NL-16-2280, Vogtle Electric Generating Plant, Units 1 & 2, Updated Final Safety Analysis Report, Section 15.2 Decrease in Heat Removal by the Secondary System, Redacted
Text
VEGP-FSAR-15 REV 14 10/07 TABLE 15.2.3-1 (SHEET 1 OF 5)
TIME SEQUENCE OF EVENTS FOR INCIDENTS WHICH RESULT IN A DECREASE IN HEAT REMOVAL BY THE SECONDARY SYSTEM
Accident Event Time (s) I. Turbine Trip A. With pressurizer control (minimum
reactivity feedback)
Turbine trip; loss of main
feedwater flow 0.0 Initiation of steam release from steam generator safety valves 7.1 Peak pressurizer pressure occurs 8.4 Overtemperature T reactor trip point reached 8.9 Rods begin to drop 10.9 Minimum DNBR occurs 12.1 B. With pressurizer control (maximum
reactivity feedback)
Turbine trip; loss of main
feedwater flow 0.0 Initiation of steam release from steam generator safety valves 7.1 Peak pressurizer pressure occurs 7.1 Low-low steam generator water level reactor trip setpoint reached 40.9 Rods begin to drop 42.9 Minimum DNBR occurs (a)
VEGP-FSAR-15 REV 14 10/07 TABLE 15.2.3-1 (SHEET 2 OF 5)
Accident Event Time (s) I. Turbine Trip C. Without pressurizer control (minimum
reactivity feedback)
Turbine trip; loss of main
feedwater flow 0.0 High pressurizer pressure reactor trip point reached 4.5 Rods begin to drop 6.5 Initiation of steam release from steam generator safety valves 7.0 Peak pressurizer pressure occurs 8.6 Minimum DNBR occurs (a) D. Without pressurizer control (maximum
reactivity feedback)
Turbine trip; loss of main
feedwater flow 0.0 High pressurizer pressure reactor trip point reached 4.5 Rods begin to drop 6.5 Initiation of steam release from steam generator safety valves 7.0 Peak pressurizer pressure occurs 7.4 Minimum DNBR occurs (a) II. Loss of nonemergency ac power to the station
auxiliaries Main feedwater flow stops 10.0 Low-low steam generator water level trip setpoint reached 54.4
VEGP-FSAR-15 REV 14 10/07 TABLE 15.2.3-1 (SHEET 3 OF 5)
Accident Event Time (s) II. Loss of nonemergency ac power to the station
auxiliaries (continued)
Rods begin to drop 56.4 Reactor coolant pumps begin coasting down 58.4 Auxiliary feedwater initiated 114.4 Core decay heat decreases to the auxiliary feedwater heat removal
capacity 1831 Peak pressurizer volume occurs 3465.8 III. Loss of normal feedwater flow Main feedwater flow stops 10.0 Low-low steam generator water
level reactor trip setpoint reached 54.2 Rods begin to drop 56.2 Auxiliary feedwater initiated 114.2 Peak pressurizer volume occurs 3185.6 Core decay heat plus pump
decreases to auxiliary feedwater
heat removal capacity 3294 VEGP-FSAR-15 REV 14 10/07 TABLE 15.2.3-1 (SHEET 4 OF 5)
Accident Event Time (s) IV. Feedwater system pipe break A. With offsite power available Feedwater control system fails 10.0 Pressurizer relief valve setpoint reached 25.5 Low-low steam generator level reactor trip setpoint reached in all
steam generator 66.5 Rods begin to drop and feedline rupture occurs 68.5 Steam generator safety valve setpoint reached in intact steam
generators 70.0 Low steam line pressure setpoint reached in affected steam
generator 110.0 All main steam line isolation valves close 120.0 Auxiliary feedwater is delivered to intact steam generators 126.5 Core decay heat decreases to auxiliary feedwater heat removal
capacity 2500 B. Without offsite power Feedwater control system 10.0 Pressurizer relief valve setpoint reached 25.5
VEGP-FSAR-15 REV 14 10/07 TABLE 15.2.3-1 (SHEET 5 OF 5)
Accident Event Time (s) B Without offsite power (continued)
Low-low steam generator level
reactor trip setpoint reached in
affected steam generator 66.5 Rods begin to drop; power lost to the reactor coolant pumps, feedline rupture occurs 68.5 Steam generator safety valve setpoint reached in intact steam
generators 70.0 Low steam line pressure setpoint reached in affected steam
generator 101.0 All main steam line isolation valves close 111.0 Auxiliary feedwater is delivered to intact steam generators 126.5 Core decay heat decreases to auxiliary feedwater heat removal
capacity 1000
- a. DNBR does not decrease below its initial value.
VEGP-FSAR-15 REV 15 4/09 TABLE 15.2.6-1 (SHEET 1 OF 2)
PARAMETERS USED IN EVALUATING RADIOLOGICAL CONSEQUENCES OF LOSS OF NONEMERGENCY ac POWER (a) I. Source Data A. Core power level (MWt) 3636 Total steam generator tube
leakage (gal/min) 1 Reactor coolant iodine activity
- 1. Accident initiated spike Initial activity equal to the DE of 1.0 µCi/g of I-131 with an iodine spike that increases the rate of
iodine release into the reactor
coolant by a factor of 500. See
table 15A-7.
- 2. Preaccident spike An assumed preaccident iodine spike which has resulted in the DE of 60 µCi/g of I-131 in the reactor coolant. See table 15A-6.
D. Gap activity released to reactor coolant from failed fuel None E. Reactor coolant noble gas activity Based on 1 percent defective fuel.
See table 15A-4.
F. Secondary system initial activity DE of 0.1
µCi/g of I-131.
G. Secondary coolant mass, four generators (g) 1.9 x 108 H. Reactor coolant mass (g) 2.3 x 10 8 I. Offsite power Lost after trip J. Primary-to-secondary leakage duration (h) 20 K. Species of iodine 100 percent elemental
VEGP-FSAR-15 REV 15 4/09 TABLE 15.2.6-1 (SHEET 2 OF 2)
II. Atmospheric Dispersion Factors See table 15A-2.
III. Activity Release Data A. Primary-to-secondary leak rate(gal/min)(b) 1.0 B. Steam released (lb) 0 to 2 h 2 to 8 h 8 to 20 h (c) 555,000 1,365,000 2,730,000 C. Iodine partition factor 0.01
- a. Power is lost at 10 s.
- b. Based on water at 62.4 lb/ft
- 3.
- c. The evaluation has included the impact of a longer time required to cool the plant resulting from the deletion of the RHR suction valve thermal relief (as specified by PS-06-1981). The 20-hour assumption is consistent with the evaluation provided by Westinghouse Electric Corporation when the RHR change was first evaluated.
REV 14 10/07 TURBINE TRIP ACCIDENT WITH PRESSURIZER SPRAY AND POWER-OPERATED RELIEF VALVES, MINIMUM MODERATOR FEEDBACK FIGURE 15.2.3-1
REV 14 10/07 TURBINE TRIP ACCIDENT WITH PRESSURIZER SPRAY AND POWER-OPERATED RELIEF VALVES, MINIMUM MODERATOR FEEDBACK FIGURE 15.2.3-2
REV 14 10/07 TURBINE TRIP ACCIDENT WITH PRESSURIZER SPRAY AND POWER-OPERATED RELIEF VALVES, MAXIMUM MODERATOR FEEDBACK FIGURE 15.2.3-3
REV 14 10/07 TURBINE TRIP ACCIDENT WITH PRESSURIZER SPRAY AND POWER-OPERATED RELIEF VALVES, MAXIMUM MODERATOR FEEDBACK FIGURE 15.2.3-4
REV 14 10/07 TURBINE TRIP ACCIDENT WITHOUT PRESSURIZER SPRAY AND POWER-OPERATED RELIEF VALVES, MINIMUM MODERATOR FEEDBACK FIGURE 15.2.3-5 REV 14 10/07 TURBINE TRIP ACCIDENT WITHOUT PRESSURIZER SPRAY AND POWER-OPERATED RELIEF VALVES, MINIMUM MODERATOR FEEDBACK FIGURE 15.2.3-6
REV 14 10/07 TURBINE TRIP ACCIDENT WITHOUT PRESSURIZER SPRAY AND POWER-OPERATED RELIEF VALVES, MAXIMUM MODERATOR FEEDBACK FIGURE 15.2.3-7
REV 14 10/07 TURBINE TRIP ACCIDENT WITHOUT PRESSURIZER SPRAY AND POWER-OPERATED RELIEF VALVES, MAXIMUM MODERATOR FEEDBACK FIGURE 15.2.3-8
REV 14 10/07 PRESSURIZER PRESSURE AND WATER VOLUME TRANSIENTS FOR LOSS OF OFFSITE POWER FIGURE 15.2.6-1
REV 14 10/07 LOOP TEMPERATURE AND STEAM GENERATOR PRESSURE TRANSIENTS FOR LOSS OF OFFSITE POWER FIGURE 15.2.6-2
REV 14 10/07 PRESSURIZER PRESSURE AND WATER VOLUME TRANSIENTS FOR LOSS OF NORMAL FEEDWATER FIGURE 15.2.7-1
REV 14 10/07 LOOP TEMPERATURE AND STEAM GENERATOR PRESSURE TRANSIENTS FOR LOSS OF NORMAL FEEDWATER FIGURE 15.2.7-2
REV 14 10/07 NUCLEAR POWER TRANSIENT AND CORE HEAT FLUX TRANSIENT FOR MAIN FEEDLINE RUPTURE WITH OFFSITE POWER AVAILABLE FIGURE 15.2.8-1
REV 14 10/07 PRESSURIZER PRESSURE AND WATER VOLUME TRANSIENTS FOR MAIN FEEDLINE RUPTURE WITH OFFSITE POWER AVAILABLE FIGURE 15.2.8-2
REV 14 10/07 REACTOR COOLANT TEMPERATURE TRANSIENTS FOR THE FAULTED AND INTACT LOOPS FOR MAIN FEEDLINE RUPTURE WITH OFFSITE POWER AVAILABLE FIGURE 15.2.8-3
REV 14 10/07 STEAM GENERATOR PRESSURE AND WATER MASS TRANSIENTS FOR MAIN FEEDLINE RUPTURE WITH OFFSITE POWER AVAILABLE FIGURE 15.2.8-4
REV 14 10/07 NUCLEAR POWER AND CORE HEAT FLUX TRANSIENTS FOR MAIN FEEDLINE RUPTURE WITHOUT OFFSITE POWER AVAILABLE FIGURE 15.2.8-5
REV 14 10/07 PRESSURIZER PRESSURE AND WATER VOLUME TRANSIENTS FOR MAIN FEEDLINE RUPTURE WITHOUT OFFSITE POWER AVAILABLE FIGURE 15.2.8-6
REV 14 10/07 REACTOR COOLANT TEMPERATURE TRANSIENTS FOR THE FAULTED AND INTACT LOOPS FOR MAIN FEEDLINE RUPTURE WITHOUT OFFSITE POWER AVAILABLE FIGURE 15.2.8-7
REV 14 10/07 STEAM GENERATOR PRESSURE AND STEAM GENERATOR WATER MASS TRANSIENTS FOR MAIN FEEDLINE RUPTURE WITHOUT OFFSITE POWER AVAILABLE FIGURE 15.2.8-8
VEGP-FSAR-15
15.3-1 REV 15 4/09 15.3 DECREASE IN REACTOR COOLANT SYSTEM FLOWRATE A number of faults which could result in a decrease in the reactor coolant system flowrate are
postulated. These events are discussed in this section. Detailed analyses are presented for the
most limiting of the following flow decrease events: A. Partial loss of forced reactor coolant flow. B. Complete loss of forced reactor coolant flow.
C. Reactor coolant pump shaft seizure (locked rotor).
D. Reactor coolant pump shaft break.
All of the accidents in this section have been analyzed. It has been determined that the most severe radiological consequences will result from the reactor coolant pump shaft seizure
accident discussed in subsection 15.3.3. Therefore, doses are reported only for that limiting
case. 15.3.1 PARTIAL LOSS OF FORCED REACTOR COOLANT FLOW 15.3.1.1 Identification of Causes and Accident Description A partial loss-of-forced-reactor-coolant flow accident can result from a mechanical or electrical failure in an RCP or from a fault in the power supply to the pump or pumps supplied by an RCP
bus. If the reactor is at power at the time of the accident, the immediate effect of the loss-of-
forced-reactor-coolant flow is a rapid increase in the coolant temperature. This increase could
result in DNB with subsequent fuel damage if the reactor does not trip promptly.
Two buses connected to the generators supply power to the pumps. When a generator trip occurs, the buses are automatically transferred to a transformer supplied from external power lines, and the pumps continue to operate. Following any turbine trip where there are no
electrical faults which require tripping the generator from the network, the generator remains
connected to the network for approximately 30 seconds. The RCPs remain connected to the
generator, thus ensuring full flow for approximately 30 seconds after the reactor trip before any
transfer is made.
The low primary coolant flow reactor trip signal, which actuates in any reactor coolant loop by two out of three low-flow signals, provides t he necessary protection against this event. Above permissive P-8, low flow in any loop will actuate a reactor trip. Between approximately 10-
percent power (permissive P-7) and the power level corresponding to permissive P-8, low flow in
any two loops will actuate a reactor trip. Above permissive P-7, two or more RCP circuit
breakers from the same bus will open which will actuate the corresponding undervoltage relays.
This results in a reactor trip which serves as backup to the flow trip.
This is an ANS Condition II incident.
VEGP-FSAR-15
15.3-2 REV 15 4/09 15.3.1.2 Analysis of Effects and Consequences 15.3.1.2.1 Method of Analysis This analysis examines partial loss-of-forced-r eactor-coolant flow involving loss of two pumps with four loops in operation.
This analysis uses three digital computer codes. First the LOFTRAN code (reference 1) calculates the loop and core flow during the transient, the time of reactor trip based on the
calculated flows, the nuclear power transient, and the primary system pressure and temperature transients. The FACTRAN code (reference 2) then calculates the heat flux transient based on
the nuclear power and flow from LOFTRAN. Fina lly, the VIPRE-01 code (section 4.4) calculates the DNBR during the transient based on the heat flux from FACTRAN and flow from LOFTRAN.
The DNBR transients presented represent the minimum of the typical or thimble fuel assembly
cell. This analysis employs RTDP methodology; therefore, the initial conditions assume nominal values of power, reactor coolant average temperature, and RCS average pressure. (See tables
15.0.3-2 and 15.0.3-3.) The limit DNBR includes uncertainties in the initial conditions.
This analysis assumes a conservatively large absolute value of the Doppler-only power coefficient. (See figure 15.0.4-1.) This is equivalent to a total integrated Doppler reactivity from 0 to 100 percent power of 0.016 k. The analysis assumes the most positive moderator temperature coefficient (minimum moderator density coefficient) since this results in the maximum core power during the initial part of the transient when the transient reaches minimum DNBR. (See figure 15.0.4-2.)
These analyses use the curve of trip reactivity insertion versus time (figure 15.0.5-3).
The basis for the flow coastdown analysis is a momentum balance around each reactor coolant loop and across the reactor core. This momentum balance is combined with the continuity equation, a pump momentum balance, and the pump characteristics and is based on high estimates of system pressure losses.
Plant systems and equipment which are necessary to mitigate the effects of the accident are discussed in subsection 15.0.8 and listed in table 15.0.8-1. No single active failure in any of
these systems or equipment w ill adversely affect the consequences of the accident. 15.3.1.2.2 Results Figures 15.3.1-1 through 15.3.1-4 show the transient response for the loss of power to two RCPs with four loops in operation. The reactor trips on the low-flow signal. Figure 15.3.1-4 shows the
DNBR to be always greater than the safety analysis limit value for the most limiting fuel assembly cell.
Since DNB does not occur, the ability of the primary coolant to remove heat from the fuel rod is not significantly reduced. Thus, the average fuel and clad temperature do not increase
significantly above their respective initial values.
The time sequence of events is shown in table 15.3.1-1 for the partial loss of flow event.
The affected reactor coolant pumps will continue to coast down, and the core flow will reach a new equilibrium value. With the reactor tripped, a stable plant condition will eventually be
attained. Normal plant shutdown may then proceed.
VEGP-FSAR-15
15.3-3 REV 15 4/09 15.3.1.3 Conclusions The analysis shows that the minimum DNBR always remains above the limit value during the
transient. Thus, all applicable acceptance criteria are met.
15.3.1.4 References
- 1. Burnett, T. W. T., et al., "LOFTRAN Code Description," WCAP-7907-P-A (Proprietary), WCAP-7907-A (Nonproprietary), April 1984. 2. Hargrove, H. G., "FACTRAN - A FORTRAN-IV Code for Thermal Transients in a UO 2 Fuel Rod," WCAP-7908-A , December 1989. 15.3.2 COMPLETE LOSS OF FORCED REACTOR COOLANT FLOW 15.3.2.1 Identification of Causes and Accident Description A loss-of-forced-reactor-coolant flow may result from a simultaneous loss of electrical power to all RCPs. If the reactor is at power at the time of the accident, the immediate effect of a loss-of-
forced-coolant flow is a rapid increase in the coolant temperature. This increase could result in
DNB with subsequent adverse effects to the fuel if the reactor does not trip promptly. The
reactor trip together with flow sustained by the inertia of the pump impeller will be sufficient to
prevent RCS overpressurization and the DNB R from exceeding the limit values.
Two buses connected to the generators supply power to the pumps. When a generator trip
occurs, the buses are automatically transferred to a transformer supplied from external power lines, and the pumps continue to operate. Following any turbine trip where there are no
electrical faults which require tripping the generator from the network, the generator remains
connected to the network for approximately 30 seconds. The RCPs remain connected to the
generator, thus ensuring full flow for approximately 30 seconds after the reactor trip before any
transfer is made.
The trip systems available to mitigate the consequences of this accident are the following:
- Reactor coolant pump power supply bus undervoltage or underfrequency.
- Low reactor coolant loop flow.
The reactor trip on reactor coolant pump undervoltage is provided to protect against conditions which can cause a loss of voltage to all reactor coolant pumps; i.e., station blackout. This
function is blocked below approximately 10-percent power (permissive P7).
The reactor trip on reactor coolant pump underfrequency is provided to trip the reactor for an underfrequency condition, resulting from frequency disturbances on the power grid. Reference 1
provides analyses of grid frequency disturbances and the resulting nuclear steam supply system
protection requirements which are applicable to the VEGP units.
The reactor trip on low primary coolant loop flow is provided to protect against loss-of-flow
conditions which affect only one reactor coolant loop. This function is generated by two out of
three low flow signals per reactor coolant loop. Above permissive P8, low flow in any loop will
actuate a reactor trip. Between approximately 10-percent power (permissive P7) and the power
level corresponding to permissive P8, low flow in any two loops will actuate a reactor trip. If the VEGP-FSAR-15
15.3-4 REV 15 4/09 maximum grid frequency decay rate is less than appr oximately 2.5 Hz/s, this trip function will protect the core from underfrequency events. This effect is fully described in reference 1.
This is an ANS Condition III incident. 15.3.2.2 Analysis of Effects and Consequences 15.3.2.2.1 Method of Analysis The method of analysis and the assumptions made regarding initial operating conditions and reactivity coefficients are identical to those discussed in subsection 15.3.1, except that following
the loss of power supply to all pumps at power, a reactor trip actuates by either RCP power
supply undervoltage or underfrequency. 15.3.2.2.2 Results Figures 15.3.2-1 through 15.3.2-4 show the transient response for the loss of power to all RCPs with four loops in operation. The reactor trips on the undervoltage signal. Figure 15.3.2-4
shows the DNBR to be always greater than the safety analysis limit value for the most limiting fuel assembly cell.
Since DNB does not occur, the ability of the primary coolant to remove heat from the fuel rod is not significantly reduced. Thus, the average fuel and clad temperature do not increase
significantly above their respective initial values. The RCPs will continue to coast down, and natural circulation flow will eventually be established as demonstrated in subsection 15.2.6. With the reactor tripped, a stable plant condition will be
attained. Normal plant shutdown may then proceed.
Besides the complete loss-of-forced-reactor-coolant flow (loss of power to four pumps), an underfrequency event with a frequency decay rate of 5 Hz/sec was also analyzed. For this
event, the reactor trip occurs on an underfrequency signal. The DNBR analysis of the
underfrequency event verified that the DNBR remains above the safety analysis limit value.
The time sequence of events in shown in table 15.3.1-1 for the complete loss-of-forced-reactor-coolant flow.
15.3.2.3 Conclusions The analysis shows that the minimum DNBR always remains above the limit value during the transient. Thus, the analysis does not predict any adverse fuel effects or clad rupture and all
applicable acceptance criteria are met. The design basis for the DNBR is described in
section 4.4.
15.3.2.4 Reference
- 1. Baldwin, M. S., et al., "An Evaluation of Loss of Flow Accidents Caused by Power System Frequency Transients in Westinghouse PWRs," WCAP-8424 , Revision 1, May 975.
VEGP-FSAR-15
15.3-5 REV 15 4/09 15.3.3 REACTOR COOLANT PUMP SHAFT SEIZURE (LOCKED ROTOR) 15.3.3.1 Identification of Causes and Accident Description For the instantaneous seizure of an RCP rotor, flow through the affected reactor coolant loop is rapidly reduced, leading to a reactor trip on a low flow signal. Following the trip, heat stored in
the fuel rods continues to be transferred into the core coolant, causing the coolant to expand. At
the same time, heat transfer to the shell side of the steam generator reduces, first because the
reduced flow results in a decreased tube side film coefficient and then because the reactor
coolant in the tubes cools down while the shell side temperature increases (turbine steam flow
reduces to zero upon plant trip). The rapid expansion of the coolant in the reactor core, combined with the reduced heat transfer in the steam generator, causes an insurge into the
pressurizer and a pressure increase throughout the RCS. The insurge into the pressurizer
causes a pressure increase, which in turn actuates the automatic spray system, opens the
power-operated relief valves, and opens the pressurizer safety valves in that sequence. The
power-operated relief valves are safety grade and would be expected to function properly during
an accident; however, for conservatism, the analysis does not use the pressure-reducing effect
of the power-operated relief valves and the pressure-reducing effect of the spray.
The analysis of the locked rotor event demonstrates that overpressurization of the RCS does not occur and that the core remains in a coolable geometry.
This is an ANS Condition IV incident. 15.3.3.2 Analysis of Effects and Consequences 15.3.3.2.1 Method of Analysis The analysis of this transient uses two digital computer codes. The LOFTRAN code (reference
- 1) calculates: 1) the resulting loop and core flow transients following the pump seizure; 2) the
time of reactor trip based on the loop flow transients; 3) the nuclear power following reactor trip;
and 4) the peak RCS pressure. The thermal behavior of the fuel located at the core hot spot is
investigated using the FACTRAN code (reference 2) based on the core flow and the nuclear
power calculated by LOFTRAN.
At the beginning of the postulated locked rotor accident (at the time the shaft in one of the RCPs is assumed to seize), the plant is assumed to be in operation under the most adverse steady-
state operating conditions; i.e., maximum guaranteed steady-state thermal power, maximum
steady-state pressure, and maximum steady-state coolant average temperature.
The plant characteristics and the initial conditions are shown in table 15.0.3-2 and table 15.0.3-3.
The analysis evaluates the transient with and without offsite power available.
For the case without offsite power available, power is lost to the unaffected pumps 2 s after reactor trip. (Note: Grid stability analyses show that the grid will remain stable and that offsite
power will not be lost because of a unit trip from 100-percent power. The 2-s delay is a
conservative assumption based on grid stability analyses.)
For the peak pressure evaluation, the initial pressure is conservatively estimated as 50 psi above nominal pressure (2250 psia) to allow for errors in the pressurizer pressure measurement
and control channels. This is done to obtain the highest possible rise in the coolant pressure VEGP-FSAR-15
15.3-6 REV 15 4/09 during the transient. To obtain the maximum pressure in the primary side, conservatively high
loop pressure drops are added to the calculated pressurizer pressure.
Plant systems and equipment which are available to mitigate the effects of the accident are discussed in subsection 15.0.8 and listed in table 15.0.8-1. No single active failure in any of
these systems or equipment w ill adversely affect the consequences of the accident. 15.3.3.2.2 Evaluation of the Pressure Transient After pump seizure, the neutron flux is rapidly reduced by control rod insertion due to reactor trip on low coolant flow in the affected loop. Rod motion begins 1 second after the flow in the
affected loop reaches 87 percent of nominal flow. No credit is taken for the pressure reducing
effect of the pressurizer relief valves, pressurizer spray, steam dump, or controlled feedwater
flow after plant trip. Although these components will operate and will result in a lower peak RCS
pressure, ignoring their effect provides an additional degree of conservatism.
The analysis conservatively bounds the pressurizer safety valves opening at 2500 psia and achieving rated flow at 2575 psia. 15.3.3.2.3 Evaluation of Departure from Nucleate Boiling (DNB) in the Core During the Accident Because DNB occurs in the core for this accident, there is an evaluation of the consequences with respect to fuel rod thermal transients. Results obtained from analyses of this "hot spot" condition represent the upper limit with respect to clad temperature and zirconium-water
reaction.
In the evaluation, the rod power at the hot spot is conservatively assumed to be 2.55 times the average rod power (i.e., F Q = 2.55) at the initial core power level.
A second evaluation is performed for this transient to determine what percentage, if any, of the
fuel rods are expected to experience DNB during the transient. For this evaluation, core
conditions are generated with the LOFTRAN and FACTRAN computer codes and a detailed
DNB analysis is performed with the VIPRE-01 computer code. Results from the VIPRE-01 calculation are then used to determine the percentage of fuel rods which experience DNB.
Table 15.0.3-2 presents the initial conditions assumed for the rods-in-DNB evaluation. 15.3.3.2.4 Film Boiling Coefficient To model the effect of DNB occurring, the FACTRAN code calculates the film boiling coefficient using the Bishop-Sandberg-Tong film boiling correlation. Fluid properties are evaluated at film
temperature (average between wall and bulk temperat ures). The program calculates the film coefficient at every time step based upon the actual heat transfer conditions at the time. The
neutron flux, system pressure, bulk density, and mass flowrate as a function of time are program inputs. This analysis uses the initial values of the pressure and the bulk density throughout the transient since they are the most conservative with respect to clad temperature response. For
conservatism, the analysis assumes DNB to start at the beginning of the accident to maximize
the fuel rod thermal transient.
VEGP-FSAR-15
15.3-7 REV 15 4/09 15.3.3.2.5 Fuel Clad Gap Coefficient The magnitude and time dependence of the heat transfer coefficient between fuel and clad (gap coefficient) have a pronounced influence on the thermal results. The larger the value of the gap
coefficient, the more heat transferred between pellet and clad. Based on investigations of the
effect of the gap coefficient upon the maximum clad temperature during the transient, the
analysis assumes the gap coefficient to increase from a steady-state value consistent with initial fuel temperature to 10,000 Btu/h-ft 2-°F at the initiation of the transient. Thus, the large amount of energy stored in the fuel because of the small initial value releases to the clad at the initiation of the transient. 15.3.3.2.6 Zirconium-Steam Reaction The zirconium-steam reaction can become significant above 1800
°F (clad temperature). In order to take this phenomenon into account, the models (reference 4) introduced the following correlation which defines the rate of the zirconium-steam reaction.
dt)(w d 2 = 33.3 x 10 6 x e-[(45,000.)/(1986 T)
] where: w = amount reacted, mg/cm
- 2. t = time, s. T = temperature, °F. The reaction heat is 1510 cal/g.
The effect of zirconium-steam reaction is included in the calculation of the hot spot clad temperature transient. 15.3.3.2.7 Results The transient results for the locked rotor accident are shown in figures 15.3.3-1 through 15.3.3-4.
Table 15.3.3-1 also summarizes the results of the locked rotor calculations. The peak RCS
pressure reached during the transient is less than that which would cause stresses to exceed
the faulted condition stress limits of the American Society of Mechanical Engineers Code,Section III. Also, the peak clad temperature is considerably less than 2700
°F. Note that the clad temperature was conservatively calculated assuming DNB occurs at the initiation of the transient. These results represent the most limiting conditions of the locked rotor event or RCP
shaft break.
The calculated sequence of events for the locked rotor event is shown in table 15.3.1-1. Figure 15.3.3-1 shows that the core flow rapidly reaches a new equilibrium value (for the case
with offsite power available). With the reactor tripped, a stable plant condition will eventually be
attained. Normal plant shutdown may then proceed.
VEGP-FSAR-15
15.3-8 REV 15 4/09 15.3.3.3 Radiological Consequences The evaluation of the radiological consequences of a postulated seizure of a reactor coolant
pump rotor; i.e., locked rotor accident (LRA), assumes that the reactor has been operating with a
small percent of defective fuel and leaking steam generator tubes for sufficient time to establish
equilibrium concentrations of radionuclides in the reactor coolant and in the secondary coolant.
As a result of the accident, a fraction of the fuel rods will undergo DNB and will release gap
inventory to the reactor coolant. Radionuclides carried by the primary coolant to the steam
generator via leaking tubes are released to the environment via the steam line safety or power-operated relief valves. 15.3.3.3.1 Analytical Assumptions The major assumptions and parameters used in the analysis are itemized in table 15.3.3-2. The
following is a more detailed discussion of the source term. 15.3.3.3.1.1 Source Term Calculations. The concentration of nuclides in the primary and secondary system prior to and following the LRA are determined as follows: A. The iodine activity in the reactor coolant prior to the accident is based upon an iodine spike which has raised the reactor coolant concentration to 60
µCi/g of dose equivalent (DE) I-131. B. The noble gas concentrations in the reactor coolant are based upon 1-percent defective fuel. C. Following the LRA, 5 percent of the fuel rods in the core undergo DNB. Hence, 5 percent of the core iodine and noble gas gap inventory is released to the reactor coolant. D. The secondary coolant iodine activity is based on the DE of 0.1
µCi/g of I-131. 15.3.3.3.1.2 Mathematical Models Used in the Analysis. Mathematical models used in the analysis are described in the following sections: A. The mathematical models used to analyze the activity released during the course of the accident are described in appendix 15A. B. The atmospheric dispersion factors used in the analysis were calculated based on the onsite meteorological measurement programs described in subsection .3.3. C. The thyroid inhalation dose and total-body gamma immersion doses to a receptor at the exclusion area boundary and outer boundary of the low population zone
were analyzed using the models described in appendix 15A. 15.3.3.3.1.3 Identification of Leakage Pathways and Resultant Leakage Activity. Radionuclides carried from the primary coolant to the steam generators via leaking tubes are
released to the environment via the steam line sa fety or power-operated relief valves. Iodines VEGP-FSAR-15
15.3-9 REV 15 4/09 are assumed to mix with the secondary coolant and partition between the generator liquid and
steam before release to the environment. Noble gas es are assumed to be directly released.
All activity is released to the environment with no consideration given to radioactive decay or to cloud depletion by ground deposition during transport to the exclusion area boundary and low population zone. Hence, the resultant radiological consequences represent the most
conservative estimate of the potential intergrated dose due to the postulated LRA. 15.3.3.3.2 Identification of Uncertainties and Conservative Elements in the Analysis A. The initial reactor coolant iodine activity is based on the technical specification limit of 1.0
µCi/g of DE I-I3I which is further increased by a large preaccident iodine spike to 60
µCi/g resulting in equivalent concentrations many times greater than the reactor coolant activities based on 0.12-percent defective fuel and
expected iodine spiking values associated with normal operating conditions. B. The noble gas activities are based on 1-percent defective fuel which cannot exist simultaneously with 1.0-
µCi/g I-131. For iodines, 1-percent defects would be approximately three times the technical specification limit. C. The fraction of failed fuel is assumed to be equal to the fraction of fuel rods experiencing DNB without consideration given to the extent of the zirc-water
reaction. Based on experimental data (3) no oxidation related fuel rod clad failure is predicted. D. A 1-gal/min steam generator primary-to-secondary leakage is assumed, which is significantly greater than that anticipated during normal operation. E. The meteorological conditions which may be present at the site during the course of the accident are uncertain. However, it is highly unlikely that the assumed
meteorological conditions would be present during the course of the accident for
any extended period of time. Therefore, the radiological consequences
evaluated, based on the meteorological conditions assumed, are conservative. 15.3.3.3.3 Conclusions 15.3.3.3.3.1 Filter Loadings. The only engineered safety feature filtration system considered in the analysis which limits the consequences of the LRA is the control room filtration system.
Integrated activity on the control room filters have been evaluated for the more limiting loss-of-coolant accident (LOCA) analysis, as discussed in paragraph 15.6.5.4.6. Since the control room
filters are capable of accommodating the potential design basis LOCA fission product iodine
loadings, there will be sufficient capacity to accommodate any fission product loading due to a
postulated LRA. 15.3.3.3.3.2 Doses to Receptor at the Exclusion Area Boundary and Low Population Zone Outer Boundary. The potential radiological consequences resulting from the occurrence of a postulated LRA have been conservatively analyzed using assumptions and models described.
VEGP-FSAR-15
15.3-10 REV 15 4/09 The total-body gamma dose due to immersion from direct radiation and the thyroid dose due to
inhalation have been analyzed for the 0- to 2-h dose at the exclusion area boundary and for the
duration of the accident (0 to 20 h) at the low population zone outer boundary. The results are listed in table 15.3.3-3. The resultant doses are well within the guideline values of 10 CFR 100.
15.3.3.4 References
- 1. Burnett, T. W. T., et al., "LOFTRAN Code Description," WCAP-7907-P-A (Proprietary), WCAP-7907-A (Nonproprietary), April 1984. 2. Hargrove, H. G., "FACTRAN - A FORTRAN-IV Code for Thermal Transients in a UO 2 Fuel Rod," WCAP-7908-A , December 1989. 3. Van Houten, R., "Fuel Rod Failure as a Consequence of Departure from Nucleate Boiling or Dryout," NUREG-0562, June 1979. 4. Baker, L. and Just, L., "Studies of Metal Water Reactions of High Temperatures, III Experimental and Theoretical Studies of the Zirconium-Water Reacton, ANL-6548 , Argonne National Laboratory, May 1962. 15.3.4 REACTOR COOLANT PUMP SHAFT BREAK 15.3.4.1 Identification of Causes and Accident Description The accident is postulated as an instantaneous failure of a reactor coolant pump shaft, as discussed in section 5.4. Flow through the affected reactor coolant loop is rapidly reduced, though the initial rate of reduction of coolant flow is greater for the reactor coolant pump rotor
seizure event. Reactor trip is initiated on a low-flow signal in the affected loop.
Following initiation of the reactor trip, heat stored in the fuel rods continues to be transferred to the coolant, causing the coolant to expand. At the same time, heat transfer to the shell side of
the steam generators is reduced--first, because the reduced flow results in a decreased tube-
side film coefficient; second, because the reactor coolant in the tubes cools down while the shell-
side temperature increases. (Turbine steam flow is reduced to zero upon plant trip.) The rapid
expansion of the coolant in the reactor core, combined with reduced heat transfer in the steam
generators, causes an insurge into the pressurizer and a pressure increase throughout the
reactor coolant system. The insurge into the pressurizer compresses the steam volume, actuates the automatic spray system, opens the power-operated relief valves, and opens the
pressurizer safety valves, in that sequence. The two power-operated relief valves are designed
for reliable operation and would be expected to function properly during the accident. However, for conservatism, their pressure-reducing effect, as well as the pressure-reducing effect of the
spray, is not included in the analysis.
This is an ANS Condition IV incident.
15.3.4.2 Conclusion The consequences of a locked rotor (subsection 15.3.3) represent the most limiting event with respect to the locked rotor or the pump shaft break. With a failed shaft, the impeller could
conceivably be free to spin in a reverse direction as opposed to being fixed in position as VEGP-FSAR-15
15.3-11 REV 15 4/09 assumed in the locked-rotor analysis. However, the net effect on core flow is negligible, resulting in only a slight decrease in the end point (steady-state) core flow. For both the shaft
break and locked-rotor incidents, reactor trip occurs very early in the transient. In addition, the
locked-rotor analysis conservatively assumes that departure from nucleate boiling occurs at the
beginning of the transient.
VEGP-FSAR-15 REV 14 10/07 TABLE 15.3.1-1 (SHEET 1 OF 2)
TIME SEQUENCE OF EVENTS FOR INCIDENTS WHICH RESULT IN A DECREASE IN REACTOR COOLANT SYSTEM FLOWRATE
Accident Event Time (s) Partial loss of forced reactor
coolant flow Loss of two pumps with four loops in operation Coastdown begins 0.0 Low-flow reactor trip 1.4 Rods begin to drop 2.4 Minimum DNBR occurs 3.6 Complete loss of forced reactor
coolant flow Loss of four pumps with four loops in operation All operating pumps lose power and begin
coasting down 0.0 Reactor coolant pump undervoltage trip point
reached 0.0 Rods begin to drop 1.5 Minimum DNBR occurs 3.2 Reactor coolant pump shaft
seizure (locked rotor)
One locked rotor with four loops in operation with
offsite power available Rotor on one pump locks 0.0 Low-flow trip point reached 0.0 Rods begin to drop 1.0 VEGP-FSAR-15 REV 14 10/07 TABLE 15.3.1-1 (SHEET 2 OF 2)
Accident Event Time (s) Maximum reactor coolant system pressure occurs 3.3 Maximum clad average temperature occurs 3.5 One locked rotor with four
loops in operation without
offsite power available Rotor on one pump locks 0.0 Low-flow trip point reached 0.0 Rods begin to drop 1.0 Maximum reactor coolant system pressure occurs 3.4 Maximum clad average temperature occurs 3.6
VEGP-FSAR-15 REV 14 10/07 TABLE 15.3.3-1
SUMMARY
OF RESULTS FOR LOCKED ROTOR TRANSIENTS (FOUR LOOPS OPERATING INITIALLY)
With Offsite Power Available Without Offsite Power Available Maximum RCS pressure (psia) 2669 2669 Maximum clad average temperature, core hot spot (°F) 2048 2054 Zr-H 2 O reaction, core hot spot (percent by weight) 0.6 0.7
REV 14 10/07 FLOW TRANSIENTS FOR FOUR LOOPS IN OPERATION, TWO PUMPS COASTING DOWN FIGURE 15.3.1-1
REV 14 10/07 NUCLEAR POWER AND PRESSURIZER PRESSURE TRANSIENTS FOR FOUR LOOPS IN OPERATION, TWO PUMPS COASTING DOWN FIGURE 15.3.1-2
REV 14 10/07 AVERAGE AND HOT CHANNEL HEAT FLUX TRANSIENTS FOR FOUR LOOPS IN OPERATION, TWO PUMPS COASTING DOWN FIGURE 15.3.1-3
REV 14 10/07 DNBR VERSUS TIME FOR FOUR LOOPS IN OPERATION, TWO PUMPS COASTING DOWN FIGURE 15.3.1-4
REV 14 10/07 FLOW TRANSIENTS FOR FOUR LOOPS IN OPERATION, FOUR PUMPS COASTING DOWN FIGURE 15.3.2-1 REV 17 4/12 NUCLEAR POWER AND PRESSURIZER PRESSURE TRANSIENTS FOR FOUR LOOPS IN OPERATION, FOUR PUMPS COASTING DOWN FIGURE 15.3.2-2
REV 14 10/07 AVERAGE AND HOT CHANNEL HEAT FLUX TRANSIENTS FOR FOUR LOOPS IN OPERATION, FOUR PUMPS COASTING DOWN FIGURE 15.3.2-3
REV 14 10/07 DNBR VERSUS TIME FOR FOUR LOOPS IN OPERATION, FOUR PUMPS COASTING DOWN FIGURE 15.3.2-4
REV 14 10/07 FLOW TRANSIENTS FOR FOUR LOOPS IN OPERATION, (ONE LOCKED ROTOR WITH OFFSITE POWER AVAILABLE)
FIGURE 15.3.3-1 (SHEET 1 OF 2)
REV 14 10/07 FLOW TRANSIENTS FOR FOUR LOOPS IN OPERATION, (ONE LOCKED ROTOR WITHOUT OFFSITE POWER AVAILABLE)
FIGURE 15.3.3-1 (SHEET 2 OF 2)
REV 14 10/07 PEAK REACTOR COOLANT PRESSURE FOR FOUR LOOPS OPERATION (ONE LOCKED ROTOR WITH OFFSITE POWER AVAILABLE)
FIGURE 15.3.3-2 (SHEET 1 OF 2)
REV 14 10/07 PEAK REACTOR COOLANT PRESSURE FOR FOUR LOOPS IN OPERATION (ONE LOCKED ROTOR WITHOUT OFFSITE POWER AVAILABLE FIGURE 15.3.3-2 (SHEET 2 OF 2)
REV 14 10/07 AVERAGE AND HOT CHANNEL HEAT FLUX TRANSIENTS FOR FOUR LOOPS IN OPERATION (ONE LOCKED ROTOR WITH OFFSITE POWER AVAILABLE)
FIGURE 15.3.3-3 (SHEET 1 OF 2)
REV 14 10/07 AVERAGE AND HOT CHANNEL HEAT FLUX TRANSIENTS FOR FOUR LOOPS IN OPERATION (ONE LOCKED ROTOR WITHOUT OFFSITE POWER AVAILABLE)
FIGURE 15.3.3-3 (SHEET 2 OF 2)
REV 14 10/07 NUCLEAR POWER AND MAXIMUM CLAD TEMPERATURE AT HOT SPOT TRANSIENTS FOR FOUR LOOPS IN OPERATION (ONE LOCKED ROTOR WITH OFFSITE POWER AVAILABLE)
FIGURE 15.3.3-4 (SHEET 1 OF 2)
REV 14 10/07 NUCLEAR POWER AND MAXIMUM CLAD TEMPERATURE AT HOT SPOT TRANSIENTS FOR FOUR LOOPS IN OPERATION (ONE LOCKED ROTOR WITHOUT OFFSITE POWER AVAILABLE)
FIGURE 15.3.3-4 (SHEET 2 OF 2)
VEGP-FSAR-15
15.4-1 REV 19 4/15 15.4 REACTIVITY AND POWER DISTRIBUTION ANOMALIES Several postulated faults can result in reactivity and power distribution anomalies. Control rod
motion, control rod ejection, boron concentration changes, or addition of cold water to the RCS
results in reactivity changes. Control rod motion, control rod misalignment, control rod ejection, or fuel assembly mislocation results in power distribution changes. This section discusses
these events. Detailed analyses are presented for the most limiting of these events.
This section presents the following incidents:
- Uncontrolled rod cluster control assembly (RCCA) bank withdrawal from a subcritical or low-power startup condition.
- Uncontrolled RCCA bank withdrawal at power.
- RCCA misalignment.
- Startup of an inactive reactor coolant pump at an incorrect temperature.
- A malfunction or failure of the flow controller in a boiling water reactor recirculation loop that results in an increased reactor coolant flowrate (not applicable to VEGP).
- Chemical and volume control system malfunction that results in a decrease in the boron concentration in the reactor coolant.
- Inadvertent loading and operation of a fuel assembly in an improper position.
- Spectrum of RCCA ejection accidents.
- Steamline break with coincidental RCCA bank withdrawal at power.
All of the accidents in this section have been analyzed. The most severe radiological consequences result from the complete rupture of a control rod drive mechanism housing
provided in subsection 15.4.8; therefore, radiological consequences are reported only for that
limiting case. 15.4.1 UNCONTROLLED ROD CLUSTER CONTROL ASSEMBLY BANK WITHDRAWAL FROM A SUBCRITICAL OR LOW-POWER STARTUP CONDITION 15.4.1.1 Identification of Causes and Accident Description An RCCA withdrawal incident is an uncontrolled addition of reactivity to the reactor core caused by withdrawal of RCCA banks resulting in a power excursion. While the occurrence of a
transient of this type is highly unlikely, a malfunction of the control rod drive system can cause
such a transient. This could occur with the reactor either subcritical, low power startup, or at
power. Subsection 15.4.2 discusses the "at power" case.
VEGP-FSAR-15
15.4-2 REV 19 4/15 RCCA bank withdrawal adds reactivity at a prescribed and controlled rate to bring the reactor
from a subcritical condition to a low power level during startup. Although the initial startup
procedure uses the method of boron dilution, the normal startup is with RCCA bank withdrawal.
RCCA bank motion can cause much faster changes in reactivity than can be made by changing
boron concentration.
The control rod drive mechanisms wire into preselected banks which remain unchanged during the core life. The circuit design is such that RCCAs cannot be withdrawn in other than their
proper withdrawal sequence. Control of the power supplied to the rod banks is such that no
more than two banks can be withdrawn at any time. The RCCA drive mechanism is the
magnetic latch type, and the coil actuation sequencing provides variable speed travel. The
analysis of the maximum reactivity insertion rate includes the assumption of the simultaneous
withdrawal of the two sequential banks having the maximum combined worth at maximum
speed. The neutron flux response to a continuous reactivity insertion is characterized by a fast rise terminated by the reactivity feedback effect of the negative Doppler coefficient. This self-limitation of the power excursion is of primary im portance since it limits the power to a tolerable level during the delay time for protective action. Should a continuous control rod assembly
withdrawal initiate, the transient will terminate by the following reactor trip functions:
- Source range high neutron flux reactor trip is actuated when either of two independent source range channels indicates a flux level above a preselected, manually adjustable setpoint. This trip function may be manually bypassed when the intermediate range flux channel indicates a flux level above the source range cutoff
level. It is automatically reinstated when both intermediate range channels indicate a
flux level below a specified setpoint.
- Intermediate range high neutron reactor flux trip is actuated when either of two independent intermediate range channels indicates a flux level above a preselected, manually adjustable setpoint. This trip function may be manually bypassed when two of the four power range channels are reading above approximately 10 percent of
full power/flux level and is automatically reinstated when three of the four power
range channels indicate a power/flux level below this setpoint.
- Power range high neutron flux reactor trip (low setting) is actuated when two out of the four power range channels indicate a flux level above approximately 25 percent
of full power/flux level. This trip func tion may be manually bypassed when two of the
four power range channels indicate a flux level above approximately 10 ercent of full
power/flux level and is automatically reinstated when three of the four channels
indicate a power/flux level below this setpoint.
- Power range high neutron flux reactor trip (high setting) is actuated when two out of the four power range channels indicate a flux level above a preset setpoint. This trip
function is always active.
- High neutron flux rate reactor trip is actuated when the positive rate of change of neutron flux on two out of four nuclear power range channels indicates a rate above
the preset setpoint. It is always active.
In addition, control rod stops on high intermediate range flux (one out of two) and high power
range flux (one out of four) serve to cease rod withdrawal and prevent the need to actuate the
intermediate range flux trip and the power range flux trip, respectively.
VEGP-FSAR-15
15.4-3 REV 19 4/15 This is an ANS Condition II incident. 15.4.1.2 Analysis of Effects and Consequences 15.4.1.2.1 Method of Analysis The following three stages comprise the analysis of the uncontrolled RCCA bank withdrawal from subcritical accident: first, an average core nuclear power transient calculation; then, an
average core heat transfer calculation; and finally, the DNBR calculation. The spatial neutron
kinetics computer code TWINKLE (reference 1) performs the average core calculation to
determine the average power generation with time including the various total core feedback
effects; i.e., Doppler reactivity and moderator reactivity. FACTRAN (reference 2) performs a
fuel rod transient heat transfer calculation to determine the average heat flux and temperature
transients. The average heat flux is next used in VIPRE-01 (section 4.4) for transient DNBR
calculations.
In order to give conservative results for a startup incident, the following additional assumptions are made concerning the initial reactor conditions: A. Since the magnitude of the neutron flux peak reached during the initial part of the transient for any given rate of reactivity insertion is strongly dependent on the
Doppler power reactivity coefficient, t he analysis employs a conservatively low value for Doppler power defect (-998 pcm). B. The contribution of the moderator reactivity coefficient is negligible during the initial part of the transient because the heat transfer time constant between the
fuel and the moderator is much longer than the neutron flux response time
constant; however, after the initial neutron flux peak, the moderator temperature
reactivity coefficient affects the succeeding rate of power increase. The analysis assumes a moderator temperature coefficient which is +7 pcm/
°F at the zero power nominal temperature. C. The analysis assumes the reactor to be at hot zero power (557
°F). This assumption is more conservative than that of a lower initial system temperature.
The higher initial system temperature yields a larger fuel-to-water heat transfer
coefficient, a larger fuel-specific heat, and a less-negative (smaller absolute
magnitude) Doppler coefficient; these reduce the Doppler feedback effect, thereby increasing the neutron flux peak. The high neutron flux peak combined
with a high fuel specific eat and larger heat transfer coefficient yields a larger
peak heat flux. The analysis assumes the initial effective multiplication factor (k eff) to be 1.0 since this results in the maximum neutron flux peak. D. The most adverse combination of instrumentation error, setpoint error, delay for trip signal actuation, and delay for control rod assembly release is taken into
account. The analysis assumes a 10-percent increase in the power range flux
trip setpoint, raising it from the nominal value of 25 percent to a value of 35
percent and not taking any credit for the source and intermediate range
protection. Figure 15.4.1-1 shows that the rise in nuclear flux is so rapid that the
effect of error in the trip setpoint on the actual time at which the rods release is
negligible. Besides the above, the assumption that the highest worth control rod
assembly is stuck in its fully withdrawn position is the basis of the rate of negative
reactivity insertion corresponding to the reactor trip.
VEGP-FSAR-15
15.4-4 REV 19 4/15 E. The maximum positive reactivity insertion rate assumed is greater than that for the simultaneous withdrawal of the two sequential control banks having the
greatest combined worth at maximum speed (45 in./min). F. The DNB analysis assumes the most limiting axial and radial power shapes associated with having the two highest combined worth banks in their high-worth
position. G. The analysis assumes the initial power level to be below the power level expected for any shutdown condition (10
-9 fraction of nominal power). The combination of highest reactivity insertion rate and low initial power produces the
highest peak heat flux. H. The analysis assumes two RCPs to be in operation (Mode 3 Technical Specification allowed operation). This is conservative with respect to the DNB
The accident analysis employs the STDP with the initial conditions shown in tables 15.0.3-2
and 5.0.3-3.
Plant systems and equipment which are available to mitigate the effects of the accident are discussed in subsection 15.0.8 and listed in table 15.0.8-1. No single active failure in any of
these systems or components w ill adversely affect the consequences of the accident. 15.4.1.2.2 Results Figures 15.4.1-1 through 15.4.1-3 show the transient behavior for the uncontrolled RCCA bank withdrawal incident, with the accident terminated by reactor trip at 35 percent of nominal power.
The reactivity insertion rate used is greater than that calculated for the two highest worth
sequential control banks, both assumed to be in their highest incremental worth region.
Figure 15.4.1-1 shows the average neutron flux transient.
The energy release and the fuel temperature increas es are relatively small. The thermal flux response, of interest for DNB considerations, is shown on figure 15.4.1-2. The beneficial effect of the inherent thermal lag in the fuel is evidenced by a peak heat flux much less than the full-
power nominal value. There is margin to DNB during the transient. Figure 15.4.1-3 shows the
response of the hot spot average fuel and clad inner temperatures. The minimum DNBR at all
times remains above the limiting value.
The calculated sequence of events for this accident is shown on table 15.4.1-1. With the reactor tripped, the plant returns to a stable condition. The plant may subsequently be cooled
down further by following normal plant shutdown procedures.
15.4.1.3 Conclusions In the event of an RCCA withdrawal accident from the subcritical condition, the core and the RCS are not adversely affected, since the combination of thermal power and the coolant
temperature results in a DNBR greater than the limiting value. The DNBR design basis is
described in section 4.4; applicable acceptance criteria have been met.
VEGP-FSAR-15
15.4-5 REV 19 4/15 15.4.1.4 References 1. Risher, D. H., Jr., and Barry, R. F., "TWINKLE--A Multi-Dimensional Neutron Kinetics Computer Code," WCAP-7979-P-A (Proprietary) and WCAP-8028-A (Nonproprietary), January 1975. 2. Hargrove, H. G., "FACTRAN--A FORTRAN-IV Code for Thermal Transients in a UO 2 Fuel Rod," WCAP-7908-A, December 1989. 15.4.2 UNCONTROLLED ROD CLUSTER CONTROL ASSEMBLY BANK WITHDRAWAL AT POWER 15.4.2.1 Identification of Causes and Accident Description An uncontrolled RCCA withdrawal at power results in an increase in core heat flux. Since the
heat extraction from the steam generator lags behind the core power generation until the steam generator pressure reaches the relief or safety valve setpoint, there is a net increase in the
reactor coolant temperature. Unless terminat ed by manual or automatic action, the power mismatch and resultant coolant temperature rise could eventually result in DNB; therefore, to avert damage to the fuel clad the reactor protection system is designed to terminate any such
transient before DNBR falls below the safety analysis limit.
The automatic features of the reactor protec tion system which prevent core damage in an RCCA bank withdrawal incident at power include the following:
- Power range neutron flux instrumentation actuates a reactor trip on high neutron flux if two out of four channels exceed an overpower setpoint.
- Reactor trip actuates if any two out of four T channels exceed an OTT setpoint.
This setpoint is automatically varied with axial power distribution, coolant average temperature, and coolant average pressure to protect against DNB.
- Reactor trip actuates if any two out of four T channels exceed an OPT setpoint.
This setpoint is automatically varied with coolant average temperature so that the allowable heat generation rate (kW/ft) is not exceeded.
- A high pressurizer pressure reactor trip, actuated from any two out of four pressure channels, is set at a fixed point. This set pressure is less than the set pressure for
the pressurizer safety valves.
- Any two out of three level channels when the reactor power is above approximately 10 percent (permissive P-7) will actuate a high pressurizer water level reactor trip.
- Power range neutron flux instrumentation actuates a reactor trip if two out of four channels exceed a specified positive flux rate. (This trip is credited for the RCS
overpressure limit. It is not credited in the reactor core protection analyses.)
Besides the above listed reactor trips, there are the following RCCA withdrawal blocks:
- High neutron flux (one out of four).
VEGP-FSAR-15
15.4-6 REV 19 4/15
- OPT (two out of four).
- OTT (two out of four).
The manner in which the combination of OPT and OTT trips provide protection over the full range of RCS conditions is described in chapter 7. Figure 15.0.6-1 presents allowable reactor coolant loop average temperature and T for the design power distribution and flow as a
function of primary coolant pressure. The boundaries of operation defined by the OPT and OTT trip are represented as "protection lines" on this diagram. The protection lines are drawn to include all adverse instrumentation and setpoint errors so that under nominal conditions trip would occur well within the area bounded by these lines. The utility of this diagram is in the fact
that the limit imposed by any given DNBR c an be represented as a line. The DNB lines
represent the locus of conditions for which the DNBR equals the safety analysis limit. All points
below and to the left of a DNB line for a given pressure have a DNBR greater than the safety
analysis limit. The diagram shows that DNB is prevented for all cases if the area enclosed with
the maximum protection lines is not traversed by the applicable DNBR line at any point.
The area of permissible operation (power, pressure, and temperature) is bounded by the combination of reactor trips:
- High neutron flux (fixed setpoint).
- High pressure (fixed setpoint).
- Low pressure (fixed setpoint).
- OPT and OTT (variable setpoints).
The purpose of this analysis is to demonstrate the manner in which the above protective
systems function for various reactivity insertion ra tes from different initial conditions to prevent fuel damage. Reactivity insertion rates and initial conditions influence which protection function
actuates first.
Reference 3 documents that a conservative analysis has been performed, assuming the reactor trip listed in table 15.0.6-1, that ensures that the RCS overpressure limit will not be exceeded for
an uncontrolled rod withdrawal during power operation.
This is an ANS Condition II incident. 15.4.2.2 Analysis of Effects and Consequences 15.4.2.2.1 Method of Analysis This transient is analyzed by the LOFTRAN code (reference 1). This code simulates the neutron kinetics, RCS, pressurizer, pressurizer relief and safety valves, pressurizer spray, steam generator, and steam generator safety va lves. The code computes pertinent plant variables including temperatures, pressures, and power level. The core limits as illustrated in
figure 15.0.6-1 are used as input to LOFTRAN to determine the minimum DNBR during the
VEGP-FSAR-15
15.4-7 REV 19 4/15 The analysis of this accident uses the RTDP described in reference 2. Subsection 15.0.3
discusses the plant characteristics and initial conditions. For an uncontrolled RCCA bank
withdrawal at power accident, the analysis assumes the following conservative assumptions: A. Nominal values form the basis of the initial reactor power, pressure, and RCS temperature assumption. The limit DNBR includes uncertainties in initial
conditions as described in reference 2. B. Reactivity coefficients -- two cases analyzed: 1. A +7 pcm/
°F moderator temperature coefficient of reactivity and a least-negative Doppler-only power coefficient form the basis of the beginning-
of-life minimum reactivity feedback assumption. 2. A conservatively large positive moderator density coefficient (corresponding to a large negative moderator temperature coefficient)
and a most-negative Doppler-only power coefficient form the basis of the
end-of-life maximum reactivity feedback assumption. C. A conservative value of 118 percent of nominal full core power actuates the reactor trip on high neutron flux. The T trips include all adverse instrumentation and setpoint errors while maximum values form the basis of the delays for the trip
signal actuation assumption. D. The assumption that the highest worth assembly is stuck in its fully withdrawn position forms the basis of the RCCA trip insertion characteristic. E. The analysis examines a range of reactivity insertion rates. The maximum positive reactivity insertion rate is greater than that for the simultaneous
withdrawal of the two control banks having the maximum combined worth at
maximum speed assuming normal overlap.
The effect of RCCA movement on the axial core power distribution is accounted for by causing a decrease in OTT trip setpoint proportional to a decrease in margin to DNB.
Plant systems and equipment which are available to mitigate the effects of the accident are discussed in subsection 15.0.8 and listed in table 15.0.8-1. No single active failure in any of
these systems or equipment w ill adversely offset the consequences of the accident. A
discussion of anticipated transients without trip considerations is presented in section 15.8. 15.4.2.2.2 Results Figures 15.4.2-1 through 15.4.2-3 show the transient response for a rapid RCCA bank withdrawal incident starting from full power with minimum feedback. Reactor trip on high
neutron flux occurs shortly after the start of the accident. Because of the rapid reactor trip with
respect to the thermal time constants of the plant, small changes in Tavg and pressure result, and the margin to DNB is maintained.
The transient response for a slow RCCA withdrawal from full power with minimum feedback is shown in figures 15.4.2-4 through 15.4.2-6. Reactor trip on OTT occurs after a longer period and the rise in temperature and pressure is consequently larger than for rapid RCCA bank withdrawal. Again, the minimum DNBR is greater than the safety analysis limit.
Figure 15.4.2-7 shows the minimum DNBR as a function of reactivity insertion rate from initial full-power operation for both minimum and maximum reactivity feedback. It can be seen that the two reactor trip functions (high neutron flux and OTT functions) provide DNB protection VEGP-FSAR-15
15.4-8 REV 19 4/15 over the whole range of reactivity insertion rates. The minimum DNBR is always greater than
the safety analysis limit.
Figures 15.4.2-8 and 15.4.2-9 show the minimum DNBR as a function of reactivity insertion rate for RCCA withdrawal incidents starting at 60- and 10-percent power, respectively. The results
are similar to the 100-percent power case; howev er, as the initial power decreases, the range over which the OTT trip is effective is increased. In neither case does the DNBR fall below the safety analysis limit.
The shape of the curves of minimum DNBR versus reactivity insertion rate in the referenced figures is due both to reactor core and coolant system transient response and to protection system action initiating a reactor trip.
Referring to figure 15.4.2-8, for example, it is noted that: A. For high reactivity insertion rates; i.e., between approximately 1.5 x 10
-4 k/s and 1.0 x 10-3 k/s, reactor trip is initiated by the high neutron flux trip for the minimum reactivity feedback cases. The neutron flux level in the core rises rapidly for these insertion rates while core heat flux and coolant system
temperature lag behind due to the thermal capacity of the fuel and coolant
system fluid. Thus, the reactor is tripped prior to significant increase in heat flux
or water temperature with resultant high minimum DNBRs during the transient.
As reactivity insertion rate decreases, core heat flux and coolant temperatures
can remain more nearly in equilibrium with the neutron flux; minimum DNBR
during the transient thus decreases with decreasing insertion rate. B. The OTT reactor trip circuit initiates a reactor trip when measured coolant loop T exceeds a setpoint based on measured RCS average temperature and
pressure. This trip circuit is described in detail in chapter 7; however, it is
important in this context to note that the average temperature contribution to the
circuit is lead-lag compensated to decrease the effect of the thermal capacity of
the RCS in response to power increases. C. With further decrease in reactivity insertion rate, the OTT and high neutron flux trips become equally effective in terminat ing the transient; e.g., at approximately 1.5 x 10-4 k/s reactivity insertion rate. For reactivity insertion rates between approximately 1 x 10
-4 k/s and approximately 2 x 10
-5 k/s, the effectiveness of the OTT trip increases (in terms of increased minimum DNBR) due to the fact that with lower insertion rates the power increase rate is slower, the rate of rise of average coolant temperature is slower, and the system lags and delays become
less significant. D. Referring to figure 15.4.2-9, it is shown that for reactivity insertion rates less than approximately 5 x 10
-5 k/s, the rise in the reactor coolant temperature is sufficiently high so that the steam generator safety valve setpoint is reached prior
to trip in the minimum feedback case. Opening of these valves, which act as an
additional heat load of the RCS, sharply decreases the rate of increase of RCS
average temperature. This decrease in rate of increase of the average coolant
system temperature during the transient is accentuated by the lead-lag compensation, causing the OTT trip setpoint to be reached later, with resulting lower minimum DNBRs.
For transients initiated from higher power levels (for example, see figure 15.4.2-7) this effect, described in item D above, which results in the sharp peak in minimum DNBR at approximately VEGP-FSAR-15
15.4-9 REV 19 4/15 3 x 10-5 k/s, does not occur since the steam generator safety valves are never actuated prior to trip. Figures 15.4.2-7, 15.4.2-8, and 15.4.2-9 illustrate minimum DNBR calculated for minimum and maximum reactivity feedback.
Since the RCCA withdrawal at power incident is an overpower transient, the fuel temperatures rise during the transient until after reactor trip occurs. For high reactivity insertion rates, the
overpower transient is fast with respect to the fuel rod thermal time constant and the core heat
flux lags behind the neutron flux response. Due to this lag, the peak core heat flux does not
exceed 118 percent of its nominal value; i.e., the high neutron flux trip setpoint assumed in the
analysis. Taking into account the effect of the RCCA withdrawal on the axial core power
distribution, the peak fuel temperature will still remain below the fuel melting temperature.
For slow reactivity insertion rates, the core heat flux remains more nearly in equilibrium with the neutron flux. The overpower transient is terminated by the OTT reactor trip before a DNB condition is reached. The peak heat flux again is maintained below 118 percent of its nominal
value. Taking into account the effect of the RCCA withdrawal on the axial core power
distribution, the peak fuel centerline temperature will remain below the fuel melting temperature.
The reactor is tripped sufficiently fast during the RCCA bank withdrawal at power transient to ensure that the ability of the primary coolant to remove heat from the fuel rods is not reduced.
Thus, the fuel cladding temperature does not rise significantly above its initial value during the
The calculated sequence of events for this accident is shown on table 15.4.1-1. With the reactor tripped, the plant eventually returns to a stable condition. The plant may subsequently
be cooled down further by following normal plant shutdown procedures.
15.4.2.3 Conclusions The high neutron flux and OTT trip channels provide adequate protection over the entire range of possible reactivity insertion rates; i.e., the minimum value of DNBR is always larger than the limiting value. 15.4.2.4 References 1. Burnett, T. W. T., et al., "LOFTRAN Code Description," WCAP-7907-P-A (Proprietary), WCAP-7907-A (Nonproprietary), April 1984. 2. Friedland, A. J. and Ray, S., "Revised Thermal Design Procedure," WCAP-11397-P-A (Proprietary), April 1989. 3. Westinghouse letter (GP-18572 dated October 14, 2009, "Transmittal of Results and Recommendations Regarding Rod Withdrawal at Power RCS Overpressurization."
VEGP-FSAR-15
15.4-10 REV 19 4/15 15.4.3 ROD CLUSTER CONTROL ASSEMBLY MISALIGNMENT (SYSTEM MALFUNCTION OR OPERATOR ERROR) 15.4.3.1 Identification of Causes and Accident Description RCCA misoperation accidents include the following:
- One or more dropped RCCAs within the same group.
- A dropped RCCA bank.
- Statically misaligned RCCA.
- Withdrawal of a single RCCA.
Each RCCA has a position indicator channel which displays the position of the assembly in a
display grouping that is convenient to the operator. Fully inserted assemblies are also indicated
by a rod at bottom signal which actuates a local alarm and a control room annunciator. Group
demand position is also indicated.
RCCAs move in preselected banks, and the banks move in the same preselected sequence.
Each bank of RCCAs consists of two groups. The rods comprising a group operate in parallel
through multiplexing thyristors. The two groups in a bank move sequentially such that the first
group is always within one step of the second group in the bank. A definite schedule of
actuation (or deactuation of the stationary gripper, movable gripper, and lift coils of a
mechanism) withdraws the RCCA attached to the mechanism. Mechanical failures are in the
direction of insertion or immobility.
The dropped RCCAs, dropped RCCA bank, and statically misaligned RCCA events are classified as ANS Condition II incidents (incidents of moderate frequency) as defined in
subsection 15.0.1. The single RCCA withdrawal incident is classified as an ANS Condition III
event, as discussed below.
No single electrical or mechanical failure in the rod control system could cause the accidental withdrawal of a single RCCA from the inserted bank at full-power operation. The operator could
withdraw a single RCCA in the control bank, since this feature is necessary in order to retrieve
an assembly should one be accidentally dropped. The event analyzed must result from multiple
wiring failures (probability for single random failure is on the order of 10
-6/h (paragraph 7.7.2.2))
or multiple significant operator errors and subsequent and repeated operator disregard of event
indication. The probability of such a combination of conditions is considered low such that the
limiting consequences may include slight fuel damage.
Thus, consistent with the philosophy and format of American National Standards Institute N18.2, the event is classified as a Condition III event. By definition, "Condition III occurrences include
incidents, any one of which may occur during the lifetime of a particular plant," and "shall not
cause more than a small fraction of fuel elements in the reactor to be damaged . . . ."
This selection of criteria is in accordance with General Design Criterion (GDC) 25, which states, "The protection system shall be designed to assure that specified acceptable fuel design limits
are not exceeded for any single malfunction of the r eactivity control systems, such as accidental withdrawal (not ejection or dropout) of control rods." (Emphases have been added.) It has been shown that single failures resulting in RCCA bank withdrawals do not violate specified fuel
design limits. Moreover, no single malfunction can result in the withdrawal of a single RCCA.
VEGP-FSAR-15
15.4-11 REV 19 4/15 Thus, it is concluded that criteria established for the single rod withdrawal at power are
appropriate and in accordance with GDC 25.
The following indicators detect one or more dropped RCCAs, RCCA group, or RCCA bank:
- Sudden drop in the core power level as seen by the nuclear instrumentation system.
- Asymmetric power distribution as seen on out-of-core neutron detectors or core exit thermocouples.
- Rod at bottom signal.
- Rod deviation alarm.
- Rod position indication.
The following indicators detect misaligned RCCAs:
- Asymmetric power distribution as seen on out-of-core neutron detectors or core exit thermocouples.
- Rod deviation alarm.
- Rod position indicators.
The resolution of the rod position indicator channel is
+/-5 percent of span (+/-7.5 in.). Deviation of any RCCA from its group by twice this distance (10 percent of span or 15 in.) will not cause power distributions worse than the design limits. The deviation alarm alerts the operator to rod deviation with respect to the group position in excess of 5 percent of span. If the rod deviation
alarm is not operable, the Technical Specifications require the operator to take action.
If one or more rod position indicator channel is out of service, the operator must follow detailed operating instructions to ensure the alignment of the nonindicated RCCAs. The operator is also
required to take action, as required by the Technical Specifications.
In the unlikely event of simultaneous electrical failures which could result in single RCCA withdrawal, the plant annunciator will display both the rod deviation and rod control urgent
failure; and the rod position indicators will indicate the relative positions of the RCCAs in the
bank. The urgent failure alarm also inhibits automatic rod motion in the group in which it occurs.
Withdrawal of a single RCCA by operator action, whether deliberate or by a combination of errors, would result in activation of the same alarm and the same visual indication. The OTT reactor trip provides automatic protection for this event, although due to the increase in local power density, it is not possible to always provide assurance that the core safety limits will not
be exceeded.
Plant systems and equipment which are available to mitigate the effects of the various control rod misoperations are discussed in subsection 15.0.8 and listed in table 15.0.8-1. No single
active failure in any of these systems or equi pment will adversely affect the consequences of
the accident.
VEGP-FSAR-15
15.4-12 REV 19 4/15 15.4.3.2 Analysis of Effects and Consequences 15.4.3.2.1 Dropped RCCAs, Dropped RCCA Bank, and Statically Misaligned RCCA 15.4.3.2.1.1 Method of Analysis. A. One or More Dropped RCCAs From the Same Group The LOFTRAN computer code (reference 2) calculates the transient system response for the evaluation of the dropped RCCA event. The code simulates the neutron kinetics, RCS, pressurizer, pressurizer relief and safety valves, pressurizer spray, steam generator, and steam generator safety valves. The
code computes pertinent plant variables including temperatures, pressures, and
power level. Calculated statepoints and nuclear models form the basis used to obtain a hot channel factor consistent with the primary system conditions and reactor power.
By incorporating the primary conditions from the transient and the hot channel
factor from the nuclear analysis, the DNB design basis is shown to be met using
the VIPRE-01 code. The transient response analysis, nuclear peaking factor
analysis, and performance of the DNB design basis confirmation are in
accordance with the methodology described in reference 1. Note that the
analysis does not take credit for the negative flux rate reactor trip. B. Dropped RCCA Bank A dropped RCCA bank results in a symmetric power change in the core. As discussed in reference 1, assumptions made for the dropped RCCA(s) analysis provide a bounding analysis for the dropped RCCA bank. C. Statically Misaligned RCCA Table 4.1-2 described the computer codes used in the analysis of steady-state power distributions. The peaking factors are then used as input to the VIPRE-01 code to calculate the DNBR. The analysis examines the case of the worst rod
withdrawn from bank D inserted at the insertion limit with the reactor initially at
full power. The analysis assumes this incident to occur at beginning of life since
this results in the minimum value of moderator temperature coefficient. This
assumption maximizes the power rise and minimizes the tendency of increased
moderator temperature to flatten the power distribution. D. Single RCCA Withdrawal at Full Power Table 4.1-2 describes the computer codes used in the calculation of power distributions within the core. The peaking factors are then used in the DNB
evaluation for the event. The plant's analysis is for the case of the worst
withdrawn rod from D bank inserted at the insertion limit, with the reactor initially
at full power. The analysis assumes the transient to occur at beginning of life
since this results in the minimum value of moderator temperature coefficient.
This assumption maximizes the power rise and minimizes the tendency of
increased moderator temperature to flatten the power distribution.
VEGP-FSAR-15
15.4-13 REV 19 4/15 15.4.3.2.1.2 Results. A. One or More Dropped RCCAs Single or multiple dropped RCCAs within the same group result in a negative reactivity insertion. The core is not adversely affected during this period, since power is decreasing rapidly. Power may be reestablished either by reactivity
feedback or control bank withdrawal. Following a dropped rod event in manual rod control, the plant will establish a new equilibrium condition. The equilibrium process without control system
interaction is monotonic, thus removing power overshoot as a concern and
establishing the automatic rod control mode of operation as the limiting case. For a dropped RCCA event in the automatic rod control mode (insertion and withdrawal), the rod control system detects the drop in power and initiates control
bank withdrawal. Power overshoot may occur due to this action by the automatic
rod controller after which the control system will insert the control bank to restore
nominal power. Figures 15.4.3-1 and 15.4.3-2 show a typical transient response
to a dropped RCCA (or RCCAs) in automatic control. Uncertainties in the initial
condition are included in the DNB evaluation as described in reference 1. In all
cases, the minimum DNBR remains above the limit value. Following plant stabilization, the operator may manually retrieve the RCCA by following approved operating procedures. B. Dropped RCCA Bank A dropped RCCA bank results in a negative reactivity insertion greater than 500 pcm. The core is not adversely affected during the insertion period, since
power is decreasing rapidly. The transient will proceed as described in part A;
however, the return to power will be less due to the greater worth of the entire
bank. The power transient for a dropped RCCA bank is symmetric. Following
plant stabilization, normal procedures are followed. C. Statically Misaligned RCCA The most severe misalignment situations with respect to DNBR at significant power levels arise from cases in which one RCCA is fully inserted or where bank D is fully inserted with one RCCA fully withdrawn. Multiple independent alarms, including a bank insertion limit alarm, alert the operator well before the transient
approaches the postulated conditions. The bank can be inserted to its insertion
limit with any one assembly fully withdrawn without the DNBR falling below the
limit value. The insertion limits in the Core Operating Limits Report (COLR) may vary from time to time depending on several limiting criteria. The full-power insertion limits
on control bank D must be chosen to be above that position which meets the
minimum DNBR and peaking factors. The full power insertion limit is usually
dictated by other criteria. Detailed resu lts will vary from cycle to cycle depending on fuel arrangements. For this RCCA misalignment, with bank D inserted to its full-power insertion limit and one RCCA fully withdrawn, DNBR does not fall below the limit value. The
analysis of this case assumes that the initial reactor power, pressure, and RCS
temperature are at their nominal values, with the increased radial peaking factor
associated with the misaligned RCCA.
VEGP-FSAR-15
15.4-14 REV 19 4/15 For RCCA misalignments with one RCCA fully inserted, the DNBR does not fall below the limit value. The analysis of this case assumes that initial reactor
power, pressure, and RCS temperatures are at their nominal values, with the
increased radial peaking factor associated with the misaligned RCCA. DNB does not occur for the RCCA misalignment incident, thus there is no reduction in the ability of the primary coolant to remove heat from the fuel rod.
The peak fuel temperature corresponds to a linear heat generation rate based on
the radial peaking factor penalty associated with the misaligned RCCA and the
design axial power distribution. The resulting linear heat generation rate is well
below that which would cause fuel melting. After identifying an RCCA group misalignment condition, the operator must take action as required by the plant Technical Specifications and operating
instructions. D. The analysis of the single rod withdrawal event considers the following two events: 1. If the reactor is in the manual rod control mode, continuous withdrawal of a single RCCA results in both an increase in core power and coolant temperature and an increase in the local hot channel factor in the area of
the withdrawing RCCA. Depending on initial bank insertion and location
of the withdrawn RCCA, automatic reactor trip may not occur quickly
enough to prevent the minimum DNBR from falling below the limit value.
Evaluation of this case at the power and coolant conditions at which the OTT trip would trip the plant shows that an upper limit for the number of rods with a DNBR less than the limit value is 5 percent. 2. If the reactor is in the automatic rod control mode, the multiple failures that result in the withdrawal of a single RCCA cause immobility of the other RCCAs in the controlling bank. The transient will then proceed in
the same manner as case 1 described above. For such cases as above, a reactor trip will ultimately ensue, although not quickly enough in all cases to prevent a minimum DNBR in the core of less than the limit
value. Following reactor trip, normal shutdown procedures are followed.
15.4.3.3 Conclusions For cases of dropped RCCAs or dropped banks, the DNBR remains greater than the limit value;
therefore, the DNB design criterion is met.
For all cases of any RCCA fully inserted, or bank D inserted to its rod insertion limits with any single RCCA in that bank fully withdrawn (static misalignment), the DNBR remains greater than the limit value.
For the case of the accidental withdrawal of a single RCCA, with the reactor in the automatic or manual control mode and initially operating at full power with bank D at the insertion limit, an
upper bound of the number of fuel rods experiencing DNBR is 5 percent of the total fuel rods in
the core.
VEGP-FSAR-15
15.4-15 REV 19 4/15 15.4.3.4 References 1. Haessler, R. L., et al., "Methodology For the Analysis of the Dropped Rod Event," WCAP-11394-P-A (Proprietary) and WCAP-11395-A (Nonproprietary), January 1990. 2. Burnett, T. W. T., et al., "LOFTRAN Code Description," WCAP-7907-P-A (Proprietary) and WCAP-7907-A (Nonproprietary), April 1984. 15.4.4 STARTUP OF AN INACTIVE REACTOR COOLANT PUMP AT AN INCORRECT TEMPERATURE 15.4.4.1 Identification of Causes and Accident Description Technical Specification 3.4.4 does not permit VEGP Units 1 and 2 operation in Modes 1 and 2 with less than four loops operating; however, this analysis assumes approximately 75-percent
power in Mode 1 in order to bound Mode 3 operation where the Technical Specifications permit
operation with less than four loops.
If the plant operates with one reactor coolant pump (RCP) out of service, there is reverse flow through the inactive loop due to the pressure difference across the reactor vessel. The cold leg
temperature of the inactive loop is identical to the cold leg temperature of the active loops. If
the reactor is operated at power, and assuming there is no isolation of the secondary side of the
steam generator in the inactive loop, there is a temperature drop across the steam generator in
the inactive loop and, with the reverse flow, the hot leg temperature of the inactive loop is lower
than the reactor core inlet temperature.
Administrative procedures require that the unit be brought to a load of less than 25 percent of full power prior to starting the pump in an inactive loop in order to bring the inactive loop hot leg
temperature closer to the core inlet temperature. Starting an idle RCP without bringing the
inactive loop hot leg temperature close to the core inlet temperature would result in the injection
of cold water into the core, which would cause a reactivity insertion and subsequent power
increase.
If the startup of an inactive RCP accident occurs, the transient terminates automatically by a reactor trip on low coolant loop flow when the power range neutron flux (two out of four
channels) exceeds the P-8 setpoint, which has been previously reset for three-loop operation.
This is an ANS Condition II incident. 15.4.4.2 Analysis of Effects and Consequences 15.4.4.2.1 Method of Analysis The analysis of this transient uses three digital computer codes. The LOFTRAN code (reference 1) calculates the loop and core flow, nuclear power, and core pressure and
temperature transients following the startup of an idle pump. FACTRAN (reference 2)
calculates the core heat flux transient based on core flow and nuclear power from LOFTRAN.
The THINC code is then used to calculate the DNBR during the transient based on system
conditions calculated by LOFTRAN and heat fluxes calculated by FACTRAN.
VEGP-FSAR-15
15.4-16 REV 19 4/15 Subsection 15.0.3 discusses plant characteristics and initial conditions. In order to obtain
conservative results for the startup of an inactive pump accident, the following assumptions are
made (this analysis employed STDP): A. Initial conditions of maximum core power and reactor coolant average temperatures and minimum reactor coolant pressure resulting in minimum initial
margin to DNB. These values are consis tent with maximum steady-state power level that would be permitted with three loops in operation. The high initial power
gives the greatest temperature difference between the core inlet temperature and
the inactive loop hot leg temperature. B. Following initiation of startup of the idle pump, the inactive loop flow reverses and accelerates to its nominal full-flow value in approximately 9 s. C. The analysis assumes a conservatively large negative moderator temperature coefficient. D. The analysis assumes a least-negative Doppler-only power coefficient. E. The initial reactor coolant loop flows are at the appropriate values for one pump out of service. F. The reactor trip occurs on low coolant flow when the power range neutron flux exceeds the P-8 setpoint. The P-8 setpoint is conservatively assumed to be 84 percent of rated power, which corresponds to the nominal setpoint plus 9 percent
for nuclear instrumentation errors.
Plant systems and equipment which are available to mitigate the effects of the accident are
discussed in subsection 15.0.8 and listed in table 15.0.8-1. No single active failure in any of
these systems or equipment w ill adversely affect the consequences of the accident.
15.4.4.2.2 Results The results following the startup of an idle pump with the above listed assumptions are shown in figures 15.4.4-1 through 15.4.4-5. These curves show that during the first part of the transient, the increase in core flow with cooler water results in an increase in nuclear power and a
decrease in the core average temperature. The minimum DNBR during the transient is greater
than the safety analysis limit values.
Reactivity addition for the inactive loop startup accident is due to the decrease in core water temperature. During the transient, this decrease is due both to the increase in reactor coolant
flow and, as the inactive loop flow reverses, to the colder water entering the core from the hot
leg side of the steam generator in the inactive loop. Thus, the reactivity insertion rate for this
transient changes with time. The resultant core nuclear power transient, computed with
consideration of both moderator and Doppler reactivity feedback effects, is shown in
figure 15.4.4-1. The calculated sequence of events for this accident is shown in table 15.4.1-1.
The transient results illustrated in figures 15.4.4-1 through 15.4.4-5 indicate that a stabilized
plant condition, with the reactor tripped, is rapidly approached. By following normal shutdown
procedures, the plant can subsequently achieve cooldown.
VEGP-FSAR-15
15.4-17 REV 19 4/15 15.4.4.3 Conclusions The transient results show that the core is not adversely affected. There is considerable margin
to the safety analysis limit DNBRs; thus, the DNB design basis as described in section 4.4 is
met. 15.4.4.4 References 1. Burnett, T. W. T., et al., "LOFTRAN Code Description," WCAP-7907-P-A, (Proprietary) and WCAP-7907-A (Nonproprietary), April 1984. 2. Hargrove, H. G., "FACTRAN--A FORTRAN-IV Code for Thermal Transients in UO 2 Fuel Rod," WCAP-7908-A, December 1989. 15.4.5 A MALFUNCTION OR FAILURE OF THE FLOW CONTROLLER IN A BOILING WATER REACTOR LOOP THAT RESULTS IN AN INCREASED REACTOR COOLANT FLOWRATE This subsection is not applicable to the VEGP. 15.4.6 CHEMICAL AND VOLUME CONTROL SYSTEM MALFUNCTION THAT RESULTS IN A DECREASE IN THE BORON CONCENTRATION IN THE REACTOR COOLANT 15.4.6.1 Identification of Causes and Accident Description Feeding primary grade water into the RCS via the reactor makeup portion of the chemical and volume control (CVCS) adds reactivity to the core. Boron dilution is a manual operation under
strict administrative controls with procedures calling for a limit on the rate and duration of
dilution. A boric acid blend system permits the operator to match the boron concentration of
reactor coolant makeup water during normal charging to that in the RCS. Even under various
postulated failure modes, the design of the CVCS limits the potential rate of dilution to a value
which gives the operator sufficient time to correct the situation in a safe and orderly manner.
The opening of the primary water makeup control valve supplies water to the RCS which can dilute the reactor coolant. Inadvertent dilution can be readily terminated by closing one of the
valves in the makeup pathway. In order to add makeup water to the RCS at pressure, at least
one charging pump in addition to the primary makeup water pumps must be running. Normally, only one primary water supply pump is operating while the other is on standby.
The boric acid from the boric acid tank blends with primary grade water at the mixing tee, and the preset flowrates of boric acid and primary grade water on the control board determine the
composition.
Information on the status of reactor coolant makeup is continuously available to the operator.
Lights on the control board indicate the operating condition of pumps in the CVCS. Alarms
actuate to warn the operator if boric acid or demineralized water flowrates deviate from preset
values as a result of system malfunction.
This is an ANS Condition II incident.
VEGP-FSAR-15
15.4-18 REV 19 4/15 15.4.6.2 Analysis of Effects and Consequences 15.4.6.2.1 Method of Analysis To cover all phases of the plant operation, this analysis considers boron dilution during refueling, cold shutdown, hot shutdown, hot standby, startup, and power operation. The
analysis assumes conservative values for the critical parameters; i.e., high RCS critical boron
concentrations, most negative boron worths, minimum shutdown margins, and small RCS
volumes. These result in conservative calculations of the time available for the operator to
determine the cause of the addition and take corrective action before shutdown margin is lost. A. Dilution During Refueling This analysis evaluates boron dilution events during refueling (Mode 6). During refueling, a very small amount of unborated chemical solution is allowed to enter the RCS for water chemistry quality control. The dilution flow path is provided by
opening CVCS valves 176 and 177. The maximum flowrate possible through this
flow path is less than 3.5 gal/min which is approximately 3.0 percent of the
limiting flowrate considered in the analysis for Modes 3, 4, and 5a. At all other
times during Mode 6, valves 176 and 177 will be locked closed. Any other
chemical makeup solution which is required during refueling will be borated water
supplied from the refueling water storage tank by the RHR pumps. Valves 175 and 183 in the CVCS will be locked closed or isolated by removal of control air or electrical supply during refueling operations (Mode 6). These
valves will block additional flow paths which could allow unborated chemical
makeup water in excess of 3.5 gal/min to reach the RCS. B. Dilution During Cold Shutdown, Hot Shutdown, and Hot Standby This analysis evaluates boron dilution events during cold shutdown with the RCS in the "loops filled" condition (Mode 5a), cold shutdown with the RCS in the "loop not filled" condition (midloop operation, Mode 5b), hot shutdown (Mode 4), and
hot standby (Mode 3). Failure modes and effects analysis, human error analysis, and event tree analysis were used to identify credible boron dilution initiators and
to evaluate the plant response to these events. For the initiators identified, time
intervals from alarm to loss of shutdown margin were calculated to determine the
length of time available for operator response. These calculations depended on
dilution flowrates, boron concentrations, and reactor coolant system volumes
specific to the event and mode of operation. The technique modeled realistic
plant conditions and responses, including both mechanical failure and human
errors.
The analysis identified four events considered to be the most likely initiators: 1. Demineralizer outlet isolation valve open during resin flushing. 2. Valve 226 open following BTRS demineralizer flushing operation.
- 3. Failure to secure chemical addition.
- 4. Boric acid flow control valve (FV-110A) fails closed during makeup.
Initiator 4 was found to be the most limiting event for Modes 3, 4, and 5a. For Mode 5b, initiator 3 was considered to allow the addition of small amounts of unborated chemical solution into the
RCS for water chemistry control. The maximum flowrate possible through this flow path is VEGP-FSAR-15
15.4-19 REV 19 4/15 approximately 3 percent of that associated with the limiting flow path for Modes 3, 4, and 5a.
The parameters used in the calculation of time available for operator response are listed in table
15.4.6-1. Conservative values of boron worth (pcm/ppm), as a function of RCS boron
concentration, were assumed in the analysis.
Since the active volumes considered are so small in Mode 5b, it was determined that the same valves locked closed in refueling (valves 175 and 183, and, except when required for small
chemical additions, valves 176 and 177) would need to be locked closed in Mode 5b. (See
paragraph A.) C. Dilution During Full Power Operation, Including Startup. For the dilution during startup (Mode 2), the analysis assumes an initial maximum critical boron
concentration of 2100 ppm based on the rods being inserted to the insertion
limits. The analysis assumes the minimum change in the boron concentration
from this initial condition to a hot zero power critical condition to be 300 ppm.
The analysis also assumes full rod insertion to occur due to reactor trip, minus
the most reactive stuck rod. The analysis assumes the dilution flow to be the
combined capacity of the two primary water makeup pumps (approximately 242
gal/min) and a minimum RCS water volume of 9583 ft
- 3. This volume corresponds to the active volume of the RCS minus the pressurizer and accounts
for 10-percent steam generator tube plugging.
During power operation (mode 1), the plant operates under either manual or automatic rod
control. While the plant is in manual control, the analysis assumes the dilution flow to be a
maximum of 242 gal/min, which is the combined capacity of the two primary water makeup
pumps. While in automatic control, the maximum letdown flow (approximately 130 gal/min)
limits the dilution flow. The analysis assumes an initial maximum critical boron concentration, corresponding to the rods inserted to the insertion limits at hot full power, of 2100 ppm. The
analysis also assumes the minimum change in the boron concentration from this initial condition
to a hot zero power critical condition to be 300 ppm. The analysis assumes full rod insertion to
occur due to reactor trip, minus the most reactive stuck rod. The analysis uses a minimum
water volume of 9583 ft 3 in the RCS, corresponding to the active volume of the RCS minus the pressurizer volume and accounts for 10-percent tube plugging.
No single active failure in any plant syst ems or equipment will adversely affect the consequences of the accident. 15.4.6.2.2 Results The calculated sequence of events is shown in table 15.4.1-1. A. Dilution During Refueling Since the maximum flowrate associated with the available dilution flow paths in mode 6 is very small, the total time fr om initiation of event to the eventual complete loss of shutdown margin is significantly large compared to the minimum required operator action time. Therefore, a considerable amount of time is
available for the operator to initiate and terminate procedures for RCS water
chemistry adjustments before potential loss of shutdown becomes a concern.
Additionally, assuming the availability of one high flux at shutdown (HFAS) alarm
set at not more than 2.3 times background, it is shown that the technical
specification shutdown margin requirement for mode 6 is sufficient to ensure that
the operator has 30 minutes from the time of alarm to terminate the dilution
before shutdown margin is lost.
VEGP-FSAR-15
15.4-20 REV 19 4/15 B. Dilution During Cold Shutdown, Hot Shutdown, and Hot Standby For dilution during cold shutdown, hot shutdown, and hot standby, the Core Operating Limits Report (COLR) provides the required shutdown margin as a function of RCS boron concentration. The specified shutdown margin ensures
that the operator has 15 min from the time of the HFAS alarm to the total loss of
shutdown margin due to initiator 4, which is the limiting case for Modes 3, 4, and
5a. Since the maximum flowrate associated with the available dilution flow paths
in Mode 5b is very small, the total time from initiation of event to the eventual complete loss of shutdown margin is significantly large compared to the minimum
required operator action time of 15 minutes. C. Dilution During Full Power Operation, Including Startup In the event of an unplanned approach to criticality or dilution during power escalation while in the startup mode, the operator is alerted to an unplanned dilution by a reactor trip at the power range neutron flux high, low setpoint. After
reactor trip there are at least 15 minutes for operator action prior to loss of
shutdown margin. During full power operation with the reactor in manual control, the operator is alerted to an uncontrolled dilution by an OTT reactor trip. At least 15 minutes
are available after the trip for operator action prior to loss of shutdown margin. During full power operation with the reactor in automatic control, the operator is alerted to an uncontrolled reactivity insertion by the rod insertion limit alarms. At
least 15 minutes are available for operator action from the low-low rod insertion
limit alarm until a loss of shutdown margin occurs.
15.4.6.3 Conclusions The results presented above show that adequate time is available for the operator to manually
terminate the source of dilution flow. Following termination of the dilution flow, the operator can
initiate boration to establish adequate shutdown margin. 15.4.7 INADVERTENT LOADING AND OPERATION OF A FUEL ASSEMBLY IN AN IMPROPER POSITION 15.4.7.1 Identification of Causes and Accident Description Fuel- and core-loading errors such as can arise from the inadvertent loading of one or more fuel assemblies into improper positions, loading a fuel rod during manufacture with one or more
pellets of the wrong enrichment, or loading a full fuel assembly during manufacture with pellets
of the wrong enrichment, will lead to increased heat fluxes if the error results in placing fuel in
core positions calling for fuel of lesser enrichment. Also included among possible core-loading
errors is the inadvertent loading of one or more fuel assemblies requiring burnable poison rods
into a new core without burnable poison rods.
Any error in enrichment, beyond the normal manufacturing tolerances, can cause power shapes which are more peaked than those calculated with the correct enrichments. There is a 5-
percent uncertainty margin included in the design value of power peaking factor assumed in the
analysis of Condition I and Condition II transients.
The in-core system of movable flux detectors VEGP-FSAR-15
15.4-21 REV 19 4/15 which is used to verify power shapes at the start of life is capable of revealing any assembly
enrichment error or loading error which causes power shapes to be peaked in excess of the
design value.
To reduce the probability of core loading errors, each fuel assembly is marked with an identification number and loaded in accordance with a core-loading diagram. During core
loading, the identification number will be checked before each assembly is moved into the core.
Serial numbers read during fuel movement are subsequently recorded on the loading diagram
as a further check on proper placing after the loading is completed.
The power distortion due to any combination of misplaced fuel assemblies would significantly raise peaking factors and would be readily observable with in-core flux monitors. In addition to the flux monitors, thermocouples are located at the outlet of about one-third of the fuel
assemblies in the core. There is a high probability that these thermocouples would also indicate
any abnormally high coolant temperature rise. In-core flux measurements are taken during the startup subsequent to every refueling operation.
This event is classified as an American Nuclear Society Condition III incident (an infrequent fault) as defined in subsection 15.0.1. 15.4.7.2 Analysis of Effects and Consequences 15.4.7.2.1 Method of Analysis Steady-state power distributions in the x-y plane of the core are calculated using the TURTLE code (1) based on macroscopic cross section calculated by the LEOPARD code.
(2) A discrete representation is used wherein each individual fuel rod is described by a mesh interval.
Representative power distributions in the x-y plane for a correctly loaded core assembly are
also given in chapter 4.
For each core loading error case analyzed, the percent deviations from detector readings for a normally loaded core are shown in all in-core detector locations. (See figures 15.4.7-1 through
15.4.7-5.) 15.4.7.2.2 Results The following core loading error cases have been analyzed:
Case A:
Case in which a region 1 assembly is interchanged with a region 3 assembly. The particular case considered was the interchange to two adjacent assemblies near the periphery of the core.
(See figure 15.4.7-1.)
Case B:
Case in which a region 1 assembly is interchanged with a neighboring region 2 fuel assembly.
Two analyses have been performed for this case. (See figures 15.4.7-2 and 15.4.7-3.)
In Case B-1, the interchange is assumed to take place with the burnable poison rods transferred with the region 2 assembly mistakenly loaded into region 1.
VEGP-FSAR-15
15.4-22 REV 19 4/15 In Case B-2, the interchange is assumed to take place closer to core center and with burnable
poison rods located in the correct region 2 position but in a region 1 assembly mistakenly
loaded in the region 2 position.
Case C:
Enrichment error: Case in which a region 2 fuel assembly is loaded in the core central position. (See figure 15.4.7-4.)
Case D:
Case in which a region 2 fuel assembly instead of a region 1 assembly is loaded near the core periphery. (See figure 15.4.7-5.)
15.4.7.3 Conclusions Fuel assembly enrichment errors would be prevented by administrative procedures implemented in fabrication.
In the event that a single pin or pellet has a higher enrichment than the nominal value, the consequences in terms of reduced departure from nucleate boiling ratio and increased fuel and
clad temperatures will be limited to the incorrectly loaded pin or pins and perhaps the
immediately adjacent pins. Fuel assembly loading errors are prevented by administrative procedures implemented during core loading. In the unlikely event that a loading error occurs, analyses in this section confirm
that resulting power distribution effects will ei ther be readily detected by the in-core movable detector system or will cause a sufficiently small perturbation to be acceptable within the
uncertainties allowed between nominal and design power shapes. 15.4.7.4 References 1. Barry, R. F., and Altomore, A., "The TURTLE 24.0 Diffusion Depletion Code," WCAP-7213-P-A (Proprietary) and WCAP-7758-A (Nonproprietary), February 1975. 2. Barry, R. F., "LEOPARD - A Spectrum Dependent Non-Spacial Depletion Code for the IBM-7094," WCAP-3269-26, September 1963. 15.4.8 SPECTRUM OF ROD CLUSTER CONTROL ASSEMBLY EJECTION ACCIDENTS 15.4.8.1 Identification of Causes and Accident Description This accident is defined as the mechanical failure of a control rod mechanism pressure housing, resulting in the ejection of a rod cluster control assembly (RCCA) and drive shaft. The
consequence of this mechanical failure is a rapid positive reactivity insertion together with an
adverse core power distribution, possibly leading to localized fuel rod damage.
VEGP-FSAR-15
15.4-23 REV 19 4/15 15.4.8.1.1 Design Precautions and Protection Certain features in the VEGP reactors are intended to preclude the possibility of a rod ejection accident or to limit the consequences if the accident occurs. These include a sound, conservative mechanical design of the rod housings, together with a thorough quality control (testing) program during assembly, and a nuclear design which lessens the potential ejection
worth of RCCAs and minimizes the number of assemblies inserted at high-power levels. 15.4.8.1.1.1 Mechanical Design. The mechanical design is discussed in section 4.6.
Mechanical design and quality control procedures intended to preclude the possibility of an RCCA drive mechanism housing failure are listed below: A. Each control rod drive mechanism housing is completely assembled and shop tested at 4100 psi. B. The mechanism housings are individually hydrotested after they are attached to the head adapters in the reactor vessel head and checked during the hydrotest of
the completed reactor coolant system (RCS). C. Stress levels in the mechanism are not affected by anticipated system transients at power or by the thermal movement of the coolant loops. Moments induced by
the design earthquake can be accepted within the allowable primary working
stress range specified by the American Society of Mechanical Engineers Code,Section III, for Class 1 components. D. The latch mechanism housing and rod travel housing are each a single length of forged type 304 stainless steel. This material exhibits excellent notch toughness
at all temperatures which will be encountered.
A significant margin of strength in the elastic range together with the large energy absorption
capability in the plastic range gives additional assurance that gross failure of the housing will not
occur. The joints between the latch mechanism housing and head adapter, and between the
latch mechanism housing and rod travel housing, are threaded joints reinforced by canopy-type rod welds which are subject to periodic inspections. 15.4.8.1.1.2 Nuclear Design. Even if a rupture of an RCCA drive mechanism housing is postulated, the operation utilizing chemical shim is such that the severity of an ejected RCCA is inherently limited. In general, the reactor is operated with the RCCA inserted only far enough to
permit load follow. Reactivity changes caused by core depletion and xenon transients are
compensated for by boron changes. Further, the location and grouping of control RCCA banks
are selected during the nuclear design to lessen the severity of an RCCA ejection accident.
Therefore, should an RCCA be ejected from its normal position during full-power operation, only
a minor reactivity excursion, at worst, could be expected to occur.
However, it may be occasionally desirable to operate with larger than normal insertions. For this reason, a rod insertion limit is defined as a function of power level. Operation with the
RCCAs above this limit guarantees adequate shutdown capability and acceptable power
distribution. The position of all RCCAs is continuously indicated in the control room. An alarm
will occur if a bank of RCCAs approaches its insertion limit or if one RCCA deviates from its
bank. Procedures require action per the Technical Specifications if shutdown or control RCCA
banks are below insertion limits.
VEGP-FSAR-15
15.4-24 REV 19 4/15 15.4.8.1.1.3 Reactor Protection. The reactor protection in the event of a rod ejection accident has been described in reference 1. The protection for this accident is provided by high
neutron flux trip (high and low setting) and high rate of neutron flux increase trip. These
protection functions are described in detail in section 7.2. 15.4.8.1.1.4 Effects on Adjacent Housings. Disregarding the remote possibility of the occurrence of an RCCA mechanism housing failure, investigations have shown that failure of a housing due to either longitudinal or circumferential cracking would not cause damage to
adjacent housings. The control rod drive mechanism is described in paragraph 3.9.4.1.1. 15.4.8.1.1.5 Effects of Rod Travel Housing Longitudinal Failures. If a longitudinal failure of the rod travel housing should occur, the region of the position indicator assembly opposite the break would be stressed by the reactor coolant pressure of 2250 psia. The most probable
leakage path would be provided by the radial deformation of the position indicator coil
assembly, resulting in the growth of axial fl ow passages between the rod travel housing and the hollow tube along which the coil assemblies are mounted.
If failure of the position indicator coil assembly should occur, the resulting free radial jet from the failed housing could cause it to bend and contact adjacent rod housings. If the adjacent
housings were on the periphery, they might bend outward from their bases. The housing
material is quite ductile; plastic hinging without cracking would be expected. Housings adjacent
to a failed housing, in locations other than the periphery, would not be bent because of the
rigidity of multiple adjacent housings. 15.4.8.1.1.6 Effect of Rod Travel Housing Circumferential Failures. If circumferential failure of a rod travel housing should occur, the broken-off section of the housing would be ejected vertically because the driving force is vertical and the position indicator coil assembly and the drive shaft would tend to guide the broken-off piece upwards during its travel. Travel is
limited by the missile shield, thereby limiting the projectile acceleration. When the projectile reached the missile shield, it would partially penetrate the shield and dissipate its kinetic energy.
The water jet from the break would continue to push the broken-off piece against the missile
shield. If the broken-off piece of the rod travel housing were short enough to clear the break when fully ejected, it would rebound after impact with the missile shield. The top end plates of the position
indicator coil assemblies would prevent the brok en piece from directly hitting the rod travel housing of a second drive mechanism. Even if a direct hit by the rebounding piece were to
occur, the low kinetic energy of the rebounding projectile would not be expected to cause
significant damage (sufficient to cause failure of an adjacent housing). 15.4.8.1.1.7 Possible Consequences. From the above discussion, the probability of damage to an adjacent housing must be considered remote. However, even if damage is postulated, it would not be expected to lead to a more severe transient since RCCAs are
inserted in the core in symmetric patterns, and control rods immediately adjacent to worst
ejected rods are not in the core when the reactor is critical. Damage to an adjacent housing
could, at worst, cause that RCCA not to fall on receiving a trip signal; however, this is already
taken into account in the analysis by assuming a stuck rod adjacent to the ejected rod.
VEGP-FSAR-15
15.4-25 REV 19 4/15 15.4.8.1.1.8 Summary. The considerations given above lead to the conclusion that failure of a control rod housing, due either to longitudinal or circumferential cracking, would not cause
damage to adjacent housings that would increase severity of the initial accident. 15.4.8.1.2 Limiting Criteria This event is classified as an American Nuclear Society (ANS) Condition IV incident. See subsection 15.0.1 for a discussion of ANS classifications. Due to the extremely low probability
of an RCCA ejection accident, some fuel damage would be considered an acceptable
consequence.
Comprehensive studies of the threshold of fuel failure and of the threshold of significant conversion of the fuel thermal energy to mechanical energy have been carried out as part of the
SPERT project by the Idaho Nuclear Corporation.
(2) Extensive tests of UO 2 zirconium-clad fuel rods representative of those in pressurized water reactor-type cores such as VEGP have
demonstrated failure thresholds in the range of 240 to 257 cal/g. However, other rods of a
slightly different design have exhibited failure as low as 225 cal/g. These results differ
significantly from the TREAT (3) results, which indicated a failure threshold of 280 cal/g. Limited results have indicated that this threshold decreases by about 10 percent with fuel burnup. The
clad failure mechanism appears to be melting for zero burnup rods and brittle fracture for
irradiated rods. Also important is the conversion ratio of thermal to mechanical energy. This
ratio becomes marginally detectable above 300 cal/g for unirradiated rods and 200 cal/g for
irradiated rods; catastrophic failure (large fuel dispersal, large pressure rise), even for irradiated
rods, did not occur below 300 cal/g.
In view of the above experimental results and conformance with Regulatory Guide 1.77 (subsection 1.9.77), criteria are applied to ensure that there is little or no possibility of fuel
dispersal in the coolant, gross lattice distortion, or severe shock waves. These limiting criteria
are as follows (reference 9): A. Average fuel pellet enthalpy at the hot spot will be below 200 cal/g for unirradiated fuel and irradiated fuel. B. Peak reactor coolant pressure will be less than that which could cause stresses to exceed the faulted condition stress limits. C. Fuel melting will be limited to less than 10 percent of the fuel volume at the hot spot even if the average fuel pellet enthalpy is below the limits of criterion A, above. 15.4.8.2 Analysis of Effects and Consequences A. Method of Analysis The calculation of the RCCA ejection transient is performed in two stages, first an average core channel calculation and then, a hot region calculation. The average core calculation is performed using spatial neutron kinetics methods to
determine the average power generation with time including the various total
core feedback effects; i.e., Doppler reactivity and moderator reactivity. Enthalpy
and temperature transients at the hot spot are then determined by multiplying the
average core energy generation by the hot channel factor and performing a fuel
rod transient heat transfer calculation. The power distribution calculated without
feedback is conservatively assumed to persist throughout the transient.
VEGP-FSAR-15
15.4-26 REV 19 4/15 A detailed discussion of the method of analysis can be found in reference 1. B. Average Core Analysis The spatial kinetics computer code, TWINKLE, (4) is used for the average core transient analysis. This code uses cross sections generated by LEOPARD (5) to solve the two-group neutron diffusion theory kinetic equation in one, two, or three spatial dimensions (rectangular coordinates) for six delayed neutron groups and
up to 2000 spatial points. The computer code includes a detailed multiregion, transient fuel clad coolant heat transfer model for calculation of pointwise
Doppler and moderator feedback effects. In this analysis, the code is used as a
one-dimensional axial kinetics code, since it allows a more realistic
representation of the spatial effects of axial moderator feedback and RCCA
movement. However, since the radial dimension is missing, it is still necessary to
employ conservative methods (described below) of calculating the ejected rod
worth and hot channel factor. Further description of TWINKLE appears in
subsection 15.0.11. C. Hot Spot Analysis In the hot spot analysis, the initial heat flux is equal to the nominal volume multiplied by the design hot channel factor. During the transient, the heat flux hot channel factor is linearly increased to the transient value in 0.1 s, the time for full
ejection of the rod. Therefore, the assumption is made that the hot spots before
and after ejection are coincident. This is conservative, since the peak after
ejection will occur in or adjacent to the assembly with the ejected rod, and prior to
ejection, the power in this region will be depressed due to the inserted rod. The hot spot analysis is performed using the detailed fuel and clad transient heat transfer computer code, FACTRAN.
(6) This computer code calculates the transient temperature distribution in a cross section of a metal clad UO 2 fuel rod and the heat flux at the surface of the rod, using as input the nuclear power
versus time and the local coolant conditions. The zirconium-water reaction is
explicitly represented, and all material properties are represented as functions of
temperature. A conservative radial power distribution is used within the fuel rod. FACTRAN uses the Dittus-Boelter or Jens-Lottes correlation to determine the film heat transfer before departure from nucleate boiling (DNB) and the Bishop-
Sandburg-Tong correlation (7) to determine the film boiling coefficient after DNB.
The Bishop-Sandburg-Tong correlation is conservatively used, assuming zero-
bulk fluid quality. The departure from nucleate boiling ratio is not calculated;
instead, the code is forced into DNB by specifying a conservative DNB heat flux.
The gap heat transfer coefficient can be calculated by the code; however, it is
adjusted in order to force the full-power, steady-state temperature distribution to
agree with the fuel heat transfer design codes. Further description of FACTRAN
appears in subsection 15.0.11. D. System Overpressure Analysis Because safety limits for fuel damage specified earlier are not exceeded, there is little likelihood of fuel dispersal into the coolant. The pressure surge may therefore be calculated on the basis of conventional heat transfer from the fuel
and prompt heat absorption by the coolant. The pressure surge is calculated by first performing the fuel heat transfer calculation to determine the average and hot spot heat flux versus time. Using VEGP-FSAR-15
15.4-27 REV 19 4/15 this heat flux data, a core thermal-hydraulic calculation is conducted to determine
the volume surge. Finally, the volume surge is simulated using the LOFTRAN
computer code. This code calculates the pressure transient taking into account
fluid transport in the RCS and heat transfer to the steam generators. No credit is
taken for the possible pressure reduction caused by the assumed failure of the
control rod pressure housing. 15.4.8.2.1 Calculation of Basic Parameters Input parameters for the analysis are conservatively selected on the basis of values calculated for this type of core. The more important parameters are discussed below. Table 15.4.8-1
presents the parameters used in this analysis. 15.4.8.2.1.1 Ejected Rod Worths and Hot Channel Factors. The values for ejected rod worths and hot channel factors are calculated using either three-dimensional static methods or by a synthesis method employing one-dimensional and two-dimensional calculations. Standard nuclear design codes are used in the analysis. No credit is taken for the flux flattening effects of
reactivity feedback. The calculation is performed for the maximum allowed bank insertion at a
given power level, as determined by the rod insertion limits. Adverse xenon distributions are
considered in the calculation.
Appropriate margins are added to the ejected rod worth and hot channel factors to account for any calculational uncertainties, including an allowance for nuclear peaking due to densification.
Power distributions before and after ejection for a worst case can be found in reference 1.
During initial plant startup physics testing, ejected rod worths and power distributions are
measured in the zero-power and part power configurations and compared to values used in the
analysis. Experience shows that the ejected rod worth and power peaking factors are
consistently overpredicted in the analysis. 15.4.8.2.1.2 Reactivity Feedback Weighting Factors. The largest temperature rises and hence the largest reactivity feedbacks occur in channels where the power is higher than average. Since the weight of a region is dependent on flux, these regions have high weights.
This means that the reactivity feedback is larger than that indicated by a simple channel
analysis. Physics calculations have been performed for temperature changes with a flat
temperature distribution and with a large number of axial and radial temperature distributions.
Reactivity changes were compared and effective weighting factors determined. These
weighting factors take the form of multipliers which, when applied to single-channel feedbacks, correct them to effective whole-core feedbacks for the appropriate flux shape. In this analysis, since a one-dimensional (axial) spatial kinetics method is employed, axial weighting is not
necessary if the initial condition is made to match the ejected rod configuration. In addition, no
weighting is applied to the moderator feedback. A conservative radial weighting factor is
applied to the transient fuel temperature to obtain an effective fuel temperature as a function of
time accounting for the missing spatial dimension. These weighting factors have also been
shown to be conservative compared to three-dimensional analysis.
(1) 15.4.8.2.1.3 Moderator and Doppler Coefficient. The critical boron concentrations at the beginning of life and end of life are adjusted in the nuclear code in order to obtain moderator VEGP-FSAR-15
15.4-28 REV 19 4/15 density coefficient curves which are conservative compared to actual design conditions for the plant. As discussed above, no weighting factor is applied to these results.
The Doppler reactivity defect is determined as a function of power level using a one-dimensional, steady-state computer code with a Doppler weighting factor of 1.0. The Doppler
defect used is given in subsection 15.0.4. The Doppler weighting factor will increase under
accident conditions, as discussed above. 15.4.8.2.1.4 Delayed Neutron Fraction, eff. Calculations of the effective delayed neutron fraction (eff) typically yield values no less than 0.70 percent at beginning of life and 0.50 percent at end of life for the first cycle. The accident is sensitive to eff if the ejected rod worth is equal to or greater than eff as in zero-power transients. To allow for future cycles, the analysis used conservative eff estimates of 0.54 percent at beginning-of-life hot zero power, 0.57 percent at beginning-of-life hot full power, and 0.46 percent for both end-of-life cases. 15.4.8.2.1.5 Trip Reactivity Insertion. The trip reactivity insertion assumed is given in table 15.4.8-1 and includes the effect of one stuck RCCA adjacent to the ejected rod. These values are reduced by the ejected rod reactivity. The shutdown reactivity was simulated by
dropping a rod of the required worth into the core. The start of rod motion occurred 0.5 s after
the high neutron flux trip point was reached. This delay is assumed to consist of 0.2 s for the
instrument channel to produce a signal, 0.15 s for the trip breaker to open, and 0.15 s for the
coil to release the rods. A curve of trip rod insertion versus time was used which assumed that
insertion to the dashpot does not occur until 3.3 s after the start of fall. The choice of such a
conservative insertion rate means that there is over 1 s after the trip point is reached before
significant shutdown reactivity is inserted into the core. This is particularly important
conservatism for hot full-power (HFP) accidents.
The minimum design shutdown margin available for this plant at hot zero power (HZP) may be reached only at end of life in the equilibrium cycle. This value includes an allowance for the
worst stuck rod, adverse xenon distribution, conservative Doppler and moderator defects, and
an allowance for calculational uncertainties. Physics calculations for this plant have shown that
the effect of two stuck RCCAs (one of which is the worst ejected rod) is to reduce the shutdown
by about an additional 1-percent ~k/k. Therefore, following a reactor trip resulting from an
RCCA ejection accident, the reactor will be subcritical when the core returns to HZP.
Depressurization calculations have been performed for a typical four-loop plant, assuming the maximum possible size break (2.75-in. diameter) located in the reactor pressure vessel head.
The results show a rapid pressure drop and a decrease in system water mass due to the break.
The safety injection system is actuated on low pressurizer pressure within 1 min after the break.
The RCS pressure continues to drop and reaches saturation (1200 psi) in about 2 to 3 min.
Due to the large thermal inertia of primary and secondary systems, there has been no
significant decrease in the RCS temperature below no-load by this time, and the depressurization itself has caused an increase in shutdown margin by about 0.2-percent k due to the pressure coefficient. The cooldown transient could not absorb the available shutdown margin until more than 10 min after the break. The addition of borated (2400 ppm) safety
injection flow starting 1 min after the break is much more than sufficient to ensure that the core
remains subcritical during the cooldown.
VEGP-FSAR-15
15.4-29 REV 19 4/15 15.4.8.2.1.6 Reactor Protection. As discussed in paragraph 15.4.8.1.1.3, reactor protection for a rod ejection is provided by high neutron flux trip (high and low setting) and high
positive rate of neutron flux increase trip; however, the analysis only models the high neutron flux trip. These protection functions are part of the reactor trip system. No single failure of the
reactor trip system will negate the protection functions required for the rod ejection accident or
adversely affect the consequences of the accident.
No single active failure in any plant syst ems or equipment will adversely affect the consequences of the accident. 15.4.8.2.1.7 Results. Cases are presented for both beginning and end of life at zero and full power. A. Beginning of Cycle, Full Power Control bank D was assumed to be inserted to its insertion limit. The worst ejected rod worth and hot channel factor were conservatively calculated to be 0.24-percent k/k and 5.5, respectively. The peak hot spot fuel centerline temperature reached melting at 4900
°F. However, melting was restricted to less than 10 percent of the pellet volume at the hot spot. B. Beginning of Cycle, Zero Power For this condition, control bank D was assumed to be fully inserted and banks B and C were at their insertion limits. The worst ejected rod is located in control bank D and has a worth of 0.75-percent k/k and a hot channel factor of 11.0.
The fuel center temperature was 3985
°F. C. End of Cycle, Full Power Control bank D was assumed to be inserted to its insertion limit. The ejected rod worth and hot channel factors were conservatively calculated to be 0.25-percent k/k and 6.0, respectively. The peak hot spot fuel centerline temperature reached melting at 4800
°F. However, melting was restricted to less than 10 percent of the pellet volume at the hot spot. D. End of Cycle, Zero Power The ejected rod worth and hot channel factor for this case were obtained assuming control bank D to be fully inserted with banks C and B at their insertion limits. The results were 0.84-percent k/k and 26.0, respectively. The fuel centerline temperature was 3891
°F. The Doppler weighting factor for this case is significantly higher than for the other cases due to the very large transient hot channel factor.
For all four cases analyzed, average fuel pellet enthalpy at the hot spot remained below
200 cal/g.
A summary of the cases presented above is given in table 15.4.8-1. The nuclear power and hot spot fuel and clad temperature transients for the worst cases are presented in figures 15.4.8-1
through 15.4.8-4.
The calculated sequence of events for the worst case rod ejection accidents, as shown in figures 15.4.8-1 through 15.4.8-4, is presented in table 15.4.8-1. For all cases, reactor trip VEGP-FSAR-15
15.4-30 REV 19 4/15 occurs early in the transient after the nucl ear power excursion is terminated by Doppler feedback. As discussed previously in paragraph 15.4.8.2.1, the reactor remains subcritical
following reactor trip.
The ejection of an RCCA constitutes a break in the RCS, located in the reactor pressure vessel head. The effects and consequences of loss-of-coolant accidents (LOCAs) are discussed in
subsection 15.6.5. Following the RCCA ejection, the operator would follow the same
emergency instructions as for any other LOCA to recover from the event. 15.4.8.2.1.8 Fission Product Release. It is assumed that fission products are released from the gaps of all rods entering DNB. In all cases considered, less than 10 percent of the rods entered DNB based on a detailed three-dimensional THINC analysis.
(1) Although limited fuel melting at the hot spot was predicted for the full-power cases, in practice, melting is not
expected since the analysis conservatively assumed that the hot spots before and after ejection
were coincident. 15.4.8.2.1.9 Pressure Surge. A detailed calculation of the pressure surge for an ejection worth of one dollar at beginning of life, hot full power, indicates that the peak pressure does not exceed that which would cause stress to exceed the faulted condition stress limits.
(2) Since the severity of the present analysis does not exceed the worst-case analysis, the accident for this
plant will not result in an excessive pressure rise or further damage to the RCS. 15.4.8.2.1.10 Lattice Deformations. A large temperature gradient will exist in the region of the hot spot. Since the fuel rods are free to move in the vertical direction, differential expansion between separate rods cannot produce distortion. However, the temperature gradients across
individual rods may produce a differential expansion tending to bow the midpoint of the rods
toward the hotter side of the rod. Calculations have indicated that this bowing would result in a
negative reactivity effect at the hot spot since Westinghouse cores are undermoderated, and
bowing will tend to increase the undermoderation at the hot spot. In practice, no significant
bowing is anticipated, since the structural rigidity of the core is more than sufficient to withstand
the forces produced. Boiling in the hot spot region would produce a net flow away from that
region. However, the heat from the fuel is released to the water relatively slowly, and it is
considered inconceivable that crossflow will be sufficient to produce sufficient lattice forces.
Even if massive and rapid boiling, sufficient to distort the lattice, is hypothetically postulated, the
large void fraction in the hot spot region would produce a reduction in the total core moderator
to fuel ratio and a large reduction in this ratio at the hot spot. The net effect would therefore be
a negative feedback. It can be concluded that no conceivable mechanism exists for a net
positive feedback resulting from lattice deformation. In fact, a small negative feedback may
result. The effect is conservatively ignored in the analysis. 15.4.8.3 Radiological Consequences The evaluation of the radiological consequences of a postulated control rod ejection accident assumes that the reactor has been operating with a small percent of defective fuel and leaking
generator tubes for sufficient time to establish equilibrium concentrations of radionuclides in the
reactor coolant and in the secondary coolant.
VEGP-FSAR-15
15.4-31 REV 19 4/15 As a result of the accident, a fraction of the fuel rods will undergo DNB and will release gap
inventory to the reactor coolant. Additionally, a small fraction of fuel is assumed to melt and
release core inventory to the reactor coolant. Radionuclides carried by the primary coolant to
the steam generators via leaking tubes are released to the environment via the steam line
safety or power-operated relief valves. Radionuclides released to the containment via the spill
from the reactor vessel head are released to the environment via containment leakage. 15.4.8.3.1 Analytical Assumptions The major assumptions and parameters used in the analysis are itemized in table 15.4.8-2. The following is a more detailed discussion of the source term. 15.4.8.3.1.1 Source Term Calculations. The concentration of nuclides in the primary and secondary system prior to and following the rod ejection accident are determined as follows: A. The iodine activity in the reactor coolant prior to the accident is based upon an iodine spike which has raised the reactor coolant concentration to 60
µCi/g of dose equivalent (DE) I-131. B. The noble gas concentrations in the reactor coolant are based upon 1-percent defective fuel. C. Following the rod ejection accident, 10 percent of the fuel rods in the core undergo DNB. Hence, 10 percent of the core iodine and noble gas gap inventory is released to the reactor coolant. In addition, 0.25 percent of the fuel in the core
is assumed to melt and release 0.00125 of the core iodines and 0.0025 of the
core noble gases to the reactor coolant. D. The secondary coolant iodine activity is based on the DE of 0.1
µCi/g of I-131. 15.4.8.3.1.2 Mathematical Models Used in the Analysis. Mathematical models used in the analysis are described in the following sections: A. The mathematical models used to analyze the activity released during the course of the accident are described in appendix 15A. B. The atmospheric dispersion factors used in the analysis were calculated based on the onsite meteorological measurement programs described in
subsection 2.3.3. C. The thyroid inhalation dose and total-body gamma immersion doses to a receptor at the exclusion area boundary and outer boundary of the low population zone
were analyzed using the models described in appendix 15A. 15.4.8.3.1.3 Identification of Leakage Pathways and Resultant Leakage Activity.
Radionuclides carried from the primary coolant to the steam generators via leaking tubes are
released to the environment via the steam line sa fety or power-operated relief valves. Iodines
are assumed to mix with the secondary coolant and partition between the generator liquid and
steam before release to the environment. Noble gas es are assumed to be directly released.
VEGP-FSAR-15
15.4-32 REV 19 4/15 Forty-five percent of the iodines and one hundred percent of the noble gases carried by the
primary coolant spill are released to the containment vapor space and are leaked to the
environment at the containment design leak rate. For the iodine release, 39 percent of the
break flow is assumed to initially flash to vapor and 10 percent of the nonflashed portion is
assumed to become airborne; i.e., 0.39 + 10 percent of 0.61 for a total of 0.45.
All activity is released to the environment with no consideration given to radioactive decay or to cloud depletion by ground deposition during transport to the exclusion area boundary and low population zone. Hence, the resultant radiological consequences represent the most
conservative estimate of the potential integrated dose due to the postulated rod ejection
accident. 15.4.8.3.2 Identification of Uncertainties and Conservative Elements in the Analysis A. The initial reactor coolant iodine activity is based on the technical specification limit of 1.0
µCi/g of DE I-131 which is further increased by a large preaccident iodine spike to 60
µCi/g, resulting in equivalent concentrations many times greater than the reactor coolant activities based on 0.12-percent defective fuel and expected iodine spiking values associated with normal operating conditions. B. The noble gas activities are based on 1-percent defective fuel which cannot exist simultaneously with 1.0-
µCi/g I-131. For iodines, 1-percent defects would be approximately three times the technical specification limit. C. The fraction of failed fuel is assumed to be equal to the fraction of fuel rods experiencing DNB, without consideration given to the extent of the zirc-water
reaction. Based on experimental data (8) no oxidation related fuel rod clad failure is predicted. Likewise, the small amount of melted fuel assumed (0.25 percent)
is not predicted. D. A 1-gal/min steam generator primary-to-secondary leakage is assumed, which is significantly greater than that anticipated during normal operation. E. The meteorological conditions which may be present at the site during the course of the accident are uncertain. However, it is highly unlikely that the assumed
meteorological conditions would be present during the course of the accident for
any extended period of time. Therefore, the radiological consequences
evaluated, based on the meteorological conditions assumed, are conservative. 15.4.8.3.3 Conclusions 15.4.8.3.3.1 Filter Loadings. The only engineered safety feature filtration system considered in the analysis which limits the consequences of the rod ejection accident is the control room filtration system.
Integrated activity on the control room filter s have been evaluated for the more limiting LOCA analysis as discussed in paragraph 15.6.5.4.6. Since the control room filters are capable of accommodating the potential design basis LOCA fission product iodine loadings, there will be
sufficient capacity to accommodate any fission product loading due to a postulated rod ejection
accident.
VEGP-FSAR-15
15.4-33 REV 19 4/15 15.4.8.3.3.2 Dose to Receptor at the Exclusion Area Boundary and Low Population Zone Outer Boundary. The potential radiological consequences resulting from the occurrence of a postulated rod ejection accident have been conservatively analyzed using assumptions and
models described. The total-body gamma dose due to immersion from direct radiation and the
thyroid dose due to inhalation have been analyzed for the 0- to 2-h dose at the exclusion area
boundary and for the duration of the accident (0 to 30 days) at the low population zone outer
boundary. The results are listed in table 15.4.8-3. The resultant doses are well within the
guideline values of 10 CFR 100.
15.4.8.4 References 1. Risher, D. H., Jr., "An Evaluation of the Rod Ejection Accident in Westinghouse Pressurized Water Reactors Using Spatial Kinetics Methods," WCAP-7588, Revision 1A, January 1975. 2. Taxelius, T. G., ed, "Annual Report-Spert Project, October 1968, September 1969," Idaho Nuclear Corporation, IN-1370, June 1970. 3. Liimataninen, R. C., and Testa, F. J., "Studies in TREAT of Zircaloy-2-Clad, UO 2-Core Simulated Fuel Elements," ANL-7225, January-June 1966, p 177, November 1966. 4. Risher, D. H., Jr., and Barry, R. F., "TWINKLE--A Multi- Dimensional Neutron Kinetics Computer Code," WCAP-7979-P-A (Proprietary) and WCAP-8028-A (Nonproprietary), January 1975. 5. Barry, R. F., "LEOPARD--A Spectrum D ependent or Non-Spacial Depletion Code for the IBM-7904," WCAP-3269-26, September 1963. 6. Hargrove, H. G., "FACTRAN-A FORTRAN-IV Code for Thermal Transients in a UO 2 Fuel Rod," WCAP-7908-A, December 1989. 7. Bishop, A. A., Sandburg, R. O., and Tong, L. S., "Forced Convection Heat Transfer at High Pressure After the Critical Heat Flux," ASME 65-HT-31, August 1965. 8. Van Houten, R., "Fuel Rod Failure as a Consequence of Departure from Nucleate Boiling or Dryout," NUREG-0562, June 1979. 9. Johnson, V. J., "Use of 2700
°F PCT Acceptance Limit in Non-LOCA Accidents," NS-NRC-89-3466, October 23, 1989. 15.4.9 STEAMLINE BREAK WITH COINCIDENTAL ROD CLUSTER CONTROL ASSEMBLY WITHDRAWAL AT POWER The automatic rod withdrawal capability of the rod control system is disabled for Vogtle Unit 1 and Unit 2. Physically disabling the automatic rod withdrawal capability eliminates the
possibility that a steam line break event will result in a consequential and coincidental rod
withdrawal. The analysis presented in this section is retained for historical purposes.
15.4.9.1 Introduction The coincidental and consequential occurrence of an uncontrolled RCCA bank withdrawal at power following steamline break event is one of four potential interaction scenarios resulting
from adverse environmental conditions (either in side or outside of containment) following a high VEGP-FSAR-15
15.4-34 REV 19 4/15 energy line break; these scenarios are identified in "IE Information Notice 79-22." The premise
of this concern is that during a high energy line break (such as steamline rupture), certain
sensors used in the control systems could be exposed to an adverse environment. If the
equipment is not qualified for the adverse env ironment, a control system malfunction might occur. The automatic rod control system is one of the control systems that could malfunction. The rod control system relies on the measurement of Tavg , nuclear power, and turbine impulse pressure to determine if control rod motion is required. A small steamline rupture may occur outside
containment near the turbine impulse pressure transmitters or inside containment in the vicinity
of the excore detectors, thus exposing equipment used in the rod control system to an adverse environment. If this equipment is not properly qualified for these conditions, a consequential
RCCA withdrawal following a steamline rupture may occur.
The steamline break affects the rod control system (via either an inside containment break near the excore detectors or an outside containment break near the turbine impulse transmitters) and causes the control rods to withdraw following the initiation of the transient. This causes an increase in reactor power and core heat flux to the point at which an OPT trip setpoint is reached. This trip terminates the most adverse part of the transient. The steamline break causes increased heat removal and subsequent decrease in primary pressure simultaneous
with the increase in reactor power. Secondary pressure also decreases until the low steamline
pressure setpoint is reached, initiating steamline isolation and safety injection actuation.
Because of the lower RCS pressure coincident with the increase in reactor power, the consequences at the point of peak heat flux may be more adverse than the RCCA bank
withdrawal at power transient analyzed in the FSAR.
The most limiting part of this transient pertinent to this study is immediately before reactor trip (i.e., rod motion). The most limiting case is that for the largest steamline break that trips on OPT prior to reaching a reactor trip on a safety injection signal (e.g., low steamline pressure).
Therefore, the analysis assumes the largest steamline break size for which a low steamline
pressure signal will not occur prior to the OPT reactor trip, and the analysis terminates 5 seconds after reactor trip. "Steam System Piping Failure" presented in subsection 15.1.5 bounds the return to power following reactor trip and steamline isolation. If the low steamline
pressure setpoint is reached, a reactor trip on safety injection actuation would result and
terminate the event. Therefore, like the analysis performed for "Uncontrolled Rod Cluster
Control Assembly Bank Withdrawal at Power" (subsection 15.4.2), to demonstrate protection by the T trips, only the applicable range of these trips needs to be considered. Also note that no
credit is taken in the steamline break with coincident rod withdrawal at power analysis for a
reactor trip via the high neutron flux overpower protection signal, since this trip function may be
inoperable due to adverse environmental conditions associated with a steamline break inside
containment.
The performance of the analysis for a steamline break with coincident withdrawal of the control rods due to an adverse environment demonstrates that the corresponding minimum DNBR does
not decrease below the appropriate safety analysis limit DNBR value, and no fuel or clad
damage occurs. Additionally, no system overpr essurization is expected since the steamline
break results in an RCS depressurization as described above.
This is an ANS Condition III/IV incident.
VEGP-FSAR-15
15.4-35 REV 19 4/15 15.4.9.2 Analysis of Effects and Consequences 15.4.9.2.1 Method of Analysis The analysis of this transient uses the LOFTRAN computer code (reference 1). The following assumptions were made for this transient: A. The analysis employs RTDP methodology in determining initial conditions of maximum core power, reactor coolant average temperature, and minimum
reactor coolant pressure. B. For end of life shutdown margin and equilibrium xenon conditions, the analysis assumes the most reactive RCCA stuck in its fully withdrawn position for
conditions following reactor trip. C. The analysis uses a negative moderator coefficient corresponding to the end of life unrodded core. This maximizes the reactivity insertion caused by the
cooldown during the steamline break. D. The analysis assumes the reactor trip setpoint on OPT at a conservative value.
The T trip includes all adverse instrumentation and setpoint errors; the delays
for trip actuation are at the maximum values. E. The analysis bases the RCCA trip insertion characteristic on the assumption that the highest worth assembly is stuck in its fully withdrawn position. F. A spectrum of break sizes are analyzed. The limiting break is the largest break size for which a low steam line pressure signal will not occur and a reactor trip occurs on OPT. G. The calculation of the steam flow during a steamline break uses the Moody Curve for f L/D = 0. H. A conservatively large reactivity insertion rate is used.
No single active failure in any plant syst ems or equipment will adversely affect the consequences of the accident.
15.4.9.2.2 Results The minimum DNBR occurred with beginning of life reactivity coefficients and a 0.7 ft break area. The calculated sequence of events for the limiting case is shown in table 15.4.1-1.
Figures 15.4.9-1, 15.4.9-2 and 15.4.9-3 show transient conditions following the steam line rupture with coincident RCCA bank withdrawal.
The steamline break affects the turbine impulse transmitters and causes the control rods to withdraw at the initiation of the transient. This causes an increase in reactor power and core heat flux to the point at which the OPT trip setpoint is reached. The reactor trip terminates the most adverse part of the transient. The steamline break causes increased heat removal and
subsequent decrease in primary pressure simultaneous with the increase in reactor power. If
the transient extends beyond post-reactor trip, secondary pressure will decrease until the low
steamline pressure setpoint is reached, initiating steamline isolation and safety injection
actuation.
VEGP-FSAR-15
15.4-36 REV 19 4/15 The analysis of the steamline break with coincident RCCA bank withdrawal demonstrates that
the DNBR limit is met. The most limiting part of this transient pertinent to this study was
immediately before reactor trip (i.e., rod motion). The transient for the steamline break
presented in subsection 15.1.5 bounds the return to power following reactor trip and steamline
isolation. The other FSAR steamline break analysis assumed a larger break size and initial
conditions corresponding to no-load temperatures (i.e., less stored energy in the RCS and
reactor fuel). The DNBR is always greater than the limit value. Figure 15.4.9-3 shows the
DNBR as a function of time for this transient.
15.4.9.3 Conclusions The analysis demonstrates that the DNBR does not decrease below the limit value and no fuel or clad damage occurs. Additionally, no system overpressurization will occur; thus, all applicable safety criteria are met. As stated in the results, the large steamline break analysis
presented in subsection 15.1.5 bounds the return to power following a reactor trip and steamline
isolation; therefore, there is adequate protection to ensure plant safety for this transient.
15.4.9.4 Reference 1. Burnett, T. W. T., et al., "LOFTRAN Code Description," WCAP-7907-P-A (proprietary), and WCAP-7907-A (nonproprietary), April 1984.
VEGP-FSAR-15 REV 14 10/07 TABLE 15.4.6-1 PARAMETERS
Dilution Flowrates:
Initiator Flowrate (gal/min) 1 63 2 100 3 3.5 4 110 Volumes:
Mode Volume (ft 3) Volume (gal) 3, 4 9583 71,681 5a (loops filled) 4120 30,818 5b (loops not filled) 3460 (a) 25,880 6 (loops not filled) 3460 (a) 25,880
- a. This volume corresponds with the reactor vessel coolant level at the mid-plane of the
nozzles.
VEGP-FSAR-15 REV 14 10/07 TABLE 15.4.8-1 PARAMETERS USED IN THE ANALYSIS OF THE ROD CLUSTER CONTROL ASSEMBLY EJECTION ACCIDENT
Time in Life HZP Beginning HZP Beginning HZP End HZP End Power level (%)
0 102 0 102 Ejected rod worth (% k) 0.75 0.24 0.84 0.25 Delayed neutron fraction (%) 0.54 0.57 0.46 0.46 Doppler feedback reactivity
weighting 1.744 1.30 3.55 1.30 Trip reactivity (%k) 2.0 4.0 2.0 4.0 F Q before rod ejection
-- 2.55 -- 2.55 F Q after rod ejection 11.0 5.5 26.0 6.0 Number of operational pumps 2 4 2 4 Maximum fuel pellet
average temperature at the hot spot (°F) 3425 4091 3412 3970 Maximum fuel center temperature at the hot spot (°F) 3985 >4900 3891 >4800 Maximum fuel stored energy at the hot spot (cal/g) 144.9 179.2 144.2 172.7 Percent of fuel melted
at the hot spot 0
<10 0 <10
VEGP-FSAR-15 REV 15 4/09 TABLE 15.4.8-2 (SHEET 1 OF 2)
PARAMETERS USED IN EVALUATING THE RADIOLOGICAL CONSEQUENCES OF A CONTROL ROD EJECTION ACCIDENT
I. Source Data
A. Core power level (MWt) 3636 B. Total steam generator tube leakage (gal/min) 1 C. Reactor coolant iodine activity prior to accident An assumed preaccident
iodine spike, which has
resulted in the DE of 60
µCi/g of I-131 in the reactor coolant. See table 15A-6. D. Gap activity released to reactor coolant from failed fuel 10 percent
See table 15A-3. E. Melted fuel 0.25 percent of core (0.00125 of core iodines, 0.0025 of core noble gases) F. Reactor coolant noble gas activity Based on 1 percent defective
fuel. See table 15A-4. G. Secondary system initial activity DE of 0.1
µCi/g of I-131. H. Reactor coolant mass (g) 2.3 x 10 8 I. Secondary coolant mass, 4 generators (g) 1.9 x 10 8 J. Offsite power Lost after trip II. Atmospheric Dispersion Factors See table 15A-2.
VEGP-FSAR-15 REV 15 4/09 TABLE 15.4.8-2 (SHEET 2 OF 2)
III. Activity Release Data
A. Containment
- 1. Leak rate (percent/day) 0.2 2. Mass of primary coolant discharged
to containment (lb) 0 to 1600 s 9.3 x 10 4 1600 to 4700 s 3.4 x 10 5 4700 to 10000 s 6.9 x 10 5 3. Fraction of activity carried by reactor
coolant spill that
is assumed to be
airborne Iodines 0.45 Noble gases 1.0 B. Steam generators
- 1. Primary-to-secondary leak rate (gal/min)(a) 1.0 2. Mass of steam released (lb) 0 - 214 s 4.9 x 10 4 3. Iodine partition factor 100
- a. Based on water at 62.4 lb/ft
- 3.
REV 14 10/07 NEUTRON FLUX TRANSIENT FOR UNCONTROLLED ROD WITHDRAWAL FROM A SUBCRITICAL CONDITION FIGURE 15.4.1-1
REV 14 10/07 THERMAL FLUX TRANSIENT FOR UNCONTROLLED ROD WITHDRAWAL FROM A SUBCRITICAL CONDITION FIGURE 15.4.1-2
REV 14 10/07 FUEL AND CLAD TEMPERATURE FOR UNCONTROLLED ROD WITHDRAWAL FROM A SUBCRITICAL CONDITION FIGURE 15.4.1-3
REV 14 10/07 UNCONTROLLED RCCA BANK WITHDRAWAL FROM FULL POWER WITH MINIMUM REACTIVITY FEEDBACK (80 pcm/s WITHDRAWAL RATE)
FIGURE 15.4.2-1 REV 14 10/07 UNCONTROLLED RCCA BANK WITHDRAWAL FROM FULL POWER WITH MINIMUM REACTIVITY FEEDBACK (80 pcm/s WITHDRAWAL RATE)
FIGURE 15.4.2-2
REV 14 10/07 UNCONTROLLED RCCA BANK WITHDRAWAL FROM FULL POWER WITH MINIMUM REACTIVITY FEEDBACK (80 pcm/s WITHDRAWAL RATE)
FIGURE 15.4.2-3 REV 14 10/07 UNCONTROLLED RCCA BANK WITHDRAWAL FROM FULL POWER WITH MINIMUM REACTIVITY FEEDBACK (2 pcm/s WITHDRAWAL RATE)
FIGURE 15.4.2-4
REV 14 10/07 UNCONTROLLED RCCA BANK WITHDRAWAL FROM FULL POWER WITH MINIMUM REACTIVITY FEEDBACK (2 pcm/s WITHDRAWAL RATE)
FIGURE 15.4.2-5 REV 14 10/07 UNCONTROLLED RCCA BANK WITHDRAWAL FROM FULL POWER WITH MINIMUM REACTIVITY FEEDBACK (2 pcm/s WITHDRAWAL RATE)
FIGURE 15.4.2-6
REV 14 10/07 MINIMUM DNBR VS. REACTIVITY INSERTION RATE FOR ROD WITHDRAWAL AT 100 PERCENT POWER FIGURE 15.4.2-7
REV 14 10/07 MINIMUM DNBR VS. REACTIVITY INSERTION RATE FOR ROD WITHDRAWAL FORM 60 PERCENT POWER FIGURE 15.4.2-8
REV 14 10/07 MINIMUM DNBR VS. REACTIVITY INSERTION RATE FOR ROD WITHDRAWAL FROM 10 PERCENT POWER FIGURE 15.4.2-9
REV 14 10/07 NUCLEAR POWER TRANSIENT AND CORE HEAT FLUX TRANSIENT FOR DROPPED RCCA FIGURE 15.4.3-1
REV 14 10/07 PRESSURIZER PRESSURE TRANSIENT AND CORE AVERAGE TEMPERATURE TRANSIENT FOR DROPPED RCCA FIGURE 15.4.3-2
REV 14 10/07 IMPROPER STARTUP OF AN INACTIVE REACTOR COOLANT PUMP FIGURE 15.4.4-1
REV 14 10/07 IMPROPER STARTUP OF AN INACTIVE REACTOR COOLANT PUMP FIGURE 15.4.4-2
REV 14 10/07 IMPROPER STARTUP OF AN INACTIVE REACTOR COOLANT PUMP FIGURE 15.4.4-3
REV 14 10/07 IMPROPER STARTUP OF AN INACTIVE REACTOR COOLANT PUMP FIGURE 15.4.4-4
REV 14 10/07 IMPROPER STARTUP OF AN INACTIVE REACTOR COOLANT PUMP FIGURE 15.4.4-5
REV 14 10/07 REPRESENTATIVE % CHANGE IN LOCAL ASSY.
AVG. POWER FOR INTERCHANGE BETWEEN REGION 1 AND REGION 3 ASSY.
FIGURE 15.4.7-1
REV 14 10/07 REPRESENTATIVE % CHANGE IN LOCAL ASSY.
AVG. POWER FOR INTERCHANGE BETWEEN REGION 1 AND REGION 2 ASSY. WITH BP RODS RETAINED BY THE REGION 2 ASSY.
FIGURE 15.4.7-2 REV 14 10/07 REPRESENTATIVE % CHANGE IN LOCAL ASSY.
AVG. POWER FOR INTERCHANGE BETWEEN REGION 1 AND REGION 2 ASSY. WITH THE BP RODS TRANFERRED TO REGION 1 ASSY.
FIGURE 15.4.7-3
REV 14 10/07 REPRESENTATIVE % CHANGE IN LOCAL ASSY.
AVG. POWER FOR ENRICHMENT ERROR (REGION 2 ASSY. LOADED INTO CORE CENTRAL POSITION)
FIGURE 15.4.7-4
REV 14 10/07 REPRESENTATIVE % CHANGE IN LOCAL ASSY.
AVG. POWER FOR LOADING REGION 2 ASSY. INTO REGION 1 POSITION NEAR CORE PERIPHERY FIGURE 15.4.7-5
REV 14 10/07 NUCLEAR POWER TRANSIENT BOL FULL POWER FIGURE 15.4.8-1
REV 14 10/07 HOT SPOT FUEL AND CLAD TEMPERATURE VS. TIME BOL FULL POWER FIGURE 15.4.8-2
REV 14 10/07 NUCLEAR POWER TRANSIENT EOL ZERO POWER FIGURE 15.4.8-3
REV 14 10/07 HOT SPOT FUEL AND CLAD TEMPERATURE VS. TIME EOL ZERO POWER FIGURE 15.4.8-4
REV 14 10/07 STEAM LINE BREAK COINCIDENT WITH CONTROL ROD WITHDRAWAL: STEAM FLOW AND STEAM PRESSURE FIGURE 15.4.9-1
REV 14 10/07 STEAM LINE BREAK COINCIDENT WITH CONTROL ROD WITHDRAWAL: RCS PRESSURE AND CORE AVERAGE TEMPERATURE FIGURE 15.4.9-2
REV 14 10/07 STEAM LINE BREAK COINCIDENT WITH CONTROL ROD WITHDRAWAL: CORE HEAT FLUX AND REACTIVITY FIGURE 15.4.9-3
VEGP-FSAR-15
15.5-1 REV 14 10/07 15.5 INCREASE IN REACTOR COOLANT INVENTORY Discussion and analysis of the following events which cause an increase in reactor coolant
inventory are presented in this section: A. Inadvertent operation of the emergency core cooling system (ECCS) during power operation. B. Chemical and volume control system (CVCS) malfunction that increases reactor coolant inventory. C. A number of boiling water reactor (BWR) transients (not applicable to VEGP). 15.5.1 INADVERTENT OPERATION OF THE EMERGENCY CORE COOLING SYSTEM DURING POWER OPERATION 15.5.1.1 Identification of Causes and Accident Description Inadvertent operation of the Emergency Core Cooling System (ECCS) at power could be
caused by operator error, test sequence error, or a false electrical actuation signal. A spurious
signal initiated after the logic circuitry in one solid-state protection system train for any of the
following engineered safety feature (ESF) functions could cause this incident by actuating the
ESF equipment associated with the affected train. A. High containment pressure. B. Low pressurizer pressure.
C. Low steam line pressure.
Following the actuation signal, the suction of the coolant charging pumps diverts from the volume control tank to the refueling water storage tank. Simultaneously, the valves isolating the
injection header from the charging pumps open and the normal charging line isolation valves
close. The charging pumps force the borated water from the RWST through the pump
discharge header, the injection line, and into the cold leg of each loop. The safety injection (SI)
pumps also start automatically but provide no flow when the reactor coolant system (RCS) is at
normal pressure. The passive accumulator tank safety injection and low head system are
available. However, they do not provide flow when the reactor coolant system (RCS) is at normal pressure.
A SI signal normally results in a direct reactor trip and a turbine trip. However, any single fault that actuates the ECCS will not necessarily produce a reactor trip. If an SI signal generates a
reactor trip, the operator should determine if the signal is spurious. If the SI signal is
determined to be spurious, the operator should terminate SI and maintain the plant in the hot
standby condition as determined by appropriate recovery procedures. If repair of the ESF
actuation system instrumentation is necessary, future plant operation will be in accordance with the Technical Specifications.
If the reactor protection system does not produce an immediate trip as a result of the spurious SI signal, the reactor experiences a negative reactivity addition due to the injected boron, which
causes a decrease in reactor power. The power mismatch causes a drop in Tavg and consequent coolant shrinkage. The pressurizer pressure and water level decrease. Load
decreases due to the effect of reduced steam pressure on load after the turbine throttle valve is VEGP-FSAR-15
15.5-2 REV 14 10/07 fully open. If automatic rod control is used, t hese effects will lessen until the rods have moved out of the core. The transient is eventually te rminated by the reactor protection system low
pressurizer pressure trip or by manual trip.
The time to trip is affected by initial operating conditions. These initial conditions include the core burnup history which affects initial boron concentration, rate of change of boron
concentration, and Doppler and moderator coefficients. 15.5.1.2 Analysis of Effects and Consequences 15.5.1.2.1 Method of Analysis Inadvertent operation of the ECCS is analyzed using the LOFTRAN (1) computer code. The code simulates the neutron kinetics, RCS, pressurizer, pressurizer relief and safety valves, pressurizer spray, feedwater system, steam generator, steam generator safety valves, and the
effect of the SI system. The code computes pertinent plant variables including temperatures, pressures, and power level.
Inadvertent operation of the ECCS at power is classified as a Condition II event, a fault of moderate frequency. The criteria established for Condition II events include the following: A. Pressure in the reactor coolant and main steam systems should be maintained below 110 percent of the design values. B. Fuel cladding integrity shall be maintained by ensuring that the minimum departure from nucleate boiling ratio (DNBR) remains above the 95/95 DNBR
limit for PWRs. C. An incident of moderate frequency should not generate a more serious plant condition without other faults occurring independently. To address criterion C, the analysis historically used the more restrictive criterion that a water-solid pressurizer condition be precluded when the pressurizer is at
or above the set pressure of the pressurizer safety valves (PSVs). This
addressed any concerns regarding subcooled water relief through the plant
PSVs. The current analysis conservatively predicts the minimum time to reaching
a pressurizer water solid condition and the resulting water relief characteristics (if
applicable). An evaluation of the PSV operability for temporary water relief under
the specific conditions of this transient was performed. The evaluation
demonstrated that a more serious plant condition will not result following an
inadvertent ECCS actuation by confirming that the RCS pressure boundary
remains intact for the post-transient plant shutdown.
The inadvertent ECCS actuation at power event is analyzed to determine both the minimum
DNBR value and maximum pressurizer volume (or minimum time to a pressurizer water-solid condition and subsequent water relief). The most limiting case with respect to DNB is a
minimum reactivity feedback condition with the plant assumed to be in manual rod control.
Because of the power and temperature reduction during the transient, operating conditions do
not approach the core limits.
For maximizing the potential for pressurizer filling, the most limiting case is a maximum reactivity feedback condition with an immediate reactor trip, and subsequent turbine trip, on the
initiating SI signal. The transient results are presented for each case.
VEGP-FSAR-15
15.5-3 REV 14 10/07 The analysis assumptions are as follows: A. Initial Operating Conditions The DNB case is analyzed with the Revised Thermal Design Procedure as described in WCAP-11397-P-A (reference 2). Initial reactor power, RCS pressure, and temperature are assumed to be at the nominal full power values.
Uncertainties in initial conditions are included in the limit DNBR as described in reference 2. VEGP has a vessel average temperature window from 570
°F to 588.4°F; therefore, cases at each end of this window are analyzed for pressurizer filling. The initial conditions for these cases assume maximum uncertainties on
power (+2 percent), vessel average temperature (-5
°F), and pressurizer pressure
(-50 psia). B. Moderator and Doppler Coefficients of Reactivity The minimum feedback case (DNB) assumes a positive (+7 pcm/
°F) moderator temperature coefficient and a low absolute value Doppler power coefficient at beginning of life (BOL). The maximum feedback case (pressurizer filling)
assumes a large (absolute value) negative moderator temperature coefficient
and a most-negative Doppler power coefficient. C. Reactor Control For the DNB case (without direct reactor trip on SI) the reactor is assumed to be in manual rod control. D. Pressurizer Pressure Control For the DNB case, the pressurizer heaters are inoperable. This assumption yields a higher rate of pressurizer decrease. The pressurizer spray portion of the pressurizer pressure control system is assumed available in order to minimize
the RCS pressure. The PORVs are also assumed operable. PORVs reduce
RCS pressure which is conservative for DNB analyses. For the pressurizer filling cases, the following pressurizer pressure control system assumptions are made:
- Normal operation of the pressurizer spray is assumed. Spray actuates as a result of the pressure increase. Spray is assumed to be fully effective in condensing steam and thus maintaining a lower pressure until the water level
increases to the point where the spray nozzle is submerged (i.e., when the
pressurizer is nearly filled). This maximizes the ECCS injection flow.
- Operation of the pressurizer heaters minimizes the time to fill the pressurizer and subsequent water relief through the PSV(s). This is important since the
maximum number of water relief cycles supported in the valve operability
evaluation is three. Operation of the heaters, however, increases the
temperature of the water that is relieved. Colder water relief temperatures
are more limiting with respect to valve operability. Therefore, to ensure that
both criteria are conservatively addressed, cases have been analyzed
assuming both normal heater operation and no heater operation.
- PORVs are not assumed as an automatic pressure control system for the pressurizer filling case. Automatic actuation of the PORVs would directly
mitigate the event consequences by preventing water relief through the
PSVs. Operator action to make one PORV available following an acceptable VEGP-FSAR-15
15.5-4 REV 14 10/07 delay is credited in the analysis to mitigate the event. Should the PORVs fail
due to water relief, the block valves would be available to isolate the RCS. E. ECCS Injection The inadvertent ECCS analysis models a maximum ECCS flow rate that bounds operation at the original design which included a positive displacement pump and the plant configuration with the replacement centrifugal pump. Safety injection (SI) is actuated at time zero, with flow injected to the RCS from two high-head
centrifugal charging pumps plus the normal charging pump. Both high- head
charging and SI pumps automatically start on an SI signal, and the associated
alternate minimum flow protection lines receive a signal to open at high RCS
back pressures. The failure of the normal charging pump to be stripped from the
bus was taken as the single failure since it results in higher flow rates than the
failure to open one safety-related miniflow path. The analysis also assumes zero
injection line purge volume for calculation simplicity; thus, the boration transient
begins immediately in the analysis. F. Turbine Load For the DNB case (without direct reactor trip/turbine trip on SI), the turbine load remains constant until the governor drives the throttle valve wide open. After the throttle valve is full open, turbine load decreases as steam pressure drops. G. Reactor Trip Reactor trip is initiated by a low pressurizer pressure signal at 1935 psia for the DNB case. The pressurizer filling case assumes reactor trip on the initiating SI signal. H. Decay Heat Core residual heat generation is based on the 1979 version of ANS 5.1 (reference 3). ANSI/ANS-5.1-1979 is a conservative representation of the decay energy release rates. Long-term operation at the initial power level preceding the
trip is assumed. I. Pressurizer Safety Valves The safety valves open at a pressure of 2425 psia which corresponds to a tolerance of -2 percent relative to the set pressure of 2475 psia. The valves are assumed to close at a pressure of 2300 psia, which corresponds to a blowdown
of 5 percent below the opening pressure of 2425 psia. J. Operator Actions An operator action, to make one PORV available for water relief, was assumed at 590 seconds in the pressurizer fill case initialized from the low end of the vessel average window (570
°F), and 625 seconds was assumed for the pressurizer fill case initialized from the high end of the vessel average window (588.4
°F). 15.5.1.2.2 Results The transient responses for the DNB and limiting pressurizer filling cases are shown in figure 15.5.1-1. Table 15.5.1-1 shows the calculated sequence of events.
VEGP-FSAR-15
15.5-5 REV 14 10/07 For the DNB case, nuclear power starts decreasing immediately due to boron injection, but
steam flow does not decrease until later in the transient when the turbine throttle valve is wide
open. The mismatch between load and nuclear power causes Tavg , pressurizer water level, and pressurizer pressure to drop. The reactor trips and control rods start moving into the core when
the pressurizer pressure reaches the pressurizer low pressure trip setpoint. The DNBR
increases throughout the transient.
For the pressurizer filling case, reactor trip occurs at event initiation followed by a rapid initial cooldown of the RCS. Coolant contraction results in a short-term reduction in pressurizer
pressure and water level. The combination of the RCS heatup, due to residual RCS heat
generation, and ECCS injected flow causes the pressure and level transients to rapidly turn
around. Pressurizer water level then increases throughout the transient.
In the case initialized from the low end of the vessel average window (570
°F), the analysis assumes that at 590 seconds the operator manually opens a PORV. For the case initialized from the high end of the vessel average window (588.4
°F), this operator action is assumed at 625 seconds. In each of these cases, once the PORV is fully open, the RCS begins to depressurize to below the pressure where the safety valves reseat.
15.5.1.3 Conclusions Results of the analysis show that spurious ECCS operation without immediate reactor trip does not present any hazard to the integrity of the RCS with respect to DNBR. The minimum DNBR
is never less than the initial value. Thus, there will be no cladding damage and no release of
fission products to the RCS. If the reactor does not trip immediately, the low pressurizer
pressure reactor trip will provide protecti on. This trips the turbine and prevents excess cooldown, which expedites recovery from the incident.
With respect to pressurizer filling, the pressurizer may reach a water-solid condition. However, the resulting potential water relief will not impair PSV operability. The RCS pressure boundary
will therefore remain intact and the event will not generate a more serious plant condition.
15.5.1.4 Reference
- 1. Burnett, T.W.T., et al., "LOFTRAN Code Description," WCAP-7907-P-A , (proprietary), WCAP-7907-A (nonproprietary), April 1984. 2. Friedland, A.J. and Ray, S., "Revised Thermal Design Procedure," WCAP-11397-P-A , April 1989. 3. ANSI/ANS-5.1-1979, "Decay Heat Power in Light Water Reactors," August 29, 1979.
15.5.2 CHEMICAL AND VOLUME CONTROL SYSTEM MALFUNCTION THAT INCREASES REACTOR COOLANT INVENTORY An increase in reactor coolant inventory which results from the addition of cold, unborated water to the reactor coolant system (RCS) is analyzed in subsection 15.4.6, Chemical and Volume
Control System Malfunction That Results in a Decrease in Boron Concentration in the Reactor
Coolant. An increase in reactor coolant inventory which results from the injection of highly
borated water into the RCS is analyzed in subsection 15.5.1, Inadvertent Operation of the
Emergency Core Cooling System During Power Operation.
VEGP-FSAR-15
15.5-6 REV 14 10/07 15.5.3 A NUMBER OF BOILING WATER REACTOR TRANSIENTS This subsection is not applicable to the VEGP.
VEGP-FSAR-15 REV 14 10/07 TABLE 15.5.1-1 (Sheet 1 of 2)
TIME SEQUENCE OF EVENTS FOR INCIDENTS WHICH RESULT IN AN INCREASE IN REACTOR COOLANT INVENTORY (Accident: Inadvertent operation of ECCS during power operation)
Case Event Time(s) DNBR case:
SI pumps begin injecting borated water 0.0 Low pressurizer pressure reactor
trip setpoint reached 45.5 Rods begin to drop 47.5 Minimum DNBR occurs (a)
Pressurizer filling case:
Pressurizer Heaters On Off A nominal T AVG = 570.7°F SI actuation, reactor trip 0.0 0.0 Operator action to manually
open PORV at 590 s Pressurizer fills with water 448.0 471.0 PSV opens - cycle #1
495.3 518.7 PSV closes - cycle #1
499.2 522.7 PSV opens - cycle #2
529.4 553.0 PSV closes - cycle #2
533.3 556.9 PSV opens - cycle #3
561.0 584.4 PSV closes - cycle #3 564.8 588.0 Time of last PSV cycle (minimum
final water relief temperature) 565.0 (633.8°F) 588.0 (628.4°F) Operator action to open PORV 590.0 590.0 VEGP-FSAR-15 REV 14 10/07 TABLE 15.5.1-1 (Sheet 2 of 2)
Accident Event Time(s) Pressurizer Heaters On Off A nominal T AVG = 588.4°F SI actuation, reactor trip 0.0 0.0 Operator action to manually
open PORV at 625 s Pressurizer fills with water 480.0 501.5 PSV opens - cycle #1
529.4 550.8 PSV closes - cycle #1
533.2 554.4 PSV opens - cycle #2
564.5 586.4 PSV closes - cycle #2
568.3 590.3 PSV opens - cycle #3
597.9 620.9 PSV closes - cycle #3 601.7 624.8 Time of last PSV cycle (minimum
final water relief temperature) 602.0 (636.9°F) 625.0 (631.8°F) Operator action to open PORV 625.0 625.0
- a. DNBR does not decrease below its initial value.
REV 14 10/07 INADVERTENT OPERATION OF ECCS AT POWER FIGURE 15.5.1-1 (SHEET 1 OF 9)
REV 14 10/07 INADVERTENT OPERATION OF ECCS AT POWER FIGURE 15.5.1-1 (SHEET 2 OF 9)
REV 14 10/07 INADVERTENT OPERATION OF ECCS AT POWER FIGURE 15.5.1-1 (SHEET 3 OF 9)
REV 14 10/07 INADVERTENT OPERATION OF ECCS AT POWER - NUCLEAR POWER AND STEAM FLOW AS A FUNCTION OF TIME (TAVG=570.7
°F, W/O Pressurizer Heaters)
FIGURE 15.5.1-1 (SHEET 4 OF 9)
REV 14 10/07 INADVERTENT OPERATION OF ECCS AT POWER -
PRESSURIZER PRESSURE AND WATER VOLUME AS A FUNCTION OF TIME (T AVG=570.7 °F, W/O Pressurizer Heaters)
FIGURE 15.5.1-1 (SHEET 5 OF 9)
REV 14 10/07 INADVERTENT OPERATION OF ECCS AT POWER - CORE AVERAGE TEMPERATURE AS A FUNCTION OF TIME (T AVG=570.7 °F, W/O Pressurizer Heaters)
FIGURE 15.5.1-1 (SHEET 6 OF 9)
REV 14 10/07 INADVERTENT OPERATION OF ECCS AT POWER - NUCLEAR POWER AND STEAM FLOW AS A FUNCTION OF TIME (T AVG=588.4 °F, W/O Pressurizer Heaters)
FIGURE 15.5.1-1 (SHEET 7 OF 9)
REV 14 10/07 INADVERTENT OPERATION OF ECCS AT POWER - PRESSURIZER PRESSURE AND WATER VOLUME AS A FUNCTION OF TIME (T AVG=588.4 °F, W/O Pressurizer Heaters)
FIGURE 15.5.1-1 (SHEET 8 OF 9)
REV 14 10/07 INADVERTENT OPERATION OF ECCS AT POWER - CORE AVERAGE TEMPERATURE AS A FUNCTION OF TIME (T AVG=588.4 °F, W/O Pressurizer Heaters)
FIGURE 15.5.1-1 (SHEET 9 OF 9)
VEGP-FSAR-15
REV 14 10/07 TABLE 15.6.1-1
TIME SEQUENCE OF EVENTS FOR INCIDENTS WHICH CAUSE A DECREASE IN REACTOR COOLANT INVENTORY
Accident Event Time (s) Inadvertent opening of a pressurizer safety valve Pressurizer safety valve
opens fully 0.0 Overtemperature T reactor trip setpoint reached 24.5 Rods begin to drop 26.5 Minimum DNBR occurs 27.0
VEGP-FSAR-15
REV 14 10/07 TABLE 15.6.3-1 OPERATOR ACTION TIMES FOR DESIGN BASIS SGTR ANALYSIS Action Time (min)
Identify and isolate AFW flow to ruptured steam
generator 7
Isolate ruptured steam generator 20 min or LOFTTR2 calculated time to recover
to 33-percent narrow
range level in the ruptured
SG, whichever is longer (a)
Operator action time to initiate cooldown 19 (overfill analysis)
9 (dose analysis)
Cooldown Calculated by LOFTTR2
Operator action time to initiate depressurization 5
Depressurization Calculated by LOFTTR2
Operator action time to initiate SI termination 3
SI termination and pressure equalization Calculated time for SI termination and
equalization of RCS and
ruptured SG pressures
- a. At-power testing at VEGP with steam generator narrow range lower level tap relocation has
shown that the steam generator narrow range level will not drop below 33 percent following a
reactor trip. Therefore, it was conservatively assumed that the ruptured SG is isolated at 20
minutes.
VEGP-FSAR-15
REV 14 10/07 TABLE 15.6.3-2 SEQUENCE OF EVENTS
Event Time (s)
SG tube rupture 0
Reactor trip 43.8 SI actuated 357 AFW flow isolated to ruptured steam generator 420 Ruptured SG isolated 1200 Ruptured SG PORV fails open 1202 Ruptured SG PORV block valve closed 2162 RCS cooldown initiated 2702 RCS cooldown terminated 3498 RCS depressurization initiated 3800 RCS depressurization terminated 3902 SI terminated 4082 Break flow terminated 5412
VEGP-FSAR-15
REV 15 4/09 TABLE 15.6.3-6 AND TABLE 15.6.3-7 DELETED
VEGP-FSAR-15
REV 15 4/09 TABLE 15.6.3-9 DELETED
VEGP-FSAR-15 REV 16 10/10 TABLE 15.6.5-1
SUMMARY
OF LARGE BREAK LOCA ANALYSIS ASSUMPTIONS
Core power 3565 MWt Calorimetric uncertainty 2%
Fuel type 17 x 17 Total core peaking factor, F Q 2.50 Hot channel enthalpy rise factor, FH 1.65 K(Z) limit 1.0 from 0 to 6 ft; 1.0 to 0.925 from 6 to 12 ft
Thermal design flow 93,600 gpm/loop
Nominal vessel average temperature 570.7 °F/588.4 °F (a)
Vessel average temperature uncertainty +/-6 °F
Pressurizer pressure 2250 psia
Pressurizer pressure uncertainty
+/-50 psi Steam generator tube plugging 10%
Accumulator water volume, nominal 900 ft 3/accumulator
Accumulator gas pressure, minimum 611.3 psia
Safety injection pumped flow Figures 15.6.5-17 and 15.6.5-18
Containment parameters Paragraph 6.2.1.5
- a. Note that the LOCBART calculations are based on a T AVG window of 573.0°F to 588.4°F, and an evaluation was performed to support operation at T AVG values between 570.7°F and 573.0°F with up to 10 percent steam generator tube plugging. See paragraph
15.6.5.3.3.1.1 for more information.
VEGP-FSAR-15 REV 14 10/07 TABLE 15.6.5-2 LARGE BREAK LOCA RESULTS C D=0.4 Low T AVG MIN SI Cosine Shape non-IFBA C D=0.6 Low T AVG MIN SI Cosine Shape non-IFBA C D=0.8 Low T AVG MIN SI Cosine Shape non-IFBA C D=1.0 Low T AVG MIN SI Cosine Shape non-IFBA C D=0.6 High T AVG MIN SI Cosine Shape non-IFBA C D=0.6 Low T AVG MAX SI Cosine Shape non-IFBA C D=0.6 Low T AVG MIN SI 8.5' Shape non-IFBA C D=0.6 Low T AVG MIN SI Cosine Shape 128-IFBA C D=0.6 Low T AVG MIN SI Cosine Shape 156-IFBA Peak Cladding
Temperature (°F) 1887.2 1936.3 1909.2 1878.6 1932.9 1868.9 1919.7 2040.0 2061.6 Peak Cladding
Temperature
Time(s) 191.5 174.4 168.8 162.5 172.8 181.0 199.1 176.1 175.6 Peak Cladding
Temperature
Location (ft) 7.25 7.25. 7.25 7.25 7.25 7.25 9.0 7.25 7.25 Maximum Local
Zr/H 2 O Reaction (%) <17.0 <17.0 <17.0 <17.0 <17.0 <17.0 <17.0 <17.0 <17.0 Maximum Local
Zr/H 2 O Location (ft) 7.25 7.25 7.25 7.25 5.25 7.25 9.0 7.25 7.25 Total Zr/H 2 O Reaction (%) <1.0 <1.0 <1.0 <1.0 <1.0 <1.0 <1.0 <1.0 <1.0 Hot Rod Burst
Time(s) 71.11 43.85 39.97 42.77 41.35 43.85 48.48 43.85 51.62 Hot Rod Burst
Loc. (ft) 6.25 5.75 5.50 5.50 5.25 5.75 8.25 5.75 5.50
VEGP-FSAR-15 REV 14 10/07 TABLE 15.6.5-3 LARGE BREAK LOCA TIME SEQUENCE OF EVENTS
RESULTS (sec)
C D=0.4 Low T AVG MIN SI Cosine Shape non-IFBA C D=0.6 Low T AVG MIN SI Cosine Shape non-IFBA C D=0.8 Low T AVG MIN SI Cosine Shape non-IFBA C D=1.0 Low T AVG MIN SI Cosine Shape non-IFBA C D=0.6 High T AVG MIN SI Cosine Shape non-IFBA C D=0.6 Low T AVG MAX SI Cosine Shape non-IFBA C D=0.6 Low T AVG MIN SI 8.5' Shape non-IFBA C D=0.6 Low T AVG MIN SI Cosine Shape 128-IFBA C D=0.6 Low T AVG MIN SI Cosine Shape 156-IFBA Start 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Reactor Trip Signal 0.44 0.43 0.42 0.42 0.49 0.43 0.43 0.43 0.43 Safety Injection
Signal 2.6 2.0 1.8 1.6 2.0 2.0 2.0 2.0 2.0 Accumulator
Injection 19.6 13.6 11.0 9.8 14.8 13.6 13.8 13.6 13.6 End of Blowdown 41.1 33.4 28.8 26.7 31.7 33.4 33.1 33.4 33.4 Start of Safety Injection 42.6 42.0 41.8 41.6 42.0 42.0 42.0 42.0 42.0 Bottom of Core
Recovery 55.5 45.9 39.2 36.8 45.3 45.6 44.1 45.9 45.9 Accumulator
Empty 61.7 54.7 51.0 49.0 54.4 55.4 54.6 54.7 54.7
VEGP-FSAR-15 REV 16 10/10 TABLE 15.6.5-5
SUMMARY
OF SMALL BREAK LOCA ANALYSIS ASSUMPTIONS
Core power 3565 MWt Calorimetric uncertainty 2%
Fuel type 17 x 17 Total core peaking factor, F Q 2.58 Hot channel enthalpy rise factor, FH 1.7 K(Z) limit 1.0 from 0 to 6 ft; 1.0 to 0.925 from 6 to 12 ft Thermal design flow 93,600 gmp/loop
Nominal vessel average temperature 570.7 °F/588.4 °F
Vessel average temperature uncertainty
+/-6 °F Pressurizer pressure 2250 psia
Pressurizer pressure uncertainty
+/-50 psi Steam generator tube plugging 10%
Accumulator water volume, nominal 900 ft 3/accumulator
Accumulator gas pressure, minimum 611.3 psia
Safety injection pumped flow Figures 15.6.5-20 and 15.6.5-21
Power shape Figure 15.6.5-22
VEGP-FSAR-15 REV 14 10/07 TABLE 15.6.5-6 SMALL BREAK LOCA LOW T AVG NOTRUMP TRANSIENT RESULTS
Event Time (sec) 2 in.(a) 3 in. 4 in. Break initiation 0 0 0 Reactor trip signal 35.5 14.9 8.58 S-signal 76.1 28.0 16.6 SI delivered 116.1 68.0 56.6 Loop seal clearing (b) 1090 473 280 Core uncovery N/A 707 737 Accumulator injection N/A 1888 945 RWST empty time 2537.7 2479.4 2441.8 PCT time N/A 1665 973.4 Core recovery N/A 2388 1567
- a. Note that there was no core uncovery for the 2-in. break case.
- b. Loop seal clearing is defined as break vapor flow > 1 lb/s.
VEGP-FSAR-15 REV 14 10/07 TABLE 15.6.5-7 SMALL BREAK LOCA LOW T AVG BEGINNING OF LIFE (BOL) ROD HEATUP RESULTS
2 in.(a) 3 in. 4 in. PCT (°F) N/A 1138 975 PCT time (s) N/A 1665 973.4 PCT elevation (ft) N/A 11.25 10.75 Burst time (s) N/A N/A N/A Burst elevation (ft) N/A N/A N/A Max. local ZrO 2 (%) N/A 0.08 0.02 Max. local ZrO 2 elev (ft) N/A 11.25 11.00 Core-Wide avg. ZrO 2 (%) N/A 0.02 0.01
- a. Note that there was no core uncovery for the 2-in. break case.
VEGP-FSAR-15 REV 14 10/07 TABLE 15.6.5-8 PEAK CLAD TEMPERATURE CHANGES FOR SMALL BREAK LOCA ANALYSIS
Unit 1 Unit 2 Calculated PCT from ECCS analysis (Analysis of Record) 1138.0 °F 1138.0 °F Total Resultant PCT 1138.0 °F 1138.0 °F
VEGP-FSAR-15 REV 15 4/09 TABLE 15.6.5-9 (SHEET 1 OF 4)
PARAMETERS USED IN EVALUATING THE RADIOLOGICAL CONSEQUENCES OF A LOSS-OF-COOLANT ACCIDENT
Source Data
Core power level (MWt) 3636 Core activity released in the containment atmosphere after
20 s into the accident (%)
Noble gas 100 Iodine 50 Core inventories Table 15A-3 Iodine distribution (%)
Elemental 91 Organic 4 Particulate 5 Atmospheric Dispersion Factors Table 15A-2 Control Room Parameters Tables 15A-1 and 15A-2
Containment Leakage of Activity
Containment leak rate (volume %/day) 0 to 24 h 0.2 1 to 30 days 0.1 Unfiltered containment leakage (%)
100 Deposition iodine removal constants elemental iodine only (h
-1) 4.8 (DF 200)
VEGP-FSAR-15 REV 15 4/09 TABLE 15.6.5-9 (SHEET 2 OF 4)
Credit for containment sprays
Spray iodine removal constants (h
-1) Elemental 10 (1) (DF 21.4) Organic 0.0 Particulate 4.2 (DF 50) 0.42 (DF > 50) Duration of sprays (h) 2 Sprayed volume (%)
78 Unsprayed volume (%)
22 Number of fan coolers operating 2 Sprayed-unsprayed mixing rate (ft 3/min) 87,000 Containment volume (ft
- 3) 2.93 x 10 6 Activity released to containment atmosphere
Isotope Curies I-131 5.15 x 10 7 I-132 7.50 x 10 7 I-133 1.05 x 10 8 I-134 1.13 x 10 8 I-135 9.75 x 10 7 Xe-131m 7.13 x 10 5 Xe-133m 3.01 x 10 7 Xe-133 2.12 x 10 8 Xe-135m 4.18 x 10 7 Xe-135 4.65 x 10 7 Xe-138 1.69 x 10 8 Kr-85m 2.68 x 10 7 Kr-85 1.04 x 10 6 Kr-87 4.93 x 10 7 Kr-88 7.02 x 10 7
VEGP-FSAR-15 REV 15 4/09 TABLE 15.6.5-9 (SHEET 3 OF 4)
Containment Purge of Activity
Purge flowrate (ft 3/min) 5000 Duration of purge, from accident initiation (s) 8.5 Reactor coolant iodine spike 60 (µCi/g I-131 dose equivalent)
Reactor coolant activity airborne in the containment (%)
Noble gas 100 Iodine 100 Activity released to the containment atmosphere from the reactor coolant
Isotope Curies I-131 1.12 x 10 4 I-132 1.14 x 10 4 I-133 2.14 x 10 4 I-134 2.73 x 10 3 I-135 1.05 x 10 4 Xe-131m 5.11 x 10 2 Xe-133m 4.45 x 10 3 Xe-133 6.48 x 10 4 Xe-135m 1.42 x 10 2 Xe-135 2.10 x 10 3 Xe-138 1.87 x 10 2 Kr-85m 5.16 x 10 2 Kr-85 2.12 x 10 3 Kr-87 3.24 x 10 2 Kr-88 9.31 x 10 2
VEGP-FSAR-15 REV 15 4/09 TABLE 15.6.5-9 (SHEET 4 OF 4)
Recirculation Leakage Outside Containment
Leak rate (gal/min, measured at 70 °F) 2
Temperature of recirculating fluid (°F)
0 to 0.5 h No recirculation 0.5 to 2.0 h 240 2.0 to 720 h
< 212 Mass of water in the containment sump (lb) 6.77 x 10 6
Activity in the sump solution at time = 0
Isotope Curies I-131 5.15 x 10 7 I-132 7.50 x 10 7 I-133 1.0 x 10 8 I-134 1.1 x 10 8 I-135 9.75 x 10 7 Volume of building served by the auxiliary
building emergency ventilation system (ft
- 3) 525,000 Auxiliary building emergency ventilation
system parameters (for each of two trains)
Recirculation flow (ft 3/min) 13,950 Discharge flow (ft 3/min) 2970 Elemental iodine filter efficiency (%) 90
__________
Notes: (1) Calculated value is 22.5 h
-1.
VEGP-FSAR-15 REV 15 4/09 TABLE 15.6.5-10 (SHEET 1 OF 7)
DESIGN COMPARISON TO THE REGULATORY POSITIONS OF REGULATORY GUIDE 1.4, ASSUMPTIONS USED FOR EVALUATING THE POTENTIAL RADIOLOGICAL CONSEQUENCES OF A LOSS-OF-COOLANT ACCIDENT FOR PRESSURIZED WATER REACTORS, REVISION 2, JUNE 1974
Regulatory Guide 1.4 Position Design 1. The assumptions related to the release of radioactive material from
the fuel and containment are as follows:
- a. 25% of the equilibrium radioactive iodine inventory
developed from maximum full-power
operation of the core should be
assumed to be immediately
available for leakage from the
primary reactor containment. 91%
of this 25% is to be assumed to be
in the form of elemental iodine; 5%
of this 25% in the form of particulate
iodine; and 4% of this 25% in the
form of organic iodides.
Fifty percent of core
inventory of iodine is
assumed to be
immediately available
for leakage from the
containment. The
iodine is assumed to
be 91% elemental, 5% particulate, and 4% organic. These assumptions are in
accordance with
Section 6.5.2 of
NUREG-0800. b. 100% of equilibrium radioactive noble gas inventory
developed from maximum full-power
operation of the core should be
assumed to be immediately
available for leakage from the
reactor containment.
Conforms. c. The effects of radiological decay during holdup in the
containment or other buildings
should be taken into account.
Conforms. Credit for
radioactive decay is
taken until the activity
is assumed to be
released.
VEGP-FSAR-15 TABLE 15.6.5-10 (SHEET 2 OF 7)
REV 15 4/09 Regulatory Guide 1.4 Position Design
- d. The reduction in the amount of radioactive material available for
leakage to the environment by
containment sprays, recirculating
filter systems, or other engineered
safety features may be taken into
account, but the amount of reduction
in concentration of radioactive
materials should be evaluated on an
individual case basis.
Conforms. e. The primary reactor containment should be assumed to
leak at the leak rate incorporated or
to be incorporated as a technical
specification requirement at peak
accident pressure for the first 24 h
and at 50% of this leak rate for the
remaining duration of the accident.
Peak accident pressure is the
maximum pressure defined in the
Technical Specifications for
containment leak testing.
Conforms. 2. Acceptable assumptions for atmospheric diffusion and dose conversion are:
- a. The 0- to 8-h ground level release concentrations may be
reduced by a factor ranging from 1
to a maximum of 3 (see Figure 1) for
additional dispersion produced by
the turbulent wake of the reactor
building in calculating potential
exposures. The volumetric building
wake correction, as defined in
section 3.3.5.2 of Meteorology and
Atomic Energy 1968, should be
used only in the 0- to 8-h period; it is
used with a shape factor of 1/2 and
the minimum cross-sectional area of
the reactor building only.
Short-term accident atmospheric dispersion
factors were calculated
based on site
meteorological
measurement program
described in section 2.3.
These factors are for
ground level releases and
are based on Regulatory
Guide 1.145 methodology
and represent the worst of
the 5% site meteorology
and the 0.5% worst sector
meteorology.
VEGP-FSAR-15 TABLE 15.6.5-10 (SHEET 3 OF 7)
REV 15 4/09 Regulatory Guide 1.4 Position Design b. No correction should be made for depletion of the effluent plume of
radioactive iodine resulting from
deposition on the ground or for the
radiological decay of iodine in
transit. Same as response to 2a
above. c. For the first 8 h, the breathing rate of persons offsite should be
assumed to be 3.47 x 10-4 m 3/s. From 8 to 24 h following the
accident, the breathing rate should
be assumed to be 1.75 x 10-4 m 3/s. After that, until the end of the
accident, the breathing rate should
be assumed to be 2.32 x 10-4 m 3/s. (These values were developed from
the average daily breathing rate (2 x
107 cm 3/day) assumed in the report of ICRP, Committee II-1959.)
Conforms. d. The iodine dose conversion factors are given in ICRP
Publication 2, Report of Committee
II, Permissible Dose for Internal
Radiation, 1959.
The dose conversion
factors provided in
Federal Guidance Report 11 are used. e. External whole body doses should be calculated using "infinite
cloud" assumptions; i.e., the
dimensions of the cloud are
assumed to be large compared to
the distance that the gamma rays
and beta particles travel. "Such as a
cloud would be considered an
infinite cloud for a receptor at the
center because any additional (gamma and) beta emitting material
beyond the cloud dimensions would
not alter the flux of (gamma rays
and) beta particles to the receptor" (Meteorology and Atomic Energy, Section 7.4.1.1; editorial additions
made so that gamma and beta
emitting material could be
considered). Under these
conditions the rate of energy
absorption per unit volume is equal The dose conversion
factors provided in
Federal Guidance Report 12 are used.
VEGP-FSAR-15 TABLE 15.6.5-10 (SHEET 4 OF 7)
REV 15 4/09 Regulatory Guide 1.4 Position Design to the rate of energy released per unit volume. For an infinite uniform
cloud containing x curies of beta
radioactivity per cubic meter, the
beta dose in air at the cloud center
is: +E457.0 D' The surface body dose rate from beta emitters in the infinite cloud can be approximated as being one-
half this amount (i .e., +E23.0 D') For gamma emitting material, the dose rate in air at the cloud center
is: +E507.0 D' From a semi-infinite cloud, the gamma dose rate in air is:
+E25.0 D' where: D' = Beta dose rate from an infinite cloud (rad/s). D' = Gamma dose rate from an infinite cloud (rad/s). E = Average gamma energy per disintegration (MeV/dis).
E = Average beta energy per disintegration (MeV/dis). = Concentration of beta of gamma emitting isotope in the cloud (Ci/m 3).
VEGP-FSAR-15 TABLE 15.6.5-10 (SHEET 5 OF 7)
REV 15 4/09 Regulatory Guide 1.4 Position Design f. The following specific assumptions are acceptable with respect to the radioactive cloud dose calculations:
(1) The dose at any distance from the reactor should be calculated based on the
maximum concentration in the plume at that
distance, taking into account specific
meteorological, topographical, and other
characteristics which may affect the maximum
plume concentration. These site-related
characteristics must be evaluated on an individual
case basis. In the case of beta radiation, the
receptor is assumed to be exposed to an infinite
cloud at the maximum ground level concentration
at that distance from the reactor. In the case of
gamma radiation, the receptor is assumed to be
exposed to only one-half the cloud owing to the
presence of the ground. The maximum cloud
concentration always should be assumed to be at
ground level.
See response to 2e
above. (2) The appropriate average beta and gamma energies emitted per disintegration, as
given in the Table of Isotopes, Sixth Edition, by C.
M. Lederer, J. M. Hollander, and I. Perlman;
University of California, Berkeley, Lawrence
Radiation Laboratory, should be used.
See response to 2e
above.
- g. The atmospheric diffusion model should be as follows:
(1) The basic equation for atmospheric diffusion from a ground level point
source is:
Short-term accident
atmospheric dispersion
factors were calculated
based on onsite
meteorological
measurement program
described in section 2.3.
These factors are for
ground level releases and
are based on Regulatory
Guide1.145 methodology
and represent the worst of
the 5% site meteorology
and the 0.5% worst sector
meteorology.
Q =z y 1 VEGP-FSAR-15 TABLE 15.6.5-10 (SHEET 6 OF 7)
REV 15 4/09 Regulatory Guide 1.4 Position Design where: = The short term average centerline value of ground level concentration (Ci/m 3). Q = Amount of material released (Ci/s) u = Windspeed (m/s).
y = The horizontal standard deviation of the plume (m). (See Figure V-1, page 48, Nuclear Safety , June 1961, Volume 2, Number 4, Use of Routine
Meteorological Observations for
Estimating Atmospheric Dispersion, F. A. Gifford, Jr.)
z = The vertical standard deviation of the plume (m). (See Figure V-2, page
48, Nuclear Safety , June 1961, Volume 2, Number 4, Use of Routine
Meteorological Observations for
Estimating Atmospheric Dispersion, F. A. Gifford, Jr.)
(2) For time period of greater than 8 h the plume should be assumed to
meander and spread uniformly over a 22.5
û sector.
The resultant equation is:
See response to 2g(1)
above. Q = u x032.2 where: = Distance from point of release to the receptor; other variables are given in
2g (1). (3) The atmospheric diffusion model2 for ground level release is based on the
information below:
See response to 2g (1)
above.
VEGP-FSAR-15 TABLE 15.6.5-10 (SHEET 7 OF 7)
REV 15 4/09 Time Following
Accident Atmospheric Conditions
0 to 8 h Pasquill type F, windspeed 1 m/s, uniform direction
8 to 24 h Pasquill type F, windspeed 1 m/s, variable direction within a 22.5
û sector 1 to 4 days (a) 40% Pasquill type D, windspeed 3 m/s
(b) 60% Pasquill type F, windspeed 2 m/s
(c) wind direction variable within a 22.5
û sector 4 to 30 days (a) 33.3% Pasquill type C, windspeed 3 m/s
(b) 33.3% Pasquill type D, windspeed 3 m/s
(c) 33.3% Pasquill type F, windspeed 2 m/s
(d) windspeed direction 33.3% frequency in a 22.5
û sector (4) Figures 2A and 2B give the ground level release atmospheric diffusion
factor based on the parameters given in 2g(3).
See response to 2g (1) above.
VEGP-FSAR-15 REV 16 10/10 TABLE 15.6.5-11 (SHEET 1 OF 2)
DOSES RESULTING FROM A LOSS-OF-COOLANT ACCIDENT
Site Boundary Dose (0 to 2 h)
Containment leakage Thyroid (rem) 74.4 Gamma body (rem) 1.9 Beta skin (rem) 4.1 Containment purge Thyroid (rem) 0.3 Gamma body (rem)
< 0.1 Beta skin (rem)
< 0.1 Recirculation leakage Thyroid (rem) 10.0 Gamma body (rem) 0.1 Beta skin (rem) 0.1 Total Thyroid (rem) 84.6 Gamma body (rem) 2.0 Beta skin (rem) 4.2 Low Population Zone (0 to 30 days)
Containment leakage Thyroid (rem) 88.1 Gamma body (rem) 1.3 Beta skin (rem) 3.1 Containment purge Thyroid (rem) 0.1 Gamma body (rem)
< 0.1 Beta skin (rem)
< 0.1 Recirculation leakage Thyroid (rem) 35.3 Gamma body 0.2 Beta skin 0.5 Total Thyroid (rem) 124 Gamma body (rem) 1.5 Beta skin (rem) 3.5
VEGP-FSAR-15 REV 16 10/10 TABLE 15.6.5-11 (SHEET 2 OF 2)
Control Room (0 to 30 days)
Containment leakage Thyroid (rem) 20.6 Gamma body (rem) 0.6 Beta skin (rem) 13.6 Containment purge Thyroid (rem) 0.3 Gamma body (rem)
< 0.1 Beta skin (rem)
< 0.1 Recirculation leakage Thyroid (rem) 8.8 Gamma body (rem) 0.1 Beta skin (rem) 3.1 Total Thyroid (rem) 29.7 Gamma body (rem) 1.0 (a) Beta skin (rem) 16.7
(a) Includes contributions from inside and outside the control room.
REV 14 10/07 NUCLEAR POWER AND DNBR TRANSIENTS FOR INADVERTENT OPENING OF A PRESSURIZER SAFETY VALVE FIGURE 15.6.1-1
REV 14 10/07 PRESSURIZER PRESSURE TRANSIENTS AND CORE AVERAGE TEMPERATURE TRANSIENT FOR INADVERTENT OPENING OF A PRESSURIZER SAFETY VALVE FIGURE 15.6.1-2
STEAM GENERATOR TUBE RUPTURE PRESSURIZER LEVEL REV 14 10/07 PRESSURIZER LEVEL FIGURE 15.6.3-1
STEAM GENERATOR TUBE RUPTURE RCS PRESSURE
REV 14 10/07 RCS PRESSURE FIGURE 15.6.3-2
STEAM GENERATOR TUBE RUPTURE SECONDARY PRESSURE
REV 14 10/07 SECONDARY PRESSURE FIGURE 15.6.3-3
STEAM GENERATOR TUBE RUPTURE INTACT LOOP HOT AND COLD LEG RCS TEMPERATURES
REV 14 10/07 INTACT LOOP T HOT AND T COLD FIGURE 15.6.3-4
STEAM GENERATOR TUBE RUPTURE RUPTURED LOOP HOT AND COLD LEG RCS TEMPERATURES REV 14 10/07 RUPTURED LOOP T HOT AND T COLD FIGURE 15.6.3-5
STEAM GENERATOR TUBE RUPTURE DIFFERENTIAL PRESSURE BETWEEN RCS AND RUPTURED SG
REV 14 10/07 DIFFERENTIAL PRESSURE FIGURE 15.6.3-6
STEAM GENERATOR TUBE RUPTURE PRIMARY TO SECONDARY BREAK FLOW
REV 14 10/07 PRIMARY TO SECONDARY BREAK FLOW FIGURE 15.6.3-7
STEAM GENERATOR TUBE RUPTURE RUPTURED SG WATER VOLUME
REV 14 10/07 RUPTURED SG WATER VOLUME FIGURE 15.6.3-8
STEAM GENERATOR TUBE RUPTURE RUPTURED SG WATER MASS
REV 14 10/07 RUPTURED SG WATER MASS FIGURE 15.6.3-9
STEAM GENERATOR TUBE RUPTURE RUPTURED SG ATMOSPHERIC MASS RELEASES
REV 14 10/07 RUPTURED SG ATMOSPHERIC MASS RELEASES FIGURE 15.6.3-10
STEAM GENERATOR TUBE RUPTURE INTACT SGS ATMOSPHERIC MASS RELEASES
REV 14 10/07 INTACT SG ATMOSPHERIC MASS RELEASES FIGURE 15.6.3-11
REV 14 10/07 IODINE TRANSPORT MODEL FIGURE 15.6.3-12
STEAM GENERATOR TUBE RUPTURE BREAK FLOW FLASHING FRACTION
REV 14 10/07 BREAK FLOW FLASHING FRACTION FIGURE 15.6.3-13
REV 14 10/07 SEQUENCE OF EVENTS FOR LARGE BREAK LOCA ANALYSIS FIGURE 15.6.5-1
REV 14 10/07 CLADDING TEMPERATURE AT PCT AND BURST ELEVATIONS (C D = 0.4, LOW T AVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-2 (SHEET 1 OF 9)
REV 14 10/07 CLADDING TEMPERATURE AT PCT AND BURST ELEVATIONS (C D = 0.6, LOW T AVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-2 (SHEET 2 OF 9)
REV 14 10/07 CLADDING TEMPERATURE AT PCT AND BURST ELEVATIONS (C D = 0.8, LOW T AVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-2 (SHEET 3 OF 9)
REV 14 10/07 CLADDING TEMPERATURE AT PCT AND BURST ELEVATIONS (C D = 1.0, LOW T AVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-2 (SHEET 4 OF 9)
REV 14 10/07 CLADDING TEMPERATURE AT PCT AND BURST ELEVATIONS (C D = 0.6, HIGH TAVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-2 (SHEET 5 OF 9)
REV 14 10/07 CLADDING TEMPERATURE AT PCT AND BURST ELEVATIONS (C D = 0.6, HIGH TAVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-2 (SHEET 6 OF 9)
REV 14 10/07 CLADDING TEMPERATURE AT PCT AND BURST ELEVATIONS (C D = 0.6, HIGH TAVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-2 (SHEET 7 OF 9)
REV 14 10/07 CLADDING TEMPERATURE AT PCT AND BURST ELEVATIONS (C D = 0.6, HIGH TAVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-2 (SHEET 8 OF 9)
REV 14 10/07 CLADDING TEMPERATURE AT PCT AND BURST ELEVATIONS (C D = 0.6, HIGH TAVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-2 (SHEET 9 OF 9)
REV 14 10/07 CORE PRESSURE DURING BLOWDOWN (C D = 0.4, LOW T AVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-3 (SHEET 1 OF 9)
REV 14 10/07 CORE PRESSURE DURING BLOWDOWN (C D = 0.6, LOW T AVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-3 (SHEET 2 OF 9)
REV 14 10/07 CORE PRESSURE DURING BLOWDOWN (C D = 0.8, LOW T AVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-3 (SHEET 3 OF 9)
REV 14 10/07 CORE PRESSURE DURING BLOWDOWN (C D = 1.0, LOW T AVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-3 (SHEET 4 OF 9)
REV 14 10/07 CORE PRESSURE DURING BLOWDOWN (C D = 0.6, HIGH T AVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-3 (SHEET 5 OF 9)
REV 14 10/07 CORE PRESSURE DURING BLOWDOWN (C D = 0.6, LOW T AVG, MAX SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-3 (SHEET 6 OF 9)
REV 14 10/07 CORE PRESSURE DURING BLOWDOWN (C D = 0.6, LOW T AVG, MIN SI, 8.5 FT POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-3 (SHEET 7 OF 9)
REV 14 10/07 CORE PRESSURE DURING BLOWDOWN (C D = 0.6, LOW T AVG, MIN SI, COSINE POWER SHAPE, 128-IFBA)
FIGURE 15.6.5-3 (SHEET 8 OF 9)
REV 14 10/07 CORE PRESSURE DURING BLOWDOWN (C D = 0.6, LOW T AVG, MIN SI, COSINE POWER SHAPE, 156-IFBA)
FIGURE 15.6.5-3 (SHEET 9 OF 9)
REV 14 10/07 VESSEL LIQUID LEVELS DURING REFLOOD (C D = 0.4, LOW T AVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-4 (SHEET 1 OF 9)
REV 14 10/07 VESSEL LIQUID LEVELS DURING REFLOOD (C D = 0.6, LOW T AVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-4 (SHEET 2 OF 9)
REV 14 10/07 VESSEL LIQUID LEVELS DURING REFLOOD (C D = 0.8, LOW T AVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-4 (SHEET 3 OF 9)
REV 14 10/07 VESSEL LIQUID LEVELS DURING REFLOOD (C D = 1.0, LOW T AVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-4 (SHEET 4 OF 9)
REV 14 10/07 VESSEL LIQUID LEVELS DURING REFLOOD (C D = 0.6, HIGH T AVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-4 (SHEET 5 OF 9)
REV 14 10/07 VESSEL LIQUID LEVELS DURING REFLOOD (C D = 0.6, LOW T AVG, MAX SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-4 (SHEET 6 OF 9)
REV 14 10/07 VESSEL LIQUID LEVELS DURING REFLOOD (C D = 0.6, LOW T AVG, MIN SI, 8.5 FT POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-4 (SHEET 7 OF 9)
REV 14 10/07 VESSEL LIQUID LEVELS DURING REFLOOD (C D = 0.6, LOW T AVG, MIN SI, COSINE POWER SHAPE, 128-IFBA)
FIGURE 15.6.5-4 (SHEET 8 OF 9)
REV 14 10/07 VESSEL LIQUID LEVELS DURING REFLOOD (C D = 0.6, LOW T AVG, MIN SI, COSINE POWER SHAPE, 156-IFBA)
FIGURE 15.6.5-4 (SHEET 9 OF 9)
REV 14 10/07 CORE INLET FLOODING RATE DURING REFLOOD (C D = 0.4, LOW T AVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-5 (SHEET 1 OF 9)
REV 14 10/07 CORE INLET FLOODING RATE DURING REFLOOD (C D = 0.6, LOW T AVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-5 (SHEET 2 OF 9)
REV 14 10/07 CORE INLET FLOODING RATE DURING REFLOOD (C D = 0.8, LOW T AVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-5 (SHEET 3 OF 9)
REV 14 10/07 CORE INLET FLOODING RATE DURING REFLOOD (C D = 1.0, LOW T AVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-5 (SHEET 4 OF 9)
REV 14 10/07 CORE INLET FLOODING RATE DURING REFLOOD (C D = 0.6, HIGH T AVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-5 (SHEET 5 OF 9)
REV 14 10/07 CORE INLET FLOODING RATE DURING REFLOOD (C D = 0.6, LOW T AVG, MAX SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-5 (SHEET 6 OF 9)
REV 14 10/07 CORE INLET FLOODING RATE DURING REFLOOD (C D = 0.6, LOW T AVG, MIN SI, 8.5 FT POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-5 (SHEET 7 OF 9)
REV 14 10/07 CORE INLET FLOODING RATE DURING REFLOOD (C D = 0.6, LOW T AVG, MIN SI, COSINE POWER SHAPE, 128-IFBA)
FIGURE 15.6.5-5 (SHEET 8 OF 9)
REV 14 10/07 CORE INLET FLOODING RATE DURING REFLOOD (C D = 0.6, LOW T AVG, MIN SI, COSINE POWER SHAPE, 156-IFBA)
FIGURE 15.6.5-5 (SHEET 9 OF 9)
REV 14 10/07 NORMALIZED CORE POWER DURING BLOWDOWN (C D = 0.4, LOW T AVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-6 (SHEET 1 OF 9)
REV 14 10/07 NORMALIZED CORE POWER DURING BLOWDOWN (C D = 0.6, LOW T AVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-6 (SHEET 2 OF 9)
REV 14 10/07 NORMALIZED CORE POWER DURING BLOWDOWN (C D = 0.8, LOW T AVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-6 (SHEET 3 OF 9)
REV 14 10/07 NORMALIZED CORE POWER DURING BLOWDOWN (C D = 1.0, LOW T AVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-6 (SHEET 4 OF 9)
REV 14 10/07 NORMALIZED CORE POWER DURING BLOWDOWN (C D = 0.6, HIGH T AVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-6 (SHEET 5 OF 9)
REV 14 10/07 NORMALIZED CORE POWER DURING BLOWDOWN (C D = 0.6, LOW T AVG, MAX SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-6 (SHEET 6 OF 9)
REV 14 10/07 NORMALIZED CORE POWER DURING BLOWDOWN (C D = 0.6, LOW T AVG, MIN SI, 8.5 ft POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-6 (SHEET 7 OF 9)
REV 14 10/07 NORMALIZED CORE POWER DURING BLOWDOWN (C D = 0.6, LOW T AVG , MIN SI, COSINE POWER SHAPE, 128-IFBA)
FIGURE 15.6.5-6 (SHEET 8 OF 9)
REV 14 10/07 NORMALIZED CORE POWER DURING BLOWDOWN (CD = 0.6, LOW TAVG, MIN SI, COSINE POWER SHAPE, 156-IFBA)
FIGURE 15.6.5-6 (SHEET 9 OF 9)
REV 14 10/07 CONTAINMENT PRESSURE (C D = 0.4, LOW T AVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-7 (SHEET 1 OF 9)
REV 14 10/07 CONTAINMENT PRESSURE (C D = 0.6, LOW T AVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-7 (SHEET 2 OF 9)
REV 14 10/07 CONTAINMENT PRESSURE (C D = 0.8, LOW T AVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-7 (SHEET 3 OF 9)
REV 14 10/07 CONTAINMENT PRESSURE (C D = 1.0, LOW T AVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-7 (SHEET 4 OF 9)
REV 14 10/07 CONTAINMENT PRESSURE (C D = 0.6, HIGH T AVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-7 (SHEET 5 OF 9)
REV 14 10/07 CONTAINMENT PRESSURE (C D = 0.6, LOW T AVG, MAX SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-7 (SHEET 6 OF 9)
REV 14 10/07 CONTAINMENT PRESSURE (C D = 0.6, LOW T AVG, MIN SI, 8.5 FT POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-7 (SHEET 7 OF 9)
REV 14 10/07 CONTAINMENT PRESSURE (C D = 0.6, LOW T AVG, MIN SI, COSINE POWER SHAPE, 128-IFBA)
FIGURE 15.6.5-7 (SHEET 8 OF 9)
REV 14 10/07 CONTAINMENT PRESSURE (C D = 0.6, LOW T AVG, MIN SI, COSINE POWER SHAPE, 156-IFBA)
FIGURE 15.6.5-7 (SHEET 9 OF 9)
REV 14 10/07 CORE INLET AND OUTLET MASS FLOW RATE DURING BLOWDOWN (CD = 0.4, LOW TAVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-8 (SHEET 1 OF 9)
REV 14 10/07 CORE INLET AND OUTLET MASS FLOW RATE DURING BLOWDOWN (CD = 0.6, LOW TAVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-8 (SHEET 2 OF 9)
REV 14 10/07 CORE INLET AND OUTLET MASS FLOW RATE DURING BLOWDOWN (C D = 0.8, LOW T AVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-8 (SHEET 3 OF 9)
REV 14 10/07 CORE INLET AND OUTLET MASS FLOW RATE DURING BLOWDOWN (C D = 1.0, LOW T AVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-8 (SHEET 4 OF 9)
REV 14 10/07 CORE INLET AND OUTLET MASS FLOW RATE DURING BLOWDOWN (C D = 0.6, HIGH T AVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-8 (SHEET 5 OF 9)
REV 14 10/07 CORE INLET AND OUTLET MASS FLOW RATE DURING BLOWDOWN (C D = 0.6, LOW T AVG, MAX SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-8 (SHEET 6 OF 9)
REV 14 10/07 CORE INLET AND OUTLET MASS FLOW RATE DURING BLOWDOWN (C D = 0.6, LOW T AVG , MIN SI, 8.5 FT POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-8 (SHEET 7 OF 9)
REV 14 10/07 CORE INLET AND OUTLET MASS FLOW RATE DURING BLOWDOWN (C D = 0.6, LOW T AVG, MIN SI, COSINE POWER SHAPE, 128-IFBA)
FIGURE 15.6.5-8 (SHEET 8 OF 9)
REV 14 10/07 CORE INLET AND OUTLET MASS FLOW RATE DURING BLOWDOWN (C D = 0.6, LOW T AVG, MIN SI, COSINE POWER SHAPE, 156-IFBA)
FIGURE 15.6.5-8 (SHEET 9 OF 9)
REV 14 10/07 CLADDING SURFACE HEAT TRANSFER COEFFICIENT AT PCT AND BURST ELEVATIONS (C D = 0.4, LOW T AVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-9 (SHEET 1 OF 9)
REV 14 10/07 CLADDING SURFACE HEAT TRANSFER COEFFICIENT AT PCT AND BURST ELEVATIONS (C D = 0.6, LOW T AVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-9 (SHEET 2 OF 9)
REV 14 10/07 CLADDING SURFACE HEAT TRANSFER COEFFICIENT AT PCT AND BURST ELEVATIONS (C D = 0.8, LOW T AVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-9 (SHEET 3 OF 9)
REV 14 10/07 CLADDING SURFACE HEAT TRANSFER COEFFICIENT AT PCT AND BURST ELEVATIONS (C D = 1.0, LOW T AVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-9 (SHEET 4 OF 9)
REV 14 10/07 CLADDING SURFACE HEAT TRANSFER COEFFICIENT AT PCT AND BURST ELEVATIONS (C D = 0.6, HIGH T AVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-9 (SHEET 5 OF 9)
REV 14 10/07 CLADDING SURFACE HEAT TRANSFER COEFFICIENT AT PCT AND BURST ELEVATIONS (C D = 0.6, LOW T AVG, MAX SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-9 (SHEET 6 OF 9)
REV 14 10/07 CLADDING SURFACE HEAT TRANSFER COEFFICIENT AT PCT AND BURST ELEVATIONS (C D = 0.6, LOW T AVG , MIN SI, 8.5 FT POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-9 (SHEET 7 OF 9)
REV 14 10/07 CLADDING SURFACE HEAT TRANSFER COEFFICIENT AT PCT AND BURST ELEVATIONS (C D = 0.6, LOW T AVG , MIN SI, COSINE POWER SHAPE, 128-IFBA)
FIGURE 15.6.5-9 (SHEET 8 OF 9)
REV 14 10/07 CLADDING SURFACE HEAT TRANSFER COEFFICIENT AT PCT AND BURST ELEVATIONS (C D = 0.6, LOW T AVG, MIN SI, COSINE POWER SHAPE, 156-IFBA)
FIGURE 15.6.5-9 (SHEET 9 OF 9)
REV 14 10/07 VAPOR TEMPERATURE AT PCT AND BURST ELEVATIONS (C D = 0.4, LOW T AVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-10 (SHEET 1 OF 9)
REV 14 10/07 VAPOR TEMPERATURE AT PCT AND BURST ELEVATIONS (C D = 0.6, LOW T AVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-10 (SHEET 2 OF 9)
REV 14 10/07 VAPOR TEMPERATURE AT PCT AND BURST ELEVATIONS (C D = 0.8, LOW T AVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-10 (SHEET 3 OF 9)
REV 14 10/07 VAPOR TEMPERATURE AT PCT AND BURST ELEVATIONS (C D = 1.0, LOW T AVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-10 (SHEET 4 OF 9)
REV 14 10/07 VAPOR TEMPERATURE AT PCT AND BURST ELEVATIONS (C D = 0.6, HIGH TAVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-10 (SHEET 5 OF 9)
REV 14 10/07 VAPOR TEMPERATURE AT PCT AND BURST ELEVATIONS (C D = 0.6, LOW T AVG, MAX SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-10 (SHEET 6 OF 9)
REV 14 10/07 VAPOR TEMPERATURE AT PCT AND BURST ELEVATIONS (C D = 0.6, LOW T AVG, MIN SI, 8.5 FT POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-10 (SHEET 7 OF 9)
REV 14 10/07 VAPOR TEMPERATURE AT PCT AND BURST ELEVATIONS (C D = 0.6, LOW T AVG , MIN SI, COSINE POWER SHAPE, 128-IFBA)
FIGURE 15.6.5-10 (SHEET 8 OF 9)
REV 14 10/07 VAPOR TEMPERATURE AT PCT AND BURST ELEVATIONS (C D = 0.6, LOW T AVG , MIN SI, COSINE POWER SHAPE, 156-IFBA)
FIGURE 15.6.5-10 (SHEET 9 OF 9)
REV 14 10/07 BREAK MASS FLOW RATE DURING BLOWDOWN (C D = 0.4, LOW T AVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-11 (SHEET 1 OF 9)
REV 14 10/07 BREAK MASS FLOW RATE DURING BLOWDOWN (C D = 0.6, LOW T AVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-11 (SHEET 2 OF 9)
REV 14 10/07 BREAK MASS FLOW RATE DURING BLOWDOWN (C D = 0.8, LOW T AVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-11 (SHEET 3 OF 9)
REV 14 10/07 BREAK MASS FLOW RATE DURING BLOWDOWN (C D = 1.0, LOW T AVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-11 (SHEET 4 OF 9)
REV 14 10/07 BREAK MASS FLOW RATE DURING BLOWDOWN (C D = 0.6, HIGH T AVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-11 (SHEET 5 OF 9)
REV 14 10/07 BREAK MASS FLOW RATE DURING BLOWDOWN (C D = 0.6, LOW T AVG, MAX SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-11 (SHEET 6 OF 9)
REV 14 10/07 BREAK MASS FLOW RATE DURING BLOWDOWN (C D = 0.6, LOW T AVG , MIN SI, 8.5 FT POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-11 (SHEET 7 OF 9)
REV 14 10/07 BREAK MASS FLOW RATE DURING BLOWDOWN (C D = 0.6, LOW T AVG, MIN SI, COSINE POWER SHAPE, 128-IFBA)
FIGURE 15.6.5-11 (SHEET 8 OF 9)
REV 14 10/07 BREAK MASS FLOW RATE DURING BLOWDOWN (C D = 0.6, LOW T AVG, MIN SI, COSINE POWER SHAPE, 156-IFBA)
FIGURE 15.6.5-11 (SHEET 9 OF 9)
REV 14 10/07 BREAK ENERGY RELEASE RATE DURING BLOWDOWN (C D = 0.4, LOW T AVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-12 (SHEET 1 OF 9)
REV 14 10/07 BREAK ENERGY RELEASE RATE DURING BLOWDOWN (C D = 0.6, LOW T AVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-12 (SHEET 2 OF 9)
REV 14 10/07 BREAK ENERGY RELEASE RATE DURING BLOWDOWN (C D = 0.8, LOW T AVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-12 (SHEET 3 OF 9)
REV 14 10/07 BREAK ENERGY RELEASE RATE DURING BLOWDOWN (C D = 1.0, LOW T AVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-12 (SHEET 4 OF 9)
REV 14 10/07 BREAK ENERGY RELEASE RATE DURING BLOWDOWN (C D = 0.6, HIGH T AVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-12 (SHEET 5 OF 9)
REV 14 10/07 BREAK ENERGY RELEASE RATE DURING BLOWDOWN (C D = 0.6, LOW T AVG, MAX SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-12 (SHEET 6 OF 9)
REV 14 10/07 BREAK ENERGY RELEASE RATE DURING BLOWDOWN (C D = 0.6, LOW T AVG, MIN SI, 8.5 FT POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-12 (SHEET 7 OF 9)
REV 14 10/07 BREAK ENERGY RELEASE RATE DURING BLOWDOWN (C D = 0.6, LOW T AVG , MIN SI, COSINE POWER SHAPE, 128-IFBA)
FIGURE 15.6.5-12 (SHEET 8 OF 9)
REV 14 10/07 BREAK ENERGY RELEASE RATE DURING BLOWDOWN (C D = 0.6, LOW T AVG , MIN SI, COSINE POWER SHAPE, 156-IFBA)
FIGURE 15.6.5-12 (SHEET 9 OF 9)
REV 14 10/07 FLUID QUALITY AT PCT AND BURST ELEVATIONS (C D = 0.4, LOW T AVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-13 (SHEET 1 OF 9)
REV 14 10/07 FLUID QUALITY AT PCT AND BURST ELEVATIONS (C D = 0.6, LOW T AVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-13 (SHEET 2 OF 9)
REV 14 10/07 FLUID QUALITY AT PCT AND BURST ELEVATIONS (C D = 0.8, LOW T AVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-13 (SHEET 3 OF 9)
REV 14 10/07 FLUID QUALITY AT PCT AND BURST ELEVATIONS (C D = 1.0, LOW T AVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-13 (SHEET 4 OF 9)
REV 14 10/07 FLUID QUALITY AT PCT AND BURST ELEVATIONS (C D = 0.6, HIGH TAVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-13 (SHEET 5 OF 9)
REV 14 10/07 FLUID QUALITY AT PCT AND BURST ELEVATIONS (C D = 0.6, LOW T AVG, MAX SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-13 (SHEET 6 OF 9)
REV 14 10/07 FLUID QUALITY AT PCT AND BURST ELEVATIONS (C D = 0.6, LOW T AVG, MIN SI, 8.5 FT POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-13 (SHEET 7 OF 9)
REV 14 10/07 FLUID QUALITY AT PCT AND BURST ELEVATIONS (C D = 0.6, LOW T AVG, MIN SI, COSINE POWER SHAPE, 128-IFBA)
FIGURE 15.6.5-13 (SHEET 8 OF 9)
REV 14 10/07 FLUID QUALITY AT PCT AND BURST ELEVATIONS (C D = 0.6, LOW T AVG , MIN SI, COSINE POWER SHAPE, 156-IFBA)
FIGURE 15.6.5-13 (SHEET 9 OF 9)
REV 14 10/07 FLUID MASS VELOCITY AT PCT AND BURST ELEVATIONS (C D = 0.4, LOW T AVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-14 (SHEET 1 OF 9)
REV 14 10/07 FLUID MASS VELOCITY AT PCT AND BURST ELEVATIONS (C D = 0.6, LOW T AVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-14 (SHEET 2 OF 9)
REV 14 10/07 FLUID MASS VELOCITY AT PCT AND BURST ELEVATIONS (C D = 0.8, LOW T AVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-14 (SHEET 3 OF 9)
REV 14 10/07 FLUID MASS VELOCITY AT PCT AND BURST ELEVATIONS (C D = 1.0, LOW T AVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-14 (SHEET 4 OF 9)
REV 14 10/07 FLUID MASS VELOCITY AT PCT AND BURST ELEVATIONS (C D = 0.6, HIGH TAVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-14 (SHEET 5 OF 9)
REV 14 10/07 FLUID MASS VELOCITY AT PCT AND BURST ELEVATIONS (C D = 0.6, LOW T AVG, MAX SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-14 (SHEET 6 OF 9)
REV 14 10/07 FLUID MASS VELOCITY AT PCT AND BURST ELEVATIONS (C D = 0.6, LOW T AVG, MIN SI, 8.5 FT POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-14 (SHEET 7 OF 9)
REV 14 10/07 FLUID MASS VELOCITY AT PCT AND BURST ELEVATIONS (C D = 0.6, LOW T AVG , MIN SI, COSINE POWER SHAPE, 128-IFBA)
FIGURE 15.6.5-14 (SHEET 8 OF 9)
REV 14 10/07 FLUID MASS VELOCITY AT PCT AND BURST ELEVATIONS (C D = 0.6, LOW T AVG , MIN SI, COSINE POWER SHAPE, 156-IFBA)
FIGURE 15.6.5-14 (SHEET 9 OF 9)
REV 14 10/07 INTACT LOOP ACCUMULATOR MASS FLOW RATE DURING BLOWDOWN(C D = 0.4, LOW T AVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-15 (SHEET 1 OF 9)
REV 14 10/07 INTACT LOOP ACCUMULATOR MASS FLOW RATE DURING BLOWDOWN(C D = 0.6, LOW T AVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-15 (SHEET 2 OF 9)
REV 14 10/07 INTACT LOOP ACCUMULATOR MASS FLOW RATE DURING BLOWDOWN(C D = 0.8, LOW T AVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-15 (SHEET 3 OF 9)
REV 14 10/07 INTACT LOOP ACCUMULATOR MASS FLOW RATE DURING BLOWDOWN(C D = 1.0, LOW T AVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-15 (SHEET 4 OF 9)
REV 14 10/07 INTACT LOOP ACCUMULATOR MASS FLOW RATE DURING BLOWDOWN(C D = 0.6, HIGH T AVG, MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-15 (SHEET 5 OF 9)
REV 14 10/07 INTACT LOOP ACCUMULATOR MASS FLOW RATE DURING BLOWDOWN(C D = 0.6, LOW T AVG, MAX SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-15 (SHEET 6 OF 9)
REV 14 10/07 INTACT LOOP ACCUMULATOR MASS FLOW RATE DURING BLOWDOWN(C D = 0.6, LOW T AVG , MIN SI, 8.5 FT POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-15 (SHEET 7 OF 9)
REV 14 10/07 INTACT LOOP ACCUMULATOR MASS FLOW RATE DURING BLOWDOWN(C D = 0.6, LOW T AVG , MIN SI, COSINE POWER SHAPE, 128-IFBA)
FIGURE 15.6.5-15 (SHEET 8 OF 9)
REV 14 10/07 INTACT LOOP ACCUMULATOR MASS FLOW RATE DURING BLOWDOWN(C D = 0.6, LOW T AVG , MIN SI, COSINE POWER SHAPE, 156-IFBA FIGURE 15.6.5-15 (SHEET 9 OF 9)
REV 14 10/07 INTACT LEG ACCUMULATOR AND SI MASS FLOW RATE DURING REFLOOD (C D = 0.4, LOW T AVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-16 (SHEET 1 OF 9)
REV 14 10/07 INTACT LEG ACCUMULATOR AND SI MASS FLOW RATE DURING REFLOOD (C D = 0.6, LOW T AVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-16 (SHEET 2 OF 9)
REV 14 10/07 INTACT LEG ACCUMULATOR AND SI MASS FLOW RATE DURING REFLOOD (C D = 0.8, LOW T AVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-16 (SHEET 3 OF 9)
REV 14 10/07 INTACT LEG ACCUMULATOR AND SI MASS FLOW RATE DURING REFLOOD (C D = 1.0, LOW T AVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-16 (SHEET 4 OF 9)
REV 14 10/07 INTACT LEG ACCUMULATOR AND SI MASS FLOW RATE DURING REFLOOD (C D = 0.6, HIGH TAVG , MIN SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-16 (SHEET 5 OF 9)
REV 14 10/07 INTACT LEG ACCUMULATOR AND SI MASS FLOW RATE DURING REFLOOD (C D = 0.6, LOW T AVG, MAX SI, COSINE POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-16 (SHEET 6 OF 9)
REV 14 10/07 INTACT LEG ACCUMULATOR AND SI MASS FLOW RATE DURING REFLOOD (C D = 0.6, LOW T AVG , MIN SI, 8.5 FT POWER SHAPE, NON-IFBA)
FIGURE 15.6.5-16 (SHEET 7 OF 9)
REV 14 10/07 INTACT LEG ACCUMULATOR AND SI MASS FLOW RATE DURING REFLOOD (C D = 0.6, LOW T AVG , MIN SI, COSINE POWER SHAPE, 128-IFBA)
FIGURE 15.6.5-16 (SHEET 8 OF 9)
REV 14 10/07 INTACT LEG ACCUMULATOR AND SI MASS FLOW RATE DURING REFLOOD (C D = 0.6, LOW T AVG , MIN SI, COSINE POWER SHAPE, 156-IFBA)
FIGURE 15.6.5-16 (SHEET 9 OF 9)
0 50 100 150 200 250 300 350 400 450 5000100200300400500600700 RCS Pressure (psia)Safety Injection Flow Rate (lbm/sec)
REV 14 10/07 SAFETY INJECTION FLOW (MINIMUM SAFETY INJECTION)
FIGURE 15.6.5-17
0 200 400 600 800 1000 1200 14000100200300400500600700RCS Pressure (psia)Safety Injection Flow Rate (lbm/sec)
REV 14 10/07 SAFETY INJECTION FLOW (MAXIMUM SAFETY INJECTION)
FIGURE 15.6.5-18
REV 14 10/07 REACTOR COOLANT SYSTEM PRESSURIZER PRESSURE 2-IN., LOW T AVG FIGURE 15.6.5-22
REV 14 10/07 CORE MIXTURE LEVEL 2-IN., LOW T AVG FIGURE 15.6.5-23
REV 14 10/07 REACTOR COOLANT SYSTEM PRESSURIZER PRESSURE 3-IN., LOW T AVG FIGURE 15.6.5-24
REV 14 10/07 CORE MIXTURE LEVEL 3-IN., LOW TAVG FIGURE 15.6.5-25
REV 14 10/07 CORE STEAM FLOW RATE 3-IN., LOW T AVG FIGURE 15.6.5-26
REV 14 10/07 PUMPED SAFETY INJECTION 3-IN., LOW T AVG FIGURE 15.6.5-27
REV 14 10/07 PEAK CLAD TEMPERATURE AT 11.25 FT 3-IN., LOW T AVG FIGURE 15.6.5-28
REV 14 10/07 HOT SPOT FLUID TEMPERATURE AT 11.25 FT 3-IN., LOW T AVG FIGURE 15.6.5-29
REV 19 4/15 HOT ROD HEAT TRANSFER COEFFICIENT AT 11.25 FT 3-IN., LOW T AVG FIGURE 15.6.5-30
REV 14 10/07 REACTOR COOLANT SYSTEM PRESSURIZER PRESSURE 4 IN., LOW T AVG FIGURE 15.6.5-31
REV 14 10/07 CORE MIXTURE LEVEL 4-IN., LOW T AVG FIGURE 15.6.5-32
REV 14 10/07 PEAK CLAD TEMPERATURE AT 10.75 FT 4-IN., LOW TAVG FIGURE 15.6.5-33
VEGP-FSAR-15
15.7-1 REV 19 4/15 15.7 RADIOACTIVE RELEASE FROM A SUBSYSTEM OR COMPONENT This class of accident can be caused by any of the following events: A. Radioactive gas waste system leak or failure--this is an American Nuclear Society (ANS) Condition III event. B. Radioactive liquid waste system leak or failure--this is an ANS Condition III event. C. Postulated radioactive release due to liquid tank failures--this is an ANS Condition IV event. D. Fuel handling accident--this is an ANS Condition IV event. E. Spent fuel cask drop accidents--this is an ANS Condition III event.
All of the accidents in this section have been analyzed. It has been determined that the most severe radiological consequences will result from the fuel handling accident analyzed in
subsection 15.7.4. 15.7.1 RADIOACTIVE WASTE GAS DECAY TANK FAILURE 15.7.1.1 Identification of Causes This accident is an infrequent fault. Its consequences will be considered in this section. The accident is defined as an unexpected and uncontrolled release of radioactive iodine, xenon, and
krypton fission product gases stored in a waste gas decay tank as a consequence of a failure of
a single gas tank or associated piping. 15.7.1.2 Sequence of Events and System Operations During a refueling shutdown, the radioactive gases are stripped from the primary coolant and are stored in the gas decay tanks. After the transfer has been completed, the tank is assumed
to fail. This releases all of the contents of the tank to the auxiliary building. Also, since the
tanks are isolated from each other, the only radioactivity released is from the failed tank. For
conservatism, the tank is assumed to fail after 40 years a , releasing the peak inventory expected in the tank.
a The renewed operating licenses authorized a 20-year period of extended operation for both VEGP units, resulting in a total plant operating life of 60 years.
Since the inventory in the Waste Gas Decay Tanks (WGDTs) has been routinely released during the first 20 years of operation and is expected to continue to be routinely released during future operation, the inv entory of the WGDTs accumulated during the first 20 years of operation will be released prior to entering the period of extended operat ion. Therefore, the stated design capacity of the GWPS remains suffici ent, and the analysis of the maximum fission product inventory in the GWPS over a 40-year plant life remains bounding for a 60-year plant life.
VEGP-FSAR-15
15.7-2 REV 19 4/15 15.7.1.3 Core and System Performance This accident occurs when the reactor is in the shutdown condition. There is no impact on the
core or its system performance. 15.7.1.4 Barrier Performance The only barrier between the released activity and the environment is the auxiliary building.
During the course of this accident, the auxiliary building is assumed to remain intact. This means that the only method of release is through the auxiliary building ventilation system. 15.7.1.5 Radiological Consequences 15.7.1.5.1 Method of Analysis 15.7.1.5.1.1 Physical Model. Radioactive waste gas decay tanks (WGDTs) are used in the design to permit the decay of radioactive gases as a means of reducing or preventing the release of radioactive materials to the atmosphere. To evaluate the radiological consequences
of the gaseous waste processing system, it is postulated that there is an accidental release of
the contents of one of the WGDTs resulting from a rupture of the tank or from another cause, such as operator error or valve malfunction. The gaseous waste processing system (GWPS) is
so designed that the tanks are isolated from each other during use, limiting the quantity of gas
released in the event of an accident by preventing the flow of radioactive gas between the
tanks. The principal radioactive nuclides of the WGDTs are the noble gases krypton and xenon, the particulate daughters of some of the krypton and xenon isotopes, and trace quantities of
halogens. The maximum amount of waste gases stored in any one tank occurs during a
refueling shutdown, at which time the WGDTs store the radioactive gases stripped from the
reactor coolant.
The maximum content of a gas decay tank given in table 15.7.1-1 is based on conservative assumptions used for the purpose of computing the noble gas and iodine inventory available for
release. Rupture of the WGDT is assumed to occur immediately upon completion of the waste
gas transfer, releasing the entire contents of the tank to the auxiliary building. For the purposes
of evaluating the accident, it is assumed that all the activity is released directly to the
environment during the 2-h period immediately following the accident. 15.7.1.5.1.2 Assumptions and Conditions. The major assumptions and parameters assumed in the analysis are itemized in table 15.7.1-1.
In the evaluation of the WGDT rupture, the fission product accumulation and release assumptions of Regulatory Guide 1.24 have been used. Table 15.7.1-2 provides a comparison
of the assumptions used in the analysis to those of Regulatory Guide 1.24. The assumptions
related to the release of radioactive gases from the postulated rupture of a WGDT are:
VEGP-FSAR-15
15.7-3 REV 19 4/15 A. The iodine concentrations in the reactor coolant, prior to shutdown, are based on 1 µCi/g of dose equivalent I-131. Coincident with the shutdown, an iodine spike is created which increases the iodine release rate from the fuel to the primary
coolant to a value 500 times greater than the release rate corresponding to the maximum equilibrium primary system iodine concentration of 1
µCi/g of dose equivalent I-131. The duration of the spike is assumed to be sufficient to raise
the reactor coolant iodine concentration to 60
µCi/g of dose equivalent I-131 (approximately 2.5 h). B. The noble gas concentrations in the primary coolant are based on 1-percent defective fuel. C. All gaseous activity has been removed fr om the reactor coolant system (RCS) and transferred to the gas decay tank that is assumed to fail. D. The maximum content of the WGDT was conservatively assumed to be the isotopic activities given in table 15.7.1-1 for the accumulated radioactivity in the GWPS after 40 years' operation a and immediately following plant shutdown and degasification of the RCS. E. The failure is assumed to occur immediately upon completion of the waste gas transfer, releasing the entire contents of the tank to the auxiliary building. F. The dose is calculated as if the release were from the auxiliary building at ground level during the 2-h period immediately following the accident. No credit for
radioactive decay is taken. 15.7.1.5.1.3 Mathematical Models Used in the Analysis. The mathematical models used in the analysis are described in the following sections: A. The mathematical models used to analyze the activity released during the course of the accident are described in appendix 15A. B. The atmospheric dispersion factors used in the analysis were calculated based on the onsite meteorological measurement programs described in section 2.3. C. The thyroid inhalation and total body gamma immersion doses to a receptor at the exclusion area boundary and outer boundary of the low population zone were
analyzed, using the models described in appendix 15A, subsections 15A.2.4 and
15A.2.6, respectively. 15.7.1.5.1.4 Identification of Leakage Pathways and Resultant Leakage Activity. For the purpose of evaluating the radiological consequences due to the postulated WGDT rupture, the
resultant activity is conservatively assumed to be released directly to the environment during the 2-h period immediately following the occurrence of the accident. This is a considerably higher a The renewed operating licenses authorized a 20-year period of extended operation for both VEGP units, resulting in a total plant operating life of 60 years.
Since the inventory in the WGDTs has been routinely released during the first 20 years of operation and is expected to continue to be routinely released during future operation, the inventory of the WGDTs accu mulated during the first 20 years of operation will be released prior to entering the period of extended operati on. Therefore, the stat ed design capacity of the GWPS remains sufficient, and the analysis of the maxi mum fission product inventory in the GWPS over a 40-year plant life remains boundi ng for a 60-year plant life.
VEGP-FSAR-15
15.7-4 REV 19 4/15 release rate than that based on the actual building exhaust ventilation rate. Therefore, the
results of the analysis are based on the most conservative pathway available. 15.7.1.5.2 Identification of Uncertainties and Conservatisms in the Analysis.
The uncertainties and conservatisms in the assumptions used to evaluate the radiological consequences of a WGDT rupture result from assumptions made involving the release of the
waste gas from the decay tank and the meteorology present at the site during the course of the
accident. A. The iodine inventory in the GWPS is based on a reactor coolant concentration of 1 µCi/g of dose equivalent I-131 with extremely large iodine spike values, persisting for 2.5 h, and resulting in equivalent concentrations many times
greater than the reactor coolant activities based on 0.12-percent defective fuel
associated with normal operating conditions. B. The noble gas inventory in the GWPS is based on a reactor coolant concentration corresponding to 1-percent defective fuel and 40 years of
operation a (to maximize the Kr-85 inventory; all other nuclides equilibrate in approximately 60 days or less). Furthermore, 1-percent defects cannot exist simultaneously with 1.0
µCi/g of dose equivalent I-131. For iodines, 1-percent defects would be approximately three times the Technical Specification limit. C. It is assumed that the WGDT fails immediately after the transfer of the noble gases and iodines from the reactor coolant to the WGDT is complete. These assumptions result in the greatest amount of gaseous activity available for
release to the environment. D. The gaseous activity contained in the ruptured WGDT was assumed to be released over a 2-h period immediately following the accident. This is a
conservative assumption. If the contents of the tank were assumed to mix
uniformly with the volume of air within the auxiliary building where the decay
tanks are located, then, using the actual building exhaust ventilation rate, a
considerable amount of holdup time would be gained. This reduces, by natural
decay, the amount of gaseous activity ava ilable for release to the environment.
However, no credit for radioactive decay is taken. E. The meteorological conditions which may be present at the site during the course of the accident are uncertain. However, it is highly unlikely that meteorological
conditions assumed will be present during the course of the accident for any
extended period of time. Therefore, the radiological consequences evaluated, based on these meteorological conditions, will be conservative.
a The renewed operating licenses authorized a 20-year period of extended operation for both VEGP units, resulting in a total plant operating life of 60 years.
Since the inventory in the WGDTs has been routinely released during the first 20 years of operation and is expected to continue to be routinely released during future operation, the inventory of the WGDTs accu mulated during the first 20 years of operation will be released prior to entering the period of extended operati on. Therefore, the stat ed design capacity of the GWPS remains sufficient, and the analysis of the maxi mum fission product inventory in the GWPS over a 40-year plant life remains boundi ng for a 60-year plant life.
VEGP-FSAR-15
15.7-5 REV 19 4/15 15.7.1.5.3 Conclusions 15.7.1.5.3.1 Filter Loading. Since the accumulated iodine activity in the WGDTs is negligible, filter loading due to WGDT rupture does not establish the necessary design margin for the auxiliary building exhaust or the control room intake filters. Hence, the respective filter loadings were not evaluated. 15.7.1.5.3.2 Dose to Receptor at the Exclusion Area Boundary and the Low Population Zone Outer Boundary. The radiological consequences resulting from the occurrence of a postulated WGDT rupture have been conservatively analyzed, using assumptions and models described in previous sections.
The total body gamma dose due to immersion and the thyroid dose due to inhalation have been analyzed for the 0- to 2-h dose at the exclusion area boundary and for the duration of the
accident at the low population zone outer boundary. The results are listed in table 15.7.1-3.
The resultant doses are well within the guideline values of 10 CFR 100. 15.7.2 RADIOACTIVE LIQUID WASTE SYSTEM LEAK OR FAILURE 15.7.2.1 Identification of Causes This is an infrequent fault, but the potential for release of significant amounts of radioactivity is present. The accident may be caused by an equipment malfunction or tank failure.
Liquid radwaste system leaks resulting in gaseous releases to the atmosphere and liquid releases to the ground water are bounded by the tank failure analyses presented in
paragraphs 15.7.2.5 and 15.7.3.4, respectively. Accidental releases of radwaste processing
facility liquid effluents to surface water are discussed in paragraph 2.4.13.2. 15.7.2.2 Sequence of Events and System Operation The recycle holdup tank (RHT) is assumed to fail. This releases 100 percent of the tank capacity to the tank compartment. 15.7.2.3 Core and System Performance This accident does not affect the core or the core system performance.
15.7.2.4 Barrier Performance It is assumed that there are no barriers to the rel ease of radioactivity from the auxiliary building.
VEGP-FSAR-15
15.7-6 REV 19 4/15 15.7.2.5 Radiological Consequences 15.7.2.5.1 Method of Analysis 15.7.2.5.1.1 Physical Model. Reactor coolant shim bleed and some valve leakage is held in the RHT.
Table 15.7.3-1 provides an inventory and the concentrations of stored radioactivity in the tank.
In the analyses, it is assumed that the liquid contents of the tank are released to the auxiliary
building, and subsequently the airborne activity is released to the environment during the 2-h period immediately following the tank failure.
The RHT was selected because it contains the maximum total inventory. 15.7.2.5.1.2 Assumptions and Conditions. The major assumptions and parameters assumed in this analysis are listed below and in table 15.7.2-1. A. The nuclide inventory of the failed tank is taken from table 15.7.3-1 and is based on 1-percent defective fuel. B. The RHT failure is assumed to occur when the contents of the tank are at a maximum. C. The doses are calculated as if the release were from the auxiliary building at ground level during the 2-h period immediately following the accident. No credit is taken for radioactive decay during holdup in the tank or in transit to the site
boundary. D. One-hundred percent of all noble gas activity in the tank is released while 1 percent of the iodine activity is released as airborne activity. E. Credit is not taken for iodine removal by the nonsafety-grade auxiliary building heating, ventilation, and air-conditioning (HVAC) charcoal adsorber. 15.7.2.5.2 Mathematical Models Used in the Analysis. A. The mathematical models used to analyze the activity released during the course of the accident are described in appendix 15A. B. The atmospheric dispersion factors used in the analysis were calculated based on the onsite meteorological measurement program described in section 2.3;
they are provided in table 15A-2. C. The thyroid inhalation dose and total body immersion dose to a receptor at the exclusion area boundary or outer boundary of the low population zone were
analyzed, using the models described in appendix 15A, sections 15A.2.4, and
15A.2.6, respectively. 15.7.2.5.2.1 Identification of Leakage Pathways and Resultant Leakage Activity. For the purpose of evaluating the radiological consequences due to the postulated RHT failure, the VEGP-FSAR-15
15.7-7 REV 19 4/15 resultant activity is conservatively assumed to be released directly to the environment during the 2-h period immediately following the occurrence of the accident. This is a considerably higher
release rate than that based on the actual building exhaust ventilation rate. Therefore, the
results of the analysis are based on the most conservative pathway available. 15.7.2.5.3 Identification of Uncertainties and Conservatisms in the Analysis The uncertainties and conservatisms in the assumptions used to evaluate the radiological consequences of the RHT failure result from assumptions made involving the release of the
radioactivity from the tank and the meteorology assumed for the site. A. It was assumed that the RHT fails when the inventory in the tank is a maximum.
This assumption results in the greatest amount of activity available for release to
the environment. B. The contents of the failed tank are assumed to be released over a 2-h period immediately following the accident. If the contents of the tank were assumed to
mix uniformly with the volume of air within the auxiliary building where the tank is
located, then, using the actual building exhaust ventilation rate, a considerable
amount of holdup time would be gained. This reduces the amount of activity
released to the environment due to the natural decay. Also, no credit is taken for
iodine removal by the auxiliary building HVAC charcoal adsorbers. C. The meteorological conditions which may be present at the site during the course of the accident are uncertain. However, it is highly unlikely that meteorological
conditions assumed will be present during the course of the accident for any
extended period of time. D. The RHT is assumed to have collected liquid waste based on operation at 100-percent power with 1-percent defective fuel for an extended period of time. 15.7.2.5.4 Conclusions 15.7.2.5.4.1 Filter Loadings. The filter loading due to an RHT failure does not establish the necessary design margin for the control room intake filters. Thus, the filter loading was not evaluated. 15.7.2.5.4.2 Doses to Receptor at the Exclusion Area Boundary and the Low Population Zone Outer Boundary. The radiological consequences resulting from the occurrence of a postulated liquid radwaste tank failure have been conservatively analyzed, using assumptions and models described in previous sections.
The total body dose due to immersion and the thyroid dose due to inhalation have been analyzed for the 0- to 2-h dose at the exclusion area boundary and for the duration of the
accident at the low population zone outer boundary. The results are listed in table 15.7.2-2.
The resultant dose is well within the guideline values of 10 CFR 100.
VEGP-FSAR-15
15.7-8 REV 19 4/15 15.7.3 POSTULATED RADIOACTIVE RELEASE DUE TO LIQUID TANK FAILURE (GROUND RELEASE) 15.7.3.1 Identification of Causes and Frequency Classification This accident is defined as an unexpected and uncontrolled postulated rupture of the recycle
holdup tank (RHT). This tank is located in the Seismic Category 1 auxiliary building at el 119 ft
3 in. Since plant grade is at el 220 ft, the only way any effluents from the postulated rupture can
be released accidentally is through postulated cracks in the auxiliary building, which would allow
the contents of the tank to enter ground water. This accident is postulated to occur with the
frequency of a limiting fault. (See paragraph 15.7.2.1.) 15.7.3.2 Sequence of Events and Systems Operation See subsection 2.4.13.
15.7.3.3 Modeling of Accident Sequence 15.7.3.3.1 Mathematical Model Subsection 2.4.13 gives the dispersion, dilution, and travel times of accidental releases of liquid effluents in surface water. 15.7.3.3.2 Input Parameters and Initial Conditions The tank failure is evaluated in accordance with the following sets of assumptions and conditions: A. One-hundred percent of the liquid volume of the RHT is released into the RHT cubicle. B. The liquid enters the ground water environment through postulated cracks in the auxiliary building. RHT data is provided in table 15.7.3-1. 15.7.3.4 Radiological Consequences The radiological consequences of this accident are presented in subsection 2.4.13.
The concentrations of any postulated accidental release of radioactive effluents from the RHT would not exceed 10 CFR 20 limits at the nearest surface water intake. 15.7.4 FUEL HANDLING ACCIDENTS The postulated fuel handling accident has been analyzed for three cases: case 1, a fuel handling accident outside the containment in the fuel handling building; case 2, a fuel handling
accident inside the reactor containment building with the containment airlocks and equipment VEGP-FSAR-15
15.7-9 REV 19 4/15 hatch closed; and case 3, a fuel handling accident inside the containment with the personnel
airlock doors and/or the equipment hatch open. 15.7.4.1 Identification of Causes and Accident Description The accident is defined as dropping of a spent fuel assembly onto another fuel assembly in the fuel storage area or refueling pool, resulting in the rupture of the cladding of all the fuel rods in
the dropped assembly plus additional rods in the struck assembly (for the accident inside
containment), despite many administrative c ontrols and physical limitations imposed on fuel
handling operations. All refueling operations are conducted in accordance with prescribed
procedures. 15.7.4.2 Sequence of Events and Systems Operations The first step in fuel handling is the safe shutdown and cooldown of the reactor. After a radiation survey of the containment, the disassembly of the reactor vessel is started. After
disassembly is complete, the first fuel handling is started. The first fuel transfer operation shall
not begin until at least 90 h after shutdown.
The fuel handling accident is assumed to occur after a fuel assembly has been removed from the core but before it has been placed in its designated location in the spent fuel storage racks. 15.7.4.3 Core and System Performance The fuel handling accident in the containment building or the fuel building does not impact the integrity of the core or its system performance. 15.7.4.4 Barrier Performance The barriers between the released activity and the environment are the containment building or the fuel building. Since these buildings are designed Seismic Category 1, it is safe to assume
that during the course of a fuel handling accident their integrity is maintained. Normally, release
of radioactivity for a postulated accident in the fuel building is via the fuel building emergency
filtration system. An open door in the fuel handling building pressure boundary could create
another release path.
For a postulated accident in the containment building with the airlocks and equipment hatch closed, the release is limited to the minimal amount of radioactivity which could potentially be
released prior to containment isolation. For a postulated accident in the containment building
with the airlock and/or equipment hatch open, the limiting pathway for the release of activity is
via the equipment building ventilation fan. During core alterations or movement of irradiated fuel
assemblies within containment, the air lock door interlock mechanism may remain disabled, but
the air lock must always be isolable by at lease one air lock door with a designated individual
available to close the air lock door, or at least one air lock door must be closed. Similarly, the
equipment hatch must be isolable and capable of being held in place by four bolts. The
requirements for containment penetration closure are sufficient to ensure fission product
radioactivity release from containment due to a fuel handling accident during refueling is
maintained to within the acceptance criteria of Standard Review Plan subsection 15.7.4 and
VEGP-FSAR-15
15.7-10 REV 19 4/15 The equipment hatch and the emergency air lock are farther away from the control room air intake than the personnel airlock. Therefore, the release path from the personnel airlock
remains bounding for control room dose. Similarly, potential release paths from the purge
supply and exhaust ductwork are no closer than the personnel airlock release path. Offsite
dose is not affected by the relative locations of the personnel and emergency airlocks, the
containment purge supply and exhaust ventilation, or the equipment hatch.
The spent fuel pool and the refueling pool provide a minimum decontamination factor of 200 for elemental iodine. 15.7.4.5 Radiological Consequences 15.7.4.5.1 Method of Analysis 15.7.4.5.1.1 Physical Model. The possibility of a fuel handling accident is remote because of the many administrative controls and phy sical limitations imposed on the fuel handling operations. (Refer to subsection 9.1.4.) All refueling operations are conducted in accordance with prescribed procedures.
When transferring irradiated fuel from the core to the spent fuel pool for storage, the reactor cavity and refueling pool are filled with borated water at a boron concentration equal to or
greater than that concentration specified for the spent fuel pool or that concentration specified
for refueling, whichever is highest, which ensures subcritical conditions in the core even if all rod
cluster control (RCC) assemblies are withdrawn. After the reactor head and RCC drive shafts
are removed, fuel assemblies are lifted from the core, transferred vertically to the upender, lowered to a horizontal position on the transfer car and pulled through the transfer tube and
canal, upended and transferred through the spent fuel pool transfer gate, then lowered into steel
racks for storage in the spent fuel pool in a pattern which precludes any possibility of a criticality
accident.
Fuel handling manipulators and hoists are designed so that the fuel cannot be raised above a position that provides an adequate water shield depth for radiation protection of operation
personnel.
The containment, fuel building, refueling cavity, refueling pool, and spent fuel pool are designed to Seismic Category 1 requirements, which prevent the structures themselves from failing in the event of a safe shutdown earthquake. The spent fuel storage racks are also located to prevent
any credible external missile from reaching the stored irradiated fuel. The fuel handling
manipulators, cranes, trollies, bridges, and associated equipment above the water cavities
through which the fuel assemblies move are designed to prevent this equipment from
generating missiles and damaging the fuel. The construction of the fuel assemblies precludes
damage to the fuel should portable or hand tools drop on an assembly.
A fuel handling accident could occur during the transfer of a fuel assembly from the core to its storage position in the spent fuel pool. The facility is designed so that heavy objects, such as a spent fuel cask, cannot be carried over or tipped over onto the irradiated fuel stored in the spent fuel pool. Only one fuel assembly can be handled at a time. Movement of equipment handling
the fuel is kept at low speeds, while exercising caution that the fuel assembly does not strike
another object or structure during transfer from the core to its storage position. In the unlikely VEGP-FSAR-15
15.7-11 REV 19 4/15 event that an assembly becomes stuck in the transfer tube, natural convection will maintain
adequate cooling. A. Containment Building Accident During core alterations or movement of irradiated fuel assemblies inside containment, the containment may be either open or closed. If the containment is closed, the equipment hatch will be held in place with at least four bolts, the air
locks will be isolated by at least one closed air lock door, and each penetration
providing direct access from the containment atmosphere to the outside
atmosphere (with the exception of the containment purge and exhaust
penetrations) will be closed in accordance with the Technical Specifications. The
containment purge and exhaust penetrations will be capable of being closed, by
operator action, by at least two containment ventilation isolation valves. The
containment radiation monitors (gaseous, particulate, iodine, and area low range)
will be operable in accordance with the Technical Specifications. In addition, the
Technical Requirements Manual requires that direct communications be
maintained between the control room and personnel at the refueling station
during core alterations. If a fuel handling accident were to occur inside
containment with containment closed, the control room would be immediately
aware of the event as a result of direct communication or a radiation alarm. Steps
would be taken to isolate containment purge and exhaust, and personnel would
be evacuated. With containment closed, the only potential release pathway
would be via the containment purge and exhaust system. However, because of
the gaseous, particulate, and iodine monitors in the exhaust portion of the
system, the potential for an unmonitored release is minimized. In addition, the
purge exhaust system is equipped with HEPA filters and charcoal adsorbers
which will further minimize any radiological release. While no credit is taken for
filtration by the purge exhaust system in the dose analyses, the availability of the
filters will be maintained in accordance with NUMARC 93-01 guidance. With containment open, the equipment hatch and/or the air lock doors may be open. The equipment hatch must be capable of being closed by at least four
bolts and the air locks must be isolable by at least one door with a designated
individual to close the open doors. A designated hatch closure crew and the
necessary tools and equipment will be available to effect timely closure of the
hatch. The equipment hatch will be capable of being cleared of obstructions so
that closure can be achieved as soon as possible. The air lock doors will be
closed within 15 minutes of a fuel handling accident. For the equipment hatch, the current commitment for closure time in response to a loss of decay removal
capability during reduced inventory conditions is 25 minutes. This closure time is
bounding for the case of a fuel handling accident inside containment with the
equipment hatch open. Radiation monitor operability, requirements for other
penetrations providing direct access from containment atmosphere to the outside
atmosphere, communication requirements, and purge exhaust system availability is the same as for the case discussed above for containment closed. During core
offload and reload with the equipment hatch open, the containment purge
exhaust system will normally be operating pr oviding an inward flow of air into containment. This is consistent with NUMARC 93-01, section 11.3.6.5, which
states that the goal of maintaining ventilation system and radiation monitor
availability is to reduce doses even further below that provided by natural decay and to avoid unmonitored releases. However, the purge exhaust system must be
shut down during hatch closure activities, and it may be shut down during fuel VEGP-FSAR-15
15.7-12 REV 19 4/15 handling while the hatch is open as required to maintain noise and comfort
levels, etc. If for any reason operation of the purge exhaust system must be
discontinued during core alterations/fuel movement with the hatch open, the
opening will be monitored for radioactive releases via the health physics air
monitoring station. B. Fuel Building Accident In the fuel building, a fuel assembly could be dropped in the transfer canal or in the spent fuel pool. In addition to the area and effluent radiation monitors, portable radiation monitors capable of emitting audible alarms are located in this area during fuel handling operations. The doors in the fuel building are normally kept closed to ensure
controlled leakage characteristics in the spent fuel pool region during operations
involving irradiated fuel. Doors on the pressure boundary, except for the railroad
bay door, may be held open during operations involving irradiated fuel. The fuel
handling building normal and post-accident ventilation system function is not lost
due to opening of personnel doors. Administrative controls are in place to close
the doors after a fuel handling accident to minimize any potential release to the
environment. Additionally, if none of the fuel handling building exhaust filter units
are in service, one should be placed in service to ensure flow past the radiation
monitors, or the doors should be closed. Should a fuel assembly be dropped in
the canal or in the pool and release radioactivity above a prescribed level, the
radiation monitors would sound an alarm. (See section 11.5 and
subsection 12.3.4.) On alarm signal, the fuel building ventilation is switched to
the emergency mode and exhausts through the engineered safety features (ESF)
emergency filtration system charcoal and high-efficiency particulate air filters to
remove most of the halogens and particulates prior to discharging to the
atmosphere via the plant vent.
A radiation monitor located in the fuel handling building ventilation exhaust duct sounds an
alarm if the radioactivity in the vent discharge exceeds the prescribed level.
The probability of a fuel handling accident is very low because of the safety features, administrative controls, and design characteristics of the facility, as previously mentioned. 15.7.4.5.1.2 Assumptions and Conditions. The major assumptions and parameters assumed in the analysis are itemized in tables 15.7.4-1 and 15A-1.
In the evaluation of the fuel handling accident, the fission product release assumptions of Regulatory Guide 1.25 are followed. Table 15.7.4-2 provides a comparison of the design to the
requirements of Regulatory Guide 1.25. The following assumptions, related to the release of
fission product gases from the damaged fuel assembly, are used in the analyses except as
identified in table 15.7.4-2: A. The dropped fuel assembly is assumed to be the assembly containing the peak fission product inventory. All the fuel rods contained in the dropped assembly
are assumed to be damaged. In addition, for the analyses of the accident in the
containment building the dropped assembly is assumed to damage 50 rods of an
additional assembly. B. The assembly fission product inventories are based on a radial peaking factor of 1.70.
VEGP-FSAR-15
15.7-13 REV 19 4/15 C. The accident occurs 90 h after shutdown, which is the earliest time fuel handling operations can begin. Radioactive decay of the fission product inventories was
taken into account during this time period. D. Only that fraction of the fission products which migrates from the fuel matrix to the gap and plenum regions during normal operation is assumed to be available
for immediate release to the water following clad damage. E. The gap activity released to the fuel pool from the damaged fuel rods consists of 5% of the total noble gases and iodines, other than Kr-85 (10%) and I-131 which
is 8% (Reg. Guide 1.195). F. The pool decontamination factor is 1.0 for noble gases and organic iodine. G. The effective pool decontamination factor is 200 for elemental iodine.
H. The iodine released from the fuel assembly is assumed to be composed of 99.75-percent inorganic and 0.25-percent organic species. I. The activity which escapes from the pool is assumed to be available for release to the environment in a time period of 2 h. J. No credit for decay or depletion during transit to the exclusion area boundary or the outer boundary of the low population zone is assumed. K. No credit is taken for mixing or holdup in the fuel building atmosphere or equipment building. L. For the case inside the reactor containment building, conservative credit is taken for mixing of the radioactivity released from the refueling pool with a minimum of the containment building free volume.
The mixing volume of 25 percent is assumed and is based on the normal airflow rate of four fan coolers. M. The containment purge rate is 15,000 ft 3/min for the case with the containment airlocks and equipment hatch closed. N. Automatic containment ventilation isolation capability is no longer required by the Technical Specifications. The limiting radiological consequences for a fuel
handling accident inside containment as reported in table 15.7.4-4 are based on
an open containment with no automatic isolation. However, the radiological
consequences for a closed containment reported in table 15.7.4-4 are based on
automatic containment ventilation isolati on. If automatic containment ventilation isolation is available, it would be assumed to occur within 10 s from the time the
containment isolation signal is generated with a 5-s signal generation time. O. The control room emergency filtration sy stem (CREFS) is initiated by RE-12116 and/or RE-12117 during a fuel handling accident in the fuel handling building. P. For the case with the airlocks and/or equipment hatch open, the activity is assumed to be released from the containment to the outside atmosphere at a
rate in which all the activity released from the damaged fuel assemblies would be
released to the outside atmosphere in 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> if the containment airlocks and/or
equipment hatch remain open. The radiological consequences of a fuel handling
accident in containment have been evaluated assuming that the containment is
open to the outside atmosphere. All airborne activity reaching the containment
atmosphere is assumed to be exhausted to the environment within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of the
accident. The calculated offsite and control room operator doses are within the VEGP-FSAR-15
15.7-14 REV 19 4/15 acceptance criteria of Standard Review Plan 15.7.4 and General Design Criteria
- 19. Therefore, although the containment penetrations do not satisfy any of 10
CFR 50.36 (c)(2)(ii) criteria, Technical Specifications provide containment closure
capability to minimize potential offsite doses. Procedures provide administrative
controls to ensure that the designated person available to close the personnel
and/or emergency air lock doors does not have other duties that would preclude
the ability to operate the door in a timely manner. In addition, a designated hatch
closure crew is available to effect a timely closure of the equipment hatch. Q. The control room volume, normal and emergency mode flow rates, and emergency mode filter efficiencies for the control room ventilation system used to
determine control room doses following a fuel handling accident with the
containment airlocks and/or equipment hatch open are given in table 15A-1 of
appendix 15A. 15.7.4.5.1.3 Mathematical Models Used in the Analysis. Mathematical models used in the analysis are described in the following sections: A. The mathematical models used to analyze the activity released during the course of the accident are described in appendix 15A, section 15A.2. B. The atmospheric dispersion factors are based on the onsite meteorological measurement described in section 2.3 and are provided in table 15A-2. C. The thyroid inhalation and total-body immersion doses to a receptor located at the exclusion area boundary and outer boundary of the low population zone are
analyzed using the models described in appendix 15A, subsections 15A.2.4 and
15A.2.6, respectively. D. The thyroid inhalation, beta skin, and gamma body doses to personnel in the control room are analyzed using the models described in appendix 15A, and
subsections 15A.3.3, 15A.3.4, and 15A.3.5. 15.7.4.5.1.4 Identification of Leakage Pathways and Resultant Leakage Activity. For evaluating the radiological consequences due to the postulated fuel handling accident in the fuel
building, the resultant activity is conservatively assumed to be released to the environment
during the 0- to 2-h period immediately following the occurrence of the accident. This is a
considerably higher release rate than that based on the actual ventilation rate. Therefore, the
results of the analysis are based on the most conservative pathway available. Only the limiting
case of a fuel handling accident is shown in table 15.7.4-1. 15.7.4.5.2 Identification of Uncertainties and Conservatisms in Analysis The uncertainties and conservatisms in the assumptions used to evaluate the radiological consequences of a fuel handling accident result from assumptions made involving the amount
of fission product gases available for release to the environment and the meteorology present at
the site during the course of the accident. The most significant of these assumptions are: A. It is assumed in the analysis that all the fuel rods in the dropped assembly are damaged. This is a highly conservative assumption, since in transferring fuel
under strict fuel handling procedures, only under the worst possible VEGP-FSAR-15
15.7-15 REV 19 4/15 circumstances could the dropping of a spent fuel assembly result in damage to
all the fuel rods contained in the assembly. B. The fission product gap inventory in a fuel assembly is dependent on the power rating of the assembly and the temperature of the fuel. The gap fractions from
Regulatory Guide 1.195 are conservatively assumed. Realistic calculations of
gap fractions show less than 2% for all short lived isotopes. C. Iodine removal from the released fission product gas takes place as the gas rises to the pool surface through the body of liquid in the spent fuel pool. The extent of
elemental iodine removal is determined by mass transfer from the gas phase to
the surrounding liquid and is controlled by the bubble diameter and contact time
of the bubble in the solution. The values used in the analysis result in a release
of elemental iodine approximately a factor of 3 greater than anticipated. The
release of activity from the pool to the containment atmosphere is time
dependent, and, consequently, there would be sufficient time for this activity to
mix homogeneously in a significantly greater percent of the containment volume
than assumed in the analysis. D. Fuel handling building emergency filtration system charcoal filters are provided; however, no credit has been taken for their capability. This means a reduction in
the iodine concentrations and, thus, a reduction in the thyroid doses at the
exclusion area boundary and the outer boundary of the low population zone. E. The containment purge exhaust system has charcoal adsorber units which filter any containment purge release. However, no credit has been taken for its
capability (90% efficiency, minimum) since these units are not specifically
designed to Seismic Category 1 criteria. It is expected that for any event which
would produce a catastrophic failure of the charcoal adsorber unit to the extent
that its filtering capability would be negated would also result in the purge
exhaust fan becoming inoperable. Therefore, failure within the purge exhaust
system would terminate any high-volume re lease from the containment. In fact, the purge exhaust fan is considerably more likely to be inoperable following any
postulated event than the failure of a passive charcoal adsorber unit. Thus, although no credit in the analysis has been given for the normal purge exhaust
filters, any release prior to containment isolation would be filtered, reducing the
calculated releases by another factor of 10. F. There is also conservatism in the time to first fuel transfer. Despite the fact that fuel could be transferred at 90 h, it is probable that fuel handling will begin
sometime later. G. The exhaust from the personnel airlock area is via the equipment building ventilation fan (1526-B7-00200). The distance from the equipment building
ventilation exhaust to the control room (CR) intake is 190 ft. If both the intake
and exhaust fans fail (loss of power to nonsafety-grade equipment), activity may
exfiltrate through the equipment building intake. The distance from the
equipment building ventilation intake to the CR intake is 90 ft. For the case of the
fuel handling accident inside containment with the personnel airlock open, the
activity is assumed to be released from the equipment building to the
environment and from the environment to the CR intake. Furthermore, the CR
dose analysis conservatively assumes that activity is released from the
equipment building intake, which is closer to the CR than the equipment building
exhaust. This assumption is limiting with respect to releases from the equipment
hatch or the emergency air lock.
VEGP-FSAR-15
15.7-16 REV 19 4/15 H. The distance from the CR intake to the nearest point on the containment is 70 ft.
The atmospheric dispersion factors (/Q) at the CR intake used to determine the CR doses following a LOCA are based on this distance of 70 ft. The distance of
90 ft from the equipment building intake to the CR intake is comparable to the distance of 70 ft used in the LOCA CR dose analysis. Thus, the same /Q as used in the LOCA CR dose analysis, which are listed in table 15A-2, are conservatively used for the CR dose analysis for a fuel handling accident inside
containment with the personnel airlock open. I. The assumption that all radioactivity released due to the fuel handling accident is released from the containment and to the outside atmosphere in the initial 2 h
following the accident if the containment remains open is conservative. There is
no driving force to push this activity out of the containment. The bulk of the
radioactivity would likely stay in the containment for much longer than 2 h, even if
the containment remained open. J. The meteorological conditions which may be present at the site during the course of the accident are uncertain. However, it is highly unlikely that meteorological
conditions assumed will be present during the course of the accident for any
extended period of time. Therefore, the radiological consequences evaluated, based on the meterological conditions assumed, are conservative. 15.7.4.5.2.1 Filter Loadings. The filtration systems which function to limit the consequences of a fuel handling accident in the fuel building are the fuel building emergency
filtration system and the control room filtration system.
The activity loadings on the control room charcoal adsorbers as a function of time have been evaluated for the loss-of-coolant accident (LOCA), as described in subsection 15.6.5. Since
these filters are capable of accommodating the design basis LOCA fission product iodine
loadings, more than adequate design margin is available with respect to postulated fuel
handling accident releases. The activity loadings on the ESF filtration system charcoal adsorbers have been evaluated in accordance with Regulatory Guide 1.52, which limits the maximum loading to 2.5 mg iodine/g
activated charcoal. 15.7.4.5.2.2 Doses to Receptor at the Exclusion Area Boundary and Low Population Zone Outer Boundary. The potential radiological consequences resulting from the occurrence of a postulated fuel handling accident occurring in the fuel building and in the reactor building have been conservatively analyzed, using assumptions and models described in previous sections.
The total-body dose due to immersion from direct radiation and the thyroid dose due to
inhalation have been analyzed for the 0- to 2-h dose at the exclusion area boundary and for the
duration of the accident (0 to 2 h) at the low population zone outer boundary. The results are
listed in table 15.7.4-4. The resultant doses are well within the guideline values of 10 CFR 100. 15.7.5 SPENT FUEL CASK DROP ACCIDENT The spent fuel cask will follow the path outlined on drawing AX4DE501. Cask handling over the spent fuel pool or the new fuel pit is prevented by interlocks.
VEGP-FSAR-15
15.7-17 REV 19 4/15 A Type 1 single-failure-proof crane designed according to NUREG-0554 is used in handling the spent fuel cask. Therefore, no cask drop will occur, and thus no radioactivity will be released.
Refer to subsection 9.1.5 for a description of the spent fuel cask handling equipment.
VEGP-FSAR-15
REV 14 10/07 TABLE 15.7.3-1 RECYCLE HOLDUP TANK DATA FOR FAILURE ANALYSIS
Volume of tank (gal) 112,000 Weight of liquid contained (g) 4.22 x 10 8 Radioactive contents Nuclide Activity (Ci)
Kr-87 5.49 x 10 2 Kr-88 1.56 x 10 3 Kr-89 4.64 x 10 1 Xe-133 1.14 x 10 5 Xe-135 3.08 x 10 3 Xe-138 2.7 x 10 2 I-131 1.18 x 10 2 I-132 1.18 x 10 2 I-133 1.77 x 10 2 I-135 9.7 x 10 1 Rb-88 2.03 x 10 2 Cs-136 1.22 x 10 2 Cs-138 4.05 x 10 1
VEGP-FSAR-15 REV 18 9/13 TABLE 15.7.4-1 (SHEET 1 OF 2)
PARAMETERS USED IN EVALUATING THE RADIOLOGICAL CONSEQUENCES OF A FUEL HANDLING ACCIDENT Containment Open or
In Fuel Building
Containment Closed (HISTORICAL)
Source Data Core power level (MWt) 3636 3636 Radial peaking factor 1.70 1.70 Decay time (h) 90 100 Number of fuel rods affected 314 1.2 assemblies Fraction of fission product gases contained in the gap
region of the fuel assembly
(Reg. Guide 1.195) 5% of the
total noble gases and iodines
(10%)
RG 1.25 for all except I-131 a (fraction of 0.12)
Atmospheric Dispersion Factors Table 15A-2 Table 15A-2 Activity Release Data
Percent of affected fuel
assemblies gap activity
released 100 100 Pool decontamination
factors Elemental iodine 400 200 Organic iodine 1 1 Noble gas 1 1 Filter efficiency (%)
No credit 0 Building mixing volumes
assumed (% total volume) 0 25
VEGP-FSAR-15 REV 18 9/13 TABLE 15.7.4-1 (SHEET 2 OF 2)
Containment Open
or In Fuel Building Containment Closed (HISTORICAL)
HVAC exhaust rate (ft 3/min) N/A 15,000 Building isolation time (s) No isolation 10+5 Activity release period (h) 2 Release terminated 10 s after containment isolation signal
with 5 s allowed for signal
generation
VEGP-FSAR-15 REV 18 9/13 TABLE 15.7.4-2 (SHEET 1 OF 9)
REGULATORY GUIDE 1.25, ASSUMPTIONS USED FOR EVALUATING THE POTENTIAL RADIOLOGICAL CONSEQUENCES OF A FUEL HANDLING ACCIDENT IN THE FUEL HANDLING AND STORAGE FACILITY FOR BOILING AND PRESSURIZED WATER REACTORS, REVISION 0, DATED MARCH 23, 1972 Regulatory Guide 1.25 Position Case 1 (In Fuel Building or Open Containment)
Case 2 (In Closed Containment Building) (HISTORICAL)
The assumptions (a) related to the release of radioactive material from the fuel and fuel storage facility as a result of a fuel handling accident are:
The accident occurs at a time after shutdown identified in the Technical Requirements Manual as the earliest time fuel handling operations may
begin. Radioactive decay of the fission product inventory during the interval between shutdown
and commencement of fuel handling operations is
taken into consideration. Conforms. Accident occurs 90 h after shutdown.
Conforms. Accident occurs 100 h after shutdown.
The maximum fuel rod pressurization(b) is 1200 psig. Conforms.
Conforms.
The minimum water depth(b) between the top of the damaged fuel rods and the fuel pool surface is
23 ft. Conforms. Water depth is greater than 23 ft. Conforms. Water depth is greater than 23 ft.
All of the gap activity in the damaged rods is released and consists of 10% of the total noble
gases other than Kr-85, 30% of the Kr-85, and
10% of the total radioactive iodine in the rods at
the time of the accident. For the purpose of sizing
filters for the fuel handling accident addressed in this guide, 30% of the I-127 and I-129 inventory is
assumed to be released from the damaged rods. Conforms, except for I-131 8%, Kr-85 10%, and 5%
noble gases and other iodines
- the gap is consistent with Reg. Guide 1.195 for lead rod average burnup
to 62,000 MWd/Mtu.
Conforms, except for I-131 which assumes 12%;
the gap is consistent with NUREG CR-5009 for lead rod average burnup to 60,000 MWd/Mtu.
The values assumed for individual fission product inventories are calculated assuming full-power operation at the end of core life immediately preceding shutdown, and such calculation should include an
appropriate radial peaking factor. The minimum
acceptable radial peaking fa ctors are 1.5 for BWRs and 1.65 for PWRs. A peaking factor of 1.70 is used since this is the maximum projected radial peaking factor. A value of 1.65 to 1.70 may be used for a cycle-specific core
reload evaluation.
A peaking factor of 1.70 is used since this is the maximum projected radial peaking factor. A value of 1.65 to 1.70 may be used for a cycle-specific
core reload evaluation.
VEGP-FSAR-15 TABLE 15.7.4-2 (SHEET 2 OF 9)
REV 18 9/13 Regulatory Guide 1.25
Position Case 1 (In Fuel Building or Open Containment)
Case 2 (In Closed Containment Building) (HISTORICAL)
The iodine gap inventory is composed of 99.75%
inorganic species and 0.25% organic species.
Conforms.
Conforms.
The pool decontamination factors for the inorganic and organic species are 133 and 1, respectively, giving an overall effective decontamination factor
of 100 (i.e., 99% of the total iodine released from the damaged rods is retained by the pool water).
This difference in decontamination factors for
inorganic and organic iodine above the fuel pool
being composed of 75% inorganic and 25%
organic species. The pool decontamination factors for the inorganic and organic species are 400 and 1, respectively, giving an overall effective decontamination factor of 200 (i.e., 99.5% of the total iodine released from the damaged rods is retained by the pool). This difference in
decontamination factors fo r inorganic and organic iodine above the fuel pool being composed of 50% inorganic and 50% organic species.
The pool decontamination factors for the inorganic and organic species are 200 and 1, respectively, giving an overall effective decontamination factor of 133 (i.e., 99.25% of the total iodine released from the damaged rods is retained by the pool). This difference in decontamination factors for inorganic and
organic iodine above the fuel pool being composed of 67% inorganic and 33% organic
species. The retention of noble gases in the pool is negligible (i.e., decontamination factor of 1). Conforms. A decontamination factor of 1 is used. Conforms. A decontamination factor of 1 is used. The radioactive material that escapes from the pool to the building is released from the building (c) over a 2-h time period. Conforms. A 0- to 2-h release from the pool to the building to the environment is assumed.
The release from pool to the building is automatically isolated upon detection of the
first trace of release.
Thus, the release is contained in the containment building after
isolation.
If it can be shown that the building atmosphere is exhausted through adsorbers designed to remove iodine, the removal efficiency is 90% for inorganic
species and 70% for organic species. No credit is taken for the FHB post-accident exhaust filters that conform to Regulatory Guide 1.52 as
described in table 9.4.1-2.
No credit is taken for the normal purge filters.
The effluent from the filter system passes directly to the emergency exhaust system without mixing (e) in the surrounding building atmosphere and is
then released (as an elevated plume for those facilities with stacks (f)).
Conforms.
Conforms.
The assumptions for atmospheric diffusion for:
Ground level releases
The basic equation for atmospheric diffusion from a ground level point source is:
zy=1 Q where: Short-term atmospheric di spersion factors corresponding to ground level release and accident conditions were
based on the meteorological measurements program described in section 2.3. The dispersion factors are in compliance with the methodology described in Regulatory Guide 1.145 and represent the worst of the 5% overall site meteorology and the 0.5% worst sector meteorology.
VEGP-FSAR-15 TABLE 15.7.4-2 (SHEET 3 OF 9)
REV 18 9/13 Regulatory Guide 1.25
Position Case 1 (In Fuel Building or Open Containment)
Case 2 (In Closed Containment Building) (HISTORICAL)
= the short-term average centerline value of the ground level concentration (Ci/m ).
Q = amount of material released (Ci/s).
µ = windspeed (m/s).
y = the horizontal standard deviation of the plume (m). See figure V-1, page
48, in F. A. Gifford, Jr., Use of
Routine Meteorological Observation
Estimating Atmospheric Dispersion, Nuclear Safety, Vol. II, No. 4, June 1961. z = the vertical standard deviation of the plume (m). See figure V-2, page 48
in F. A. Gifford, Jr., Use of Routine
Meteorological Observation for
Estimating Atmospheric Dispersion, Nuclear Safety, Vol. II, No. 4, June 1961. For ground level releases, atmospheric diffusion
factors(g) used in evaluating the radiological consequences of the accident addressed in this guide are based on the following assumptions:
windspeed of 1 m/s, uniform wind direction, and Pasquill diffusion category F.
Figure 1 is a plot of atmospheric diffusion factor
(/Q) versus distance derived by use of the equation for a ground level release given in regulatory position 2.a.(1) and under the
meteorological conditions given in regulatory position 2.a.(2).
Atmospheric diffusion factors for ground level releases may be reduced by a factor ranging from
1 to a maximum of 3 (see figure 2) for additional dispersion produced by the turbulent wake of the reactor building. The volumetric building wake
correction as defined in subsection 3-3.5.2 of
VEGP-FSAR-15 TABLE 15.7.4-2 (SHEET 4 OF 9)
REV 18 9/13 Regulatory Guide 1.25
Position Case 1 (In Fuel Building or Open Containment)
Case 2 (In Closed Containment Building) (HISTORICAL)
Meteorology and Atomic Energy-1968 is used with a shape factor of 1/2 and the minimum cross-sectional area of the reactor building only.
Elevated releases The basic equation for atmospheric diffusion from an elevated release is: Not applicable; ground level releases were assumed. Not applicable; ground level releases were assumed.
zy z zµ=e Q/2 h where: = the short-term average centerline value of the ground level concentration (Ci/m 3). Q = amount of material released (Ci/s).
µ = windspeed (m/s).
y = the horizontal standard deviation of the plume (m). See figure V-1, page 48 in, F. A. Gifford, Jr., Use
of Routine Meteorological
Observations for Estimating
Atmospheric Dispersion, Nuclear Safety, Vol. II. No. 4, June 1961. z = the vertical standard deviation of the plume (m). See figure V-2, page 48 in, F. A. Gifford, Jr., Use
of Routine Meteorological
Observations for Estimating
Atmospheric Dispersion, Nuclear Safety, Vol. II, No. 4, June 1961. h = effective height of release (m).
For elevated releases, atmospheric diffusion factors(h) used in evaluating the radiological consequences of the accident addressed in this VEGP-FSAR-15 TABLE 15.7.4-2 (SHEET 5 OF 9)
REV 18 9/13 Regulatory Guide 1.25
Position Case 1 (In Fuel Building or Open Containment)
Case 2 (In Closed Containment Building) (HISTORICAL) guide are based on the following assumptions: windspeed of 1 m/s, uniform wind direction, envelope of Pasquill diffusion categories for
various release heights, and a fumigation condition existing at the time of the accident.(h) Figure 3 is a plot of at mospheric diffusion factors versus distance for an elevated release assuming
no fumigation, and figure 4 is for an elevated release with fumigation.
Elevated releases are cons idered to be at a height equal to no more than the actual stack height.
Certain site conditions may exist, such as surrounding elevated topography or nearby structures, which will have the effect of reducing
the effective stack height. The degree of stack height reduction will be ev aluated on an individual case basis.
The following assumptions and equations may be
used to obtain conservati ve approximations of thyroid dose from the i nhalation of radioiodine and external whole-body dose from radioactive clouds:
The assumptions rela tive to inhalation thyroid dose approximations are: Conforms. See appendix15A, subsection 15A.2.4. Conforms. See appendix15A, subsection 15A.2.4. The receptor is located at a point on or beyond the site boundary where the maximum ground level concentration is
expected to occur.
No correction is made for depletion of the effluent plume of radioiodine due to
deposition on the ground or for the radiological decay of radioiodine in transit.
Inhalation thyroid doses may be approximated by use of the following
equation:
)DF()DF()QIFPBR(F DfP g= where:
VEGP-FSAR-15 TABLE 15.7.4-2 (SHEET 6 OF 9)
REV 18 9/13 Regulatory Guide 1.25
Position Case 1 (In Fuel Building or Open Containment)
Case 2 (In Closed Containment Building) (HISTORICAL)
D = thyroid dose (rd). F g = fraction of fuel rod iodine inventory in fuel rod void space (0.1). I = core iodine inventory at time of accident (Ci).
F = fraction of core damaged so as to release void space iodine.
P = fuel peaking factor. = breathing rate = 3.47 x 10
-4 m 3/s (i.e., 10 m 3/8-h workday as recommended by the
ICRP). DF p = effective iodine decontamination factor for pool water. DF f = effective iodine decontamination factor for
filters (if present).
/Q = atmospheric diffusion factor at receptor location (s/m 3). R = adult thyroid dose conversion factor for the iodine isotope of
interest (rd/Ci). Dose
conversion factors for I-131
through I-135 are listed in the table below.(i) These values were derived from "standard
man" parameters
recommended in ICRP
Publication 2.(j)
VEGP-FSAR-15 TABLE 15.7.4-2 (SHEET 7 OF 9)
REV 18 9/13 Regulatory Guide 1.25
Position Case 1 (In Fuel Building or Open Containment)
Case 2 (In Closed Containment Building) (HISTORICAL)
Adult Inhalation Thyroid Dose Conversion Factors Iodine Isotope Conversion
Factor (R)
(rd/Ci inhaled)
131 1.48 x 10 6 132 5.35 x 10 4 133 4.0 x 10 5 134 2.5 x 10 4 135 1.24 x 10 5 See table 15A-5 for dose conversion factors.
See table 15A-5 for dose conversion factors.
The assumptions relative to external whole-body
dose approximations are: Conforms. See appendix 15A, subsection 15A.2.6 Conforms. See appendix 15A, subsection 15A.2.6 The receptor is located at a point on or beyond the site boundary where the maximum ground level concentration is expected to occur.
External whole-body doses are calculated using "infinite cloud" assumptions; i.e., the dimensions of the cloud are assumed to be large compared to the
distances that the gamma rays and beta particles travel. The dose at any distance from the reactor is calculated based on the maximum ground level
concentration at that distance.
For an infinite unifo rm cloud containing Ci of beta radioactivity per m 3 , the beta dose rate in air at the cloud center is:
=E457.0 D where:
See table 15A-5 for dose conversion factors.
See table 15A-5 for dose conversion factors.
D = beta dose rate from an infinite
cloud (rd/s).
E = average beta energy per disintegration (MeV/dis).
= concentration of beta or gamma emitting isotope in the cloud (Ci/m 3).
VEGP-FSAR-15 TABLE 15.7.4-2 (SHEET 8 OF 9)
REV 18 9/13 Regulatory Guide 1.25
Position Case 1 (In Fuel Building or Open Containment)
Case 2 (In Closed Containment Building) (HISTORICAL)
Because of the limited range of beta particles in tissue, the surface-body dose rate from beta
emitters in the infini te cloud can be approximated as being one-half this amount or:
=E23.0 D For gamma-emitting materi al the dose rate in tissue at the cloud center is:
=E D507.0 where:
D = gamma dose rate from an infinite cloud (rd/s).
E = average gamma energy per disintegration (MeV/disintegration).
However, because of the presence of the ground, the receptor is assumed to be exposed to only
one-half of the cloud (s emi-infinite) and the equation becomes:
=E D25.0 Thus, the total beta or gamma dose to an
individual located at the center of the cloud path may be approximated as:
=E D23.0 or =E D25.0 where = the concentration time integral for the cloud (Ci s/m 3). The beta and gamma energies emitted per disintegration, as giv en in Table of Isotopes,(i) are averaged and used according to the
methods described in ICRP Publication 2.
VEGP-FSAR-15 TABLE 15.7.4-2 (SHEET 9 OF 9)
REV 18 9/13
- a. The assumptions given are valid only for oxide fuels of the types currently in use and in cases where the following condit ions are not exceeded:
- 1. Peak linear power density of 20.5 kW/ft for the highest power assembly discharged.
- 2. Maximum centerline operating fuel temperature less than 4500
°F for this assembly.
- 3. Average burnup for the peak assembly of 25,000 MWd/t or le ss (this corresponds to a peak local burnup of about 45,000 MWd/t
).
- b. For release pressures greater than 1200 psig and water depths less than 23 ft, the iodine decontamination factors will be less than those assumed in this guide and must be calculated on an individual-case basis using assumptions comparable in conservatism to those of this guide.
- c. The effectiveness of features provided to reduce the amount of radioactive material avail able for release to the environment will be evaluated on an i ndividual-case basis.
- d. These efficiencies are based upon a 2-in. charcoal bed depth with 1/4-s residence time. Efficiencies may be different for other systems and must be calculated on an individual-case basis.
- e. Credit for mixing will be allowed in some cases; the amount of credit will be evaluated on an individual-c ase basis.
- f. Credit for an elevated release will be given only if the point of release is more than 2 1/2 times the height of any structure close enough to affect the dispersion of the plume or located far enough from any structure which could affect the dispersion of the plume. For those plants without stacks the atmo spheric diffusions factors assuming ground level release given in regulatory positi on 2.b should be used.
- g. These diffusion factors s hould be used until adequate site meteorological data are obtained. In some cases, available information on such site conditions as meteorology, topography, and geographical location may dictate the use of more restrictive parameters to ensure a conservative estimate of p otential offsite exposures.
- h. For sites located more than 2 miles from large bodies of water such as oceans or one of the Great Lakes, a fumigation condi tion is assumed to exist at the time of the accident and continue for 1/2 h. For sites located less than 2 miles from large bodies of water a fumigation condition is assumed to exist at the time of the accident and continue for the duration of the release (2 h).
- i. Dose conversion factors taken from F. D. Anderson, R. E.
Baker, J. J. DiNunno, "Calculation of Distance Factors for Power a nd Test Reactor Site," TID-14844, 1962.
- j. Recommendations of the International Commission on Radiological Prot ection, "Report of Committee II on Permissible Dose for Internal Radiation (1959)
," ICRP Publication 2, Permagon Press, New York, 1960.
- k. Meteorology and Atomic Energy-1968, chapter 7.
- l. C. M. Lederer, J. M. Hollander, and I. Perlman, Table of Isotopes, sixth edition, John Wiley and Sons, Inc., New York, 1967.
VEGP-FSAR-15 REV 18 9/13 TABLE 15.7.4-4 RADIOLOGICAL CONSEQUENCES OF A FUEL HANDLING ACCIDENT Doses (rem) Fuel Building or Open Containment
Exclusion area boundary (0 to 2 h)
Thyroid 23.4 Whole body 1.1 Low population zone outer boundary (0 to 2 h)
Thyroid 9.4 Whole body 0.4 Control Room (a) Thyroid 13.7 Whole body 0.6 Beta Skin 5.6 Containment Closed (HISTORICAL)
Exclusion area boundary (0 to 2 h)
Thyroid 0.3 Whole body
< 0.1 Low population zone outer boundary (0 to 2 h)
Thyroid 0.1 Whole body
< 0.1 ________________________
- a. Doses from MURPU and Control Room Habitability (TSTF-448) implementation.
VEGP-FSAR-15
15.8-1 REV 16 10/10 15.8 ANTICIPATED TRANSIENTS WITHOUT TRIP The worst common mode failure which is postulated to occur is the failure to scram the reactor
after an anticipated transient has occurred. A series of generic studies (1,2) on anticipated transients without scram (ATWS) showed acceptable consequences would result provided that the turbine trips and auxiliary feedwater flow is initiated in a timely manner. The effects of
ATWS events are not considered as part of the design basis for transients analyzed in Chapter
- 15. The final NRC ATWS rule (3) requires that Westinghouse-designed plants install ATWS mitigation system circuitry (AMSAC) to initiate a turbine trip and actuate auxiliary feedwater flow independent of the reactor protection system. The Vogtle AMSAC design is described in
section 7.7.
In support of the Measurement Uncertainty Recapture Power Uprate, a plant-specific evaluation was performed to demonstrate continued conformance with the analyses that formed the basis for the ATWS rule (Reference 4 and 5), at the uprated conditions. 15.
8.1 REFERENCES
- 1. "Westinghouse Anticipated Transients Without Trip Analysis," WCAP-8330 , August 1974. 2. Anderson, T. M., "ATWS Submittal," Westinghouse Letter NS-TMA-2182 to S. H.
Hanauer of the NRC, December 1979. 3. ATWS Final Rule - Code of Federal Regulations 10 CFR 50.62 and Supplementary Information Package, "Reduction of Risk from Anticipated Transients Without Scram (ATWS) Events for Light-Water-Cooled Nuclear Power Plants." 4. NL-07-1010, "Vogtle Electric Generating Plant Request to Change Licensed Maximum Power Level," L. M. Stinson to USNRC, August 28, 2007. 5. NL-08-0307, "Vogtle Electric Generating Plant, Units 1 and 2, Issuance of Amendments Regarding Measurement Uncertainty Recapture Power Uprate (TAC Nos. MD6625 and MD6626)," USNRC to T. E. Tynan, February 27, 2008.
VEGP-FSAR-15A REV 15 4/09 TABLE 15A-1 (SHEET 1 OF 2)
PARAMETERS USED IN ACCIDENT ANALYSIS
General Core power level (MWt) 3636 Number of fuel assemblies in the core 193 Maximum radial peaking factor 1.70 Steam generator tube leak (gal/min) 1.0 Sources
Core inventories (Ci) Table 15A-3 Gap inventories (Ci) Table 15A-3 Primary coolant specific activities for 1% fuel defects (µCi/g) Table 15A-4 Primary coolant activity, Technical Specification limit for iodines - I-131 dose equivalent (µCi/g) 1.0 See table 15A-6.
Secondary coolant activity Technical Specification limit for iodines - I-131 dose equivalent (µCi/g) 0.1 Activity Release Parameters
Free volume of containment (ft
- 3) 2.95 x 10 6 Containment leak rate 0 to 24 h (percent per day) 0.2 After 24 h (percent per day) 0.1 Control room Free volume (ft
- 3) 1.72 x 10 5 Normal ventilation rate, unfiltered (ft 3/min) 3000 Time to isolate normal ventilation (s) 11.3 Time to establish emergency ventilation one unit operating (s) 99.3 Time to establish emergency ventilation, three units operating (s) 108 Emergency ventilation intake rate - one unit operating (ft 3/min) 1500 Emergency ventilation intake rate - three units operating (ft 3/min) 3870 VEGP-FSAR-15A REV 15 4/09 TABLE 15A-1 (SHEET 2 OF 2)
Emergency ventilation rate, - one unit operating (ft 3/min) 17,100 (a) Emergency ventilation rate, - three units operating (ft 3/min) 47,500 (a) Unfiltered infiltration rate (ft 3/min) unpressurized control room 825 + 10 (b) pressurized control room 120 + 10 (c) Iodine removal efficiency for recirculation filters (all forms of iodine) (percent) 99 Iodine removal efficiency for intake filters (all forms of iodine) (percent) 99 High-efficiency particulate air filter efficiency (percent) 99 Miscellaneous
Atmospheric dispersion factors (/Q)(s/m 3) Table 15A-2 Dose conversion factors Gamma body and beta skin (rem-m 3/Ci-s) Table 15A-5 Thyroid (rem/Ci) Table 15A-5
- a. The value is for combined intake and recirculation air flow. The value also reflects the Technical Specification acceptance criterion of +/- 10% of the nominal flow for a single train.
- b. 825 cfm unfiltered inleakage for inleakage testing. 10 cfm is for ingress/egress.
- c. 120 cfm unfiltered inleakage for inleakage testing. 10 cfm is for ingress/egress.
VEGP-FSAR-15A REV 18 9/13 TABLE 15A-3 CORE FISSION PRODUCT INVENTORY (a) Nuclide Total Core Inventory (Ci)
Fuel Rod Gap Inventory (Ci)(b)(c) I-131 1.03E+08 1.03E+07 I-132 1.50E+08 1.50E+07 I-133 2.10E+08 2.10E+07 I-134 2.26E+08 2.26E+07 I-135 1.95E+08 1.95E+07 Kr-85m 2.68E+07 2.68E+06 Kr-85 1.04E+06 3.12E+05 Kr-87 4.93E+07 4.93E+06 Kr-88 7.02E+07 7.02E+06 Xe-131m 7.13E+05 7.13E+04 Xe-133m 3.01E+07 3.01E+06 Xe-133 2.12E+08 2.12E+07 Xe-135m 4.18E+07 4.18E+06 Xe-135 4.65E+07 4.65E+06 Xe-138 1.69E+08 1.69E+07 I-127 4.45 kg 1.34 kg I-129 18.3 kg 5.49 kg
- a. Source term at end of fuel cycle with zero decay.
- b. The gap fractions are assumed to be 10% of the core activity for all isotopes except for Kr-85, I-127, and I-129 for which the gap fraction is assumed to be 30%. An exception to this is taken for the fuel handling accident which assumes a gap fraction of 12% for I-131, following the recommendation in NUREG/CR-5009.
- c. The gap fractions assumed for the fuel handling accident analyses in subsection 15.7.4 are based on Regulatory Guide 1.195.
VEGP-FSAR-15A REV 15 4/09 TABLE 15A-4 PRIMARY COOLANT NOBLE GAS CONCENTRATIONS (a) Nuclide Concentration
(µCi/g)
Kr-85m 2.04 Kr-85 8.37 Kr-87 1.28 Kr-88 3.68 Xe-131m 2.02 Xe-133m 17.6 Xe-133 256 Xe-135m 0.56 Xe-135 8.30 Xe-138 0.74 _________ a. Based on operation with 1.0% of power produced by fuel rods with cladding defects and with no purge of noble gas activity from the volume control tank to the gaseous waste processing system.
REV 14 10/07 RELEASE PATHWAYS FIGURE 15A-1
VEGP-FSAR-15B REV 14 10/07 APPENDIX 15B
(This appendix has been deleted)
VEGP-FSAR-16
16.1-1 REV 14 10/07 TECHNICAL SPECIFICATIONS 16.1 PRELIMINARY TECHNICAL SPECIFICATIONS The preliminary Technical Specifications were provided in the VEGP Preliminary Safety Analysis Report as part of an application for a construction permit. The construction permit for
VEGP was issued on June 28, 1974. Therefore, this section is not applicable to the VEGP Final
Safety Analysis Report.
VEGP-FSAR-16
16.2-1 REV 14 10/07 16.2 PROPOSED FINAL TECHNICAL SPECIFICATIONS 16.2.1 FOREWORD The following paragraphs briefly describe the applicability, format, and schedule for the development of the VEGP Technical Specifications.
16.2.2 APPLICABILITY The Nuclear Regulatory Commission's (NRC's) Standard Technical Specifications for Westinghouse Pressurized Water Reactors (NUREG-0452) and Standard Radiological Effluent
Technical Specifications for Pressurized Water Reactors (NUREG-0472) will be adapted to
reflect the VEGP design.
16.2.3 FORMAT The format of the Technical Specifications will address the categories required by 10 CFR 50 and will consist of six sections covering definitions, safety limits and lim iting safety systems settings, limiting conditions for operation (LCOs), surveillance requirements, design features, and administrative controls. The LCOs and surve illance requirements (sections 3 and 4) will be presented in a combined format, with each LCO appearing first, followed immediately by the
applicable surveillance requirements. The combined section 3/4 will be subdivided into 12
subsections covering the following areas:
- Reactivity control systems.
- Power distribution limits.
- Instrumentation.
- Containment systems.
- Plant systems.
- Electrical power systems.
- Refueling operations.
- Special test exceptions.
- Radioactive effluents.
- Radiological environmental monitoring.
VEGP-FSAR-16
16.2-2 REV 14 10/07 16.2.4 SCHEDULE The Technical Specifications for VEGP Units 1 and 2 will be submitted to the NRC approximately 15 months before the scheduled fuel load date of each unit. This submittal will
be separate from the VEGP Final Safety Analysis Report but will be incorporated into the VEGP
docket by confirmatory letter. The Technical Specifications for the VEGP will be based on the
current version of the NRC's Standard Technical Specifications for Westinghouse Pressurized
Water Reactors and Standard Radiological Effluent Technical Specifications for Pressurized
Water Reactors.
VEGP-FSAR-16
16.3-1 REV 19 4/15 16.3 TECHNICAL SPECIFICATION IMPROVEMENT PROGRAM The Technical Specification Improvement Program fo r VEGP resulted in the inclusion of certain technical requirements into the FSAR. These improvements are provided below. Changes to these requirements shall be reviewed and approv ed in accordance with VEGP administrative procedures. 16.3.1 REQUIREMENT 1 - REACTOR TRIP SYSTEM RESPONSE TIMES The reactor trip system response times are addressed in FSAR paragraph 7.2.1.2.6, Minimum Performance Requirements. 16.3.2 REQUIREMENT 2 - ENGINEERED SAFETY FEATURE ACTUATION SYSTEM RESPONSE TIMES The engineered safety feature actuation system response times are addressed in FSAR paragraph 7.3.1.1.2.6, Minimum Performance Requirements. 16.3.3 REQUIREMENT 3 - LOOSE PART DETECTION SYSTEM The loose part detection system requirements are addressed in the Technical Requirements Manual by TR 13.3.8, Loose Part Detection System. 16.3.4 REQUIREMENT 4 - REACTOR VESSEL MATERIAL IRRADIATION SPECIMENS The reactor vessel material irradiation specimen requirements are addressed in FSAR paragraph 5.3.1.6, Material Surveillance. 16.3.5 REQUIREMENT 5 - CONTAINMENT ISOLATION VALVES The containment isolation valve isolation time requirements of Technical Specification 3.6.3, Containment Isolation Valves, are addressed in FSAR paragraph 6.2.4.2.1, General Description. 16.3.6 REQUIREMENT 6 - CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTION The containment penetration conductor overcurrent protection requirements are addressed in Technical Requirements Manual TR 13.8.1, C ontainment Penetration Conductor Overcurrent Protective Devices.
VEGP-FSAR-16
16.3-2 REV 19 4/15 16.3.7 REQUIREMENT 7 - AREA TEMPERATURE MONITORING The area temperature monitoring requirement s are addressed in Technical Requirements Manual TR 13.7.5, Area Temperature Monitoring. 16.3.8 REQUIREMENT 8 - TURBINE OVERSPEED PROTECTION
The turbine overspeed protection requirements are addressed in the Technical Requirements Manual by TR 13.3.5, Turbine Overspeed Protection. 16.3.9 REQUIREMENT 9 - TECHNICAL REQUIREMENTS MANUAL
Technical requirements that are licensing commitments, but which may be controlled by the licensee in accordance with the process for changes, tests, and experiments as provided in
10 CFR 50.59, can be maintained in the Technical Requirements Manual (TRM).
The TRM contains selected requirements that apply to the operation of VEGP with the intent being to provide a single, prominent, and easily accessible document for operating staff to
reference and which will support the operating staff's compliance with these requirements with a
minimum of effort. These requirements are conditions for operation, associated action
requirements, and surveillance requirements with the format for presentation of the
requirements being the same as used in the VEGP NUREG-1431 based Technical
Specifications.
The administrative controls for the TRM are the same as used for the control of the FSAR.
These administrative controls ensure proposed TRM changes do not require prior NRC
approval, or if prior approval is required, the controls ensure NRC review and approval are
obtained, prior to implementation of the change. Additionally, other federal regulations may
apply to the control of certain technical requirements and may be so stated at the appropriate
location in the body of the TRM. 16.3.10 REQUIREMENT 10 - REACTOR COOLANT SYSTEM PRESSURE ISOLATION VALVES AND LEAKAGE LIMITS The reactor coolant system pressure isolat ion valves and leakage limit requirements of Technical Specification 3.4.14, RCS Pressure Isolation Valve (PIV) Leakage, are addressed in FSAR paragraph 5.4.12.4, Tests and Inspections.
VEGP-FSAR-18
REV 14 10/07 TABLE 18.1-1 MAIN CONTROL ROOM ANNUNCIATOR ALARM SEQUENCE FIRST-OUT SEQUENCE OF OPERATION (MODIFIED)(a)
Field Condition Contact Lamp Horn 1 Horn 2 Normal Normal Off Off Off
Alarm First Abnormal Gallop flas h On Off Subsequent Abnormal Fast flash On Off
Return to First Normal Gallop flas hOn Off normal before
acknowledge
Subsequent Normal Fast flash On Off
Acknowledge First Abnormal Slow flashOff Off
Subsequent Abnormal Steady Off Off
Return to First Normal Slow flashOff On normal
Subsequent Normal Slow flashOff On
Reset First Normal Off Off Off
Subsequent Normal Off Off Off
Test First Normal Gallop flas h On Off
- a. All windows will be on a first-out condition during the test sequence.
VEGP-FSAR-18
REV 14 10/07 TABLE 18.1-2 MAIN CONTROL ROOM ANNUNCIATOR ALARM SEQUENCE RING-BACK SEQUENCE OF OPERATION
Field Condition Contact Lamp Horn 1 Horn 2 Normal Normal Off Off Off
Alarm Abnormal Fast flash On Off
Return to
normal Normal Fast flash On Off before acknowledge Acknowledge Abnormal Steady Off Off
Return to
normal Normal Slow flash Off On Reset Normal Off Off Off
Test Normal Fast flash On Off
VEGP-FSAR-18
REV 14 10/07 TABLE 18.1-3 (SHEET 1 OF 2)
MAIN CONTROL ROOM ANNUNCIATOR ALARM SEQUENCE
Reflash Sequence of Operation - One Incoming Alarm Which Returns to Normal Before Being Acknowledged (Common Window)
Field Condition Contact Lamp Horn 1 Horn 2 Normal Normal Off Off Off
Alarm (a) Abnormal Fast flash On Off
Return to norm a Normal Fast flash On Off before acknowledge
Acknowledge Normal Slow flash Off On
Reset Normal Off Off Off
Reflash Sequence of Operation - Two or More Incoming Alarms (Common Window)
Field Condition Contact Lamp Horn 1 Horn 2 Normal Normal Off Off Off
Alarm 1 (a) Abnormal Fast flash On Off
Alarm 2 (a) Abnormal Fast flash On Off
Acknowledge Abnormal Steady Off Off
Alarm 3 (a) Abnormal Fast flash On Off A larm 1 return s Abnormal Fast flash On Off t o n o r m a l Acknowledge Abnormal Steady Off Off A larm 2 return sAbnormal Steady Off Off t o n o r m a l VEGP-FSAR-18
REV 14 10/07 TABLE 18.1-3 (SHEET 2 OF 2)
Field Condition Contact Lamp Horn 1 Horn 2 Alarm 3 returns Normal Slow flash Off On to normal
Reset Normal Off Off Off
- a. Incoming alarm shall always have precedence over return to normal.
VEGP-FSAR-18
18.2-1 REV 14 10/07 18.2 PRELIMINARY REVIEW OF THE CONTROL ROOM AND CONTROL BOARD DESIGN 18.2.1 REVIEW PROCEDURES 18.2.1.1 Introduction The preliminary review of the control room and control board design was conducted by the General Physics Corporation, with the primary objective of providing an adequate evaluation of
the human factors.
The review included primarily those panels which comprised the inner ring of panels in the control room.
Certain additional panels which are not in the inner ring were also reviewed. A listing of the panels reviewed is given below:
Inner Ring Panels Outer Ring Panels QMCB A1 HVC QMCB A2 QPCP QMCB C QMCB B1 QMCB B2 QMCB D QEAB Figure 18.1-1 illustrates the layout of the panels in the main control room.
The review procedures and results are presented in detail in reference 1 and summarized in this section. The review was performed in accordance with the guidelines of NUREG/CR-1580.
(2) The use of engineering checklists provided standards of assessment of various properties of the
control room including, among other aspects:
- Functional grouping.
- Anthropometrics.
- Readability of labels.
- Controls discrimination.
These checklists were developed based upon the latest established and recommended human
factors engineering criteria.
Several techniques were employed in the review of the VEGP control room. Operators were used to determine how the VEGP control board stood in relationship to similar vintage control
boards. Human factors specialists judged the control board against applicable guidelines.
Engineering checklists were employed to evaluate individual controls and control/display layout.
Scenario evaluations were performed to assess the operability of the board. Using the above
methods, the human factors engineering group was able to make assessments of:
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18.2-2 REV 14 10/07
- Anthropometrics and panel elements.
- System layout.
- Component usage.
- Readability of displays and labels.
- Coding/discrimination methods.
- Environmental conditions.
- Operability of control board.
Below is a detailed description of methodologies used in anthropometrics and panel elements
analysis, system evaluation, component evaluati on, and scenario evaluation. The information gathered by use of these human factors methodol ogies served as a basis for the development of preliminary recommendations. The evaluation of these recommendations and their
resolutions are provided in subsection 18.2.2.
18.2.1.2 Anthropometrics Anthropometric evaluation was performed by com paring the control room design to established human factors guidelines. The main references used were Bechtel drawings, NUREG-1580, (2) and MIL-STD-1472B.
(3) The guidelines were applied three ways: by scale drawings, by use of a 1/4-in. scale panel silhouette and mannequins scaled for the 95th and 5th percentile male, and by actual
measurements of reach and heights taken from the mockup.
Items examined were:
- Panel height.
- Distance of reach.
- Viewing distance.
- Viewing angle.
- Placement of controls and displays in relationship to anthropometric value. 18.2.1.3 System Evaluation System evaluation was performed after developi ng engineering checklists from the current applicable human factors engineering guidelines, specifically NUREG/CR-1580.
(2) A separate set of questions was asked about each control and each display. A list of these questions is provided below. The questions were asked about each individual component with
answers recorded as a yes or no. A. Control Checklist VEGP-FSAR-18
18.2-3 REV 14 10/07 1. Are controls placed such that they may be easily operated? 2. Is control located to prevent inadvertent operation?
- 3. Does control give the information needed for operation of the equipment/system? 4. Is the control clearly marked as to what it does?
- 5. Do controls move in the culturally normal direction (clockwise for on)?
- 6. Is this control the best type of control for the function needed?
- 7. Are controls grouped in a consistent left-to-right, top-to-bottom order?
- 8. Is control not prone to be misread or its position misinterpreted? B. Display Checklist 1. Is display prone to be misread or misinterpreted?
- 2. Is display the best type for indicating system/equipment function?
- 3. Does display give the type of information needed?
- 4. Does display movement correspond to the control movement?
- 5. Is display in reasonable proximity to the control? 18.2.1.4 Component Evaluation Component evaluation was performed by reviewi ng all pertinent human factors guidelines, then developing a list of these guidelines applicable to components in the control room. Additions to this list draw heavily on Nuclear Regulatory Commission (NRC) Safety Evaluation Reports.
(4)(5)(6) These documents were reviewed:
- Electrical one-line diagrams.
- Piping and instrumentation diagrams.
- Control logic diagrams.
- Instrument specification sheets.
- Instrument index.
- Digital rod position indicator specification.
- Specification for the electrical auxiliary board and the miscellaneous control board.
- Various vendor documents were utilized.
Where possible, a hands-on evaluation of controls was performed. This entailed the use of
testing devices such as a snap-on torque meter or an Amtex torsional testing machine. In
addition, observation of equipment equivalent to that found in the VEGP control rooms was
made at various operating simulators. In particular, the Sequoyah and McGuire simulators were
used.
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18.2-4 REV 14 10/07 Safety evaluation reports were reviewed to determine how the NRC implemented the various
guidelines. 18.2.1.5 Scenario Evaluation Scenario walkthroughs were performed at the control room mockup for Unit 1 to gain an operational perspective on the proposed layout and to evaluate it from the operator's point of
view. The primary purpose of this methodology was to assess the logical sequencing of all
actions and the flow of required motions to perform the required actions in a timely manner.
This evaluation was performed in three phases. The first phase was the creation of operating procedures from Westinghouse generic procedures. The second phase was the actual
walkthrough. The third phase was the scenario evaluation.
Nine scenarios were selected from Westinghouse generic procedures. Four nonprocedural scenarios were added during the review. The nine selected were chosen because they
represent a wide variety of plant activities and contain the basic parameters for many more
operating tasks. The four shorter scenarios were added to provide a review of observational
tasks. The nine scenarios were:
- Immediate action and diagnostics.
- Steam generator tube rupture.
- Operation with natural circulation.
- Plant shutdown from minimum load to cold shutdown.
- Reactor coolant system leak.
- Station blackout.
- Plant startup from cold shutdown to minimum load.
- Loss of reactor coolant.
The four additional scenarios performed were:
- Loss of secondary coolant.
- Starting the diesel generators.
- Controlling steam generator level.
- Changeover from recirculating mode to injection mode.
The information collected by use of these human factors methodologies served as a basis for
the development of preliminary recommendations.
The evaluation of these recommendations is provided in subsection 18.2.2.
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18.2-5 REV 14 10/07 18.2.1.6 Reviewer Experience General Physics Corporation, the prime control board reviewer, has had the following
experience in design review:
- North Anna, Unit 2 Control Room Review.
- EPRI-RP769, Performance Measurement System for Training Simulators.
- Babcock & Wilcox and U.S. Department of Energy, Disturbance Analysis and Surveillance System.
- Clinch River Breeder Reactor Control Room Review.
- Edison Electric Institute, Operator Selection Study.
- Operability Assessment of Prototype Large Breeder Reactor Designs.
- Electric Power Research Institute, Survey and Analysis of Communication Problems in Nuclear Power Plants. 18.2.2 CONTROL ROOM AND CONTROL BOARD EVALUATION RESULTS 18.2.2.1 Human Factors Deficiencies Categories The human factor deficiencies were categorized into five general groupings: A. Administrative, where no hardware solutions were available. B. Components, where the type of display, means and methods of manipulation, and elimination of the chances for inadvertant or accidental misoperation were considered. C. Labeling, where the identifications of systems, trains, and devices were reviewed so that quick and easy identification by the operators would be enhanced. D. Rearrangement of components, where component functional relationships were considered and their actual arrangement on the board was then critiqued. E. Workshop/environment, where noise, temperature, lighting, and workspace definition were considered which would lead to increased operation effectiveness
and reduced distraction; other deficiencies which would negatively affect operator
performance. 18.2.2.2 Findings and the Resolutions Thereof The preliminary control room design review identified human engineering deficiencies at an
early stage in the design in order that they could be incorporated in design improvements, operator training, and plant operating and administrative procedures. When final NRC guidance
was issued, the review process was repeated in the detailed control room design review, detailed in section 18.3.
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18.2-6 REV 14 10/07 18.2.2.3 References
- 1. General Physics Corporation, "Report on Human Factors Evaluation of Alvin W. Vogtle Nuclear Power Plant Control Room," GP-R-23003, Columbia, Maryland. 2. U.S. Nuclear Regulatory Commission, "Human Engineering Guide to Control Room Evaluation - Draft Report," NUREG/CR-1580, July 1980. 3. U.S. Department of Defense, "Human Engi neering Design Criteria for Military Systems, Equipment, and Facilities," MIL-STD-1472B, Washington, D.C., May 1978. 4. U.S. Nuclear Regulatory Commission, "Safety Evaluation Report, Supplement No. 1, Docket Nos. 50-327 and 50-328, Sequoyah Nuclear Plant Units 1 and 2," NUREG-0011, February 1980. 5. U.S. Nuclear Regulatory Commission, "Safety Evaluation Report, Supplement No. 10, Docket No. 50-339, North Anna Power Station Unit 2," NUREG-0053, July 1980. 6. U.S. Nuclear Regulatory Commission, "Safety Evaluation Report, Supplement No. 4, Docket No. 50-311, Salem Nuclear Generating Station Unit 2, NUREG-0512, January
1979.
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18.3-1 REV 14 10/07 18.3 DETAILED CONTROL ROOM DESIGN REVIEW 18.3.1 BACKGROUND Guidance for the control room design review (CRDR) was provided by various NUREGs and Regulatory Guides. A Nuclear Utility Task Action Committee (NUTAC) with staff support from
the Institute of Nuclear Power Operations (INPO) developed a generic control room design
review implementation plan from these guidelines. NRC guidance and NUTAC guidelines were
used by Georgia Power Company (GPC) for t he development of the detailed CRDR process.
The detailed control room design review stands alone in documenting compliance with NRC
requirements. Many design changes recommended in the preliminary review were already incorporated, resulting in fewer design deficiencies when reviewed by NUREG 0700 guidance.
However, some items identified in the preliminary review had not been incorporated into the
design. To assure problems were not overlooked, those items were incorporated in the review
as human engineering discrepancies (HEDs) for review and resolution. 18.3.2 OBJECTIVES OF THE CRDR The objective of the CRDR was to determine the extent to which the VEGP control room provides the operators with sufficient information to complete their required functions and task
responsibilities efficiently under emergency conditions. The review also determined the human
engineering suitability of the designs of the instrumentation and equipment in the VEGP control
room. To ensure that the CRDR fulfilled its stated purpose, several specific objectives were identified and met during the review. The following specific objectives were defined for the CRDR:
- To perform a control room survey that compares the existing control room with accepted human engineering criteria.
- To review relevant plant operational experience using appropriate documentation and operator questionnaires.
- To determine the information and control requirements of control room operator tasks during emergency conditions.
- To identify human engineering discrepancies.
- To evaluate the extent and importance of identified discrepancies.
- To formulate and implement solutions for significant discrepancies.
- To ensure that the proposed solutions do, in fact, eliminate or mitigate the discrepancies for which they are formulated without creating new discrepancies.
- To verify that implemented solutions eliminate or mitigate identified discrepancies.
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18.3-2 REV 14 10/07 18.3.3 CONTROL ROOM DESIGN REVIEW PROCESS This section describes the process that was used to accomplish the objectives of the CRDR. 18.3.3.1 Preliminary CRDR Status Evaluation Recognizing that the 1982 control room design review would provide valuable input to the current control room design review, each of the identified deficiencies/discrepancies was
reviewed by the use of the following checklist:
- Action reflects the recommended intent and resolves the HED.
- Action reflects the recommended intent but does not resolve the HED.
- Action does not reflect the recommended intent.
- Actions taken create other HED(s).
- No action taken, deficiency remains.
- No action taken, deficiency resolved by resolution of HED.
- New HED(s) generated.
- Other (explain). 18.3.3.2 Operating Experience Review The Vogtle Electric Generating Plant was under construction with no operating history, and the
onsite experience of operational personnel and data from plant operating documents provided little information for the CRDR. Accordingly, the operating experience review focused primarily
on industry experience at similar plants and c onsidered the experience gained from the VEGP plant-specific simulator.
Two separate steps were involved in reviewing operating experience. The first was to review available and applicable historical documentation pertaining to plant-specific and generic
occurrences. The second step was to survey operating personnel. Operating personnel surveys (operator questionnaire) identified specific problem areas in the VEGP control room that may
occur during normal and emergency operation. The operator questionnaire was extracted from
the Control Room Design Review Survey Development Guideline (INPO 83-014). 18.3.3.3 Problem Reports An open ended control room design problem form was sent to all control room and simulator personnel. Copies were made available in the control room and the simulator. This allowed
any problem noted to be promptly reported. Thes e problem reports were evaluated for possible
HEDs by the review team leader. In many case s, the problem reports identified items already documented by surveys or prior problem reports.
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18.3-3 REV 14 10/07 18.3.3.4 Control Room Surveys Surveys of the existing VEGP control room were conducted during the CRDR. The purpose of the surveys was to compare the design features of the existing control room with applicable
human engineering design guidelines. The surveys were conducted by the CRDR review team.
The survey team used questionnaires, checklists, and surveys to compile information regarding the as-built characteristics of the VEGP control room.
Eleven separate surveys were completed duri ng the CRDR survey activity. Some of the surveys consisted simply of recording (or determi ning) control room conventions, such as color usage and instrument arrangement. In general, HEDs were not written during the convention surveys. Instead, the information obtained was used in other CRDR activities to determine
where particular instruments or system s departed from the overall convention.
Other surveys measured certain physical quantities, such as illumination and sound level, and
compared these measurements to acceptable, or preferred, human engineering standards for such quantities. HEDs were written for characteristics that fell outside the acceptable band.
The individual surveys were:
- General design convention survey (NUTAC 83-042).
- Design convention survey for repetitive groupings (NUTAC 83-042).
- Lighting survey (NUREG 0700 Section 6.1.5).
- Noise survey (NUREG 0700 Appendix E).
- Anthropometric survey (NUTAC 83-042 and NUREG 0700 Section 6.1.2).
- Annunciator survey (NUREG 0700 Section 6.3).
- Communication survey (NUREG 0700 Section 6.2).
- Abbreviation and acronym survey (NUTAC 83-042).
- Color coding survey (NUTAC 83-042).
- Control room computer survey (NUREG 0700 Section 6.7).
- NUTAC 83-042 appendices B-H survey (using applicable NUREG 0700 guidelines). 18.3.3.5 Task Analysis The operating experience review and the control room survey identified as HEDs those control room characteristics that had caused, or near ly caused, problems during normal operation and
simulator exercises and those characteristics that did not conform to certain human engineering
design criteria. The task analysis identified the tasks that operators must perform during
emergency operation and determined whether the instrumentation, controls, and equipment
were available and suitable to perform those tasks. In addition to determining the availability of
suitable instrumentation, controls, and equipment, the task analysis validated that the VEGP-FSAR-18
18.3-4 REV 14 10/07 emergency tasks identified could be performed in real time under simulated emergency
conditions in the VEGP control room.
The task analysis used as its basis the Emergency Response Guidelines (ERGs) developed by the Westinghouse Owners Group (WOG). 18.3.3.6 Instrumentation and Control Characteristics Review In response to the NRC in-progress audit concerns that the task analysis did not identify instrument and control (I&C) needs as compared to the I&C control room inventory, an
independent review of the VEGP control room inventory, instrumentation and control
characteristics was conducted. The instrumentation and control characteristics review program
identified the instrumentation, controls, and characteristics necessary for proper operator
response to emergency transients. This review program first identified generic characteristics
based on the Westinghouse Owners Group high-pressure reference plant design, followed by
the identification of plant-specific deviations. The characteristics of the installed control room
instrumentation were justified with the development of or reference to appropriate generic or
plant-specific basis documentation. 18.3.3.6.1 Identification of Required Instrumentation and Controls The Emergency Response Guidelines and the ERG background documents were reviewed to identify:
- All operator tasks necessary to support the operator functions.
- Operator information and control needs necessary to support the operator functions and major actions.
- Plant systems necessary to provide information and control needs.
- Plant instrumentation and controls necessary to provide information and control needs. For the required plant instrumentation and controls identified above, characteristics were
determined based on the information and control needs. The characteristics for the
instrumentation included the following:
- Setpoints.
- Units.
- Range.
- Resolution.
- Type of display.
Characteristics for controls included the following:
- Positions.
VEGP-FSAR-18
18.3-5 REV 14 10/07
- Type of control (e.g., variable).
From the information gathered in the characteristics review, a required characteristics
justification table was developed for required instrumentation. This table identified operator
action categories and associated operator information needs, criteria, and characteristics. The
basis for each action category or information need was described or a reference to other
documentation was provided.
Following identification of the required characteristics, the VEGP specifics were identified. The VEGP-specific characteristics consisted of app licable generic characteristics and plant-specific deviations. To identify VEGP-specific instrumentation and controls and their associated
required characteristics, the Vogtle Emergency Operating Procedures were reviewed to identify
deviations from the Emergency Response Guide lines. These VEGP-specific characteristics were then entered in the required characteristics justification tables.
Generic and VEGP-specific required characteristics were reviewed and the limiting required characteristics were summarized in characteristics requirements tables.
18.3.3.6.2 Verification Verification of the installed control board instrumentation with respect to the above defined required instrumentation and control characteristics was performed. The CRDR team
developed an inventory of VEGP control board instrumentation and controls. The CRDR team
then compared the inventory to the instrumentation and control characteristics requirements
tables for consistency. No HEDs (not already identified in the original task analysis) were
identified from this review. This verification provided assurance that the operator did in fact
have the required instrumentation and controls assumed in the Westinghouse Owner's Group
transient analysis for response to emergency transients. 18.3.4 EVALUATION OF HUMAN ENGINEERING DISCREPANCIES 18.3.4.1 Objectives of Evaluation Process The objectives of this phase of the CRDR were:
- Evaluate the significance of the HEDs identified in the previous phases of the CRDR.
- Where HEDs were found to be of minor significance, describe the technical and operational basis for such a finding.
- Where the HEDs were found to be significant, formulate changes to the control room design, procedures, operator training, or any combination thereof to mitigate those HEDs. 18.3.4.2 Evaluation Criteria Human engineering discrepancies found during the control room surveys, the operating
experience review, and the task analysis were evaluated by the review team for their potential to
adversely affect normal and emergency operation. A categorization scheme was used that VEGP-FSAR-18
18.3-6 REV 14 10/07 required each HED to be assessed by the review team and prioritized for resolution. The
following five categories were designed to be unique so a consensus could be obtained from
the review team as to which category each HED should be assigned.
- Category 1 (Safety Significant) - HEDs that have caused errors in or are judged likely to adversely affect the management of emergency conditions by control room
operators.
- Category 2 - HEDs that are known to have caused problems during normal operation.
- Category 3 - HEDs that can be fixed with simple and inexpensive enhancements, so called "paint, tape, and label" (PTL) fixes. This included HEDs that were easy to fix
but difficult to assess as to the effect on emergency operation.
- Category 4 - These HEDs were judged by the review team as unlikely to affect emergency operation, not documented as causing problems during normal
operation, and not easily corrected. However, corrective action was recommended.
- Category 4a - A minor deviation from standards not expected to cause a problem.
No corrective action was recommended.
HEDs were initially categorized using a subjective approach that reflected the consensus
judgment of the multidisciplinary CRDR team. This HED category review employed a
systematic approach based on the assessment process identified in NUREG 0800 and NUREG
0801 (Draft).
HEDs were evaluated with respect to the following attributes and subjected to the algorithm presented in figure 18.3-1 to determine their significance and effects on plant safety. Item 1 HEDs experienced (EOP validation) or assessed (surveys or checklists) as having a high probability of contributing to operator error. Item 2 HEDs associated with engineered safety features (ESF) systems.
Item 3 HEDs that could result in unsafe operation or violation of the Technical Specifications. Item 4 HEDs identified through the operating experience review or actual problems identified in the operator questionnaire. Item 5 HEDs determined to be easily correctable with paint, tape, labels, engraving changes, or work space environment improvements. Item 6 HEDs determined to contribute to the operator mental work load (cumulative effects) resulting in fatigue, confusion, or discomfort. 18.3.4.3 Resolution of Human Engineering Discrepancies 18.3.4.3.1 Approach to Correction The correction of human engineering discrepancies was generally based on the following preferred order of approaches:
VEGP-FSAR-18
18.3-7 REV 14 10/07 A. Guideline compliance - The first preference for correction of HEDs was to modify the control room to comply with the guidelines of NUREG 0700. This approach
was used for labeling, procedural, and support equipment HEDs. Control board
arrangement HEDs used this approach when consistent with regulatory (train
separation) and physical (panel space) limitations. B. Compensatory measures - When conflicting regulatory or physical constraints prevented a straightforward change to achieve guideline compliance, changes
were used which eliminated or reduced the impact of an HED on the operators. 18.3.4.3.2 Engineering Consensus The development and selection of corrections to HEDs was accomplished by group meetings of the detailed CRDR team. Alternate approaches, benefits, and costs were discussed, and an
engineering consensus was arrived at on the recommended approach to correct each HED.
The diverse backgrounds of team members were intended to provide input from all disciplines
on the resolution of HEDs. The procedures in use called for final recording of the board
recommendations. Brief summaries of the resolutions and supporting comments were reported
in the Detailed CRDR Report of June 10, 1986. 18.3.4.3.3 Cost-Benefit Analysis The engineering consensus approach considered costs vs. benefits but did not perform a detailed, documented cost-benefit analysis. The emphasis was on correction of the HEDs to
enhance operator performance. The correction of safety significant HEDs was a commitment
without regard to cost. In all cases the team members sought to develop the most practical
solution balancing constructability, schedule, and cost to achieve the objective of enhanced
operator performance.
Some example cost considerations were: A. Labeling and procedure changes were always implemented to achieve compliance with NUREG 0700. These were typically less than $10,000-projects. B. Panel rearrangements generally less than $100,000 were implemented.
C. A major control room layout modification of $300,000 was implemented.
D. Major control panel replacements which would cost several million dollars were not recommended. HEDs involving such changes for exact compliance with NUREG 0700 guidelines were addressed with alternate solutions. 18.3.5 COORDINATION WITH OTHER ACTIVITIES The CRDR process was coordinated with other post-TMI activities in several ways. These activities included the following:
- Upgrading Emergency Operating Procedures.
- Detailed control room design review.
- Post-accident monitoring system (section 7.5).
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18.3-8 REV 14 10/07
- Safety parameter display system (subsection 9.5.10).
- Upgrading emergency response facilities.
The mechanism for coordination of control room improvements with other programs was the Emergency Operating Procedures validation program.
The coordination was achieved by: (1) having several members of the detailed CRDR team serve as members of the EOP observation teams during the EOP validation exercises, (2) the task analysis was a common basis for both the detailed CRDR and EOP programs, and (3) the
findings or discrepancies identified during the validation exercises related to man and machine
interface were processed via the detailed CRDR HED assessment process.
In addition, control room modifications that resulted from the Emergency Operating Procedures validation program were addressed in the detailed CRDR verification plan to ensure design
improvements provided the necessary correction. 18.3.5.1 Emergency Operating Procedures The task analysis portion of the detailed CRDR used the Westinghouse ERGs as plant-specific EOPs as its starting point. Thus, the task of upgrading emergency procedures is inherently
integrated into the detailed CRDR. The simulator validation of the task analysis was combined
with the VEGP EOP validation program. 18.3.5.2 Safety Parameter Display System (SPDS)
GPC used the SPDS during the EOP validation exercise, and evaluated it to NUREG 0700 Section 6.7 (process computer) guidelines. Some HEDs identified during the EOP validation
exercise or the computer survey and judged to be significant by the review team were resolved by incorporating certain features into the SPDS and associated displays. In addition, the
detailed CRDR team leader was chairman of a control room computer task force and
participated in developing displays and board arrangements. This served to incorporate human
engineering requirements into the design of the SPDS and further integrate them into the
detailed CRDR process. (See the Emergency Plan, section H.4.5.) 18.3.5.3 Regulatory Guide 1.97 The design of Regulatory Guide 1.97 instrumentation was essentially complete at the time of this review. This instrumentation was evaluated in the detailed CRDR survey and task analysis.
REV 14 10/07 HUMAN ENGINEERING DISCREPANCY EVALUATION ALGORITHM FIGURE 18.3-1 (SHEET 1 OF 2)
REV 14 10/07 HUMAN ENGINEERING DISCREPANCY EVALUATION ALGORITHM FIGURE 18.3-1 (SHEET 2 OF 2)
VEGP-FSAR-19
19.1-1 REV 16 10/10 19.0 LICENSE RENEWAL - AGING MANAGEMENT PROGRAMS AND ACTIVITIES
19.1 INTRODUCTION
19.1.1 BACKGROUND Renewed operating licenses for Vogtle Electric Generating Plant (VEGP) Units 1 and 2 were issued on June 3, 2009, extending the original licensed operating term by 20 years. Units 1 and 2 will enter the period of extended operation on January 17, 2027 and February 10, 2029 for Units 1 and 2, respectively. 19.1.1.1 License Renewal Rule and Process 10 CFR Part 54, the license renewal rule, establishes the procedures, criteria, and standards governing nuclear plant license renewal.
Plant systems, structures, and components (SSC s) within the scope of license renewal are defined in 10 CFR 54.4(a) as:
- Safety-related SSCs (i.e., perform a safety-related function as defined in 10 CFR 54.4(a) (1)).
- Nonsafety-related SSCs whose failure could prevent satisfactory accomplishment of safety-related functions.
- All SSCs relied on in safety analyses or plant evaluations to perform a function that demonstrates compliance with the Commission's regulations for fire protection (10 CFR 50.48), environmental qualification (10 CFR 50.49), pressurized thermal shock (10 CFR 50.61), anticipated transients without scram (10 CFR 50.62), and station blackout (10 CFR 50.63).
The license renewal rule focuses on managing the effects of aging on the passive intended functions of long-lived structures and components, and on evaluation of time-limited aging analyses (TLAA), as defined in 10 CFR 54.21. (See paragraph 19.1.1.3 for a discussion of the definition of a TLAA.)
The license renewal rule generically excludes structures and components associated only with active functions from an aging management review. Functional degradation resulting from the effects of aging on active functions is more readily determinable and detectable, and existing programs and regulatory requirements are expected to directly detect the effects of aging. The license renewal rule credits the continued applicability of existing programs and regulatory requirements, and the maintenance rule requirements (10 CFR 50.65), to monitor the performance and condition of SSCs that perform active functions.
The license renewal process includes the identification of SSCs within the scope of the license renewal rule, determining the in-scope structures and components subject to aging management review (i.e., are passive and long-lived), and assuring the effects of aging on the intended functions are adequately managed through the identification and/or development of VEGP-FSAR-19
19.1-2 REV 16 10/10 various aging management programs and activities. The process also includes the identification and evaluation of TLAAs, including any exemptions containing TLAAs.
The license renewal rule and the renewed operating licenses require that a summary description of the aging management programs and activities and the TLAA evaluations become part of the FSAR. To meet this requirement, sections 19.2 through 19.4 are incorporated into the FSAR. After issuance of the renewed license, 10 CFR 54.37(b) requires that, for newly identified SSCs that would have been subject to aging management review or evaluation of TLAAs in accordance with 10 CFR 54.21, the FSAR be updated to describe how the effects of aging will be managed such that the intended functions(s) in 10 CFR 54.4(b) will be effectively maintained during the period of extended operation. 19.1.1.2 Aging Management Programs The NRC, in the Standard Review Plan for License Renewal (NUREG-1800), Appendix A.1, "Aging Management Review - Generic (Branch Technical Position RLSB-1)," describes the elements of an acceptable aging management program to the NRC staff. Additionally, NUREG-1801, "Generic Aging Lessons Learned Report,"
describes aging management programs that have been found acceptable to the NRC Staff to manage the aging effects of SSCs for license renewal. In many cases, programs and activities existing at the time of the license renewal application were found adequate for managing aging for the period of extended operation. In some cases, the existing programs or activities required some degree of enhancement. Also, some new programs and activities were identified. It is important to note that only a portion of certain programs or activities may be relied upon for managing the effects of aging under the license renewal rule.
More than one program or activity may be credited to manage aging in a single system, structure, or component. Conversely, in other cases, one program or activity may manage the effects of aging in multiple systems. 19.1.1.3 Time-Limited Aging Analyses The license renewal rule requires that TLAA be evaluated to capture certain plant-specific aging analyses explicitly based on the original 40-year operating life of the plant. In addition, the Rule requires that any exemptions based on TLAAs be identified and analyzed to justify extension of those exemptions through the renewal term.
TLAA evaluations are defined by the license renewal rule in 10 CFR 54.3 as those calculations and analyses that meet all of the following six criteria:
- Involve SSCs within the scope of license renewal.
- Consider the effects of aging.
- Involve time-limited assumptions defined by the operating term, e.g., 40 years.
- Were determined to be relevant in making a safety determination.
- Involve conclusions or provide the bases for conclusions related to the capability of the SSC to perform its intended functions, as delineated in the Rule.
VEGP-FSAR-19
19.1-3 REV 16 10/10
- Are contained or incorporated by reference in the current licensing basis.
Once a TLAA has been identified, the Rule in 10 CFR 54.21 (c) requires it to be dispositioned by one of the following three specific criteria:
- The analyses remain valid for the period of extended operation.
- The analyses have been acceptably projected to the end of the period of extended operation.
- The effects of aging on the intended functions(s) will be adequately managed (e.g., programs or activities are in place) for the period of extended operation.
After the renewed license has been issued, 10 CFR 54.37 (b) requires that any newly identified calculations or analyses that would have been a TLAA be evaluated and a summary description placed in the FSAR. 19.1.2 AGING MANAGEMENT PROGRAMS The following programs are credited to manage the effects of aging during the period of extended operation for license renewal and are described in section 19.2 as listed below:
- Bolting Integrity Program (19.2.2).
- Boric Acid Corrosion Control Program (19.2.3).
- Buried Piping and Tanks Inspection Program (19.2.4).
- Closed Cooling Water Program (19.2.6).
- Diesel Fuel Oil Program (19.2.7).
- External Surfaces Monitoring Program (19.2.8).
- Fire Protection Program (19.2.9).
- Flow-Accelerated Corrosion Program (19.2.10).
- Flux Thimble Tube Inspection Program (19.2.11).
- Generic Letter 89-13 Program (19.2.12).
- Inservice Inspection Program (19.2.13).
- Nickel Alloy Management Program for Non-Reactor Vessel Closure Head Penetration Locations (19.2.14).
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19.1-4 REV 16 10/10
- Nickel Alloy Management Program for Reactor Vessel Closure Head Penetrations (19.2.15).
- Oil Analysis Program (19.2.16).
- One-Time Inspection Program (19.2.17).
- One-Time Inspection Program for ASME Class 1 Small Bore Piping (19.2.18).
- One-Time Inspection Program for Selective Leaching (19.2.19).
- Overhead and Refueling Crane Inspection Program (19.2.20).
- Periodic Surveillance and Preventive Maintenance Activities (19.2.21).
- Piping and Duct Internal Inspection Program (19.2.22).
- Reactor Vessel Closure Head Stud Program (19.2.23).
- Reactor Vessel Internals Program (19.2.24).
- Reactor Vessel Surveillance Program (19.2.25).
- Steam Generator Tubing Integrity Program (19.2.26).
- Steam Generator Program for Upper Internals (19.2.27).
- Water Chemistry Control Program (19.2.28).
- 10 CFR 50 Appendix J Program (19.2.29).
- Inservice Inspection Program - IWE (19.2.30).
- Inservice Inspection Program - IWL (19.2.31).
- Structural Monitoring Program (19.2.32).
- Structural Monitoring Program - Masonry Walls (19.2.33).
- Non-EQ Cables and Connections Program (19.2.34).
- Non-EQ Inaccessible Medium-Voltage Cables Program (19.2.35).
- Non-EQ Electrical Cable Connections One-Time Inspection Program (19.2.36). 19.1.3 AGING MANAGEMENT PROGRAMS - TIME LIMITED AGING ANALYSES (TLAA) The aging management programs credited for managing the associated TLAAs during the period of extended operation are described in section 19.3 as listed below:
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- Environmental Qualification Program (19.3.1).
- Fatigue Monitoring Program (19.3.2). 19.1.4 TLAA EVALUATIONS The evaluation of TLAAs for the period of extended operation is provided in section 19.4. The TLAAs evaluated for the period of extended operation are listed below:
- Reactor Vessel Neutron Embrittlement Analyses (19.4.1).
- Metal Fatigue Analysis (19.4.2).
- Environmental Qualification Calculations (19.4.3).
- Containment Tendon Pre-Stress Analysis (19.4.4).
- Penetration Load Cycles (19.4.5).
- Other Plant Specific Analysis (19.4.6).
19.
1.5 REFERENCES
- 1. NUREG-1800, Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants, U.S. Nuclear Regulatory Commission (Rev. 1), September 2005. 2. NUREG-1801, Generic Aging Lessons Learned (GALL) Report, U.S. Nuclear Regulatory Commission, (Rev. 1), September 2005. 3. Vogtle Electric Generating Plant Technical Specifications, Units 1 and 2.
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19.2-1 REV 16 10/10 19.2 AGING MANAGEMENT PROGRAM DESCRIPTIONS The VEGP integrated plant assessment for license renewal identified the aging management programs credited to provide reasonable assur ance that structures and components requiring an aging management review will continue to perform their intended functions consistent with the current licensing basis through the period of extended operation. This section describes the aging management programs and activities required to manage the effects of aging during the period of extended operation.
The aging management programs and activities in this section rely on the operations quality assurance program (OQAP) for VEGP and SNC for the elements of corrective action, confirmation process, and administrative controls. The VEGP quality assurance (QA) procedures, review and approval processes, and administrative controls are implemented in accordance with the requirements of 10 CFR 50, Appendix B. Corrective actions and administrative (document) control for both safety-related and nonsafety-related structures and components are accomplished per the existing co rrective action program and document control program and are applicable to all aging management programs and activities that will be required during the period of extended operation. The confirmation process is part of the corrective action program and includes reviews to assure that corrective actions are adequate, tracking and reporting of corrective actions, and reviews of corrective action effectiveness. Any followup inspection required by the confirmation process is documented in accordance with the corrective action program. The corrective acti on, confirmation process, and administrative controls of the OQAP are applicable to all aging management programs and activities required during the period of extended operation. 19.2.1 ACCW SYSTEM CARBON STEEL COMPONENTS PROGRAM The Auxiliary Component Cooling Water (ACCW) System Carbon Steel Components Program is a plant-specific program that manages cracking of carbon steel components exposed to ACCW through a combination of leakage monitoring and routine and periodic inspections. This includes the Units 1 and 2 ACCW systems, as well as carbon steel components serviced by these ACCW systems. The program is in response to operating experience related to nitrite-induced stress corrosion cracking (SCC) and subsequent component leakage in ACCW system components.
The program relies upon leakage detection monitoring, routine walkdowns, and periodic visual examinations. The program also includes preventive measures applicable to repairs and modifications intended to minimize crack initiation sites, lower stresses, and improve inspectability.
The ACCW System Carbon Steel Components Progr am will be implemented prior to the period of extended operation. 19.2.2 BOLTING INTEGRITY PROGRAM The Bolting Integrity Program is a plant-specific program that manages cracking, loss of material, and loss of preload in mechanical bolted closures. The Bolting Integrity Program applies to safety-related and nonsafety-related bolting for pressure-retaining components within the scope of license renewal, with the exception of the reactor vessel head studs which are addressed by the Reactor Vessel Head Closure Stud Program.
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19.2-2 REV 16 10/10 Preventive aspects of the program include use of appropriate bolting and torquing practices, including control of thread lubricants. Peri odic replacement of steam generator manway and handhole bolting is also included in the scope of the program as a preventive measure for managing cumulative fatigue damage for these fasteners. The program's bolting and torquing practices are based on industry guidelines, vendor recommendations, and VEGP operating experience, as appropriate for VEGP applications. Consistent with NUREG-1339 recommendations, the use of lubricants containing molybdenum disulfide, which has been specifically implicated in SCC of bolting, is prohibited by the program.
The program also includes periodic inspection of closure bolting assemblies to detect signs of leakage that may be indicative of loss of preload, loss of material, or cracking. Periodic inspection of bolted closures in conjunction with the Inservice Inspection Program and External Surfaces Monitoring Program will detect the effects of aging and joint leakage. Operator rounds and system walkdowns also identify joint leakage. 19.2.3 BORIC ACID CORROSION CONTROL PROGRAM The Boric Acid Corrosion Control Program monitors the condition of components on which borated water may leak to ensure that borated water leakage and associated boric acid residue are identified, evaluated, and removed before any loss of intended function of affected components. The program detects boric acid leakage by periodic visual inspection of systems containing borated water for evidence of leakage and by inspection of adjacent structures and components for evidence of leakage. The program was developed in response to the recommendations of Generic Letter 88-05 and addresses operating experience contained in recent NRC generic communications.
Prior to the period of extended operation, VEGP will enhance the Boric Acid Corrosion Control Program to address the effects of borated water leakage on materials other than steels, including electrical components (e.g., electrical connectors), that are susceptible to boric acid corrosion. 19.2.4 BURIED PIPING AND TANKS INSPECTION PROGRAM The Buried Piping and Tanks Inspection Program manages loss of material from the external surfaces of buried carbon steel, cast iron, and stainless steel components. The program includes both preventive measures and visual inspections. Preventive measures consist of coatings and wrappings which are required by design in accordance with industry standards.
Buried components in the scope of license renewal will be inspected when they are excavated for maintenance or when exposed for any other reason.
Prior to entering the period of extended operation, a review will be performed to determine if at least one opportunistic or focused inspection of buried piping and tanks has been performed within the 10-year period prior to the period of extended operation. If an inspection did not occur, a focused inspection will be performed prior to the period of extended operation.
In addition, a focused inspection of buried piping and tanks will be performed within 10 years after entering the period of extended operation, unless an engineering evaluation concludes that sufficient opportunistic and focused inspections have occurred during this time to demonstrate the ability of the underground coatings to protect the underground piping and tanks from degradation.
The Buried Piping and Tanks Inspection Program will be implemented prior to the period of extended operation.
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19.2-3 REV 16 10/10 19.2.5 CASS RCS FITTING EVALUATION PROGRAM The Cast Austenitic Stainless Steel (CASS) Reactor Coolant System (RCS) Fitting Evaluation Program manages the effects of loss of fracture toughness due to thermal aging for susceptible CASS components in the RCS. This program augments VEGP Inservice Inspection Program requirements.
This aging management program evaluates the su sceptibility of CASS components to thermal aging embrittlement based on casting method, molybdenum content, and percent ferrite.
Screening for susceptibility to thermal aging is not required for pump casings and valve bodies, based on the assessment documented in the letter dated May 19, 2000, from Christopher Grimes, Nuclear Regulatory Commission (NRC), to Douglas Walters, Nuclear Energy Institute (NEI), ADAMS Accession No. ML003717179. The existing ASME Section XI inspection requirements, including the alternative r equirements of ASME Code Case N-481 for pump casings, are adequate for all pump casings and valve bodies.
The program provides aging management through ei ther a flaw tolerance evaluation or enhanced volumetric examination. Additional inspection or evaluations to demonstrate that the material has adequate fracture toughness are not required for components that are not susceptible to thermal aging embrittlement.
Based on screening consistent with the process specified in NUREG-1801, Rev. 1,Section XI.M12, the VEGP components that require additional aging management under this program are the VEGP Unit 1 Loop 4 and Unit 2 Loop 1 RCP inlet elbows. For these two casings, loss of fracture toughness due to thermal aging will be managed by component-specific flaw tolerance evaluation, additional inspections, or a combination of these techniques.
The CASS RCS Fitting Evaluation Program will be implemented prior to the period of extended operation. 19.2.6 CLOSED COOLING WATER PROGRAM The Closed Cooling Water (CCW) Program manages loss of material, cracking, and reduction of heat transfer in closed-cycle cooling wa ter systems and the components cooled by these systems. The program is based on the EPRI CCW chemistry guidelines.
The program includes maintenance of corrosion inhibitor, pH buffering agent, and biocide concentrations. Concentrations of detrimental ionic species are monitored and reduced if necessary. Important diagnostic parameters are monitored and evaluated for significant trends.
The program also uses corrosion-monitoring activities including trending of iron and copper concentrations and component inspections. Corrosion rate monitoring methods may also be used. Prior to the period of extended operation, VEGP will enhance the CCW Program to indicate the components in each system that are most susceptible to various corrosion mechanisms and to ensure that corrosion monitoring is appropriately accomplished. This qualitative assessment will be based on an understanding of corrosion principles associated with CCW chemistries and on review of system, plant, and industry operating experience. Parameters considered in the review will include system flow parameters (f ocusing on identification of stagnant regions and on intermittently operated systems), normal oper ating temperatures, and component geometries (e.g., creviced areas).
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19.2-4 REV 16 10/10 19.2.7 DIESEL FUEL OIL PROGRAM The Diesel Fuel Oil Program is a plant-specific program that manages loss of material in the diesel fuel oil systems for the emergency diesel generators and the diesel engine-driven fire water pumps through monitoring and maintenance of diesel fuel oil quality. The program is based on VEGP Technical Specifications requirements and supplemental requirements.
Draining, cleaning, and internal condition inspections of diesel fuel oil components are implemented under other VEGP aging m anagement programs as noted below.
- Periodic cleaning and inspection of the interior of the EDG system's diesel fuel oil storage tanks is performed under the Periodic Surveillance and Preventive Maintenance Program.
- Visual inspection of the diesel engine-driven fire water pumps fuel supply lines for leakage during diesel operation is performed under the Fire Protection Program.
- The One-Time Inspection Program describes inspections to verify the effectiveness of the Diesel Fuel Oil Program. The inspections include thickness measurements of storage tank bottom surfaces to verify that significant degradation of the tank base material is not occurring. 19.2.8 EXTERNAL SURFACES MONITORING PROGRAM The External Surfaces Monitoring Program inspec ts external surfaces of mechanical system components requiring aging management for license r enewal in external air environments.
Surfaces constructed from materials susceptible to aging in these environments are inspected at frequencies that assure the effects of agi ng are managed such that system components will perform their intended function during the period of extended operation.
The program detects corrosion, flange leakage, missing or damaged insulation, damaged coatings, and indications of fretting or wear. Inspections of insulated surfaces are performed on a sampling basis, targeting areas identified by baseline inspections and operating experience as most susceptible. Accessible polymers and elastomers are also inspected. Systems and components which are normally inaccessible and therefore not readily available for inspection are inspected when they are made accessible during outages or routine maintenance or repair or they may be inspected by remote means. The External Surfaces Monitoring Program will be implemented prior to the period of extended operation.
SNC will perform an inspection of an emergency diesel generator fuel oil day tank vent line.
This inspection will determine whether a debris screen is installed on the open end of the vent line. If a screen is installed, the inspection will further determine the material of construction of the debris screen. 19.2.9 FIRE PROTECTION PROGRAM The Fire Protection Program includes inspections, performance testing, and condition monitoring of water- and gas-based fire protection systems, fire barriers, and fire pump diesels and their fuel oil supply components. The program manages fire protection components relied VEGP-FSAR-19
19.2-5 REV 16 10/10 upon for 10 CFR 50.48 compliance such that the intended functions will be maintained through the period of extended operation.
The water-based and gas-based fire suppression systems are tested and inspected in accordance with plant procedures based, in part, on the applicable National Fire Protection Association codes and standards. Periodic inspections, performance testing, and system monitoring provide an effective means to assure functionality of these components.
Diesel-driven fire pumps and fuel oil supply components are periodically inspected and tested to ensure that the diesels, pumps, and fuel oil supply components can perform their intended functions.
The fire barrier inspections include periodic visual inspection of structural fire barriers, including fire walls, floors, ceilings, fire penetration seals, and fire doors.
VEGP will implement the following enhancements to the Fire Protection Program:
- Wall thickness evaluations will be performed on water suppression piping systems using nonintrusive volumetric testing or visual inspections to ensure that wall thicknesses are within acceptable limits. Initial wall thickness evaluations will be performed before the end of the current operating term. Subsequent evaluations will be performed at plant-specific intervals during the period of extended operation. The plant-specific inspection intervals will be determined based on previous evaluations and site operating experience.
- A sample of sprinkler heads will be inspected using the guidance of NFPA 25 "Inspection, Testing and Maintenance of Water-Based Fire Protection Systems" (1998 Edition), Section 2-3.1.1 or NFPA 25 (2002 Edition), Section 5.3.1.1.1. Where sprinkler heads have been in service for 50 years, they will be replaced or representative samples from one or more sample areas will be submitted to a recognized testing laboratory for field service testing. This sampling will be performed every 10 years after the initial fiel d service testing. The 50 years of time in service begins when the system was plac ed in service, not when the plant became operational.
- Prior to the period of extended operation, Fire Protection Program procedures will be revised to provide more detailed instructions for visual inspection of fire pump diesel fuel supply lines for leakage, corrosion, and general degradation while the engine is running during fire suppression system pump tests. 19.2.10 FLOW-ACCELERATED CORROSION PROGRAM The Flow-Accelerated Corrosion (FAC) Program manages loss of material (wall thinning) due to FAC in susceptible plant piping and other components. The FAC Program is based on the guidance of NSAC-202L-R2, "Recommendations for an Effective Flow-Accelerated Corrosion Program," including subsequent revisions. The program includes analysis to determine susceptible locations, predictive modeling techniques, baseline inspections of wall thickness, followup inspections, and repair or replacement of degraded components as necessary.
VEGP also uses the FAC Program and its inspection techniques to manage wall thinning that is occurring in piping components downstream of t he steam generator blowdown demineralizers.
The wall thinning has been attributed to the acidic conditions of the demineralizer effluent, not FAC.
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19.2-6 REV 16 10/10 19.2.11 FLUX THIMBLE TUBE INSPECTION PROGRAM The Flux Thimble Tube Inspection Program manages loss of material due to fretting/wear of the incore flux detector thimble tubes. The program implements the VEGP response to NRC Bulletin No. 88-09, "Thimble Tube Thinning in Westinghouse Reactors." The program uses proven nondestructive examination techniques to monitor for wear of the flux thimble tubes.
Wear rate predictions determine the need for corrective actions such as repositioning, capping, or replacement of a flux thimble tube. The wear-rate predictions are also used to establish the interval to the next inspection.
Prior to the period of extended operation, a VEGP program procedure will be issued documenting the Flux Thimble Tube Inspecti on Program administration and implementing activities credited for license renewal. 19.2.12 GENERIC LETTER 89-13 PROGRAM The Generic Letter 89-13 Program includes the activities which implement the VEGP response to the NRC recommended actions contained in Generic Letter (GL) 89-13, "Service Water System Problems Affecting Safety-Related E quipment." The Generic Letter 89-13 Program activities include mitigation, as well as performance and condition monitoring techniques, to ensure that the effects of aging on the Nuclear Service Cooling Water (NSCW) system, and on those components supplied by t he NSCW system will be managed.
Prevention or mitigation of fouling and loss of material in the NSCW system and NSCW supplied components is accomplished, in part, by intermittent injection of appropriate water treatment chemicals. Other preventive and m onitoring aspects of the VEGP Generic Letter 89-13 Program include periodic flushing of lines to mitigate or prevent fouling, periodic measurement of flow rates through selected components, periodic analysis of corrosion coupons, and cleaning of selected heat exchangers at regular intervals. Some components are visually inspected for fouling or loss of material. Volumetric examination may be used to detect degradation.
Prior to the period of extended operation, VEGP will implement the following enhancements to the Generic Letter 89-13 Program:
- An overall program procedure will be prepared which describes the various program activities that comprise the Generic Letter 89-13 Program and their implementing controls such as chemistry procedures, maintenance activities, scheduled surveillances, or other mechanisms.
- The VEGP Generic Letter 89-13 Program activities will include inspection of the NSCW transfer pumps' casings and bolting and NSCW cooling tower spray nozzles. 19.2.13 INSERVICE INSPECTION PROGRAM The VEGP Inservice Inspection Program is a plant-specific program that mandates examinations, testing, and inspections of components and systems to detect deterioration and manage aging effects. The program uses periodic visual, surface, and volumetric examination and leakage tests of Class 1, 2, and 3 pressure-retaining components, their integral attachments, and supports to detect and characterize flaws.
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19.2-7 REV 16 10/10 The program is implemented in accordance with 10 CFR 50.55(a), which imposes the inservice inspection requirements of ASME Section XI for Class 1, 2, and 3 pressure-retaining components, their integral attachments, and supports. Inspection, repair, and replacement of these components are covered in Subsections IWB, IWC, IWD, and IWF, respectively.
In conformance with 10 CFR 50.55a(g)(4)(ii), and as based on ASME Inservice Inspection Program B (IWA-2432), the VEGP Inservice Inspection Program is updated at the end of each inspection interval to the latest edition and addenda of the Code specified in 10 CFR 50.55a, 12 months before the start of the inspection interval. 19.2.14 NICKEL ALLOY MANAGEMENT PROGRAM FOR NONREACTOR VESSEL CLOSURE HEAD PENETRATION LOCATIONS The Nickel Alloy Management Program for Nonreactor Vessel Closure Head Penetration Locations is a plant-specific program that manages cracking due to primary water stress corrosion cracking (PWSCC) for nonreactor vessel head nickel alloy component locations. The overall goal of the program is to maintain plant safety and minimize the impact of PWSCC on plant availability through assessment, inspection, mitigation, and repair or replacement of susceptible components. Program development is based on MRP-126, "Generic Guidance for Alloy 600 Management."
The program is based on the following set of implementation commitments: 1. SNC will continue to participate in industry initiatives directed at resolving PWSCC issues, such as owners' group programs and the EPRI Materials Reliability Program. 2. SNC will comply with applicable NRC orders. 3. SNC will submit a program inspection plan for VEGP that includes implementation of applicable NRC bulletins, generic letters, and staff-accepted industry guidance. The inspection plan will be submitted to the staff for review and approval not less than 24 months prior to entering the period of extended operation for VEGP Units 1 and 2.
The inspection plan will include assessments of each of the 10 aging management program elements defined in Section A.1.2.3 of NUREG-1800, Revision 1.
Nickel Alloy Management Program for Nonreactor Vessel Closure Head Penetration Locations will be fully implemented prior to the period of extended operation. 19.2.15 NICKEL ALLOY MANAGEMENT PROGRAM FOR REACTOR VESSEL CLOSURE HEAD PENETRATIONS The Nickel Alloy Management Program for Reactor Vessel Closure Head Penetrations addresses industry concerns regarding the potential for PWSCC in nickel alloy components exposed to the reactor coolant environment.
The program is based upon the requirements of NRC First Revised Order EA-03-009, which establishes requirements for susceptibility ranking and inspections. Susceptibility ranking is based on calculated effective degradation years and the results of previous inspection findings. Inspection frequencies are determined by the susceptibility category. Inspections to detect cracking include bare metal visual examinations and nonvisual techniques.
The program implements commitments for reactor vessel closure head penetrations associated with nickel alloys from NRC orders, bulletins, and generic letters and staff-accepted industry guidelines.
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19.2-8 REV 16 10/10 19.2.16 OIL ANALYSIS PROGRAM The VEGP Oil Analysis Program ensures that the lubricating oil and hydraulic fluid environments of in-scope mechanical systems are maintained to the required quality. The Oil Analysis Program maintains lubricating oil and hy draulic fluid system contaminants (primarily water and particulates) within acceptable limits, thereby preserving an environment that is not conducive to deleterious aging effects. Program activities include sampling and analysis of lubricating oil and hydraulic fluid for detrimental contaminants.
The One-Time Inspection Program includes inspections planned to verify the effectiveness of the Oil Analysis Program.
Prior to the period of extended operation, VEGP will implement the following enhancements to the Oil Analysis Program:
- An overall program procedure or guideline will be prepared to formalize the sampling and analysis activities performed.
- Viscosity, relative level of oxidation, and flashpoint of lubricating oil samples will be determined for components where the lubricating oil is changed based on its analyzed condition (instead of being changed on a regular schedule regardless of condition). The relative level of oxidation of the lubricating oil will be monitored by analysis of the neutralization number or other appropriate parameters(s). Flashpoint monitoring will be performed for those components which have the potential for contamination of the lubricating oil with a light hydrocarbon such as fuel oil.
- When a lubricating oil sample's wear metal content screening results exceed the limits established for the wear metal content screening, the lubricating oil from that component will be subjected to additional testing. The additional testing may include detailed particle counting, elemental analysis, or analytical ferrography as necessary to validate the initial screening results and to diagnose the source of the particulates. 19.2.17 ONE-TIME INSPECTION PROGRAM The VEGP One-Time Inspection Program provides objective evidence that an aging effect is not occurring, or that the aging effect is occurring slowly enough to not affect the component or structure intended function during the period of extended operation, and therefore will not require additional aging management.
The program uses one-time inspections of plant piping and components to verify the effectiveness of aging management programs or to confirm the insignificance of potential aging effects where: a. An aging effect is not expected to occur but there is insufficient data to rule it out with reasonable confidence, b. An aging effect is expected to progress very slowly in a specified environment, but localized conditions may be more adverse than specified, or c. The characteristics of the aging effect include a long incubation period relative to the operating life of the plant.
The inspections will be performed within a window of 10 years immediately preceding the period of extended operation.
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19.2-9 REV 16 10/10 The inspections will include a baseline and a followup inspection of the effectiveness of the BoralŽ neutron-absorbing panels credited in the criticality analysis for the Unit 1 spent fuel storage racks to provide reasonable assurance that the panels will continue to perform their reactivity control function during the period of extended operation. The baseline inspection will be performed within a window of 10 years immediately preceding the period of extended operation. The followup inspection will be performed at a date to be determined based on the results of the baseline inspection and relevant industry guidance, not to exceed 10 years after the baseline inspection. 19.2.18 ONE-TIME INSPECTION PROGRAM FOR ASME CLASS 1 SMALL BORE PIPING The VEGP One-Time Inspection Program for ASME Class 1 Small Bore Piping addresses NRC concerns on the potential for cracking of Class 1 piping with a diameter less than NPS 4.
To address SCC concerns, volumetric examination of a sample population of ASME Class 1 Piping butt welds less than NPS 4 will be performed. Examination locations will be selected using a risk-based approach that will consider susceptibility, inspectability, dose, and operating experience.
To address unanticipated thermal fatigue cracking of ASME Class 1 piping less than NPS 4, VEGP will screen and evaluate pipe lines using MRP-146, "Management of Thermal Fatigue in Normally Stagnant Nonisolable Reactor Cool ant System Branch Lines," or later updated guidance. Small bore piping inspections will be performed to detect thermal fatigue only at piping locations that fail screening and are not monitored for thermal cycling.
Examinations performed by the program may be incorporated into an NRC-approved Risk-Informed Inservice Inspection Program. The inspections will be performed within a window of 10 years immediately preceding the period of extended operation. 19.2.19 ONE-TIME INSPECTION PROGRAM FOR SELECTIVE LEACHING The VEGP One-Time Inspection Program for Selective Leaching addresses selective leaching in susceptible cast iron and copper alloy components. The program includes a one-time examination of a sample population of components most likely to exhibit selective leaching.
Initial examinations will be completed prior to entering the period of extended operation. If degradation due to selective leaching is identifi ed, additional examinations will be performed.
Examination techniques may include hardness m easurement (where feasible-based on form and configuration), visual examination, metallurgical evaluation, or other proven techniques determined to be effective in identifying and assessing the extent of selective leaching.
The inspections will be performed within a window of 10 years immediately preceding the period of extended operation. 19.2.20 OVERHEAD AND REFUELING CRANE INSPECTION PROGRAM The VEGP Overhead and Refueling Crane Inspection Program manages the effects of general corrosion and wear of the crane bridge and trolley structural girders and beams and the crane rails and support girders in the scope of license renewal.
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19.2-10 REV 16 10/10 The Overhead and Refueling Crane Inspection Program is a condition monitoring program that includes the following nuclear safety-related and quality-related material handling systems:
refueling machine, fuel handling machine bridge crane, spent fuel cask bridge crane, and the containment building (reactor) polar crane.
Prior to the period of extended operation, VEGP will enhance applicable plant procedures to explicitly identify inspection of crane rails and crane structural components for loss of material due to corrosion and wear and for indication of rail misalignment. 19.2.21 PERIODIC SURVEILLANCE AND PREVENTIVE MAINTENANCE ACTIVITIES The Periodic Surveillance and Preventive Maintenance Activities is a plant-specific program that includes existing and new periodic inspections and tests that are relied on by license renewal to manage the aging effects applicable to the components included in the program. The Periodic Surveillance and Preventive Maintenance Activiti es Program is generally implemented through repetitive tasks and surveillances.
Inspection and testing intervals are dependent on the component, material, and environment and take into consideration industry and plant-specific operating experience and manufacturer's recommendations.
The extent and schedule of inspections and testing assure detection of component degradation prior to loss of intended functions. Established techniques such as visual inspections are used.
The following existing surveillance and maintenance activities are credited for license renewal:
- Control building control room filter unit seal inspections.
- Emergency diesel generator (EDG) diesel fuel oil storage tank cleaning and inspections.
- Steam generator blowdown trim heat exchanger inspections.
- NSCW cooling tower fill and drift eliminator testing.
- Diaphragm inspections for the boric acid storage tank, condensate storage tank, and reactor makeup water storage tank.
Prior to the period of extended operation, VEGP will enhance the Periodic Surveillance and Preventive Maintenance Activities to include the following additional surveillance and maintenance activities:
- Steam generator blowdown secondary sample bath shell inspections.
- Steam generator blowdown corrosion product monitor cooler shell inspections.
- Potable water system water heater housing inspections (for the in-scope water heaters). 19.2.22 PIPING AND DUCT INTERNAL INSPECTION PROGRAM The VEGP Piping and Duct Internal Inspection Program manages corrosion of steel, stainless steel, and copper alloy components and degradation of elastomer components due to changes VEGP-FSAR-19
19.2-11 REV 16 10/10 in material properties. Inspections are normally performed concurrent with scheduled preventive maintenance, surveillance testing, and corrective maintenance activities. Specific examinations not coordinated with existing wo rk activities may also be performed at the discretion of the program owner. Inspection locations and intervals are dependent on assessments of the likelihood of significant degradation and on current industry and plant-specific operating experiences.
Examination techniques will be appropriate to detect and assess the aging mechanism of concern and may include visual examination, nonvisual NDE such as ultrasonic testing or radiography, physical manipulation of elastomers, etc.
The Piping and Duct Internal Inspection Program will be implemented prior to the period of extended operation. 19.2.23 REACTOR VESSEL CLOSURE HEAD STUD PROGRAM The VEGP Reactor Vessel Closure Head Stud Program provides direction for loss of material and cracking in the reactor vessel closure head studs, nuts, and washers. Program aspects include preventive measures, as described in Regulatory Guide 1.65, and condition monitoring. Preventive measures include material controls and the use of approved lubricants. The VEGP reactor vessel head studs are fabricated from modified SA-540 Grade B24 material as specified in ASME Boiler and Pressure Vessel Code case 1605. This Code case is not specified in Regulatory Guide 1.65 but has been approved by the NRC via Regulatory Guide 1.85. VEGP actual stud material properties have ultimate tensile strengths less than 170 ksi. Reactor vessel closure head studs and nuts are lubricated with an approved, stable lubricant at each reassembly.
Condition monitoring includes examination and leakage detection consistent with the VEGP Inservice Inspection Program. 19.2.24 REACTOR VESSEL INTERNALS PROGRAM The Reactor Vessel Internals Program is a plant-specific program that addresses material degradation issues for the VEGP reactor vessel internals.
The program will be based on the following set of implementation commitments: a. SNC will participate in the industry program for investigating and managing aging effects on reactor vessel internals. b. SNC will evaluate and implement the results of the industry programs, such as the EPRI Material Reliability Program (MRP), as applicable to the VEGP reactor vessel internals. c. SNC will submit an inspection plan for the VEGP reactor vessel internals to the NRC for review and approval not less than 24 months before entering the period of extended operation for VEGP Units 1 and 2. This inspection plan will address the bases, inspection methods, and acceptance criteria associated with aging management of the reactor vessel thermal sleeves and the core support lugs (along with the associated support pads and attachment welds).
The Reactor Vessel Internals Program will be implemented prior to the period of extended operation.
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19.2-12 REV 16 10/10 19.2.25 REACTOR VESSEL SURVEILLANCE PROGRAM The Reactor Vessel Surveillance Program manages loss of fracture toughness due to neutron embrittlement in reactor vessel alloy steel materials exposed to neutron fluence exceeding 1 x 10 17 n/cm 2 (E > 1.0 MeV). The program is based on 10 CFR 50, Appendix H, "Reactor Vessel Material Surveillance Requirements," and ASTM E 185-82, "Standard Practice for Conducting Surveillance Tests for Light-Water Cooled Nuclear Power Reactor Vessels."
Capsules are periodically removed during the course of plant operating life. Neutron embrittlement is evaluated through surveill ance capsule testing and evaluation, fluence calculations and benchmarking, and monitoring of effective full power years (EFPYs).
For both the VEGP Unit 1 and 2 reactor vessels, capsules with accumulated neutron fluence equivalent to 60 years of operation have already been pulled and tested. The remaining capsules (2 capsules in each unit) will be removed such that, at the time of removal, each of the remaining capsules will have accumulated neutron fluence that is not less than once, nor greater than twice, the peak end of life fluence expected for an additional 20-year license renewal term (80 years of operation).
The Reactor Vessel Surveillance Program will be enhanced as follows: 1. Prior to removal of the last surveillance capsule in each unit, program documents will be revised to require that tested and untested specimens from all capsules removed from the VEGP reactor vessels remain in storage. 2. Alternate dosimetry will be installed to monitor neutron fluence on the reactor vessel after removal of the last surveillance capsule in that unit. This enhancement will be implemented prior to removal of the last surveillance capsule in each unit. 19.2.26 STEAM GENERATOR TUBING INTEGRITY PROGRAM The Steam Generator Tubing Integrity Program is a subprogram of the Steam Generator Program, which is an integrated program for managing the condition of the VEGP steam generators. The program focuses on steam generator tube integrity, tube planning, and the management and repair of steam generator tubing.
The Steam Generator Program is in compliance with the program described in NEI 97-06, Steam Generator Program Guidelines, and VEGP Technical Specifications, subsection 5.5.9. Program deviations from NEI 97-06 are prepared and approved in accordance with NE I 97-06 and EPRI steam generator management program guidance.
The program includes a balance of prevention, inspection, evaluation and repair, and leakage monitoring. Major program elements include degradation assessments, inspection, integrity assessments, leakage monitoring, and chemistry controls. 19.2.27 STEAM GENERATOR PROGRAM FOR UPPER INTERNALS The Steam Generator Program for Upper Internal s is a plant-specific subprogram of the VEGP Steam Generator Program, which is an integr ated program for managing the condition of the steam generators. The Steam Generator Program is in compliance with the program described in NEI 97-06, Steam Generator Program Guidelines.
The Steam Generator Program for Upper Inter nals includes VEGP Steam Generator Program activities associated with aging management of the steam generator upper internals components determined to be within the scope of license renewal. The program implements VEGP-FSAR-19
19.2-13 REV 16 10/10 inspection activities intended to detect degradation of secondary side internals needed to maintain tubing integrity and accomplish steam generator intended functions. An assessment based upon steam generator design, potential degradation mechanisms, and related VEGP and industry operating experience is performed to establish inspection requirements for secondary side internals components. The resulting inspection requirements are incorporated into the steam generator inspection plans. 19.2.28 WATER CHEMISTRY CONTROL PROGRAM The VEGP Water Chemistry Control Program mitigates loss of material, cracking, and reduction of heat transfer in system components and structures through the control of water chemistry.
The program includes control of detrimental chemical species and the addition of chemical agents. The VEGP Water Chemistry Control Program is based on the EPRI water chemistry guidelines for primary and secondary water chemistry control.
The One-Time Inspection Program includes inspections to verify the effectiveness of the Water Chemistry Control Program.
VEGP will monitor spent fuel pool aluminum concentrations to ensure the Boral spent fuel racks will continue to perform their intended function during the period of extended operation. If adverse trends are identified, SNC will implem ent corrective actions. Additionally, SNC will monitor industry experience related to Boral and will take appropriate actions if significant degradation of Boral is identified. 19.2.29 10 CFR 50 APPENDIX J PROGRAM The 10 CFR 50 Appendix J Program monitors leakage rates through the containment pressure boundary, including penetrations and access openings. Containment leak rate tests assure that leakage through the primary containment and systems and components penetrating primary containment does not exceed the allowable leakage limits specified within the VEGP Technical Specifications. Corrective actions are taken if leakage rates exceed established administrative limits for individual penetrations or the overall containment pressure boundary. 19.2.30 INSERVICE INSPECTION PROGRAM - IWE The VEGP Inservice Inspection Program - IWE is a plant-specific program implemented in accordance with 10 CFR 50.55(a), which imposes the inservice inspection requirements of ASME Section XI, Subsection IWE. The program manages aging effects for the containment liners and its integral attachments including connecting penetrations and parts forming the leaktight boundary. The primary inspection method for the program is periodic visual examination along with limited volumetric ex aminations utilizing ultrasonic thickness measurements as needed.
In conformance with 10 CFR 50.55a(g)(4)(ii) and as based on ASME Inservice Inspection Program B (IWA-2432), the VEGP Inservice Inspection Program - IWE is updated at the end of each 120-month inspection interval to the latest edition and addenda of the Code specified in 10 CFR 50.55a, 12 months before the start of the inspection interval.
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19.2-14 REV 16 10/10 Prior to the period of extended operation, the VEGP Inservice Inspection Program - IWE will be revised to provide more explicit direction to the registered professional engineer for trending and evaluating conditions identified during visual examinations. 19.2.31 INSERVICE INSPECTION PROGRAM - IWL The VEGP Inservice Inspection Program - IWL is a plant-specific program implemented in accordance with 10 CFR 50.55(a), which imposes the inservice inspection requirements of ASME Section XI Subsection IWL for Class CC components. The program manages the reinforced concrete and unbonded post-tensioning systems of the containment structures.
In conformance with 10 CFR 50.55a(g)(4)(ii) and as based on ASME Inservice Inspection Program B (IWA-2432), the VEGP Inservice Inspection Program - IWL is updated at the end of each 120-month inspection interval to the latest edition and addenda of the Code specified in 10 CFR 50.55a, 12 months before the start of the inspection interval.
Prior to the period of extended operation, the VEGP Inservice Inspection Program - IWL will be revised to provide more explicit direction to the registered professional engineer for trending and evaluating conditions identified during concrete visual examinations. 19.2.32 STRUCTURAL MONITORING PROGRAM The VEGP Structural Monitoring Program is based on the requirements and guidance set forth in 10 CFR 50.65, "Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," and Regulatory Guide 1.160, Rev. 2, "Monitoring the Effectiveness of Maintenance at Nuclear Power Plants." VEGP uses the Structural Monitoring Program to monitor the condition of structures and structural components within the scope of the Maintenance Rule, thereby providing reasonable assurance that there is no loss of structure or structural component intended function.
Prior to the period of extended operation, VEGP will implement the following enhancements to the Structural Monitoring Program:
- The scope of the Structural Monitoring Program will be expanded to include the additional structures that require monitoring for license renewal.
- The scope of inspection for structures that require monitoring for license renewal will be clarified. An area-based inspection will be performed unless a detailed inspection scope is provided.
- The Structural Monitoring Program scope for hangers and supports will be clarified.
- Program requirements will be revised to include periodic groundwater monitoring to confirm that groundwater chemistry remains nonaggressive as defined in NUREG 1801.
- Underwater inspection of the NSCW cooling tower basins, including appropriate inspection and acceptance criteria, will be added to the Structural Monitoring Program.
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19.2-15 REV 16 10/10
- Guidance will be given regarding proper documentation of condition adverse to quality and its probable causes for any CR written against a finding during Structural Monitoring Program walkdown.
- For any finding (e.g., crack, leakage, etc.) guidance will be given for data to be collected and evaluated.
- More explicit direction will be given for trending of the problems. 19.2.33 STRUCTURAL MONITORING PROGRAM - MASONRY WALLS The Structural Monitoring Program - Masonry Walls is part of the VEGP Structural Monitoring Program that implements structures monitoring requirements as specified by 10 CFR 50.65.
The Masonry Wall Program manages aging of masonry walls, and structural steel restraint systems of the masonry walls, within scope of license renewal. The program includes the concrete masonry units and restraint systems used to seal and provide radiation shielding of some access openings in the Seismic Category I structures.
The program contains inspection guidelines and lis ts attributes that cause aging of masonry walls, which are to be monitored during structural monitoring inspections, as well as establishes examination criteria, evaluation requirements, and acceptance criteria.
The Structural Monitoring Program - Masonry Walls will be enhanced prior to the period of extended operation to include monitoring of masonry walls in the structures which are in scope for license renewal but are not currently monitored under the program. 19.2.34 NON-EQ CABLES AND CONNECTIONS PROGRAM The Non-EQ Cables and Connections Program will be used to maintain the function of electrical cables and connections, which are not subject to the environmental qualification requirements of 10 CFR 50.49, but are exposed to adverse lo calized environments caused by heat, radiation, or moisture. An adverse localized environment is an environment that is significantly more severe than the service condition for the insulated cable or connection.
A representative sample of accessible insulated cables and connections within the scope of license renewal will be visually inspected for cable and connection jacket surface anomalies such as embrittlement, discoloration, and cracking. The technical basis for the sample selections of cables and connections to be inspected is provided. The scope of this sampling program includes electrical cables and c onnections in adverse localized environments.
The Non-EQ Cables and Connections Program will be implemented and the first inspection completed prior to the period of extended operation. 19.2.35 NON-EQ INACCESSIBLE MEDIUM-VOLTAGE CABLES PROGRAM The Non-EQ Inaccessible Medium-Voltage Cabl es Program manages the aging effects for inaccessible medium-voltage cables (cables with operating voltage from 2 kV to 35 kV) in the scope of license renewal exposed to significant moisture and voltage. The aging effect of concern is "localized damage and breakdown of insulation." The program includes periodic inspection and removal of water accumulation in cable manholes and periodic cable testing.
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19.2-16 REV 16 10/10 Manholes which retain water and contain medium-voltage cables in the scope of license renewal are periodically inspected for water collection and the accumulated water removed, as needed. The frequency of inspection is based on actual plant-experience but at least once every 2 years.
In-scope medium-voltage cables exposed to significant moisture and voltage are tested at least once every 10 years to provide an indication of the condition of the conductor insulation. The specific test performed is a proven test for detecting deterioration of the insulation system due to wetting. The Non-EQ Inaccessible Medium-Voltage Cables Program will be implemented and the first inspections completed prior to the period of extended operation. 19.2.36 NON-EQ ELECTRICAL CABLE CONNECTIONS ONE-TIME INSPECTION PROGRAM The Non-EQ Cable Connections One-Time Inspecti on Program is a plant-specific program that performs one-time inspections on a sample of bolted connections in the scope of license renewal to confirm that loosening of electrical connections is not an aging effect requiring additional aging management during the period of extended operation. The program inspects for loosening of bolted connections due to thermal cycling, ohmic heating, electrical transients, vibration, chemical contamination, corrosion, and oxidation.
The factors considered for sample selection are application (medium and low voltage, defined as < 35 kV), circuit loading (high loading), and location (high temperature, high humidity, vibration, etc.). The technical basis for the sample selections will be documented. Inspection methods may include thermography, contact resistance testing, or appropriate methods including visual inspection based on plant configuration and industry guidance.
The inspections will be performed within a window of 10 years immediately preceding the period of extended operation.
19.2.37 REFERENCES 1. NUREG-1800, Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants, U. S. Nuclear Regulatory Commission, (Rev. 1), September 2005. 2. NUREG-1801, Generic Aging Lessons Learned (GALL) Report, U. S. Nuclear Regulatory Commission, (Rev. 1), September 2005. 3. Vogtle Electric Generating Plant Technical Specifications, Units 1 and 2.
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19.3-1 REV 16 10/10 19.3 AGING MANAGEMENT PROGRAMS - TIME LIMITED AGING ANALYSES (TLAA) 19.3.1 ENVIRONMENTAL QUALIFICATION PROGRAM The Environmental Qualification (EQ) Program implements the requirements of 10 CFR 50.49.
The EQ Program has been established to demonstrate that certain electrical components located in harsh plant environments are qualified to perform their safety functions in those harsh environments, consistent with 10 CFR 50.
49 requirements. The EQ Program manages component thermal, radiation, and cyclical aging, as applicable, through the use of aging evaluations. The program requires action be taken before individual components in the scope of the program exceed their qualified life. Actions taken include replacement on a specified time interval of piece parts or complete components to maintain qualification and reanalysis.
As required by 10 CFR 50.49, EQ components not qualified for the current license term are to be refurbished, replaced, or have their qualification extended prior to reaching the aging limits established in the evaluation. Some aging evaluations for EQ components specify a qualification of at least 40 years and are considered TLAAs for license renewal. The EQ Program ensures that these EQ components are maintained within the bounds of their qualification bases. 19.3.2 FATIGUE MONITORING PROGRAM The VEGP Fatigue Monitoring Program consists of two existing programs, which are the Fatigue and Cycle Monitoring Program and Thermal Stratification Data Collection. The Fatigue and Cycle Monitoring Program, also known as t he VEGP Component or Cyclic Transient Limit Program (CCTLP), is described in subsection 5.5.5 of the Technical Specifications. This program provides controls to track the tr ansient cycles to ensure that components are maintained within the design limit. The component cyclic or transient limits are provided in VEGP UFSAR paragraph 3.9.N.1. The Thermal Stratification Data Collection Program monitors for adverse thermal stratification and cycling resulting from isolation valve leakage in the normally stagnant nonisolable reactor coolant system (RCS) branch lines identified in the VEGP response to IEB 88-08. The VEGP Fatigue Monitoring Program uses a combination of cycle counting, cycle-based fatigue monitoring, and stress-based fatigue monitoring to monitor and track fatigue usage. At least 2 years prior to the period of extended operation, the Fatigue Monitoring Program will be enhanced as follows: 1. Implementing documents will be revised to address the effect of the full structural weld overlays applied to the pressurizer spray and surge nozzles on the stress-based module calculation of cumulative usage factor (CUF). 2. The VEGP UFSAR will be revised to require fatigue monitoring of the accumulator/reactor heat removal (RHR) nozzles and pressurizer heater penetrations. 3. Implementing documents will be revised to reduce acceptable CUF values to account for environmental fatigue effects for those NUREG-6260 locations monitored for fatigue.
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19.3-2 REV 16 10/10 4. Implementing documents will be revised to explicitly require that the corrective actions initiated for exceeding an acceptance criterion include a review to identify and assess any additional affected reactor coolant pressure boundary locations. 5. SNC will revise the FatiguePro software to calculate a minimum projected value of 1 for any events that may potentially occur. 6. SNC will revise the FatiguePro initial CUF values for the Unit 1 and Unit 2 hot leg surge nozzles, pressurizer surge nozzles, and pressurizer heater penetrations to double the current values and recalculate the current and projected CUFs. 7. SNC will implement a fatigue management software program that uses six stress components in the stress-based fatigue calculation. The software will be appropriately benchmarked against an ASME NB-3200 fatigue analysis, and the stress-based fatigue monitoring locations will be modeled with the as-built configuration. The new software will be used to reproject 60-year CUF values for the monitored locations. When those locations were evaluated for environmental effects on fatigue, the new software will also be used to demonstrate that the environmental effects on fatigue will be adequately managed for those locations during the period of extended operation.
19.
3.3 REFERENCES
- 1. NUREG-1800, Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants, U. S. Nuclear Regulatory Commission (Rev. 1), September 2005. 2. NUREG-1801, Generic Aging Lessons Learned (GALL) Report, U. S. Nuclear Regulatory Commission (Rev. 1), September 2005. 3. Vogtle Electric Generating Plant Technical Specifications, Units 1 and 2.
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19.4-1 REV 16 10/10 19.4 EVALUATION OF TIME LIMITED AGING ANALYSES (TLAA)
In accordance with 10 CFR 54.21(c), an application for a renewed operating license must include evaluation of TLAAs for the period of extended operation. This section summarizes the TLAAs identified for VEGP license renewal. 19.4.1 REACTOR VESSEL NEUTRON EMBRITTLEMENT ANALYSES Analyses associated with embrittlement of reactor vessel materials due to neutron irradiation are TLAAs. The end-of-life (EOL) bases for these analyses are selected to bound the projected effective full-power years (EFPY) for an operating term of 60 years.
The following VEGP analyses are TLAAs that address the effects of neutron embrittlement on the VEGP reactor vessels:
- Neutron fluence.
- Upper-Shelf Energy (USE).
- Pressurized Thermal Shock (PTS).
- Adjusted Reference Temperature (ART).
- Pressure-Temperature (P-T) limits. 19.4.1.1 Neutron Fluence Calculation The VEGP reactor vessel neutron fluence calculations were projected out to EOL for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(ii). The reactor vessel neutron fluences, including extended beltline materials, were calculated using a method satisfying the requirements set forth in Regulatory Guide 1.90, "Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence," Revision 0 (March 2001). These projections are used in the USE, PTS, ART, and P-T analyses described in the sections that follow. 19.4.1.2 Upper-Shelf Energy (USE) Calculation Charpy impact test upper-shelf absorbed energy (USE) of no less than 50 ft-lbs throughout the life of the reactor vessel, unless an approved analysis supports a lower value.
The VEGP analyses have been projected to the end of the period of extended operation for the reactor vessel materials (base materials and welds) with projected fluence exceeding 1 x 10 17 n/cm 2 (MeV > 1.0). All Unit 1 and Unit 2 base materials and welds have a USE value at EOL of greater than 50 ft-lbs, which meets the acceptance criteria of 10 CFR 50, Appendix G.
Therefore, these TLAAs have been shown to be acceptable for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(ii).
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19.4-2 REV 16 10/10 19.4.1.3 Pressurized Thermal Shock (PTS) Calculation The requirements of 10 CFR 50.61 provide for protection against PTS events in pressurized water reactors. The screening criterion in 10 CFR 50.61 is 270°F for plates, forgings, and axial welds and 300
°F for circumferential welds. According to this regulation, if the calculated RT PTS for the reactor beltline materials is less than the specified screening criterion, then the vessel is acceptable with regard to the risk of vessel failure during postulated pressurized thermal shock transients.
The RT PTS calculations for VEGP Units 1 and 2 have been projected to the end of the period of extended operation for all reactor vessel materials (base materials and welds) with projected fluence exceeding 1 x 10 17 n/cm 2 (MeV > 1.0). All Unit 1 and Unit 2 base materials and welds meet the screening criteria contained in 10 CFR 50.61 at EOL. Therefore, these TLAAs have been shown to be acceptable for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(ii). 19.4.1.4 Adjusted Reference Temperature (ART) Calculation The ART values are an input to the pressure-temperature (P-T) limit curves discussed in the following section. The calculations determining the ART for the critical locations of the reactor vessel meet the definition of the TLAA pursuant to the criteria of 10 CFR 54.3. These ART calculations have been projected through the end of the period of extended operation and the results demonstrate the beltline materials remain limiting, and the projected ART values permit adequate operating margins to P-T limits through the period of extended operation. Therefore, these TLAAs have been shown to be acceptable for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(ii). 19.4.1.5 Pressure-Temperature (P-T) Limits Calculation Appendix G of 10 CFR Part 50 requires heatup and cooldown of the reactor pressure vessel be accomplished within established pressure and temperature limits. Plant-specific calculations establish these limits. The calculations utilize materials and fluence data obtained through plant-specific reactor surveillance capsule programs. The calculations for VEGP Units 1 and 2 meet the definition of a TLAA.
As described in the Pressure Temperature Limits Report (PTLR), the Reactor Vessel Surveillance Program updates the P-T limit curves considering the data gained from examination of surveillance specimens from capsules that SNC pulls. The content and update of the PTLR is in accordance with the requirements of subsection 5.6.6 of the VEGP Technical Specifications. When the operating conditions of each unit merit the use of a difference curve, the PTLR for that unit is updated to include P-T limit curves that bound the current level of neutron embrittlement (i.e., EFPY) for the unit. Therefore, this TLAA demonstration is made in accordance with 10 CFR 54.21(c)(1)(ii) and (iii).
The VEGP PTLR (for each unit) will be updated to address neutron embrittlement for the 60-year operating life prior to the unit entering the period of extended operation. 19.4.2 METAL FATIGUE ANALYSIS The thermal fatigue analyses of the VEGP mechanical components have been identified as TLAAs.
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19.4-3 REV 16 10/10 19.4.2.1 ASME Section III, Class 1 Component Fatigue Analysis The VEGP design incorporates the requirements of Section III Class 1 of the ASME Code, which requires a discrete analysis of the thermal, mechanical, and dynamic stress cycles on components that make up the reactor coolant pressure boundary. Although original design specifications commonly state that the transient conditions are for a 40-year design life, the fatigue analyses themselves are based on specified numbers of design transients, rather than on a specific operating life. Operating exper ience at VEGP and similar units has demonstrated that the analyzed numbers of design basis transients are, in general, conservative for a 40-year life. The Fatigue Monitoring Program monitors and tracks the transient cycles.
To address the additional operating term, the VEGP design transient cycles were projected through the period of extended operation. For the feedwater cycling, loss of charging flow, and loss of letdown and return to service transients, VEGP relies on cumulative usage factor (CUF) monitoring of the limiting component locations in lieu of cycle counting. Therefore, the CUFs were projected for these limiting locations in lieu of projecting their transient cycles. These limiting component locations are the steam gener ator main and auxiliary feedwater nozzles and the normal and alternate charging nozzles. The results of the cycles and CUF projections show that the original transient cycles were conservative and that the design fatigue analyses for Class 1 components and piping remain valid for 60 years.
In addition to the original design transients, fatigue loading transients and issues have been subsequently identified that are not part of the original fatigue analyses. For the pressurizer lower head and surge line, thermal stratification and insurge/outsurge transients are evaluated (IEB 88-11). Also, the impact of the reactor coolant system environment on the fatigue life of piping and components (GSI-190) requires specific evaluation for license renewal.
To address NRC IEB 88-11, the impact of thermal stratification on the fatigue usage in the surge line was evaluated for VEGP. The original evaluation showed that the surge line fatigue usage was acceptable for 40 years of operation, including the effects of thermal stratification due to insurge and outsurges from the pressurizer. For license renewal, stress-based fatigue monitoring is credited for managing the CUF of the surge line, including the effects of pressurizer insurge/outsurge and thermal stratification in both the pressurizer lower head and both surge line nozzles.
Generic Safety Issue (GSI) 190 addresses fatigue life of metal components and was closed by the NRC in December 1999. In the closure letter, however, the NRC concluded that licensees should address the effects of reactor coolant environment on the fatigue life of selected components as aging management programs are fo rmulated in support of license renewal.
The effects of reactor coolant environment on component fatigue life for locations equivalent to those in Section 5.4 of NUREG/CR-6260 for the newer vintage Westinghouse plants have been evaluated for VEGP using the formulas from NUREG/CR-5704 for stainless steel components and from NUREG/CR-6583 for carbon and low-alloy steel components.
For the following locations, the application of the appropriate environmental factors to the design CUF values that were calculated based on the VEGP set of original design transients yielded acceptable results (e.g., CUF < 1.0):
- Reactor vessel shell and lower head.
- Reactor vessel inlet and outlet nozzles.
For the following locations, the application of the appropriate environmental factors to the CUF values that were calculated based on the VEGP set of original design transients yielded VEGP-FSAR-19
19.4-4 REV 16 10/10 unacceptable results without additional m anagement. VEGP manages the environmentally adjusted fatigue CUF values for these locations using fatigue monitoring implemented by the Fatigue Monitoring Program:
- Surge line hot leg nozzle.
- Pressurizer heater penetrations.
- Pressurizer surge line nozzles.
- Charging nozzles.
- Safety injection nozzles.
- Accumulator / RHR nozzles.
NRC Branch Technical Position MEB 3-1 is the basis for the VEGP criteria for the postulation of high-energy line breaks (HELBs) with the exception of lines that have eliminated postulated breaks based on leak-before-break analysis. One of the criteria in MEB 3-1 for Class 1 piping is postulating pipe breaks at any intermediate locations where the CUF exceeds 0.1. The NRC staff has determined that this analysis qualifies as a TLAA.
The existing VEGP HELB analyses have been shown to remain valid for the period of extended operation as long as the Fatigue Monitoring Program maintains the CUF of the charging nozzles less than or equal to 1.0. Therefore, this TLAA has been demonstrated to be acceptable for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(i) and 10 CFR 54.21(c)(1)(iii).
Full structural weld overlays (FSWOL) have been installed on the pressurizer spray nozzles, pressurizer safety and relief nozzles, and the pressurizer surge nozzles. Fatigue crack growth analyses using ASME Code Section XI methodology were performed to demonstrate the fatigue qualification at the structural weld overlay regions. Reconciliation of the existing fatigue evaluation was performed for the limiting locations outside the FSWOL, and it was demonstrated that the pressurizer nozzles would still meet the applicable ASME Code Section III requirements. In summary, the reconciliation of the existing fatigue evaluation that was performed for the limiting locations outside the FSWOL is a TLAA that remains valid for the period of extended operation, because the cycles assumed will not be exceeded during 60 years of operation. Therefore, this TLAA has been demonstrated to be acceptable for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(i).
In conclusion, the VEGP fatigue TLAAs for ASME Class 1 components have been evaluated and shown to remain valid or are adequately managed for the period of extended operation, in accordance with the demonstration methods of 10 CFR 54.21(c)(1)(i) and 10 CFR 54.21(c)(1)(iii). The Fatigue Monitoring Program m onitors and tracks transient cycles and their severity and performs CUF monitoring of selected components to ensure that Class 1 components are maintained within their fatigue design limits. 19.4.2.2 ASME Section III, Non-Class 1 Component Fatigue Analysis The design of ASME III Code Class 2 and 3 piping systems at VEGP incorporates stress reduction factors for determining the acceptability of the piping design with respect to thermal stresses. Those in-scope components that are designed in accordance with ANSI B31.1 requirements also incorporate stress-reduction factors based upon an assumed number of VEGP-FSAR-19
19.4-5 REV 16 10/10 thermal expansion cycles. In general, 7000 full-tem perature thermal cycles are assumed in the calculation of the thermal expansion stress, leading to a stress-reduction factor of 1.0 in the stress analyses.
SNC evaluated the validity of this assumption of 7000 full-temperature thermal cycles for 60 years of plant operation. The results of this evaluation indicate that the 7000-thermal cycle assumption remains valid and bounding for 60 years of operation. Therefore, the existing pipe stress calculations are valid for the extended period of operation in accordance with 10 CFR 54.21(c)(1)(i).
There are non-Class 1 fatigue evaluations that use a different method of analysis than the 7000 cycles described above. In general, those evaluati ons use the same cycles, or a subset of the cycles, used for the Class 1 piping. These analyses include the letdown heat exchangers, containment cooler cooling coils, and the main stream isolation valves. In each case, the analysis was determined to remain valid for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(i). 19.4.2.3 Reactor Coolant Pump Flywheel Fatigue A calculation was performed for the VEGP reactor coolant pump flywheels which assumes that each pump will be subjected to 6000 start/stop cycles over a 60-year life. Current projections indicate that the 6000 start/stop cycles will remain bounding for 60 years of operation by a large margin. Therefore, fatigue of the reactor coolant pump flywheels is demonstrated in accordance with 10 CFR 54.21(c)(1)(i). 19.4.2.4 Fatigue of Reactor Vessel Supports The Westinghouse Generic Technical Report WCAP 14422, Revision 2a, identifies fatigue of reactor vessel supports as a potential TLAA if the supports of the reactor vessel were constructed in accordance with the 1963 version of the AISC Code.
The reactor pressure vessel supports embedded within the primary shield wall are procured in accordance with ASME Code,Section III, Division 1, Subsection NF; however, since they are outside the ASME jurisdictional boundary, their design follows AISC specifications. Therefore, both the 1969 version of the AISC Code and ASME Code,Section III, Division 1, Subsection NF apply to the supports.
In the SER for WCAP 14422, the NRC has indicated that licensees must ensure that a version of the AISC Code later than 1963 was used. Since the design used the 1969 version of the AISC Code, the existing analysis is demonstrated to be valid for the extended term of operation in accordance with 10 CFR 54.21(c)(1)(i). 19.4.2.5 Fatigue of Steam Generator Secondary Manway and Handhole Bolts Westinghouse performed a fatigue calculation for steam generator secondary manway and handhole bolts that assumed the same cycles used for Class 1 component fatigue evaluations.
That calculation resulted in a qualified life for the manway bolts of only 20 years. In 1993, it was determined that after low-temperature rerate, the qualified life of the manway bolts would be reduced to 14.5 years. A new secondary side manway and handhole bolts fatigue evaluation was performed based on actual cycles to qualify the bolts for 40 years with rerating.
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19.4-6 REV 16 10/10 To ensure that the cycle limits for these bolts are not exceeded, SNC will replace both the secondary side manway bolts and the handhole bolts after 30 years of service, unless a less restrictive replacement schedule is developed and documented based on potential updated analyses initiated by the Bolting Integrity Program. SNC considers this fatigue evaluation a TLAA that is managed by the Bolting Integrity Program. Therefore, this TLAA is demonstrated in accordance with 10 CFR 54.21(c)(1)(iii). 19.4.2.6 Fatigue of Reactor Vessel Internals A fatigue analysis of the reactor vessel internals was not required when VEGP was originally designed. However, as part of rerating, Westinghouse performed a fatigue calculation for reactor vessel internals that assumed the same cycles used for Class 1 component fatigue evaluations and resulted in CUFs less than 1.0 for all subcomponents evaluated.
VEGP evaluated this TLAA for the extended period of operation. Since the analysis utilized the same design transients as the Class 1 component evaluations, the evaluation of the ASME Class 1 piping and component design transient cycles is also applicable to the reactor vessel internals. The design cycles for the transients applicable to the reactor vessel internals are bounded by the RCS design cycles, therefore the reactor vessel internals fatigue analysis remains valid for the period of extended operation. This TLAA is demonstrated in accordance with 10 CFR 54.21(c)(1)(i). 19.4.3 ENVIRONMENTAL QUALIFICATION CALCULATIONS The NRC has established environmental qualification (EQ) requirements in 10 CFR Part 50 Appendix A and in 10 CFR 50.49. The Environmental Qualification Program for VEGP has been established to demonstrate that certain electrical components are qualified to perform safety functions in the harsh environment following a DBA. Elements of the proof of qualification involve the original 40-year license period. Hence, the qualification reports and calculations that comprise the EQ Program meet the definition of a TLAA. Qualified lives for EQ components have already been determined, and these components are tracked to determine when they are nearing the end of their qualified lives. For those components that are nearing the end of their qualified lives, the EQ Program has provisions for the component to be re-evaluated for longer service, refurbished, requalified, or replaced. The EQ Program will be continued through the period of extended operation. Therefore, this TLAA is demonstrated in accordance with 10 CFR 54.21(c)(1)(iii). 19.4.4 CONTAINMENT TENDON PRESTRESS ANALYSIS To meet the requirements on 10 CFR 50.55a (b)(2)(ix)(B), SNC uses an analysis to predict the amount of residual prestress in the containment tendons for VEGP. This analysis meets the definition of a TLAA. SNC extended the analysis to estimate the amount of residual prestress on the tendons after 60 years of operation. The analysis results conclude that acceptable containment tendon prestress will be retained throughout the period of extended operation.
Therefore, adequate containment prestress for the period of extended operation is demonstrated in accordance with 10 CFR 54.21(c)(1)(ii).
Results from containment tendon surveillances conducted under the Inservice Inspection Program - IWL periodically update the analysis and confirm prestresses remain above the minimum required values.
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19.4-7 REV 16 10/10 19.4.5 PENETRATION LOAD CYCLES A fatigue analysis was required for some of the VEGP containment penetrations. Those analyses qualify as TLAAs. Review of the trans ient assumptions for those evaluations against the transient assumptions for Class 1 component fatigue determined that none of the cycles assumed in the penetration fatigue analyses will be exceeded within the period of extended operation. Therefore, fatigue analyses for containment penetrations are acceptable without revision, and the TLAAs are demonstrated in accordance with 10 CFR 54.21(c)(1)(i). 19.4.6 OTHER PLANT-SPECIFIC ANALYSIS 19.4.6.1 Leak-Before-Break Analysis Plant-specific leak-before-break (LBB) analyses have been performed for both VEGP units.
These analyses provide the technical justification for changes to the structural design basis involving protection against the effects of postulated pipe ruptures and are identified as TLAAs since they include assumptions regarding fatigue cycles and material fracture toughness properties.
VEGP LBB analyses exist for the Units 1 and 2 reactor coolant loop piping, the pressurizer surge line, and the Unit 2 accumulator injection and the RHR branch connection lines.
The LBB analyses for the pressurizer surge line and the Unit 2 RHR branch connection line were reviewed and determined to be acceptable without revision for the period of extended operation. Therefore, these LBB analyses are demonstrated in accordance with 10 CFR 54.21(c)(1)(i).
The analyses for the primary coolant loops and the Unit 2 accumulator line have been evaluated and updated to address operation through 60 years, including reductions in cast material fracture toughness properties due to thermal aging. Therefore, these LBB analyses are demonstrated in accordance with 10 CFR 54.21(c)(1)(ii).
WCAP-10551-P, Addendum 1 performed an LBB evaluation for the Units 1 and 2 primary loop piping that explicitly addressed the PWSCC concern for the Alloy 82/182 welds in this piping.
However, the NRC has not yet accepted the process used as adequately addressing their concerns. Once the NRC has accepted a process for addressing PWSCC of Alloy 82/182 welds in LBB evaluations and at least 2 years prior to the period of extended operation, SNC will verify the LBB evaluation in WCAP-10551-P, Addendum 1 meets the conditions of that process or have it reperformed using the acceptable process. 19.4.6.2 Fuel Oil Storage Tank Corrosion Allowance The VEGP diesel fuel oil storage tanks and associated piping are not provided with cathodic protection; therefore, a liberal corrosion allowance was included. A calculation performed to evaluate the corrosion allowance included a 40-year assumption and has been determined to be a TLAA.
The calculation determined the depth of penetration for a hole of approximately 1/32 in.
diameter (0.001 in
- 2) in the coating. The calculation was reviewed for license renewal, and it was determined that depth of penetration due to corrosion would not exceed the corrosion allowance during a 60-year operating life. Spec ifically, consideration of 60 years instead of VEGP-FSAR-19
19.4-8 REV 16 10/10 40 years in the calculation increases the depth of penetration due to corrosion from 25% to 51%
of the corrosion allowance for the tanks and from 50% to 76% of the corrosion allowance for the pipes. Therefore, demonstration is in accordance with 10 CFR 54.21(c)(1)(ii). 19.4.6.3 Steam Generator Tube, Loss of Material VEGP UFSAR subsection 5.4.2 describes allowances for erosion and corrosion that are partially based upon a measured loss of material rate for 40 years. These allowances are used as inputs to demonstrate that stress limits established by Regulatory Guide 1.121 continue to be satisfied. Subsection 5.4.2 demonstrates that a large margin exists between the allowable tube wall degradation which satisfies Regulatory Guide 1.121 limits and the tube plug limits established by the VEGP Steam Generator Tubing Integrity Program. Increasing the expected corrosion allowance to address the period of extended operation has an insignificant effect on this margin. Further, steam generator tubing wall loss is managed by the Steam Generator Tubing Integrity Program and the requirements of Regulatory Guide 1.121 are considered within that program.
Therefore, this TLAA is managed by the Steam Generator Tubing Integrity Program and is demonstrated in accordance with 10 CFR 54.21(c)(1)(iii). 19.4.6.4 Cold Overpressure Protection System As described in paragraph 5.2.2.10 of the VEGP UFSAR, VEGP has a cold overpressure mitigation system (COPS). A calculation has been performed to confirm that the setpoints will maintain the system pressure within the established limits when the pressure difference between the pressure transmitter and reactor midplane and maximum temperature/pressure instrument uncertainties are applied to the setpoints. This calculation meets the definition of a TLAA. The P-T limit curves in the VEGP PTLR have been evaluated for 36 EFPY. When a revision to the PTLR is issued, the cold overpressure mi tigation system setpoints will also be updated to reflect the period covered by the PTLR revision. Therefore, this cold overpressure mitigation setpoint calculation TLAA is demonstrated in accordance with 10 CFR 54.21(c)(1)(ii).
As described in the PTLR, the Reactor Vessel Surveillance Program updates the P-T limit curves considering the data gained from capsules SNC pulls, and the content and update of the PTLR is in accordance with VEGP Technical Specifications, subsection 5.6.6. The associated COPS setpoints are also updated as operational needs dictate to bound the current level of neutron embrittlement (i.e., EFPY) for the unit. Therefore, this TLAA demonstration is made in accordance with 10 CFR 54.21(c)(1)(ii) and (iii). The VEGP PTLR (for each unit) will be updated to address neutron embrittlement for a 60-year operating life, including any changes to the COPS setpoints, prior to the unit entering the period of extended operation. 19.4.6.5 Underclad Cracking of the Reactor Pressure Vessel There is no plant-specific evaluation of underclad cracking at VEGP, and no such cracks have been identified. Freedom from underclad cracking is ensured by special evaluation of the procedure qualification for cladding applied on low-alloy steel (SA-508, Class 2) in accordance VEGP-FSAR-19
19.4-9 REV 16 10/10 with Regulatory Guide 1.43. However, SNC conservatively includes underclad cracking as a TLAA. Analyses performed by Westinghouse in WCAP-15338 demonstrate that growth of underclad cracks in Westinghouse reactor pressure vessels (RPVs) does not represent a significant challenge to reactor vessel integrity for an operating term of 60 years. The assumptions used as inputs to WCAP-15338 are applicable to VEGP. The results of these analyses demonstrate that underclad cracking of reactor vessel components is not an aging effect requiring management for VEGP. TLAA disposition is in accordance with 10 CFR 54.21(c)(1)(i).
19.
4.7 REFERENCES
- 1. NUREG-1800, Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants, U. S. Nuclear Regulatory Commission (Rev. 1), September 2005. 2. NUREG-1801, Generic Aging Lessons Learned (GALL) Report, U. S. Nuclear Regulatory Commission (Rev. 1), September 2005. 3. Vogtle Electric Generating Plant Unit 1 & Unit 2 Technical Specifications.