FR2924951A1 - PROCESS FOR CO- OR TRI-GENERATION WITH IMPLEMENTATION OF A FIRST AND A SECOND H2S CAPTURE UNITS AND / OR PARALLEL OPERATING CO2. - Google Patents

Abstract

A method of co- or tri-generation, using an adiabatic compressor assembly - gas turbine associated with a gasifier or at least one catalytic vapor reforming unit, characterized in that said method uses at least a first and a second unit for capturing H2S and / or CO2, carried by at least one combustible gas and a non-combustible gas, operating in parallel.

Description

The present invention relates to a method of co- or tri-generation using an adiabatic compressor - gas turbine assembly associated with a gasifier or at least one catalytic vapor reforming unit, characterized in that said method comprises at least a first and a second unit for capturing H2S and / or CO2 carried by at least one combustible gas and a non-combustible gas operating in parallel.

Catalytic vapor reforming means a catalytic process for producing a mixture consisting mainly of hydrogen and carbon monoxide in the presence of water vapor. Cogeneration is a high efficiency energy production system, typically between 80% and 90%. In the most advanced industrial applications, the efficiency can reach and sometimes exceed 95%. A properly designed cogeneration plant offers better yields than any conventional boiler, and is one of the most energy-efficient techniques for using fossil and renewable energy. When the load is a solid fuel, one of the previous methods directed towards the maximum production of electricity is to implement a conventional IGCC scheme (Integrated Gasification Combined Cycle Power Plant = Combined cycle with integrated coal gasification). The combined cycle plant with integrated coal gasification (IGCC) is the most advanced technology. An IGCC facility is a combined gas turbine (TAG) and steam turbine (TAV) facility, supplemented by an upstream coal gasification facility to convert solid fuel into gaseous fuel. However, a gas cleaning plant is used after the gasification plant to give the gas a quality that can be treated by the gas turbine.

However, such a process leads to high CO2 emissions due to the very high carbon content of a solid fuel.

Due to the need to control greenhouse gas emissions, cogeneration and even fossil fuel-based electricity generation units may become very expensive to operate as a result of the implementation of a tax on greenhouse gas emissions such as CO2. From there, it becomes essential to review these production patterns in order to integrate the elements or conditions necessary for CO2 capture. However, the studies carried out so far show that the simple addition, on an existing scheme, of a CO2 capture equipment generates additional costs that can be significant (> 25%) while seriously penalizing the conversion efficiency. combined cycle (-9 to 12% points) and cogeneration processes with specific CO2 capture costs still well above the expected 20 / tonne. The most commonly proposed solutions consist in integrating CO2 capture equipment in post- or pre-combustion or oxyfuel combustion to allow direct CO2 production due to the absence of nitrogen in the oxidizer. In case of post-combustion CO2 capture, a chemical absorption system of CO2 is generally proposed to be placed on the low-pressure fumes of the gas turbine, but the associated disadvantages are high. Indeed, because of the excess air used in the gas turbine, the CO2 is highly diluted and its mass content falls below 13% or even up to 5% depending on the carbon content of the fuel. This does not favor its capture at low pressure and requires the use of very high affinity absorbents for a low CO2 partial pressure capture, so chemical absorption.

The negative repercussions of this approach are then:> High consumption of low pressure steam to allow regeneration of the absorbent (3.2 to 6 MJ / kg CO2 depending on the chosen chemical absorbent), thus penalizing the energy performance global; - An electrical consumption for all the pumps and the extracting fan increasing with a decrease in the CO2 content. and ranging from 0.17 kWh / Nm3 CO2 for 5% wet mass content to 0.08 kWh / Nm3 CO2 for 13% wet mass content (MEA process reference 30% weight). The need to treat a very large flow rate corresponding to the totality of the low-pressure (super-atmospheric) flow coming from the gas turbine, which results in the use of one or even generally of very large absorption columns and costly in relatively noble materials (see corrosion problems by progressive decomposition of the chemical absorbent during the regeneration phases and / or because of the presence of oxygen), thus increasing the overall investment.

In the case of capture of CO2 in pre-combustion, it is necessary to convert the heating value of the carbonaceous fuel gas into a mixture containing mainly Hydrogen and CO2. To do this, downstream of a gasifier converting the fuel charge into H2 and CO, an exothermic reactor for catalytic vapor reforming of CO (CO + H2O = CO2 + H2) operating at intermediate temperature (250 ° C) is used. at 500 ° C) and used to switch the heating value of CO to Hydrogen. Then, after cooling, a CO2 pressure absorption system is used which is considered to be relatively efficient and of moderate cost because of the high CO2 content of the gas to be treated (20 to 45% vol depending on the content of the initial fuel carbon and the gasifier conversion efficiency) and its high pressure allowing the use of moderate affinity adsorbents, with expansion regeneration (corresponding to less than 0.15 kWh / Nm3 CO2) and therefore low regeneration steam consumption (-0.3 MJ / kg CO2). The negative repercussions of this approach are then:> Serialization of units with limited energy yields, resulting in a significant loss of calorific value of the fuel sent to the gas turbine burners (ranging from -15% to -30% since 90% * 90% = 81% ...) and a strong reduction in the flow of fuel in the turbine, thus penalizing overall energy performance; - The necessary investment of one or two CO conversion reactors with their equipment for temperature control and steam generation, thus increasing the overall investment; - The need to develop hydrogen burners operating at high pressure and very high power to equip the gas turbine; premix burners to further combine the use of a ballast gas such as nitrogen or water vapor to maintain a stable hydrogen flame and limit NOx; hence the need to have pure nitrogen under pressure to dilute the hydrogen to be burned around 30 to 50 vol% or to consume very expensive water vapor because of the vaporization of demineralised water. - The conversion of CO into hydrogen via the CO conversion reactor means that, in the combustion of synthesis gas, water will be produced instead of CO2, which reduces the capacity of the heat recovery exchanger ( HRSG) to recover the calories present in the exit fumes of the TAG because of the absence of CO2 and the condensation of the water (sensible heat of the CO2 replaced by the latent heat of the water). When oxycombustion is used, pure oxygen, generally produced by a cryogenic separation unit for the air gases, is sent to an atmospheric oxy-fuel furnace or to high-pressure burners of a combustion turbine. gas using a CO2 recycle as ballast gas. The negative repercussions of this approach are then:> The need to separate the oxygen from the air, inducing an electrical levy on the production of 0.25 to 0.35 kWh / Nm3 02 and a thermal sampling of steam at 150 ° C of the order of 0.12 MJ / kg O 2 for the regeneration of the TSA upstream unit; - In the case of a low-pressure oxy-fuel combustion, the use of Hirn-type steam cycles which, even in supercritical operation, are limited to high temperatures of 700 ° C and therefore can not exceed a cycle efficiency 45%; - In the case of a low-pressure oxy-fuel combustion, the need to develop a new set of oxy-fuel combusted oxy-fuel burners; - In the case of high-pressure oxy-fuel combustion, the need to develop a new CO2-recirculated gas turbine with a pressure ratio (ù 40) at least twice as high as gas-air turbines, which lengthens significantly the number of compression stages and the tree length. When the filler is a gaseous or liquid hydrocarbon (natural gas, Naphtha ...) or a low sulfur synthesis gas, it is directly used in the gas turbine which induces a need for post-combustion CO2 capture. via an absorption system placed on its fumes. However, we find the same disadvantages as those mentioned above with a content and partial pressure of CO2 that can be even lower due to the lower carbon content of these fuels (=> 3% vol) which further increases the CO2 capture costs.

For this type of load, it can also be considered a capture of CO2 in pre-combustion. We then find the same disadvantages as those cited above with the addition, in the case of a natural gas or Naphtha type feedstock, the need to invest also in an upstream steam catalytic reforming unit, expensive, for convert this hydrocarbon into a synthesis gas rich in H2 and CO to be placed upstream of a unit for converting CO to H2. This is why this second solution is generally not considered and that the implementation of a steam catalytic reforming unit is carried out only when a complementary production of hydrogen is desired. Finally, when it is desired to perform an oxycombustion of this type of charge, there is the need to produce upstream pure oxygen and its energy penalty induced. To allow maximum efficiency, the use of a combined cycle is preferred which induces the use of a high pressure oxy-fuel combustion located at the gas turbine burners. The major disadvantage is again the necessary development of a gas turbine with CO2 recycle and compression ratio at least twice as high as the gas turbines in the air to allow a sufficient drop in temperature within the relaxation turbine. By taking the above elements, it is then possible to compare from an energy point of view the different methodologies previously presented and allowing the capture of CO2. First, note that for any production of one mole of CO2 by combustion of a non-oxidized and non-wet hydrocarbon feed (natural gas, Naphtha, bituminous coal ...), one mole of O 2 is consumed. Thus, an equivalence in energy consumption is possible between the energy consumption of separation of air gases (N2 / 02) and separation of nitrogen and CO2 by working in molar equivalent of pure O 2 produced or CO2 captured . Post-combustion Pre-combustion Oxy-combustion Oxy-combustion (atmospheric P) (P> 20 bar) (atmospheric P) (P> 20 bar) Gas to be separated N2 / CO2 H2 / CO2 N2 / 02 N2 / 02 Energy 3, 2 MJ / kg CO2 0.3 MJ / kg CO2 0, 12 MJ / kg 02 0.12 MJ / kg 02 thermal (KS-1) (DPMEG) (TSA) (TSA) separation Energy 0.08 kWh / Nin -3 0.02 kWh / Nm3 0.25 to 0.35 0.25 to 0.35 electrical CO2 & 0.17 kWh / CO2 kWh / Nm3 02 kWh / Nm3 02 separation Nm3 CO2 at 13% & (Distillation ( Cryogenic 5% cryogenic volume distillation) Equivalent 3.49 to 3.82 MJ / kg CO2 0.37 MJ / kg CO2 1.38 to 1.88 MJ / kg 02 1.38 to 1.88 MJ / kg 02 energy = 6.9 to 7.5 MJ / Nm3 CO2 = 0.73 MJ / Nm3 CO2 = 1.97 to 2.7 MJ / Nm3 02 = 1.97 to 2.7 MJ / Nm3 02 Thermal (*) at 13 % & 5% volume Estimated 7.4 to 8.0 MJ / Nm3 CO2 0.87 MJ / Nm3 CO2 1.97 to 2.7 MJ / Nm3 CO2 1.97 to 2.7 MJ / Nm3 Energy CO2 with (# ) (#) with equivalence with equivalence pre gasification molar 02 / CO2 molar 02 / CO2 Cycle Hirn Brayton & Hirn Hirn Brayton & Hirn energy // / / / T max 700 ° C 1400 ° C 700 ° C 1400 ° C Yld. Max (x) 45% 58% 45% 58% Development Reduce very Burner Furnace Turbine Gas CO2 to major to significantly Hydrogen to oxycombustion pressure ratio achieve energy separation premix & with recycle CO2 & high (40 ) and burner via the choice of a high burners 02. oxycombustion pressure. high pressure. Absorbent at lower heat of reaction. (*) It is considered that the efficiency of conversion of thermal energy into electrical energy is 50%, that is to say that 0.139 kWh electric 1 MJ thermal; (x) The maximum electrical cycle efficiency is calculated as follows: 1 - (Tmin / Tmax) ≤ 0.5; (#) In the case of pre-gasification, considering that the gasification was carried out with oxygen, it is also necessary to consider for about a quarter of the production of CO2, the energy of separation of the air at its low level (1.97 MJ / Nm3 02).

Here we observe a strong disparity in separation energy for the separation of these various pairs of molecules that do not specifically follow the natural order that could be expected because of the knowledge of the boiling temperatures of the different gases. CO2 gas 02 N2 H2 T boiling (° C) -78.55 -183 -195.8 -252.8 Torques N2 / CO2 H2 / CO2 N2 / 02 H2 / N2 AT Boiling (° C) 117.25 174.25 12.8 57 Equivalent 6.9 to 7.5 MJ / Nm3 0.87 MJ / Nm3 CO2 1.97 to 2.7 MJ / Nm3 / energy CO2 02 Thermal (*) Thus, the energy of separation of the air (through separation N2 / 02) by cryogenic distillation can be considered excellent compared to post-combustion CO2 separation technologies (Cryogenic distillation of air with a difference in boiling temperatures of only 12.8 ° C for the separation N2 / 02 consumes about 2 MJ / Nm3 02 while it is necessary to consume about 7 MJ / Nm3 CO2 to separate two molecules (N2 / CO2) having 117,25 ° C difference of boiling temperatures with current technologies). This also shows that there is a very significant potential for progress for these N2 / CO2 separation technologies since it must be possible to go well below 2 MJ / Nm3 CO2 (û1 MJ / kg CO2), more if the CO2 content is raised to about twenty percent as for the content of 02 of air. Note also the large difference in maximum electrical efficiency (13% points) due to the choice of the energy cycle and corresponding high temperatures. On the basis of this, a problem that arises is to design a cogeneration process, or even an improved IGCC, implementing a means of capturing CO2, and avoiding all of the negative repercussions mentioned above. Thus, the present patent application aims to meet this ambition with the following general objectives:> to limit the losses of conversion efficiency for maximum efficiency; - to ensure a reasonable or even minimal CO2 capture cost; - to be applicable to different types of carbonaceous charges; solid, liquid, gaseous hydrocarbons or synthetic gas type; - to limit the need for technological development for a quick and inexpensive implementation.

A solution of the invention is a co- or tri-generation process, using an adiabatic compressor-gas turbine assembly associated with a gasifier or at least one catalytic vapor reforming unit, characterized in that said process employs at least a first and a second H2S capture unit and / or CO2, carried by at least one fuel gas and a non-combustible gas, operating in parallel. Depending on the case, the method according to the invention may have one of the following characteristics: each capture unit has an operating pressure ranging between a partial vacuum and 80 bars, the first and the second capture units implement at least one absorbent and are regenerated within the same regeneration unit, each capture unit operates at an operating pressure of between 5 and 80 bars and uses a physical, physicochemical or ionic absorbent, each capture unit operates at a working pressure between a partial vacuum and 5 bars, and uses a chemical or physicochemical or ionic absorbent, - each capture unit uses a chemical absorbent comprising ammonium carbonate ( NH4) 2CO3 and ammonium bicarbonate NH4HCO3 in reaction equilibrium for the exclusive capture of CO2, - each capture unit uses a chemical absorbent comprising carbo ammonium nate (NH4) 2CO3, ammonium bicarbonate NH4HCO3 and ammonium hydrogenothiocarbonate NH4HSCO2 in reaction equilibrium for the capture of H2S in the presence of CO2, each capture unit uses an adsorption technology the second capture unit captures CO2 at a pressure comprised between a partial vacuum and 5 bars, and the said CO2 comes from a gas turbine; the second capture unit captures CO2 at a pressure comprised between a vacuum; 40 bar, and said CO2 is from a gas turbine combined with a recycle circuit, - said method uses a working gas which follows the following pressure cycle: compression, superheating, expansion within the gas turbine and cooling, - said method comprises the following steps: a) passing a gaseous fuel containing sulfur compounds through the first capture unit so as to remove at least a portion of the sulfur compounds, b) at least a portion of the gaseous fuel derived from at least step a) is introduced at a pressure greater than 8 bar absolute and at a temperature of between 250 ° C. and 650 ° C. into a combustion chamber which is also supplied with an oxidant pressurized gas comprising oxygen, preferably air, c) combustion gases containing CO2 are recovered at the outlet of the combustion chamber at a temperature greater than 800 ° C. and at a pressure greater than 8 bar absolute. d) the combustion gases from step c) are mixed with the working gas, preheated to a temperature between 250 and 650 ° C and a pressure greater than 8 bar absolute, so as to adjust the temperature of the gas the resultant working temperature so that its inlet temperature in the expansion turbine is between 1000 and 1600 ° C, e) the resulting working gas from step d) is directed into an expansion turbine so that the gas resulting work is expanded and drives the turbine which then provides a mechanical work, f) recovering the expanded working gas from step e) at a temperature between 200 and 700 ° C and directs the latter in a heat exchanger of heat, where its thermal energy is transmitted to a coolant, characterized in that: • before step d) a portion of the working gas is extracted before the combustion chamber and then cooled in a heat exchanger to reach a temperature between 10 and 150 ° C, before being sent at a pressure between 8 and 40 bars absolute to the second CO2 capture unit, or • after step f) a portion of the working gas is recovered at a temperature of temperature between 10 and 150 ° C, and at a pressure between a partial vacuum and 5 bars absolute and sent to the second unit for capturing CO2, the gaseous fuel comprises at least one of the impurities selected from COS, NH3 , Hg, HCN, CS2, mercaptans, carbonyls, acetone, naphthalene, toluene and volatile organic compounds, and in that said process comprises before step a) at least one pre-purification step, the gaseous fuel is a hydrocarbon feed, the oxidant is an N 2 / O 2 mixture, in particular air or O 2 enriched air with an O 2 content of less than or equal to 40%, after the step f) is recovered at the outlet of the steam recovery exchanger and this steam is sent through a steam turbine, - the flow rate of the gas stream entering the CO2 capture unit is between 30% and 50% the flow of gas leaving the gas turbine, the CO2 captured in the CO2 capture unit is then packaged in a bottle or feeds a CO2 line for industrial use or underground storage, said process comprises a step of complementary production of hydrogen. By co-generation is meant the simultaneous production of electricity and high-pressure steam. By tri-generation is meant the simultaneous generation of electricity, high pressure steam and hydrogen. The invention will be described in more detail by means of FIGS. 1 to 10.

FIG. 1 represents a general diagram, according to the invention, of implementation of a co-generation or even of a tri-generation unit using a solid fuel with total or partial capture of CO2 via two high-pressure capture units for stopping H2S and CO2 respectively and operating in parallel.

FIG. 2 represents a general diagram, according to the invention, of implementation of a co-generation or even of a tri-generation unit using a solid fuel with total or partial capture of CO2 via two high and medium capture units. low pressure for the shutdown respectively of H2S and CO2 and operating in parallel. FIG. 3 shows the various elements of FIG. 1 but represents a general diagram, according to the invention, of implementation of a combined cycle unit employing a solid fuel with total or partial capture of CO2 via two capture units at high pressure for stopping H2S and CO2 respectively and operating in parallel. FIG. 4 shows the various elements of FIG. 2 but represents a general diagram, according to the invention, of implementation of a combined cycle unit employing a solid fuel with total or partial capture of CO2 via two capture units at high and low pressure for stopping H2S and CO2 respectively and operating in parallel. FIG. 5 shows the various elements of FIG. 2 but to represent a general diagram, according to the invention, of implementation of a conventional gas turbine with air, using a solid fuel with total or partial capture of the CO2 via two high- and low-pressure capture units for halting H2S and CO2 respectively and operating in parallel. In FIGS. 1 to 5, the gases to be treated, which carry H2S and / or CO2 and whose regeneration unit 18 is common, are always respectively a combustible gas (synthesis gas) and a non-combustible gas (nitrogen). or depleted air). The description below is common to FIGS. 1 to 5 and differs only with respect to the location and the pressure of the second CO2 capture unit, the absence of an export of high pressure steam. 34 in the case of the combined cycle diagrams of Figures 3 & 4 as well as the absence of an adiabatic air compressor 11 for Figure 5.

The solid fuel 1 (coal, lignite, petroleum residues, etc.) transported pneumatically by nitrogen 24, admitted via line 2, is first gasified in the gasifier 3 at high temperature (1100.degree.-166.degree. of oxygen 23 and water 14 in a gasifier via the following main conversion reactions: C + 0.5 O2 = CO -222 MJ / k.mol C + O2 = CO2 -394 MJ / k.mol C + H2O = CO + H2 +131 MJ / k.mol Since the fuel is in excess of the oxidant (air or oxygen), any gasification process corresponds to a partial combustion aimed at producing a synthesis gas rich in H2 and CO. At least three types of gasifier can be used in the context of the invention. They can be fixed bed, fluidized bed or driven bed. These types of gasifier differ essentially in the type of introduction of the reactants, the manner in which the oxidant / fuel contact is made, the H2O / 02 ratio of the relative rates introduced into the gasifier inlet and the ash removal method. The gaseous fuel from the gasifier is then cooled by high-pressure steam (which can be partially exported at 34 as part of the cogeneration units) and dusted at 4 before being prewashed to stop a high proportion of steam. impurities from the gasifier and its combustible charge. Among the impurities that may be present, there may be: COS, NH 3, H 2, HCN, CS 2, H 2 S, mercaptans, carbonyls, acetone, naphthalene, toluene and volatile organic compounds. These impurities can be largely eliminated by a treatment of the cold gas via various stages among which: - the use of activated carbon impregnated for the stop of the Mercury; A washing with water for stopping ammonia NH3; ; a benzene washing for stopping Naphthalene, toluene and acetone; an acid wash, responsible for the dissolution of the compounds soluble in water and the precipitation of heavy metals; hydrolysis, a slightly exothermic catalytic reaction, converting the carbonyl sulphide COS into H2S sulphide acid (COS + H2O = CO2 + H2S at 200 ° C.) and the hydrocyanic acid HCN into its elementary compounds (H2O, CO2, N2) Deep desulfurization on ZnO after hydrogenation of the sulfur; - Prewash with cold methanol for stopping HCN, NH3, Naphthalene, toluene, acetone ... After passing through some of these various pre-purification units, the synthesis gas is sent to the first capture unit 5 selective for stopping H2S. In the case of an absorption unit, the solvent used in washing, which can be pre-saturated with CO2, is saturated with H 2 S after passing through an absorption column and then regenerated continuously, while hot, in a or more flash columns (stripper) and desorption 18. The desorbed H2S 19 can then be sent to a unit for converting H2S to elemental solid sulfur using the Claus process (H2S + 0.5 02 = S + H2O) itself followed by a waste gas treatment and a liquid effluent treatment unit. Similarly, the desorbed CO2 20 from the same regeneration unit 18, can be compressed to be sequestered in the sub soil to prevent its emission to the atmosphere.

This desulfurization unit 5, here under pressure, can implement a physical or chemical or physicochemical absorption technology employing a solvent or a combination of solvents that can be, without exclusivity, among:> Methanol (Rectisol), - The n -methyl-2-pyrrolidone - NMP (Purisol), - polyethylene glycol dimethyl ether - DPMEG (Selexol), - propylene carbonate (Fluorine), - potassium carbonate (Benfield, Catacarb), - 2-n methyldiethnolamine (MDEA), 6n-diglycolamine (DGA-Econamine), diisopropylamine (DIPAM-Amisol), ammonium carbonate by conversion to bicarbonate / ammonium hydrogenothiocarbonate. The desulfurized fuel gas is then preheated by passing through the HRSG exchanger 6 before rejoining the combustion chamber 7 of the gas turbine.

It should be noted that the combustible gas undergoes a minimum of chemical and physical transformations between the solid charge and the gas turbine so that the fuel power of this gas is maximal for maximum electricity production of the gas turbine or the combined cycle. The energy conversion efficiency of the gasifier 3 is therefore predominant in the overall electrical conversion efficiency of the site. The oxygen 23 and nitrogen 24 used by the gasifier are produced by an air separation unit 8 (ASU), which can be cryogenic distillation, and receiving air 9 from a dedicated isothermal compressor 10 as well as possibly an adiabatic compressor 11 (or 15 for FIG. 5) of large capacity whose main function is to supply air (oxidant) under pressure (8 to 40 bars) and hot (> 200 ° C.). combustion chamber, ideally stoichiometric, 7 of the gas turbine.

By combustion of this hot pressurized air and the desulfurized and preheated fuel gas, it is then possible to superheat the working gas of the gas turbine to reach a maximum temperature before expansion, of the order of 1000 to 1600 ° C, preferentially around 1400 ° C (function of technologies and suppliers). The working gas 12 (or 9 for Figure 5) or working fluid is the gas that is used by the gas turbine and follows the Brayton thermodynamic cycle: compression 15, overheating 7, expansion 16 and cooling 6 & 13 (water condenser). In the context of the present invention, the working gas 12 is preferably a recycle gas resulting from the stoichiometric or slightly stoichiometric combustion produced in the combustion chamber 7. The latter, after being cooled in the HRSG assembly (6 - heat recovery steam generation exchanger) is undercooled via the condenser 13 to allow the condensation of the combustion water 14 before being returned to the inlet of the compressor 15 of the gas turbine. A first part of this compressed and heated working gas is sent into the combustion chamber 7 as a dilution gas to limit the temperature of this chamber while a second part bypasses it and is mixed with the gases from the combustion to allow to adjust the temperature of the hot gases to a level compatible with the required temperature at the inlet of the expansion turbine 16 (1000 to 1600 ° C, preferably around 1400 ° C).

For FIGS. 1 and 3, a portion of the working fluid 12 resulting from the compression 15 may be extracted from the gas turbine to be cooled in the recovery exchanger 6 before being sent (21) to a pressure that can be between 5 and 40 bars to a second capture unit 17 under CO2 pressure. The non-combustible waste gas from this capture unit 17 being under pressure and very rich in nitrogen, can then be purified in a purification unit 35 to supply a customer with nitrogen 36 or to supply cooling capacity to the ASU for an additional production of liquid nitrogen. Another option may be expansion in a dedicated nitrogen turbine or in a hydrogen or conventional gas turbine to convert this pressure into electrical energy. This decarbonation unit 17, here under pressure, can implement a physical or chemical or physicochemical absorption technology using a solvent or a combination of solvents that can be, without exclusivity, among:> Methanol (Rectisol), - the n-methyl-2-pyrolidone NMP (Purisol), polyethylene glycol dimethyl ether DPMEG (Selexol), propylene carbonate (Fluorine), potassium carbonate (Benfield, Catacarb), 2 n-methyldiethnolamine (MDEA), 6n-diglycolamine (DGA Econamine), diisopropylamine (DIPAM-Amisol), ammonium carbonate by conversion to ammonium bicarbonate, or other capture methods employing ionic or other liquids or even an absorbent rather used for the capture of CO2 at low pressure and presented below. Ideally, the absorbent (or solvent) will be common to both H2S and / or CO2 capture units and will therefore be sufficiently selective with respect to these two compounds to allow the implementation of the same. regeneration unit 18 of the absorbent. The choice of the final absorbent will depend to a large extent on the partial pressure of CO2 and its regenerative potential by expansion (the absorption capacity of a physical or physicochemical absorbent being a function of the partial pressure of CO2, relaxing the absorbent lowers the partial pressure of CO2 which releases / desorbs this CO2) which greatly reduces the thermal energy necessary for its regeneration. A chemical adsorbent such as ammonium carbonate may also be considered because of its very low heat of reaction. Separately, at the outlet of the regeneration unit 18, H2S 19 and CO2 20 are recovered.

For Figures 2, 4 and 5, the description previously made and relating to Figures 1 and 3 remains valid but differs in that there is no extraction 21 of a portion of the working fluid 12 at the output of the compressor 15 of the gas turbine since a portion of this working fluid is extracted at 22 in the low pressure part of the cycle, that is to say after the expansion step 16, after cooling in the HRSG 6 and generally after the condenser 13. Thus, the CO2 capture unit sees a gas to be treated at a pressure close to atmospheric pressure and in all cases between a partial vacuum and 5 bars, but for FIGS. 2 and 4, always with a relatively high content of CO2 (20 to 45% vol depending on the carbon content of the initial fuel and the conversion efficiency of the gasifier) and may be less than one third of the mass flow leaving the gas turbine. Thus, it may be implemented an affinity absorbent or heat of moderate reaction to allow the capture of CO2. The non-combustible waste gas is then at low pressure (<5 bar) which avoids having to valorize nitrogen under pressure as in the previous cases. In addition, the absence of this nitrogen turbine does not make it possible to value a possible gain due to a partial integration between the ASU and one of the adiabatic compressor 11 (or 15 in FIG. 5), which makes the examples given are preferentially without integration. This low-pressure CO2 capture unit 17 may implement a chemical or physicochemical absorption technology employing a solvent or a combination of solvents which may be, without exclusivity, among: - 2-5 n monoethanolamine with its chemical inhibitors (MEA ), - diethanolamine with its chemical inhibitors (DEA), - triethanolamine with its chemical inhibitors (TEA), 2-4n diisopropanolamine & 2n methyldiethanolamine (ADIP), 2-amino-2-methyl-1-propanol (AMP), - 1,8-pmethanediamine (MDA), - 2piperone ethanol (PE), - amines KS-1, KS-2 or KS-3,> ammonium carbonate by conversion to ammonium bicarbonate, or other capturing processes employing ionic or other liquids and that would significantly reduce the regeneration energy since, as we have seen, the reaction heat of primary amines (MEA), secondary (DEA) and tertiary (MDEA) are respectively 1.9; 1.5 and 1.34 MJ / kg CO2, which is still much higher than the 1 MJ / kg CO2 that it should be possible to obtain as total energy for capturing this carbon dioxide, all the more accessible from elsewhere, if two regeneration stages are employed.

Thus, the solution could come for example from the use of cold NH3, which, by combination with CO2 and water forms ammonium carbonate (NH4) 2CO3 and ammonium bicarbonate NH4HCO3 whose heat of reaction presented is 0.6 MJ / kg CO2 = 1.19 MJ / Nm3 CO2 which would meet the desired objectives of CO2 capture at low pressure while possibly improving the CO2 capture performance at high pressure. Thus, according to recent publications, a total electricity consumption of 0.15 kWhe / Nm3 CO2 is expected for the capture and compression of CO2 at 110 bar. According to the assumptions (*), this would correspond to an overall energy consumption of 2.39 MJ / Nm3 CO2, which is largely within the expected orders of magnitude since the regeneration of this adsorbent could be directly carried out between 20 and 41 bar absolute, saving all the energy of compression. In addition, in the context of the invention, in case of need of a combined capture of H2S and CO2, it will still be possible to use as solvent ammonium carbonate (NH4) 2CO3 since, by combination with the H2S and CO2, an equimolar mixture of ammonium bicarbonate NH4HCO3 and ammonium hydrogenothiocarbonate NH4HSCO2 is formed. The CO2 produced will ideally be of sufficient purity to allow its sequestration in the basement after recompression. In the context of the present invention, the two units for capturing H2S and / or CO2, which can use the same absorber regeneration system, operate in parallel with one another, that is, that is, the fuel gas from the absorber of the first capture unit is not sent to the absorber of the second capture unit without a combustion-type intermediate chemical transformation. Thus, these two capture units see carrier gases of different natures (example: fuel gas or synthesis gas as a carrier gas for H2S or CO2, nitrogen or non-combustible gas as a carrier gas for CO2). Similarly, since these two units for capturing H2S and / or CO2 operate on different carrier gases (fuel gas, non-combustible gas) and have a common regeneration system, the implementation will be judiciously carried out for allow safe absorption on the same absorbent or a combination of absorbents due to the possible presence of oxygen in the non-combustible carrier gas. With regard to the pressurized air supply of the ASU, it is possible to use, in the context of the invention, where possible, partial integration. Indeed, by providing an air supply of the ASU of at least 30% via a dedicated air isothermal compressor 10, it simplifies the startup and partial load operation phases of the entire site while maintaining at most in the system thermal energy generated during the adiabatic compression phase 11 of the air 9 which has the effect of improving the overall energy efficiency. Moreover, with regard to starting the gas turbine, because of the similarity of the physical properties of the air and of the recycle gas, it would suffice to start the assembly in the air and to close again little by little the gas turbine cycle to reach the nominal running where the working fluid is solely from combustion products (see dashed in Figures 1 & 3 representing the inlet air injection 15 in the start phase).

The method according to the invention has several advantages. Indeed, the different negative impacts due to the CO2 capture previously seen in post-capture, pre-combustion or oxy-fuel combustion cases do not reappear since:> The fraction of CO2 of the gas to be treated is not diluted the capture unit through the use of quasi-stoichiometric air (or enriched air) combustion and recycling; - The flow rate to be treated by the CO2 capture unit is about three times less than the flow from the gas turbine (working fluid) and is at high pressure or possibly at a pressure close to atmospheric pressure if a CO2 capture process, very low energy reaction, a new generation is used (eg mono and ammonium bicarbonate); -The regeneration of the CO2 capture adsorbent is by relaxation and is low steam consuming if the CO2 capture is carried out under pressure (about 0.3 MJ / kg CO2) because it is not necessary to use a high affinity solvent which reduces the penalty on the energy efficiency of the whole because of CO2 capture; - There is no heat loss of the synthesis gas before it is sent to the gas turbine because of the non implementation of intermediate units for conversion of CO into hydrogen and therefore no associated over-investment; - It is not used high pressure hydrogen burners which avoids the development of this technology and the implementation of an injection of nitrogen or dilution water vapor to stabilize the hydrogen flame. In addition, the CO2 always present in the gas to be burned serves as ballast gas to limit the production of NOx while providing a surplus of power due to its relaxation in the TAG; - The combustion of synthesis gas, not converted into hydrogen, produces less water which tends to condense in the HRSG exchanger at the expense of heat recovery; - High pressure oxy-fuel burners are not used, which avoids the development of this technology as well as the associated CO2 gas turbine; - When a strong electricity production is requested, it is used a combined cycle for a maximum electrical efficiency which uses technologies very close to the state of the art which avoids heavy developments. Figures 1, 2 and 5 show a cogeneration unit, or even tri-generation (dotted line); pressurized water vapor 34 is superheated and exported after its vaporization within the HSRG exchanger 6, or even within the refrigeration unit of the synthesis gas leaving the gasifier. In addition, it is also represented in optional form (dashed lines), a step case for complementary hydrogen production where, downstream of the first H2S capture unit 5, a conversion reactor is used. CO 25 and a hydrogen PSA 26 for the purification of hydrogen 27. The waste gas 28 of the hydrogen PSA being sent to the afterburners in the air located at the HRSG 6 assembly to allow a overheating and / or additional steam production. Note that this post combustion does not generate CO2 emissions since its combustion products are mixed with the hot gas from the gas turbine which are then processed in the second capture unit. Figures 3 and 4 show a combined cycle unit, the pressurized and superheated steam within the HSRG 6, or even within the synthesis gas refrigeration unit leaving the gasifier is used as a working fluid in a set of steam turbines 29 following a Hirn cycle to allow additional production of electricity. Indeed, by combining a steam turbine 29 and a gas turbine 16 in the context of a combined cycle it is possible to ensure a maximum production of electricity. Thus, when the heat-transfer fluid is water, the high-pressure, high-temperature steam is recovered at the outlet of the HSRG heat exchanger 6 (for example between 120 and 170 bars, and between 500 and 650 ° C. This vapor can then drive a steam turbine 29 instead of being used directly in an external process, and with an alternator placed on the axis of the steam turbine 29, it is thus possible to produce additional electricity. The low-pressure heat demand required for the regeneration of the absorbent used to capture H2S and / or CO2 can also be satisfied by steam extracted from a backpressure steam turbine (TAV at outlet pressure of a few bars), extracted here from the medium pressure turbine (MP), it is obvious that such configurations allow a high electrical efficiency, which results in a lower thermal efficiency, and FIGS. It is preferred if the two units of capture of H2S and / or CO2 are rather at the same relative pressure, that is to say, rather at high pressure, which facilitates the choice of absorbent. While Figures 2, 4 and 5 show an alternative where the H2S capture unit is in high pressure while the CO2 capture unit is in low pressure which may be possible for a chemical absorbent or physicochemical which could then also be used in high absorption pressure; even more so if it has a very low heat of reaction for CO2. Compared with the state of the art known, let us note some additional novelties:> The gas turbine operates in semi-closed cycle which allows to choose a lower optimal cycle pressure that can be different from the atmospheric pressure. Thus, in particular, if it is higher it is possible to reduce the gas flow volumes in the HRSG 6 and in the lower pressure stages of the gas turbine. In addition, additional cooling water is probably needed to ensure a sufficiently low gas turbine inlet temperature for improved energy efficiency. - The combustion air and the working / recycle fluid of the gas turbine are compressed by two separate adiabatic compressors that may or may not be on the same shaft (the air compressor may for example be driven by a turbine steam engine). Overall, the 02 of the air to be compressed is replaced by CO2 in the recycle gas to be compressed which has only a reduced impact on the molar mass (29 against 31.1 in the attached example) and very limited on the ratio of the Cp / Cv heat capacities of the working fluid (1.4 against 1.37 in the attached example) which makes it possible to use the conventional technologies of gas turbines in the air and to capitalize on previously developed technologies. - The combustion chamber of the gas turbine being stoichiometric type with integration of two external gases (fuels & oxidants), a specific development work of this environment will be necessary here. But this type of synthesis gas combustion with modest heating value (8 to 15 MJ / kg) does not present a specific technical difficulty and is already referenced. - In the case of a pressure extraction of a portion of the working gas carrying CO2, it is necessary to seek to minimize the pressure drop at the extraction of the TAG and to recover in a manner or another residual nitrogen still under pressure obtained after decarbonation. A first option is to heat this gas to an intermediate temperature (200 to 400 ° C) before expansion in a dedicated nitrogen turbine 35 (which may be coupled to the adiabatic air compressor) or in a conventional gas turbine. A second option would eventually be to purify this nitrogen for export to an external customer.

Another variant of the present invention relates to the use of a gaseous or liquid hydrocarbon of natural gas or Naphtha type as fuel. Five figures illustrate the possibilities of implementation of the invention. FIG. 6 represents a general diagram of this variant of the invention of implementation of a tri-generation unit using a liquid or gaseous fuel with total or partial capture of CO2 via two high-pressure CO2 capture units. and operating in parallel. FIG. 7 represents a general diagram, according to the invention, of implementation of a tri-generation unit using a liquid or gaseous fuel with total or partial capture of CO2 via two low-pressure CO2 capture units and operating in parallel. FIGS. 8 and 9 represent two general diagrams, according to the invention, for implementing a tri-generation unit using a liquid or gaseous fuel with total or partial capture of CO2 via two high and low pressure capture units CO2 and operating in parallel.

FIG. 10 shows the various elements of FIG. 8 but to represent a general diagram of this variant of the invention, of implementation of a conventional gas turbine with air, employing a liquid or gaseous fuel with capture total or partial CO2 through two CO2 high and low pressure capture units operating in parallel.

Note then a particular element to the invention and common to Figures 6 to 10. The gases to be treated carrying CO2 and treated by the two units 17, the regeneration unit 18 is common, are always respectively a fuel gas (gas synthesis or waste gas of PSA H2) and a non-combustible gas (nitrogen or depleted air). The natural gas or Naphtha 33 is initially admitted into an HRSG 6 type exchanger to be preheated to over 300 ° C. Then, the fuel successively passes through a hydrogenation reactor (for the extraction of carbon chain stresses to form H2S) while hot and a deep desulfurization reactor by chemistry-sorption on ZnO (ZnO + H2S = ZnS + H2O). ) hot before being used partially as fuel gas in the gas turbine.

The method according to the invention has several advantages. Indeed, on the one hand, the combustion chamber 7 is fed with a part of the desulphurized fuel gas which facilitates the cooling of the fumes and the removal of SOX; on the other hand, a stoichiometric or slightly stoichiometric combustion is also carried out here at 02 with recycle of a part of the fumes, which also limits the dilution of the CO2 and makes it possible to maintain at the outlet of the gas turbine a CO2 content at least equal to the content of 02 of the oxidant. Thus, the flow rate to be treated to capture the CO2 produced is reduced to about one third of the flow rate from the gas turbine. Moreover, the CO2 capture unit 17 can treat a gas at a pressure close to atmospheric pressure and in all cases between a partial vacuum and 5 bars with intermediate affinity absorbents or can treat a gas at high pressure that is to say at a pressure of between 5 and 40 bar with an absorbent with a lower chemical affinity. In this application, the regenerator 18 is specifically linked to the CO2 absorption capture unit and consists of a steam heating column of the absorbent allowing purge of the pure CO 2 at the top of the column and regenerated solvent production. at the bottom of the column.

The thermal conversion efficiency of the unit is maximum since the fuel undergoes a degradation in minimum calorific value before combustion since it is not converted into hydrogen-rich fuel oil. Finally, the oxidant used in the combustion is air which avoids the cost of separation of the air.

This scheme fits very well with a complementary production of hydrogen since the implementation of a catalytic reforming unit with steam 32 can very well integrate with the heat recovery and steam generation assembly 6 (HRSG) while offering the possibility of combining the two CO2 capture units 17 respectively integrated in the hydrogen generation chain via the CO 25 conversion units and the hydrogen PSA 26 and to that of electricity production and of steam. Thus, FIGS. 6 and 7 represent a preferred application where the two CO2 capture units are rather at the same relative pressure, that is to say, rather at high pressure and rather at low pressure, which facilitates the choice of the 'absorbent. While FIGS. 8, 9 and 10 show an alternative where the CO 2 capture pressures are at high pressure for one unit and at low pressure for the other unit, which may be possible for a chemical or physicochemical absorbent that choked then be used also in high absorption pressure.

Example 1: Consider a German Lignite type solid charge with the following properties: Dried natural solid fuel data

PCS kJ / kg 10,778 kJ / kg 9,010 19,700 Moisture% 54.5 12.0 Ashes% 4.9 9.5 Carbon% 27.3 52.8 Hydrogen% 2.0 3.9 Nitrogen% 0.4 0.8 Oxygen% 10.3 19.9 Suffer% 0.6 1.1 With PCS = higher heating value, and PCI = lower calorific value The gasifier (3) used in this simulation is a High Temperature Winkler with a fluidized bed, also known as HTW gasifier, which has been demonstrated industrially in Berrenrath, Germany (Uhde dimensioning). Its operating pressure is taken at 30 bar, its bed temperature at 850-900 ° C for an outlet temperature of 950-100 ° C. The pressure drop across the gasifier is taken at 1.5 bar for a contact time of between 10 and 100 seconds. The lignite is crushed beforehand and then dried by a mechanical compression method of fluidized bed drying steam (WTA process for minimizing the drying energy). The electrical energy consumed was taken at 85 kWh / ton of dried Lignite.

At the outlet of the gasification reactor, the synthesis gas is dedusted by a recycle cyclone increasing the carbon conversion as well as by ceramic filters (4) resistant to high temperatures and pressures before being cooled to around 250 ° C. via high and medium pressure steam production. Then, the synthesis gas is cleaned by washing to remove the residual solid particles as well as to dissolve the hydrochloric and hydrofluoric acids present in traces before being saturated with water at 200 ° C. to reach the catalytic hydrolysis bed of the COS in H2S. After this conversion, to continue cooling the synthesis gas, it is then necessary to dissolve the naphthalene (co-product of the gasification) in a suitable mixture to prevent it from solidifying (from 70 ° C) and block the exchangers . The thus cooled synthesis gas is then sent to the H2S absorption column (5) which can operate at temperatures ranging from -70 to + 120 ° C depending on the type of solvent. The calculation of the pressure capture unit of H2S is based here on the performances obtained when methanol is used as a solvent via the Rectisol process. The pure H2S from the regeneration column is converted to solid sulfur downstream via the oxy-claus process. The synthesis gas can now be heated to 300 ° C. before being burned in the combustion chamber 7 of the gas turbine having adiabatic compression and expansion yields respectively 91.5% and 87.94% corresponding substantially to a Siemens advanced F-type V94.3A gas turbine (SGTS-4000F) with a compression ratio of 20.5 while stoichiometric combustion is performed with an excess of air of the order of 10% at 20%, for a turbine inlet temperature of 1232 ° C (2250 ° F). The adiabatic air compressor retains the 91.5% adiabatic yield for an outlet pressure and temperature of respectively 21.5 bar absolute and 433 ° C. In addition, in the presence of a combined cycle, the steam turbines are calculated with an adiabatic expansion efficiency of 88%, a high vapor level of 550 ° C at the inlet of the three steam turbines (HP / MP / BP = 150 / 72/10 bar absolute) for a minimum pressure at the LP turbine outlet of 50 mbar absolute, with extraction of steam at 2 bar absolute (to ensure the regeneration of the absorbent), and for a minimum refrigeration temperature of 25 ° C .

It should also be noted that in order to minimize exergy losses at the HSRG 6, vaporization of the steam cycle water is carried out at the maximum pressure of 150 bar only, re-heating is performed and the minimum temperature approach is taken. 2 ° C. The mechanical and electrical conversion efficiencies considered are respectively 99.6% and 98.5%. The adiabatic compression yields of the liquid pumps are taken to 75%. With regard to CO2 capture and regeneration of the absorbent, a thermal consumption in the form of BP vapor (120 ° C to 2 bar) of 2 MJ / kg of CO2 was considered for a low catch pressure (a realistic target already well exceeded by the ammonium bicarbonate process which goes down to 0.66 MJ / kg of CO2) and 0.85 MJ / kg of CO2 for CO2 capture at high pressure. In addition, the associated power consumption is taken at 0.06 kWh / Nm3 of CO2 for a low pressure capture and at 0.02 kWh / Nm3 of CO2 for high pressure capture. Finally, for its compression up to 110 bar, an electricity consumption of 0.2 kWh / Nm3 of CO2 (102 kWh / ton CO2) is considered as safe, as it is possible to envisage that the unit of capturing CO2 renders the gas desorbed at an intermediate pressure thereby decreasing the compression energy (as is the case for the ammonium bicarbonate capture process). With regard to the energy of separation of the oxygen, it was considered an electrical consumption of the order of 0.31kWh / Nm3 of O2 and a thermal sampling of steam at 150 ° C of the order of 0 12 MJ / kg 02 for the regeneration of the upstream TSA unit. Oxygen 95% purity and pure nitrogen, preheated to 250 ° C, are delivered respectively at 40 and 31 bar absolute (equivalent pressures for simplicity). Thus, at the output of the HTW gasifier and after cooling and dedusting, the gas entering and leaving the H2S capture unit is of the following form: Gas parameters and Before the unit After the unit of elements the H2S capture component H2S capture Temperature (° C) 192 40 Pressure (bar) 28.7 25.6 Maximum amount (ton / h) 308.5 250 H2 24.68% 31.75% CO 28.79% 37 , 03% CH4 4.63% 5.95% CO2 13.74% 17.68% Ar 0.53% 0.68% 02 0% 0% N2 4.86% 6.54% H2O 22.36% 0 , 30% Benzene 0.06% 0.06% H2S 0.12% traces COS 0.005% traces NH3 0.22% traces HCN 0.004% Traces According to the assumptions given above, a summary of the results obtained for the processes relating to Figures 1 and 2, without production of hydrogen, in the case of a cogeneration process. 10 Overall Process Performance Units Figure 1 Figure 2 Moist lignite rate t / h 323.7 / 148.0 323.7 / 148.0 Moisture Lignite LC MJ / kg 9. 01 / 19.7 9.01 / 19.7 Load Energy (A) MWth 810 810

Thermal energy of synthesis gas (B) MWth 730.9 730.9 Yield of gasification (B / A * 100)% 90.29 90.29

Power consumed by the Comp. Air Adiab. MWe 131.3 112.7 Power delivered by the TAG (SGT5-4000F) MWe 282.8 403.5 Power delivered by the steam turbines MWe / / Power delivered by the turbine Nitrogen MWe 66.65 / Gross power delivered (D) MWe 218.15 290.8 Exported vapor -PCS (E MWth 522.5 333.5 Volumetric fraction of CO2 before capture% vol. 19.32% 19.32% Thermal regeneration energy MWth 70.32 165.5

ASU consumption + compression 02 & N2 MWe 18.14 25.55 Lignite MWe drying consumption 12.58 12.58 MWe gasifier consumption 4.82 4.82 H2S MWe capture 1.65 1.65 CO2 capture, drying & compression MWe 33.50 39.24 TAG + TAV MWe block consumption 3.16 2.02 Total consumption of auxiliaries (F) MWe 73.85 85.86

Net electricity generation (G = D - F) MWe 144.3 204.94 Gross electricity yield (D / A * 100)% 26.93 35.90 Net electricity efficiency (G / A * 100)% 17.81 25.30 Steam export efficiency (E / A * 100)% 64.51 41.17 Cogeneration efficiency ((G + E) / A * 100)% 82.32 66.47 Mass flow rate of CO2 captured ton / h 297.5 297.5 CO2 capture rate% 92.66 * 92.67 * Specific CO2 emissions kg / MWh 57.37 40.31 It is considered that 5% of the carbon of the load is not gasified and is found in the ashes. Cogeneration efficiency is the ratio of net equivalent 5 MW (or GJ / h) of steam and electricity produced divided by the equivalent heating value in MW (or GJ / h) of the initial fuel load.

Below is a summary of the results obtained for the processes relating to FIGS. 3 and 4, without production of hydrogen, in the case of a combined cycle process for maximum electricity production. Overall Unit Process Performance Figure 3 Figure 4 Moist lignite rate t / h 323.7 / 148.0 323.7 / 148.0 Moisture Lignite PCI Mo / kg 9.01 / 19.7 9.01 / 19.7 Thermal Energetic Load (A) MWth 810 810

Thermal energy of synthesis gas (B) MWth 730.9 730.9 Yield of gasification (B / A * 100)% 90.29 90.29

Power consumed by the Comp. Air Adiab. MWe 131.3 112.7 Power delivered by the TAG (SGT5-4000F) MWe 282.8 394.4 Power delivered by the steam turbines MWe 213.6 175.2 Power delivered by the turbine Nitrogen MWe 68.53 / Gross power delivered (D) MWe 433.63 456. 9 Steam exported - PCS (E) MWth 0 0 Volume fraction of CO2 before capture% vol. 19.32% 19.38% Thermal regeneration energy MWth 70.32 165.5

ASU consumption + compression 02 & N2 MWe 18.14 25.55 Lignite MWe drying consumption 12.58 12.58 MWe gasifier consumption 4.82 4.82 H2S MWe capture 1.65 1.65 CO2 capture, drying & compression MWe 33.50 39.20 Consumption of the TAG + TAV MWe block 3.00 2.72 Total consumption of auxiliaries (F) MWe 73.69 86.52

Net electricity generation (G = D - F) MWe 359.94 370.4 Gross electrical output (D / A * 100)% 53.53 56.41 Net electricity efficiency (G / A * 100)% 44.44 45.72 Steam export efficiency (E / A * 100)% 0 0 Cogeneration efficiency ((G + E) / A * 100)% 44.44 45.72 Mass flow rate of CO2 captured Ton / h 297.5 297.5 CO2 capture rate *% 92.66 92.66 Specific emissions of CO2 kg / MWh 22.99 22.32 It is considered that 5% of the carbon of the load is not gasified and is found in the ashes.

It appears that for the cogeneration process as well as for the combined cycle process, the capture version of carbon dioxide under high pressure (19.5 bar absolute) is already very efficient (82.32% and 44.44%) with current catch. On the other hand, it appears that if a system for capturing CO2 at low pressure is used, the cogeneration process remains poor in performance (66.47%), even when the heat required for the regeneration of the absorbent is order of 2 MJ / kg CO2. However, conversely, the low pressure capture combined cycle process has a better energy efficiency than for the high pressure CO2 capture scheme (45.72% against 44.44%) even when the heat required for the regeneration of the absorbent is of the order of 2 MJ / kg CO2. These low-pressure capture schemes are therefore potentially very interesting in performance when a combined cycle is implemented while being less difficult to implement due to the absence of a nitrogen turbine and HP extraction. . In addition, in all the calculated schemes, the mass flow rate sent to the CO2 capture unit is of the order of 43 to 44% of the mass flow leaving the gas turbine, thanks to the recycling which makes it possible to approach the 20% volume of CO2 at the unit inlet, and significantly reduce the volume of the absorption columns. In order to evaluate the maximum potential of CO2 capture schemes at low pressure, let us take the previous hypotheses but now considering the use of cold ammonia absorption systems (carbonate / bicarbonate / ammonium hydrogenothiocarbonate ) for the capture of both H2S and CO2, in the context of Figures 2 and 4, without production of Hydrogen. Thus, the overall chemical absorption reactions considered are: (NH4) 2CO3 (aq) + CO2 (g) + H2S (g) C => NH4HCO3 (aq) + NH4HSCO2 (aq) for the capture of H2S in the presence of CO2 and: (NH4) 2CO3 (aq) + CO2 (g) + H2O Cl> 2 NH4HCO3 (aq) AHf = -26.75 MJ / kmol for CO2 capture in the presence of water. While the associated thermal consumption for their implementation is taken equal to 0.85 MJ / kg of H2S for a capture of H2S and with 0.66 MJ / kg of CO2 for a capture of CO2. The capture power consumption of these compounds is maintained at 0.02 kWh / Nm3 of H2S and 0.06 kWh / Nm3 of CO2 respectively, but the consumption required for the compression of CO2 at 110 bar is taken equal to 0.09 kWh / Nm3 of CO2 as recently published (which is made possible by a regeneration at more than 20 bar).

The results obtained are summarized in the following table: Overall performance of the Units process Figure 2 Figure 4 (NH3) (NH3) Moist lignite rate t / h 323.7 / 148.0 323.7 / 148.0 Ln Moisture Lignite Moisture / kg 9.01 / 19.7 9.01 / 19.7 Thermal energy of the load (A) MWth 810 810

Thermal energy of synthesis gas (B) MWth 730.9 730.9 Yield of gasification (B / A * 100)% 90.29 90.29

Power consumed by the Comp. Air Adiab. MWe 112.7 112.7 Power delivered by TAG (SGT5-4000F) MWe 403.5 394.4 Power delivered by steam turbines MWe 0 194.9 Power delivered by the turbine Nitrogen MWe / / Gross power delivered (D) MWe 290.8 476.6 Steam exported - PCS (E ) MWth 454.4 0 Volume fraction of CO2 before capture% vol. 19.32% 19.38% Thermal regeneration energy MWth 54.6 54.6

ASU consumption + compression 02 & N2 MWe 25.56 25.55 Lignite MWe drying consumption 12.58 12.58 MWe gasifier consumption 4.82 4.82 H2S MWe capture 1.65 1.65 CO2 capture, drying & MWe compression 22.73 22.91 TAG + TAV MWe block consumption 0 2.65 Total consumption of auxiliaries (F) MWe 67.34 70.16

Net electricity generation (G = D - F) MWe 223.5 406.4 Gross electricity yield (D / A * 100)% 35.90 58.84 Net electricity yield (G / A * 100)% 27.59 50.18 Export steam yield (E / A * 100)% 56.10 0 Cogeneration efficiency ((G + E) / A * 100)% 83.69 50.18 Mass flow rate of CO2 captured ton / h 297.5 297.5 CO2 capture rate *% 92.67 92.66 Specific emissions of CO2 kg / MWh 36.96 20.35 It is considered that 5% of the carbon of the load is not gasified and is found in the ashes.

It appears that the implementation of the cold ammonia capture method with carbonate / bicarbonate / ammonium hydrogenothiocarbonate combined with the various schemes proposed makes it possible to achieve very attractive performances for cogeneration or for an IGCC integrating accessible technologies. short-term and best integrated to ensure efficient CO2 capture (83.69% and 50.18% respectively for Figures 2 and 4) .10

Claims (19)

claims 1. A method of co- or tri-generation, using an adiabatic compressor assembly - gas turbine associated with a gasifier or at least one catalytic steam reforming unit, characterized in that said method uses at least a first and a second unit for capturing H2S and / or CO2, carried by at least one combustible gas and a non-combustible gas, operating in parallel. 2. Method according to claim 1, characterized in that each capture unit has an operating pressure between a partial vacuum and 80 bar. 3. Method according to one of claims 1 or 2, characterized in that the first and second capture units use at least one absorbent and are regenerated within a single regeneration set. 4. Method according to one of the preceding claims, characterized in that each capture unit operates at an operating pressure between 5 and 80 bar and uses a physical, physico-chemical or ionic absorbent. 5. Method according to one of claims 1 to 3, characterized in that each capture unit operates at a working pressure between a partial vacuum and 5 bar, and uses a chemical or physico-chemical or ionic absorbent. 25 6. Method according to one of the preceding claims, characterized in that each capture unit uses a chemical absorbent comprising ammonium carbonate (NH4) 2CO3 and ammonium bicarbonate NH4HCO3 in reaction equilibrium for the exclusive capture of CO2. 30 7. Method according to one of claims 1 to 5, characterized in that each capture unit uses a chemical absorbent comprising ammonium carbonate (NH4) 2CO3, ammonium bicarbonate NH4HCO3 and hydrogenothiocarbonate20d ' ammonium NH4HSCO2 in reaction equilibrium for the capture of H2S in the presence of CO2. 8. Method according to one of claims 1 or 2, characterized in that each capture unit uses an adsorption technology. 9. The method of claim 5, characterized in that the second capture unit captures CO2 at a pressure between a partial vacuum and 5 bar, and said CO2 is from a gas turbine. 10. Method according to one of claims 1 to 8, characterized in that the second capture unit captures CO2 at a pressure between a partial vacuum and 40 bar, and said CO2 comes from a gas turbine combined with a recycling circuit. 15 11. Method according to one of the preceding claims, characterized in that said method uses a working gas which follows the following pressure cycle: compression, superheating, expansion within the gas turbine and cooling. 12. Process according to claim 11, characterized in that said process comprises the following steps: a) a gaseous fuel containing sulfur-containing compounds is passed through the first capture unit so as to eliminate at least a part of the sulfur-containing compounds b) introducing at least a portion of the gaseous fuel from at least step a) at a pressure above 8 bar absolute and at a temperature between 250 ° C and 650 ° C in a combustion chamber which is also fed with a gaseous oxidizer under pressure comprising oxygen, preferably air, c) is recovered at the outlet of the combustion chamber combustion gases containing CO2 at a temperature above 800 ° C and at a temperature of pressure above 8 bar absolute, 10d) is mixed these combustion gases from step c) with the working gas, preheated to a temperature between 250 and 650 ° C and pressure of less than 8 bar absolute, so as to adjust the temperature of the resulting working gas so that its inlet temperature in the expansion turbine is between 1000 and 1600 ° C, e) the resulting working gas from the step d) in an expansion turbine so that the resulting working gas is expanded and drives the turbine which then provides mechanical work; f) recovering the expanded working gas from step e) at a temperature between 200 and 700 ° C and directs the latter in a heat exchanger, where its thermal energy is transmitted to a coolant, characterized in that: - before step d) a portion of the working gas is extracted before the combustion chamber and then cooled in a heat exchanger to reach a temperature between 10 and 150 ° C, before being sent at a pressure between 8 and 40 bars absolute to the second unit for capturing CO2, or - Morn in step f) part of the working gas is recovered at a temperature between 10 and 150 ° C, and at a pressure between a partial vacuum and 5 bars absolute and sent to the second CO2 capture unit, 13. The method of claim 12, characterized in that the gaseous fuel comprises at least one of the impurities selected from COS, NH3, Hg, HCN, CS2, mercaptans, carbonyls, acetone, naphthalene, toluene and volatile organic compounds, and in that said process comprises before step a) at least one pre-purification step. 14. Method according to one of claims 12 or 13, characterized in that the gaseous fuel is a hydrocarbon feedstock. 15. Method according to one of claims 12 to 14, characterized in that the oxidant is a mixture N2 / O2, in particular air or air enriched in 02 with a content of 02 less than or equal to 40 %. 16. Method according to one of claims 12 to 15, characterized in that after step f) is recovered at the outlet of the steam recovery heat exchanger and this steam is sent through a steam turbine. 17. Method according to one of claims 12 to 16, characterized in that the flow rate of the gas stream entering the CO2 capture unit is between 30% and 50% of the gas flow leaving the gas turbine. 18. Method according to one of the preceding claims, characterized in that the CO2 captured in the CO2 capture unit is then packaged in a bottle or feeds a CO2 line for industrial use or underground storage. 19. Method according to one of the preceding claims, characterized in that said process comprises a step of complementary production of hydrogen.