Steam generation system having multiple combustion chambers and dry flue gas cleaning

Abstract

A method for producing steam while concurrently reducing emissions. The method includes combusting fuel and an oxidant stream having a high concentration of oxygen in a combustion zone having multiple combustion chambers and heat exchangers to produce a flue gas. The flue gas is subsequently cleaned in a dry flue gas cleaning chamber by contacting it with a dry adsorbent. In one embodiment, the method advantageously regenerates the dry adsorbent so that the dry adsorbent can be subsequently recycled back into the dry gas flue chamber.

Claims

1. A steam-generating oxy-boiler system comprising: an oxidant delivery system for providing an oxidant enriched gas stream having an oxygen content of 75 to 100% by volume; a first combustion chamber in fluid communication with the oxidant delivery system, wherein the first combustion chamber is operable to combust a portion of a fuel stream in the presence of the oxidant enriched gas stream to generate a first product stream comprised of flue gas and non-combusted fuel; a first heat exchanger in fluid communication with the first combustion chamber, wherein the first heat exchanger is operable to remove heat from the first product stream such that the temperature of the first product stream is maintained within a desired range; a second combustion chamber in fluid communication with the first heat exchanger, wherein the second combustion chamber is operable to combust a portion of the non-combusted fuel of the first product stream to produce a second product stream, wherein the second product stream has a greater amount of flue gas as compared to the first product stream, wherein the first combustion chamber further comprises water circulating within walls of the first combustion chamber for regulating the temperature within the first combustion chamber, wherein the second combustion chamber further comprises water circulating within walls of the second combustion chamber for regulating the temperature within the second combustion chamber; a second heat exchanger in fluid communication with the second combustion chamber, wherein the second heat exchanger is operable to remove heat from the second product stream such that the temperature of the second product stream is maintained within a desired range; a flue gas cleaning chamber in fluid communication with the second heat exchanger, the flue gas cleaning chamber having an amount of a solid adsorbent contained therein that is operable to remove, via a chemical reaction, at least a portion of SO.sub.x from the second product stream and an amount of a reducing agent contained therein that is operable to remove, via a chemical reaction, at least a portion of NO.sub.x from the second product stream to produce a third product stream, the third product stream comprising a desulfurized and denitrified flue gas and spent adsorbent, the desulfurized and denitrified flue gas having reduced amounts of SO.sub.x and NO.sub.x as compared to the flue gas within the second product stream, wherein the solid adsorbent and the reducing agent are independently fed into the flue gas cleaning chamber; a precipitating unit in fluid communication with the flue gas cleaning chamber for removing the spent adsorbent from the desulfurized and denitrified flue gas to produce a spent adsorbent stream and a cleaned desulfurized and denitrified flue gas stream; an adsorbent storage tank in fluid communication with the precipitating unit for receiving the spent adsorbent stream; a discharge line in fluid communication with the precipitating unit for sending the cleaned desulfurized and denitrified flue gas stream to a CO.sub.2 recovery unit or to the atmosphere; a reducing gas feed line in fluid communication with the flue gas cleaning chamber for introducing reducing gas to the flue gas cleaning chamber; a regeneration unit in fluid communication with the adsorbent storage tank, the reducing gas feed line, and the flue gas cleaning chamber, the regeneration unit operable to regenerate a portion of the spent adsorbent stream by contacting the spent adsorbent stream with the reducing gas to produce regenerated adsorbent and spent reducing gas, wherein the regenerated adsorbent is then recycled back to the flue gas cleaning chamber; and a sulfur discharge line in fluid communication with the regeneration unit, the sulfur discharge line operable to introduce the spent reducing gas to a sulfur recovery unit, a third heat exchanger in fluid communication with the precipitating unit and the discharge line, the third heat exchanger operable to transfer heat energy from the flue gas stream to a target fluid prior to sending the cleaned flue gas stream to the CO.sub.2 recovery unit or to the atmosphere, wherein the target fluid is the water before circulating within the walls of the first combustion chamber and within the walls of the second combustion chamber; wherein the walls comprise membrane tubes and welded fins connecting the membrane tubes.

2. The system of claim 1, wherein the solid adsorbent has particle sizes in the range of 50 to 500 microns.

3. The system of claim 1, wherein the solid adsorbent is selected from the group consisting of MgO, CaO, and combinations thereof.

4. The system of claim 1, wherein the precipitating unit comprises a first precipitator, the first precipitator operable to remove all of the spent adsorbent from the desulfurized and denitrified flue gas.

5. The system of claim 1, wherein the first heat exchanger is further operable to receive the target fluid from the third heat exchanger and exchange heat between the first product stream and the target fluid such that the temperature of the first product stream is maintained within a desired range.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) These and other features, aspects, and advantages of the present invention will become better understood with regard to the following description, claims, and accompanying drawings. It is to be noted, however, that the drawings illustrate only several embodiments of the invention and are therefore not to be considered limiting of the invention's scope as it can admit to other equally effective embodiments.

(2) FIG. 1 is an embodiment of the present invention.

DETAILED DESCRIPTION

(3) While the invention will be described in connection with several embodiments, it will be understood that it is not intended to limit the invention to those embodiments. On the contrary, it is intended to cover all the alternatives, modifications and equivalence as may be included within the spirit and scope of the invention defined by the appended claims.

(4) In FIG. 1, fuel 2 and oxidant enriched gas stream 4 enter combustion zone CZ and are fed into first combustion chamber 10, wherein fuel 2 combusts to produce flue gas and heat. In one embodiment, oxidant enriched gas stream 4 has an oxygen content between 75% to 100% oxygen by volume. This increased level of oxygen content provides an increased level of desulfurization over lower levels of oxygen content. In a preferred embodiment, the heat is partially transferred to a mixture of liquid water and steam circulating within the walls of the first combustion chamber 10. Preferably, the walls of first combustion chamber 10 are of membrane type tubes having tubes connected by welded fins. The temperature within first combustion chamber 10 can be adjusted by controlling the flow rate of fuel 2 and oxidant enriched gas stream 4 entering first combustion chamber 10. In one embodiment, the temperature is maintained within a range from 800 to 2500 degrees Celsius. In another embodiment, the temperature is maintained within a range from 1000 to 1400 degrees Celsius, in order to help prevent NO.sub.x formation. The flue gas, which in some embodiments can include unreacted fuel and oxygen, exit first combustion chamber 10 via line 12 and passes through first heat exchanger HX1 at a predetermined flow rate such that the temperature of the exiting flue gas is maintained between 200 and 1600 degrees Celsius. The flue gas then enters second combustion chamber 20 via line 14, wherein additional fuel is combusted to produce additional flue gas and heat. If there is not enough unreacted fuel or oxygen in line 14, then a fresh makeup stream of fuel 6 and/or oxidant 8 can be added to second combustion chamber 20. Similar to the behavior of first combustion chamber 10, the flue gas exits second combustion chamber 20 via line 22 and passes through second heat exchanger HX2 at a predetermined flow rate such that the temperature of the flue gas in line 24 is maintained between 200 and 1600 degrees Celsius.

(5) The cooled flue gas then enters dry flue gas cleaning chamber 30 and is contacted with adsorbent 26 in order to remove the sulfur oxides from the flue gas. Adsorbent 26 is a solid and could be of any type that allows for removal of sulfur oxides from flue gases. Preferably, adsorbent 26 will be recoverable in order to reduce the production of by-products. In one embodiment, the particle size of adsorbent 26 can be between 50 and 500 microns. Exemplary adsorbents include MgO and CaO.

(6) In one embodiment, dry flue gas cleaning chamber 30 is equipped with one or more injectors that allow for homogenous dispersion of the adsorbent within dry flue gas cleaning chamber 30. Recycled flue gas can be used to improve the dispersion of the adsorbent within dry flue gas cleaning chamber 30. Depending upon the temperature of the flue gas in line 24, the walls of dry flue gas cleaning chamber 30 may or may not be of the membrane type like first combustion chamber 10 and second combustion chamber 20. In embodiments in which the temperature of the flue gas in line 24 is between 800 and 1100 degrees Celsius, a reducing agent such as urea or ammonia can be injected into dry flue gas cleaning chamber 30 along with adsorbent 26 in order to remove the nitrogen oxide.

(7) Flue gas and spent adsorbent travel to first precipitator 40 via line 32. In one embodiment, first precipitator 40 is a cyclone. First precipitator 40 separates the flue gases from the spent adsorbent. The cleaned flue gases can sometimes contain fine-adsorbent particles. In these situations, the cleaned flue gases are sent to second precipitator 50 via line 42 in order to remove the remaining adsorbent particles. Examples of second precipitator 50 can include an electrostatic precipitator type or fabric filter bag type. The removed adsorbent particles are evacuated through line 51 and sent with the adsorbent removed from first precipitator 40 via line 44 to adsorbent storage tank 60. The cleaned flue gases exit second precipitator 50 through line 52 and pass through one or several heat exchangers (HX3, HX4). Preferably, third heat exchanger HX3 is fed with saturated steam to produce super-heated steam that can be fed to first heat exchanger HX1 or second heat exchanger HX2. Fourth heat exchanger HX4 is preferably fed with liquid water in order to increase its temperature before being used in the walls of first combustion chamber 10 and/or second combustion chamber 20.

(8) After passing through third heat exchanger HX3 and fourth heat exchanger HX4, the cleaned flue gas is split into two streams, with recycle stream 56 being used to help recycle regenerated adsorbent back to dry flue gas cleaning chamber 30. CO.sub.2 recovery stream 58 can be sent to a carbon dioxide recovery unit for additional process, or alternatively released to the atmosphere.

(9) The spent adsorbent travels from first precipitator 40 to adsorbent storage tank 60 via line 44. In a preferred embodiment, gases produced from other parts of the system, such as nitrogen or cleaned flue gas, may be used to transport the spent adsorbent throughout the system. From adsorbent storage tank 60, the spent adsorbent travels to adsorbent regenerator 70 via line 62, where the spent adsorbent is contacted with a regeneration gas 64. Adsorbent regenerator 70 can be any reactor that allows efficient contact of the spent adsorbent and the regeneration gas, such as fluidized bed, fixed bed, or moving bed reactor. Preferred regeneration gases include hydrogen, methane, ethane, propane, and combinations thereof. Any other light hydrocarbon that is operable to react with the adsorbent can also be used as a regeneration gas. Spent regeneration gas exits adsorbent regenerator 70 via line 74 and can be sent to a sulfur recovery unit (not shown). Regenerated adsorbent leaves adsorbent regenerator 70 and can be combined with recycle stream 56 en route to dry flue gas cleaning chamber 30.

(10) In an alternate embodiment, a portion of the spent adsorbent can be recycled back to dry flue gas cleaning chamber 30 via line 61 before being sent to adsorbent regenerator 70. This allows the adsorbent to be used multiple times, which advantageously improves the desulfurization efficiency of the system.

(11) In an alternate embodiment, third heat exchanger HX3 is not required since the adsorption of the sulfur oxides within dry flue gas cleaning chamber 30 occurs at a temperature that is not compatible with superheating steam after dry flue gas cleaning chamber 30. For example, in an embodiment in which the temperature within line 32 is at or less than the boiling point of water, third heat exchanger HX3 is not required.

Example 1

(12) In this example, magnesium oxide (M.sub.gO) is used as the dry adsorbent to remove the sulfur oxide from the produced flue gases. The system combusts an oil heavy residue having a composition (in mass basis) according to Table I.

(13) TABLE-US-00001 TABLE I Fuel Composition in ppm Carbon Hydrogen Sulphur Nitrogen Metals 84 9 6 1 290e6

(14) The Low Heating Value (LHV), which represents the amount of energy contained in the fuel, is estimated at 38 MJ/kg. The system is designed to produce about 100 MW of superheated steam at 480 C. and 80 bar. The oxidizer composition is given in Table II in mass basis.

(15) TABLE-US-00002 TABLE II Oxidizer Composition Oxygen Nitrogen Argon 95 3 2

(16) Based on fuel composition and oxidizer composition, the flue gas composition exiting the combustion zone and prior to the dry flue gas cleaning chamber is given in Table III in mass basis.

(17) TABLE-US-00003 TABLE III Flue Gas Composition CO.sub.2 H.sub.2O N.sub.2 O.sub.2 SO.sub.2 A.sub.r 68.41 23.16 1.92 2.02 2.67 1.83

(18) The temperature at the entry of the dry flue gas cleaning chamber was adjusted to 1000 C. in order to optimize the adsorption of sulphur oxides. The basic reaction for adsorption and regeneration of the adsorbent are:

(19) Oxidation of SO.sub.2:
SO.sub.2+1/2O.sub.2SO.sub.3

(20) Adsorption of SO.sub.3:
M.sub.gO+SO.sub.3M.sub.gSO.sub.4

(21) Regeneration of the Used Adsorbent:
H.sub.2+M.sub.gSO.sub.4SO.sub.2+H.sub.2O+M.sub.gO
H.sub.2S+M.sub.gSO.sub.4SO.sub.2+H.sub.2O+M.sub.gO+S

(22) A catalyst can be used in order to increase the conversion of SO.sub.2 in the oxidation reaction. This catalyst can be any materials that have the property of improving the oxidation of SO.sub.2 to SO.sub.3 for example a cerium oxide CeO. The regeneration gas is a mixture of hydrogen H.sub.2 and hydrogen sulphur H.sub.2S.

(23) The molar ratio between magnesium and fuel sulphur (M.sub.g/S) was adjusted according to the adsorbent residence time in the dry flue gas cleaning chamber. With an M.sub.g/S ratio at nine and a residence time in the dry flue gas cleaning chamber of two seconds, a desulphurization ratio of 94% can be achieved. Table IV displays the composition of the resulting cleaned flue gas in mass basis.

(24) TABLE-US-00004 TABLE IV Desulfurized Flue Gas Composition CO.sub.2 H.sub.2O N.sub.2 O.sub.2 SO.sub.2 A.sub.r 70.17 23.76 1.97 2.07 0.16 1.87

Example 2

(25) The same procedure was run for Example 2, with the exception that the oxygen levels of oxidant stream were increased to 100%. Table V and Table VI below provide a summary of the temperature, flow rates, and resulting composition data of various streams throughout the system.

(26) TABLE-US-00005 TABLE V Temperature, Flow Rate, and Composition Data of Various Streams Stream 4 2 12 22 Temperature ( C.) 25 230 1344 1344 Flow rate (kg/s) 4.2 1.3 5.8 12 Stream composition (wt %) CO.sub.2 71.22 72.57 H.sub.2O 23.90 22.46 SO.sub.2 2.77 2.83 O.sub.2 100 0.12 2.14 N.sub.2 Ar H.sub.2S M.sub.gO M.sub.gSO.sub.4 CeO.sub.2 Fuel 100

(27) TABLE-US-00006 TABLE VI Temperature, Flow Rate, and Composition Data for Additional Streams Stream 26 32 58 61 64 74 72 Temperature ( C.) 20 695 180 695 1128 700 700 Flow rate (kg/s) 0.004 17.34 12 5.34 1.36 1.52 1.2 Stream composition (wt %) CO.sub.2 38.3 74.55 74.55 76.9 40.86 36.36 H.sub.2O 23.07 23.07 13.3 14.31 SO.sub.2 0.17 0.17 1.18 9.85 O.sub.2 11.7 2.2 2.2 N.sub.2 Ar H.sub.2S 15.12 10.03 H.sub.2 0.38 0.27 M.sub.gO 45 0.004 48.5 69.84 M.sub.gSO.sub.4 0.004 44.47 21.61 CeO.sub.2 5 0.001 7.04 8.56 S 29.16 29.18 Fuel

(28) While the invention has been described in conjunction with specific embodiments thereof, it is evident that many alternatives, modifications, and variations will be apparent to those skilled in the art in light of the foregoing description. Accordingly, it is intended to embrace all such alternatives, modifications, and variations as fall within the spirit and broad scope of the appended claims. The present invention may suitably comprise, consist or consist essentially of the elements disclosed and may be practiced in the absence of an element not disclosed.