RC-16-0083, Virgil C. Summer, Unit 1 - Updated Final Safety Analysis Report, Chapter 5, Reactor Coolant System
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RT NDT'"TEMPERATURE300 SOUTH CAROLINA ELECTRIC&GAS CO.VIRGILC.SUMMER NUCLEAR STATION CharpyV-Notch Curve for Core Beltline Region Haz Metal Figure 5.2-23 5.3-1Reformatted PerAmendment 00-015.3THERMAL HYDRAULIC SYSTEM DESIGN5.3.1ANALYTICAL METHODS AND DATAThe thermal and hydraulic design bases of the Reactor Coolant System (RCS) issummarized in Table 5.1-1 and described further in Sections 4.3 and 4.4 in terms ofcore heat generation rates, departure from nucleate boiling ratio (DNBR), analyticalmodels, peaking factors, and other relevant aspects of the reactor.5.3.2OPERATING RESTRICTIONS ON PUMPSThe minimum net positive suction head (NPSH) and minimum seal injection flowratemust be established before operating the reactor coolant pumps. With the minimum 6gpm seal injection flowrate established, the operator will have to verify that the system pressure satisfies NPSH requirements and that the number 1 seal bypass flow satisfies seal flow requirements.5.3.3POWER-FLOW OPERATING MAP (BWR)Not applicable to pressurized water reactors.5.3.4TEMPERATURE-POWER OPERATING MAPThe NSSS is designed to operate with a full power average coolant temperature rangingfrom 572F to 587.4F. The relationship between RCS temperature and power isshown in Figure 5.3-1 for thermal design conditions with a Tavg of 587.4F at a corepower of 2900 MWt.The effects of reduced core flow due to inoperative pumps is discussed in Sections5.5.1, 15.2.5, and 15.3.4.5.3.5LOAD FOLLOWING CHARACTERISTICSThe RCS is designed on the basis of steady-state operation at full power heat load.The reactor coolant pumps utilize single speed motors as described in Section 5.5 andthe reactor power is controlled to maintain average coolant temperature at a value which is a linear function of load, as described in Section 7.7. Operation with 1 pump out of service requires adjustment only in reactor trip system setpoints as discussed in Section 7.2.5.3.6TRANSIENT EFFECTSTransient effects on the RCS are evaluated in Chapter 15.
5.3-2Reformatted PerAmendment 00-015.3.7THERMAL AND HYDRAULIC CHARACTERISTICS
SUMMARY
TABLEThe thermal and hydraulic characteristics are given in Tables 4.3-1, 4.4-1, and 5.1-1.
00-01 630 621.9°620 TDF=92,600 GPM/LOOP CORE POWER2900 MWT 610 iL 600 T HOT- 587.4 0590580 a. 570 I-560 T coLD 552.9°550 540 0 20 40 60 80 100 PERCENT POWER AMENDMENT 96-02 JULY 1996
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U X Y Z L11 0287 SOUTH CAROLINA ELECTRICGAS CO.VIRGIL C.SUMMER NUCLEAR STATION Surveillance Capsule Locations Figure 5.4-1 5.5-1 Reformatted January 2016 5.5 COMPONENT AND SUBSYSTEM DESIGN 5.5.1 REACTOR COOLANT PUMPS 5.5.1.1 Design Bases The reactor coolant pump ensures an adequate core cooling flowrate and hence sufficient heat transfer, to maintain a departure from nucleate boiling ratio (DNBR) greater than 1.30 within the parameters of operation. The required net positive suction head is by conservative pump design always less than that available by system design and operation.
Sufficient pump rotation inertia is provided by a flywheel, in conjunction with the impeller and motor assembly, to provide adequate flow during coastdown. This flow, following an assumed loss of pump power, provides the core with adequate cooling.
The reactor coolant pump motor is tested, without mechanical damage, at overspeeds up to and including 125% of normal speed. The integrity of the flywheel during a LOCA is demonstrated in Reference [1]. Reference [1] is undergoing generic review by the NRC.
The reactor coolant pump is shown in Figure 5.5-1. The reactor coolant pump design parameters are given in Table 5.5-
- 1.
Code and material requirements are provided in Section 5.2.
5.5.1.2 Design Description The reactor coolant pump is a vertical, single stage, centrifugal, shaft seal pump designed to pump large volumes of reactor coolant at high temperatures and pressures.
The pump consists of 3 areas from bottom to top. They are the hydraulics, shaft seals, and the motor.
- 1. The hydraulic section consists of an impeller, diffuser, casing, thermal barrier heat exchanger, lower radial bearing, bolting ring, motor stand, and pump shaft.
- 2. The shaft seal section consists of 3 devices. They are the number 1, controlled leakage, film riding face seal and the number 2 and number 3 rubbing face seals. These seals are contained within the main flange and seal housing.
- 3. The motor section consists of a vertical solid shaft, squirrel cage induction type motor, an oil lubricated double tilting pad Kingsbury type thrust bearing, 2 oil lubricated radial bearings, and a flywheel.
5.5-2 Reformatted January 2016 Attached to the bottom of the pump shaft is the impeller. The reactor coolant is drawn up through the impeller, discharged through passages in the diffuser, and out through the discharge nozzle in the side of the casing. Above the impeller is a thermal barrier heat exchanger which limits heat transfer between hot system water and seal injection water.
High pressure seal injection water is introduced through the thermal barrier wall. A portion of this water flows up around the bearing through the seals; the remainder flows down through the thermal barrier where it acts as a buffer to prevent system water from entering the radial bearing and seal section of the unit. The thermal barrier heat exchanger provides a means of cooling system water to an acceptable level in the event that seal injection flow is lost. The water lubricated journal type pump bearing, mounted above the thermal barrier heat exchanger, has a self-aligning spherical seat.
The reactor coolant pump motor bearings are of conventional design. The radial bearings are the segmented pad type, and the thrust bearings are tilting pad Kingsbury bearings. All are oil lubricated. The lower radial bearing and the thrust bearings are submerged in oil, and the upper radial bearing is oil fed from an impeller integral with the thrust runner.
The motor is an air-cooled, Class F thermalastic epoxy insulated, squirrel cage induction motor. The rotor and stator are of standard construction and are cooled by air. Six (6) resistance temperature detectors are located throughout the stator to sense the winding temperature. The top of the motor consists of a flywheel and an anti-reverse rotation device.
Each of the reactor coolant pumps is equipped for continuous monitoring of reactor coolant pump shaft and frame vibration levels. Shaft vibration is measured by 2 relative shaft probes mounted on top of the pump seal housing. The probes, 1 in line with the pump discharge and the other perpendicular to the pump discharge, are mounted in the same horizontal plane near the pump shaft. Frame vibration is measured by 2 velocity velomitors located 90 degrees apart in the same horizontal plane and mounted at the top of the motor support stand. Proximeters and converters convert the probe signals to linear output which is displayed on monitor meters in the control room. The monitor meters automatically indicate the highest output from the relative probes and velomitors; manual selection allows monitoring of individual probes.
Indicator lights display caution and danger limits of vibration, which are adjustable over the full range of the motor scale.
All parts of the pump in contact with the reactor coolant are austenitic stainless steel except for special parts, such as seals and bearings. Component cooling water is supplied to the 2 oil coolers on the pump motor and to the pump thermal barrier heat exchanger.
RN 13-001 RN 13-001 5.5-3 Reformatted January 2016 In addition, the reactor coolant pumps receive pump shaft seal cooling water from the Chemical and Volume Control System (CVCS). The component cooling water supply to the thermal barrier is provided as a backup heat sink to the CVCS cooling water flow to the reactor coolant pump seals. A failure of the CCWS supply to the thermal barrier would not jeopardize operation of the reactor coolant pump or cause loss of reactor coolant. The individual CCWS return lines from the upper and lower bearing oil coolers, as well as the return line from the thermal barrier, are equipped with seismically qualified flow indicators powered from the vital bus (associated). These flow indicators actuate alarms on the main control board. The temperature indicator and alarms on the CCWS return lines are located on the main control board. The reactor coolant pump motor bearing temperatures are supplied as input to the process computer. A high temperature causes the computer to alarm and identify the out-of-limit temperatures. The CCWS isolation valve monitor lights, which would indicate valve closure, are located on the main control board.
The operator action necessary to trip the reactor and stop the reactor coolant pumps is not complicated and is a direct logical result of the event symptoms alarmed and indicated. An operator response time of 10 minutes is conservative and appropriate for this event during normal operation.
Actual tests performed by Westinghouse Electric Corporation on reactor coolant pumps of the type provided for the Virgil C. Summer Nuclear Station show that interruption of the CCWS flow for 10 minutes or less will not result in damage to the pump.
The pump shaft, seal housing, thermal barrier, main flange, and motor stand can be removed from the casing without disturbing the reactor coolant piping. The flywheel is available for inspection by removing the cover.
The performance characteristic, shown in Figure 5.5-2, is common to all of the fixed speed mixed flow pumps and the "knee" at about 45% design flow introduces no operational restrictions, since the pumps operate at full speed.
5.5.1.3 Design Evaluation 5.5.1.3.1 Pump Performance The reactor coolant pumps are sized to deliver flow at rates which equal or exceed the required flowrates. Initial Reactor Coolant System (RCS) tests confirm the total delivery capability. Thus, assurance of adequate forced circulation coolant flow is provided prior to initial plant operation.
The Reactor Trip System ensures that pump operation is within the assumptions used for loss of coolant flow analyses, which also assures that adequate core cooling is provided to permit an orderly reduction in power if flow from a reactor coolant pump is lost during operation.
5.5-4 Reformatted January 2016 An extensive test program has been conducted for several years to develop the controlled leakage shaft seal for pressurized water reactor applications. Long term tests were conducted on less than full scale prototype seals as well as on full size seals.
Operating plants continue to demonstrate the satisfactory performance of the controlled leakage shaft seal pump design.
The support of the stationary member of the number 1 seal ("seal ring") is such as to allow large deflections, both axial and tilting, while still maintaining its controlled gap relative to the seal runner. Even if all the graphite were removed from the pump bearing, the shaft could not deflect far enough to cause opening of the controlled leakage gap. The "spring-rate" of the hydraulic forces associated with the maintenance of the gap is high enough to ensure that the ring follows the runner under very rapid shaft deflections.
Testing of pumps with the number 1 seal entirely removed (full reactor pressure on the number 2 seal) shows that relatively small leakage rates would be maintained for long periods of time; even if the number 1 seal fails entirely, the number 2 seal would maintain these small leakage rates. The plant operator is warned of number 1 seal damage by the increase in number 1 seal leakoff. Following warning of excessive seal leakage conditions, the plant operator should close the number 1 seal leakoff line and secure the pump, as specified in the instruction manual. It may be concluded that gross leakage from the pump does not occur if the proper operator action is taken subsequent to warning of excessive seal leakage conditions.
The effect of loss of offsite power on the pump itself is to cause a temporary stoppage in the supply of injection flow to the pump seals and also of the cooling water for seal and bearing cooling. The emergency diesel generators are started automatically due to loss of offsite power so that seal injection flow is automatically restored.
5.5.1.3.2 Coastdown Capability It is important to reactor operation that the reactor coolant continues to flow for a short time after a reactor trip. In order to provide this flow in a station blackout condition, each reactor coolant pump is provided with a flywheel. Thus, the rotating inertia of the pump, motor, and flywheel is employed during the coastdown period to continue the reactor coolant flow. The coastdown flow transients are provided in the figures in Section 15.3.
The pump/motor system is designed for Seismic Category 1. The integrity of the bearings is described in Section 5.5.1.3.4. Hence, it is concluded that the coastdown capability of the pumps is maintained even under the most adverse case of a loss of offsite power coincident with the safe shutdown earthquake. Core flow transients and figures are provided in Section 15.2.
RN 99-110 5.5-5 Reformatted January 2016 5.5.1.3.3 Flywheel Integrity Demonstration of integrity of the reactor coolant pump flywheel is discussed in Section 5.2. Additional discussion is contained in Reference [1].
5.5.1.3.4 Bearing Integrity The design requirements for the reactor coolant pump bearings are primarily aimed at ensuring a long life with negligible wear, so as to give accurate alignment and smooth operation over long periods of time. The surface bearing stresses are held at a very low value and even under the most severe seismic transients do not begin to approach loads which cannot be adequately carried for short periods of time.
Because there are no established criteria for short time stress-related failures in such bearings, it is not possible to make a meaningful quantification of such parameters as margins to failure, safety factors, etc. A qualitative analysis of the bearing design, embodying such considerations, gives assurance of the adequacy of the bearing to operate without failure.
Low oil levels in the lube oil sumps signal an alarm in the control room and require shutting down of the pump. Each motor bearing contains embedded temperature detectors, and so initiation of failure, separate from loss of oil, is indicated and alarmed in the control room as a high bearing temperature. This, again, requires pump shutdown. If these indications are ignored and the bearing proceeded to failure, the low melting point of Babbitt metal on the pad surfaces ensures that sudden seizure of the shaft will not occur. In this event the motor continues to operate, as it has sufficient reserve capacity to drive the pump under such conditions.
However, the high torque required to drive the pump will require high current which will lead to the motor being shutdown by the electrical protection systems.
5.5.1.3.5 Locked Rotor It may be hypothesized that the pump impeller might severely rub on a stationary member and then seize. Analysis has shown that under such conditions, assuming instantaneous seizure of the impeller, the pump shaft fails in torsion just below the coupling to the motor, disengaging the flywheel and motor from the shaft. This constitutes a loss of coolant flow in the loop. Following such a postulated seizure, the motor continues to run without any overspeed, and the flywheel maintains its integrity, as it is still supported on a shaft with 2 bearings. Flow transients are provided in the figures in Section 15.4 for the assumed locked rotor.
There are no other credible sources of shaft seizure other than impeller rubs. Any seizure of the pump bearing is precluded by graphite in the bearing. Any seizure in the seals results in a shearing of the anti-rotation pin in the seal ring. The motor has adequate power to continue pump operation even after the above occurrences. Indications of pump malfunction in these conditions are initially by high temperature signals from the bearing water temperature detector and excessive number 1 seal 5.5-6 Reformatted January 2016 leakoff indications respectively. Following these signals, pump vibration levels are checked. Excessive vibration indicates mechanical trouble and the pump is shutdown for investigation.
5.5.1.3.6 Critical Speed The reactor coolant pump shaft is designed so that its operating speed is below its first critical speed. This shaft design, even under the most severe postulated transient, gives low values of actual stress.
5.5.1.3.7 Missile Generation Each component of the pump is analyzed for missile generation. Any fragments of the motor rotor would be contained by the heavy stator. The same conclusion applies to the pump impeller because the small fragments that might be ejected would be contained by the heavy casing. Further discussion and analysis of missile generation are contained in Reference [1].
5.5.1.3.8 Pump Cavitation The minimum net positive suction head required by the reactor coolant pump at running speed is approximately a 192 foot head (approximately 85 psi). In order for the controlled leakage seal to operate correctly it is necessary to have a minimum differential pressure of approximately 200 psi across the seal. This corresponds to a primary loop pressure at which the net positive suction head requirement is exceeded and no limitation on pump operation occurs from this source. At this pressure the net positive suction head requirement is exceeded and the pump can be successfully operated.
5.5.1.3.9 Pump Overspeed Consideratio ns For turbine trips actuated by either the Reactor Trip System or the Turbine Protection System, the generator and reactor coolant pumps are maintained connected to the external network for at least 30 seconds to prevent any pump overspeed condition (see Section 8.2).
An electrical fault requiring immediate trip of the generator (with resulting turbine trip) could result in an overspeed condition. However, the turbine control system and the turbine intercept valves limit the overspeed to less than 120%.
In case a generator trip de-energizes the pump buses, the reactor coolant pump motors will be transferred to offsite power within 6 to 10 cycles. Further discussion of pump overspeed considerations is contained in Reference [1].
RN 11-015 5.5-7 Reformatted January 2016 5.5.1.3.10 Anti-Reverse Rotation Device Each of the reactor coolant pumps is provided with an anti-reverse rotation device in the motor. This anti-reverse mechanism consists of 5 pawls mounted on the outside diameter of the flywheel, a serrated ratchet plate mounted on the motor frame, a spring return for the ratchet plate, and 2 shock absorbers.
After the motor has slowed and come to a stop, the dropped pawls engage the ratchet plate and, as the motor tends to rotate in the opposite direction, the ratchet plate also rotates until it is stopped by the shock absorbers. The rotor remains in this position until the motor is energized again. When the motor is started, the ratchet plate is returned to its original position by the spring return.
As the motor begins to rotate, the pawls drag over the ratchet plate. When the motor reaches sufficient speed, the pawls are bounded into an elevated position and are held in that position by friction resulting from centrifugal forces acting upon the pawls.
Considerable shop testing and plant experience with the design of these pawls have shown high reliability of operation.
5.5.1.3.11 Shaft Seal Leakage Leakage along the reactor coolant pump shaft is controlled by 3 shaft seals arranged in series such that reactor coolant leakage to the containment is essentially 0. Charging flow is directed to each reactor coolant pump via a 5 micron seal water injection filter.
The flow is injected into the reactor coolant pump through a pipe in the thermal barrier flange and is directed down to a point between the pump shaft bearing and the thermal barrier cooling coils. Here the flow enters the shaft annulus; a portion flows down past the thermal barrier cooling cavity, labyrinth seals and into the RCS; the remainder flows up the pump shaft annulus cooling the lower shaft bearing. This flow provides a back pressure on the number 1 seal and a controlled flow through the seal. Above the seal most of the flow leaves the pump via the number 1 seal leakoff line. Minor flow passes through the number 2 seal and leakoff line and the number 3 seal and leakoff line. This arrangement assures essentially 0 leakage of reactor coolant or trapped gases from the pump.
5.5.1.3.12 Seal Discharge Piping Discharge pressure from the number 1 seal is reduced to that of the volume control tank. Water from each pump number 1 seal is piped to a common manifold, through the seal water return filter, and through the seal water heat exchanger where the temperature is reduced to that of the volume control tank. The number 2 and number 3 leakoff lines dump number 2 and number 3 seal leakage to the reactor coolant drain tank.
RN 98-128 5.5-8 Reformatted January 2016 5.5.1.3.13 Loss of Component Cooling Water or Seal Injection Component cooling water is provided to the reactor coolant pump thermal barrier heat exchanger, as well as to the upper and lower motor bearing oil coolers. In addition, seal injection flow is supplied to the pumps from the chemical and volume control system.
These cooling supplies are discussed in the following paragraph and are shown schematically in Figure 5.5-16. Detailed flow diagrams of the Chemical and Volume Control System and the Component Cooling Water System are shown in FSAR Figures 9.3-16 and 9.2-5, respectively.
Consequences of the loss of either of these supplies are also discussed in the following paragraphs.
Seal injection flow, at a slightly higher pressure and at a lower temperature than the Reactor Coolant System, enters the pump through a pipe connection on the thermal barrier flange (see Figure 5.5-17) and is directed to a point between the pump radial bearing and the thermal barrier heat exchanger. Here the flow splits with a portion flowing down through the thermal barrier labyrinth (where it acts as a buffer to prevent reactor coolant from entering the radial bearing and seal section of the pump) and into the Reactor Coolant System. The remainder of the seal injection water flows up through the pump radial bearing and the shaft seals and is discharged via the seal leakoffs.
The pump shaft seal section consists of 3 seals in series, which are contained within a seal housing. The seal arrangement is shown in Figure 5.5-18. The No. 1 seal, the primary seal of the pump, is a controlled-leakage, film-riding seal. Most of the seal injection flow (directed to the seals) is discharged through the No. 1 seal leakoff, which is piped to the volume control tank. Minor leakage passes through the No. 2 and No. 3 seals, which are rubbing-face type seals. The No. 2 and No. 3 seal leakoffs ar e directed to the reactor coolant drain tank. This arrangement minimizes leakage of water and vapor into the containment.
The thermal barrier is a welded assembly consisting of a flanged cylindrical shell, a series of concentric stainless steel cans, a heat exchanger coil assembly, and 2 flanged water connections.
Component cooling water enters the thermal barrier through a flanged connection on the thermal barrier flange (see Figure 5.5-17). The cooling water flows through the inside of the coiled stainless steel tubing in the heat exchanger and exits through another flanged connection on the thermal barrier flange. During normal operation, the thermal barrier limits the heat transfer from the reactor coolant to the pump internals.
5.5-9 Reformatted January 2016 The upper bearing assembly contains an oil-cooled pivoted-pad radial guide bearing (upper guide bearing), as well as a double acting oil-cooled Kingsbury-type thrust bearing (see Figure 5.5-19). The thrust bearing shoes are positioned above and below a common runner to accommodate thrust in both directions. The shoes are mounted on equalizing pads, which distribute the thrust load equally to all the shoes.
The oil is circulated through an external oil-to-water shell and tube heat exchanger (oil cooler) to which component cooling water is supplied.
The lower guide bearing is a pivoted-pad radial bearing, similar to the upper guide bearing.
The entire lower guide bearing assembly is located in the lower oil reservoir, which contains an integral oil-to-water coil type heat exchanger (see Figure 5.5-19).
Component cooling water is supplied to this heat exchanger.
Should a loss of seal injection to the RCPs occur, the pump radial bearing and seals are lubricated by reactor coolant flowing up through the pump. Under these conditions, the CCWS continues to provide flow to the thermal barrier heat exchanger and the heat exchanger, functioning in its backup capacity, cools the reactor coolant before it enters the pump radial bearing and the shaft seal area. The loss of seal injection flow may result in a temperature increase in the pump bearing area, a temperature increase in the seal area, and a resultant increase in the number one seal leak rate; however, pump operation can be continued (for up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />), provided these parameters remain within the allowable limits.
Should a loss of CCW to the RCPs occur, the Chemical and Volume Control System continues to provide seal injection flow to the RCPs; the seal injection flow is sufficient to prevent damage to the seals with a loss of thermal barrier cooling. Consequently, the RCP can continue to run following a loss of thermal barrier cooling provided that pump seal temperatures remain within allowable limits. However, the loss of CCW to the motor bearing oil coolers will result in an increase in oil temperature and a corresponding rise in motor bearing metal temperature. It has been demonstrated by testing, that the reactor coolant pumps will incur no damage as a result of a CCW flow interruption of 10 minutes.
Two (2) safety related transmitters are provided to redundantly monitor component cooling water flow to the upper and lower reactor coolant pump bearings. Two (2) additional safety related transmitters are provided to redundantly monitor component cooling water flow to the reactor coolant pump thermal barriers. These transmitters provide flow indication and actuate low flow alarms in the control room.
5.5-10 Reformatted January 2016 A discussion of the loss of seal injection is provided above. This discussion justifies the use of non-safety grade instrumentation for seal injection flow, since loss of seal injection is not limiting in terms of continued pump operation and does not require immediate operator action.
As discussed above, a loss of CCW to the motor bearing oil coolers will result in an increase in oil temperature and a corresponding rise in motor bearing temperature.
Since the loss of CCW to the thermal barrier does not, in itself, affect operation of the RCP, a simultaneous loss of CCW to the thermal barrier and to the motor bearing o il coolers is no worse than a loss of CCW only to the motor bearing oil coolers.
Westinghouse contends that the loss of CCW to the RCPs will not result in an instantaneous seizure of a single pump and, further, that instantaneous seizure of 2 pumps simultaneously is not a credible ultimate consequence.
will be an abbreviated coastdown. If a limiting condition of the babbitt metal is considered, an increasing coefficient of friction, as well as an increasing retarding torque is expected. However, in view of the large rotational inertia of the pump/motor assembly, Westinghouse maintains that an instantaneous seizure will not result.
Because an initial seizure is not expected, it is not possible to define a precise point in time at which a sequential seizure would be anticipated. Therefore, for the purpose of defining the time expected between sequential seizures, the following discussion will be presented in terms of sequential occurrences of reaching a "high" bearing temperature.
The upper thrust bearing exhibits the limiting temperature; therefore, an upper thrust bearing temperature of 240F has been chosen arbitrarily as the "high" temperature. It should be noted that the use of this value does not imply pump seizure at this temperature.
Variables affecting the steady state operating temperature of the bearings include the following:
- a. Surface finish of the bearing and runner.
- b. Bearing (and oil pumping mechanism) clearances.
- c. Inlet temperature of water to heat exchanger (oil cooler).
- d. Condition of oil-to-water heat exchanger (oil cooler) (i.e., extent of fouling).
- e. Condition of oil.
- f. Amount of oil in oil pot.
- g. Oil temperature.
5.5-11 Reformatted January 2016 These variables would be expected to interact concurrently in a manner which individualizes the performance of the bearings during actual steady state plant operation.
In order to quantify the resultant variation in performance, Westinghouse has collected data from an operating plant. This data demonstrates that the upper thrust bearings operate at different steady state temperatures (i.e., 128F, 132F, 135F, and 145F). It should be noted that this data was collected from a 4 loop plant; the following evaluation based on this data is applicable to a 3 loop plant (i.e., Virgil C. Summer).
Using these actual steady state operating values (A-128F, B-132F, C-135F, D-145F) and assuming a conservative 5F/minute linear heatup rate after a loss of CCW, sequential occurrences of reaching the high bearing temperature could be expected at the time intervals tabulated below. (See Figures 5.5-20 and 5.5-21.)
Sequential Motors Operating Temperature( F) Time Interval(minutes)
A and B 4 0.8 B and C 3 0.6 C and D 10 2.0 A and C 7 1.4 B and D 13 2.6 A and D 17 3.4 To summarize, 2 bearings sequentially reaching a temperature of 240F could be expected at a minimum time interval of 0.6 minutes and at a maximum time interval of 3.4 minutes.
Westinghouse has obtained motor bearing heatup data. These test data show actual values of bearing temperatures following a loss of CCW. The test data presented in Figure 5.5-22 will be examined relative to the above discussion. The test runs, which were performed at different times using different motors, demonstrate similar heatup rates; this fact supports the assumption of identical linear heatup rates made in the previous discussion. In addition, the average heatup rates evidenced in the test data are less than 3.3F/minute, which substantiates the use of 5F/minute as a conservative value. The actual test data, although limited, is supportive of the assumptions posed in defining the time intervals tabulated above.
In conclusion, Westinghouse contends that a single or multiple pump seizures as the result of a loss of CCW to the RCPs is not a credible event. However, in our judgment and based on the above discussion, 2 RCP motor upper thrust bearings could sequentially reach a "high" bearing temperature of 240F at a minimum time interval of 0.6 minutes (or approximately 40 seconds).
5.5-12 Reformatted January 2016 Section 15.4.4 of the Virgil C. Summer FSAR presents the analysis of a single RCP locked rotor. It should be pointed out that the Section 15 analysis assumes an instantaneous seizure of a reactor coolant pump rotor on a non-mechanistic basis.
Westinghouse contends that a postulated mechanistic instantaneous seizure of a pump rotor due to a loss of CCW to the RCP will not occur and is not a credible event.
However, in response to the NRC request, the results of a second non-mechanistic instantaneous seizure occurring at 40 seconds after a first non-mechanistic instantaneous seizure have been evaluated. Although a Section 15 approach was utilized to evaluate this situation, Westinghouse does not recognize a postulated mechanistic instantaneous locked rotor as a credible consequence of the loss of CCW to the RCPs.
Assuming that a second pump seizure occurs 40 seconds after a first pump seizure, no noticeable change is seen in the Reactor Coolant System pressure and the clad temperature transients. Furthermore, even if the time interval between the sequential seizures is reduced to 10 seconds, no noticeable change is seen in the Reactor Coolant System pressure and the clad temperature transients.
The hypothetical seizure of 1 RCP results in a low flow reactor trip approximately 1 second after the initiation of the event. As a result of the fast reactor trip and the consequential decrease in core heat flux, the Reactor Coolant System pressure and the clad temperature reach the peak values at about 2.5 seconds and then start to decrease.
Because the core has been shut down, at 40 seconds - or even 10 seconds - after a pump seizure, the Reactor Coolant System pressure and the clad temperature transients have decreased to a point at which a second pump seizure results in no noticeable change in the transients.
Operating procedures are provided for a loss of component cooling water and seal injection to the reactor coolant pumps and/or motors. Included in these operating procedures is the provision to trip the reactor if component cooling water flow, as indicated by the instrumentation discussed previously, is lost to the reactor coolant pump motors and cannot be restored within 10 minutes. The reactor coolant pumps will also be tripped following the reactor trip.
This section provides a description of testing performed and the test results which constitute the basis of reactor coolant pump operation for 10 minutes without CCW with no resultant damage. Two (2) RCP motors have been tested with interrupted CCW flow; these tests were conducted at the Westinghouse Electro Mechanical Division. In both cases, the reactor coolant pumps were operated to achieve "hot" (2230 psia, 552F) equilibrium conditions. After the bearing temperatures stabilized, the cooling water flow to the upper and lower motor bearing oil coolers was terminated and bearing (upper thrust, lower thrust, upper guide, and lower guide) temperatures were monitored. A bearing metal temperature of 185F was established as the maximum test temperature. When that temperature was reached, the cooling water flow was restored.
5.5-13 Reformatted January 2016 In both tests, the upper thrust bearing exhibited the limiting temperatures. Figure 5.5-21 shows the upper thrust bearing temperature versus time. In both cases, 185F was reached in approximately 10 minutes.
The maximum test temperature of 185F is also the suggested alarm setpoint temperature and the suggested trip temperature is 195F. It should be noted that the melting point of the babbitt bearing metal exceeds 400 F. The information presented above constitutes the basis of the RCP qualification for 10 minute operation without CCW with no resultant damage.
5.5.1.4 Tests and Inspections The reactor coolant pumps can be inspected in accordance with the ASME Code,Section XI, for Inservice Inspection of Nuclear Reactor Coolant Systems.
Any full penetration welds in the pressure boundary are prepared with a smooth surface transition between weld metal and parent metal for radiographic inspection. However, the pump casing is cast in one piece, eliminating welds in the casing.
Support feet are cast integral with the casing to eliminate a weld region.
The design enables disassembly and removal of the pump internals for usual access to the internal surface of the pump casing.
The reactor coolant pump quality assurance program is given in Table 5.5-
- 2. 5.5.2 STEAM GENERATORS 5.5.2.1 Design Bases The replacement steam generators installed in the V. C. Summer plant are Westinghouse Delta-75, feedring type steam generators. To facilitate replacement in the plant, the geometric characteristics of the Delta-75 steam generators are identical to the original D3 steam generators. Additionally, the Delta-75 steam generators must provide an equal or better level of performance than the original steam generators. The Delta-75 steam generators are expected to supply steam at about 1.3% higher than the original D3 steam generators at a plant thermal rating of 2787 MWt. At the Engineered Safeguards Power Rating of 2912 MWt, the Delta-75 steam generators are expected to deliver steam at about 2.0% above that projected for the original D3 steam generators.
The steam generators are designed and analyzed according to the requirements of Section III of the ASME Code, 1971 Edition through Summer 1971 Addenda, and constructed according to the 1986 Edition. To minimize the impact on steam generator supports and seismic considerations, the total weight of each empty Delta-75 steam generator is 360 tons.
5.5-14 Reformatted January 2016 Steam generator design data is given in Table 5.3-3. The design sustains transient conditions given in Section 5.2.1. Although the required secondary side ASME classification is Class 2, Class 1 requirements are applied for all pressure retaining portions of the steam generator. Assurance of adequate fracture toughness of all pressure boundary materials, is, therefore, as described in Section 5.2.4 and complies with Article NB-2300 of Section III of the ASME Code. Rupture of a steam generator tube is discussed in Section 15.4.3.
The internal moisture separation equipment is designed to ensure that moisture carryover does not exceed 0.10% by weight under the following conditions:
- 1. Steady-state operation up to 100% of full load steam flow, with water at the normal operating level.
- 2. Loading or unloading at a rate of 5% of full load power steam flow per minute in the range from 15% to 100% of full load steam flow.
- 3. A step load change of 10% of full power in the range from 15% to 100% full load steam flow.
The water chemistry in the reactor side is selected to provide the necessary boron content for reactivity control and to minimize corrosion of RCS surfaces. The water chemistry of the steam side and its effectiveness in corrosion control is discussed in Section 10.3.5.
5.5.2.2 Design Description. The original VCSNS steam generators were Model D3 type, which employed the use of an integral preheater at the feedwater inlet. The original steam generators were replaced during the Refuel 8 outage, approximately September, 1994, with Westinghouse Delta-75 steam generators. The Delta-75 steam generator has the same profile dimensions as the original D3 steam generator. Like the D3 steam generator, the Delta-75 is a vertical shell and U-tube evaporator with integral moisture separation equipment. The Delta-75 steam generator is shown in Figure 5.5-3. The reactor coolant flows through the inverted U-tubes, entering and leaving through the nozzles located in the hemispherical bottom head of the steam generator. The head is divided into inlet and outlet chambers by a vertical partition plate extending from the head to the tubesheet. Manways are provided for access to both sides of the divided head. The feedwater inlet on the original D3 steam generators was located several feet above the top surface of the tubesheet, on the cold leg or return side of the U-tube bundle. The incoming feedwater was forced through a back and forth path within the preheater by several staggered tube support plates. This path allowed the feedwater temperature to be rapidly heated almost to saturation temperature before entering the boiler section. In the Delta-75, the feedwater inlet is located at approximately 2/3 of the steam generator height and is distributed equally around the circumference of the steam generator shell.
Feedwater enters the tube bundle by flowing downward between the steam generator 5.5-15 Reformatted January 2016 external shell and inner wrapper barrel. An open area at the bottom of the wrapper barrel permits the feedwater to enter the tube bundle. The simplified design of the Delta-75 steam generator supports a more simplified steam generator operating procedure and eliminates some of the low power operating restrictions applied to the D3 steam generators. The total steam generator heat transfer surface area is increased in the Delta-75 to account for the thermal performance characteristics of the preheater.
Steam is generated and flows upward through the moisture separators and through the flow restrictor outlet nozzle at the top of the steam drum. The Delta-75 utilizes high efficiency centrifugal steam separators, which remove most of the entrained water.
Chevron dryers are employed to increase the steam quality to a minimum of 99.90%
(0.10% moisture).
The steam generator channel head and tubesheet are protected from the primary water by applying an autogenous weld deposited stainless steel cladding to the primary surfaces of the channel head and Inconel to the tubesheet. The cladding surface is machined to a smooth condition and electropolished thereby reducing the collection of radioactive contamination inside the steam generators during refueling and maintenance periods.
Steam generator materials of construction are listed in Table 5.2-8. All materials are selected and fabricated in accordance with the requirements of the ASME Code,Section III, and Code Case N-20-3. The steam generator tubing material is Alloy 690. Alloy 690 material represents the state of the art technology for heat transfer tubing.
The tubing receives a heat treatment process after forming which results in a grain boundary structure which has been shown by test to be exceptionally resistive to primary water stress corrosion cracking (PWSCC), which initiates tube degradation in the expansion region within the tubesheet area and has resulted in the majority of tube plugging in the original D3 steam generators at V. C. Summer. The tube expansion process used for the replacement steam generator is not expected to result in similar strain levels or patterns as observed in the original D3 steam generators. Alloy 690 tubing material is also exceptionally resistive to outer diameter stress corrosion cracking (ODSCC), which has affected the secondary side of the tubes in operating plants at the tube support plate intersections.
Ferritic material in the primary side of the steam generators includes the following:
channel head casting, tubesheet, primary nozzles, manway covers, and manway studs and nuts. Fracture toughness data for the steam generator bolting materials is shown in Table 5.2-22. Fracture toughness data for the channel head, tubesheet, and associated weldments will be consistent with ASME Code. As-built data generally shows the test data to far exceed the ASME Code minimum values. The materials of construction and general design of the steam generator shell of the Delta-75 have resulted in a reduction in the number of pressure boundary welds required for assembly of the shell.
02-01 5.5-16 Reformatted January 2016 5.5.2.3 Design Evaluation 5.5.2.3.1 Forced Convection The effective heat transfer coefficient is determined by the physical characteristics of the Delta-75 steam generator and the fluid conditions in the primary and secondary systems for the nominal 100% design case. It includes a conservative allowance for fouling and uncertainty. A designed heat transfer area is provided to permit the achievability of the full-design heat-removal rate. Although margin for tube fouling is available, operating experience to date has not indicated that steam generator thermal performance decreases over a long term period. Adequate tube surface area is selected to ensure that the full design heat removal rate is achieved.
5.5.2.3.2 Natural Circulation Flow The steam generators, which provide a heat sink, are at a higher elevation than the reactor core, which is the heat source. Thus natural circulation is assured for the removal of decay heat.
5.5.2.3.3 Tube and Tubesheet Stress Analyses Tube and tubesheet stress analyses of the steam generator, which are discussed in Section 5.2, confirm that the steam generator tubesheet will withstand the loading caused by a loss of reactor coolant (LOCA). Routine inservice inspections of the steam generator tubing will assess tubing integrity and adequacy for continued operation based upon the 40% depth of indication limit specified by Section XI of ASME Code. Tube degradation existing at this level will maintain integrity consistent with the recommendations of Regulatory Guide 1.121 during the transient events identified in Section 5.2.
5.5.2.3.4 Corrosion The Delta-75 steam generator utilizes thermally treated Alloy 690 tube material. This material is used in the replacement steam generators at North Anna Unit 1 and Indian Point Unit 3. Thermally treated Alloy 690 tubing is also used in a number of plants, which include the Turkey Point replacements, Surry replacements, D. C. Cook Unit 2 replacements, and Prairie Island replacements, Wolf Creek, Seabrook and Millstone Unit 3.
To date, the only form of tube degradation which has been identified in Model F-type units is fretting wear between the tube and steam generator anti-vibration bars (AVB).
Only a small number of tubes (expected to be less than 1% total over the life of the steam generators) would be subject to this phenomena. The AVB design in the Delta-75 steam generators maintain smaller, more tightly controlled tube-to-AVB gaps, increased tube-to-AVB contact area, agenerators. These factors should greatly lower the potential for tube fretting at AVB intersections in the Delta-75 steam generators.
5.5-17 Reformatted January 2016 5.5.2.3.5 Compatibility of Steam Generator Tubing with Primary and Secondary Coolant As previously discussed, the Alloy 690 tubing installed in the Delta-75 steam generators at V. C. Summer have been shown by test (and operating experience) to be exceptionally resistant to both PWSCC and ODSCC. The Delta-75 Alloy 690 tubing
specification is in accordance with the requirements of ASME Code Case N-20-3, ASME Code Section III, ASME Code Section II Specification SB-163, and meets the EPRI Guidelines for Procurement of Alloy 690 steam generator tubing, NP-6743-L, February 1991.
The steam generator tube expansion process employed in the tubesheet region results in reduced residual stress levels compared to the original D3 steam generators. This reduced residual stress will lower the potential for PWSCC in this region. Additionally , no evidence of PWSCC has been identified in either the Model F type steam generators operating today, or the replacement steam generators manufactured by Westinghouse.
The potential for ODSCC to develop in the Delta-75 steam generators is also greatly reduced. The axial flow paths around the steam generator tubes provided by the trifoil support design significantly reduces crevice area and contaminant hideout potential.
The stainless steel tube support plate material does not represent a potential for magnetite generation or general corrosion product buildup. Also, the most recent revision of the EPRI Secondary Water Chemistry Guidelines have incorporated a sodium-chloride molar ratio control philosophy, which will help to maintain an as neutral as possible crevice chemistry within the entire steam generator secondary side.
5.5.2.3.6 Flow Induced Vibration The potential for tube wall degradation attributable to mechanical or flow induced excitation is exceptionally low in a feedring type steam generator design. Flow induced vibration at the tube support plate intersections has not been observed in Model F type steam generators.
5.5.2.3.7 Tube Denting Localized steam generator tube diameter reductions were first discovered during the April 1975 steam generator inspection at the Surry Unit 2 plant. This discovery was evidenced by eddy current signals, resembling those produced by scanning dents, and by difficulty in passing the standard 0.700 inch diameter eddy current probe through the tubes at their intersections with the support plates. Subsequent to the initial finding, steam generator inspections at other operating plants revealed essentially identical results.
5.5-18 Reformatted January 2016 The phenomena of tube denting is attributed to a localized buildup of corrosion products (due to magnetite generation in the support plate crevice) in the tube-to-tube support plate crevice, which eventually deforms the tube wall as the corrosion products continue to build. The implementation of All Volatile Treatment (AVT) chemistry on th e secondary side of the steam generator has minimized the potential of denting.
Additionally, the Delta-75 steam generators at the V. C. Summer plant employ stainless steel tube support plates, which should preclude the formation of corrosion products within the crevice. The Delta-75 tube support plates employ a limited contact trifoil hole shape which permits axial flow around the tube, which also minimizes the buildup of corrosion products in this area. The original D3 steam generators utilized carbon steel support plates with drilled tube holes of a diameter approximately 0.013 inch larger in diameter than the tubes, which can be filled with corrosion products.
5.5.2.4 Test and Inspections The steam generator quality assurance program is given in Table 5.5-4. During manufacture, cleaning is performed on the primary and secondary sides of the steam generator in accordance with written procedures which follow the guidance of Regulatory Guide 1.37 and other industry standards, such as those developed by the American Society of Testing and Materials (ASTM). Radiographic inspections, liquid penetrant inspections, magnetic particle inspections, ultrasonic inspections, and the implementation of the associated acceptance criteria for each are instituted according to the requirements of the ASME Code.
The steam generators are designed to permit inservice inspections in accordance with the requirements of Section XI to the ASME Code, and steam generator tubing eddy current examination consistent with the requirements of V.C. Summer Technical
When required, tests, using a Lithium or radioactive Sodium tracer, are conducted to properly account for moisture carryover in the plants calorimetric and precision RCS flow measurement.
5.5.3 REACTOR COOLANT PIPING 5.5.3.1 Design Bases The RCS piping is designed and fabricated to accommodate the system pressures and temperatures attained under all expected modes of plant operation or anticipated system interactions. Stresses are maintained within the limits of Section III of the ASME Nuclear Power Plant Components Code. Code and material requirements are provided in Section 5.2.
Materials of construction are specified to minimize corrosion/erosion and ensure compatibility with the operating environment.
RN 10-016 RN 99-110 RN 99-110 5.5-19 Reformatted January 2016 The piping in the RCS is Safety Class 1 and is designed and fabricated in accordance with the ASME Code,Section III, Class 1 requirements.
Stainless steel pipe conforms to ANSI B36.19 for sizes 1/2 inch through 12 inches and wall thickness Schedules 40S through 80S. Stainless steel pipe outside of the scope of ANSI B36.19 conforms to ANSI B36.10.
The minimum wall thicknesses of the loop pipe and fittings are not less than that calculated using the ASME Code,Section III, Class 1 formula of Paragraph NB-3641.1 (3) with an allowable stress value of 17,550 psi. The pipe wall thickness for the pressurizer surge line is Schedule 160. The minimum pipe bend radius is five nominal pipe diameters; ovality does not exceed 6%.
All butt welds, branch connection nozzle welds, and boss welds are of a full penetration design.
Processing and minimization of sensitization are discussed in Sections 5.2.3 and 5.2.5.
Flanges conform to ANSI B16.5.
Socket weld fittings and socket joints conform to ANSI B16.11.
Inservice inspection is discussed in Section 5.2.8.
5.5.3.2 Design Description Principal design data for the reactor coolant piping is given in Table 5.5-
- 5.
The piping is seamless forged; the fittings are cast without longitudinal welds and electroslag welds. Piping and fittings comply with the requirements of the ASME Code,Section II, Parts A and C,Section III, and Section IX.
The RCS piping is specified in the smallest sizes consistent with system requirements.
This design philosophy results in the reactor inlet and outlet piping diameters given in Table 5.5-5. The line between the steam generator and the pump suction is larger to reduce pressure drop and improve flow conditions to the pump suction.
The reactor coolant piping and fittings which make up the loops are austenitic stainless steel. There is no electroslag welding on these components. All smaller piping which comprise part of the RCS such as the pressurizer surge line, spray and relief line, loop drains, and connecting lines to other systems are also austenitic stainless steel. The nitrogen supply line for the pressurizer relief tank is carbon steel. All joints and connections are welded, except for the pressurizer code safety valves, where flanged joints are used. Thermal sleeves are installed at some points in the system where high thermal stresses could develop due to rapid changes in fluid temperature during normal operational transients. These points include:
RN 03-051 5.5-20 Reformatted January 2016
- 1. The pressurizer surge line connection at the pressurizer.
- 2. Pressurizer spray line connection at the pressurizer.
Piping connections from auxiliary systems are made above the horizontal centerline of the reactor coolant piping, with the exception of:
- 1. Residual heat removal pump suction lines, which are 45° down from the horizontal centerline. This enables the water level in the RCS to be lowered in the reactor coolant pipe while continuing to operate the Residual Heat Removal System, should this be required for maintenance.
- 2. Loop drain lines and the connection for temporary level measurement of water in the RCS during refueling and maintenance operation.
- 3. The differential pressure taps for flow measurement, which are downstream of the steam generators on the first 90° elbow. The tap arrangement is discussed in Section 5.6.
- 4. The pressurizer surge line, which is attached at the horizontal centerline.
- 5. The safety injection connections to the hot leg, for which inservice inspection requirements and space limitations dictate location on the horizontal centerline.
Penetrations into the coolant flow path are limited to the following:
- 1. The spray line inlet connections extend into the cold leg piping in the form of a scoop so that the velocity head of the reactor coolant loop flow adds to the spray driving force.
- 2. The reactor coolant sample system taps protrude into the main stream to obtain a representative sample of the reactor coolant.
In the current design, they provide a convenient location for the narrow range thermowell mounted RTDs.
- 4. The wide range temperature detectors and the cold leg fast response temperature detectors are located in resistance temperature detector wells that extend into the reactor coolant pipes.
5.5-21 Reformatted January 2016 The RCS piping includes those sections of piping interconnecting the reactor vessel, steam generator, and reactor coolant pump. It also includes the following:
- 1. Charging line and alternate charging line from the system isolation valve up to the branch connections on the reactor coolant loop.
- 2. Letdown line and excess letdown line from the branch connections on the reactor coolant loop to the system isolation valve.
- 3. Pressurizer spray lines from the reactor coolant cold legs to the spray nozzle on the pressurizer vessel.
- 4. Residual heat removal lines to or from the reactor coolant loops up to the designated check valve or isolation valve.
- 5. Safety injection lines from the designated check valve to the reactor coolant loops.
- 6. Accumulator lines from the designated check valve to the reactor coolant loops.
- 7. Loop fill, loop drain, sample (1), and instrument (1) lines to or from the designated isolation valve to or from the reactor coolant loops.
- 8. Pressurizer surge line from one reactor coolant loop hot leg to the pressurizer vessel inlet nozzle.
- 9. Resistance temperature detector scoop element, pressurizer spray scoop, sample connection (1) with scoop, reactor coolant temperature element installation boss, and the temperature element well itself.
- 10. All branch connection nozzles attached to reactor coolant loops.
- 11. Pressure relief lines from nozzles on top of the pressurizer vessel up to and through the power operated pressurizer relief valves and pressurizer safety valves.
- 12. Seal injection water and labyrinth differential pressure lines to or from the reactor coolant pump inside reactor building.
(1) Liquid filled lines with a 3/8 inch flow restricting orifice qualify as Safety Class 2a; in the event of a break in one of these Safety Class 2a lines, the normal makeup system is capable of providing makeup flow while maintaining pressurizer water level. Instrument impulse lines connected to the pressurizer steam space above the water level have been upgraded to Safety Class 1, since failure of these lines could cause automatic operation of the ECCS systems.
RN 07-012 5.5-22 Reformatted January 2016
- 13. Auxiliary spray line from the isolation valve to the pressurizer spray line header.
- 14. Sample lines (1) from pressurizer to the isolation valve.
Details of the materials of construction and codes used in the fabrication of reactor coolant piping and fittings are discussed in Section 5.2.
5.5.3.3 Design Evaluation Piping load and stress evaluation for normal operating loads, seismic loads, blowdown loads, and combined normal, blowdown, and seismic loads are discussed in Section 5.2.1.
5.5.3.3.1 Material Corrosion/Erosion Evaluation The water chemistry is selected to minimize corrosion. A periodic analysis of the coolant chemical composition is performed to verify that the reactor coolant quality meets the specifications.
The design and construction are in compliance with the ASME Code,Section XI.
Pursuant to this, all pressure containing welds out to the second valve that delineates the RCS boundary are available for examination with removable insulation.
Components constructed with stainless steel will operate satisfactorily under normal plant chemistry conditions in pressurized water reactor systems because chlorides, fluorides, and particularly oxygen are controlled to very low levels (see Section 5.2.3).
Periodic analysis of the coolant chemical composition is performed to monitor the adherence of the system to desired reactor coolant water quality listed in Table 5.2-10.
Maintenance of the water quality to minimize corrosion is accomplished using the Chemical and Volume Control System and process sampling system which are described in Sections 9.3.4 and 9.3.2, respectively.
5.5.3.3.2 Sensitized Stainless Steel
Sensitized stainless steel is discussed in Sections 5.2.3 and 5.2.5.
5.5.3.3.3 Contaminant Control
Contamination of stainless steel and Inconel by copper, low melting temperature alloys, mercury, and lead is prohibited. Only selected lubricants, which are not deleterious to stainless steel, are used.
Prior to application of thermal insulation, the austenitic stainless steel surfaces are cleaned and analyzed to a halogen limit of 0.0015 mg Cl/dm 2 and 0.0015 F/dm
- 2.
5.5-23 Reformatted January 2016 5.5.3.3.4 Alloy 600 Dissimilar Metal Welds The RCS Piping includes Alloy 600 dissimilar metal welds at the Reactor Vessel Nozzles, Steam Generator Nozzles, Pressurizer Surge Line Nozzle, Pressurizer Safety Valves, Power Operated Relief Valves, and Pressurizer Spray Nozzle.
A thru-wall leak was identified on the Reactor Vessel "A" Loop Hot Leg Nozzle to Pipe Weld during Refuel 12. The weld was completely removed and a pipe spool piece was welded in place. The root cause was determined to be Primary Water Stress Corrosion Cracking (PWSCC). The Reactor Vessel Nozzle to Pipe Weld was made using Alloy 690. Alloy 690 is a material with more resistance to PWSCC.
Due to the high susceptibility to PWSCC in the Reactor Vessel Hot Leg Nozzle to Pipe Welds, mitigative measures were taken during Refuel 13. The Mechanical Stress Improvement Process (MSIP) is a remediation process for pipe-to-pipe and pipe-to-nozzle welds that are susceptible to stress corrosion cracking from welding induced residual stresses. MSIP equipment applies a narrow permanent radial deformation adjacent to a pipe weld that redistributes the residual stresses in the weld region producing compressive stress at the inside diameter of the weld joint. This process removes one of the three factors (material susceptibility, environment, and high residual tensile stresses) required to create PWSCC in RCS components. MSIP was applied to the Reactor Vessel "B" and "C" Loop Hot Leg Nozzle to Pipe Welds.
The Pressurizer Nozzle Alloy 600 dissimilar metal welds were mitigated during Refuel 17 by the application of a full structural weld overlay. This weld overlay was applied to each of the nozzles on the pressurizer utilizing alloy 52M filler metal which is high in chromium and more resistant to PWSCC (consistent with alloy 690). This pre-emptive mitigation provided a full structural overlay to each of the nozzles and provides an ultrasonic NDE inspectable geometry which meets the ASME volumetric inspection requirements. The pre-weld overlay geometry did not meet the volumetric inspection requirements of the ASME XI code. Application of the weld overlay also provides a beneficial compressive stress to the underlying pipe, safe end, nozzle, and welds.
5.5.3.4 Tests and Inspections The RCS piping quality assurance program is given in Table 5.5-
- 6.
Volumetric examination is performed throughout 100% of the wall volume of each pipe and fitting in accordance with the applicable requirements of Section III of the ASME Code for all pipe 27-1/2 inches and larger. All unacceptable defects are eliminated in accordance with the requirements of the same section of the code.
A liquid penetrant examination is performed on both the entire outside and inside surfaces of each finished fitting in accordance with the criteria of the ASME Code,Section III. Acceptance standards are in accordance with the applicable requirements of the ASME Code,Section III.
RN 04-031 RN 08-022 5.5-24 Reformatted January 2016 The pressurizer surge line conforms to SA-376 Grade 304, 304N, or 316 with supplementary requirements S2 (transverse tension tests) and S6 (ultrasonic test). The S2 requirement applies to each length of pipe. The S6 requirement applies to 100% of the piping wall volume.
The end of pipe sections, branch ends, and fittings are machined back to provide a smooth weld transition adjacent to the weld path. All butt welds are ground smooth to permit inservice inspection in accordance with the ASME Code,Section XI. There is one pipe-to-pipe weld ("A" Hot Leg).
5.5.4 STEAM OUTLET FLOW RESTRICTOR (STEAM GENERATOR) 5.5.4.1 Design Bases Each steam generator is provided with a flow restrictor having several small diameter venturi-type throats. The flow restrictors are designed to limit steam flowrate consequent to the unlikely event of a steam line rupture; thereby, reducing the cooldown rate of the primary system and limiting stresses of internal steam generator components.
The flow restrictor is designed to minimize unrecovered pressure loss coincident with limiting accident flowrate to an acceptable value.
Although it is not considered to be part of the pressure vessel boundary, the restrictor is constructed of material specified in Section III of the ASME Code and is Seismic Category 1.
5.5.4.2 Design Description The flow restrictor is an assembly of 7 smaller nozzles installed within the steam outlet nozzle of the steam generator. Upper and lower internal discs support an outer circle of 6 nozzles and 1 central nozzle. The discs and outer cylinder are made of steel plates and pipe and the venturi nozzles are Inconel. The flow restrictor assembly is welded into the main steam generator outlet by a circumferential weld between the rim of the outer cylinder and the inside surface of the outlet nozzle.
5.5.4.3 Design Evaluation The equivalent throat diameter of the steam generator outlet is 16 inches and the resultant pressure drop through the restrictors at 100% steam flow is approximately 3.4 psig. The steam side weld to the outlet nozzle is in compliance with manufacturing and quality control requirements of the ASME Code,Section III, and is Seismic Category 1.
5.5.4.4 Tests and Inspections The restrictors are not a part of the steam system boundary. No tests or inspections of RN 04-031 5.5-25 Reformatted January 2016 5.5.5 MAIN STEAM LINE ISOLATION SYSTEM The main steam line isolation system is discussed in Sections 10.3.2 and 10.3.3. The discussion presented in the referenced sections include information on measures taken to reduce potential leakage of radioactivity to the environment in the event of a main steam line break.
5.5.6 REACTOR CORE ISOLATION COOLING SYSTEM Not applicable to pressurized water reactors.
5.5.7 RESIDUAL HEAT REMOVAL SYSTEM The Residual Heat Removal System (RHRS) transfers heat from the RCS to the Component Cooling Water System (CCWS) to reduce the temperature of the reactor coolant to the cold shutdown temperature at a controlled rate during the second part of normal plant cooldown and maintains this temperature until the plant is started up again.
During the first phase of cooldown, the temperature of the RCS is reduced by transferring heat from the RCS to the steam and power conversion system through the steam generators.
Parts of the RHRS also serve as parts of the Emergency Core Cooling System (ECCS) during the injection and recirculation phases of a loss of coolant accident (see Section 6.3).
The RHRS is also used to transfer refueling water between the refueling cavity and the refueling water storage tank at the beginning and end of the refueling operations.
5.5.7.1 Design Bases RHRS design parameters are listed in Table 5.5-
- 7.
The RHRS is placed in operation approximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after reactor shutdown when the temperature and pressure of the RCS are approximately 350F and less than 425 psig, respectively. The RHRS heat exchanger design heat load is based upon transferring 1/2 of the decay heat load at 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> after reactor shutdown (for the original RTP of 2775 MWt) with 5600 gpm CCWS flow (CCWS temperature is limited to 120F maximum and will decrease towards 105F as the cooldown proceeds) and 3750 gpm RHRS flow. With the current licensed RTP of 2900 MWt each RHRS heat exchanger is capable of transferring 1/2 of the decay heat load at 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after reactor shutdown with the same flowrates and CCWS temperature given above.
At the original RTP of 2775 MWt, the coupled RHRS/CCWS/SWS system is capable of cooling the RCS from 350F beginning at 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after reactor shutdown from an extended run at full power to 200F within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after the start of the RHRS cooldown 02-01 02-01 5.5-26 Reformatted January 2016 and to 140F within 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> after the start of the RHRS cooldown. With the current licensed RTP of 2900 MWt the coupled RHRS/CCW/SWS system is still capable of cooling the RCS from 350F beginning at 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after reactor shutdown from an extended run at full power to 200F within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after the start of the RHRS cooldown and to 140F within 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> after the start of the RHRS cooldown. The RHRS heat load during the transient includes the heat from 1 RCP (RCP off after RCS reaches
160F), core decay heat, and the sensible heat of the RCS metal and fluid; also, RCS cooldown rate is limited to 50F/hr. 5.5.7.1.1 Compliance with BTP RSB 5-1 The safe shutdown design basis of the Virgil C. Summer Nuclear Station is hot standby. Under abnormal conditions, the plant is designed to remain in a safe hot standby condition until (a) normal systems can be restored to permit either return to power operation or cooldown to cold shutdown conditions, or (b) sufficient systems capability can be restored (depending on plant condition) to permit cooldown to cold shutdown conditions under abnormal plant conditions. This design basis is considered to constitute a safe design.
BTP RSB 5-1 establishes specific design requirements that address the various system functions that are required to achieve and maintain a safe hot standby and cold shutdown conditions. BTP RSB 5-1 requires plants with construction permits docketed after January 1, 1978, to comply in full with the design requirements of the BTP. Plants
with construction permits docketed prior to January 1, 1978, (including Virgil C. Summer Nuclear Station) are required to address the BTP technical requirements and demonstrate partial compliance.
The following is a discussion of the Virgil C. Summer Nuclear Station compliance with the technical requirements of BTP RSB 5-1. This discussion demonstrates that under the postulated condition of BTP RSB 5-1 the Virgil C. Summer Nuclear Station can be maintained in a safe hot standby condition and taken to Residual Heat Removal System (RHRS) initiation conditions within approximately 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />, including credit for limited manual actions outside the control room to operate and/or repair a limited number of components that are not safety-grade or single failure proo
- f.
Itemized below are the technical requirements of BTP RSB 5-1 followed by a general discussion of the Virgil C. Summer Nuclear Station compliance. The technical requirements section is then followed by more detailed discussion in sections entitled Cold Shutdown Scenario, Single Failure Evaluation and Natural Circulation.
- 1. Provide safety-grade steam generator dump valves, operators, air, and power supplies which meet the single failure criterion.
One (1) safety grade steam generator power operated relief valve is provided for each of the 3 steam generators. Safety grade remote operators and power supplies are not required since hot standby can be achieved and maintained using 02-01 5.5-27 Reformatted January 2016 the safety grade steam generator safety valves. The steam generator power operated relief valves are provided with handwheels and can be operated locally to permit plant cooldown. See the cold shutdown scenario and single failure evaluation provided below (Part II, Removal of Residual Heat).
- 2. Provide the capability to cooldown to cold shutdown in a reasonable period of time assuming the most limiting single failure and loss of offsite power or show that manual actions inside or outside containment or return to hot standby until the manual actions or maintenance can be performed to correct the failure provides an acceptable alternative.
If a condition occurred requiring cold shutdown of the plant, design features permit the maintenance of a hot standby condition for an indefinite period of time. The plant is capable of being cooled via natural convection and reaching RHRS initiating conditions including the time required to perform any manual actions.
- 3. Provide the capability to depressurize the Reactor Coolant System with only safety-grade systems assuming a single failure and loss of offsite power or show that manual actions inside or outside containment or remaining at hot standby until manual actions or repairs are complete provides an acceptable alternative.
The plant can be maintained in a safe hot standby condition while any required manual actions are taken. See the cold shutdown scenario and single failure evaluation provided below (Part IV, Depressurization).
- 4. Provide the capability for borating with only safety grade systems assuming a single failure and loss of offsite power, or show that manual actions inside or outside containment or remaining at hot standby until manual actions or repairs are completed provides an acceptable alternative.
The plant can be maintained in a safe hot standby condition while any required manual actions are taken. See the cold shutdown scenario and single failure evaluation provided below (Part III, Boration and Makeup).
- 5. Provide the system and component design features necessary for the prototype testing of both the mixing of the added borated water and the cooldown under natural circulation conditions with and without a single failure of a steam generator atmospheric dump valve.
02-01 5.5-28 Reformatted January 2016 on mixing and cooldown test in natural circulation was originally to be demonstrated through referencing testing which was to be conducted at the Diablo Canyon nuclear plant.
Since that time, other plants have demonstrated the following results.
During natural circulation testing at Farley 2, North Anna II, Salem II and Sequoyah I, the following observations were made:
- b. By directly comparing North Anna and Farley natural circulation test results, these plants effectively exhibited identical behavior in terms of: time to stability following the reactor coolant pump trip; core flow distribution; core power distribution; and flow rates as indicated Results of the boron mixing and cooldown tests at Sequoyah, Salem, and North Anna indicate that:
- b. The tests performed at Salem and North Anna were performed at the end of cycle with a decay heat level on the order of 1% of the rated power where the Sequoyah test was done with nuclear heat of approximately 2% of the rated power. These power levels (and flow) are nominally lower than those expected following an emergency condition since the operator would initiate a boration quickly following the reactor trip to assure shutdown margin.
- c. The capability of the RCS to perform a natural circulation cooldown at a rate of approximately 50F/hr was demonstrated by all of these tests. This is at a higher rate than the Westinghouse emergency procedures (25F/hr).
- d. All plants demonstrated that no core temperature distribution anomalies were induced by the addition of boric acid into the RCS or the cooldown process while using natural circulation.
Since the tests at all plants successfully and conclusively demonstrated the capability of the plant to mix boric acid and cool down under natural circulation conditions, there would be no benefit from the Virgil C. Summer Nuclear Station performing this test.
5.5-29 Reformatted January 2016
- a. Commit to providing specific procedures for cooling down using natural circulation and submit a summary of these procedures.
Specific procedures for cooling down using natural circulation are provided in the Virgil C. Summer Nuclear Station "EOPs" which includes natural circulation cooldown with boron mixing. A summary of the procedures is provided in the cold shutdown scenario and single failure evaluation provided below.
- b. Provide a seismic Category 1 AFW supply for at least 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> at Hot Shutdown plus cooldown to the RHR system cut-in based on the longest time (for only onsite or offsite power and assuming the worst single failure), or show that an adequate alternate Seismic Category 1 source will be available.
Sufficient emergency feedwater is provided in the Seismic Category 1 condensate storage tank to permit 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of operation at hot standby plus cooldown to RHR initiation conditions. In addition, a long term source of Emergency Feedwater is provided by a connection to the Seismic Category 1 Service Water System. See the cold shutdown scenario and single failure evaluation provided below (Part II, Removal of Residual Heat).
- c. Provide for collection and containment of RHR pressure relief or show that adequate alternative methods of disposing of discharge are available.
The RHR relief valves discharge to the pressurizer relief tank located inside containment.
5.5.7.1.1.2 Cold Shutdown Scenario The safe shutdown design basis of Virgil C. Summer Nuclear Station is hot standby. The plant can be maintained in a safe hot standby condition while manual actions are taken to permit achievement of cold shutdown conditions following a safe shutdown earthquake with loss of offsite power. Under such conditions the plant is capable of achieving RHR initiation conditions (approximately 350F and less than 425 psia), including the time required for any manual actions. To achieve and maintain cold shutdown, 4 key functions must be performed. These are: (1) circulation of the reactor coolant, (2) removal of residual heat, (3) boration and makeup, and (4) depressurization.
- 1. Circulation of Reactor Coolant
Circulation of the reactor coolant has 2 stages in a cooldown from hot standby to cold shutdown. The first stage is from hot standby to 350F. During this stage, circulation of the reactor coolant is provided by natural circulation with the reactor core as the heat source and steam generators as the heat sink. Steam release from the steam generators is initially via the steam generator safety valves and 00-01 02-01 5.5-30 Reformatted January 2016 occurs automatically as a result of turbine and reactor trip. Steam release for cooldown is via the steam generator power operated relief valves. If air and control power are available, these valves will be operated from the main control board. A back-up air compressor can be manually loaded on the diesel generator busses. If these power sources are not available, communications will be established between the control room and auxiliary operators at the valves. These valves can be manually operated by handwheel. The steam generator power operated relief valves are easily accessible for local operation at floor level or by permanently installed platforms in the Seismic Category 1 penetration access area.
The ability to operate these valves locally by handwheel was verified in the plant hot functional testing program. As a result of the installed noise reduction features on the valve, noise levels were sufficiently low that plant personnel were able to communicate with the control room and operate the valves with no difficulty.
The status of each steam generator can be monitored using Class 1E instrumentation located in the control room. Separate indication channels for both steam generator pressure and water level are available.
Feedwater to the steam generators is provided from the Emergency Feedwater System which has a 500,000 gallon Seismic Category 1 condensate storage tank (160,054 usable gallons are reserved for emergency feedwater, see Section 9.2.6.1) as the primary source and 2 separate Seismic Category 1 piping sub-systems. The first sub-system is composed of 2 motor driven pumps each powered from a different emergency power train, and the second sub-system incorporates a turbine driven pump which can receive motive steam from either of 2 steam generators. Backup is from the Seismic Category 1 Service Water System. There are additional sources of feedwater backup which can be manually accessed. The operation of the Emergency Feedwater System can be monitored using Class 1E instrumentation located in the control room.
The second stage of reactor coolant circulation is from 350F to cold shutdown. During this stage, circulation of the reactor coolant is provided by the residual heat removal pumps.
- 2. Removal of Residual Heat
Removal of residual heat also has 2 stages in a cooldown from hot standby to cold shutdown. The first stage is from hot standby to 350 F.
During this stage, the steam generators act as the means of heat removal from the Reactor Coolant System. When the operators are ready to begin the cooldown, the steam generator power operated relief valves are opened slightly. As the cooldown proceeds, the operators will occasionally adjust these valves to increase the amount they are open. This allows a reasonable cooldown rate to be maintained. Feedwater makeup to the steam generators is provided from the Emergency Feedwater System. The Emergency Feedwater System has the ability 99-01 99-01 RN 10-014 5.5-31 Reformatted January 2016 to remove decay heat by providing feedwater to all 3 steam generators for extended periods of operation.
The second stage is from 350F to cold shutdown. During this stage, the Residual Heat Removal (RHR) System is brought into operation. The residual heat removal exchangers in the RHR system act as the means of heat removal from the Reactor Coolant System. In the RHR heat exchanger, the residual heat is transferred to the Component Cooling System which transfers the heat to the Service Water System. The Component Cooling and the Service Water Systems are both
designed to Seismic Category 1. The RHR System includes 2 residual heat removal pumps and 2 residual heat removal heat exchangers. Each RHR Pump is powered from different emergency power trains and each RHR heat exchanger is cooled by a different component cooling loop. If any component in one RHR loop becomes inoperable, cooldown of the plant is not compromised; however, the time for cooldown would be extended.
The operation of the RHR System can be monitored using Class 1E instrumentation in the control room.
- 3. Boration and Makeup
Boration is accomplished using portions of the Chemical and Volume Control System (CVCS). Boric acid 4 wt. % (approximately 7,000 ppm) from the boric acid tanks is supplied to the suction of the centrifugal charging pumps by the boric acid transfer pumps. The centrifugal charging pumps inject the borated water into the Reactor Coolant System via the normal charging and/or reactor coolant pump seal injection flow paths. The 2 boric acid tanks, 2 boric acid transfer pumps, centrifugal charging pumps, and the associated piping are of Seismic Category 1 design. There is sufficient boric acid capacity to provide for a cold shutdown with
the most reactive rod withdrawn. The boric acid transfer pumps are each powered from different emergency power trains. The boric acid tank level can be monitored using Class 1E instrumentation in the control room to verify the operability of the boration portion of the CVCS.
Makeup, in excess of that required for boration, can be provided from the refueling water storage tank (RWST) using centrifugal charging pumps and the same injection flow paths as described for boration. Two (2) motor operated valves, each powered from different emergency power trains and connected in parallel, will transfer the suction of the charging pumps to the RWST. Makeup from the RWST can be monitored using Class 1E instrumentation in the control room.
- 4. Depressurization
Depressurization is normally accomplished using the reactor coolant pumps and the normal spray lines to the pressurizer.
RN 99-110 5.5-32 Reformatted January 2016 Depressurization can be accomplished using the pressurizer power operated relief valves after boration and RCS cooldown to 450F. This method consists of (1) discharging reactor coolant from the pressurizer to the pressurizer relief tank via the pressurizer power operated relief valves, and (2) allowing the pressurizer to cool via ambient heat losses as the Reactor Coolant System is maintained at 350F via natural circulation.
- 5. Maintaining RCS Temperature and Pressure Without Letdown
Letdown is isolated by fail closed air operated valves and is assumed to be unavailable during accident conditions. The cold shutdown scenario of maintaining RCS temperature and pressure without letdown is considered the limiting cold shutdown scenario and is presented to demonstrate cold shutdown capability under abnormal conditions. As additional components are assumed to be available, the cold shutdown scenario is simplified. For example, as the reactor vessel head vent valves or the pressurizer PORVs are assumed to be available, the boration and makeup function or the depressurization function, respectively, is simplified as RCS letdown becomes available.
In performing the cooldown, the operator will integrate the functions of heat removal, boration and makeup, and depressurization so that these functions can be accomplished without letdown from the Reactor Coolant System. Boration, cooldown, and depressurization will be accomplished in a series of short steps arranged to keep Reactor Coolant System temperature and pressure and pressurizer level in the desired relationships. The boration requirements will be evaluated by the operator prior to initiating cooldown and depressurization. Based on initial plant conditions, the operator and/or the contents of the boric acid tanks. Once the plant is cooled to 350F and depressurized to 425 psia, Residual Heat Removal System operation is initiated and the Reactor Coolant System is taken to cold shutdown conditions.
To demonstrate that boration and depressurization can be done without letdown, a simpler scenario can be used. First the operators integrate the cooldown and boration functions taking advantage of the RCS inventory contraction resulting from the cooldown. Finally, the operators use auxiliary spray from the CVCS to depressurize the plant to RHRS initiating conditions. The SCE&G calculation to demonstrate this capability assumes worst case boration requirements based on core end of life/peak xenon conditions and the following RCS initial conditions following plant trip:
RCS Temperature 557 F RCS Pressure 2250 psia Pressurizer Water Volume 350 ft 3 Pressurizer Steam Volume 1050 ft 3 02-01 02-01 5.5-33 Reformatted January 2016 The cooldown from 557F to 350F decreases the volume of water in the RCS by approximately 1420 cubic feet. This assumes that the pressurizer is not cooled and the water level is maintained at the initial condition. Makeup for contraction is supplied by 4 wt. % boric acid stored in the boric acid tanks at 70F. A boric acid tank volume of approximately 1170 cubic feet is required to maintain the reactor within the technical specification shutdown requirements at 350F. A boric acid tank volume of approximately 1170 cubic feet will expand to approximately 1310 cubic feet as it is heated to the RCS temperature of 350F. The volume required for boration requirements at 350F is less than the contraction volume available at 350 F. To calculate if depressurization can be accomplished without letdown and without taking the plant water solid, it was assumed that the pressurizer was at saturated conditions with 350 cubic feet of water, 1050 cubic feet of steam, and the pressurizer metal at 653F (2250 psia). It was further assumed that no additional water would be removed from the pressurizer by the cooldown contraction. With these assumptions, including the effect of heat input from the pressurizer metal, it was determined that spraying in approximately 450 cubic feet of 70F water would provide saturated conditions at 425 psia (450F) with a water volume of 913 cubic feet and a steam volume of 487 cubic feet.
Once depressurized to 425 psia, RHRS operation is initiated and cooldown is continued to cold shutdown conditions. The cooldown from 350F to 200F further decreases the volume of water in the RCS. This assumes that the pressurizer is not cooled and the pressurizer water level is maintained at the level resulting from depressurization. There is no additional boration required in going from Mode 4 (350F) to Mode 5 (200F). This is expected since the shutdown margin requirements are less restrictive in Mode 5 than in Mode 4.
The results of the calculations described above demonstrate that, based on the assumed initial conditions, boration and depressurization with 4 wt. %
(approximately 7,000 ppm) boric acid can be accomplished without letdown and without taking full credit for the available volume created by the cooldown contraction. Should boration without letdown prove impractical due to any combination of plant conditions or equipment failures, letdown can be achieved by discharging RCS inventory via the pressurizer power operated relief valves or the reactor vessel head vent valves.
02-01 02-01 02-01 02-01 02-01 RN 99-110 5.5-34 Reformatted January 2016
- 6. Instrumentation Class 1E instrumentation is available in the control room to monitor the key functions associated with achieving cold shutdown. This instrumentation is discussed in Section 7.5 (Safety Related Display Instrumentation) and includes the following:
- a. RCS wide range temperature
- b. RCS wide range pressure
- c. Pressurizer water level
- d. Steam generator water level (per steam generator)
- e. Steam line pressure (per steam line)
- f. RWST level
- g. Boric acid tank level (per boric acid tank)
- h. Reactor building pressure
This instrumentation is sufficient to monitor the key functions associated with cold shutdown and to maintain the RCS within the desired pressure, temperature, and inventory relationships. Operation of the auxiliary systems that service the RCS can be monitored by the control room operator, if desired, via remote communication with an operator in the plant.
5.5.7.1.1.3 Single Failure Evaluation
- 1. Circulation of the Reactor Coolant
- a. From Hot Standby to 350F (Refer to FSAR Figures 5.1-1, 10.3-1, and 10.3-4) - Three (3) reactor coolant loops and steam generators are provided, any 2 of which can provide sufficient natural circulation flow to provide adequate core cooling. Even with the most limiting single failure (of a steam generator power operated relief valve), 2 of the reactor coolant loops and steam generators remain available.
- b. From 350F to cold shutdown (Refer to FSAR Tables 5.5-7, 5.5-8, and Figure 5.5-4); 2 RHR pumps are provided, either 1 of which can provide adequate circulation of the reactor coolant.
5.5-35 Reformatted January 2016
- 2. Removal of Residual Heat
- a. From Hot Standby to 350F [Refer to FSAR Figures 10.3-1, 10.3-4, 10.4-16, 9.2-2 (Sheets 1 through 4), and 9.2-3]. (1) Steam generator power operated relief valves - Three (3) are provided (1 per steam generator), any 2 of which are sufficient for residual heat removal. In the event of a single failure, 2 power operated relief valves remain available.
(2) Emergency feedwater pumps - Two (2) motor driven and 1 steam driven emergency feedwater pumps are provided. In the event of a single failure, 2 pumps remain available, either of which can provide sufficient feedwater flow.
(3) Flow control valves - Air operated, fail open valves are provided. In the event of a single failure of 1 flow control valve (which effects flow to 1 steam generator from either a motor driven pump or the steam driven pump), emergency feed flow can still be provided to all 3 steam generators from the other pumps.
(4) Backup source - A backup source of emergency feedwater can be provided to the suction of the emergency feedwater pumps from either train of the Seismic Category 1 Service Water System.
- b. From 350F to 200 F [Refer to FSAR Table 5.5-15 and Figure 5.5-4, and Figures 9.2-1, 9.2-2 (Sheets 1 through 4), 9.2-3, and 9.2-4].
(1) RHR Suction Isolation Valves 8701A and 8702A (RHR Pump 1) and 8701B and 8702B (RHR Pump 2) - The 2 valves in each RHR subsystem are each powered from different emergency power trains.
Failure of either power train could prevent initiation of RHR cooling in the normal manner from the control room. In the event of such a failure, the affected valve can be de-energized and opened with its handwheel.
Another method of operating these valves is by the use of alternate temporary power. Any other single failure can be tolerated as it would only affect one of the RHR subsystems, and adequate cooling can be provided by the redundant subsystem.
(2) RHR pumps 1 and 2 - Each pump is powered from a different emergency power train. In the event of a single failure, either pump can provide sufficient RHR flow.
RN 09-002 RN 09-002 5.5-36 Reformatted January 2016 (3) RHR heat exchangers 1 and 2 - If either heat exchanger is unavailable for any reason, the remaining heat exchanger is unavailable for any reason, the remaining heat exchanger can provide sufficient heat removal capability.
(4) RHR Flow Control Valves HCV603A and B - If either of these normally open fail open valves closes spuriously, sufficient RHR cooling can be provided by the unaffected RHR train.
(5) RHR/SIS Cold Leg Isolation Valves 8888A and B - If either of these normally open, motor operated valves, which are powered from different emergency power trains, closes spuriously, sufficient RHR cooling can be provided by the unaffected RHR train. The affected valve can be de-energized and opened with its handwheel.
(6) Component Cooling Water System - Two (2) redundant subsystems are provided for safety related loads. Either subsystem can provide sufficient heat removal via one of the RHR heat exchangers.
(7) Service Water System - Two (2) redundant subsystems are provided for safety related loads. Either subsystem can provide sufficient heat removal via 1 of the CCW heat exchangers.
- 3. Boration and Makeup (Refer to FSAR Figures 5.1-1, 6.3-1, and 9.3-16)
- a. Boric Acid Tanks 1 and 2 - Two (2) boric acid tanks are provided. Each tank contains sufficient 4% (approximately 7,000 ppm) boric acid to borate the Reactor Coolant System for cold shutdown.
- b. Boric Acid Transfer Pumps 1 and 2 - Each pump is powered from a different emergency power train. In the event of a single failure, either pump can provide sufficient boric acid flow.
- c. Isolation Valve 8104 - If valve 8104, which is supplied from emergency power and is normally closed, cannot be opened due to power train or operator failure, it can be opened locally with its handwheel. If valve 8104 cannot be opened with its handwheel, an alternate flow path is available via a) air operated, fail open valve FCV-113A and normally closed manual valve 8439, or b) gravity feed through normally closed manual valves 8329 and 8331.
- d. Refueling Water Storage Tank Isolation Valves LCV-115B and LCV-115D - Each valve is powered from a different emergency power train, only one of these normally closed motor operated valves needs to be opened to provide a makeup flow path from the RWST to the centrifugal charging pumps.
RN 99-110 5.5-37 Reformatted January 2016
- e. Centrifugal Charging Pumps A, B, and C - Pumps A and B are powered fro m a different emergency power train. In the event of a single failure, any 1 pump can provide sufficient boration or makeup flow.
- f. Charging Pump Suction Isolation Valves 8130A, B and 8131A, B - If 1 of these normally open motor operated valves
--each of which is powered from a different emergency power train
--closes spuriously, operator action can be used to de-energize the valve operator and reopen the valve with its handwheel.
- g. Normal Charging Flow Control Valve FCV-122 - This normally open valve fails open on loss of air or power. If FCV-122 closes spuriously, the charging pumps can operate on their miniflow circuits until operator action can open bypass valve 8403.
- h. Normal Charging Isolation Valves 8107 and 8108 - If either of these normally open, motor operated valves
--each of which is powered from a different emergency power train
-- closes spuriously, operator action can be used to de-energize the valve operator and reopen the valve with its handwheel.
- i. Normal Charging Isolation Valve 8146 - If the normally open valve closes spuriously, alternate charging valve 8147, which fails open, can be used.
- j. Charging Pump Discharge Isolation Valves 8132 A, B, and 8133 A, B - If 1 of these normally open motor operated valves
--each of which is powered from a different emergency power train
--closes spuriously, operator action can be used to de-energize the valve operator and reopen the valve with its handwheel. Power to valves 8133A, B is normally locked out to prevent spurious operation. Reference FSAR Section 6.3.2.20.
- k. Reactor Coolant Pump Seal Injection Isolation Valve 8105 - If this normally open motor operated valve closes spuriously, operator action can be used to
de-energize the valve operator and reopen the valve with its handwheel (also see item p.).
- l. Reactor Coolant Pump Seal Injection Flow Control Valve HCV-186 - This normally open valve fails open on loss of air or power. If HCV-186 closes spuriously, the charging pumps can operate on their miniflow circuits until operator action can open bypass valve 8389 (also see item p.).
- m. Reactor Coolant Pump Seal Injection Valves 8102 A, B, and C - If any of these normally open motor operated valves closes spuriously, operator action can be used to de-energize the valve operator and reopen the valve with its handwheel.
98-01 RN 11-039 RN 11-027 RN 11-027 5.5-38 Reformatted January 2016
- n. Cold Leg Injection Isolation Valves 8801 A and B - Each valve is powered from a different emergency power train; only 1 of these normally closed motor operated valves needs to be opened to provide a makeup path and source for boration.
- o. Reactor Vessel Head Vent Valves 8095 A, B, and 8096 A, B - These valves fail as-is on loss of power. They are arranged with 2 valves in series in each of 2 parallel paths. The isolation valves in series in each flow path are powered from separate emergency power supplies. One (1) normally closed isolation valve and 1 normally open valve are located in each flow path. This valving and power supply arrangement ensures that 1 path from the reactor vessel head can be opened assuming a single failure. One (1) path is sufficient to permit letdown from the Reactor Coolant System to augment boration and makeup operations.
20 gpm RWST water downstream of HCV-186 and XVT-8105. The ASI system is an ASME Code Class 2 system (pressure boundary); however, the power source for the ASI pump (XPP0230) is from an NNS power supply.
- 4. Depressurization (Refer to FSAR Figure 9.3-16)
- a. Pressurizer Power Operated Relief Valves PCV-444B and PCV-445A - These normally closed valves fail closed on loss of air or power. However, the valves are redundant, are powered by separate emergency electrical power supplies, and have backup seismic category air supply accumulators. The operability of either valve is sufficient to permit depressurization.
- 5. Instrumentation
Sufficient instrumentation is provided to monitor from the control room the key function associated with cold shutdown. All necessary indications are redundant.
Thus, in the event of a single failure, the operator can make comparisons between duplicate information channels or between functionally related channels in order to identify the particular malfunction. Refer to FSAR Section 7.5 (Safety Related Display Instrumentation) for applicable details.
RN 11-027 5.5-39 Reformatted January 2016
- 6. Qualification The equipment discussed in the cold shutdown scenario is safety grade with the following exceptions. These are few in number and of such a nature that local manual actions and/or equipment repair could be performed while the plant is maintained in the hot standby condition while preparations are made to go to cold shutdown. These manual actions would not prevent the plant from achieving residual heat removal system initiations within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.
- a. Steam generator power operated relief valves - These air operated valves are provided with safety grade remote operators; however, remote control provisions are control grade. Hot standby can be achieved and maintained using the safety grade steam generator safety valves. The steam generator power operated relief valves are provided with handwheels which can be operated locally to permit plant cooldown.
- b. Charging line isolation valves (8146, 8147), Charging line auxiliary spray valve (8145) - Seal injection line hand control valve (HCV-186). Charging line flow control valve (FCV-122).
These air operated valves are not provided with safety grade remote operators, air supplies, or power supplies. Their failure consequences were discussed in the Parts 3 and 4 of the single failure evaluation.
- c. Residual Heat Removal System Flow Control Valve HCV-603 A/B - This air operated valve is not provided with a safety grade remote operator, air supply, or power supply. Its failure consequence was discussed in Part 2 of the single failure evaluation.
- d. Pressurizer relief tank - This tank is a non-nuclear safety class and non-Seismic Category 1 tank. Its failure does not affect the ability of the Virgil C. Summer Nuclear Station to achieve cold shutdown.
- e. Pressurizer power operated relief valves - These air operated valves are not supplied with safety grade remote operators; however, they are powered from separate vital DC electrical power supplies and 2 of them have Seismic Category 1 air supply accumulators. These valves are discussed in Part 4 of the cold shutdown scenario.
5.5.7.1.1.4 Natural Circulation The natural circulation capabilities of the Virgil C. Summer Nuclear Station are compared with 3 and 4 loop test results in Section 5.5.7.1.1, Item 5.
RN 98-020 5.5-40 Reformatted January 2016 5.5.7.2 System Description The RHRS, as shown in Figure 5.5-4 consists of 2 residual heat exchangers, 2 residual heat removal pumps, and the associated piping, valves, and instrumentation necessary for operational control. The inlet lines to the RHRS are connected to the hot legs of 2 reactor coolant loops, while the return lines are connected to each of the cold legs and to 2 hot legs of the reactor coolant loops. These return lines are also the ECCS low head cold leg injection/recirculation lines and the hot leg recirculation lines (see Figure 6.3-1).
The RHRS suction lines are isolated from the RCS by 2 motor operated valves in series and a relief valve, all located inside the Reactor Building. Each discharge line is isolated from the RCS by 2 check valves located inside the Reactor Building and by a motor operated valve located outside the Reactor Building. (The check valves and the motor operated valve on each discharge line are not shown as part of the RHRS; these valves are shown as part of the ECCS, see Figure 6.3-1.)
During RHRS operation, reactor coolant flows from the RCS to the residual heat removal pumps, through the tube side of the residual heat exchangers, and back to the RCS. The heat is transferred to the component cooling water circulating through the shell side of the residual heat exchangers.
Coincident with operation of the RHRS, a portion of the reactor coolant flow may be diverted from downstream of the residual heat exchangers to the Chemical and Volume Control System (CVCS) low pressure letdown line for cleanup and/or pressure control.
By regulating the diverted flowrate and the charging flow, the RCS pressure may be controlled. Pressure regulation is necessary to maintain the pressure range dictated by the fracture prevention criteria requirements of the reactor vessel and by the number 1 seal differential pressure and net positive suction head requirements of the reactor coolant pumps.
The RCS cooldown rate is manually controlled by regulating the reactor coolant flow through the tube side of the residual heat exchangers. A line containing a flow control valve bypasses each residual heat exchanger and is used to maintain a constant return flow to the RCS. Instrumentation is provided to monitor system pressure, temperature and total flow.
The RHRS is also used for filling the refueling cavity before refueling. After refueling operations, water is pumped back to the refueling water storage tank until the water level is brought down to the flange of the reactor vessel. The remainder of the water is removed via a drain connection at the bottom of the refueling cavity.
When the RHRS is in operation, the water chemistry is the same as that of the reactor coolant. Provision is made for the process sampling system to extract samples from the flow of reactor coolant downstream of the residual heat exchangers. A local sampling point is also provided on each residual heat removal train between the pump and heat exchanger.
99-01 5.5-41 Reformatted January 2016 The RHRS functions in conjunction with the high head portion of the ECCS to provide injection of borated water from the refueling water storage tank into the RCS cold legs during the injection phase following a loss of coolant accident.
In its capacity as the low head portion of the ECCS, the RHRS provides long term recirculation capability for core cooling following the injection phase of the loss of coolant accident. This function is accomplished by aligning the RHRS to take fluid from the reactor building sump, cool it by circulation through the residual heat exchangers, and supply it to the core directly as well as via the centrifugal charging pumps.
The use of the RHRS as part of the ECCS is more completely described in Section 6.3.
5.5.7.2.1 Component Description The materials used to fabricate RHRS components are in accordance with the applicable code requirements. All parts of components in contact with borated water are fabricated or clad with austenitic stainless steel or equivalent corrosion resistant material.
Portions of the system that are designed to carry E CCS fluid outside containment during the recirculation phase of E CCS operation are designed to minimize leakage to the atmosphere as described in Section 6.3.2.11.3.
Component codes and classifications are given in Section 3.2 and component parameters are listed in Table 5.5-
- 8. 5.5.7.2.1.1 Residual Heat Removal Pumps Two (2) pumps are installed in the RHRS. The pumps are sized to deliver reactor coolant flow through the residual heat exchangers to meet the plant cooldown requirements. The use of 2 separate residual heat removal trains assures that cooling capacity is adequately maintained should 1 pump become inoperative.
The residual heat removal pumps are protected from overheating and loss of suction flow by minimum flow bypass lines that assure flow to the pump suction. A valve located in each minimum flow line is regulated by a signal from the flow switch located in each heat exchanger discharge header. The control valves open when RHR discharge flow to the RCS reaches the minimum flow setpoint, which is set to prevent RHR pump flow from approaching the minimum design flow of 500 gpm. The control valves close when flow reaches the close setpoint at nearly the maximum range of the flow switch, or approximately 1500 gpm.
A pressure sensor in each pump discharge header provides a signal for an indicator in the control room. A high pressure alarm is also actuated by the pressure sensor. The 2 pumps are vertical, centrifugal units with mechanical seals on the shafts. All pump surfaces in contact with reactor coolant are austenitic stainless steel or equivalent corrosion resistant material.
RN 03-047 RN 04-005 5.5-42 Reformatted January 2016 5.5.7.2.1.2 Residual Heat Exchangers Two (2) residual heat exchangers are installed in the system. The heat exchanger design is based on heat load and temperature differences between reactor coolant and component cooling water existing at 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> after reactor shutdown from an extended full power run at 2775 MWt when the temperature difference between the 2 systems is small. For the current licensed RTP of 2900 MWt, the corresponding decay heat level occurs at 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after reactor shutdown.
The installation of 2 heat exchangers in separate and independent residual heat removal trains assures that the heat removal capacity of the system is adequately maintained if 1 train becomes inoperative.
The residual heat exchangers are of the shell and U-tube type. Reactor coolant circulates through the tubes, while component cooling water circulates through the shell.
The tubes are welded to the tubesheet to prevent leakage of reactor coolant.
5.5.7.2.1.3 Residual Heat Removal System Valves Valves that perform a modulating function are equipped with 2 sets of packings and an intermediate leakoff connection that discharges to the drain header.
Manual and motor operated valves have backseats to facilitate repacking and to limit stem leakage when the valves are open. Leakage connections are provided where required by valve size and fluid conditions.
5.5.7.2.2 System Operation 5.5.7.2.2.1 Reactor Startup Generally, while at cold shutdown condition, decay heat from the reactor core is being removed by the RHRS. The number of pumps and heat exchangers in service depends upon the heat load at the tim
- e.
At initiation of the plant startup, the RCS is completely filled, and the pressurizer heaters are energized. The RHRS is operating and is connected to the CVCS via the low pressure letdown line to control reactor coolant pressure. During this time, the RHRS acts as an alternate letdown path. The manual valves downstream of the residual heat exchangers leading to the letdown line of the CVCS are opened. The control valve in the line from the RHRS to the letdown line of the CVCS is then manually adjusted in the control room to permit letdown flow. Failure of any of the valves in the line from the RHRS to the CVCS has no safety implications, either during startup or cooldown.
5.5-43 Reformatted January 2016 After the reactor coolant pumps are started, the residual heat removal pumps are stopped but pressure control via the RHRS and the low pressure letdown line is continued until the pressurizer steam bubble is formed. Indication of steam bubble formation is provided in the control room by the damping out of the RCS pressure fluctuations, and by pressurizer level indication. The RHRS is then isolated from the RCS and the system pressure is controlled by normal letdown and the pressurizer spray and pressurizer heaters.
5.5.7.2.2.2 Power Generation and Hot Standby Operation During power generation and hot standby operation, the RHRS is not in service but is aligned for operation as part of the ECCS.
5.5.7.2.2.3 Reactor Cooldown Reactor cooldown is defined as the operation which brings the reactor from no-load temperature and pressure to cold shutdown conditions.
The initial phase of reactor cooldown is accomplished by transferring heat from the RCS to the steam and power conversion system through the use of the steam generators.
When the reactor coolant temperature and pressure are reduced to approximately 350F and less than 425 psig, approximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after reactor shutdown, the second phase of cooldown starts with the RHRS being placed in operation. It should be noted that given the decay heat models and the RCP heat assumed, the RHRS system, under worst case design conditions, cannot begin to cooldown the RCS until approximately 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> after an extended full power run at the current licensed RTP of 2900 MWt (although, it can be placed into service in parallel with the steam dump system at approximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after reactor shutdown). Plant procedures do verify that heat removal occurs via RHRS before fully transferring from the steam dump system.
Startup of the RHRS includes a warmup period during which time reactor coolant flow through the heat exchangers is limited to minimize thermal shock. The rate of heat removal from the reactor coolant is manually controlled by regulating the coolant flow through the residual heat exchangers. By adjusting the control valves downstream of the residual heat exchangers the mixed mean temperature of the return flows is controlled. Coincident with the manual adjustment, each heat exchanger bypass valve is regulated to give the required total flow.
The reactor cooldown rate is limited by RCS equipment cooling rates based on allowable stress limits, as well as the operating temperature limits of the CCWS. As the reactor coolant temperature decreases, the reactor coolant flow through the residual
he tube side outlet line.
02-01 02-01 5.5-44 Reformatted January 2016 Assuming that only 1 heat exchanger and pump are in service and that the heat exchanger is supplied with component cooling water at design flow and at a temperature not exceeding 120F, the coupled RHRS/CCWS/SWS system is capable of reducing the RCS temperature from 350F at 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> after shutdown from an extended full power run at the current licensed RTP of 2900 MWt to 200F within 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> from the beginning of the cooldown. The RHRS heat load during the transient includes the heat from one RCP, core decay heat, and the sensible heat of the RCS metal and fluid.
As cooldown continues, the pressurizer is filled with water and the RCS is operated in the water solid condition.
At this stage, pressure control is accomplished by regulating the charging flowrate and the rate of letdown from the RHRS to the CVCS.
After the reactor coolant pressure is reduced and the temperature is 140F or lower, the RCS may be opened for refueling or maintenance once the remaining shutdown operations are considered complete.
5.5.7.2.2.4 Refueling Both residual heat removal pumps are utilized during refueling to pump borated water from the refueling water storage tank to the refueling cavity. During this operation, the isolation valves in the inlet lines of the RHRS are closed, and the isolation valves from the refueling water storage tank are opened.
Station operating procedures include instructions for draining the Reactor Coolant System for vessel head removal prior to refueling operations. The instruction includes the installation of clear hose between 1 of the Reactor Coolant System loop drains and the pressurizer relief line vent to provide level indication after the pressurizer level indication is off scale. The procedure also states that after the Reactor Coolant System level has reached 4 to 12 inches below the reactor vessel flange, draining operations are secured. These actions insure that air will not be introduced into the RHR System via the Reactor Coolant System during refueling operations.
The reactor vessel head is lifted. The refueling water is then pumped into the reactor vessel through the normal RHRS return lines and into the refueling cavity through the open reactor vessel. After the water level reaches the normal refueling level, the refueling water storage tank supply valves are closed, the inlet isolation valves are opened, and residual heat removal is resumed.
During refueling, the RHRS is maintained in service with the number of pumps and heat exchangers in operation as required by the heat load.
Following refueling, the residual heat removal pumps are used to drain the refueling cavity to the top of the reactor vessel flange by pumping water from the RCS to the refueling water storage tank.
RN 14-018 5.5-45 Reformatted January 2016 5.5.7.3 Design Evaluation 5.5.7.3.1 System Availability and Reliability General Design Criterion 34 requires that a system to remove residual heat be provided. The safety function of this system is to transfer fission product decay heat and other residual heat from the core at a rate sufficient to prevent fuel or pressure boundary design limits from being exceeded. Safety grade systems are provided in the plant design to perform this safety function. The NSSS safety grade systems which perform this function, for all plant conditions except a LOCA, are: the RCS and steam generators, which operate in conjunction with the Emergency Feedwater System, and the steam generator safety valves; and the RHRS which operates in conjunction with the reactor plant Component Cooling Water System and the Service Water System. The BOP safety grade systems which perform this function, for all plant conditions except LOCA, are: the Emergency Feedwater System, the steam generator safety valves, which operate in conjunction with the Reactor Coolant System and the steam generators; and the reactor plant Component Cooling Water and Service Water Systems, which operate in conjunction with the RHRS. For LOCA conditions, the safety grade system which performs the function of removing residual heat from the reactor core is the ECCS, which operates in conjunction with the reactor plant Component Cooling Water System and the Service Water System.
The Emergency Feedwater System, along with the steam generator safety valves provides a completely separate, independent, and diverse means of performing the safety function of removing residual heat, which is normally performed by the RHRS when RCS temperature is less than 350F. The Emergency Feedwater System is capable of performing this function for an extended period of time following plant shutdown.
The RHRS is provided with 2 residual heat removal pumps, and 2 residual heat removal heat exchangers arranged in 2 separate, independent flow paths. To assure reliability, each residual heat removal pump is connected to a different vital bus. Each residual heat removal train is isolated from the RCS on the suction side by 2 motor operated valves in series. Each motor operated valve receives power via a separate motor control center and the 2 valves in series in each train receive their power from a different vital bus. Each suction isolation valve is also independently and diversely interlocked to 1 of 2 RCS wide range pressure instruments to prevent opening the valves when the RCS pressure is above 425 psig. Independence is accomplished by aligning each RCS wide range pressure transmitter to a different vital bus. Diversity is accomplished through the use of 2 RCS wide range pressure instruments which employ different pressure sensing principals.
Also, at strategically identified local high points, the RHRS is provided with indicating air-traps to ensure the RHRS remains void free (reference NRC GL 20 08-01). RN 09-003 5.5-46 Reformatted January 2016 RHRS operation for normal conditions is accomplished from the control room. The redundancy in the RHRS design provides the system with the capability to maintain its cooling function even with major single failures, such as failure of an RHR pump, valve, or heat exchanger since the redundant train can be used for continued heat removal.
See Table 5.5-15 for a single active failure analysis of the RHRS.
Although such major system failures are within the system design basis, there are other less significant failures which can prevent opening of the RHR suction isolation valves from the control room. Since these failures are of a minor nature, improbable to occur, and easily corrected outside the control room, with ample time to do so, they have been realistically excluded from the engineering design basis. Such failures are not likely to occur during the limited time period in which they can have any effect (i.e., when opening the suction isolation valves to initiate RHR operation); however, even if they should occur, they have no adverse safety impact and can be readily corrected. In such a situation, the emergency feedwater system and steam generator safety valves can be used to perform the safety function of removing residual heat and can be used to continue the plant cooldown below 350F, until the RHR system is made available.
One (1) failure which can prevent opening the RHR suction isolation valves from the control room is a failure of an electrical power train. Such a failure is extremely unlikely to occur during the few minutes per year operating time, during which it can have any consequence. If such an unlikely event should occur, several alternatives are available.
The most realistic approach would be to obtain restoration of offsite power, which can be expected to occur in less than 1/2 hour. Other alternatives are to restore the emergency diesel generator to operation, to bring in an alternate power source, or to open the affected valves with their manual handwheels.
The only impact of either of the above types of failure is some delay in initiating RHR operation, while action is taken to open the RHR suction isolation valves. This delay has no adverse safety impact because of the capability of the emergency feedwater system and steam generator safety relief valves to continue to remove residual heat.
The safe shutdown design basis of the Virgil C. Summer Nuclear Station is hot standby, as it is for all other Westinghouse designed pressurized water reactors. Hot standby is a safe and stable plant condition which can be maintained for an extended period of time following any Condition II, III, or IV event. In the hot standby condition, residual heat removal, in compliance with GDC 34, is provided by the Emergency Feedwater System in conjunction with the steam generator safety valves. Cross connections from the Service Water System to the Emergency Feedwater System provide a long term (i.e., greater than 7 days) source of emergency feedwater.
98-01 5.5-47 Reformatted January 2016 In view of the above described capability, the Residual Heat Removal (RHR) System is not required to fully comply with the single failure requirement of GDC 34. For most major single failures, the RHR System does fully comply with the single failure criterion.
The only situation where full compliance is not provided is for opening the RHR suction isolation valves (to initiate RHR cooling) in the event of the failure of 1 of the safeguards power trains. In the event of such a failure, sufficient time is available to either compensate for the single failure by manual actions inside (i.e., by opening a suction valve with its manual handwheel) or outside (by providing an alternate temporary power supply to a suction valve) the containment or to restore the failed safeguards power train to operation.
See Section 5.5.7.1.1 for compliance with BTP RSB 5-
- 1. The maximum cooldown rate which can result if both RHR flow control valves and both RHR bypass valves all simultaneously fail in such a manner as to permit maximum flow through the RHR heat exchangers (a low probability event considering the few hours a year when it could cause any effect) depends on several factors including the RHR flow rate, the Component Cooling Water System flow rates and temperatures, and other heat loads on the Component Cooling Water System. One (1) of the key factors is the RCS temperature, since the heat removal rate depends on the temperature differential between the RHR (RCS) flow and the component cooling water flow in the RHR heat exchanger. Typically, it is impossible to maintain a cooldown rate even as high as the design rate of 50F/hr when the RCS temperature is less than 250F, even with the maximum flow through the RHR heat exchangers.
Even if maximum flow through the RHR heat exchangers was experienced at the instant of initiating RHR operation and no operator action was taken, it is unlikely that the cooldown would exceed 100F in the first hour. The cool down rate in the subsequent hours would be much less than 100F/hr. The maximum possible cooldown rate from 350F to 250F would not exceed 200F/hr. Calculations have been done which show that, from a stress standpoint, a cooldown rate greater than 200F/hr is acceptable for such a hypothetical cooldown from 350F to 250F even though, as discussed above, the actual maximum rate of cooldown at or below 250F is not expected to exceed 50F/hr.
Although such a hypothetical cooldown event is acceptable assuming no operator action, it should be noted that the operator can significantly limit the maximum possible cooldown rate by merely stopping one of the RHR pumps.
5.5.7.3.2 Leakage Provisions and Activity Release In the event of a loss of coolant accident or during normal recirculation mode, radioactive fluid may be recirculated through part of the RHRS exterior to the reactor building. If the residual heat removal pump seal should fail, the water would spill out on a floor in a shielded compartment. Each residual heat removal pump compartment contains a sump which is equipped with an alarm system set to indicate leakage of 5.5-48 Reformatted January 2016 greater than 45 gpm. The alarm system is annunciated in the control room so the operator can determine the location of the leak. Redundant sump pumps are capable of handling leakage flows up to 50 gpm each. In the case of failure of both sump pumps, each residual heat removal pump room has a water tight volume of at least 200 ft 3 to accommodate a 50 gpm leak for at least 30 minutes. This provides protection against pump flooding in the event of a 50 gpm leak. Any leakage, whether handled by the residual heat removal pump room sumps or the Auxiliary Building sump pumps, is directed to holdup tanks in the liquid waste processing system. Residual heat removal piping and pumps in each cubicle can be remotely isolated by motor operated valves so they can be drained and flushed prior to being repaired.
The maximum discharge rate from a moderate energy pipe crack in the RHR system is approximately 714 gpm.
Since such a leak rate would have no effect on core cooling until it resulted in emptying the RCS loops, the time available to the operator to take action is at least 73 minutes.
The operator would be alerted to the leak by decreasing pressurizer level and the pressurizer low level alarm. Depending on the location of the crack, the operator could also be alerted by RHR pump compartment sump level alarms. The only action necessary to recover from the event is to close the suction isolation valve(s) of the affected RHR train and to initiate cooling on the other RHR train, if it is not already operating. Depending on the amount of water lost before isolating the leak, the operator may be required to makeup to the RCS.
5.5.7.3.3 Overpressurization Protection Each inlet line to the RHRS is equipped with a pressure relief valve which protects the system from inadvertent overpressurization during plant cooldown or startup. Each valve has a relief flow capacity of 900 gpm at a set pressure of 450 psig. Analyses have been conducted to confirm the capability of the RHRS relief valve to prevent overpressurization of the RHRS. All credible events were examined for their potential to overpressurize the RHRS. These events included normal operating conditions, infrequent transients, and abnormal occurrences. The analyses confirmed that 1 relief valve has the capability to keep the RHRS maximum pressure within 10CFR50 Appendix G limits.
Each discharge line from the RHRS to the RCS is equipped with a pressure relief valve to relieve the maximum possible back-leakage through the valves separating the RHRS from the RCS. Each valve has a relief flow capacity of 20 gpm at a set pressure of 600 psig. These relief valves are located in the ECCS (see Figure 6.3-1).
The fluid discharged by the suction side relief valves is collected in the pressurizer relief tank. The fluid discharged by the discharge side relief valves is collected in the recycle holdup tanks of the boron recycle system.
02-0 1 02-01 5.5-49 Reformatted January 2016 5.5.7.3.4 Prevention of Exposure of the RHRS to Normal RCS Operating Pressure The design of the RHRS includes 2 motor-operated gate isolation valves in series on each inlet line between the high pressure RCS and the lower pressure RHRS. They are closed during normal operation and are only opened for residual heat removal and RCS cold overpressure protection during a plant cooldown after the RCS pressure is reduced to less than 425 psig and the RCS temperature is reduced to approximately 350 F. During a plant startup, the inlet isolation valves are shut after drawing a bubble in the pressurizer and prior to increasing RCS pressure above 425 psig. Power to th e isolation valves is manually locked out during normal operation.
The 2 inlet isolation valves in each residual heat removal subsystem are independently and diversely interlocked with pressure signals to prevent their being opened whenever the RCS pressure is greater than approximately 425 psig. The autoclosure interlock of these valves has been removed as per WCAP-11835. An alarm has been added to alert the operator if the valves are not closed when the RCS pressure increases above the alarm setpoint of 520 psig.
The use of 2 independently powered motor-operated valves in each of the 2 inlet lines, along with an independent and diverse pressure interlock to prevent them from being opened, and a RCS pressure high with RHR suction valves not closed alarm assures a design which meets applicable single failure criteria. Not only more than one single failure, but also different failure mechanisms, must be postulated to defeat the function of preventing possible exposure of the RHR system to normal RCS operating pressure.
This protective interlock design, in combination with alarm, administrative controls, and plant operating procedures, provide the means for accomplishing the protective function. For further information on the instrumentation and control features, see Section 7.6.2.
The RHR inlet isolation valves are provided with red-green position indicator lights on the main control board and a ESF monitor light for proper valve position. ESF monitor light is independent and diverse from valve position indication.
Isolation of the low pressure RHRS from the high pressure RCS is provided on the discharge side by 2 check valves in series. These check valves are located in the ECCS and their testing is described in Section 5.2.2.4.
5.5.7.3.5 Shared Function The safety function performed by the RHRS is not compromised by its normal function which is normal plant cooldown. The valves associated with the RHRS are normally aligned to allow immediate use of this system in its engineered safety features mode of
operation. The system has been designed in such a manner that 2 redundant flow circuits are available, assuring the availability of at least 1 train for safety purposes.
02-01 02-01 5.5-50 Reformatted January 2016 The normal plant cooldown function of the RHRS is accomplished through a suction line arrangement which is independent of any safety function. The cold leg cooldown return lines are arranged in parallel redundant circuits and are utilized also as the low head injection lines to the RCS. Utilization of the same return circuits for cold leg cool down lends assurance to the proper functioning of these lines for engineered safety features purposes.
5.5.7.3.6 Radiological Consideration The highest radiation levels experienced by the RHRS are those which would result from a loss of coolant accident. Following a loss of coolant accident, the RHRS is used as part of the ECCS. During the recirculation phase of emergency core cooling, the RHRS is designed to operate for up to a year pumping water from the Reactor Building sump, cooling it, and returning it to the Reactor Building to cool the core.
Since, except for some valves and piping, the RHRS is located outside the reactor building, most of the system is not subjected to the high levels of radioactivity in the Reactor Building post accident environment.
The operation of the RHRS does not involve a radiation hazard for the operators since the system is controlled remotely from the control room. If maintenance of the system is necessary, the portion of the system requiring maintenance is isolated by remotely operated valves and/or manual valves with stem extensions which allow operation of the valves from a shielded location. The isolated piping is drained and flushed before maintenance is performed.
5.5.7.4 Tests and Inspections Periodic visual inspections and preventive maintenance are conducted during plant operation according to normal industrial practice.
The instrumentation channels for the residual heat removal pump flow instrumentation devices are calibrated during each refueling operation if a check indicates that recalibration is necessary.
Due to the role the RHRS has in sharing components with the ECCS, the residual heat removal pumps are tested as a part of the ECCS testing program (see Section 6.3.4).
Preoperational testing is discussed in Chapter 14.
5.5.8 REACTOR COOLANT CLEANUP SYSTEM The Chemical and Volume Control System provides reactor coolant cleanup and is discussed in Section 9.3.4. The radiological considerations are discussed in Chapter 11.
5.5-51 Reformatted January 2016 5.5.9 MAIN STEAM LINE AND FEEDWATER PIPING Main steam line and feedwater piping are discussed in Sections 10.3 and 10.4.7, respectively.
5.5.10 PRESSURIZER 5.5.10.1 Design Bases The general configuration of the pressurizer is shown in Figure 5.5-6. The design data of the pressurizer are given in Table 5.5-9. Codes and material requirements are provided in Section 5.2.
The pressurizer provides a point in the RCS where liquid and vapor can be maintained in equilibrium under saturated conditions for pressure and control purposes.
Stress analysis of the pressurizer components were performed at the plant conditions associated with steam generator replacement. While a slight increase in the fatigue usage for several of the pressurizer components was noted, the acceptance limits of Section III of the ASME Code were not exceeded. Therefore, the pressurizer components will not be overstressed or subject to fatigue usage during the remainder of the projected plant lifetime.
5.5.10.1.1 Pressurizer Surge Line The surge line is sized to limit the pressure drop between the RCS and the safety valves with maximum allowable discharge flow from the safety valves. Overpressure of the RCS does not exceed 110% of the design pressure.
The surge line and thermal sleeve at the pressurizer end are designed to withstand the thermal stresses resulting from volume surges of relatively hotter or colder water which may occur during operation.
The pressurizer surge line nozzle diameter is given in Table 5.5-9 and the pressurizer surge line dimensions are shown in Figure 5.1-1, Sheet 2.
5.5.10.1.2 Pressurizer The volume of the pressurizer is equal to or greater than the minimum volume of steam, water, or total of the 2 which satisfies the following requirements:
- 1. The combined saturated water volume and steam expansion volume is sufficient to provide the desired pressure response to system volume changes.
- 2. The water volume is sufficient to prevent the heaters from being uncovered during a 10% step load increase to full power.
RN 03-051 5.5-52 Reformatted January 2016
- 3. The steam volume is large enough to accommodate the surge resulting from 50% reduction of full load with automatic reactor control and 40% steam dump without the water level reaching the high level reactor trip point.
- 4. The steam volume is large enough to prevent water relief through the safety valves following a loss of load with the high water level initiating a reactor trip, without reactor control or steam dump.
- 5. The pressurizer will not empty following reactor trip and turbine trip.
- 6. The emergency core cooling signal is not activated during reactor trip and turbine trip. 5.5.10.2 Design Description 5.5.10.2.1 Pressurizer Surge Line The pressurizer surge line connects the pressurizer to 1 reactor hot leg. The line enables continuous coolant volume pressure adjustments between the RCS and the pressurizer.
5.5.10.2.2 Pressurizer The pressurizer is a vertical, cylindrical vessel with hemispherical top and bottom heads constructed of carbon steel, with austenitic stainless steel cladding on all surfaces exposed to the reactor coolant. A stainless steel liner or tube is used in lieu of cladding in some nozzles.
The high strength welds joining the component parts of the pressurizer are the 4 girth welds joining the upper head, 3 shell barrels, and the lower head, and the 3 longitudinal welds joining the 3 sections of the shell barrels. The various weld and flux combinations used in these welds are listed in Table 5.5-18 along with the appropriate fracture toughness test information.
The surge line nozzle and removable electric heaters are installed in the bottom head.
The heaters are removable for maintenance or replacement. A thermal sleeve is provided to minimize stresses in the surge line nozzle. A screen at the surge line nozzle and baffles in the lower section of the pressurizer prevent an insurge of cold water from flowing directly to the steam/water interface and assist mixing.
Spray line nozzles, relief, and safety valve connections are located in the top head of the vessel. Spray flow is modulated by automatically controlled air operated valves.
The spray valves can also be operated manually in the control room.
A small continuous spray flow is provided through a manual bypass valve around the power operated spray valves to assure that the pressurizer liquid is homogeneous with the coolant and to prevent excessive cooling of the spray piping.
5.5-53 Reformatted January 2016 During an outsurge from the pressurizer, flashing of water to steam, and generating of steam by automatic actuation of the heaters keep the pressure above the minimum allowable limit. During an insurge from the RCS, the spray system, which is fed from 2 cold legs, condenses steam in the vessel to prevent the pressurizer pressure from reaching the setpoint of the power operated relief valves for normal design transients.
Heaters are energized on high water level during insurge to heat the subcooled surge water that enters the pressurizer from the reactor coolant loop.
SA533 Grade A Class 2 material was used in the Virgil C. Summer pressurizer. (SA533 Grade A Class 2 material was not used in primary side (RCPB) pressure retaining applications of the Virgil C. Summer steam generators.) The actual fracture toughness data for the SA533 Grade A Class 2 material in the pressurizer are tabulated in Table 5.5-17.
Material specifications are provided in Table 5.2-8 for the pressurizer, pressurizer relief tank, and the surge line. Design transients for the components of the RCS are discussed in Section 5.2.1.5. Additional details on the pressurizer design cycle analysis are given in Section 5.5.10.3.5.
The pressurizer nozzle weld overlays as noted in section 5.5.3.3.4 identified that the overlay weld filler material used was alloy 52M. This high chromium weld filler metal is compatible with the carbon steel, stainless steel and existing Inconel materials in the underlying components.
This weld metal was applied utilizing a temperbead method to eliminate the need for pre and post weld heat treatment.
5.5.10.2.2.1 Pressurizer Support The skirt type support is attached to the lower head and extends for a full 360 degrees around the vessel. The lower part of the skirt terminates in a bolting flange with bolt holes for securing the vessel to its foundation. The skirt type support is provided with ventilation holes around its upper perimeter to assure free convection of ambient air past the heater plus connector ends for cooling.
5.5.10.2.2.2 Pressurizer Instrumentation Refer to Chapter 7 and Section 5.6 for details of the instrumentation associated with pressurizer pressure, level, and temperature.
5.5.10.2.2.3 Spray Line Temperatures Temperatures in the spray lines from 2 loops are measured and indicated. Alarms from these signals are actuated by low spray water temperature. Alarm conditions indicate insufficient flow in the spray lines.
RN 08-022 5.5-54 Reformatted January 2016 5.5.10.2.2.4 Safety and Relief Valve Leakage Monitoring Monitoring of the status of the pressurizer safety and relief valves is by the following methods:
- a. Temperature detectors in the piping downstream of the valves. (An increase in discharge line temperature is an indication of leakage through the valve.)
- b. Acoustical type monitors to detect safety valve leakage.
- c. Pressure/temperature/level of the pressurizer relief tank.
- d. Valve limit switches on the pressurizer power operated relief valves which indicate valve open/closed position.
All 4 methods for detecting leakage through the pressurizer safety and relief valves are monitored in the control room.
5.5.10.3 Design Evaluation 5.5.10.3.1 System Pressure Whenever a steam bubble is present within the pressurizer, RCS pressure is maintained by the pressurizer. A safety limit has been set to ensure that the RCS pressure does not exceed the maximum transient value allowed under the ASME Code,Section III, and thereby assure continued integrity of the RCS components.
Evaluation of plant conditions of operation which follow indicate that this safety limit is not reached.
During startup and shutdown, the rate of temperature change is controlled by the operator. Heatup rate is controlled by pump energy and by the pressurizer electrical heating capacity. This heatup rate takes into account the continuous spray flow provided to the pressurizer. When the reactor core is shutdown, the heaters are
de-energized.
When the pressurizer is filled with water (i.e., during initial system heatup) and near the end of the second phase of plant cooldown, RCS pressure is maintained by the letdown flowrate via the Residual Heat Removal System.
5.5.10.3.2 Pressurizer Performance The normal operating water volume at full load conditions is 60% of the free internal vessel volume. Under part load conditions, the water volume in the vessel is reduced for proportional reductions in plant load to 25% of free vessel volume at 0 power level. The various plant operating transients are analyzed and the design pressure is not exceeded with the pressurizer design parameters as given in Table 5.5-
- 9.
5.5-55 Reformatted January 2016 5.5.10.3.3 Pressure Setpoints The RCS design and operating pressure together with the safety, power relief and pressurizer spray valves setpoints, and the protection system setpoint pressures are listed in Table 5.2-7. The design pressure allows for operating transient pressure changes. The selected design margin considers core thermal lag, coolant transport times and pressure drops, instrumentation and control response characteristics, and system relief valve characteristics.
5.5.10.3.4 Pressurizer Spray Two (2) separate, automatically controlled spray valves with remote manual overrides are used to initiate pressurizer spray. In parallel with each spray valve is a manual throttle valve which permits a small continuous flow through both spray lines to reduce thermal stresses and thermal shock when the spray valves open and to help maintain uniform water chemistry and temperature in the pressurizer. Temperature sensors with low alarms are provided in each spray line to alert the operator to insufficient bypass flow. The layout of the common spray line piping to the pressurizer forms a water seal which prevents the steam buildup back to the control valves. The spray rate is selected to prevent the pressurizer pressure from reaching the operating setpoint of the power relief valves during a step reduction in power level of 10% of full load.
The pressurizer spray lines and valves are large enough to provide adequate spray using as the driving force the differential pressure between the surge line connection in the hot leg and the spray line connection in the cold leg. The spray line inlet connections extend into the cold leg piping in the form of a scoop so that the velocity head of the reactor coolant loop flow adds to the spray driving force. The spray valves and spray line connections are arranged so that the spray will operate when 1 reactor coolant pump is not operating. The line may also be used to assist in equalizing the boron concentration between the reactor coolant loops and the pressurizer.
A flow path from the Chemical and Volume Control System to the pressurizer spray line is also provided. This additional facility provides auxiliary spray to the vapor space of the pressurizer during cooldown if the reactor coolant pumps are not operating. The thermal sleeves on the pressurizer spray connection and the spray piping are designed to withstand the thermal stresses resulting from the introduction of cold spray water.
5.5.10.3.5 Pressurizer Design Analysis The occurrences for pressurizer design cycle analysis are defined as follows:
- 1. The temperature in the pressurizer vessel is always, for design purposes, assumed to equal saturation temperature for the existing RCS pressure, except in the pressurizer steam space subsequent to a pressure increase. In this case, the temperature of the steam space will exceed the saturation temperature since an isentropic compression of the steam is assumed.
5.5-56 Reformatted January 2016 The only exception of the above occurs when the pressurizer is filled solid during plant startup and cooldown.
- 2. The temperature shock on the spray nozzle is assumed to equal the temperature of the nozzle minus the cold leg temperature. The temperature shock on the surge nozzle is assumed to equal the pressurizer water space temperature minus the hot leg temperature.
- 3. Pressurizer spray is assumed to be initiated instantaneously to its design value as soon as the RCS pressure increases 40 psi above the nominal operating pressure.
Spray is assumed to be terminated as soon as the RCS pressure falls 40 psi below normal operating pressure.
- 6. Temperature changes occurring as a result of pressurizer spray are assumed to be instantaneous. Temperature changes occurring on the surge nozzle are also assumed to be instantaneous.
- 7. Whenever spray is initiated in the pressurizer, the pressurizer water level is assumed to be at the no load level.
5.5.10.4 Tests and Inspections The pressurizer is designed and constructed in accordance with the ASME Code,Section III.
To implement the requirements of the ASME Code,Section XI, the following welds are designed and constructed to present a smooth transition surface between the parent metal and the weld metal. The path is ground smooth for ultrasonic inspection.
- 1. Support skirt to the pressurizer lower head.
- 2. Surge nozzle to the lower head.
- 3. Nozzles to the safety, relief, and spray lines.
- 4. Nozzle to safe end attachment welds.
- 5. All girth and longitudinal full penetration welds.
5.5-57 Reformatted January 2016
- 6. Manway attachment welds.
The liner within the safe end nozzle region extends beyond the weld region to maintain a uniform geometry for ultrasonic inspection.
The Pressurizer nozzles for the surge, spray, safe ty and relief lines had full structural weld overlays applied during Refuel 17. These weld overlays were designed to ensure that a smooth surface was applied such that the ultrasonic inspection volumetric requirements are maintained. The result of the weld overlays resulted in 100%
ultrasonic inspection volumetric coverage of the respective nozzles and underlying welds and components. A Performance Demonstration Initiative (P DI) linear phased array inspection technique was used to perform the post weld overlay inspections.
Peripheral support rings are furnished for the removable insulation modules.
The pressurizer quality assurance program is given in Table 5.5-
- 10.
5.5.11 PRESSURIZER RELIEF TANK 5.5.11.1 Design Bases Design data for the pressurizer relief tank are given in Table 5.5-11. Codes and materials of the tank are given in Section 5.2.
The tank design is based on the requirement to absorb a discharge of pressurizer steam equal to 110% of the volume above the full power pressurizer water level setpoint. The tank is not designed to accept a continuous discharge from the pressurizer.
The volume of water in the tank is capable of absorbing the heat from the assumed discharge, assuming an initial temperature of 120F and increasing to a final temperature of 200F. If the temperature in the tank rises above 120F during plant operation, the tank is cooled by spraying in cool water and draining out the warm mixture to the waste processing system.
5.5.11.2 Design Description The pressurizer relief tank condenses and cools the discharge from the pressurizer safety and relief valves. Discharge from smaller relief valves located inside the containment is also piped to the relief tank. In addition, in the event that the reactor vessel head vent system is used, the pressurizer relief tank receives the discharge from the Reactor Coolant System. An itemized list identifying the discharges to the pressurizer relief tank is provided in Table 5.2-6. The tank normally contains water and a predominantly nitrogen atmosphere; however, provision is made to permit the gas in the tank to be periodically analyzed to monitor the concentration of hydrogen and/or oxygen. RN 08-022 5.5-58 Reformatted January 2016 By means of its connection to the waste processing system, the pressurizer relief tank provides a means for removing any noncondensable gases from the RCS which might collect in the pressurizer vessel.
Steam is discharged through a sparger pipe under the water level. This arrangement provides for condensing and cooling the steam by mixing it with water that is near ambient temperature. The tank is also equipped with an internal spray and a drain which are used to cool the tank following a discharge. A flanged nozzle is provided on the tank for the pressurizer discharge line connection to the sparger pipe.
5.5.11.2.1 Pressurizer Relief Tank Pressure The pressurizer relief tank pressure transmitter provides an indication of pressure relief tank pressure. An alarm is provided to indicate high tank pressure.
5.5.11.2.2 Pressurizer Relief Tank Level The pressurizer relief tank level transmitter supplies a signal for an indicator with high and low level alarms.
5.5.11.2.3 Pressurizer Relief Tank Water Temperature The temperature of the water in the pressurizer relief tank is indicated, and an alarm actuated by high temperature informs the operator that cooling to the tank contents is required.
5.5.11.3 Design Evaluation The volume of water in the tank is capable of absorbing a discharge of 110% of the pressurizer steam volume above the full power water level setpoint. Water temperature in the tank is maintained at the nominal containment temperature.
The rupture disks on the relief tank have a relief capacity equal to or greater than the combined capacity of the pressurizer safety valves. The tank design pressure is twice the calculated pressure resulting from the maximum design safety valve discharge described above. The tank and rupture disc holders are also designed for full vacuum to prevent tank collapse if the contents cool following a discharge without nitrogen being added.
The discharge piping from the safety and relief valves to the relief tank is sufficiently large to prevent backpressure of the safety valves from exceeding 20% of the setpoint pressure at full flow.
5.5-59 Reformatted January 2016 5.5.12 VALVES 5.5.12.1 Design Bases As noted in Section 5.2, all valves out to and including the second valve normally closed or capable of automatic or remote closure, larger than 3/4 inch, are Safety Class 1, and ASME III, Code Class 1 valves. All 3/4 inch or smaller valves in liquid fill ed lines connected to the RCS are Class 2 since the interface with the Class 1 piping is provided with suitable orificing for such valves. Pressurizer instrument root valves connected to the steam space above the normal water level have been upgraded to Safety Class 1, since failure of these valves could cause automatic operation of the ECCS systems.
Design data for the RCS valves are given in Table 5.5-12.
To ensure that the valves meet the design objectives, the materials specified for construction must minimize corrosion/erosion and ensure compatibility with the environment. Leakage is minimized to the extent practicable by design and Class 1 stresses are maintained within the limits of the ASME Code,Section III and the limits specified in Section 5.5.1.
5.5.12.2 Design Description Valves in the RCS which are in contact with the coolant are constructed primarily of stainless steel. Other materials in contact with the coolant, such as for hard surfacing and packing, are special materials.
Manual and motor operated valves of the RCS which are 3 inches and larger are provided with double-packed stuffing boxes and intermediate lantern ring leakoff connections. Throttling control valves, regardless of size, are provided with double-packed stuffing boxes and with stem leakoff connections. Leakoff connections on valves, normally operated in a radioactive fluid, are piped to a closed collection system. Leakage to the atmosphere is essentially 0 for these valves.
Gate valves at the engineered safety features interface are wedge design and are essentially straight through. The wedges are flex-wedge or solid. All gate valves have backseats. Globe valves are "T" and "Y" style. Check valves are swing type for sizes 2-1/2 inches and larger. All check valves which contain radioactive fluid are stainless steel and do not have body penetrations other than the inlet, outlet, and bonnet. The check hinge is serviced through the bonnet.
The accumulator check valve is designed such that at the required flow the resulting pressure drop is within the specified limits. All operating parts are contained within the body. The disc has limited rotation to provide a change of seating surface and alignment after each valve opening.
RN 07-012 5.5-60 Reformatted January 2016 5.5.12.3 Design Evaluation The design/analysis requirements for Class 1 valves, as discussed in Section 5.2, limit stresses to levels which ensure the structural integrity of the valves. In addition, the testing programs described in Section 3.9.2.4 demonstrate the ability of the valves to operate as required during anticipated and postulated plant conditions.
Reactor coolant chemistry parameters are specified in the design specifications to assure the compatibility of valve construction materials with the reactor coolant.
5.5.12.4 Tests and Inspections RCS valves are tested in accordance with the requirements of the ASME Code,Section III. The tests and inspections discussed in Section 3.9.2.4 are performed to ensure the operability of active valves. In-place operational testing is performed on valves as required by the Technical Specifications.
There are no full penetration welds within valve body walls. Valves are accessible for disassembly and internal visual inspection to the extent practical. Plant layout configurations determine the degree of inspectability. The valve quality assurance program is given in Table 5.5-13.
Inservice inspection is discussed in Section 5.2.8.
5.5.13 SAFETY AND RELIEF VALVES 5.5.13.1 Design Bases The combined capacity of the pressurizer safety valves is designed to accommodate the maximum surge resulting from complete loss of load. This objective is met without reactor trip or any operator action by the opening of the steam safety valves when steam pressure reaches the steam side safety setting.
The pressurizer power operated relief valves are designed to limit pressurizer pressure to a value below the fixed high pressure reactor trip setpoint for most transients.
Conservative analyses indicate that, for the 95% load rejection transient, the high pressure reactor trip setpoint would be reached. No credit is taken for automatic operation of these valves to mitigate the consequences of an accident. They are designed to fail to the closed position on loss of air supply.
5.5.13.2 Design Description The pressurizer safety valves are totally enclosed pop type. The valves are spring loaded, self-actuated, and with backpressure compensation features.
The pipe connecting the pressurizer nozzles to their respective code safety valves are shaped in the form of a loop. The low point of the loops is drained continuously to the RN 04-012 5.5-61 Reformatted January 2016 pressurizer liquid space to remove any condensation formed in the safety valve inlet pipes.
The pressurizer power operated relief valves are pneumatic actuated valves which respond to a signal from a pressure sensing system or to manual control. Remotely operated stop valves are provided to isolate the power operated relief valves if excessive leakage develops.
Pressurizer safety and relief valve leakage monitoring is discussed in Section 5.5.10.2.2.4. Refer to Section 5.2 for a discussion of discharge line supports.
Design parameters for the pressurizer spray control, safety, and power relief valves are given in Table 5.5-
The pressurizer power relief valves prevent actuation of the fixed reactor high pressure trip for all design transients except the design step load decreases with steam dump.
For this event, peak pressure will exceed the trip setpoint but remains below the safety valve setpoint. The relief valves limit undesirable opening of the spring-loaded safety valves. Note that setpoint studies to date indicate that the pressure rise in a 3-loop plant for the design step load decrease of 10% from full power is limited to 60 psi.
These studies also indicate that the design step load decrease of 10% under N-1 loop operation is limited to approximately 50 psi. In both cases, the pressure rise is not sufficient to actuate the power operated relief valves, and thus, this design is conservative.
5.5.13.4 Tests and Inspections All safety and relief valves are subjected to hydrostatic tests, seat leakage tests, operational tests, and inspections as required. For safety valves that are required to function during a faulted condition, additional tests are performed. These tests are described in Section 3.9.2.4.
There are no full penetration welds within the valve body walls. Valves are accessible for disassembly and internal visual inspection.
5.5-62 Reformatted January 2016 5.5.14 COMPONENT SUPPORTS Component supports allow virtually unrestrained lateral thermal movement of the loops during plant operation and provide restraint to the loops and components during accident conditions. The loading combinations and design stress limits are discussed in Section 5.2.1.10. The design maintains the integrity of the Reactor Coolant System boundary for normal and accident conditions and satisfies the requirements of the piping code. Results of piping and supports stress evaluation will be presented in Section 5.2.1.10. The normal operating temperatures for the Reactor Coolant System supports are 50F to 400 F. 5.5.14.1 Description The support structures are of welded steel construction and are either linear type or plate and shell type. Vessel skirts and saddles are fabricated from plate and shell elements to accommodate a biaxial stress field. Linear supports are tension and compression struts, beams and columns. Attachments are of integral and nonintegral types. Integral attachments are welded, cast, or forged to the pressure boundary component by lugs, shoes, rings, and skirts. Nonintegral attachments are bolted, pinned, or bear on the pressure boundary component.
The supports permit unrestrained thermal growth of the supported systems, but restrain vertical, lateral, and rotational movement resulting from seismic and pipe break loadings. This is accomplished using pin-ended columns for vertical support and girders, bumper pedestals, and tie rods for lateral support.
Shimming and grouting enable adjustment of all support elements during erection to achieve correct fit-up and alignment.
- 1. Vessel Supports for the reactor vessel (see Figure 5.5-7) are individual air cooled rectangular box structures beneath the vessel nozzles bolted to the primary shield wall concrete. Each box structure consists of a horizontal top plate that receives loads from the reactor vessel shoe, a horizontal bottom plate supported by and transferring loads to the primary shield wall concrete, and connecting vertical plates. The supports are air cooled to maintain the supporting concrete temperature within acceptable levels.
02-01 5.5-63 Reformatted January 2016
- 2. Steam Generator The lower supports for the steam generator (see Figure 5.5-8) consist of 4 vertical pin-ended columns bolted to the bottom of the steam generator support pads; and lateral support girders and pedestals that bear against horizontal bumper blocks bolted to the side of the generator support pads. The upper lateral steam generator support consists of a ring girder around the generator shell supported by struts. Loads are transferred from the equipment to the ring girder by means of a number of bumper blocks between the girder and generator shell.
- 3. Pump The reactor coolant pump supports (see Figure 5.5-9) consist of 3 pin-ended structural steel columns and 3 lateral tie bars. A large diameter bolt connects each column and tie rod to a pump support pad. The outer ends of all 3 tie rods have slotted pin holes to permit unrestrained lateral movement of the pump during plant heatup and cooldown, but provide lateral restraint for accident loadings.
- 4. Pressurizer
The pressurizer (see Figure 5.5-10) is supported at its base by bolting the flangering to the supporting concrete slab. In addition, upper lateral support is provided near the vessel center of gravity by 4 "V frames" or struts extending horizontally from the compartment walls and bearing against the vessel lugs.
5.5.14.2 Evaluation Detailed evaluation ensures the design adequacy and structural integrity of the reactor coolant loop and the primary equipment supports system. This detailed evaluation is made by comparing the analytical results with established criteria for acceptability.
Structural analyses are performed to demonstrate design adequacy for safety and reliability of the plant in case of a large or small seismic disturbance and/or loss of coolant accident conditions. Loads that the system is designed to encounter, of 10 during its lifetime (thermal, weight, pressure, and operating basis earthquake), are applied and stresses are compared to allowable values, as described in Section 5.2.1.10.
All Reactor Coolant System (RCS) supports are designed for concurrent loadings from deadweight, pressure, postulated pipe ruptures in the RCS as identified in WCAP-8082 and WCAP-13206, and the safe shutdown earthquake. As indicated in Section 3.6, postulated breaks in the reactor coolant loop piping, except for branch line connections, have been eliminated. Reactor coolant loop piping branch nozzle (i.e., accumulator connection, pressurizer surge line, residual heat removal, etc.) breaks are postulated.
Additionally, steam line breaks, and safety and relief line breaks are considered in the design of steam generator and pressurizer supports respectively. Included under the considerations for pipe rupture loads are the effects of RCS hydraulic loads, jet impingement, thrust, and asymmetric pressures about the supported components.
02-01 5.5-64 Reformatted January 2016 The pipe rupture analysis which is performed for the reactor vessel support loads includes nonaxisymmetric pressure distributions on the internals.
A detailed dynamic model of the reactor vessel and internals includes the stiffnesses of the reactor vessel support and the attached piping. Hydraulic forces are developed in the internals for the postulated break; these forces are characterized by time dependent forcing functions on the vessel and core barrel. In the derivation of these forcing functions, the fluid-structure (or hydroelastic) interaction in the downcomer region between the barrel and the vessel is taken into account. As a result of the loop branch pipe breaks, loop mechanical loads are also applied to the vessel. The loads from these 3 sources, the internals reactions, reactor cavity pressure loads, and the loop mechanical forces are applied simultaneously in a nonlinear elastic dynamic time history analysis on the model of the vessel, supports, and internals. The results of this analysis are the dynamic loads on the reactor vessel supports and vessel time history displacements. The maximum loads are combined with other applicable loads, such as seismic and deadweight and applied statically to the vessel support structure.
Although considered in the design, it is expected on the basis of past experience that asymmetric pressure loadings on the major components will be negligible.
For public health and safety, the safe shutdown earthquake and design basis loss of coolant accident, resulting in a rapid depressurization of the system, are required design condition. For these loadings, the basic criteria ensure that the severity of the accident will not be increased, thus maintaining the system in a safe condition. The rupture of a reactor coolant loop pipe will not violate the integrity of the unbroken leg of the loop. To ensure the integrity and stability of the reactor coolant loop support system and a safe shutdown of the system under loss of coolant accident and the worst combined (Normal
+ SSE + LOCA) loadings, the stresses in the unbroken piping of a broken loop, the unbroken loop piping, and the supports system are analyzed. The results of design analysis are provided in Section 5.2.1.10.
5.5.14.3 Tests and Inspections The design and fabrication is specified in accordance with the AISC Specifications for the "Design, Fabrication, and Erection of Structural Steel for Buildings," 1969 Edition and applicable portions of the ASME Boiler and Pressure Vessel Code. Welder qualifications, welding procedures, and inspection of welded joints is specified to be in accordance with Section IX of the ASME Code.
5.5-65 Reformatted January 2016 5.5.15 REACTOR VESSEL HEAD VENT SYSTEM 5.5.15.1 Design Basis The basic function of the Reactor Vessel Head Vent System (RVHVS) is to remove non-condensable gases or steam from the reactor vessel head. This system is designed to mitigate a possible condition of inadequate core cooling or impaired natural circulation resulting from the accumulation of noncondensable gases in the RCS. The design of the RVHVS is in accordance with the requirements of NUREG-0578 and subsequent definitions and clarifications (References [2] and [3]).
5.5.15.2 Design Description and Evaluation 5.5.15.2.1 General Description The RVHVS is designed to remove non-condensable gases or steam from the Reactor Coolant System via remote manual operations from the control room. The system discharges to the pressurizer relief tank. The RVHVS is designed to vent a volume of hydrogen, noncondensable gases, etc., at system design pressure and temperature approximately equivalent to 1/2 of the Reactor Coolant System volume in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
An H 2 burn from a 100% zircaloy/H 2O reaction has been addressed and it has been determined that containment integrity would not be breached. Therefore, contained venting outside containment is not considered necessary.
The flow diagram of the RVHVS is shown in Figure 5.5-13. The RVHVS consists of 2 parallel flow paths with redundant isolation valves in each flow path. The venting operation uses only 1 of the flow paths at any time.
The physical layout of the RCS hot leg piping is such that its entire volume can be vented via the RVHV system.
The equipment design parameters are listed in Table 5.5-
- 16.
As indicated above, normally the venting from the RVHVS is contained by the pressurizer relief tank. However, venting to containment could occur if the rupture disc ruptures. In that case, the location of the PRT is such that excellent gas communication exists within the secondary shield area that any gas that escapes from the PRT will be readily mixed with the containment atmosphere with additional mixing being promoted by the Reactor Building Ventilation System.
5.5-66 Reformatted January 2016 The active portion of the system consists of 4 two-inch motor operated isolation valves connected to the reactor vessel head vent pipe. The isolation valves in series in each flow path are powered by opposite vital power supplies. The isolation valves are fail as is, active valves. One (1) normally closed isolation valve and 1 normally open valve are located in each flow path. Leakage past the vent valves during normal plant operation is detected by the pressurizer relief tank instrumentation. All of the isolation valves are qualified to IEEE - 323-1974, 344-1975, and 382-1972 and to the requirements of Regulatory Guide 1.48 as described in Appendix 3A.
If one single active failure prevents a venting operation through 1 flow path, the redundant path is available for venting. Similarly, the 2 isolation valves in each flow path provide a single failure method of isolating the venting system. With 2 valves in series, the failure of any 1 valve or power supply will not inadvertently open a vent path. Thus, the combination of safety grade train assignments and valve failure modes will not prevent vessel head venting nor venting isolation with any single active failure.
The RVHVS has 2 normally de-energized valves in series in each flow path. Power lockout capability to all 4 isolation valves is provided by administrative control at the motor control load center. This arrangement eliminates the possibility of a spuriously opened flow path.
The system is operated from the control room. The position indication from each valve is monitored in the control room by status lights. Position indication is unavailable in the control room when the motor control breaker is open.
The RVHVS is connected to the head vent pipe as shown on Figure 5.5-13. The system is orificed to limit the blowdown from a break downstream of either of the orifices to within the capacity of 1 of the centrifugal charging pumps.
A break of the RVHVS line upstream of the orifices would result in a small LOCA of not greater than 1 inch diameter. Such a break is similar to those analyzed in WCAP-9600 (Reference [4]). Since a break in the head vent line would behave similarly to the hot leg break case presented in WCAP-9600, the results presented therein are applicable to a RVHVS line break. This postulated vent line break, therefore, results in no calculated core uncovery.
All piping and equipment from the vessel head vent up to and including the second isolation valve in each flowpath are designed and fabricated in accordance with ASME,Section III, Class 1 requirements. The remainder of the piping and equipment is non-nuclear safety, but is seismically supported up to the 12" pressurizer relief line.
The system provides for venting the reactor vessel head by using only safety grade equipment. The RVHVS satisfies applicable requirements and industry standards including ASME Code classification, safety classification, single-failure criteria, and environmental qualification.
RN 14-037 5.5-67 Reformatted January 2016 5.5.15.2.2 Supports The vent system piping is supported to ensure that the resulting loads and stresses on the piping and on the vent connection to the vessel head are acceptable.
The support design for attaching the head vent system piping to the reactor vessel head lifting leg is shown in Figure 5.5-14. The support is a 2-part clamp configuration, called a double bolt riser clamp. The clamp and associated bolts, nuts, spacers, and washers are made of stainless steel. A gap exists between the 1 inch head vent pipe and the support clamp to allow for thermal expansion in the vertical direction.
The support design for attaching the head vent system piping to the CRDM seismic support platform is shown in Figure 5.5-
- 15. This support is a 2-part clamp configuration, called a double bolt clamp bracket. This clamp support is used to rigidly support the piping in the radial direction. The clamp and associated bolts, nuts, spacers, and washers are made of stainless steel, with high strength hold down bolts threaded into the deck of the CRDM Seismic support platform. A gap exists between the one inch head vent pipe and the support clamp to allow for thermal expansion in the axial direction.
All supports and support structures comply with the requirements of the AISC Code, Part II.
5.5.15.3 Analytical Considerations The analysis of the reactor vessel head vent piping is based on the following plant operation conditions defined in the ASME Code Section III:
- 1. Normal Condition:
Pressure, deadweight, and thermal expansion analysis of the vent pipe during
a) normal reactor operation with the 2 inboard vent isolation valves closed and
b) post-refueling venting.
- 2. Upset Condition:
Loads generated by the operating basis earthquake (OBE) response spectra.
- 3. Faulted Condition:
Loads generated by the safe shutdown earthquake (SSE) and by valve thrust during venting. In accordance with ASME Code Section III, faulted conditions are not included in fatigue evaluations.
5.5-68 Reformatted January 2016 The Class I piping used for the reactor vessel head vent is one inch schedule 160 and, therefore, in accordance with ASME Code Section III, is analyzed following the procedures of NC-3600 for Class II piping.
For plant operating conditions listed above, the piping stresses are shown to meet the requirements of equations (8), (9), (10), or (11) of ASME III, Section NC-3600 with a design temperature of 650F and a design pressure of 2485 psig.
5.5.16 REFERENCES
- 1. "Reactor Coolant Pump Integrity in LOCA," WCAP-8163, September, 1973.
- 2. Letter from D. B. Vassallo (NRC) to all Applicants for an Operating License, "Followup Actions Resulting From the NRC Staff Reviews Regarding the Three Mile Island Unit 2 Accident," and Enclosure 4: Installation of Remotely Operated High Point Vents in the Reactor Coolant System, September 27, 1979.
- 3. Letter from D. B. Vassallo (NRC) to all Applicants for an Operating License, "Discussion of Lessons Learned Short Term Requirements," Enclosure 1, pp.
44-49, Reactor Coolant System Venting, November 9, 1979.
- 5. "Basis for Heatup and Cooldown Limit Curves," WCAP-7924-A, April 1975.
- 6. WCAP-13480, Revision 1, "Westinghouse Delta-75 Steam Generator Design and Fabrication Information for the V. C. Summer Nuclear Station," October 1993.
TABLE 5.5-1 REACTOR COOLANT PUMP DESIGN PARAMETERS Unit Design Pressure, psig 2485 Unit Design Temperature, F 650 (1) Unit Overall Height, ft 26 Seal Water Injection, gpm 8 Seal Water Return, gpm 3 Cooling Water Flow, gpm 195 Maximum Continuous Cooling Water Inlet Temperature, F 105 Pump Capacity, gpm 100,700 Developed Head, ft 279 NPSH Required, ft Figure 5.5-2 Suction Temperature, F 554.6 Pump Discharge Nozzle, Inside Diameter, in 27-1/2 Pump Suction Nozzle, Inside Diameter, in 31 Speed, rpm 1180 Water Volume, ft 3 81 Weight (dry), lbs.
199,000 Motor Type Drip proof, s quirrel cage induction air-cooled Power, Hp 7000 Voltage, volts 6900 Phase 3 Frequency, Hz 60 Insulation Class Class F, thermoplastic epoxy insulation Starting Current 3000 amp @ 6900 volts Input, hot reactor coolant 501 amp Input, cold reactor coolant 635 amp 5.5-69 AMENDMENT 97-01 AUGUST 1997 5.5-70 AMENDMENT 97-01 AUGUST 1997 TABLE 5.5-1 (Continued)
REACTOR COOLANT PUMP DESIGN PARAMETERS Motor (Continued) Pump Moment of Inertia, lb-ft 2 maximum Flywheel 70,000 Motor 22,500 Shaft 520 Impeller 1,980
(1) Design temperature of pressure retaining parts of the pump assembly exposed to the reactor coolant and injection water on the high pressure side of the controlled leakage seal shall be that temperature determined for the parts for a primary loop temperature of 650 F.
TABLE 5.5-2 REACTOR COOLANT PUMP QUALITY ASSURANCE PROGRAM RT (1) UT (1) PT (1) MT (1) Castings Yes Yes Forgings 1. Main Shaft Yes Yes 2. Main Studs Yes Yes 3. Flywheel (Rolled Plate)
Yes Weldments 1. Circumferential Yes Yes 2. Instrument Connections Yes (1) RT - Radiographic UT - Ultrasonic PT - Dye Penetrant MT - Magnetic Particle
5.5-71 AMENDMENT 97-01 AUGUST 1997 TABLE 5.5-3 STEAM GENERATOR DESIGN DATA Design Pressure, reactor coolant side, psig 2485 Design Pressure, steam side, psig 1185 Design Temperature, reactor coolant side, F 650 Design Temperatur e, steam side, F 600 Total Heat Transfer Surface Area, ft 2 75,185 Maximum Moisture Carryover, wt percent 0.10 Overall Height, ft-in 67-8 Number of U-Tubes 6307 U-Tube Outer Diameter, in 0.688 Tube Wall Thickness, nominal, in 0.040 Number of Manways 4 Inside Diameter of Manways, in 16 Number of Handholes 8 Inside Diameter of Handholes, in 4" and 6" Design Fouling Factor hr-ft 2- F/BTU 0.00011 99-01 99-01 5.5-72 Reformatted Per Amendment 99-01 TABLE 5.5-4 STEAM GENERATOR QUALITY ASSURANCE PROGRAM RT (1) UT (1) PT (1) MT (1) ET (1) Tubesheet 1. Forging Yes Yes 2. Cladding
Yes (2) Yes (3) Channel Head
- 1. Casting Yes Yes 2. Cladding
Yes Secondary Shell & Head
- 1. Plates
Yes Tubes Yes Yes Nozzles (Forgings) Yes Yes Weldments 1. Shell, longitudinal Yes Yes 2. Shell, circumferential Yes Yes 3. Cladding (channel head-tubesheet joint cladding restoration)
Yes 4. Steam and feedwater nozzle to shell Yes Yes 5. Support brackets Yes 6. Tube to tubesheet Yes 7. Instrument connections (primary and secondary)
Yes 8. Temporary attachments after removal Yes 9. After hydrostatic test (all welds and complete channel head - where
accessible)
Yes 5.5-73 AMENDMENT 97-01 AUGUST 1997 5.5-74 AMENDMENT 97-01 AUGUST 1997 TABLE 5.5-4 (Continued)
STEAM GENERATOR QUALITY ASSURANCE PROGRAM RT (1) UT (1) PT (1) MT (1) ET (1) Weldments (Continued) 10. Nozzle safe ends (if forgings) Yes Yes 11. Nozzle safe ends (if weld deposit)
Yes
(1) RT- Radiographic UT - Ultrasonic
PT - Dye Penetrant
MT - Magnetic Particle
ET - Eddy Current
(2) Flat Surfaces Only
(3) Weld Deposit Areas Only TABLE 5.5-5 REACTOR COOLANT PIPING DESIGN PARAMETERS Reactor Inlet Piping, inside diameter, in 27-1/2 eactor Inlet Piping, nominal wall thickness, in 2.32 eactor Outlet Piping, inside diameter, in 29 eactor Outlet Piping, nominal wall thickness, in 2.45 oolant Pump Suction Piping, inside diameter, in 31 oolant Pump Suction Piping, nominal wall thickness, in 2.60 ressurizer Surge Line Pipi ng, nominal pipe size, in 14 ressurizer Surge Line Piping, nominal wall thickness, in 1.406 eactor Coolant Loop Piping R
R
R
C
C
P
P
R Design/Operating Pressure, psig 2485/2235 Pressurizer Surge Line Design Temperature, F 650 Design Pressure, psig 2485 Pressurizer Safety Valve Inlet Line
Design Temperature, F 680 Design Pressure, psig 2485 Pressurizer (Power-Operated) Relief Valve Inlet Line
Design Temperature, F 680 Design Pressure, psig 2485 Pressurizer Relief Tank Inlet Line
Design Temperature, F 680 Design Pressure, psig 600 Design Temperature, F 600 5.5-75 AMENDMENT 97-01 AUGUST 1997 TABLE 5.5-6 REACTOR COOLANT PIPING QUALITY ASSURANCE PROGRAM RT (1) UT (1) PT (1)
Yes Yes Fittings and Pipe (Forgings)
Yes Yes Weldments 1. Circumferential
Yes Yes 2. Nozzle to runpipe (Except no RT for nozzles less
than 6 inches)
Yes Yes 3. Instrument Connections
Yes Castings Yes Yes (after finishing)
Forgings Yes Yes (after finishing)
(1) RT - Radiographic UT - Ultrasonic PT - Dye Penetrant 5.5-76 AMENDMENT 97-01 AUGUST 1997 TABLE 5.5-7 DESIGN BASES FOR RESIDUAL H EAT REMOVAL SYSTEM OPERATION Residual Heat Remo 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after Reactor eactor Coolant System Initial Pressure, psig F F (1) Temperature not exceeding 120 F) (2)val System Startup Shutdown.
425 R Reactor Coolant System Initial Temperature, Component Cooling Water Design Temperature, 350 Cooldown Time, Hours After In itiation of Residual Heat 105 Removal System Operation (CCWS S upply 16 Reactor Coolant System Temper ature At End of Cooldown, F 20 Decay Heat Generation at 20 Hours After Reactor Shutdown, BTU/hr 140 60.6 x 10 6(1) Decay Heat Generation at 24 Hours Afte r Reactor Shutdown, BTU/hr 60.6 x 10 6 (2)
- 1) Core Power = 2775 MWt
(
(2) Core Power = 2900 MWt 5.5-77 AMENDMENT 97-01 AUGUST 1997 TABLE 5.5-8 RESIDUAL HEAT REMOVAL SYSTEM COMPONENT DATA Residual Heat Removal Pumps Number 2 Design Pressure, psig 600 Design Temperature, F 400 Design Flow, gpm 3750 Design Head, ft 240 NPSH at 3750 gpm, ft 14 Motor Power, HP 300 Residual Heat Exchangers Number 2 Design Heat Removal Capacity
30.3 x 10 6 BTU/hr Tube Side Shell Side Design Pressure, psig 600 150 Design Temperature, F 400 200 Design Flow, lb/hr 1.86 x 10 6 2.8 x 10 6 Inlet Temperature, F 139 105 Outlet Temperature, F 123 116 Material Austenitic Stainless Steel Carbon Steel Fluid Reactor Coolant Component Cooling Water 5.5-78 AMENDMENT 97-01 AUGUST 1997 TABLE 5.5-9 PRESSURIZER DESIGN DATA Design Pressure, psig 2485 Design Temperature, F 680 Surge Line Nozzle Diameter, in
14 Heatup Rate of Pressurizer Using Heaters Only, F/hr 55 Internal Volume, ft 3 1400 5.5-79 Reformatted Per Amendment 02-01 TABLE 5.5-10 PRESSURIZER QUALITY ASSURANCE PROGRA M RT (1) UT (1) PT (1) MT (1) Heads 1. Plates Yes 2. Cladding Yes Shell 1. Plates Yes 2. Cladding Yes Heaters 1. Tubing (2) Yes Yes 2. Centering of element Yes Nozzle (Forgings)
Yes Yes (3) Yes (3) Weldments 1. Shell, longitudinal Yes Yes 2. Shell, circumferential Yes Yes 3. Cladding Yes 4. Nozzle Safe End (if forging) Yes Yes 5. Instrument Connection Yes 6. Support Skirt Yes Yes 7. Temporary Attachments (after removal)
Y e s 8. All external pressure boundary welds after shop hydrostatic test Y e s 02-01 02-01 02-01 (1) RT - Radiographic UT - Ultrasonic PT - Dye Penetrant MT - Magnetic Particle
(3) MT or PT 5.5-80 Reformatted Per Amendment 02-01 TABLE 5.5-11 PRESSURIZER RELIEF TANK DESIGN DATA Design Pressure, psig 100 Rupture Disc Release Pre ssure, psig Nominal: 91 Range: 86-100 Design Temperature, F 340 Total Rupture Disc Relief Capacity, lb/hr at 100 psig 1.6 x 10 6 5.5-81 AMENDMENT 97-01 AUGUST 1997 TABLE 5.5-12 REACTOR COOLANT SYSTEM VALVE DESIGN PARAMETERS Design/Normal Operating Pressure, psig 2485/2235 Preoperational Plant Hy drotest, psig 3107 Design Temperature, F 650 5.5-82 AMENDMENT 97-01 AUGUST 1997 TABLE 5.5-13 REACTOR COOLANT SYSTEM VALVES QUALITY ASSURANCE PROGRAM RT (1) UT (1) PT (1) Boundary Valves, Pressurizer Relief and Safety Valves Castings - (larger than 4 inches)
(2 inches to 4 inches)
Yes Yes(2) Yes Yes Forgings - (larger than 4 inches)
(2 inches to 4 inches)
(3)(3) Yes Yes (1) RT - Radiographic UT - Ultrasonic PT - Dye Penetrant (2) Weld Ends Only (3) Either RT or UT 5.5-83 AMENDMENT 97-01 AUGUST 1997 TABLE 5.5-14 PRESSURIZER VALVES DESIGN PARAMETERS Pressurizer Spray Valves Number 2 Design Pressure, psig 2485 Design Temperature, F 650 Design Flow, for valves full open, each, gpm 350 Pressurizer Safety Valves Number 3 Maximum Relieving Capacity, ASME rated flow, lb/hr 420,000 Set Pressure, psig 2485 Design Temperature, F 650 Fluid Saturated steam Transient Condition, F (Superheated steam) 680 Backpressure:
Normal, psig 3 to 5 Expected during discharge, psig
350 Pressurizer Power Relief Valves Number 3 Design Pressure, psig 2485 Design Temperature, F 650 Relieving Capacity, at 2350 psig, lb/hr (per valve) 210,000 Fluid Saturated steam Transient Condition, F (Superheated steam) 680 5.5-84 AMENDMENT 97-01 AUGUST 1997 TABLE 5.5-15 SINGLE ACTIVE FAILURE ANALYSES OF THE RESIDUAL HEAT REMOVAL SYSTEM Component Malfunction Comments 1. RHR suction isolation valve (8701 A or B or 8702 A or B) Fails to open RHR cooling restricted to one train. Cooldown time extended.
- 2. RWST/RHR suction isolation valve (8809 A or B) Fails to close RHR cooling restricted to one train. Cooldown time
extended.
extended.
Slight increase in RHR
pump flow in one train.
Slight extension in
cooldown time.
Slight extension in
cooldown time.
- 6. Flow instrument (605A or 605B)
Fails low Bypass valve opens.
Cooldown in one train reduced. Cooldown time
extended.
- 7. Flow instrument (605A or 605B)
Fails high Bypass valve closes.
Constant total return flow in one train to the RCS cannot be maintained. No
adverse effects.
Fails to close Cooling in one train reduced. Cooldown time
extended.
5.5-85 AMENDMENT 97-01 AUGUST 1997 5.5-86 AMENDMENT 97-01 AUGUST 1997 TABLE 5.5-15 (Continued)
SINGLE ACTIVE FAILURE ANALYSES OF THE RESIDUAL HEAT REMOVAL SYSTEM Component Malfunction Comments 9. Bypass valve (FCV 605A or FCV 605B)
Fails to open Constant total return flow in one train to the RCS cannot be maintained. No
adverse effects.
- 10. RHR heat exchanger (no. 1 or 2)
Fails to function RHR cooling restricted to one train. Cooldown time
extended.
extended.
Fails open Cannot control cooldown rate in one train, thus, requiring that cooling be
restricted to the other train.
Cooldown time extended.
See Sections 5.5.7.3.3 and 5.5.7.3.4, respectively, for a discussion of Overpressurization Protection and Prevention of Exposure of the RHR System to Normal RCS Pressures.
TABLE 5.5-16 REACTOR VESSEL HEAD VENT SYSTEM EQUIPMENT DESIGN PARAMETER Valves Number (include two manual valves) 6 Design pressure, psig 2485 Design temperature, F 650 Piping Normal vent line nominal diameter, in.
1 - 3/4 RVHVS flow path line, nominal diameter, in 1 Design pressure, psig 2485 Design temperature, F 650 5.5-87 Reformatted Per Amendment 02-01 TABLE 5.5-17 FRACTURE TOUGHNESS DATA FOR SA533 GRADE A CLASS 2 MATERIAL Component Component Part Test Number Charpy V-Notch (ft-lb) Lateral Expansion (in) Orientation Longitudinal (L)Transverse (T)
Test Temperature
( F) T NDT ( F) RT NDT ( F) Pressurizer (1581) Lower Head T03639 82, 85, 80 90, 90, 78
.074, .071, .068 .063, .072, .072 T L 70 10 10 10 Pressurizer (1581) Upper Head T03625 53, 54, 53 75, 74, 91
.052, .051, .048 .060, .070, .071 T L 70 10 10 10 Pressurizer (1581) Shell Barrel T03328 78, 82, 81 .056, .057, .049 L 10 -* - Pressurizer (1581) Shell Barrel T03704 65, 59, 56 .051, .056, .059 T 70 0 10 Pressurizer (1581) Shell Barrel T03605 78, 78, 85 .065, .071, .066 T 70 10 10 02-01
- Drop weight test results not available.
5.5-88 Reformatted Per Amendment 02-01 TABLE 5.5-18 PRESSURIZER WELD DATA Material Weld Process Test Number Drop WT @ 20 F (1) Charpy V-Notch FT-LB (1) TestTemp.
( F) Lat. Expansion (Mils) RT NDT F Electrode Flux SFA 5.18 SAW 2755 3970 2 NB 130-127-134 70 59-57-61 10 SFA 5.18 SAW 3864 3970 2 NB 121-111-130 70 80-71-73 10 SFA 5.18 SAW 4113 4553 2 NB 111-114-112 70 84-78-79 10 SFA 5.18 SAW 3882 4080 2 NB 126-126-124 70 61-61-52 10 SFA 5.18 SAW 4098 4553 2 NB 108-106-106 70 80-78-78 10 SFA 5.18 SAW 2881 4080 2 NB 120-138-144 70 93-92-64 10 SFA 5.18 SAW 2755 3561 94-87 10 66-66-61 10 SFA 5.5 SMAW 3418 - 2 NB 210-257-219 70 91-71-80 10 SFA 5.5 SMAW 3991 - 2 NB 73-78-57 70 57-62-41 10 SFA 5.5 SMAW 3415 - 2 NB 82-84-84 70 61-67-61 10 SFA 5.5 SMAW 3419 - 2 NB 91-92-101 70 70-71-76 10 SFA 5.5 SMAW 3401 - - Average 65 10 - 30 SFA 5.5 SMAW 4507 - 2 NB 80-79-74 70 67-76-64 10 SFA 5.5 SMAW 3993 - 2 NB 102-104-100 70 81-77-80 10 SFA 5.5 SMAW 4503 - 2 NB 52-75-76 70 43-61-51 10 SFA 5.5 SMAW 2165 - - Average 52 10 - 30 NOTE:
- 1. Where complete charpy or drop weight data was not obtained, RTNDT was estimated in accordance with the guidelines of MTEB 5-2 and Westinghouse WCAP-7924A, "Basis for Heat-up and Cooldown Curves".
5.5-89 AMENDMENT 97-01 AUGUST 1997 FLYWHEEL UPPER RADIAL BEARING THRUST BEARING MOTOR SHAFT MOTOR STATOR MAIN LEAD CONDUIT BOX LOWER RADIAL BEARING NO,SEAL LEAK OFF'NO 2 SEAL LEAK OFF PUMP SHAFT COOLING WATER INLET DISCHARGE NOZZLE WEIRSUCTI ON NOZZLE THRUST BEAR I NG OIL LIFT PUMP+MOTOR MOTOR UNIT ASSEMBLY SEAL HOUSING NO.I SEAL LEAK OFF FLANGE COOLING WATER OUTLET Iil'I'fHt-Mrl+-4-------
RAD IAL BEAR I NG ASSEMBLY BARRIER AND HEAT EXCHANGER-h'------------CAS I NG
IMPELLER SOUTH CAROLINA ELECTRIC&GAS CO.VIRGIL C.SUMMER NUCLEAR STATION Reactor Coolant Controlled Leakage Pump Figure 5.5-1
SOUTH CAROLINA ELECTRIC&GAS CO.VIRGIL C.SUMMER NUCLEAR STA TlON Reactor Vessel Head Vent System Pipe Support Clamp to CROM Seismic Support Platform Figure 5.5-15 600 500 I-Q300200 100///./
NET 10 20 30 qO 50 60 70 80 90 100II0 SOUTH CAROLINA ELECTRIC&GAS CO.VIRGil C.SUMMER NUCLEAR STATION Reactor Coolant Pump Estimated Performance Characteristic STEA...OUTLETNOZ2l..ETUBESHEET SOUTH CAROLINA ELECTRIC 8<GAS CO.VIRGIL C.SUMMER NUCLEAR STATION Model DEL T A-75 Steam Generator F"i<Jure 5.5-3 AMENDMENT 96-02 JULY 1996
SOUTH CAROLINA ELECTRIC&GAS CO.VIRGIL C.SUMMER NUCLEAR STATION Pressurizer Figure
SOUTH CAROLINA ELECTRIC&GAS CO.VIRGILSUMMER NUCLEAR STATION Reactor Vessel Supports Figure 5.5-7
AMENDMENT 02-01 MAY 2002 SOUTH CAROLINA ELECTRIC AND GAS CO.VIRGIL C.SUMMER NUCLEAR STATION Steam Generator Supports Figure 5.5-8
OF SOUTH CAROLINA ELECTRIC&GAS CO.VIRGIL SUMMER NUCLEAR STATION Reactor Coolant Pump Supports Figure 5.5-9
SOUTH CAROLINA ELECTRIC&GAS CO.VIRGIL SUMMER NUCLEAR STATION Pressurizer Supports Figure 5.5-10
Figure 5.5-11 Deleted By Amendment 95-04 Amendment 95-04 November 1995
Figure 5.5-12 Deleted By Amendment 95-04 Amendment 95-04 November 1995
SOUTH CAROLINA ELECTRIC&GAS CO.VIRGILSUMMER NUCLEAR STATION Reactor Vessel Head Vent System Pipe Support Clamp to Head Lifting Leg Figure 5.5-14
SOUTH CAROLINA ELECTRIC&GAS CO.VIRGIL C.SUMMER NUCLEAR STA TlON Reactor Vessel Head Vent System Pipe Support Clamp to CROM Seismic Support Platform Figure 5.5-15 Upper Cooler Lower I Oil Cooler I No.3 Seal Leakoff No.2 Seal Leakoff No.1 Seal Leakoff Seal 3 Seal 2 Seal 1 , Seal Injection
, Thermal Barrier Heat Exchanger".
/,/,I I ,,SOUTH CAROLINA ELECTRICGAS CO.VIRGILC.SUMMER NUCLEAR STATION RCP Cooling Supplies Figure 5.5 0 16 auJN COO\,IHG
""':;.k--r-""'"t'-\MAS 8CEN IlEL0C-4Tt'OIUUSTR&TlVE PI.lIlPOses.
__
PUMP SHAFT'nJRNlHG"':--+--+------
..P(t..U:JI-I--I----------U.$ING SUCTIOlll lIIIOrzu: SOUTH CAROLINA ELECTRIC&GAS CO.l VIRGILSUMMER NUCLEAR STATION Reactor Coolant Pump Figure 5.5-11 LEA KOFF1 SOUTH CAROLINA ELECTRIC&GAS CO,.VIRGIL C.SUMMER NUCLEAR STATION Seal Flow Diagram Figu 5.5-18
BEARINGSOUTH CAROLINA ELECTRIC&GAS CO.VIRGIL C.SUMMER NUCLEAR STA nON Reactor Coolant Pump Motor I I II I IIu.0 I.IJ::::l I-I.IJ Q..I.IJ.I-TI ME (M I NUTES)..1-.__"'--_---' SOUTH CAROLINA ELECTRIC&GAS CO.VlRGllC.SUMMER NUCLEAR STATION RCP Motor Bearing Heatup Data for loss of CCW Figure 22 21I I I I I IIIIII I II I..I I"..I--19 1817 SOUTH CAROLINA elECTRICGAS CO.VIRGILC.SUMMER NUCLEAR STATION RCP Motor Bearing Heatup Data for Loss of CCW-Details Figure 5.5-21 o<1<10<1 0<10<10<Ct a:l0<1<]0<1(I)1-)1:...J(I)(I)
'"'"....JQ0
'"-'":r::::""0<1 00.......OJ(.).....".::; CI)E I-:::::lI-....:::<Il I-::l.......Cl.EI-....<Il::l l.- I-...Cl.Cl
'-.... LO SOUTH CAROLINA ELECTRIC&GASVIRGil C.SUMMER NUCLEAR STATION Motor Upper Thrust Bearing Temperatures After Termination of Cooling Water Flow Figure 5.5*22 5.6-1Reformatted PerAmendment 99-015.6INSTRUMENTATION REQUIREMENTSProcess control instrumentation is provided for the purpose of acquiring data on thepressurizer and on a per loop basis for the key process parameters of the Reactor Coolant System (including the reactor coolant pump motors), as well as for the Residual Heat Removal System. The pick-off points for the Reactor Coolant System are shown in Figure 5.1-1 (Sheets 1 through 3); and for the Residual Heat Removal System in Figures 5.5-4 and 6.3-1, Sheet. 3. In addition to providing input signals for the protection system and the plant control systems, the instrumentation sensors furnish input signals for monitoring and/or alarming purposes for the following parameters:1.Temperatures 2.Flows 3.Pressures 4.Water levels 5.Valve position In general these input signals are used for the following purposes:
1.Provide input to the reactor trip system for reactor trips as follows:a.Overtemperature Tb.Overpower Tc.Low pressurizer pressure d.High pressurizer pressure e.High pressurizer water level f.Low primary coolant flowIt is noted that the following parameters, which are also sensed so as to generate aninput to the reactor trip system, while not part of the Reactor Coolant System, areincluded here for purposes of completeness:g.Feedwater flowh.Multiple steam generator water level i.Turbine first stage pressure 99-01 5.6-2Reformatted PerAmendment 99-012.Provide input to the Engineered Safety Features Actuation System as follows:a.Pressurizer low pressureIt is noted that the following parameters, which are also sensed so as to generate aninput to the Engineered Safety Features Actuation System, while not part of the ReactorCoolant System, are included here for purposes of completeness:b.High steamline differential pressurec.High steamline flow coincident with lo-lo reactor coolant averagetemperature (T avg)d.High containment pressure e.Low steamline pressure3.Furnish input signals to the non-safety-related systems, such as the plant controlsystems and surveillance circuits so that:a.T avg is maintained within prescribed limits. The resistance temperaturedetector instrumentation is identified on Figure 5.1-1, Sheet 3.b.Pressurizer level control, using T avg to program the setpoint, maintains thecoolant level within prescribed limits.c.Pressurizer pressure is controlled within specified limits.
d.Steam dump control, using T avg control, accommodates sudden loss ofgenerator load.e.Information is furnished to the control room operator and to local stations formonitoring.
5.6-3Reformatted PerAmendment 99-01The following is a functional description of the system instrumentation. Unlessotherwise stated, all indicators, recorders, and alarm annunciators are located in the control room. 1.Temperature Monitoring Instrumentationa.Narrow Range Hot and Cold Leg TemperatureThe hot and cold loop temperature signals required for input to the protectionand control functions are obtained using thermowell mounted RTDs installedin each reactor coolant loop. The hot leg temperature measurement in each loop is accomplished using 3fast response, narrow range, dual element RTDs mounted in thermowells.The hot leg thermowells are located within the 3 scoops previously used for the RTD bypass manifold at locations 120° apart in the cross sectional plane.
The scoops were modified by drilling a flow hole in the top of the scoops sothat water flows in through the existing holes in the leading edge of the scoop, past the RTD, and out through the new drilled hole.Due to temperature streaming, the 3 fast response hot leg RTDs are electronically averaged to generate the hot leg temperature.The cold leg temperature measurements in each loop are accomplished by 1 fast response, narrow range, dual element RTD. The existing cold leg RTDbypass penetration nozzle was modified to accept the thermowell and RTD.
Temperature streaming in the cold leg is not a concern due to the mixing action of the reactor coolant pumpSignals from these instruments are used to compute the reactor coolant T(temperature of the hot leg, T hot, minus the temperature of the cold leg, Tcold)and the T avg. These temperatures are indicated on the main control board foreach loop. In addition, high T avg , T ref deviation, overtemperature setpoint,overpower setpoint, and T setpoint, are recorded on the main control board.b.Cold Leg and Hot Leg TemperaturesTemperature detectors, located in the thermometer wells in the cold and hotleg piping of each loop, supply signals to wide range temperature recordersand indicators for loops A and B on the main control board. This information is used by the operator to control coolant temperature during startup and shutdown.
5.6-4Reformatted PerAmendment 99-01c.Pressurizer TemperatureThere are 2 temperature detectors in the pressurizer, 1 in the steam phaseand 1 in the water phase. Both detectors supply signals to temperatureindicators and high temperature alarms in the control room. The steam phase detector, located near the top of the vessel, is used during startup to determine water temperature when the pressurizer is completely filled withwater. The water phase detector, located at an elevation near the center of the heaters, is used during cooldown when the steam phase detector response is slow due to poor heat transfer.d.Surge Line TemperatureThis detector supplies a signal for a temperature indicator and a low temperature alarm in the control room. Low temperature is an indication thatthe continuous spray rate is too small.e.Safety and Relief Valve Discharge TemperaturesTemperatures in the pressurizer safety and relief valve discharge lines are measured and supply signals for a high temperature alarm and indicator inthe control room. An increase in a discharge line temperature is an indication of leakage through the associated valve.f.Spray Line TemperaturesTemperatures in the spray lines from 2 loops are measured and indicated on the main control board. Alarms from these signals are actuated by low spraywater temperature. Alarm conditions indicate insufficient flow in the spray lines.g.Pressurizer Relief Tank Water TemperatureThe temperature of the water in the pressurizer relief tank is indicated on the main control board. An alarm actuated by high temperature informs theoperator that cooling of the tank contents is required.h.Reactor Vessel Flange Leakoff TemperatureThe temperature in the leakoff line from the reactor vessel flange o-ring seal leakage monitor connections is indicated on the main control board. Anincrease in temperature above ambient is an indication of o-ring seal leakage.
High temperature actuates an alarm.
5.6-5Reformatted PerAmendment 99-01i.Reactor Coolant Pump Motor Temperature Instrumentation(1)Thrust Bearing Upper and Lower Shoes TemperatureResistance temperature detectors are provided with 1 located in theshoe of the upper and 1 in the shoe of the lower thrust bearing.Monitoring of these detectors is provided by the plant computer which actuates a high temperature alarm at the computer.(2)Stator Winding TemperatureThe stator windings contain 6 resistance type detectors, 2 per phase, imbedded in the windings. A signal from 1 of these detectors ismonitored by the plant computer which actuates a high temperature alarm at the computer.(3)Upper and Lower Bearing TemperatureResistance temperature detectors are located 1 in the upper and 1 in the lower radial bearings. Monitoring of these detectors is provided bythe plant computer which actuates a high temperature alarm at the computer.2.Flow Indicationa.Reactor Coolant Loop FlowFlow in each reactor coolant loop is monitored by 3 differential pressure measuring detectors at a piping elbow tap in each reactor coolant loop andindicated on the main control board. These measurements on a 2 out of 3 coincidence circuit provide a low flow signal to actuate a reactor trip. b.Safety Valve FlowAn acoustical type sensor is provided downstream of each safety valve to detect flow through the safety valves. The sensor activates an alarm in thecontrol room when flow is detected. Control room indication is provided to enable the plant operator to determine which valve is open.
5.6-6Reformatted PerAmendment 99-013.Pressure Indicationa.Pressurizer PressureThree (3) pressurizer pressure transmitters provide signals for individualindicators in the control room for actuation of both a low pressure trip and ahigh pressure trip. One (1) of the signals may be selected by the operator for indication on a pressure recorder. Three (3) transmitters provide low pressure signals for safety injection initiation. Three (3) transmitters provide signals for safety injection signal unblock during plant startup. An additional transmitter is used, along with a reference pressure signal, to develop a demand signal for a 3-mode controller. The lower portion of the controller's output range operates the pressurizer heaters. For normal operation, a small group of heaters is controlled by variable power to maintain the pressurizer operating pressure. If the pressure error signal falls towards the bottom of the variable heater control range all pressurizer heaters are turned on.The upper portion of the controller's output range operates the pressurizerspray valves and 1 power relief valve. The spray valves are proportionallycontrolled in a range above normal operating pressure with spray flow increasing as pressure rises. If the pressure rises significantly above the proportional range of the spray valves, a power relief valve (interlocked with a separate transmitter so as to prevent spurious operation) is opened. A further increase in pressure will actuate a high pressure reactor trip. A separate transmitter (interlocked also with another transmitter to prevent spurious operation) provides power relief valve operation for 2 additional valves upon high pressurizer pressure. A signal interlock between transmitter is required to open (or keep open) the power relief valve.b.This item deleted.c.Reactor Coolant Loop PressuresTwo (2) transmitting channels are provided. Both transmitters provide arecorder signal and an indication of reactor coolant pressure on 2 of the hotlegs. These are wide range transmitters which provide pressure indication over the full operating range. The recorder, together with the indicators, serve as a guide to the operator for manual pressurizer heater and spray control and letdown to the Chemical and Volume Control System during plant startup and shutdown. An amplifier signal from the lower portion of the range of one of the channels is indicated on the main control board to provide improved legibility at the lower pressures.The 2 wide range channels provide the permissive signals for the residualheat removal loop suction line isolation valve interlock circuit.
5.6-7Reformatted PerAmendment 99-01d. Pressurizer Relief Tank PressureThe pressurizer relief tank pressure transmitter provides a signal to anindicator and a high pressure alarm in the control room.e.Reactor Coolant Pump Motor Oil Pressure and Level(1)Oil PressurePressure switches are provided on the high pressure oil lift system. Low oil pressure actuates an alarm on the main control board. In addition,an interlock system prevents starting of the pump until the oil lift pump is started manually prior to starting the reactor coolant pump motor and actuates a status light to indicate adequate oil pressure. A local pressure gauge is also provided.(2)Lower Oil Reservoir Liquid LevelA level switch is provided in the motor lower radial bearing oil reservoir.
The switch actuates a high or low level alarm in the control room(3)Upper Oil Reservoir Liquid LevelA level switch is provided in the motor upper radial bearing and thrust bearing oil reservoir. The switch actuates a high or low level alarm inthe control room.4.Liquid Level Indicationa.Pressurizer Water LevelThree (3) pressurizer liquid level transmitters provide signals for use in the Reactor Control and Protection System, the Emergency Core CoolingSystem, and the Chemical and Volume Control System. Each transmitter provides an independent high water level signal that is used to actuate an alarm and a reactor trip. The transmitters also provide independent low water level signals that activate an alarm. Each transmitter also provides a signal for a level indicator that is located on the main control board.
5.6-8Reformatted PerAmendment 99-01In addition to the above, signals may be selected for specific functions asfollows:(1)Any 1 of the 3 level transmitter signals may be selected by the operatorfor display on a level recorder located on the main control board. Thissame recorder is used to display a pressurizer reference liquid levelsignal.(2)Two (2) of the 3 transmitters perform the following functions: (A selectorswitch allows the third transmitter to replace either of these 2.)(a)One (1) transmitter provides a signal which actuates an alarmwhen the liquid level falls to a fixed level setpoint. The samesignal trips the pressurizer heaters "off" and close the letdown line isolation valves.(b)One (1) transmitter supplies a signal to the liquid level controllerfor charging flow control and initiation of a low flow (hi demand)alarm. This signal is compared to the reference level. If the actual level is lower than the reference level, a low alarm is actuated. If the actual level exceeds the reference level, a high level alarm and all pressurizer backup heaters are energized.A fourth independent pressurizer level transmitter that is calibrated for low temperature conditions, provides water level indication on the main controlboard during startup, shutdown and refueling operations.b.Pressurizer Relief Tank LevelThe pressurizer relief tank level transmitter supplies a signal for an indicator on the main control board for high and low level alarms.c.Reactor Vessel LevelThe reactor vessel level system provides a direct reading of reactor vessel level on the main control board which can be used by the operator inconjunction with the core subcooling monitor to identify the possibility of inadequate core cooling conditions. Details of the reactor vessel level system are provided in Section 7.6.9.5.Valve PositionThe pressurizer power operated relief valves are provided with limit switches for safety grade indication of valve open/closed position in the control room.
5.6-9Reformatted PerAmendment 99-016.Core Subcooling IndicationThe core subcooling monitor provides continuous monitoring of the margin tosaturation in the reactor core (i.e., the amount of subcooling) on the main controlboard. The core subcooling monitor utilizes inputs from the hot leg RTDs, ReactorCoolant System pressure sensors, and selected incore thermocouples. Details of the core subcooling monitor system are provided in Section 7.5.5. The Reactor Coolant System design and operating pressure together with thesafety, power relief and pressurizer spray valve setpoints, as well as the protectionsystem setpoint pressures are listed in Table 5.2-7.The design pressure allows for operating transient pressure changes. Theselected design margin considers core thermal lag, coolant transport times andpressure drops instrumentation and control accuracy and response characteristics, and system relief valve characteristics.Process control instrumentation for the Residual Heat Removal System is providedfor the following purposes:a.Furnish input signals for monitoring and/or alarming purposes for:(1)Temperature indications(2)Pressure indications (3)Flow indicationsb.Furnish input signals for control purposes of such processes as follows:(1)Control valve in the residual heat removal pump bypass line so that itopens at flows below a preset limit and closes at flows above a presetlimit.(2)Residual heat removal inlet valves control circuitry. See Section 7.6 forthe description of the interlocks and requirements for automatic closure.(3)Control valve in the residual heat removal heat exchanger bypass line tocontrol temperature of reactor coolant returning to reactor coolant loopsduring plant cooldown.(4)Residual heat removal pump circuitry for starting residual heat removalpumps on "S" signal.
ROTATION
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