access openings to permit inspection or repairs. These access manways permit entry into the waterboxes (for inspection of tubes and tube joints), into the hotwells, and into the condenser shells to permit internal inspection of the condenser.

Inspection can be undertaken if there are indications of condenser operating abnormalities (such as tube leaks), or for general inspection purposes. Inspections may consist of draining the condenser (hotwell and/or waterbox), removing the inspection covers, and inspecting for waterbox fouling, impingement erosion, internal structural damage, and cleanliness.

RBS USAR Revision 13 10.4-5 September 2000 The main condenser is continually monitored for its performance and tube leakage. If this monitoring reveals condenser operating abnormalities, then the main condenser is inspected and appropriate corrective action is taken. The shell (steam) side of the main condenser is normally inspected at each refueling;

however, the frequency of inspection may be based on plant-specific experience.

10.4.1.5 Instrumentation Requirements Condenser vacuum is indicated in the main control room for both condenser shells, and a low vacuum (equal to or greater than 5 in Hg abs) in either condenser shell is annunciated in the main control room.

13 The turbine bypass valves are proportionally controlled by the NSSS pressure regulator and main turbine speed/load control system (Section 7.7.1.4). Extreme high condenser pressure (equal to or greater than approximately 21.5 in Hg abs) in either of the condenser shells automatically overrides the bypass valve positioning signal and closes the turbine bypass valves and the main steam isolation valves. This condition is alarmed in the main control room. A lower condenser pressure (greater than approximately 7.5 in Hg abs) trips the turbine. The position of the bypass valves is indicated in the main control room. Low vacuum trips and alarms function under all modes of operation.

Conditions relative to a loss of condenser vacuum are discussed in Section 15.2.5.

Condenser hotwell temperature and circulating water differential pressure across the condenser are monitored by the plant computer.

Condenser hotwell level instrumentation is described in Section 9.2.6.5.

Waterbox inlet and condensate conductivities are monitored by recorders in both the main and auxiliary control rooms.

Low pressure turbine exhaust hood temperatures are monitored by the plant computer. Temperature controls are provided for modulating an air-operated control valve, which admits condensate to the exhaust hood spray nozzles to prevent the exhaust hoods from overheating. Exhaust hood spray header pressure is 13

RBS USAR Revision 13 10.4-6 September 2000

13 monitored by the plant computer. High turbine exhaust hood temperature (greater than 175°F) is annunciated in the main control room, and extreme high temperature (greater than 225°F) trips the turbine.

Control is provided in the main control room for jogging the position of the turbine exhaust hood spray bypass valve.

13

10.4.2 Condenser Air Removal System The condenser air removal system removes air and noncondensable gases from the condenser. The condenser air removal system is shown in Fig. 10.4-1.

10.4.2.1 Design Bases The condenser air removal system is designed in accordance with the following criteria:

1.

The system is designed to maintain a 1.1 in Hg absolute pressure in the condenser, with air inleakage of 40 scfm, during operation and provide air removal for startup.

2.

The system is designed to maintain the hydrogen concentration below the lower explosive limit of 4 percent.

3.

The air ejectors are furnished in accordance with the Heat Exchange Institute Standards for Steam Jet Ejectors. Piping is furnished in accordance with ANSI B31.1. The air removal system is not safety related.

4.

The heat exchangers associated with the system are designed and fabricated in accordance with ASME Section VIII, Div. 1.

10.4.2.2 Description Two half-capacity, motor-driven air removal pumps, complete with discharge separators and silencers, are provided for startup to establish a pressure of approximately 8 to 5 in Hg abs prior to transferring to the air ejectors.

RBS USAR Revision 14 10.4-7 September 2001

14 During normal operation, one of two full-capacity air ejectors evacuate the air and noncondensables through perforated pipes, which run the length of each condenser shell. Each air ejector uses two primary steam jets complete with intercondenser, intercooler, and one secondary steam jet for removing the air and noncondensables. Excess steam is supplied to the secondary steam jet to dilute the air and noncondensables extracted from the main condenser, so that the hydrogen in the mixture discharged to the off-gas system is reduced to less than 4 percent by volume. The dilution also ensures that the exit temperature from the recombiner in the radwaste off-gas system is sufficiently below a temperature which may cause metallurgical damage to the pipe material. The steam jet air ejector inlet valves close on a low steam flow signal to the second stage.

14

The shellside drains from the intercondenser and intercooler are returned to the condenser.

Cooling water for the intercondensers is condensate from the discharge of the condensate pumps. Cooling water for the intercoolers is service water. Steam for the primary and secondary steam jets is taken from the main steam system and reduced to about 250 psig by pressure control valves.

The steam jet air ejectors, intercondensers, intercoolers, associated piping, and valves are provided with pressure relief protection (see Figure 10.4-1).

10.4.2.3 Safety Evaluation

14 During startup, 8 to 5 in Hg absolute pressure is obtained in the condenser by operation of both motor-driven air removal pumps.

The discharge of the air removal pumps is passed through charcoal filters, described in Section 9.4.4, to limit its radioactivity before being released to the atmosphere. Should the radiation monitor located in the discharge of the charcoal filters detect high radiation, the condition is evaluated and if warranted, operator action is required to terminate the release. The air removal pumps are automatically shut off if high radiation is detected in the main steam lines.

14

RBS USAR 10.4-8 August 1987 Each full-capacity air ejector is designed to remove air and noncondensable gases from the condenser during normal operation and exhaust them to the radwaste off-gas treatment system. An inventory of radioactive contaminants in the condenser air removal system is presented in Table 12.2-9. The gaseous radwaste system, which treats the off gas prior to its discharge to the atmosphere, is discussed in Section 11.3. Provisions for the sampling and monitoring of radioactive materials in gaseous effluent from the air removal system are described in Sections 9.3.2 and 11.5.3. The capacity of the ejectors is determined by taking into consideration potential air inleakage, the oxygen and hydrogen formed by disassociation of water in the reactor, and the water vapor contained in the air-gas mixture.

The first stage steam jet air

ejectors, intercondensers, associated piping, and valves are not specifically designed to withstand the effects of a hydrogen detonation. The second stage steam jet air ejector and connected intercooler is designed to withstand the effects of a hydrogen detonation equal to 20 x 14.7 psig. The normal operation of the steam jet air ejectors prevents the process flow to the offgas system from reaching flammable limits. Although a significant reduction or loss of steam flow to the air ejectors could result in the process flow reaching flammable limits, the condenser air removal system has the following design features and instrumentation available to monitor system operation:

1.

The motive steam flow to the second stage jet is monitored in the main control room (see Section 10.4.2.5).

2.

A significant reduction or loss of motive steam flow to the second stage jet automatically closes the ejector suction valves (see Section 10.4.2.5).

3.

Low motive steam pressure downstream of the regulating valve is indicated and alarmed in the main control room.

4.

Increased main condenser pressure due to the buildup of air and noncondensible gases is indicated and alarmed in the main control room (Section 10.4.1.5).

5.

In addition to the instrumentation provided in the condenser air removal system, two hydrogen analyzers are provided in the offgas system downstream of the recombiners. These analyzers allow monitoring of hydrogen concentrations as an additional safeguard against the occurrence of hydrogen detonation.

RBS USAR Revision 5 10.4-9 August 1992 Loss of condenser vacuum due to the malfunction of an air ejector is extremely remote. Loss of condenser vacuum prevents the operation of the turbine bypass system. When condenser pressure reaches approximately 21.5 in Hg abs, the turbine bypass valves close and the main steam isolation valves are closed, resulting in the opening of the main steam safety relief valves.

10.4.2.4 Testing and Inspection Requirements Piping is inspected and tested in accordance with Paragraphs 136 and 137, respectively, of ANSI B31.1. The shell and tube side of the air ejector intercondensers and intercooler are hydrostatically tested to 1.5 times their design pressure.

Standby equipment is periodically cycled inservice to ensure its availability. The system is tested for leaks and proper operation during the startup test program. This program is discussed in Section 14.2.1. The mechanical vacuum pumps have been given a shop performance test.

10.4.2.5 Instrumentation Applications Control switches are provided in the main control room for manual operation of the air removal pumps. Control logic is provided to stop the pump when the radiation level of the main steam lines reaches a predetermined level or the main steam line radiation monitors become inoperative. Section 7.6.1.3.1 describes the main steam line radiation monitoring system. Interlocks prevent the air removal pump suction valves from opening when the pump is not running. Air removal pump discharge separator high or low level activates an alarm in the main control room.

5 Manual control stations are provided in the main control room for remote manual operation of the air ejector suction valves.

Control switches are provided in the main control room for remote manual operation of main steam to air ejector shutoff, inlet and pressure regulator bypass valves.

5

Steam flow to the second stage of each air ejector is monitored in the main control room. An extreme low flow condition automatically closes the air ejector suction valve. Low flow alarms are provided in the main control room.

Main steam pressure to the air ejectors is monitored, and a low-pressure alarm is provided in the main control room. A pressure controller and regulator maintain steam pressure at about 250 psig.

RBS USAR Revision 10 10.4-10 April 1998 Control switches are provided in the auxiliary control room for the remote manual operation of the air ejector intercondenser and intercooler drain line isolation valves 1-DTM-AOV55A and 55B (see Fig. 9.3-8c). These valves are opened after steam is lined up to the air ejectors and a vacuum has been established.

10 Train A and Train B High level alarms and a pressure indicator for the intercooler are provided in the auxiliary control room.

10

10.4.3 Turbine Gland Sealing System The turbine gland sealing system serves the high-and low-pressure turbine seals and certain main steam system valves.

The turbine gland sealing system is shown in Fig. 10.4-2.

10.4.3.1 Design Bases The turbine gland sealing system is designed in accordance with the following criteria:

1.

The turbine gland sealing system is designed to prevent air leakage into the low-pressure turbine and to prevent radioactive steam leakage out of the high-pressure turbine.

8 2.

The system provides clean sealing steam as the sealing medium which is normally provided by the steam seal evaporator, a shell and tube heat exchanger.

3.

The steam seal evaporator vessel is

designed, fabricated, tested, and stamped in accordance with the ASME Boiler and Pressure Vessel Code,Section VIII, Division I.

4.

The turbine gland sealing system piping is furnished in accordance with ANSI B31.1, except for the portion that is furnished by General Electric (GE). This piping is furnished in accordance with GE standards, which parallel those of ANSI B31.1. The steam seal condenser is also furnished by GE.

8

RBS USAR Revision 8 10.4-11 August 1996 10.4.3.2

System Description

8 7 Clean steam to the steam seal supply header is normally furnished by the steam seal evaporator. During evaporator shutdown, clean steam may be furnished directly by a temporary, skid-mounted boiler using existing plant piping. This boiler provides clean sealing steam during periods when the plant steam supply is unavailable and it is desired to draw a vacuum on the main condenser.

The evaporator receives water from the condensate system downstream of the condensate demineralizer. Steam from the third point extraction lines is capable of providing the heating medium for the evaporator, except during startup and low-load operation when there is insufficient pressure available. During startup and low-load operation, the source of heating steam is the main steam system. The heating steam is condensed in the evaporator and flows into a drain receiver, where drain flow is controlled to the fourth point heaters.

7

The clean steam from the evaporator flows through a pressure-regulating valve to the steam seal supply header. The pressure-regulating valve controls the supply header pressure at approximately 4 psig.

The steam seal supply header provides clean steam to the seals of both the high-and low-pressure turbines, the main turbine stop and control valves, the combined intercept and intermediate stop valves, and the turbine bypass control valves. Leakoffs from the outboard ends of these seals are piped through the steam seal return headers to either the steam seal condenser, crossaround piping, or main condenser. Condensed steam from the steam seal condenser normally flows to the main condenser; however, if the steam seal supply is from the temporary skid-mounted boiler, the condensed steam from the steam seal condenser may be piped to the radwaste system for reprocessing.

8

The steam seal condenser is equipped with two full-capacity exhausters, each of which maintains the steam seal return header at a

pressure slightly below atmospheric and discharges noncondensables to the atmosphere through the plant exhaust duct.

The noncondensable vent radiation level is continuously monitored.

RBS USAR Revision 12 10.4-12 December 1999 10.4.3.3 Safety Evaluation The turbine gland sealing system is designed to provide the required amount of sealing steam under all modes of operation and then condense the leakoffs from the various glands.

12 7 If a steam seal evaporator tube leak were to occur, either extraction steam or main steam would contaminate the clean steam seal system. A leak of any significance would be detected by high radioactivity in either the steam seal evaporator discharge or the steam seal condenser exhaust discharge to the atmosphere.

When a leak is detected, the steam seal evaporator is isolated.

This would result in the loss of steam seals and result in a Turbine trip due to high condenser pressure.

A loss of condenser vacuum is classified as an event of moderate frequency in Section 15.2.5 of the USAR. The reliability of the turbine gland sealing system design has been evaluated using Probabilistic Risk Assessment (PRA) methodology. Based on this PRA evaluation, the design of this system provides a system reliability well within the acceptable range for a moderate frequency event.

12

If the seals should be lost, a relatively small amount of steam would leak out of the high-pressure turbine glands before air inleakage through the low-pressure turbine glands would cause a turbine trip due to high condenser pressure. This isolates the turbine and precludes a substantial release of radioactive material to the environment. The design of turbine shaft and valve seals prevents contamination of the steam seal return header with radioactive steam. See Section 11.3 for further details on the radiological evaluation of the steam seal system.

7

The turbine gland sealing system is nonsafety-related and is not required for safe shutdown of the unit. It is located in the turbine building. A break in the high-energy pipe within this system is not significant since there are no safety-related systems or components located in the turbine building.

10.4.3.4 Testing and Inspection Requirements Piping is inspected and tested in accordance with paragraphs 136 and 137, respectively, of ANSI B31.1, except for the piping furnished by the turbine manufacturer. This piping is inspected

RBS USAR Revision 21 10.4-13 and tested in accordance with the manufacturer's standards, which closely parallel those of ANSI B31.1. The shell and tube sides of the gland seal condenser are hydrostatically tested to 1.5 times design pressure. Standby equipment is periodically cycled in service to ensure its availability.

The shell and tube sides of the steam seal evaporator are hydrostatically tested to 1.5 times design pressure (150 psi) in accordance with ASME Boiler and Pressure Vessel

Code,Section VIII.

10.4.3.5 Instrumentation Applications Steam seal header pressure is monitored and a low-pressure alarm is provided in the main control room.

7 During normal operation, when the steam seal evaporator is providing steam to the steam seal supply header, steam seal supply header pressure is controlled by modulating an air-operated valve in the line to the steam seal supply header.

Control switches are provided in the main control room for manual operation of the steam seal evaporator block valve and bypass valve.

7

A control switch is provided in the main control room for manual operation of the isolation valve for the extraction line supply to the steam seal evaporator.

8 7 Control switches are provided in the main control room for manual operation of the main steam admission valve.

7 8

Control switches are provided in the main control room for manual operation of the steam seal evaporator block valve and the steam supply bypass valve during startup and low-load operations.

Steam seal evaporator tube and shell side pressures are maintained at their set points by modulating an air-operated valve in the main steam to steam seal evaporator line. Steam seal evaporator tube and shell side pressures are monitored in the main control room.

RBS USAR 10.4-14 August 1987 The radiation level of the steam seal evaporator clean steam outlet is monitored and high radiation alarms are provided in both the main and auxiliary control rooms.

Control switches are provided in the main control room for manual control of the steam seal condenser exhaust blowers and associated discharge valves.

Steam seal condenser vacuum is monitored and a vacuum inadequate alarm is provided in the main control room. A low steam seal condenser water level alarm is also provided in the main control room.

10.4.4 Turbine Bypass System The turbine bypass system has been designed to reduce the levels of reactor power surges during system transients, to regulate reactor pressure during startup and shutdown, and to provide a flow path to a heat sink after a turbine trip. The turbine bypass system is shown in Fig. 10.3-1.

10.4.4.1 Design Bases The turbine bypass system is designed in accordance with the following criteria:

1.

Failure or malfunction of the system does not adversely affect essential systems or components.

These effects are evaluated in Chapter 15.

2.

The turbine bypass system upstream of the bypass valves is designed in accordance with ANSI B31.1, with additional inspections and analysis as described in Section 3.2. Downstream of the bypass valves, the system is designed to ANSI B31.1 requirements.

3.

The system is designed in accordance with the intent of Branch Technical Positions APCSB 3-1 and MEB 3-1, as related to breaks in high-and moderate-energy piping systems outside containment.

RBS USAR Revision 17 10.4-15

14

4.

The system is designed to pass greater than 9.5 percent of rated steam flow. The turbine bypass valves are fast response, modulating type, and are controlled by the initial pressure regulator.

14

10.4.4.2

System Description

The turbine bypass system is designed to perform the following functions:

1.

Regulate reactor pressure during reactor vessel heatup to rated pressure.

2.

Regulate reactor pressure while the turbine is brought up to rated speed and synchronized.

3.

Regulate reactor pressure during power operation when reactor steam generation exceeds the turbine requirements.

4.

Provide a steam path to the condenser as a heat sink during normal reactor cooldown.

5.

Provide a means for making rapid changes in turbine power levels while maneuvering the reactor within its normal operational limits.

The turbine bypass system (Fig. 10.3-1) consists of two automatically and sequentially operated control valves mounted on a 10-in valve manifold. The manifold is connected to the main steam header. Each 10-in bypass valve outlet is piped individually to the main condenser, and a pressure reducer is located in each line at the condenser connection. The full capacity of the turbine bypass system is equally distributed between the two condenser shells.

When the steam bypass valves are open, steam enters each end of the chest, flows downward over the disk, between the seat and the stem, and exits through the discharge casing. The amount of steam passing through each valve is controlled by the lift of the valve. Valve discs are hard surfaced at their mutual contacting points to improve their ability to maintain adequate seating contact. Steam flow tends to close the valve, and a compression

RBS USAR Revision 17 10.4-16 spring is used to supplement the valve closing forces. The force required to open and position each steam bypass valve is applied to the valve stem by the power actuator mounted directly below each valve. The actuator includes a double acting hydraulic cylinder controlled by a servovalve.

The turbine bypass system is not safety related and is located in the turbine building.

10.4.4.3 Safety Evaluation One or both of the turbine bypass valves are opened to control reactor

pressure, provided a

condenser vacuum permissive interlock is satisfied.

After a normal, orderly shutdown of the turbine generator leading to reactor cooldown, the turbine bypass control valves are used for several hours to route steam generated by decay heat from the reactor to the condenser.

The turbine bypass valves are capable of responding to the maximum closure rate of the turbine control valves, so that reactor steam flow is not significantly affected until the magnitude of the load rejection exceeds the capacity of the bypass system, which is 9.5 percent of rated steam flow.

The effects of turbine bypass system malfunction on reactor operation are bounded by events presented in Appendix 15A as follows:

1.

A turbine bypass system line failure is bounded by event 43 discussed in Section 15A.6.5.3.

2.

A failure of the bypass valves to open is bounded by events 30 and 31 discussed in Section 15A.6.4.3.

3.

An inadvertent opening of the bypass valves, at worst, might cause a high steam line flow with resultant MSIV closure trip (event 14 discussed in Section 15A.6.3.3) or, if the condenser heat rejection rate is inadequate, a loss of main condenser vacuum with resultant MSIV closure trip (event 26 discussed in Section 15A.6.3.3).

RBS USAR Revision 8 10.4-17 August 1996 This system is not safety related and is not required to function for the prevention or mitigation of an accident. A failure within the system does not prevent a safe shutdown of the unit.

Piping and equipment in the turbine building were not analyzed for protection against postulated turbine bypass system piping failures because there are no safety-related components or systems in the turbine building except for selected instruments designed to fail safe in the event of piping failures.

In the event of a turbine bypass system piping failure, it is unlikely that both the electric speed control system and the hydraulic speed control system would be affected. Even so, the loss of control fluid pressure due to a turbine bypass system pipe failure would result in closure of the turbine stop and control valves, thereby preventing the possibility of turbine overspeed (see Section IV of Reference 2 of USAR Section 10.2).

10.4.4.4 Testing and Inspection Requirements The turbine bypass system is designed in accordance with ANSI B31.1 and is inspected and tested in accordance with paragraphs 136 and 137 of that code. Initial testing of this system in accordance with Regulatory Guide 1.68 is discussed in Chapter 14.

8 The turbine bypass valves are exercised at the frequency specified in Technical Specifications by opening each valve and observing, by the valve position indicator, that it moves smoothly to a fully open position.

8

10.4.4.5 Instrumentation Applications Controls and valves are designed so that the bypass valves steam flow is shut off if the control system loses its electric power or hydraulic system pressure. For testing the bypass valves during operation, the stroke time of the individual valves is increased during testing to limit the rate of bypass flow increase and decrease to approximately 1 percent/sec of reactor rated flow.

Upon turbine trip or generator load rejection, the start of the bypass valve steam flow is not delayed more than 0.1 sec after the start of the stop valve or the control valve fast closure motion. A minimum of 80 percent of the rated bypass capacity is established within 0.3 sec after the start of the stop valve or the control valve closure motion. For more detail, refer to Section 7.7.

RBS USAR Revision 12 10.4-18 December 1999 10.4.5 Circulating Water System

12 6 The circulating water system dissipates heat from the main condenser. The water is used to remove heat rejected by the turbine exhaust and turbine bypass steam as well as from other incidentals (Section 10.4.4) over the full range of operating loads. The circulating water system is shown in Fig. 10.4-3a, b, and c.

6 12

10.4.5.1 Design Bases The circulating water system is designed in accordance with the following criteria:

7

1.

The system includes four multicell cooling towers, four cooling tower outfall screens with large mesh, four 25-percent capacity circulating water

pumps, and associated piping from the pumps to the condensers and back to the cooling towers.

7

2.

The circulating water system is designed to prevent any injection of radioactive material into the circulating water and its subsequent release to the atmosphere through evaporation in the cooling tower or to the river via the blowdown lines. The circulating water passing through the condenser is always at a higher pressure than the shell or condensing side; therefore, any leakage (such as from the condenser tubes) is from the circulating water into the shell side of the condenser.

3.

The circulating water system serves no safety function.

Malfunction or failure of a component of the system, including an expansion joint, does not affect the intended function of safety-related systems or components.

4.

Means are provided to prevent or control flooding of safety-related areas due to leakage from the circulating water system.

5.

Agents used for the control of circulating water chemistry, corrosion, and organic fouling are compatible with the materials of the system.

6.

The system is designed in accordance with the intent of Branch Technical Positions APCSB 3-1 and MEB 3-1, as related to breaks in high-and moderate-energy piping systems outside containment.

RBS USAR Revision 20 10.4-19

7 7.

The condenser is provided with a sponge ball Condenser Tube Cleaning System to maintain tube side cleanliness.

7

10.4.5.2 Description

6 Circulating water is pumped from the circulating water pump structure through the condenser shells to the cooling towers, subsequently flowing into the flume and back to the circulating water pump structure. Makeup water is pumped from the Mississippi River to offset the evaporation and drift losses from the cooling towers and the blowdown quantities (Section 9.2.11). The flow from the cooling towers is directed to circulating water pumps which deliver water to the main condensers. The discharge from the main condensers is returned to the cooling towers for cooling prior to reuse.

10 8 Blowdown water quantity is up to 4,400 gpm and is extracted from the circulating water system in order to maintain an acceptable solids concentration in the circulating water system. Effluents from the sanitary Wastewater Treatment Plant (WWTP) facility are mixed with the blowdown water and returned to the Mississippi River.

6 8 10

14 7 Four vertical wet-pit circulating water pumps are located outdoors and provide a total design flow of 511,560 gpm. The temperature rise through the main condenser is 27°F at 100%

rated power of the turbine generator. Each of the four pumps is located in a separate screenwell bay which has an inlet stop gate and primary stationary panel screen. A second panel screen is installed prior to removing the primary stationary panel screen for cleaning or maintenance. Both screens have small mesh for trash.

12 6 Four multicell cooling towers are provided for a total design flow of approximately 565,000 gpm for the circulating water system. At 100% rated conditions, the temperature of cooled water from the towers is a maximum of 96°F.

6 12

Each condenser inlet is provided with four ball injectors to inject sponge balls along with 350 gpm circulating water. Each condenser outlet is provided with a ball strainer to extract sponge balls along with 350 gpm circulating water.

Recirculating piping ball pump and collector tank system provides recirculation of sponge balls to the inlet.

7 14

RBS USAR Revision 17 10.4-20

14 10.4.5.3 Safety Evaluation Each of the four circulating water pumps is designed to deliver 138,750 gpm of water to the condensers and back to the cooling towers. The pump size is determined by the quantity of heat to be rejected by the main condenser at all loads up to and including the maximum expected load (at 100% of rated power).

The pumps are equipped with separate butterfly valves which are interlocked with the start and stop sequence of each pump and which permit each circulating water pump to be isolated.

14

The four circulating water pumps discharge into a common single pipe running to the condenser inlet waterboxes. The discharge from the condenser outlet waterboxes feeds a common return pipe running back to the cooling towers. The condenser waterboxes are connected to the circulating water piping using expansion joints located between the condenser waterboxes and the motor-operated butterfly valves on both the inlet and outlet sides.

Expansion joints are also located at the discharge of each circulating water pump. A rupture of an expansion joint at a circulating water pump will discharge water to the ground at the cooling towers, over 1,000 ft from any safety-related structures.

No safety-related equipment would be affected by a rupture of these expansion joints.

If a rupture occurred at a condenser expansion joint, the escaping water would first accumulate in the retention pit around the condenser. This pit is provided with a sump and level alarms. The sudden deluge of water immediately activates the high level alarms of the sumps.

The condenser vacuum is monitored in the main control room. A loss of condenser cooling water causes a vacuum loss, activating alarms in the main control room when the condenser pressure rises to 5 in Hg abs. The time required for this pressure increase to occur, with subsequent activation of the alarms, is calculated to be a maximum of 1 min. This is a conservative estimate for either of the detection systems previously described.

RBS USAR Revision 7 10.4-21 January 1995 Once a rupture is determined, the operator stops all pumps and closes the butterfly valve located up-and downstream of each condenser expansion joint. The operator's reaction time is estimated as 30 sec, and the response to the pump shutdown and valve closure signals is essentially instantaneous.

The coastdown time for the pumps is approximately 35 sec, and the valve closure time is 20 sec. Therefore, the total time from rupture to pump shutdown and valve closure is approximately 2 min.

The water flowing through the break is conservatively assumed as the pump flow rate from the instant of failure until pumps shut down. This maximum flow rate is 509,360 gpm, based on the four circulating water pumps delivering the design flow less blowdown.

Therefore, the maximum volume of a leak of this nature is 1,018,720 gal. This figure is conservative since it does not consider the decrease in the pump flow rate after power shutoff.

The water would fill the retention pit and the heater drain pipe trenches completely, with the level rising to 13 in above the turbine building basement floor. The rate of rise of water in the pit and pipe tunnels is approximately 8 ft/min, and of the water in the basement is approximately 1 ft/min.

Closure of the butterfly valves up-and downstream of each expansion joint prevents any gravity drainage of water from yard piping or cooling towers through a ruptured joint. Assuming the butterfly valve closure does not affect pump flow, the total leakage is limited to the volume of water pumped from the instant of failure to pump shutdown.

7 The valve operators are not protected from water spraying from the rupture. Upon rupture of the expansion joints, the retention pit will fillup with circulating water and the valve operators may become submerged. Therefore, the valve operators are coated with a heavy vinyl liner to repel water as long as possible.

However, the impact of the worst possible flooding is evaluated by assuming that the circulating water pumps fail to stop and the butterfly valves are not operational to isolate the circulating water flow. The pumps would continue to operate until no water remained in the main flume and forebay. The total water inventory of 13.624 x 10 6 gal would be discharged into the turbine building, resulting in a flood level of 97 ft 6 in within the turbine building. There is no safety-related equipment located in the turbine building at or below the 97 ft 6 in elevation.

7

RBS USAR 10.4-22 April 1998 Safety-related equipment is located in Seismic Category I structures that are protected from flooding (Section 3.4). Thus, no essential electrical systems or components are submerged following the failure of a circulating water condenser expansion joint.

The circulating water supply piping system is designed for a maximum design pressure of 75 psig and a minimum of 3 psig vacuum, with a normal operating pressure of 55 psig.

The system was analyzed for hydraulic transients due to pump tripout and valve closure. In the case of pump tripout, it was assumed, for the worst case, that all four pumps tripped simultaneously due to the loss of either offsite power or normal service power. The analyses showed that the transient pressures were well below the system design pressure of 75 psig. In the case of valve closure, a pump discharge valve closure time of 60 sec was selected, based on the analyses showing transient pressures no higher than normal operating pressures utilizing this closure time. The possibility of higher than normal operating pressures resulting from the sudden closure of a pump discharge or condenser isolation valve is considered highly unlikely, since valve malfunction would occur only from a gross failure of the valve disc shaft or motor drive gear unit.

During most periods of plant operation, the wet bulb temperature is less than the maximum design temperature of 83°F, and the circulating water system may be run with only three of the four pumps in operation. In addition, some of the cooling tower fans may be shut down in sequence to maintain a constant water temperature.

During low temperatures (subfreezing) when the circulating water temperature falls below 32°F, individual tower fan motors are manually shut down to avoid unnecessary depression of the circulating water temperature. Based on 30 yr of data collected at Ryan Airport, 32°F or lower temperatures have only occurred 1 percent of the time, and these never fell below 10°F.

Therefore, it is believed that low temperature procedures are not necessary.

RBS USAR Revision 22 10.4-23

• 16 *10 *6 *3 The water quality of the circulating water system is controlled in order to minimize scaling, corrosion, and biological fouling.

This is accomplished by injecting multifunctional chemicals (Fig.

10.4-4a and 10.4-4b). One of the chemicals injected is a sodium hypochlorite/sodium bromide solution (Fig. 10.4-4a).

The solution is periodically injected into the circulating water flume to inhibit biological growth in the circulating water system. An alternate method to inhibit biological growth is the injection of granules into the flume water by the Towerbrom subsystem. Sulfuric acid is also injected into the flume to control cooling water pH so that scaling and corrosion in the system is minimized. Additionally, a corrosion inhibitor and a dispersant are injected into the circulating water system to maintain proper residual concentrations based upon the cycles of concentration and water quality.

6* 16*

The hypochlorite solution tank is sized for approximately 14 days' storage of delivered and diluted hypochlorite. Since the hypochlorite solution is not toxic, an accidental release does not endanger main control room or plant personnel. There are no adverse interactions between the water quality control program of the circulating water system and the plant structures.

10*

If a design basis accident or a loss of station power occurs, the circulating water system is not operated. The circulating water system is not required for shutdown cooling.

3*

10.4.5.4 Testing and Inspection Requirements All active components of the system (except the main condensers) are accessible for inspection and testing during station operation.

10.4.5.5 Instrumentation Applications

• 14 14*

The differential pressure across the condensers is monitored by the plant computer. When a pump automatically trips, an alarm is activated in the main control room.

RBS USAR Revision 20 10.4-24 The temperature of the circulating water at both the inlet and outlet of each condenser waterbox is monitored by the plant computer.

Pushbutton controls are provided in the main control room for manually starting the circulating water pumps. Interlocks prevent startup of a pump unless its discharge valve is fully closed. The valve opens when pump running is established and close when the pump stops running.

Control switches are provided in the main control room for manual operation of the condenser waterbox inlet and outlet valves. Interlocks prevent startup of a circulating water pump unless the valves for one of the condensers are fully open.

Alarms are provided in the main control room for high differential pressure of the pump intake primary and secondary intake screens.

Circulating water pump and motor bearing and stator winding temperatures are monitored in the main control room.

14 8 8 14

15 Pushbutton controls are provided in the main control room for manual operation of the circulating water system cooling tower fans. Interlocks are provided to trip a running fan in the event of high vibration, sustained bus undervoltage, or fan motor overload. A cooling tower fan automatic trip is indicated in the main control room by the circulating water pumphouse station trouble alarm.

15

10 2 Controls are provided in the auxiliary control room for manually positioning circulating water blowdown valve CWS-MOV104 to maintain a constant blowdown.

Circulating water flume level is indicated and recorded in the auxiliary control room, as discussed in Section 9.2.11.5.

Circulating water system blowdown flow is monitored in the auxiliary control room. Cooling tower blowdown radiation trouble alarms are provided in both the auxiliary and main control rooms.

2 10

The pH of the circulating water is recorded on a local panel. A high or low pH activates an alarm in the auxiliary control room.

RBS USAR Revision 14 10.4-25 September 2001

7 Each Condenser Tube Cleaning System is remote manually operated from central panel located in line of sight of the recirculation pumps and ball collector tank. Differential pressure across the ballstrainer grills is indicated at these panels and an alarm is initiated upon high and high-high lP and upon equipment failure.

High-high dP will initiate automatic backwash. A common trouble alarm for each system is provided in the auxiliary control room.

7

14 10 The instrumentation and controls for the chemical feed-hypochlorite system are located on a

local panel (Fig. 10.4-4a).

10 14

10.4.6 Condensate Demineralizer System The purpose of the condensate demineralizer system is to remove suspended and soluble impurities from the condensate stream.

The condensate demineralizer system is shown in Fig. 10.4-5a through 10.4-5f.

10.4.6.1 Design Bases The system is designed in agreement with the following criteria:

1.

The system is designed in accordance with Reg. Guide 1.56 with respect to maintaining the proper water purity specified for the reactor.

2.

The system is not safety related and is classified nonnuclear safety (NNS). Piping is furnished in accordance with ANSI B31.1.0, and pressure vessels in accordance with ASME Section VIII.

12

3.

The system is designed to treat 115.5 percent of the rated condensate flow from the condenser hotwell (approximately 10,314,693 lb/hr).

12

4.

The system is designed to meet the intent of NRC Branch Technical Positions APCSB 3-1 and MEB 3-1 as related to breaks in high-and moderate-energy piping systems outside the containment.

5.

Sufficient demineralizer capacity is provided to permit ultrasonic resin cleaning while the system retains its normal demineralizing capacity.

RBS USAR (1) Includes soluble and insoluble iron, copper, and nickel, of which total copper does not exceed 2 ppb.

(2) Feedwater chloride concentrations are maintained within limits such that the chloride concentration limit of the reactor water at operating pressure is maintained. This means that the feedwater chloride concentration is less than 2 ppb.

Revision 17 10.4-26 10.4.6.2

System Description

The condensate demineralizer system is designed to maintain the condensate at the required purity by removal of the following contaminants:

11

1.

Corrosion products that result from the corrosion which occurs in the main steam system and turbine extraction piping, feedwater heater shells, condenser, and drains.

11

2.

Suspended and dissolved solids that may be introduced by small leakages of circulating water through the condenser tubes.

3.

Fission and activation products that are entrained in the reactor steam and retained in the condensate leaving the hotwell.

4.

Solids carried in by the makeup water and miscellaneous drains going to the condenser.

7 Based upon the expected condensate demineralizer influent concentrations listed in Table 10.4-2, and a design condensate flow for extended normal operation, the condensate demineralizer effluent should typically produce the following water quality:

7

Specific conductivity at 25°C, S/cm 0.1 max Silica as Si02, ppb 10 max Total metals, ppb 15 max (1)

Chlorides, ppb (2) pH at 25°C, S.U.

6.5-7.5

11 7 The condensate demineralizer system consists of two trains of five ion exchangers, each containing a bed of mixed resins in the proportion of approximately one part cation resin to one part anion resin by equivalence. It is intended that at least nine ion exchangers be in service at one time under normal conditions.

The tenth ion exchanger is normally placed in service and is used to augment the in service demineralizers to permit ultrasonic resin cleaning of the demineralizer resin beds.

7 11

RBS USAR Revision 14 10.4-27 September 2001

14 12 The units have sufficient capacity to treat the total normal condensate flow based on a design flow rate of 65 gpm/sq ft. The condensate demineralizer system is designed to treat 115.5 percent of the rated condensate flow from the condensate pumps (approximately 10,314,693 lb/hr). The total feedwater flow consists of this rated condensate flow plus flow from heater drains, which enters forward of the condensate demineralizers.

Consequently, during each cycle approximately two-thirds of the total feedwater flow entering the reactor vessel is treated by the condensate demineralizer system.

12 14

The design pressure of the condensate side of the condensate demineralizer system is 600 psig.

Condensate Demineralizers

11 The condensate demineralizers are in the direct flow path of the condensate flow to the reactor vessel and are located downstream of the condensate pumps. Each demineralizer has an effluent resin strainer to minimize the effects and prevent gross resin carryover with the condensate.

11

The condensate demineralizer system is sized to process condensate with peak impurity concentrations resulting from plant startup operation.

9 The condensate demineralizer system minimum residual capacity is sufficient to maintain the designated treated effluent quality for a period of 6 hr, following a condenser leakage rate of 35 gpm. This is predicated on the maximum total dissolved solids contained in the recirculating cooling water.

9

11 A mixed-bed demineralizer is manually removed from service when there is an excess pressure drop across the unit, indicating a high accumulation of particulate matter, or upon exhaustion of the resin bed, as indicated by high-effluent conductivity.

Additionally, a demineralizer may be removed to support periodic resin cleaning.

11

RBS USAR Revision 11 10.4-28 October 1998

11 When any of the above occurs, the resin is removed from a mixed-bed demineralizer by pneumatic-hydraulic sluicing and the resin is either physically cleaned, using an ultrasonic resin cleaner, or replaced, whichever is required. Interlocks are provided to preclude the accidental transfer of a resin bed.

All wastewater resulting from the transfer of dirty or exhausted resin from the ion exchangers to the resin holding tanks and from the ultrasonic resin cleaners is discharged to the dirty waste sump and then transferred for processing by the liquid radwaste system (Section 11.2). Selection of which tank in the radwaste system will receive the effluent depends on the conductivity of the water. All other wastewater is directed to the recovered water sump for subsequent reuse.

10.4.6.3 Safety Evaluation The condensate demineralizer system is not safety related. A reduction in condensate caused by a malfunction in the condensate demineralizer results in a corresponding reduction in feedwater flow. Reduced feedwater flow transients are analyzed in Section 15.2. The system is designed so that condensate flow cannot be blocked by the failure of valves in the system or high differential pressure across one of the demineralizers.

8 Sufficient redundancy is provided in the system to negate the possibility of overloading the radioactive waste treatment system when the condensate demineralizer system is operating at normal influent concentrations. If the radwaste handling system should approach design capacity, such as when condenser tube leaks force maximum rates of replacement of the demineralizer resin beds, the unit load can be reduced to prevent plant operation from exceeding technical requirements limits (Chapter 16).

8

The demineralizer vessels are located in two separate shielded compartments with five vessels in each compartment. Each of these five demineralizer units may be placed into service by remote operation, as required (Section 10.4.6.2). Fresh resin batches are charged for these units by remote operation. All routinely maintained equipment such as valves, strainers, and gauges are located in an area between the shielded compartments (Fig. 12.3-7, 12.3-9, and 12.3-11). No maintenance is expected to be required within the two demineralizer compartments during plant operation. Should entrance into the area be required, administrative procedures regarding radiation exposure to plant personnel are enforced (Section 12.5).

11

RBS USAR Revision 11 10.4-29 October 1998

11 In accordance with Regulatory Guide 1.56, the condensate demineralizer system provides the capability of monitoring resin capacity through electrical conductivity. This ensures that the predetermined minimum operating capacity of the demineralizer system is maintained during operation. Residual resin capacity is maintained and monitored, and is available in reserve to ensure sufficient time for an orderly reactor shutdown in the event of a condenser leak. Operational criteria for the condensate demineralizer system are established and defined as follows:

11

1.

Conductivity is continuously monitored at selected points in the condensate and reactor recirculation systems. Conductivity cells with high alarms are provided at the effluent of each demineralizer and the combined demineralizer effluent. These conductivity cells are to alert plant operators of abnormal conductivity levels, which could indicate breakthrough of one or more demineralizers, and possibly, the need for orderly or immediate reactor shutdown.

In accordance with Regulatory Guide 1.56, Table 2, the following condensate conductivity limits have been established:

Specific Conductivity uS/cm @ 25°C Limit (1) Maximum (2)

11 Condensate Demineralizer Common Influent 0.5 10.0 Condensate Demineralizer Common Effluent 0.1 0.2 Individual Demineralizer Effluent 0.2 0.5 11

(1) Indicates condenser inleakage or marginal demineralizer performance, which requires corrective action to be taken.

(2) Indicates orderly reactor shutdown and/or immediate corrective action to be taken.

7

2.

The quality of the water entering the reactor is maintained by the condensate demineralizers. Each demineralizer contains approximately 2,061 kgrs of anion capacity for the removal of chlorides, and 2,140 kgrs of cation capacity for soluble metal ion removal, expressed as calcium carbonate (CaCO3).

7

RBS USAR Revision 12 10.4-30 December 1999 A demineralizer bed shall be removed from service and replaced when the calculated remaining anion capacity reaches 30 percent of the initial available capacity, or 618 kgrs. For normal operation, this ensures that sufficient total demineralizer capacity exists in the system at all times to permit an orderly shutdown of the reactor.

3.

The method used to calculate the quantity of principle ions likely to cause demineralizer breakthrough is commensurate with Regulatory Guide 1.56. Plant operating personnel:

12 a.

Read and record the condensate demineralizer influent and individual bed effluent conductivities from the continuous conductivity recorders.

b.

Calculate the remaining anion capacity for each condensate demineralizer bed by a

formula that is a

function of the conductivity

change, total

flow, and correlated to laboratory analyses.

12

The effluent strainer in the effluent piping from each condensate demineralizer protects the feedwater system against a massive discharge of resin in the event of an underdrain failure in the demineralizer.

10.4.6.4 Testing and Inspection Requirements Piping is inspected and tested in accordance with Paragraphs 136 and 137, respectively, of ANSI B31.1.0. All pressure vessels are hydrostatically tested to 1.5 times their design pressure.

11 Each standby demineralizer is recycled in a manual mode to ensure acceptable water quality and availability prior to placing the demineralizer into operation.

11

Condensate demineralizer resins are purchased to technical specifications which are commensurate to their intended application. Certification of the resins' quality is ensured by the resin vendor sampling and analyzing each batch of resin prior to shipment to the site. Certified test results are furnished upon shipment for each batch of condensate demineralizer resin.

RBS USAR Revision 11 10.4-31 October 1998

11 In accordance with Regulatory Guide 1.56, The following are demineralizer resin sampling requirements:

1.

Initial total capacity of new anion and cation demineralizer resins should be measures.

2.

For resins not regenerated (replaced periodically and time of replacement exceeds one year) with material of the same type, measurements of the initial capacity should be made on a sample of new material at each replacement.

3.

When the type of cation or anion resin is changed, a measurement of total capacity of the replacement resin should be made prior to use in the demineralizer.

These samples are analyzed in accordance with approved plant procedures. River Bend Station does not regenerate condensate demineralizer resin.

Periodically, a

representative sample of the condensate demineralizer resin bed is obtained during the ultrasonic resin cleaning cycle. The sample is analyzed for the residual anion exchange capacity and correlated to the calculated residual anion capacity. This correlation ensures that the minimum residual anion capacity is maintained for an orderly reactor shutdown, if required. This correlation is determined semiannually, as a minimum.

11

Conductivity meters for the condensate demineralizer system are electronically calibrated in accordance with approved plant Calibration Data Packages. On a semiannual basis, or whenever instrument malfunction is suspected, the installed process conductivity monitors are correlated to inline laboratory conductivity cells. This correlation is performed in accordance with approved plant procedures, under controlled conditions.

10.4.6.5 Instrumentation Applications Control panels located in the auxiliary control room accommodate instruments and controls for operation of the condensate demineralizer system.

RBS USAR Revision 22 10.4-32

• 12 *11 *10 The differential pressure across the condensate demineralizer system is continuously recorded. A high differential pressure condition activates an alarm in the auxiliary control room. The flow rate through each of the condensate demineralizers is measured in a similar manner. Each demineralizer effluent line has a flow element, flow indicating switch and transmitter, and flow indicating integrator. Demineralizer and system flow measurements are continuously recorded on the computer based Condensate Demineralizer Monitoring System located in the auxiliary control room. A low-flow alarm is provided in the auxiliary control room for each demineralizer. The condensate demineralizer system influent and effluent conductivities are continuously recorded in both the auxiliary and main control rooms. The effluent conductivity of each demineralizer is continuously recorded, and a high effluent conductivity alarm is provided in both the auxiliary and main control rooms. The effluent conductivity alarm set point for each demineralizer bed is 0.1 S/cm while the combined demineralizer effluent set point will be 0.1 S/cm. The effluent conductivity readings provide a direct indication of marginal performance or breakthrough of one or more demineralizers. Based on operating data at the design condensate

flow, the extended normal operation influent conductivity is expected to be 0.2 S/cm. The influent conductivity alarm set point for the condensate system will be 0.1 S/cm. The differential pressure across each resin strainer is recorded, and a high strainer differential pressure alarm is provided in the auxiliary control room.

10* 11* 12*

A three point recorder in the auxiliary control room provides a continuous record of the level in the chemical waste sump, dirty waste sump, and recovered-water sump. An extreme high-level in the chemical waste sump activates an alarm in the auxiliary control room and a condensate demineralizer trouble alarm in both the main and auxiliary control rooms.

RBS USAR Revision 16 10.4-33 March 2003

16 Control switches are provided for manual operation of the chemical waste and dirty waste sump pumps. In the automatic mode of operation, control logic provides the following functions:

1.

A high-level condition starts the lead pump.

2.

An extreme high-level condition starts the backup pump.

3.

A low-level condition stops the running pump(s).

The lead pump is selected by a mechanical alternator.

Control switches are provided for manual operation of the recovered-water sump pumps. In the automatic mode of operation, a recovered-water demand signal starts the lead pump. An alternator is provided to alternate the lead pump. Control logic is provided to stop the running pump when the level in the sump reaches a low level.

16

11 A flow control panel is provided for regulating the flow and pressure of the water to the ultrasonic resin cleaner when the ultrasonic resin cleaning mode is selected. Alarms are provided in the auxiliary control room for high level in the ultrasonic resin cleaning tank and high or low resin flow to the ultrasonic resin cleaning tank.

11

10.4.7 Condensate and Feedwater System This section includes a discussion of the condensate and feedwater system from the condenser to the outboard motor-operated isolation valve. The condensate and feedwater system from the outboard motor-operated isolation valve to the reactor is discussed in Section 5.4.9.

10.4.7.1 Design Bases The condensate and feedwater system is designed in accordance with the following criteria:

1.

The system from the condenser hotwell up to, but not including, the outermost containment isolation valve is not safety related.

RBS USAR Revision 18 10.4-34

10

2.

Piping from the condenser hotwell up to, but not including, the outermost containment isolation valve is furnished in accordance with ANSI B31.1, with the exception of certain replaced portions of feedwater piping, where the post weld heat treatment requirements of ASME Section III, ND-4622.7 were used. The feedwater heaters, zinc dissolution vessel, condensate prefilter vessels and air receiver tank, and drain receivers are furnished in accordance with ASME Section VIII.

10

3.

The system is designed in accordance with the intent of Branch Technical Positions APCSB 3-1 and MEB 3-1, as related to breaks in high-and moderate-energy piping systems outside the containment.

4.

The system is designed in accordance with Reg.

Guide 1.68.1, as related to preoperational and initial startup testing.

5.

The condensate and feedwater system is stress-analyzed for the forces and moments which result from thermal growth.

6.

Containment and reactor coolant pressure boundary isolation criteria are provided in Section 6.2.4 and Table 6.2-35.

7.

Hotwell storage capacity and availability of condensate for emergency purposes are discussed in Sections 10.4.1.2 and 9.4.6.2, respectively.

8.

There are no inservice inspection requirements other than normal plant maintenance for the nonsafety-related portion of the feedwater system and for all of the condensate system furnished in accordance with ANSI B31.1.

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9.

The nonsafety-related portions of the condensate and feedwater systems are located in the turbine building and in the condensate demineralizer, regeneration, and off gas building. Environmental design conditions for the turbine building zones are provided in Section 3.11 and Table 3.11-6. The environmental design conditions for the condensate demineralizer, regeneration, and off gas building are similar to those for the turbine building.

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RBS USAR Revision 17 10.4-35 10.4.7.2 Description The condensate and feedwater system is not required to effect or support the safe shutdown of the reactor or to perform in the operation of reactor safety systems. However, in the event that the condensate and feedwater system is available after an accident, it can supply feedwater to the reactor.

14 The condensate and feedwater system is designed to return condensate from the condenser hotwell to the reactor at the required flow, pressure, temperature, and chemistry. The condensate and feedwater system has sufficient capacity to exceed feedwater flow required at 100.3% of uprated core thermal power conditions against uprated reactor feedwater sparger inlet pressure. The system is designed to automatically maintain the water level in the reactor during steady-state and transient conditions.

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The condensate and feedwater system consists of the piping,

valves, pumps, heat exchangers,

controls, instrumentation, associated equipment, and subsystems that supply the reactor with heated feedwater in a closed steam cycle using regenerative feedwater heating.

The condensate system is shown in Fig. 10.4-6a, 10.4-6b, 10.4-6c, and 10.4-6d. The feedwater system is shown in Fig. 10.4-7.

Three half-capacity, vertical, motor-driven condensate pumps take their suction from the condenser hotwell and discharge through one of two air ejectors, the steam seal condenser, condensate prefilters, and the off-gas condenser to the condensate demineralizers (Section 10.4.6). An iron injection skid is located downstream of the condensate demineralizer vessels. This skid has the necessary piping, pumps, and valves to allow injection of a small amount of iron solution. The pumped solution will be less than 1% as iron. The iron compound, ferric oxalate hexahydrate, will be diluted with condensate water (Ref.

Fig 10.4-1d). The iron injection skid is provided to allow Chemistry to administratively control Feedwater Iron to about 0.5 ppb to minimize transport of Cobalt. Condensate returning from the condensate demineralizers discharges through two strings of heaters, consisting of the fifth point and fourth point heater external drain coolers; the sixth, fifth, fourth, third, and second point heaters, each at half-capacity, to the suction of the reactor feed pumps. The fifth and the fourth point heater external drain coolers are horizontal, straight tube, single pass type designed for subcooling only. The sixth and fifth point heaters are horizontal U-tube type without integral drain coolers and are located inside the condenser necks. The fourth, third, and second point heaters are also horizontal U-tube type heaters with integral drain cooling, except for the third point heater, which has no integral drain cooler. All heaters and drain coolers have Type 304 stainless steel tubes which are rolled and welded to the tube sheets. A condensate pump recirculation system functions to maintain a flow through each condensate pump in excess of manufacturer's minimum flow during low-load operation.

The

RBS USAR 10.4-36 August 1987 minimum flow is controlled by a flow element downstream of the condensate demineralizers. Recirculated condensate is returned to the condenser.

The required condensate flow through each condenser air ejector is maintained by a flow element downstream of the air ejector.

This flow element modulates the flow control valve in the bypass around the air ejector.

Three one-third nominal

capacity, horizontal, centrifugal, motor-driven reactor feed pumps operate in series with the condensate pumps and receive condensate from the second point heaters. The reactor feed pumps discharge through the feedwater control station to the two high-pressure first point heaters arranged in parallel and then through the reactor containment isolation valves to the reactor. The feedwater control system is discussed in detail in Section 7.7.

In order to avoid pump vibration and high temperatures during startup and low load operation, each reactor feed pump is provided with an individual minimum flow recirculation line returning to the main condenser (Fig. 10.4-7). The recirculation line is located between each reactor feed pump and its discharge check valve.

Proportional flow control valves in each recirculation line are controlled by a local controller which senses the flow through the pump by means of a flow element located in the pump suction line. The control valves open proportionally as flow drops below approximately 30 percent pump design flow. The valves close proportionally as flow approaches approximately 30 percent pump design flow. Deenergizing a reactor feed pump automatically closes its recirculation valve after a time delay (to allow for safe pump coast down). When a reactor feed pump is energized, the recirculation control valve opens fully before reactor feed pump startup is permitted.

The first point heaters are horizontal U-tube type with integral drain coolers and with Type 304 stainless steel tubes rolled and welded to the tube sheets.

The shell sides of both the high-and the low-pressure feedwater heaters are continuously vented to the condenser.

Drains from the two reheaters are collected in individual reheater drain receivers which discharge to the first point heaters. Drains from the first point heaters cascade to the second point heaters, and those of the second point heaters

RBS USAR Revision 22 10.4-37 cascade to the third point heaters. Drains from the two moisture separators are collected in individual moisture separator drain receivers which also discharge to the third point heaters.

Two of the four half-capacity, vertical, motor-driven heater drain pumps take suction from each third point heater and discharge into the condensate system upstream of the respective second point heater. Two pumps (one for each third point heater) are normally operating. Minimum flow is maintained through each pump by a recirculation line to the third point heater.

The fourth point heater drains cascade through a separate drain cooler and thence to the condenser, as do the drains leaving the fifth point heaters. The drains from the sixth point heaters drain directly to the condenser through a loop seal.

The necessary piping and valves are furnished from the suction header to the discharge header of the reactor feed pumps to bypass these pumps, and from the feedwater line downstream of the first point heaters to the condenser in order to establish a flow path to the condenser for recirculation. This ensures proper reactor water quality during startup and establishes the feedwater flow prior to admitting water into the reactor vessel.

The quality of the water in the condensate and feedwater system is monitored through appropriately located sample points (Section 9.3.2).

• 10 The necessary piping and valves are furnished from the reactor feed pumps discharge to the feed pump suction header to inject zinc into the feedwater using the differential pressure across the feed pumps. A dilute solution of zinc in water is obtained by passing a small stream of feedwater through the dissolution vessel containing Depleted Zinc Oxide (DZO) pellets. The zinc inhibits the plate-out of activated metals, primarily Co-60, on steel surfaces and therefore reduces the resulting radiation buildup due to CRUD formation.

The On-Line NobleChem Injection Skid and necessary piping, tubing and valves from the skid to the main feedwater piping are furnished to enable periodic application of the On-Line NobleChem process. NobleChem, in addition to Hydrogen Water Chemistry, provides for controlling the potential for stress corrosion cracking of vessel internals with reduced hydrogen injection rates.

10*

10.4.7.3 Evaluation Normally, the three half-capacity condensate pumps and two of the four half-capacity heater drain pumps are in service together with both strings of feedwater heaters. The system is designed so that the maximum required total flow can still be obtained with two condensate pumps and two of four heater drain pumps in service. Approximately 70 percent of the maximum required flow rate can be obtained with one of the strings of low-pressure feedwater heaters isolated and with two condensate pumps and one heater drain pump in service.

RBS USAR Revision 12 10.4-38 December 1999

12 All three reactor feed pumps are normally in service. The system is designed so that at least 80 percent of the maximum total required flow rate can be obtained should any one of the reactor feed pumps or one of the first point heaters be taken out of service. The complete loss of feedwater accident is discussed in Section 15.2. Either string of low-pressure feedwater heaters may be taken out of service by closing motor-operated isolation valves at the inlet to the fifth point heater drain cooler and at the outlet of the second point heater.

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The bypass around the two strings of heaters is also provided with a motor-operated isolation valve.

Both second point heaters are provided with motor-operated isolation valves at their inlet and outlet, and also in the bypasses around them.

The condensate, heater drain, and reactor feed pumps are all designed to provide the maximum required design flows, plus adequate margin to account for both transients and pump wear.

Adequate margin is provided in the net positive suction head requirements to ensure noncavitating performance under normal conditions.

Seal leakoffs for the reactor feed pumps are directed to the turbine building equipment drains.

During operation, slightly radioactive water is present in the system. Radiation sources from the condensate and feedwater system are discussed in Section 12.2.

Pipe breaks and fluid transients are discussed in Chapter 3. The condensate and feedwater system is designed with welded connections wherever practicable to minimize leakage.

10.4.7.4 Testing and Inspection Requirements The portion of the condensate and feedwater system within the jurisdiction of ANSI B31.1 is inspected and tested in accordance with Paragraphs 136 and 137.

Performance tests are made on all condensate, heater drain, and reactor feed pumps in accordance with ASME Power Test Codes for Centrifugal Pumps, PTC 8.2.

RBS USAR Revision 25 10.4-39 The casings of the condensate, the heater drain, and the reactor feed pumps are hydrostatically tested to approximately 1.5 times their shutoff discharge pressures. The shell and tube side of all feedwater heaters and drain coolers, and all drain receivers are hydrostatically tested to 1.5 times their design pressure.

10.4.7.5 Instrumentation Applications 10.4.7.5.1 Feedwater System Feedwater flow-control instrumentation measures the feedwater flow rate from the condensate and feedwater system. This measurement is used by the feedwater control system, which regulates the feedwater flow to the reactor to meet system demands.

The feedwater control system is described in Section 7.7.1.

Pushbutton controls are provided in the main control room for manual operation of each reactor feed pump. The following conditions automatically trip a running feed pump:

1.

Pump suction extreme low pressure (two out of three logic)

2.

Reactor vessel high water level (two out of three logic)

3.

Lube oil extreme low pressure (after time delay)

4.

Speed increaser lube oil extreme low pressure

5.

Bus undervoltage trip

6.

Electrical protection trip.

7.

Reactor vessel high water level (two out of two logic secondary trip)

Pump discharge pressure is monitored in the main control room, and an alarm is provided for a low discharge pressure condition for any pump that is running. Pump suction pressure and discharge temperature are monitored by the plant computer, and a low-pressure alarm is provided in the main control room.

After a reactor feedwater pump is started, its discharge valve must be opened manually. Pushbutton controls are provided in the main control room for this operation. However, the pumps and valves are interlocked so that the valve closes automatically when the pump trips.

RBS USAR Revision 8 10.4-40 August 1996 Control switches and pushbutton controls are provided in the main control room for manual operation of the feedwater system isolation valves and first point heater influent and effluent valves, respectively.

Minimum flow through each reactor feed pump is maintained at its set point by modulating the respective feed pump minimum flow recirculation air-operated valve (from pump discharge to the main condenser). A low reactor feed pump suction flow (pump trip) produces a reactor recirculation runback signal. The minimum flow recirculation valve closes after a time delay when the reactor feed pump stops running.

Feedwater startup recirculation flow is monitored in the main control room. Minimum startup flow is controlled at its set point by modulating an air-operated valve in the startup recirculation line (downstream from the first point heater to the main condenser). Pushbutton controls are provided in the main control room for manual operation of the feedwater system startup recirculation block valve. During normal operation, this valve is closed.

Level controllers are provided for maintaining the water level of each high-pressure feedwater heater (first point heaters) at its set point by modulating the respective normal and high water level drain control valves. High and low level alarms for each heater are provided in the main control room. The level of each heater is monitored in the main control room. Each heater drain temperature is monitored by the plant computer.

8 Feedwater pump vibration is monitored, and a high vibration alarm is provided in the main control room.

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10.4.7.5.2 Condensate System The condensate pumps are manually controlled by pushbutton in the main control room. The condenser vacuum breaker valves, condensate pump discharge valves, and condensate pump vent valves are individually controlled by pushbutton and control switches in the main control room.

Minimum flow for the condensate system is controlled at its set point by modulating an air-operated valve in the recirculation line to the main condenser. Interlocks close the valve automatically when all three pumps are stopped. Total condensate flow is monitored by the plant computer. The recirculation valve is closed when all condensate pumps are stopped.

RBS USAR Revision 17 10.4-41 The condensate flow through the air ejectors is limited by modulating a valve in the air ejector bypass line in response to a total condensate flow signal.

Condensate header temperature is monitored by the plant computer.

Condenser hotwell outlet conductivity is recorded in the main and auxiliary control rooms. Condensate pump discharge header pressure is monitored, and a low-pressure alarm is provided in the main control room. Condensate pump vibration is monitored, and a high-vibration alarm is provided in the main control room.

Condensate polishing demineralizer outlet pressure is monitored in the main control room. Off-gas condenser inlet condensate temperature is monitored in the main control room.

Level controllers are provided for maintaining the level of each low-pressure feedwater heater (second, third, and fourth point heaters and fifth point heater drain receivers) at its set point by modulating the respective normal and high water level drain control valves. High and low level alarms for all low-pressure heaters in each string are provided in the main control room.

The level of each heater and heater drain receiver is monitored in the main control room. Each heater and heater drain receiver drain temperature is monitored by the plant computer.

14 Extreme high water level in either the fifth or sixth point heater closes the isolation valves of the affected low-pressure heater string. Pushbutton controls are provided in the main control room for testing the operation of the inlet and outlet isolation valves. Extreme high level alarms are provided in the main control room for each heater. The level in each heater is monitored by the plant computer.

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12 Control switches are provided in the main control room for manual operation of the third point heater drain pumps and for the third point heater drain pump suction and discharge valves and air-operated cooling water valves. Control logic is provided to trip the heater drain pump when the water level in the third point heater drops to a low point. Each pump is interlocked with its suction valve so that the pump does not start unless the valve is fully open and the pump stops when the valve is not fully open. Pump suction and discharge pressures are monitored by the plant computer. The third point heater drain pump air-operated recirculation valve modulates the recirculation flow back to the third point heater whenever one of the pumps is running. Pump vibration is monitored, and an alarm is provided in the main control room if excessive vibration of any one of the third point heater drain pumps is detected.

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The condensate prefilter system consists of 5 parallel trains of filter vessels each containing 430 pleated, disposable, non-precoated filter elements, and an air receiver tank for backwash

RBS USAR Revision 17 10.4-42 purposes. The system is designed for 1 train to be out of service for backwash or maintenance purposes at any time. If 2 or more trains are required to be out of service at the same time, the bypass valve may be opened to pass sufficient flow around the prefilter system to prevent the system or individual train differential pressure alarms from alarming. Operation of the system with the bypass valve open should be minimized to prevent transfer of particulate to the condensate demineralizers, which shortens resin life.

The condensate prefilter subsystem is controlled by a PLC operated from the auxiliary control room (ACR). The PLC monitors air operated valve positions, total system flow and differential pressure, and individual train flow and differential pressures.

The PLC provides an additional level of safety for system operation by use of program steps and timing sequences for verification of valve position changes. In addition, the air operated valves all fail to a safe position on loss of power, loss of air, and loss of signal. The separate equipment trouble alarms are received in the ACR. The only alarm in the main control room is Condensate Filtration System High DP.

The control room has no auto response to any alarm condition that may adversely affect a filter that is already in SERVICE mode.

In general, the solenoid valves and/or valve positioners are ultimately what control the filter valves. The service inlet valve solenoids are only instantaneously energized in order to change valve position. Once the valve is set in a position (closed or open), the solenoids are locked in place and require another output signal to be generated to change position.

Therefore, unless the PLC gives a command to change service inlet valve position, the valve will not move regardless of the failure. Conversely, the backwash valve solenoids remain energized to hold the associated valve open.

The valve positioners are driven by the position demand signal generated by the PLC. Once a demand signal is sent to the positioner, that signal remains on the positioner until the demand signal is adjusted. This can only be done by normal operational procedures through the PLC. There is no auto signal or response for any alarm condition that will change the previously set valve position. Additionally, the PLC is programmed to HOLD LAST STATE upon any signal failure (broken wire). This protects the system by holding the effluent valve at the last position.