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A nuclear reactor produces heat. A steam generator converts that heat into high pressure steam. The steam expands while turning a steam turbine which drives a line synchronous generator to produce 60 Hz 3 Phase electric power.
A steam generator reference paper is Steam Generation - An Overview by Babcock and Wilcox.
Spray evaporator theory is discussed in the reference: Spray Evaporator Theory
Steam plants are discussed in the references: Steam Plant Operation and Industrial Boilers and Heat Recovery Steam Generators.
HEAT TRANSPORT OVERVIEW:
In a liquid sodium cooled Fast Neutron Reactor (FNR) for safety purposes there is an isolated secondary liquid sodium heat transport loop between each immersed intermediate heat exchange bundle and the corresponding steam generator. There is an induction type circulation pump in the return pipe from the steam generator to the intermediate heat exchange bundle.
The electricity output from a FNR is controlled by modulating the flow rates of the induction pumps. The steam production rate is approximately proportional to the total secondary sodium flow rate.
Each steam generator has a local control loop that maintains the desired water column height in the steam generator by controlling the rate of high pressure condensate water injection.
This web page is concerned with detail related to the steam generator design.
FNR STEAM GENERATOR DESCRIPTION:
A FNR steam generator is in essence a vertical tube in shell heat exchanger with water and/or steam flowing upward inside the tubes and liquid sodium flowing downward outside the tubes but inside the shell. A FNR steam generator and its support equipment must be designed so that a steam generator heat exchange tube rupture does not create a dangerous situation due to high pressure water jetting into low pressure liquid sodium and instantaneously producing large amounts of hydrogen gas.
a) The higher heat capacity of water as compared to sodium;
b) The latent heat of vaporization of water;
c) The changes in temperature of the sodium and the water in normal operation;
the downward sodium mass flow rate in the steam generator is much higher than the upward water/steam mass flow rate. Hence the water flows inside narrow tubes and the sodium occupies the space around the tubes but inside the shell.
The water is normally at a high pressure (11.25 MPa) while the secondary sodium is normally at a very low pressure (~ 0.1 MPa).
The sodium is hotest on top and flows almost straight downwards. The water is coolest on the bottom and flows almost straight upwards through the tubes. Inside the upper portion of the tubes gas flow turbulators force a zig-zag vapor flow path which improves heat transfer from the tube walls to the rising steam vapor. The high thermal conductivity of the liquid sodium minimizes heat transfer limitations due to laminar sodium flow outside the tubes.
During normal operation a steam pressure regulating valve connected in line between one side of the steam genertor upper manifold and the steam discharge pipe to the turbogenerators keeps the steam pressure inside the upper manifold and hence the pressure in the steam generator tubes and the lower manifold at about 11.25 MPa. This pressure in combination with the properties of water keeps the super heated liquid water inside the lower portions of the steam generator tubes at 320 degrees C.
Connected to the opposite side of the upper manifold are a steam release valve and a rupture disk, both vented to the atmosphere via 12.75 inch OD schedule 160 pipes. The rupture disk is configured to rupture open at a steam pressure of about 14 MPa. Thus there are two redundant means of protecting the steam generator from failure due to steam over pressure.
The steam generator consists of six stacked coaxial sections. Starting from the bottom:
1) A bottom manifold which preheats the injected high pressure water. This section has schedule 160 shell and fittings;
2) An externally sleeved lower tube section where some of the injected water is vaporized. The sleeves limit the heat flux through the tube wall near the bottom of the tubes where liquid water is in contact with the tube inner wall. This section has a shell side 12.75 inch OD schedule 80 sodium discharge pipe.
3) A middle tube section where the balance of the injected water is vaporized;
4) An upper tube section containing steam flow turbulators where the dry bulb temperature of the steam is increased. This section has a 12.75 inch OD schedule 80 sodium inlet pipe.
FNR STEAM GENERATOR PRESSURE ISSUES:
In normal operation the steam generator shell side contains secondary sodium with an argon cover which normally operates at an absolute pressure of about 0.1 MPa. The shell should be hydraulic pressure tested to at least 9.0 MPa to safely manage 6 MPa maximum possible pressure transients that might be caused by sudden release of hydrogen gas.
The steam generator tubes contains water/steam normally at a pressure of about 11.25 MPa. After fabrication the tube side of the steam generator should be hydraulic pressure tested at 18 MPa.
The top half metre of the steam generator shell side contains argon gas. Below that gas pocket the shell side of the steam generator is filled with liquid sodium. A 16 inch diameter schedule 80 hydrogen vent pipe connects to the gas filled section. This vent pipe initially contains 0.1 MPa absolute pressure argon gas. The argon is retained by a roof top metal ball check for thermal isolation followed by a goose neck air seal. The goose neck must be deep enough to ensure that sealing water will never back flow and must have reliable level control/monitoring and rain water exclusion. It will need anti-freeze to ensure reliable operation in the winter.
The vent pipe, liquid/air separator and dump tank all provide cushion tank capacity to supplement the argon filled space inside the steam generator. This cushion space contains no sodium and has no valves other than the rooftop rupture disk and gravity reset ball check. The pipe from the steam generator to the liquid/gas separator slopes slightly downward toward the steam generator to ensure positive liquid sodium drainage back to the steam generator.
There are sodium level, argon pressure and argon temperature sensors. An unanticipated decrease in sodium level indicates either a secondary sodium leak or a dump tank argon leak. A temperature corrected increase in argon/hydrogen gas pressure in the vent system indicates a likely small leak in one of the steam generator heat exchange tubes.
This arrangement, if working pressure rated for 6 MPa, can safely absorb over 50X its volume of hydrogen gas as the secondary sodium pressure rises from 0.1 MPa to 5 MPa.
For each steam generator there is a small valved pressure balancing tube between the argon filled space over the primary sodium and the argon filled space over the secondary sodium. This valve is normaly closed to prevent hydrogen leaking into the space over the primary sodium.
Above the roof the vertical 16 inch vent pipe contains a 16 inch X 16 inch X 16 inch tee and above the tee is a ball check. The branch of the tee is sealed with a 16 inch diameter 6 MPa rated rupture disk.
The ball check consists of a 16 inch schedule 80 feed pipe from below topped by a 24 inch diameter schedule 80 tee and two gooseneck air seals filled with water/anti-freeze.. There is a conical transition region between the 16 inch and 24 inch diameter pipe sizes and a 20 inch diameter heat tolerant ball. There is a thermal break at the top of the top of the metal conical transition region.
On the occurrance of a steam generator tube failure high pressure water and steam both jet through the rupture into the shell side of the steam generator where they contact sodium and chemically release hydrogen which causes a rapid pressure rise on the steam generator shell side. The rate of the pressure rise is mitigated by:
a)Use of narrow heat exchange pressure tubes which limit the water flow rate;
b)Use of a secondary sodium argon cover and vent pipe system that act as a pressure cushion tank and vent the argon/hydrogen gas.
The rise in gas pressure over the secondary sodium immediately causes::
a) Opening of the ball check and gooseneck gas seals.
b) Turn-off of the electric power that keeps the multiple steam generator lower manifold drain valves closed and keep the steam vent valve closed. Residual steam pressure in the upper manifold expels liquid water from the heat exchange tubes and from the lower manifold into the drain. The high water pressure forces the lower manifold drain valves wide open;
c) Stopping of the injection water pump. There are two series connected pump control relays activated by independent high pressure sensors for certainty in stopping water injection;
d) Opening of the steam vent valve releases the steam in the upper manifold to the atmosphere.
e) Stopping the secondary sodium induction pump prevents NaOH produced by the chemical reaction between water and sodium being swept into the intermediate heat exchanger.
f) Complete closing of the steam pressure regulating valve and shutdown of parallel connected steam generators in the same heat exchange gallery prevents reverse steam flow through the pressure regulating valve.
This pressure relief arrangement protects the intermediate heat exchanger from large hydrogen induced liquid sodium pressure pulses. Note that the 12 inch pipes conveying secondary sodium between the steam generator and the intermediate heat exchanger are designed so that the pressure difference between these two pipes is always very small and so that hydrogen gas cannot enter these pipes. To avoid possible liquid sodium hammer damage to the intermediate heat exchanger liquid sodium and hydrogen gas are not permitted in the same pipe. To ensure expulsion of hydrogen these two pipes should slope slightly upwards towards the steam generator.
THe induction pump is located close to the pool deck level to ensure that during heat transport loop operation it always has sufficient suction head pressure.
Below the primary sodium pool deck level is a secondary sodium dump tank for holding secondary sodium to permit heat transport loop maintenance. If the argon pressure in the secondary sodium dump tank is released the secondary sodium will drain down almost to the pool deck level. This feature can be used to extinguish a secondary sodium fire.
The secondary sodium argon cover gas is installed with the system cool at an absolute pressure of about 0.1 MPa. The increase in contained argon pressure caused by the normal liquid sodium temperature increase will cause some of the contained argon be vented via the rooftop ball check. On a system shutdown the temperature will drop and the vented argon must be automatically replaced to maintain the desired liquid sodium level. If the vent argon pressure rises to 0.2 MPa absolute for even a few milliseconds the loop safety shutdown sequence should be initiated.
The secondary sodium heat transport system is fabricated with schedule 80 pipe to have a working pressure rating of 6.0 MPa and must be hydraulically tested at 9.0 MPa so as to ensure safety in the presence of multiple steam generator heat exchange tube ruptures.
It is difficult to realize good high temperature high pressure sodium seals at flanged mechanical joints. Hence normally the secondary sodium operates below 0.1 MPa gauge pressure. The secondary sodium system is rated for a much higher pressure simply to ensure that there is no major damage when there is a steam generator tube rupture. It is possible that as a result of a major hydrogen pressure pulse gasketed flange joints may leak, in which case the secondary sodium must be drained down into the dump tank and the flange joint sealing gaskets replaced. The implication of this is that a steam generator tube failure may result in that heat transfer loop being out of service until the next reactor shutdown. However, the large number of independent heat transfer loops minimizes the consequence of a single loop shutdown.
There must be protection against liquid sodium hammer in each secondary sodium circuit. This objective is achieved by prevention of hydrogen and sodium mixing in the secondary sodium heat transport piping. The hydrogen is vented from the argon cover space. The 12.75 inch OD schedule 80 inlet sodium pipe connection must be below and separated from the hydrogen vent pipe connection. These two pipes require separate connections to the steam generator outer wall. Due to weakening of this wall by these pipe connections the 24 inch diameter steam generator shell should be schedule 160.
HEAT EXCHANGE TUBE WALL STRESS REDUCTION:
High temperature differentials across heat exchange tube walls can potentially cause thermal stress in excess of the material yield stress. Part of the steam generator design focuses on reducing the maximum material thermal stress.
There are two general approaches to heat exchange tube wall thermal stress reduction. At the bottom of the steam generator where the tubes contain liquid water external sleeves around the tubes are used to reduce the heat flux per unit area and hence the maximum temperature drop across the tube wall.
Higher up the tubes there is a layer of steam adjacent to the inside surface of the heat exchange tube which reduces the heat flux per unit area through the tube wall. Hence in this region the tube wall temperature is close to the downward flowing liquid sodium temperature. The heat flux through the tube wall is limited by the rate of heat transfer from the tube wall to steam, which is much less than the rate of heat transfer from the tube wall to liquid water.
Each heat exchange tube contains a central water column. Near the bottom of the tube this water column is as wide as the inside diameter of the tube but the water column width decreases in diameter further up the tube, eventually reaching zero. The space between the water column and the tube wall is filled with rising steam. The height of the water columns inside the heat exchange tubes is indirectly controlled by controlling the height of an pure liquid water column in an external tube connected between the top and bottom manifolds. This external tube has no radial heat flow. That external water column height is sensed and is controlled by controlling the flow rate of high pressure water injection into the lower manifold. Due to steam formation the height of the water columns inside the heat exchange tubes is several times the height of the sensed water column in the external tube. However, the pressure at the bottom of all the water columns is identical.
Below the top of a central water column heat transferred from the tube wall to the steam is almost immediately absorbed by latent heat of evaporation of water in the central water column that is transitioning from water to steam. Thus below the top of a central water column the fluid temperature is nearly constant at about 320 degrees C at a pressure of 11.25 MPa, corresponding to saturated steam. The head pressure is maintained by the steam pressure regulating valve connected to the upper manifold.
Above the top of the central water column the steam becomes drier and rises to a top temperature in the range 400 degrees C to 440 degrees C depending on the system thermal load.
Above the top of each central water column a bent metal turbulator suspended from the upper manifold. Turbulators are used to improve the heat transfer rate from the heat exchange tube inner wall to the rising steam.
Note that the pressure distribution in the heat exchange tubes and hence the water column height is affected by viscosity and flow turbulator effects.
TUBE SHEET THERMAL STRESS MITIGATION:
Note that the bottom tube sheet should have a layer of thermal insulating material installed on its under side to prevent water boiling inside the lower manifold and to reduce thermal stress in the lower tube sheet.
LOWER MANIFOLD THERMAL STRESS MITIGATION:
There is feed water temperature mixing below the bottom manifold of the steam generator to minimize thermal stress on the steam generator heat exchange tube portions that contain water. The feed water temperature rise from 25 deg C to 320 C is realized by feed water heat recouperation from the turbine discharge steam immediately upstream from the turbine condenser followed by water mixing below the bottom manifold of the steam generator.
TUBE FAILURE MITIGATION:
An important issue in FNR steam generator design is preventing a water leak from a tube rupture from causing a serious accident. When high pressure water and steam jets into the low pressure hot liquid sodium the chemical reaction:
2 Na + 2 H2O = 2 NaOH + H2 (gas)
instantaneously occurs. Hydrogen gas is produced at a rate limited only by the leakage water mass flow. At one atmosphere pressure the volume of that hydrogen released will be of the order of 1000X_____ the cumulative volume of the water leak. The system must be designed to:
1) Remain structurally safe in the presence of this rapid hydrogen pressure rise;
2) Prevent a dangerous pressure transient reaching the connected intermediate heat exchanger;
3) Prevent liquid sodium hammer damage at the intermediate heat exchanger;
4) Rapidly and safely vent the hydrogen gas to prevent an explosion.
5) Open lower manifold drain valves and use residual steam pressure in the upper manifold to rapidly expel liquid water from the heat exchange tubes;
6) Stop the injection water flow;
7) Release high pressure steam from the upper manifold to the atmosphere to stop steam jetting into the sodium from both sides of the tube rupture;
8) Force the steam pressure regulating valve fully closed and shut down parallel connected steam generators to prevent steam from other steam generators back flowing through the steam pressure regulating valve;
9) Turn off the secondary sodium induction pump to prevent NaOH accumulating in the intermediate heat exchanger;
10) Safely isolate components for cleanup and repair;
11) Confirm correct sodium level and presence of argon cover gas at less than 0.3 MPa before restarting the induction pump.
In a continuously operating energy generation system sooner or later there will be a steam generator heat exchange tube failure. Such a failure will allow high pressure injection water to flow through the rupture and into the secondary sodium. Hydrogen gas will be generated very quickly. There must be cushion tank volume of sufficient size to slow the rapid rise in pressure in the secondary circuit enough to allow time for the rise in pressure to be detected, the secondary sodium over pressure gravity reset ball type safety valve to reliably open venting hydrogen and argon cover gas from the cushion tank volume, the lower manifold drain valves to open, the dedicated injection water pump to stop and the heat exchange tubes to drain their contained water into the lower manifold, the steam vent to open, steam pressure control valve to close, residual steam to vent to the atmosphere and the induction pump to stop.
There must be fully redundant pressure relief safety devices (rupture disks) to ensure that the aforementioned venting occurs because failure of the vents to work as contemplated could have catestrophic consequences. In addition to gas pressure sensors there must be sodium level sensors to confirm the sodium level in the steam generator, water level sensors to control the injection water pumps and a means to ensure that obstructing solid sodium does not accumulate in the hydrogen vent pipe.
The worst FNR nightmare is a sudden overpressure in a secondary sodium circuit which causes a rupture of the corresponding intermediate heat exchanger such that a dual equipment failure allows injection water to flow from the steam loop into the primary sodium pool. There must be redundant means of stopping the injection water flow to ensure that this nightmare cannot occur.
The pressure relief pipe and check valve must be large enough (16 inch diameter) to ensure that hydrogen can be vented as fast as it is generated, which in the case of heat exchange tube ruptures is limited only by the maximum possible water and steam flow rates through the throats of the ruptured steam generator heat exchange tubes. eg To achieve reliable argon/air seals use gravity reset ball checks topped by silicone oil filled U tubes. Metal or ceramic gravity reset balls will trap the heat from below and the silicone oil will give a reliable air seal. After an emergency trip the silicone oil may need to be replaced.
Similarly, there must be redundant lower manifold drains.
The consequence of any potential steam generator tube rupture are physically limited by the use of 56 independent heat transfer loops, each with its own steam generator.
STEAM GENERATOR PRESSURE ISSUES:
The secondary sodium argon cover is installed at an absolute pressure of about 0.1 MPa and normally operates at an absolute pressure of 0.2 MPa. If this pressure rises to 0.3 MPa the loop safety shutdown sequence should be initiated.
The secondary sodium heat transport system should be hydraulically tested at 9 MPa so as to safely manage any combination of steam generator heat exchange tube ruptures.
The general approach is to have a large high pressure rated cushion tank above the secondary sodium circuit. Assume that the secondary sodium is initially at 0.2 MPa. This cushion tank, if working pressure rated for (6 MPa), could safely absorb about 25X its volume of hydrogen gas as the secondary sodium pressure rises from 0.2 MPa to 5 MPa. It can simultaneously discharge hydrogen gas to the atmsophere. Note that the intermediate heat exchanger and its connecting piping should also have a working pressure rating of 5 MPa.
Note that the liquid water flow through the heat exchange tube rupture and into the sodium will stop when the steam generator lower manifold is partially drained. However, the steam flow from both sides of the tube rupture will continue until all the steam in the upper manifold is vented. The over pressure in the sodium must trip a high speed steam pressure relief valve to dischage steam from the upper manifold as fast as possible so that steam does not continue to flow into the sodium.
After the water is expelled from the heat exchange tubes steam will leak through the rupture via both ends of the ruptured tube. The steam in the upper manifold must be vented to stop this process.
There must be protection against liquid sodium hammer in each secondary sodium circuit. This objective is achieved by preventing hydrogen and sodium mixing in the secondary sodium piping. The hydrogen is vented from the argon cover space in the steam generator. The 12 inch diameter sodium inlet pipe connection to the steam generator must be well below the 16 inch diameter hydrogen vent pipe. These pipes require separate connections to the steam generator shell.
STEAM GENERATOR SUMMARY REVIEW:
1) The steam generator is basically an upright shell and tube heat exchanger;
2) The shell side contains liquid sodium at a relatively low pressure. Within the steam generator there is an argon cover gas space at least 18 inches high above the top of the sodium. Above the steam generator and connected to the argon cover gas space is an argon filled 16 inch diamete schedule 80 vent pipe which also serves as the secondary sodium expansion tank. This tank collects and vents any hydrogen gas that forms in the secondary sodium heat transfer loop.
3) The pressure in the gas space over the sodium is monitord by two independent fast response pressure sensors. On th occurence of a transient high pressure, each sensor activates independent relays that implement the heat transport loop shutdown sequence.
4) The tube side of the steam generator contains super heated liquid water on the bottom and steam on top.
5) Near the bottom of the steam generator the vertical tubes have external metal sleeves. The maximum thickness of these sleeves is limited by the distance between adjacent heat exchange tubes. These sleeves extend above the level in the heat exchange tubes where liquid water is in contact with the tube's inner wall. These sleeves locally reduce the temperature drop across the tube wall. In the event of a tube crack in the sleeved portion of the fuel tube the sleeve limits the rate of flow of high pressure water through the crack and into the lower pressure secondary sodium.
6) The upper portions of the vertical heat exchange tubes contain turbulators suspended from the upper manifold. These turbulators enhance heat transfer from the tube wall to the rising water vapor inside the tubes. In the event that the turbulators are blown upwards they should be stopped by the upper manifold cover and should slide back down due to gravity.
7) Due to the top and bottom manifolds the bottom pressure exerted by water/steam in the tubes is the same for all the heat exchange tubes.
8) One external tube connected between the upper and lower manifolds has water level sensors which are used to control the injection water flow rate.
9) The liquid sodium feeds into the shell side of the steam generator below the argon cover space. The liquid sodium flows downwards, snaking around horizontal flow baffles before exiting at the bottom of the shell side.
10) The top and bottom manifolds are approximately twice the diameter of the body of the steam generator. The manifold covers are removable and are held in place by a large number of perimeter bolts. These manifold covers need special gaskets.
11) The bottom manifold contains water. The injection water inlet and drain ports are in the side of the lower manifold, as is the water level sensing tube port
12) The top manifold has a dedicated pressure regulating steam discharge valve, which attempts to maintain 11.25 MPa steam pressure in upper manifold.
13) There is a rupture disk that will vent steam to the atmosphere if the steam pressure regulating valve fails to operate properly.
14) There is a normally open steam pressure release valve which will vent steam to the atmosphere when there is loss of closure solenoid control power and water must be evaporated to remove fission product decay heat. During normal reactor operation this valve is kept closed by a solenoid.
15) If a steam generator tube rupture occurs the high pressure water leaks into the sodium and immediately forms hydrogen gas. The hydrogen rises and mixes with the argon in the cushion tank. The mixed gas presssure rises which raises the pressure throughout the secondary sodium circuit.
16) When the gas pressure becomes sufficient a gravity reset ball check pressure relief valve located at the top of the hydrogen vent pipe opens and hydrogen is vented.
17) On the occurance of a rise in pressure in the shell side of the steam generator electric power to the water injection pump is cut off and multiple drain valves held closed by solenoids open under the water pressure.
18) The steam pressure in the upper manifold drives liquid water in the heat exchange tubes back into the lower manifold.
19) Liquid water will continue to jet through the heat exchange tube rupture and into the liquid sodium until all the tubes are drained of water and the water level in the lower manifold falls significantly below the top of the lower manifold. Hence it is essential to partially drain the lower manifold as fast as possible
20) Even after the water level in the lower manifld is reduced residual steam from the top manifold will leak into the sodium from both sides of the heat exchange tube rupture as long as there is steam pressure in the upper manifold. Hence the upper manifold steam pressure must be rapidly reduced by opening an electrically operated dedicated steam pressure relief valve.
21) There is a redundant hydrogen/argon pressure relief rupture disk to prevent over pressure occuring in the secondary sodium circuit.
22) The lower tube sheet has water side bottom insulation to prevent super heated water boiling in the lower manifold.
23) There are two water level sensors for controlling the steam generator water level under both normal operation and cold shutdown conditions.
24) The hydrogen vent pipe is normally be filled with argon to prevent hydrogen self ignition in the vent pipe at the instant of H2 release.
25) A diagram showing a steam generator in a heat exchange gallery is:________
FNR STEAM GENERATOR NORMAL OPERATION:
The condensate injection pummp inputs condensate water from the turbogenerator condenser at about 50 degrees C and at a pressure of less than 0.1 MPa and raises its pressure to about 11.5 MPa. This pressurized water flows first through the condenser recuperator coil which raises its temperature to about 100 degrees C before the water flows to the steam generator.
Near the bottom of the heat exchange tubes there are external tube sleeves to minimize the heat flux from the secondary liquid sodium into liquid water contacting the inner tube wall. The temperature difference between the two liquids is dropped across the metal tube wall plus the sleeve wall. A thin layer of liquid sodium between the tube outside surface and the sleeve inside surface ensures good thermal contact between the tube and the sleeve. The gap between the tube and the sleeve must be sufficient to allow for differential thermal expansion but not sufficient to allow significant liquid sodium flow circulation within the gap.
To minimize thermal stress in the tube wall and the sleeve wall it is essential to keep the temperature difference across the metal walls within the material rating by ensuring that the liquid water rising into the bottom of the heat exchange tubes sufficiently warm.
In the bottom manifold of the steam generator there is a temperature stratified water bath which normally operates at a maximum temperature of about 315 degrees C. Cool input water from the turbogenerator recuperator flows into a preheating loop which warms the input water before discharging this input water into the bottom manifold of the steam generator. There the input water mixes with the water from the preheating bath before flowing into the sleeved section of the steam generator which operates at about 320 degrees C.
In the bottom manifold of the steam generator due to the higher pressure and lower water temperature there is no steam formation.
The lower portion of the tubed section of the FNR steam generator provides to the water its latent heat of vaporization. The design object is to ensure a layer of steam between the metal tube inner wall and the liquid water column to limit the heat flux per unit area through the wall of the heat exchange tube. Thus the temperature difference across the heat exchange tube wall is minimized. The water evaporates from the water column in the center of the tube forming nearly saturated steam.
In the top portion of the steam generator tubes there is no liquid water. The heat transfer is from hot liquid sodium to water vapor. The water vapor forms a thin boundary layer of hot vapor adjacent to the surface of the heat exchange tubes. The effect of this boundary layer is to reduce the temperature differential across the heat exchange tube wall. Hence the temperature of the heat exchange tube metal is close to the temperature of the liquid sodium, so the thermal stress within the heat exchange tube wall metal is small.
The tubed section of the steam generator acts as a counter current heat exchanger which raises the temperature of the steam from its boiling point at about 320 deg C to about 400 degrees C. At light loads this steam discharge temperature rises to about 440 degrees C. Thus in the top section of the steam generator the overall direction of the secondary sodium flow is downwards.
A pressure regulating steam discharge valve keeps the pressure inside the steam generator upper manifold at 11.25 MPa. This vapor pressure in combination with the properties of water keeps the liquid water film in the tube sections containing a water column at about 320 degrees C.
The upper portion of the steam generator must supply the sensible heat required to raise the steam temperature from 320 C to the steam generator discharge temperature of about 400 C. The upper portion of the tube bundle may also have to supply heat to vaporize small liquid water droplets that the flowing steam carries with it. It is important to vaporize these water droplets to prevent them eroding the down stream steam turbine.
At low thermal loads the secondary liquid sodium flow rate will be low. The secondary sodium return to the intermediate heat exchanger will be at a temperature close to 320 C and kept there by the pressure - temperature relationship maintained by the steam generator steam discharge valve.
At high thermal loads the secondary sodium flow rate is much higher. The secondary sodium circulates faster and delivers more heat to the water filled portion of the steam generator. The injection water pump is forced to speed up to maintain the steam generator water level. However, the temperature difference across the steam generator tube wall is never more than about 25 C.
CONDENSATE AND EMERGENCY WATER INJECTION:
It is necessary to control the injection water pumps to control the water levels in the steam generators. Note that the time constant of this control loop should be small compared to the rate of change of the reactor power which controls the intermediate sodium flow rate. It is important to not reduce the reactor power too quickly to prevent flooding of the steam generator tubes above the sleeves. Such flooding might cause thermal stress damage to the steam generator heat exchange tubes.
A key safety issue on loss of station power is to maintain condensate injection into the steam generators to enable removal of fission product decay heat. On loss of station power the steam generator pressure control valves must close and the steam pressure relief valves must open to reduce the steam pressure in the steam generators so that water injection into the steam generators can occur at a low injection pressure. Dedicated low pressure low power water injection pumps with reliable emergency power should be used. These dedicated pumps should be installed below the bottom of the on-site reserve water tanks to ensure maintenance of pump inlet suction head. When city water is available the reserve water tanks should automatically refill.
At full thermal load the resulting temperature distribution is as follows:
Steam generator water temperature = 320 C
Steam generator steam discharge temperature = 390 C
Secondary sodium inlet temperature = 430 C
Secondary sodium discharge temperature = 330 C
The steam generators are installed to achieve precise pipe alignment with the corresponding intermediate heat exchanger. The steam discharge pipes are potentially more tolerant of alignment error with holes in the outside wall of the heat exchange gallery. These holes can be larger to give more mis-alignment tolerance. Moreover, the steam pipes are long and have multiple elbows to permit thermal expansion/contraction.
STEAM GENERATOR HEAT EXCHANGE AREA:
With the aforementioned steam generator design the temperature difference across a heat exchange tube metal wall and the steam boundary layer is about 40 degrees C. Where the tubes are immersed in liquid water the full load tube wall temperature drop is typically about 10 degrees C.
Assume each intermediate heat exchanger bundle feeds one tall steam generator.
The steam generator must withstand the steam pressure. However, the steam generator has turbulent fluid flow on both sides of its tubes so it can operate with less tube area than the corresponding intermediate heat exchange bundle.
The contemplated steam generator is realized using 20 foot lengths of 24 inch diameter thick wall (610 mm OD) pipe. This pipe is available in 59.54 mm wall thickness to safely contain a pressure of up to 13.7 MPa @ 427 degrees C.
The inside diameter of this pipe is:
610 mm - 2(59.54 mm) = 490.92 mm
As shown elsewhere on this web page each 20 foot long X 2 foot outside diameter steam generator shell will accept 625 X 0.500 ich OD tubes.
Within each such steam generator bundle there is a heat exchange area of:
625 tubes X 230 inches / tube X Pi X (.500 inch - 0.065 inch) = 196,448 inch^2
= 126.74 m^2
The corresponding heat flow rate per bundle limited by Inconel 600 conductivity is:
20.9 Wt / m-deg K X 126.74 m^2 X (1 / .065 inch) X (1 inch / .0254 m) = 1,604,401 Wt / deg K
= 1.604 MWt / deg K
The design target for each heat to electricity conversion subsystem is:
1000 MW / 56 = 17.857 MWt. Thus this target can be met with a tube wall temperature drop of:
17.857 MWt / [(1.604 MWt / deg K)] = 11.133 deg C.
FNR STEAM GENERATOR CONSTRUCTION DETAIL:
Each steam generator has two end manifolds, each rated for the steam generator working pressure (11.25 MPa). The manifolds are nominally 48 inches OD and 58 inches OD when insulated. The manifold covers are removeable for interior access and are held in place by numerous bolts. Pipe connections are made to the manifold sides. However, the 24 inch (610 mm) outside diameter shell wall of the steam generator (Schedule 160 steel pipe) is much more robust than the 24 inch (610 mm) outside diameter shell wall of the intermediate heat exchanger (Schedule 40 steel pipe).
The steam discharge port from each steam generator is 12.75 inch OD and connects to a pressure regulating valve facing the outside wall. There are 2 other 12.75 inch steam discharge ports, one fitted with a steam pressure relief valve and vent and one fitted with a rupture disk and vent. The vents are also fabricated from schedule 160 pipe. One of the design objects is to minimize the volume of steam contained in the upper manifold.
The water inlet to the steam generator lower manifold must be pressure rated for the steam generator working pressure. The lower manifold must have large diameter drain valves and pipes to enable rapid drainage.
Outside the heat exchange galleries are two 24.00 inch OD steam headers. The 12.75 inch OD steam discharge pipes go straight through the heat exchange gallery outside wall and then elbow up to connect to one of the two outside steam headers. The inner header serves the four heat transport systems closest to the air lock. The outer header serves the three heat transport systems furthest from the air lock. This heat transport system to steam header assignment maximumizes free space for use of cranes parked opposite the air locks. Each steam header feeds a dedicated steam turbogenerator.
FNR STEAM GENERATOR TUBE CONFIGURATION:
Assume that in the steam generator there is one central tube surrounded by 15 hexagonal rings of tubes. Then the total number of tubes for such a hexagonal array is:
1 + 6 + 12 + 18 + 24 + 30 + 36 + 42 + 48 + 54 + 60 + 66 + 72 + 78 + 84 + 90
= 7 + 7 (102)
= 715 tubes
Now assume corner clipping to approximate a circle:
The 13th ring loses 1 X 6 = 6
The 14th ring loses 5 X 6 = 30
The 15th ring loses 9 X 6 = 54
Hence the total number of tubes lost is:
6 + 30 + 54 = 90
Hence the number of tubes remaining for use in the steam generator is:
715 - 90 = 625 tubes
The corresponding heat flow rate per steam generator limited by Inconel 600 conductivity is:
= 2567.0 N Wt / tube deg K X 625 tubes = 1,604,375 Wt / deg K
Now assume a staggered lattice tube center to tube center distance space of 0.700 inches.
On the flat hexagon faces the inter-ring distance is:
0.7000 inch X 3^0.5 / 2 = 0.6062177826 inches
The required shell inside diameter is slightly greater than:
31 X 0.6062177826 inches = 18.79275 inches
For the steam generator with a schedule 160 shell the available shell inside diameter is:
610 mm - 2(59.54 mm)
= 490.92 mm /(25.4 mm / inch) = 19.32756 inch
That dimensional choice allows for a
(19.32756 inch - 18.79275 inch) / 2
= 0.2674 inch
= (1 / 4) inch clearance around the tube bundle to allow for shells and tubes with non-ideal dimensions.
The area of a 0.500 inch diameter hole is:
Pi (0.25 inch)^2 = 0.1963495 inch^2
The area of 625 holes is:
625 X 0.1963495 inch^2 = 122.718 inch^2
The steam generator end face area = Pi (19.33 inch / 2)^2
= 293.463 inch^2
Hence the loss of tube sheet material strength due to tube sheet boring is:
122.718 / 293.463 = 0.411817
The loss of inside shell cross sectional area for fluid flow is also 41.18%.
The inside shell open area is:
(100% -41.8%) X 293.463 inch^2
= 170.80 inch^2
= Pi (54.365 inch^2)
= Pi (7.373 inch)^2
= Pi (14.746 inch / 2)^2
which if the sodium flow was vertical would require a 16 inch diameter pipe. However, due to the limited space available for pipe flanges 12.75 inch OD secondary sodium pipes are used. Thus the secondary sodium pipes connecting to the intermediate heat exchanger should be 12.75 inch OD schedule 80.
Due to the large holes in the steam generator shell, the shell material is thick (Schedule 160) and as shown herein the maximum number of steam generator tubes with a 0.70 inch staggered grid is 625 tubes.
Assume a heat exchange tube size of 0.500 inche OD, 0.065 inch wall thickness. The resultind ID is:
0.500 inch - 2 (0.065 inch) = 0.370 inch
= 0.370 inch X 0.0254 m / inch = .0009398 m
Tube cross sectional area
= Pi (.0009398 m / 2)^2
= 6.9368 X 10^-5 m^2
In a tube:
Flow power = force X velocity
= (pressure X area X velocity)
Flow power = kinetic energy / unit time
= (mass / sec) X (velocity)^2 / 2
= (density X area X velocity X (velocity)^2 / 2
Equating the two expressions for flow power gives:
pressure = density X velocity^2 / 2
Velocity = [2 X pressure / density]^0.5
volumetric flow rate = area X [2 X pressure / density]^0.5
mass flow rate = density X area X [2 X pressure / density]^0.5
= area X [2 X pressure X density]^0.5
Hence the maximum flow rate of super heated water through a single heat exchange tube is:
= 6.9368 X 10^-5 m^2 X [ 2 X 11.25 X 10^6 Pa X 1000 kg / m^3]^0.5 = 6.9368 X 10^-5 m^2 X [2 X 11.25 X 10^6 kg m /s^2 m^2 X 1000 kg / m^3]^0.5 = 6.9368 X 10^-5 m^2 X 15 X 10^4 kg / s m^2
= 10.4052 Kg / s
The corresponding rate of production of hydrogen gas is:
(10.4052 kg / s) / 16 = 0.6503 kg / s
At 0 degrees C, 1 atmosphere (.101 MPa), one mole (2 gm) of hydrogen gas occupies 22.4 lit. At 430 deg C one mole of hydrogen occupies [(430 + 273 ) / 273] X 22.4 lit = 57.68 lit. At 4.6 MPa and 430 degrees C 2 gm of hydrogen gas occupies:
57.68 lit X (0.101 MPa / 4.6 MPa) = 1.226 lit
Thus the enclosed volume required to safely absorb the released hydrogen at 4.6 MPa is:
0.6503 kg / s X 1000 g / kg X 1.226 lit / 2 gm X 1 m^3 / 1000 lit
= 0.6503 X 1.226 / 2 m^3 / s = .4118 m^3 / s
Assume that the vent pipe is 16.000 inch OD schedule 80 (0.843 inch wall) so the ID is 14.314 inch. Then the volume of that pipe is:
Pi (14.314 inch / 2 X .0254 m / inch)^2 X L
= 0.10382 m^2 L
Hence if L = 10 m the vent pipe will reach its maximum safe hydrogen pressure of 4.6 MPa in about:
(0.10382 m^2 X 10 m) / (0.4118 m^3 / s) = 2.52 s
Thus on the occurrence of a single tube rupture the 16 inch ball check must move from full closed to full open in about 2.5 seconds.
Another important constraint is how fast it is possible to continuously vent 4.6 MPa of hydrogen through a 16 inch OD vent pipe. Assume that the pipe inside cross sectional area is 0.10382 m^2 as calculated above.
As indicated above the hydrogen gas density at 4.6 MPa is:
2 gm / 1.226 lit = 2 X 10^-3 kg / 1.226 X 10^-3 m^3 = 1.631 kg / m^3
mass flow rate = area X [2 X pressure X density]^0.5
Thus at 4.6 MPa the maximum hydrogen venting rate is:
mass flow rate = 0.10382 m^2 X [2 X 4.6 X 10^6 Pa X 1.631 kg / m^3]^0.5
= 0.10382 m^2 X [2 X 4.6 X 10^6 kg m / s^2 m^2 X 1.631 kg / m^3]^0.5
= 0.10382 X 3.874 X 10^3 kg / s
= 402.20 kg / s
Thus under these circumstances the maximum tolerable number of simultaneous steam generator tube ruptures is:
(402.20 kg / s) / 0.6503 kg / s-tube) = 618.5 tubes
However, the intermediate heat exchangers and the steam generator shell side must also be rated for a 4.6 MPa working pressure at their operating temperature. Hence if the hydraulic pressure testing of the steam generator shell is done at room temperature, the intermediate heat exchanger tube side and the steam generator shell must be subject to a hydraulic pressure test at:
4.6 MPa X 1.5 = 6.9 MPa.
Hence for the secondary sodium we can use schedule 80 pipe and fittings. However, we need a schedule 160 steam generator shell due to the large diameter branch pipes connecting to the shell.
On the occurance of a heat exchange tube rupture the 1st object is to reduce the liquid water level in the lower manifold as fast as possible so that only steam feeds the rupture. The second object is to reduce the steam pressure in the upper manifold as fast as possible to limit the mass of steam ultimately injected into the sodium via the tube rupture.
WATER MASS FLOW RATE:
During normal operation each steam generator must supply:
1000 MWt / 56 = 17.857 MWt of heat to water flowing through it.
= [(380 deg C X 1 cal / gm deg C X 4.186 J / cal) + (1200 J / gm)] [flow rate]
= [17.857 X 10^6 J / s] / [(380 deg C X 1 cal / gm deg C X 4.186 J / cal) + (1200 J / gm)]
= [17.857 X 10^6 gms / s] / [(380 X 4.186) + (1200)]
= [17.857 X 10^6 gms / s] / [2790.68]
= 6398.85 gms / s
= 6.399 kg / s
This web page last updated March 27, 2021
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