Chapter
2 Systems of BWR Nuclear Power Plants
The moisture separator is
used to remove the moisture from the high pressure turbine exhaust
steam to prevent corrosion and to increase thermal efficiency. In
the moisture separator, wet steam is passed through corrugated
plates which are arranged with a narrow separation. Droplets
included in the steam adhere to the plates and the moisture is
removed. Earlier a vertical type moisture separator was used, but a
horizontal chevron type has been adopted recently.
The moisture separator
re-heater is this horizontal type moisture separator,
having heating tubes with fins inside its body. After moisture is
removed by the corrugated plates, the steam is superheated to
increase the thermal efficiency of the low pressure turbine. The
re-heater uses the high pressure turbine extraction steam (at the
first stage of the re-heater) and a part of the main steam (at the
second stage of the re-heater).
Recently two 50% capacity moisture separator reheaters have
been commonly installed, instead of the moisture separator.
Figure.2.5.4 also shows the structure of a horizontal moisture
separator reheater.
The turbine is controlled by an EHC unit. Noncombustible oil is
used because of its high pressure environment (ll.OMPa (gauge)). In
the early days of nuclear power generation, an analog type was used,
but recently a digital type using a micro computer has been in use.
A schematic drawing of the turbine control unit is shown in Figure
2.5.5. This is an example of a triplicated EHC unit used for
increasing reliability.
The main steam pressure and the turbine
speed are controlled by the
turbine control valve using the EHC unit. When a turbine trips, the
turbine stop valve, the intermediate stop valve and the intercept
valve are quickly closed to prevent turbine over speed, and the
turbine bypass valve is
opened quickly to send the reactor steam directly to the condenser.
The list of trip signals of the steam turbine shutdown system is
shown in Table 2.5.1.
Table 2.5.2 shows key specifications of the main equipment which
composes the main steam and the condensate feed water systems of a
l,100MWe class turbine generator.
The main steam header is installed to balance the pressures between
the four main steam lines connected to the turbine main steam stop
valve. The turbine bypass system is used to send the reactor steam
directly to the condenser during reactor startup and shutdown, or
when a transient occurs. If the turbine bypass system has a capacity
for 100% of the reactor steam, the plant can be shifted to an
inhouse operation by isolating it from the grid when the
generator load is fully rejected during rated power operations.
The steam extraction system is installed to improve the plant
thermal efficiency by supplying steam to the feed water heater to
heat the reactor feed water and by treating moisture drain separated
in the turbine stages. The steam extraction line has a check valve
to limit turbine over speed below the pre-specified value (111%)
when the turbine trips.
The feed water heater drain system is installed to treat the drain
condensed in the feed water heater. Drain levels in the feed water
heaters are maintained within the pre-specified values by the level
control system in order to maintain the feed water heater
efficiencies. The moisture separator drain is also collected in the
feed water heater and used to heat the feed water. The feed water
heater drain passes through the lower stage feed water heaters
sequentially and is returned to the condenser, but the drain is
discharged directly to the condenser by a bypass line when the level
increases during startup or transient conditions. Non-condensable
gas in the feed water heaters is vented to the condenser
continuously to maintain the feed water heater efficiencies.
In the ABWR, the drain-up system is adopted, which directly collects
the feed water heater drain into the condensate system.
2-51
NSRA,
JapanMoisture separator and heater
Electro-hydraulic turbine control (ehc) unit
Main Steam System and Condensate Feed Water System
Main steam line and turbine bypass system
Steam extraction system and feed water heater drain system
Figure
2.5.5 Outline of the turbine control unit
Table
2.5.1 List of steam turbine shutdown system trip signals |
Detector |
Trip Level |
Purpose |
|
Type |
Location |
|||
Main Oil Pump Discharge Pressure: Low |
Pressure Switch |
Oil Pump Discharge Line |
0.73 MPa |
Prevent Damage Of Turbine Bearing By Heat |
Wear Of Thrust |
Pressure Switch |
Thrust Collar |
55 kPa |
Prevent Damage Of Thrust Bearing By Heat |
Control Oil Pressure: Low |
Pressure Switch |
Oil Pump Discharge Line |
7.55 MPa |
Prevent Instability Of Turbine Control |
Shaft Vibration: High |
Vibration Sensor |
Bearing |
0.25 mm |
Prevent Rotor Rubbing |
Low Pressure Turbine Exhaust Hood Temperature: High |
Temperature Switch |
Turbine Exhaust Hood |
107 °C |
Prevent Shaft Vibration |
Condenser Vacuum: Low |
Pressure Switch |
Condenser |
-76kPa |
Prevent Shaft Vibration |
Moisture Separator Water Level: High |
Water Level Switch |
Moisture Separator |
bottom |
Prevent Water Inflow To Turbine |
Turbine Overspeed |
Eccentric Ring |
Turbine Shaft |
110-111% |
Prevent Damage Of Rotor |
Backup Governor Actuated |
Speed Sensor |
Turbine Shaft |
111.5% |
Prevent Damage Of Rotor |
Turbine Control Equipment Failure |
— |
EHC |
— |
Prevent Instability Of Turbine Control |
Reactor Scram |
Relay |
Reactor Protection System |
scram |
Safe Shut Down Of Turbine |
Reactor Water Level: High |
Water Level Switch |
Reactor Pressure Vessel |
level 8 |
Prevent Water Inflow To Turbine |
Generator Lock-out Relay Actuated |
Relay |
Generator Protection System |
trip |
Prevent Generator Failure Development |
Inlet Pressure Of Stator Cooling Water: Low |
Pressure Switch |
Stator |
0.89 kPa |
Prevent Damage Of Stator Coil By Heat |
Outlet Temperature Of Stator Cooling Water: High |
Temperature Switch |
Stator |
77 °C |
Prevent Damage Of Stator Coil By Heat |
RCIC Startup |
Relay |
Reactor Protection System |
Startup |
Prevent Water Inflow to Turbine | |
NSRA,
Japan
2-52
Chapter
2 Systems of BWR Nuclear Power Planls
Table
2.5.2 Specifications of |
|||
|
Type |
|
tandemcompound 6 flow |
|
Number of Units |
|
1 |
|
Capacity |
Rated |
about 1.100MW |
|
Rotation Speed |
|
1.500 rpm |
|
Steam Conditions |
Pressure |
6.55 MPa (gauge) |
|
|
Temperature |
282 °C |
|
|
Wetness Fraction |
0.4% |
|
Length |
|
about 45m |
|
Weight |
|
about 2,8001 |
|
Steam Flow Rate |
|
about 6,400 t/h |
|
Degree of Condenser Vacuum |
|
-96.3 kPa |
|
Closing Time of Main Steam Stop Valve |
|
about 0.1s |
|
Closing Time of Steam Control Valve |
|
about 0.2s |
|
|
|
|
(2) Turbine bypass system |
|||
|
Number of Systems |
|
1 |
|
Capacity |
|
about 2400t/h (about 37.5% of rated steam flow) |
|
|
|
|
(3) Moisture separator |
|||
|
type |
|
horizontal chevron |
|
number of units |
|
2 |
|
|
|
|
(4) Condenser |
|||
|
type |
|
surface type, one pass, 3 divisions |
|
number of units |
|
1 |
|
exhaust flow |
|
about 3500t/h |
|
degree of vacuum |
|
-96.3 kPa |
|
cooling water flow rate |
|
about 280,000 m3/h |
|
material of cooling tube |
|
titanium |
|
sea water temperature (design base) |
|
19 °C |
|
|
|
|
(5) Air ejector |
|||
(a) Steam jet air ejector (SJAE) |
|||
|
type |
|
2 flows, 2 stage steam jet type | |
|
number of units |
|
1 |
|
capacity |
|
about 40Nm3/h (non-condensable gas) |
(b) SJAE for startup |
|
|
|
|
type |
|
1 flow, 2 stage steam jet type |
|
number of units |
|
1 |
|
capacity |
|
150 Nm3/h |
(c) Vacuum pump |
|
|
|
|
type |
|
horizontal, water sealing type |
|
number of units |
|
1 |
|
capacity |
|
about 7,100 Nm7h |
,100
MWe class turbine system |
||
(a) Low pressure condensate pump |
||
|
type |
turbo type |
|
number of units |
3 including 1 standby pump) |
|
capacity |
about 3,700 Nm3/h/unit |
(b) High pressure condensate pumps |
||
|
type |
centrifugal |
|
number of units |
3 (including Istandby pump) |
|
capacity |
about 3,700 Nm3/h/unit |
|
|
|
(7) Condensate cleanup system |
||
(a) Condensate demineralizer |
||
|
type |
external-regenerative type |
|
|
(but non-regenerative operation) (demineralizing by mix-bed ion exchange resin) |
|
number of units |
8 (including 1 standby unit) |
|
capacity (max) |
about 1,000 m3/h/unit |
(b) Condensate filters |
||
|
type |
non-pre-coat type |
|
number of units |
5 (no standby units) |
|
capacity (max) |
about 1,300 m3/h/unit |
|
|
|
(8) Feed water heaters |
||
|
type |
horizontal U-tube type |
|
number of units |
high pressure: 2 loop X 2 stage low pressure: 3 loop X 4 stage |
|
|
|
|
capacity |
high pressure: about 3,200 t/h/loop low pressure: about 2,100t/ h/loop |
|
|
|
|
material |
shell: low alloy steel tube: stainless steel |
|
|
|
|
|
|
(9) Reactor feed water pumps |
||
(a) Turbine driven reactor feed water pumps |
||
|
steam turbine |
|
|
type |
condensing type |
|
number of units |
2 |
|
capacity |
about 9,000 kW/unit |
|
rotation speed |
5,000 rpm |
|
feed water pumps |
|
|
type |
turbo type |
|
number of units |
2 |
|
capacity |
about 3,900 m3/h/unit |
|
total head |
about 740 m |
|
rotation speed |
5,000 ppm |
(b) Motor driven reactor feed water pump |
||
|
type |
turbo type |
|
number of units |
2 |
|
capacity |
about 2,000 m3/h/unit |
|
total head |
about820 m |
|
motor power |
about 5,600 kW |
|
|
|
(10) Circulation waterpumps |
||
|
type |
turbo type |
|
number of units |
3 |
2-53
NSRA,
Japan
Outlines of the high pressure and low pressure drain-up system
structures are shown in Figs, 2.5.6
and 2.5.7, respectively. In the high
pressure drain-up system, the high pressure feed water
heater drain is collected into one high
pressure
drain tank and
pressurized by a drain pump in order to feed it into the upper
stream of the reactor feed water pump. In the low
pressure drain-up system, the drain is collected into the
upper stream of the condensate demineralizer considering the
Figure
2.5.6 Outline of the high pressure drain up system
to
feed water heater NO.5
(50%
X 3)
Figure
2.5.7 Outline of the low pressure drain up system
NSRA,
Japan
2-54
