Chapter 11. Design of Other BOP

Transcription

1 Nuclear Systems Design Chapter 11. Design of Other BOP Prof. Hee Cheon NO

2 11.1 Condenser Design Consider Performance Requirements Accepting heat rejected by steam cycle as final heat sink Maintaining design vacuum Accepting a large number of transient steam dumps Isolation from condenser cooling water Isolation from atmosphere Rejection of noncondensibles to atmosphere 2

3 Description of Condenser 3

4 Thermal Design of Condenser Q m [ h h h ] UA T m c T c c fg e f c ln cw p cw where Given T T T : condensate depression cd s c T ( T T ) / ln[( T T ) /( T T )] ln cw2 cw1 s cw1 s cw2 T and T, T, T, T, T cw1 cw 1 2 cw ln are to a first approximation proportional to thermal duty (Q) 4

5 Steam-Driven Air Ejector Vacuum Pump Simple Structure High Reliability Low Cost 5

6 Capture of Air at The Exit of The First Nozzle by high speed steam Compression in the second nozzle(diffuser) Discharge of Mixture at the exit 6

7 7

8 11.2 Feedwater/Condensate System Functional Objectives Returning high quality(chemically, thermally) feedwater to control corrosion and to increase efficiency 1. Function of The Condensate System Returning the condensed steam from the condenser hotwell to the SG feedwater pump suction : Collecting condensate from various components Chemically treating condensate Preheating the condensate Suppling the neccesary suction pressure for the feedwater pumps 8

9 2. Function of The Feedwater System Returning high quality(chemically, thermally) feedwater from the condenser hotwell to SG Returning the feedwater from the suction of the SG feedwater pumps to the main condenser to the SG : preheating the feedwater, and controlling it to maintain the desired SG water level. 9

10 Description of System 10

11 Description of System 11

12 System Feature (1) Condenser Receiving the exhaust steam from the low pressure turbines Forming the condensate through the circulation water flowing through the tubes Draining the condensate into the hotwell, combining with the condensate Draining the shell sides of the low pressure feed heaters (2) Hotwell-Level Control System Automatic makeup and reject system to maintain a normal level in the hotwell On low water level in the hotwell: a control valve opens to admit condensate from the condensate storage tank into howell via gravity On high water level in the hotwell: another control valve opens to reject condensate from the hotwell pump discharge to the condensate storage tank 12

13 (3) Low & High Pressure Heaters Three strings with four heat exchanges each Each string is designed to handle 50% of full flow with one out of service (4) Three Condensate Pumps Taking suction from the condenser hotwell and discharging the condensate into a common header 2 operating pumps and 1 spare pump, which automatically starts on the loss of one of the operating condensate pumps ex) 3x33%: lower capital cost saving ($200K-1M) 3x50%: capacity saving ($4M) 13

14 (5) Deaerator Liquid inventory: 31/2 min of design feedwater flow Providing heater feedwater to maintain SG level to reduce feedline cracking Nitrogen and/or steam blanket to assure that Elevation for adequate NPSH to feedwater booster pumps (6) 3 Main Feedwater Fumps 3 pumps in parallel driven by adjustable speed motors with variable frequency power suppliers Recirculation system: centrifugal pumps require a minimum flow requirement. 3% design margin of each feedwater pump for imprecise design wear and fouling: excessive margin requires more throttling 14

15 (7) SG Water Level Control Feedwater control valves: three-element feedwater controller (feedwater flow, steam flow, water level) to maintain a programmed water level of SG above 15% power Bypass control valves: to overcome instability and non-linear flow vs. valve position characteristics at low flow rates below 15 % power 15

16 11.3 Feedwater System Non-contact Feedwater Heater 16

17 Direct-Contact Feedwater Heaters (Deaerator) Bred steam is in contact with the condensate, and the condensate and steam are at the same pressure in the shell: TTD~0 where * TTD(Terminal Temperature Difference) = (temperature of saturated steam within feedwater heater) - (temperature of condensate leaving the heater) 17

18 ~3mins continuous water supply to SG after stop of condensate pump ~FH(feedwater heater) s draining ~Saturation condition: TTD~0 18

19 11.4 Main/Extraction and Its Design 19

20 11.4 Main/Extraction and Its Design Functional Objectives (1) Main Steam System 20

21 11.4 Main/Extraction and Its Design Functional Objectives (1) Main Steam System Transport main steam from SG to HPT, MSR, turbine driven auxiliary feedwater pumps, gland seal steam system Provide steam bypass and relief capabilities: dump system Provide isolation of main steam lines in case of a main steam line break (2) Extraction system Transport extraction steam from HPT to LPT to feedwater heaters 21

22 System Feature (1) PORV (Atmospheric Steam Relief Valves) Preventing SV opening and dissipating decay heat to atmosphere if main condenser is not available Minimizing actuation of SV Maximum capacity: 10% of rated SG flow (2) SV Protecting steam system from overpressure conditions Maximum capacity: 110% of rated SG flow 22

23 (3)MSIV (Main Steam Line Isolation Valves) Preventing overpresurization of containment from steam line break and limiting cooldown of primary system Actuation signals for opening MSI Hi steam flow coincident with either Lo-Lo Tavg or Lo steam line pressure Hi-Hi containment pressure (4) Steam Dump System Used to reduce reactor power transient following a sudden reduction in turbine power demand through dumping steam directly to the condenser Requirements: load rejection requirement: permission of load rejection without a reactor trip turbine and reactor trip requirement: allowing turbine and reactor trip from full load without lifting SG safety valves 23

24 (5) Turbine Stop Valves Quickly isolating steam to turbines to prevent turbine overspeed Either fully open or fully shut (6) Turbine Control Valves Controlling steam flow to the high pressure turbines Positioned by the EHC(electro-hydraulic control) system for speed control during startup and load control after the synchronization with the grid Acting as a back-up to the turbine stop valves 24

25 11.5 CVCS Chemical Volume Control System Functions Control of Boron concentration for normal and accident operations RCS inventory Seal water flow to RCP shaft seals Chemistry and radioactivity treatment Degassification of RCS process for reuse of boric acid and reactor makeup water 25

26 System Description Letdown line Charging line Aux spray line Seal return line Seal injection line Safety injection line 26

27 (1) Connection of Letdown Lines to RCS Letting down reactor coolant from RCS corssover leg to the shell side of the regenerative heat exchanger (2) Regenerative Heat Exchanger Dropping the fluid temperature through increasing the fluid temperature in the charging line to avoid void generation after pressure drop (3) Letdown Orifices Dropping the fluid pressure to about 400 psig 27

28 (4) Letdown Heat Exchanger Further dropping the fluid temperature using component cooling water as its cooling medium (5) Letdown Pressure Control Valve Controlling upstream pressure at psig to prevent coolant from flashing to steam (6,7) Mixed-bed /Cation Demineralizers Mixed-Bed Demineralizers: removing ionic impuriteis Cation Demineralizer: removing lithium formed from the boron-neutron reaction. This extra lithium could result in excessively high ph values in the RCS. 28

29 (8) VCT(Volume Control Tank) Spray nozzle Increasing interfacial area to enhance dissolving hydrogen in the coolant and extracting fission gas absorbed in it Degassification Extracted fission gas is stored in the holdup tank before it is released to atmosphere Hydrogen addition To remove oxygen in the coolant at high temperature and control RCS metal corrosion Nitrogen addition To purge hydrogen and fission gas from VCT 29

30 (9) Charging Pumps Taking suction from VCT Two types of pumps: Positive displacement charging pumps(pcp) and centrifugal charging pumps(ccp) Charging flow control valves To control charging flow in order to maintain the pressurizer level (10) Pressurizer Auxiliary Spray Line Suppling the pressurizer auxiliary spray when no RCPs are running and normal pressurizer spray is not available 30

31 (11) Seal Water Heat Exchanger Dropping the temperature of the seal water exiting RCP through the No.1 seal using component cooling water as its cooling medium (12) Reactor Makeup Control System Automatic makeup addition to CVCS with a preset blended boric acid concentration or preset quantity of either concentrated boric acid or pure water Emergency boration: sending boric acid from boric acid tanks to the suction of the charging pumps via an emergency boration control valve 31