CA1221754A - Steam generator control systems - Google Patents

Abstract

Abstract of the Disclosure Steam Generator Control Systems Control systems (or controllers) for once through, unfired stream generators (or boilers) which control a single parameter -- the feedwater flow to the boiler -- in accord with an energy or enthalpy balance between the hot gases supplied to the boiler and the steam generated in it. These control systems have a predictive mode of feedwater control and, optionally, an operator selectable, feedback mode to compensate for drifts in the predictive mode. Other corrections may also be made, and predictive and corrective flow splits can be provided to obtain maximum efficiency when the control system is utilized to regulate the operation of a dual pressure boiler.

Description

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Description Steam Generator Control Systems Technical Field _ This invention relates to control systems and, more particularly, to novel, improved control systems for unfired generators (or boilers) of the once-through type.
Background Art Conventional steam boilers have a number of economic shortcomings and cause many operating problems in combined cycle applications, particularly those of small capacity using gas turbines in the 4000-25000 Ow range. Among the major contributors to these drawbacks are the complex systems utilized to control the operation of combined cycle power plant boilers Typical prior art control systems for combined cycle power plants are disclosed in US. Patent Nos. 3,505,811 to Underwood and 2,965,765 to Mart et at.
The complex prior art boiler control systems tend to have large numbers of components that are subject to malfunction which makes maintenance costs high and reduces boiler availability. Also, attended operation may be required for safe and efficient boiler operation.
The present invention is directed to overcoming one or more of the problems as set forth above.

Disclosure of the Invention In one aspect of the present invention, a steam generator control system includes an unfired boiler; a source of thermal energy for the boiler;

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means for effecting a flow of feed water to the boiler;
and a controller for controlling the operation of the boiler. The controller includes means operable in a predictive mode of operation for periodically calculating the energy available to the boiler from the thermal energy source and the quantity of dry steam having a set point temperature which is an assigned or calculated number of degrees lower than the temperature of the thermal energy source that can be generated by the trouncer of the energy to the feed water. The system also includes means under the direction of the controller for so modulating the flow of feed water to the boiler as to supply to the boiler the quantity of feed water that can be turned into steam of the specified temperature by the transfer of the thermal energy thereto.
The present invention provides novel controllers designed around the philosophy that an unfired boiler can be so controlled as to efficiently produce steam of acceptable quality by regulating a single operating parameter; viz., the flow of feed water to the boiler. An energy or enthalpy balance is struck between the ho-t gases supplied to the boiler and steam at a specified temperature relative to the temperature of those gases (the approach temperature) because steam quality and boiler efficiency are closely related to steam temperature, and the flow of feed water is so regulated that the steam is produced at the selected (approach set point) temperature. The herein disclosed boiler operation controllers are simple, reliable, inexpensive, and capable of providing safe and efficient unattended boiler operation.

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Brief Description of the Drawings Figure 1 is a schematic view of a combined cycle power plant with a boiler and illustrating one embodiment of the present invention;
Figure 2 is a schematic illustration of one controller which can be employed to control the operation of the boiler shown in Figure l;
Figure 3 is a schematic illustration of a subsystem that can be added to the controller of Figure 2 to afford more accurate control over the operation of the boiler;
Figure 4 shows, graphically, the effect of different types of control on boiler operation;
Figure 5 shows, schematically, a subsystem which can be added to the controller of Figure 2 in applications involving dual pressure boilers to make the operation of the boiler more efficient; and Figure 6 is a schematic representation of yet another subsystem that can be used in conjunction with that shown in Figure 5 to make the operation of a dual pressure boiler more efficient.

jest Mode for Carrying Out the Invention Referring now to the drawing, Figure 1 depicts a combined cycle power plant 20 which includes: a gas turbine engine 22 drive connected to an alternator 24;
a boiler 26 in which steam is generated by thermal energy recovered from the hot gases exhausted from gas turbine engine 22; and a steam turbine I also drive connected to alternator 24 and employing the steam produced in boiler 26 as a motive fluid.

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In power plant 20, steam turbine 28 also drives the exemplary load; in this example an alternator 24. However, it can equally well be employed to drive a load which is different from the load briny driven by gas turbine engine 22.
For the most part, the components of power plant 20 are of conventional or otherwise familiar construction Those components will be described herein only to the extent necessary for an 10 understanding of the present invention.
The illustrated gas turbine engine is of conventional configuration; it includes a compressor 30, a combustor 32, a gas producer turbine 34 for driving compressor 30, and a power turbine 36. Hot 15 gases exhausted from power turbine 36 at a temperature in the range of 427-4~2C are dueled to, and flow through, the casing 38 of steam generator 26.
Normally, these gases will be exhausted to atmosphere through stack 40 at a temperature of about 112C.
20 The heat thus recovered in steam generator 26 is 21-25%
higher than can be recovered in the unfired boilers heretofore employed in combined cycle power plants.
The boiler 26 illustrated in Figure 1 has a once-through, dual pressure configuration. It includes 25 a steam generating module 42 which, in one actual boiler design in accord with the principles of the present invention, is made up of forty steam generating circuit assemblies each including a high pressure tube 46 and a low pressure tube 48. In each ox these tubes 30 a phase change of water to saturated steam and a change from saturated steam to superheated steam occurs in a continuous flow path extending from the inlet 50 (or 52) to the outlet 54 (or 56) of the tube as the water flows downwardly through the -tube in efficient, 35 counterfoil relationship to the flow of the hot gas .: .

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turbine engine exhaust gases. Thus, different regions in each tube function as a feed water heater, as a vaporizer, and as a superheater.
High pressure steam generated in tubes 46 of boiler 26 slows into the high pressure section of dual pressure steam turbine engine 28, and low pressure steam flows into the low pressure section of the turbine.
A number of desirable attributes such as reduced maintenance and operating costs, simplification of automatic operation, and elimination of possibilities for operator error are obtained by the use of corrosion resistant materials in boiler 26, thereby eliminating the need for controlling pi and for chemically and/or mechanically controlling the dissolved oxygen content of the boiler feed water. To this end, tubes 46 and 48 are made of such a material, typically a nickel-chromium-iron containing, high temperature and corrosion resistant alloy.
Steam exhausted from turbine 28 flows into a conventional condenser 62 where the steam is condensed. This component may be, as examples, a water or air cooled condenser of conventional design Condensate accumulates in hot well 64 which contains the small inventory of feed water needed for boiler 26.
That only a small inventory of feed water is needed to operate boiler 26 is of considerable practical importance. The large mass of saturated water contained in the drums of a conventional boiler, and eliminated in the novel boilers disclosed herein is a safety hazard and has produced widespread legislation requiring attended operation of steam boilers. By eliminating this large mass of saturated water, the requirement for attended operation can also be eliminated. This is cost effective and, also, facilitates remote, unattended operation of combined cycle power plant 20.
From hot well I the condensed steam is circulated by condensate pump 66 to a condensate polisher 68. were, dissolved solids are removed from the condensate which is then pumped to steam generator 26 by feed water pump 70 through a modulating type flow control valve 72. This valve is controlled by a system lo embodying the principles of the present invention, and discussed in detail hereinafter, which matches the feed water flow rate to the enthalpy in the hot gases supplied to the steam generator from gas turbine 22.
us indicated above, it has unexpectedly been found that the fabrication of those boiler components wetted by aqueous fluids eliminates the need for chemically removing dissolved oxygen from the feed water supplied to boiler 26 or for controlling the pi of the feed water. However, physical removal of dissolved gases as by hot well decoration will typically be necessary to maintain an adequate pressure drop across the system. Hot well decoration is effected by a vacuum pump 78 connected to hot well 64 through condenser 62. Oxygen evacuated from the hot well and condenser by the vacuum pump typically contains appreciable amounts of entrained water. Consequently, the evacuated air is pumped into a conventional separator 80. Air is discharged from separator 80 to atmosphere, and water is returned through trap 82 from separator 80 to condenser 62.
One of the important advantages of the steam generators disclosed herein is that the requirement for make-up of feed water is nominal. For example one boiler of the type disclosed herein is planned to produce 6,998 kilograms of team per hour at one I

exemplary design point. Make-up water requirements for this boiler are less than 2.4 liters per hour. In contrast, make-up water requirements for a conventional slowdown boiler of comparable capacity are about 170 liters per hour.
Such make-up water as is required is first circulated through a demineralize 84 to remove dissolved and suspended solids from the water and then supplied to hot well 64 through make-up water line 86.
Referring still to the drawing, Figures 2 and

3 show, schematically, one flow control system (or flow controller) 88 in accord with the principles of the present invention for regulating the flow of feed water to boiler 26 by modulating the flow of the Editor through flow control valve 72.
Flow controller 88 employs the above-discussed strategy of recovering the maximum amount of thermal energy from the hot gases supplied to boiler 26 without adjusting the flow of fuel to or otherwise predicating the operation of gas turbine engine 22 on conditions in the boiler; that is, the operation of boiler 26 is subordinated or slaved to the operation of the gas turbine engine.
This strategy can be followed and safe, efficient operation of boiler 26 obtained in an extremely simple fashion by controlling only the flow of feed water to the boiler, this control being so effected as to maintain only one parameter within specified limits. This parameter is the approach temperature of boiler 26 which is defined as the temperature of the hot gases supplied to the boiler minus the temperature of the high pressure steam generated in the boiler.
Controller 88 achieves this goal by calculating the energy available from the hot gases supplied to boiler 26 and the maximum amount of steam that can thereby be produced within the foregoing constraint and adjusting feed water flow valve 72 accordingly.
The energy added to the feed water to generate steam equals the energy recoverable from the gas turbine engine exhaust gases. Because outlets 54 and 56 (see Figure 1) are fixed restrictions, that energy balance can be approximated by:
(C TOW hug) Wow = Was Gas gas 10 where:
CpFW = the average specific heat of steam on the water side of the boiler at design point, TO out Tin = the increase from feed water temperature to steam outlet temperature, hug = the latent heat of vaporization of water, IT gas = the change in temperature of turbine exhaust gases in the boiler, Wow = the mass flow of feed water through the boiler, W = the mass flow of hot gas gas supplied to the boiler from the gas turbine engine as calculated from measured operating parameters of gas turbine engine 22, and Gas = the specific heat of the hot gases supplied to the boiler.
Certain set points were established to optimize the generation of steam in the boiler 26 of combined cycle power plant 20. The first was that the g temperature of the gas leaving the boiler should be 221 F. Thus, Togas = Togas - 221 F, where Togas is the temperature of the gas being supplied to boiler 26 and is a measured parameter. The specific heats Gas and CpFw were assigned average values of Gas = 0.25 and CpF~ = 0.53~. The water inlet temperature, Tin, is relatively constant and was assigned an average value of 92 F.
With the foregoing, the feed water equation can be rewritten as follows:
gas (Togas 221 F) Gas (2) CPFW ( HP gas fog The term hug is relatively constant and was replaced by an assigned value. As CpF~ and Tin are relatively constant, values assigned to these parameters were multiplied together and added algebraically to the value assigned to hug. The resulting figure was 920.
As discussed above, the maximum amount of dry steam (within constraints) can be produced if Top, the outlet steam temperature, is kept within a specified number of degrees of Togas. This difference, termed the approach temperature, Tarp =
T -- T
yes HP-The expression (Top - Togas) is preferably replaced by one which takes the wanted approach temperature into account, and is:
HP SET POINT gas i ASP
where Tarp is an assigned value or is calculated from Togas Thus with all assigned values substituted, the feed water flow control algorithm becomes:
0~25 gas (Togas 221) (3) O o 538 Top SET POINT

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The only variables in the open loop, predictive mode of operation afforded flow controller 88 by the feed water flow control algorithm (3) are the mass flow and temperature of the gases supplied to boiler 26.
The mass flow of exhaust gases available from turbine 22 (Was) is proportional to the speed of gas producer turbine 34 for any given ambient temperature of the air introduced into compressor 30.
Consequently, controller 88 is designed to convert the speed and ambient air temperature information from sensor 90 and 92 into a mass flow value. This can be done with a conventional function generator 94 designed to make the calculations shown in graphical fashion in Figure 2. The Was value and the gas temperature (measured by a sensor 96 such as a thermocouple) are transmitter to calculation block 98 as is the selected TOP SET POINT. Calculation block 98 solves the equation or algorithm I discussed above, generating a feed water flow signal WIFE. This signal is transmitted to the (typically) electropneumatic actuator (not shown) of feed water flow valve 72 to regulate the flow of feed water to boiler 26 in accord with the operating strategy discussed above.
In one exemplary controller embodying the principles of the present invention, the input data for the feed water flow control equation is collected at a rate of ten times per second, and Wow is recalculated after each update in the input data. The significant result of updating the input data and recalculating Wow at this frequency is that the feed water flow rate is for all practical purposes based on a prediction rather than results at the boiler input. This is important because the transit time of the water through 75~

the boiler is measured in minutes; and, if output results were the only control factor, regulation of the feed water flow would be based on obsolete data.
Figure 4 shows, graphically, the effect on steam temperature (and thus steam quality) of a temperature change in the hot gases supplied to boiler 26. In the case of a rapid drop in the exhaust gas temperature and no feed water control, the steam temperature will drop; and the steam will rapidly lo become saturated (undesirable) as shown by curve 100.
On the other hand, if the feed water flow is regulated by the predictive flow control equation discussed above, the feed water flow will be decreased as the gas temperature drops as shown by curve 102. As a result, the steam temperature will stabilize at a temperature approaching the selected set point as shown by curve 104.
Even better control over the generation of steam in boiler 26 can be gained in some circumstances by adding to the open loop, predictive mode flow control discussed above the feedback loop 106 shown in Figure I. Typically, this closed loop mode of control will be made operator selectable.
The closed loop, feedback mode of control is employed to compensate for inherent drifts in the predictive flow control equation (drift factors may cause significant errors in the predictive equation).
Drift may be caused by, for example, miscalibration of valve 72, fouling of steam generating tubes 46 and 48, inaccuracies in the mass flow calculation made by function generator 94, and signific variations in TEXT from the assigned value.

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In the closed loop mode of boiler control a corrected feed water flow rate and a Editor flow correction factor WCLcF are generated in accord with the equations:
FWTOTAL FOE WCLCF
and WCLCF = -[(TOGAS TARP) TOP] KCLCF
where:
FATUITY = the newly computed feed water flow including the closed loop correction, in lb/hr, Top a the measured high pressure outlet steam temperature, and KCLCF = a gain coefficient for converting temperature to feed water flow.
The gain coefficient is assigned a value of

4 lb/hr/F, Tarp = 80 if TOGAS 720, and The reason for adopting a variable approach temperature is that a fixed approach temperature does not guarantee a sufficient margin of superheat when gas turbine engine 22 is operating under part load The steam output temperature, Top, is measured by any desired technique, for example by a thermocouple, and summed i an adder 108 with TOP SET POINT.
This produces an error signal which is converted as by a conventional PI controller 110 into a control signal compatible with that generated in function generator 98. This latter signal is inverted in inventor 112 and summed with the predictive 75~

Editor flow (Wow) signal in adder 114, producing the new feed water flow comlnand signal (Fly TOTAL for operating the electropneumatic actuator of feed water flow control valve 72.
Curve 116 in Figure 4 shows how the feed water flow is regulated when the closed loop correction factor is used in conjunction with the predictive flow value to control valve 72. In the same Figure, curve 117 shows that this combination of predictive and closed loop modes of operation can be taken advantage ox to maintain the steam output temperature at the selected set point.
It is of course theoretically possible to control future flow solely by the use of a feedback loop as shown in Figure 2 without simultaneously employing predictive flow control. However, Figure 4 makes it clear that this will not provide the desired results; viz., the generation of dry steam and the maximum recovery of thermal energy (which requires that JO the steam temperature be maintained as closely as possible to the steam temperature set point). If the gain in the feedback control is set low, the result of a change in gas temperature as shown in Figure 4 is over damping as indicated by curves 118 and 119, and the steam rapidly becomes saturated. On the other hand, if a high gain feedback correction signal is employed to control the feed water flow, oscillation occurs as indicated by curves 1~0 and 122; and unstable, inefficient boiler operation with periodic generation of saturated steam is the result.
It is preferred, in feed water flow control systems employing the principles of the present invention, that the actual feed water flow be measured and that any differences between the measured and command values be employed to correct the feed water 75~

flow. A subsystem for accomplishing this function in controller 88 is illustrated in Figure 3 and identified by reference character 128.
In this subsystem, the flow of steam from boiler 26 is measured and converted to a measured feed water flow rate in function generator 130. This signal is summed with the feed water flow command signal Wow or WIFE TOTAL in adder 132. The resulting error signal is converted to a new feed water flow command signal in a fast response (POD) controller 134; and the new command signal is utilized to operate the electropneumatic actuator of feed water flow control valve 72.
As discussed above, the illustrated boiler 26 is of the dual pressure type, including as it does two independent circuits composed respectively of tubes 46 and 48 in which steam is generated at high and low pressures. Optimal operation of a boiler within he principles of the present invention can be furthered by splitting the dual pressure feed water flow between the tubes 46 and 48 in accord with a particular flow split;
viz., that obtained by dividing the high pressure steam flow by the low pressure steam flow.
A subsystem designed to provide this additional degree of control is illustrated in Figure 5 and identified by reference character 138.
As in the case of predictive feed water flow, the feed water split or ratio can be determined from the ambient temperature of the air supplied to gas turbine engine compressor 30 and the speed of gas producer turbine 34. The values of these two parameters, obtained from sensors 90 and 92, are combined into a flow split signal by function generator 140 in accord with the calculations shown graphically in Figure 5.
This flow split or ratio signal is applied to the operator (again typically electropneumatic) of a flow proportioning valve 142 in series with feed water flow control valve 72 (see Figure 1) to proportion the flow of feed water between the high and low pressure steam generating tubes 46 and 48 in boiler 26.
Also, in the case of dual pressure boiler, boiler operation is preferably further optimized by employing feedback to correct the feed water Flow split signal.
Specifically, as shown in Figure 5, the controller for a dual pressure boiler may have an input a Top SET POINT which is analogous to, and provided for essentially the same purposes as, the TOP SET POINT discussed above; viz., to insure an adequate degree of superheat in the low pressure steam and maximum recovery of the heat from the hot gases on which boiler 26 is operated.
In the feedback mode of operation, which again is preferably operator selectable, the temperature of the low pressure steam is measured as by a thermocouple, and the resulting signal is summed with that representing Top SETpoINT
The resulting error signal is converted to a control signal in PI controller 144, and is inverted in inventor 146. This produces a signal which is combined with the feed water flow split command signal from function generator 140 in adder 148, producing a command signal which is, again, applied to the actuator of proportioning valve 142.
Still another degree of refinement, and increase in boiler performance, can be obtained in the case of a dual pressure boiler by comparing the actual split of feed water with the predictive flow split and adjusting flow proportioning valve 142 accordingly.
This subsystem is shown in Figure 6 and identified by reference character 150.

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In the illustrated subsystem, the flow of high pressure and low pressure steam from boiler 26 are measured and signals indicative of the resulting mass flows converted to a flow split value in function

5 generator 152 in accord with the equation:
Split FEW LPFW HP ( 6) LUFF LO
where:
WLPFW = the low pressure steam flow, and FEW LOW = the high pressure steam flow.
The resulting signal is summed with the flow split command signal from function generator 1~0 or adder 1~8 in adder 154, producing an error signal which is converted to a command signal in POD controller 156. That signal is inverted in inventor 158 and, as discussed previously, applied to the actuator of flow proportioning valve 142.
It is reiterated, in conjunction with the foregoing detailed description of the invention, that the novel feed water flow controllers described herein are across-the-board applicable to once through, unfired boilers. In particular, as the control strategy involves only an energy or enthalpy balance between the hot gases supplied to the boiler and steam generated in the boiler, and as the only variable inputs to the controller can be measured or calculated gas temperature and mass flow) or can be assigned constant values, it will be readily apparent to the reader that the principles of the present invention are applicable independent of the source of the waste heat.
The invention may be embodied in other specific forms without departing from the spirit or essential characteristics thereof. The present embodiment is therefore to be considered in all respects as illustrative and not restrictive, the scope of the invention being indicated by the appended claims rather than by the foregoing description; and all changes which come within the meaning and range of equivalency of the claims are therefore intended to be embraced therein.

Claims (9)

Claims

1. The combination of an unfired boiler; a source of thermal energy for said boiler; means for effecting a flow of feedwater to said boiler; a controller for controlling the operation of said boiler, said controller including means operable in a predictive mode of operation for periodically calculating the energy available to said boiler from said thermal energy source and the quantity of dry steam having a setpoint temperature which is an assigned or calculated number of degrees lower than the temperature of the thermal energy source that can be generated by the transfer of said energy to said feedwater; and means under the direction of said controller for so modulating the flow of feedwater to said boiler as to supply to said boiler the quantity of feedwater that can be turned into steam of said specified temperature by the transfer of said thermal energy thereto.

2. A combination as defined in claim 1 wherein said controller includes means for measuring the temperature of the steam discharged from said boiler and for adding a signal representative of that temperature to a signal representative of the setpoint temperature to generate an error signal, means for converting said error signal to a feedwater flow correction signal, means for adding said feedwater flow correction signal to a flow indicative signal generated in said predictive mode of operation to generate a corrected flow command signal, and means for transmitting said corrected flow command signal to said flow modulating means.

3. A combination as defined in claim 1 or 2 wherein said controller has means for generating a signal indicative of the flow of the feedwater actually passed through said boiler, means for adding said signal to said flow correction signal to generate an error signal, means for converting said error signal to a further corrected flow command signal, and means for transmitting said further corrected flow command signal to said flow modulating means.

4. The combination of an unfired boiler having a high pressure steam generating circuit means and a low pressure steam generating circuit means, a source of thermal energy for said boiler, means for effecting a flow of feedwater to said boiler, a controller for controlling the operation of said boiler, said controller including means for periodically calculating the energy available to said boiler from said thermal energy source and the quantity of dry steam that can be generated by the transfer of said energy to said feedwater, means under the direction of said controller for so modulating the flow of feedwater to said boiler as to supply to said boiler the quantity of feedwater that can be turned into steam as aforesaid by the transfer of said thermal energy thereto, and means for proportioning the flow of feedwater between said high pressure steam generating circuit means and said low pressure steam generating circuit means in accord with the equation where:

WHP is the mass flow of the steam generated in the high pressure steam generating circuit means, and WLP is the mass flow of the steam generated in the low pressure steam generating circuit means.

5. A combination as defined in claim 4 which has a feedwater flow proportioning means upstream of said high and low pressure steam generating circuit means and wherein said controller has means for generating first and second signals indicative of the flow of the feedwater actually passed through said boiler and through said low pressure steam generating circuit means, means for converting said first and second signals to a flow split signal in accord with the equation where:
WFW is the total measured flow of feedwater through the boiler, and WLPFW is the measured flow of the feedwater through the low pressure steam generating circuit means;
means for adding the just mentioned flow split signal to the flow split signal indicative of the proportioning of said feedwater between said high and low pressure steam generating circuit means to create a flow split error signal, means for converting said error signal to a flow split command signal, and means for transmitting said flow split command signal to said feedwater flow proportioning means.

6. A combination as defined in claim 4 or 5 wherein said controller has means as aforesaid for calculating the quantity of steam having a setpoint temperature which is an assigned or calculated number of degrees lower than the temperature of the thermal energy source that can be generated by the transfer of said energy to the feedwater supplied to said high pressure steam generating circuit means, means for measuring the temperature of the steam discharged from said high pressure steam generating circuit means and for adding a signal representative of that temperature to a signal representative of the setpoint temperature to generate an error signal, means for converting said error signal to a feedwater flow correction signal, means for adding said feedwater flow correction signal to a flow indicative signal generated in said predictive mode of operation to generate a corrected flow command signal, and means for transmitting said corrected flow command signal to said flow modulating means.

7. The combination of an unfired boiler, a source of thermal energy for said boiler, means for effecting a flow of feedwater to said boiler, means for effecting a flow of hot gases from said thermal energy source to and through said boiler, a controller for periodically calculating the energy available to said boiler from said thermal energy source and the quantity of dry steam that can be generated by transfer of said energy from said hot gases to said feedwater in accord with the algorithm:

where:

WFW = the mass flow of feedwater through the boiler, CPFW = the average specific heat of the steam on the water side of boiler at design point, .DELTA.TFW = Tout - Tin = increase from feedwater temperature to steam outlet temperature, hfg = the latent heat of vaporization of water, .DELTA.Tgas = the change in temperature of the hot gases in the boiler, Wgas = the mass flow of hot gas as supplied to the boiler from the thermal energy source, and Cgas = the specific heat of the hot gases supplied to the boiler;
and flow control means for modulating the flow of feedwater to said boiler at the rate WFW calculated by said controller and thereby supplying to said boiler the quantity of feedwater that can be turned into said steam by the transfer of said thermal energy thereto from said hot gases.

8. The combination of an unfired boiler, a source of thermal energy for said boiler, means for effecting a flow of feedwater to said boiler, means for effecting a flow of hot gases from said thermal energy source to and through said boiler, a controller for periodically calculating the energy available to said boiler from said thermal energy source and the quantity of dry steam that can be generated by transfer of thermal energy said to feedwater from said hot gases to said feedwater in accord with the algorithm:

W = where:
WFW = the mass flow of feedwater through the boiler, Wgas = the mass flow of hot gases supplied to the boiler from the thermal energy source, Tgas = the change in temperature of the hot gases in the boiler, and THP SETPOINT = the selected temperature at which steam is to be discharged from the boiler, and flow control means for modulating the flow of feedwater to said boiler at the rate WFW calculated by said controller and thereby supplying to said boiler the quantity of feedwater that can be turned into said steam by the transfer of said thermal energy thereto from said hot gases.

9. A combination as defined in claim 7 or 8 wherein said controller has means for adding a correction factor to the feedwater flow value WFW to compensate for drift in accord with the algorithim:

FWTOTAL = WFW = WCLCF' where:
WCLCF = -[(TGAS - TAPP) - THP] KCLCF
and:
FWTOTAL = the newly computed feedwater flow including the correction, THP = the measured high pressure outlet steam temperature, TAPP = TGAS - THP, TCLCF = a gain coefficient for converting temperature to feedwater flow, TAPP = 80 if TGAS ? 720, and TAPP = 68 - if TGAS <720.