Field of the Invention

The present invention relates to a method, apparatus and system for reducing the concentration of sulfur oxides ("SOx") and nitrogen oxides ("NOx") in the flue gases emitted by the combustion of fossil fuels in, for instance, coal- fired power plants. As such, the present invention stands to bring forth perceptible

environmental benefits when reduced to practice on an industrial scale.

The invention will be discussed hereinafter with reference to its potential use within a coal-fired power station. Power stations of this type burn coal, which in turn gives rise to flue gases rich in SOx and NOx (amongst other contaminants). The technology is applicable to both retrofit of existing coal-fired power plants and new coal- fired power plants. However, it will be appreciated that the invention is not necessarily limited to these specific fields of use.

Background of the Invention

Any discussion of the prior art throughout the specification should in no way be considered as an admission that such prior art is widely known or forms part of common general knowledge in the field.

It is widely accepted that coal- fired power plants cause great harm to the environment. Such power stations use rotating machinery to convert the heat energy of combustion into mechanical energy, which in turn operates an electrical generator. The prime mover may be a steam turbine, a gas turbine or, in small plants, a reciprocating internal combustion engine. All plants use the energy extracted from expanding gas (i.e., steam or combustion gases).

It is widely appreciated that oxides of carbon (i.e., C0 ₂ , CO) are notorious polluters of the atmosphere. However, the various oxides of other elements are also greatly significant. The flue gases produced from the combustion of fossil fuels are ultimately discharged to the air. These gases contain carbon dioxide and water vapor, as well as the oxides of other elements, mercury, traces of other metals, and (for coal- fired plants), fly ash.

In this respect, two of the most renowned flue gas polluters are the oxides of nitrogen (NOx) and sulfur (SOx). The processes by which these gases are removed from flue gases are termed "desulfurisation" ("de-SOx") and "denitrification" ("de- NOx"), respectively. Emission of SOx and NOx from coal- fired power plants can give rise to acid rains, heavy smog, etc., which are major public concerns on a global basis. The pollution of air has also caused serious health problems to various communities throughout the world. As such, SOx and NOx removal is becoming critically important nowadays in countries where coal is fired intensively to meet the high demand of electricity, in particular, the most heavily populated countries such as China and India.

Worldwide, there are over 50,000 active coal-fired power plants - and this number is expected to grow; the world's power demands are expected to rise 60% by 2030. Furthermore, there remains sufficient coal within un-mined mineral deposits with which to satisfy global electricity demand for at least another fifty years. It is estimated that fossil fuels will account for 85% of the world's energy market by 2030.

Due to the chemical composition of coal there are significant practical difficulties in removing impurities from the solid fuel prior to its combustion.

However, modern coal- fired power plants pollute less than older designs due to new "scrubber" technologies that filter the exhaust gases in flue gas stacks/chimneys. However emission levels of various pollutants are still on average several times greater than for natural gas-fired power plants.

As mentioned above, acid rain is caused by the emission of NOx and SOx. These gases may be only mildly acidic themselves, yet when they react with the atmosphere, they create acidic compounds such as sulfurous acid, nitric acid and sulfuric acid which then fall as rain. Stricter regulatory emission laws and a decline in heavy industries have to some extent reduced the environmental hazards associated with this problem - nonetheless, acid rain remains a significant environmental concern.

In 2008, the European Environment Agency (EEA) documented fuel- dependent emission factors based on actual emissions from power plants in the

European Union. As the below data clearly show, NOx and SOx (by way of sulfur dioxide) are two of the chief pollutants discharged into the atmosphere in flue gases. Hard coal combustion emissions of 292 g/GJ and 765 g/GJ, respectively, when offset against the annual global fossil fuel energy production of around 8500 TWh (2008) puts into some perspective just how much NOx and SOx is potentially discharged into the atmosphere each year.

Table 1: Chief environmental contaminants in flue gases (EU; 2008)

Flue gas stacks serve to disperse exhaust pollutants and thereby reduce the concentration of such pollutants to levels required by governmental environmental regulations. However, although consistent with the myth that "dilution is the solution to pollution", it will be appreciated that flue gas stacks are not, of themselves, the answer - the same net amount of SOx and NOx eventually ends up in the atmosphere.

However, not all NOx and SOx that is generated will be discharged into the atmosphere. The art is replete with methods of capturing these pollutants at source. To this end, flue gas desulfurisation ("FGD") refers to a set of technologies used to remove SOx from exhaust flue gases. As stringent environmental regulations regarding SOx emissions have been enacted in many countries, SOx remediation technologies have evolved to encompass a variety of methods, including: "wet scrubbing" {i.e., using a slurry of alkaline sorbent, usually limestone or lime, or seawater to "scrub" gases); "spray-dry scrubbing" {i.e., using similar sorbent slurries); wet sulfuric acid ("WSA") processes, which recover sulfur in the form of commercial quality sulfuric acid; "SNOX" FGD (discussed below); and dry sorbent injection systems. For a typical coal- fired power station, FGD processes may remove up to 95% of the SOx in the flue gases.

SNOX FGD removes sulfur dioxide, nitrogen oxides and particulates from flue gases. The sulfur is recovered as concentrated sulfuric acid and the nitrogen oxides are reduced to free nitrogen. The process is based on the well-known WSA process for recovering sulfur from various process gases in the form of commercial quality sulfuric acid. In the SNOX process, SOx and NOx are removed separately, in different reactors. The process is based on catalytic reactions and does not produce any waste, except for the separated dust. In addition, the process can handle other sulfurous waste streams. The SNOX process catalytically reduces both SOx and

NOx concentrations in flue gases by up to 95% and with integration of the recovered heat from the WSA condenser it may also give rise to attractively low operating costs.

The SNOX technology is especially suitable for cleaning flue gases from the combustion of high-sulfur fuels. SNOX is a very energy- efficient means to convert the NOx in the flue gas into nitrogen and the SOx into concentrated sulfuric acid of commercial quality without using any absorbents and without producing significant waste.

Most FGD systems employ two stages: one for fly ash removal {i.e., filtering of the particulate matter) and the other for SOx removal. In wet scrubbing systems, the flue gas normally passes first through a fly ash removal device, either an electrostatic precipitator or a wet scrubber, and then into the SOx absorber.

However, in dry injection or spray drying operations, the SOx is first reacted with the sorbent, and then the flue gas passes through a particulate control device. Another design consideration associated with wet FGD systems is that the flue gas exiting the absorber is saturated with water and still contains some SOx. These gases are highly corrosive to any downstream equipment such as fans, ducts, and stacks.

SOx (specifically, S0 ₂ ) is an acidic gas; the sorbent slurries or other materials used to remove the S0 ₂ from the flue gases are thereby typically alkaline. The reactions taking place in a "wet scrubbing" step, using limestone (equation 1) or lime (equation 2) slurries both produce calcium sulfite. The problem is that the slurries are circulated through the scrubber instead of a solution; this makes it harder on the equipment. Wet scrubbing with a magnesium hydroxide slurry produces magnesium sulfite (equation 3); and wet scrubbing with sodium hydroxide (equation 4) is limited to smaller combustion units because it is more expensive than lime, but it has the advantage that it forms a solution rather than a slurry; this makes it easier to operate. It produces a "spent caustic" solution of sodium sulfite/bisulfite (depending upon the pH), or sodium sulfate that must be disposed of.

S0 ₂ ( _g ) + CaC0 ₃ (s)→ CaS0 ₃ ( _s) + C0 ₂ ( _g)

S0 _{2 (g)} + Ca(OH) _{2 (s)} → CaS0 _{3 (s)} + H ₂ 0 ₍₁₎

S0 _{2 (g)} + Mg(OH) _{2 (s)} → MgS0 _{3 (s)} + H ₂ 0 ₍₁₎

S0 _{2 (g)} + NaOH _(s) → NaS0 _{3 (s)} + H ₂ 0 ₍₁₎

To partially offset the cost of the FGD installation, the calcium sulfite can be further oxidised to produce saleable gypsum (equation 5):

CaS0 _{3 (s)} + H ₂ 0 ₍₁₎ + ½0 _{2 (g)} → CaS0 _{4 (s)} + H ₂ 0 ₍₁₎ ...(5)

In industry, a 50 degree Baume solution of sodium hydroxide is often used to scrub S0 ₂ , producing sodium sulfite (equation 6):

S0 _{2 (g)} + 2NaOH _(aq) → Na ₂ S0 _{3 (aq)} + H ₂ 0 ₍₁₎ ...(6)

To promote maximum gas-liquid surface area and residence time, a number of wet scrubber designs have been used, including spray towers, Venturis, plate towers, and mobile packed beds. Because of scale build-up, plugging, or erosion, the trend is to use relatively simple scrubbers such as spray towers; the configuration may be vertical or horizontal, and flue gas can flow co-currently, counter-currently, or cross-currently with respect to the liquid. The chief drawback of spray towers is that they require a higher liquid-to-gas ratio requirement for equivalent S0 ₂ removal than other absorber designs.

For simultaneous removal of S0 ₂ and fly ash, venturi scrubbers can be used. Although removal of both particulate matter and S0 ₂ in one vessel can be economical, the problems of high pressure drops and finding a scrubbing medium to remove heavy loadings of fly ash are clear drawbacks. However, in cases where the particle concentration is low, such as from oil-fired units, it can be more effective to remove particulate matter and S0 ₂ simultaneously. Of course, this does not extend to the products of coal combustion.

A packed bed scrubber consists of a tower with packing material inside to maximise the contact area between the dirty gas and liquid. Packed towers typically operate at much lower pressure drops than venturi scrubbers and are therefore somewhat cheaper to operate. They also typically offer higher S0 ₂ removal efficiency. The drawback is that they have a greater tendency to plug up if particulate matter is present in excess in the exhaust air stream, which makes them unsuitable for remediating flue gases from coal- fired power stations.

Statistically-speaking, approximately 85% of the FGD units installed in the United States are wet scrubbers, 12% are spray dry systems, and 3% are dry injection systems. The highest S0 ₂ removal efficiencies (> 90%) are achieved by wet scrubbers and the lowest (< 80%) by dry scrubbers. The capital, operating and maintenance costs per short ton of S0 ₂ removed (US$; 2001) are: for wet scrubbers larger than 400 MW, the cost is $200 to $500 per ton; for wet scrubbers smaller than 400 MW, the cost is $500 to $5000 per ton; for spray dry scrubbers larger than 200 MW, the cost is $150 to $300 per ton; and for spray dry scrubbers smaller than 200 MW, the cost is $500 to $4,000 per ton.

More recently, a new FGD technology has emerged; it is a radiation technology where an intense beam of electrons is fired into the flue gas at the same time as ammonia is added. The Pomorzany power plant in Poland is the best-known example of such a process being effected on a commercial scale. However, the industrial sized scale-up has been beset by problems by way of breakdown and maintenance. On the other hand, aside from the "clean" removal of SOx, a byproduct of this new process is ammonium sulfate, which can be used as a nitrogenous fertiliser.

An alternative to removing sulfur from flue gases after burning is to remove it before or during combustion. Hydrodesulfurisation of fuel has been used for treating fuel oils before use, but is to this point, undeveloped with respect to coal. A recently-developed biological de-SOx method combines gas purification with sulfur recovery. Micro-organisms in a bioreactor oxidise the sulfide to elemental sulfur. This elemental sulfur is then separated and finally recovered at the end of the process for further usage in, for example, agricultural products. Safety is one of the greatest benefits of this method, as the whole process takes place at atmospheric pressure and ambient temperature. However, the process is extremely slow - and thereby unsuitable for scale-up to an industrial sized operation.

As can be readily deciphered from the above discussion, there are several processes by which flue gases can be remediated with varying degrees of efficiency and/or environmental detriment - especially as it pertains to SOx and/or NOx gases. To generalise, SOx and NOx removal is conventionally carried out in two separate units. Many existing FGD processes using wet-scrubbers consume vast quantities of water. This, in turn, gives rise to potential environmental concerns and increases operation costs. Many de-SOx and de-NOx technologies also require the injection of ammonia. All these practical and environmental restrictions point to one need, which is the integration of de-SOx and de-NOx technologies, with a concomitant reduction in water usage, capital and operating costs.

Rahmaninejad, et al., in Applied Catalysis B: Environmental, 119-120, (2012), pp.297-303, discloses a dry, regenerable, CuO/Al ₂ 03 catalyst for

simultaneous removal of SOx and NOx from flue gas.

Richter, et al., in Gas Separation and Purification, Vol.1, (1987), discloses active coke processes for S0 ₂ /NOx removal.

It is an object of the present invention to overcome or ameliorate at least one of the disadvantages of the prior art, or to provide a useful alternative.

It is an object of a preferred form of the present invention to provide a flue gas remediation process that may effectively remove SOx and NOx from a flue gas within a single reactor, thereby aiding efficiencies. Ideally, such a process would be a dry, or substantially dry method, avoiding the need for vast quantities of water and the subsequent and damaging contamination thereof.

Unless the context clearly requires otherwise, throughout the description and the claims, the words "comprise", "comprising", and the like are to be construed in an inclusive sense as opposed to an exclusive or exhaustive sense; that is to say, in the sense of "including, but not limited to".

The present invention is directed to a means of "removing" SOx and NOx from flue gases. Of course, "removing" is not to be construed as an absolute term, i.e., the invention does not need to reduce the concentration of SOx and/or NOx from its initial concentration to 0% in order to adequately "work". In this context, remediation, per se, is properly considered with respect to SOx and NOx

concentrations present in flue gases, if emitted straight into the atmosphere. As such, the invention properly relates to a method of reducing the concentration of SOx and/or NOx in flue gases - preferably to levels in accordance with environmental regulations. The SOx concentration in flue gases produced in a coal-fired power plant is typically about 1200-2400 ppmv; the concentration of NOx is typically about 100-500 ppmv.

Although the invention will be described with reference to specific examples it will be appreciated by those skilled in the art that the invention may be embodied in many other forms.

Brief Description of the Drawings

A preferred embodiment of the invention will now be described, by way of example only, with reference to the accompanying drawings in which:

Figure 1 is a schematic representation of a preferred embodiment of the present invention. The overall process flow can be summarised as depicted (AH: air heater; ESP: electrical static precipitator; FB: fixed bed).

Figure 2 is a schematic diagram depicting the process of the present invention. Flue gas and the sorbent catalyst are actively brought into chemical contact at a temperature of between 300 °C and 400 °C in a counter-flow relationship within the reactor Rl;

Figure 3 is a graph depicting de-SOx efficiency of the copper-based

(Cu _x iFe _x2 Mn _X3 Ce _x4 Zn _x5 ) sorbent catalyst over time. Two temperatures were tested (Tl 350 °C; T2 300 °C). The catalyst worked at optimum efficiency for nearly 1000 hours (for T2) and 1400 hours (for Tl); it would then be subjected to regeneration, as described below.

Figure 4 is a graph depicting de-NOx efficiency of the copper-based (Cu _x iFe _x2 Mn _X3 Ce _x4 Zn _x5 ) sorbent catalyst over time. Two temperatures were tested (Tl 350 °C; T2 300 °C). The catalyst worked at optimum efficiency for nearly 900 hours (for T2) and about 1400 hours (for Tl); it would then be subjected to regeneration, as described below.

Summary of the Invention

According to a first aspect of the present invention there is provided a catalyst sorbent of the general formula Cu _x iFe _x2 Mn _X3 Ce _X4 Zn _X 5, wherein: xl is 30-60%; x2 is 20-40%; x3 is 10-15%; x4 is 1-5%; and x5 is 0.1-0.3%. Alternatively, there is provided a catalyst sorbent of the general formula Co _x iFe _X2 Mn _x3 Ce _X4 Zn _x5 , wherein: xl is 30-60%; x2 is 20-40%; x3 is 10-15%; x4 is 1-5%; and x5 is 0.1-0.3%.

Copper and cobalt have been exemplified for the purposes of the present invention. However, those skilled in the art will recognise that any transition metal having good reductant properties can be used within the context of the present invention.

In an embodiment, the catalyst is operatively supported on an activated char. Preferably, the activated char has a mesoporosity of about 40-60%. The mesoporous nature of the char provides, on the on hand, a substrate upon which the catalyst sorbent is deposited - and on the other hand, provides the additional advantage that trace mercury present in the flue gas adsorbs onto said active char support, thereby to actively remove mercury from the flue gas.

In an embodiment, the catalyst is adapted for use in a process for lessening the concentration of sulfur oxides ("SOx") and nitrogen oxides ("NOx") in flue gas.

In an embodiment, the process takes place at a temperature of between about 300 °C and about 400 °C.

In another embodiment, the mesoporosity provides for mercury to adsorb onto said active char support, thereby to actively remove mercury from a flue gas.

In another embodiment, the catalyst sorbent is adapted for recycling or regeneration, thereby to return a spent catalyst sorbent to its original state, having its original catalytic activity.

According to a second aspect of the present invention there is provided a process for lessening the concentration of sulfur oxides ("SOx") and nitrogen oxides ("NOx") in flue gas, said process comprising the steps of:

supplying a feed stream of flue gas to a reactor, said reactor comprising a sorbent bed;

chemically associating said stream of flue gas with said sorbent bed, thereby to actively chemically reduce said SOx and said NOx and to provide an exhaust stream of substantially remediated ("de-SOx" and "de-NOx") flue gas;

wherein said sorbent bed comprises an active char support of the general formula Cu _x iFe _x2 Mn _X3 Ce _X4 Zn _X 5, wherein: xl is 30-60%; x2 is 20- 40%; x3 is 10-15%; x4 is 1-5%; and x5 is 0.1-0.3%.

Alternatively, the sorbent bed comprises an active char support of the general formula Co _x iFe _X2 Mn _x3 Ce _X4 Zn _x5 , wherein: xl is 30-60%>; x2 is 20-40%>; x3 is 10-15%; x4 is 1-5%; and x5 is 0.1-0.3%.

Preferably, the method further comprises the step of exhausting said remediated flue gas to a flue gas stack. Preferably, the method further comprises the step of extracting, from a regeneration unit operatively associated with said sorbent bed, sulfuric acid as a by-product of the reduction of said SOx and said NOx.

In an embodiment, said active char support has a mesoporosity of about 40- 60%). Preferably, said mesoporosity provides for mercury present within said feed stream of flue gas to adsorb onto said active char support, thereby to actively remove mercury from said flue gas.

In an embodiment, the parameters of the process are as follows: residence time 2-16 minutes; operating temperature 350-400 °C for the de-SOx/de-NOx unit; and 750-850 °C for the regeneration unit.

In an embodiment, the process can be characterised as being substantially

"dry" by comparison with a SNOX FGD process. In an embodiment, the process takes place at a temperature of between about 300 °C and about 400 °C.

In an embodiment, the flue gas and the catalyst sorbent are chemically associated in a counter-flow arrangement.

In an embodiment, in said regeneration unit, spent catalyst sorbent is heated to flash sulfur trioxide gas, said sulfur trioxide then reacted with water to form said sulfuric acid; and the resultant regenerated catalyst sorbent returned to said reactor. Preferably the flashing of sulfur trioxide occurs at a temperature of about 750 °C. In an embodiment, spent catalyst is able to be regenerated up to about 1000 times.

According to a third aspect of the present invention there is provided use of a catalyst sorbent operatively supported on an active char support, the catalyst of the general formula Cu _x iFe _x2 Mn _X3 Ce _X4 Zn _X 5, wherein: xl is 30-60%; x2 is 20-40%>; x3 is 10-15%>; x4 is 1-5%; and x5 is 0.1-0.3%), in a process for lessening the concentration of sulfur oxides ("SOx") and nitrogen oxides ("NOx") in flue gas. Alternatively, the active char support is of the general formula Co _x iFe _X2 Mn _x3 Ce _X4 Zn _x5 , wherein: xl is 30-60%; x2 is 20-40%; x3 is 10-15%; x4 is 1-5%; and x5 is 0.1-0.3%.

In an embodiment, said active char support has a mesoporosity of about 60%. Preferably, said mesoporosity provides for mercury within said flue gas to adsorb onto said active char support, thereby to actively remove mercury from said flue gas.

Preferably, the flue gas and the catalyst sorbent are chemically associated in a counter-flow arrangement. In a preferred embodiment, use within the process can be characterised as substantially "dry" by comparison with a SNOX FGD process.

According to a fourth aspect of the present invention there is provided an apparatus for lessening the concentration of sulfur oxides ("SOx") and nitrogen oxides ("NOx") in flue gas, said apparatus comprising:

means for supplying a feed stream of flue gas to a reactor, said reactor comprising a sorbent bed;

means for chemically associating said stream of flue gas with said sorbent bed, thereby to actively chemically reduce said SOx and said NOx and to provide an exhaust stream of substantially remediated ("de-SOx" and "de-NOx") flue gas;

wherein said sorbent bed comprises an active char support of the general formula Cu _x iFe _X2 Mn _x3 Ce _X4 Zn _x5 , wherein: xl is 30-60%>; x2 is 20- 40%; x3 is 10-15%; x4 is 1-5%; and x5 is 0.1-0.3%.

Alternatively, the active char support is of the general formula

Co _x iFe _x2 Mn _x3 Ce _x4 Zn _x5 , wherein: xl is 30-60%; x2 is 20-40%; x3 is 10-15%; x4 is 1- 5%; and x5 is 0.1-0.3%.

In an embodiment, the apparatus further comprises means for exhausting said remediated flue gas to a flue gas stack. In another embodiment, the apparatus further comprises a regeneration unit operatively associated with said sorbent bed; and means for extracting sulfuric acid therefrom, said acid being a by-product of the reduction of said SOx and said NOx.

In an embodiment, the active char support has a mesoporosity of about 60%.

Preferably, the mesoporosity provides for mercury present within said feed stream of flue gas to adsorb onto said active char support, thereby to actively remove mercury from said flue gas.

In a preferred embodiment of the invention, the apparatus is for use within a substantially "dry" process for lessening the concentration of sulfur oxides ("SOx") and nitrogen oxides ("NOx") in flue gas by comparison with a SNOX FGD process.

In an embodiment, the apparatus is adapted for operation at a temperature of between about 300 °C and about 400 °C. Preferably, said flue gas and said catalyst sorbent are chemically associated in a counter-flow arrangement.

The invention also relates to a process for making the catalyst sorbents described above. Such a method comprises the general steps of: loading the active components into lignite coal; then gasifying the coal using steam at about 850 °C for about 20-30 minutes. It is found that the catalyst sorbents produced by such process are chemically reactive and facilitate high de-SOx and de-NOx removal efficiencies.

In an embodiment, the overall process flow can be summarised as shown in

Figure 1 of the accompanying drawings.

According to a fifth aspect of the present invention there is provided a method for making a catalyst sorbent as defined according to the first aspect of the present invention, said method comprising the steps of:

loading the active components (Cu _x iFex2Mn _X3 Ce _X4 Zn _X 5 or

Co _x iFe _X 2Mn _x3 Ce _x4 Zn _X 5, wherein: xl is 30-60%; x2 is 20-40%; x3 is 10-15%; x4 is 1-5%; and x5 is 0.1-0.3%) into lignite coal;

gasifying the coal using steam at about 850 °C for about 20-30 minutes. According to a broad description of the invention, there is provided a dry integrated flue gas de-SOx and de-NOx technology ("DIFGDSN"), which provides for the efficient simultaneous removal of S0 ₂ and NOx in one dry unit, with the additional advantage that mercury is removed also. The capital investment and operational cost of a unit deploying the present invention is expectably on the same scale of a single SCR (selective catalytic reduction) unit, which can in turn, lead to operational and cost efficiencies.

Preferably, the overall efficiency of the simultaneous SOx and NOx removal will meet with governmental environmental standards. The technology is applicable to both the retrofit of existing power plants (e.g., to replace the old FGD units) and new power plants in which both de-SOx and de-NOx are now mandatory under government environmental requirements.

The following table provides for a summary of the present invention, relating to a DIFGDN process, with conventional (separate) de-SOx and de-NOx

technologies.

Table 2: Summary of comparative advantages of the present invention

The inventive process has at least the following distinguishing characteristics over conventional de-SOx/de-NOx processes: Firstly, the FB reactor unit uses an inventive sorbent supported on an activated char. Accordingly, the new composition of active components is defined according to the general formula:

Cu _x iFe _X2 Mn _x3 Ce _X4 Zn _X 5, wherein: xl is 30-60%; x2 is 20-40%; x3 is 10-15%; x4 is 1- 5%; and x5 is 0.1-0.3%. Alternatively, the new composition of active components is defined according to the general formula: Co _x iFex2Mn _X3 Ce _X4 Zn _X 5, wherein: xl is 30- 60%; x2 is 20-40%; x3 is 10-15%; x4 is 1-5%; and x5 is 0.1-0.3%.

The five components are impregnated onto the activated char support. The active char support has a mesoporosity of about 60%, which permits high reactivity of the active constituents and conveniently facilitates the adsorption of mercury thereupon.

It is found that the FB reactor using the inventive sorbent can simultaneously remove SOx and NOx (and mercury) from a flue gas, which cannot be achieved using existing flue gas cleansing technologies and processes.

The mechanism of S0 ₂ removal is through the reaction between S0 ₂ and the active components:

S0 ₂ + 0 ₂ + MO→ MS0 ₄ Simultaneously, the active constituents act as a catalyst for NOx removal:

NOx + C→ N ₂ + C0 ₂

The NOx is reduced to nitrogen gas through the catalytic reactions between NOx and the carbon in the activated char. The activated char support, having mesoporosity, also permits the adsorption of the mercury with subsequent removal thereof from the flue gas.

Although the invention has been described with reference to specific examples it will be appreciated by those skilled in the art that the invention may be embodied in many other forms. It will be appreciated by one skilled in the art that the invention described above provides for the efficient simultaneous removal/reduction in the concentration of SOx and NOx from flue gases by the chemical reduction thereof on a sorbent bed of copper-based char (or cobalt-based char).

The above-described invention is clearly industrially-applicable. Existing power stations could be retrofitted with this technology and/or the inventive process could be incorporated within designs for new power stations. The invention is especially applicable to power stations in regions of the world where a low-grade (highly contaminated) coal is used; this in turn results in more contaminated flue gas, having relatively high concentrations of SOx and NOx.

Description of a Preferred Embodiment of the Invention

With reference to Figure 2 of the accompanying drawings, the inventive process is represented according to a schematic diagram. The process utilises two reactors. Firstly, there is provided a fixed-bed reactor (Rl) in which de-SOx and de- NOx of flue gases are effected; and a second fixed-bed reactor (R2), which is the regeneration unit described in further detail below. Although the process can be effected both on a continuous or a batch basis, it has been described hereinafter as a continuous process.

Reactor Rl is a fixed bed reactor comprising a catalyst sorbent (1) of the general formula Cu _x iFex2Mn _X3 Ce _X4 Zn _X 5, wherein: xl is 30-60%; x2 is 20-40%; x3 is 10-15%; x4 is 1-5%; and x5 is 0.1-0.3%. The sorbent catalyst is operatively supported on an activated char having a mesoporosity of about 40-60%. In other embodiments, cobalt can be used instead of copper. However, as described herein, the copper sorbent catalyst is used.

Flue gas (2) generated by the burning of coal enters the reactor (Rl) via a flue gas inlet port (3). The temperature of the gas (2) is typically about 130 °C prior to entering the reactor. The temperature within the reactor (Rl) is generally about 300- 400 °C; as such, the flue gas gains significant kinetic energy from the heat ramp upon entry into the reactor (Rl).

The reactor (Rl) is equipped with a sorbent exit port (4), through which spent sorbent catalyst (1) is transmitted, preferably under gravity, to the regeneration reactor (R2) via a conduit (5). The temperature within the regeneration reactor (R2) is about 750 °C; such high temperature vaporises S0 ₃ adsorbed previously onto the surface of the sorbent catalyst (1). The vaporised SO ₃ then exits the regeneration reactor (R2) via a conduit (6) to a further reactor (R3) whereupon it is dissolved into water to form sulfuric acid, which in turn exits the reactor (R3) via a conduit (7). The concentrated sulfuric acid is preferably commercial grade - and can be on-sold if desired.

Returning now to the regeneration reactor (R2), once the SO ₃ has been flashed from the surface of the catalyst (1), the catalyst is, by these means, then essentially refreshed or regenerated. The regeneration reactor has an exit port (8) through which regenerated sorbent catalyst (1) exits the reactor (R2). The regenerated catalyst is then transmitted back to the reactor (Rl) via a conduit (9); this could be under pressure or by mechanical transmission. The regenerated sorbent catalyst (1) then enters the reactor (Rl) at an entry point (10) near the top of the reactor. From there, it moves downward under gravity.

As such, it will be appreciated that the sorbent catalyst (1) performs (with respect to the schematic depicted in Figure 2) a "clockwise" cyclic movement from the reactor (Rl) to the reactor (R2), back to the reactor (Rl) - and so forth.

Returning now to the flue gas (2), the "raw" gas (i.e., containing a relatively high concentration of NOx and SOx) moves in a counter-flow relationship to the sorbent catalyst (1). That is, as the sorbent catalyst moves "downward" through the reactor (Rl), the flue gas (2) moves "upwards" as depicted by the dotted path (11). As such, the relatively raw (i.e., SOx and NOx concentrations are relatively high) flue gas (2) entering the reactor (Rl) first encounters relatively spent sorbent catalyst (1) (i.e., near the bottom of the reactor (Rl)); this spent sorbent catalyst (1) is essentially at the end of its cycle - and soon moves to the regeneration reactor (R2) as described above. On the other hand, the relatively raw flue gas moves upward through the reactor (Rl) in counter- flow to the sorbent (1), thereby encountering progressively fresher (less spent) catalyst (1) as it progresses upward.

By the time the flue gas (2) reaches the "top" of the reactor (R2), it has been remediated (for the purposes of the present invention, the SOx and NOx

concentrations have been reduced); the remediated flue gas (1) then exits the reactor (Rl) via an exit port (12). The temperature of the remediated gas is around 300 °C - and the remediated gas can then be exhausted to a flue gas stack (not shown) - or can undergo secondary cleansing (e.g., to remove particulate matter) via an ESP, etc.

It has been found empirically that the sorbent catalyst (1) can be regenerated via reactor (R2) at least around 1000 times before it loses its effectiveness. One reason why the catalyst (1) is not regenerable indefinitely is that the mesoporosity (typically 40-60%) traps mercury within the pores. Mercury is present in flue gases only in trace amounts. However, as will be appreciated, after 1000 or so passes, the pores do become somewhat clogged.

It is also found that the optimum residence time for the flue gas within the reactor (Rl) {i.e., the time taken to effect de-SOx and de-NOx) is somewhere between 2 and 16 minutes.

It is also found empirically, with particular reference to Figure 3 and Figure

4, that nearly 100% of SOx and NOx can be removed from raw flue gases using the invention described above.

Although the invention has been described with reference to specific examples it will be appreciated by those skilled in the art that the invention may be embodied in many other forms.

Industrial Applicability

The industrial applicability of the present invention is palpable. The scale of environmental damage caused by the combustion of fossil fuels has been identified above - and any invention that provides means by which such damage may be lessened or even reversed has clear industrial potential.