NL9102195A - METHOD FOR TREATING GASES OBTAINED BY COAL GASIFICATION, RESIDUAL GASIFICATION, WASTE GASIFICATION OR OIL GASIFICATION - Google Patents

Description

Title: Process for treating gases obtained from coal gasification, residue gasification, waste gasification or oil gasification.

The invention relates to a method for treating gases obtained from coal, residue, waste or oil gasification.

Coal gasification plants are built to produce synthesis or fuel gas, which is used to generate electricity in gas turbine powered generators. Coal gasification plants have advantages over direct-fired coal-fired power plants, since such plants have more favorable emission and efficiency properties.

Many aromatics are currently produced as lead replacements in petrol. A large amount of H 2 is released during the production of these aromatics, which is used again in the refineries in hydrogenation and hydrogenating desulphurisation processes. The addition of aromatics to gasoline is expected to be reduced or even completely discontinued, because aromatics can be carcinogenic. However, this will lead to a shortage of H2 in refineries. At the moment, therefore, the installation of residue and / or oil gasification plants for the production of hydrogen-containing gas is already underway. for residues, gasification is most attractive, because combustion of this type of sulfur-rich streams is prohibited even in marine engines.

In the production of synthesis or fuel gas, such as in coal, residue or oil gasification, many sulfur compounds are released which have to be removed in order to limit the emissions of, in particular, SO2, which is generated when such sulfur compounds are burned in the atmosphere.

In addition to CO, H2 and H2S, the synthesis or fuel gas from the gasification of coal, oil or residue will usually contain COS, CS2, CO2, HCN and NH3. Such a gas is highly reducing.

The extent to which the sulfur compounds must be removed depends on the intended use of the gas and the quality requirements. If synthesis gas must comply with the so-called "pipeline specification", the hydrogen sulfide content must be reduced to a value below 5 mg / Nm3. requirements are also imposed on the maximum content of other sulfur compounds such as carbonyl sulfide (COS) and carbon disulfide (CS2).

Many methods are known in the art with which the amount of sulfur compounds in a gas, such as synthesis or fuel gas, can be reduced.

Usually, the following process route is used to remove sulfur-containing components from gases. In a first step, the gas to be treated is purified, whereby sulfur-containing components are removed from the gas, followed by a recovery of sulfur from these sulfur-containing components, after which a residual gas-sulfur cleaning step follows, in this last step an attempt is made to recover the last percent sulfur before emitting the residual gas into the atmosphere through a chimney.

processes are used in the gas purification step, in which mostly aqueous solvents (solvents) are used. These processes are divided into five main groups, namely chemical solvent processes, physical solvent processes, physical / chemical solvent processes, redox processes, where H2S is directly oxidized to sulfur in aqueous solutions, and finally the group of fixed bed processes, where H2S is chemically or physically absorbed or adsorbed, or selectively oxidized catalytically to sulfur.

The first three groups of methods mentioned are generally used in industry for removing large amounts of sulfur from mostly large amounts of gas. The latter two groups of processes, with the exception of fixed-bed oxidation, are limited in terms of the amount of sulfur to be removed and the concentration of the h2S in the gases to be purified and are therefore less suitable for use in large industrial gas treatment plants .

The chemical solvent processes include the so-called amine processes, in which aqueous solutions of alkanolamines are used, and the so-called hot potassium carbonate processes, in which aqueous solutions of potassium carbonate are used.

Different types of chemicals are used in the physical solvent processes, for example dimethyl ether of polyethylene glycol (DMPEG), known in this branch of the art under the name Selexol, N-methyl-pyrrolidone (NMP), known under the name Purisol, or methanol, known under the name Rectisol.

The Sulfinol process is well known from the group of physical / chemical processes. This method uses a mixture of an alkanolamine with sulfolane dissolved in a small amount of water.

In the above three methods, an absorber and a regenerator are used, in the absorber the sulfur-containing components are chemically and / or physically bound to the solvent. Due to pressure drop and temperature increase in the regenerator, the sulfur-containing components are released again from the solvent, which can then be reused.

A detailed description of these methods can be found in R.N. Maddox, "Gas and Liquid Sweetening", Campbell Petroleum Series (1977).

In these processes, the degree of removal of H 2 S and other sulfur compounds, such as COS and CS 2, but also, for example, carbon dioxide (CO 2), depends on the selected solvent and pressure. The higher the pressure, the more sulfur compounds are removed. For example, from a synthesis or fuel gas containing 1% by volume of H2S at a pressure of 5 bar, absolutely 99.5% of the sulfur compounds will be removed, while from natural gas containing 1% by volume of H2S, about 99.95% of these sulfur compounds will be removed. connections are removed at a pressure of 80 bar. However, the removal of sulfur compounds is never complete and with subsequent use of the gas, the compounds still present may give rise to some SO2 emissions.

The solvents used in these processes are recycled from the absorber to the regenerator and then back to the absorber. Heat exchangers are often used to save energy.

The sulfur compounds removed are carried along with the CO2 from the regenerator to a sulfur recovery plant to recover sulfur from H 2 S and other sulfur compounds.

The Claus process is a frequently used process for the recovery of sulfur from the sulfur compounds thus obtained, in particular H2S. This process is described in detail in H.G. Paskall, "Capability of the Modified Claus Process", Western Research Development, Calgary, Alberta, Canada (1979).

The Claus process consists of a thermal step followed by usually two or three reactor steps. in the thermal step, a third of the H2S is burned to SO2 according to the reaction: h2s + l1 / 2 o2 - * so2 + h2o, after which the rest, so two thirds, of the H2S reacts with the SO2 formed in the so-called Claus reaction to sulfur 2 H2S + S02 «3 S + 2 H20

The efficiency of the Claus process depends on a number of factors. With an increasing water content in the gas, the equilibrium in the Claus reaction shifts to the H2S side. In addition, a disturbance occurs due to the formation of COS and CS2 in the thermal step. Furthermore, the control of the combustion air is critical and finally losses occur because sulfur in the residual gas is entrained in the form of sulfur vapor and as sulfur particles.

Usually the efficiency of a Claus installation is between 90-98% depending on the number of reactors. Given the environmental requirements, this sulfur recovery efficiency is currently insufficient and industrial plants are equipped with residual gas sulfur cleaning plants, known in the process technology as Tail Gas Treating units (TGTU) or Tail Gas Clean-up Units (TGCU).

Tail gas sulfur cleaning processes are described in U.H.F. Sander et al., "Sulfur, Sulfur Dioxide and Sulfuric Acid", The British Sulfur Corporation Ltd, 59-95 (1984).

Sulfur recovery efficiency is increased to 98.5-99.95% by using these tail gas-sulfur cleaning processes, which essentially remove residues of H2S, SO2, COS and CS2. Known processes are, for example, the Sulfrene and SCOT processes.

One of the latest developments to increase returns is the so-called SUPERCLAUS ™ process. This uses a catalyst, as described in European patent applications Nos. 242,920 and 242,006, and European patent application 409,353, in which this catalyst is used in a third or fourth reactor step, as described inter alia in "Hydrocarbon Processing", April 1989 , pages 40-42. Using this method, the last residues of H 2 S contained in the inert gas stream are selectively oxidized to elemental sulfur according to the reaction H 2 S + V 2 O 2 -> S + H 2 O increasing the efficiency to 98.5-99.5%. The residual gases from a residual gas sulfur cleaning installation, such as a SCOT or SUPERCLAUS installation, are afterburned in a post-combustion installation or incinerator, before the residual gases are emitted.

In the above process steps, the total SO 2 emission is the sum of the efficiency loss in the gas purification step and in the sulfur recovery step. In the case where, for example, 10,000 Nm3 / h synthesis gas, containing 1 vol.% H2S, is treated in a gas purification plant having an efficiency of 99.5% and then in a sulfur recovery plant with an efficiency of 95%, the total SO2 emissions 5.475%, which corresponds to a total sulfur recovery efficiency of 94.525%.

For an equal amount of synthesis gas with the same concentration of hydrogen sulfide, where the gas purification installation has an efficiency of 99.95% and the Claus installation followed by a SCOT installation has an efficiency of 99.8%, the total S02 emission is 0.25% based on the sulfur initially present, which corresponds to a total sulfur recovery efficiency of 99.75%.

It is very difficult and expensive to achieve total sulfur recovery efficiencies above 99.9%.

The use of redox processes in scrubbing, which involves direct oxidation of H 2 S to sulfur in aqueous solutions, is less suitable for removing large amounts of sulfur. Apart from the fact that these processes can only be used with gases with a low sulfur content, the recovered sulfur is of very poor quality due to contaminants with substances from the solvents used. Blockages also occur frequently, there is a high chemical consumption and environmental problems are caused by waste chemicals, which can sometimes be very toxic, such as the arsenic compounds released in the known Stretford process.

A drawback of the use of fixed bed scrubbing processes is that most of these processes absorb the H 2 S, after which the absorbent is no longer suitable for reuse. Fixed bed absorption of absorbent that can be regenerated presents significant problems. An example of this is the absorption of H2S formed on iron oxide during coal gasification, where the H2S is converted into Fes (cf. H. Shirai et al, "Development of fixed bed desulfurization systems with honeycomb type iron oxide sorbens for hot coal gas"; study presented at the fourth world congress of Chemical Engineering, Karlsruhe, June 1991). as appears from this nomination, a number of problems also arise in this (modern) manner of gas purification using iron oxide, in particular in connection with the regeneration of partially converted absorbent.

Also in the gas adsorption to activated carbon, which is optionally impregnated with, for example, iodine, whereby the h2S in the gas is directly oxidized with oxygen to elemental sulfur below 120 ° C according to the reaction H2S + V2 02 ----> S + H20 and where the sulfur is adsorbed in the pores of the activated carbon, the activated carbon is usually used once, so that in this case too the process presents a waste problem (cf. Dechema Monographies 64 (1970) p. 91 et seq).

The group of fixed bed processes also includes the catalytic selective oxidation processes discussed above.

In this gas purification by means of a selective oxidation catalyst, in which the H2S in the gas is oxidized to sulfur above the sulfur melting point of 120 ° C, as described, for example, in European patent application 242.920 and in German patent application 39 03 294, the drawback is that it gas leaving the gas purification, after condensation of the sulfur formed, still contains sulfur vapor. After all, after condensation of the sulfur, the gas is still saturated with sulfur vapor. This sulfur vapor can cause serious blockages in the fuel gas pipe system. Another inevitable problem is that even small amounts of SO2 are formed when using the oxidation catalyst. S02 and water vapor can cause serious corrosion problems in the fuel gas system after condensation.

according to the invention a method is proposed in which the total sulfur recovery efficiency can be considerably increased, the loss of efficiency being even negligibly small, for example less than 0.1%, and therefore no or virtually no sulfur component and more via the chimney to the atmosphere. In addition, according to at least one of the variants of this method, a significant number of the listed operational problems can be solved. Finally, the method according to the invention is considerably cheaper than the methods known from the prior art.

The invention therefore relates to a method for treating synthesis or fuel gas obtained by coal gasification, residue gasification, waste gasification or oil gasification, wherein the gas stream obtained by gasification, which contains reducing and optionally inert gases, optionally after separation of the desired product synthesis or fuel gas , is treated to remove sulfur, then hydrogenated, the sulfur compounds still present in the gas stream being converted to hydrogen sulfide, the hydrogen sulfide being removed from the gas stream by adsorption or absorption to a solid or liquid adsorbent or absorbent, and the loaded adsorption or absorbent is supplied to the coal, residues, waste or oil to be gasified.

Suitable raw materials for gasification to synthesis or fuel gas are the sulfur-containing raw materials customary in the art, such as various types of coal (coal, brown coal and the like), oil (fuel oil and other, often heavy petroleum fractions), waste (household waste, plastic, waste sludge and the like) and residues.

The synthesis or fuel gas is preferably obtained from the gasification of coal, fuel oil or petroleum residue residues.

It has also proved possible to add waste rubber from used tires to the gasification. The rubber is gassed in a clean manner, which gives a good solution to this waste problem.

The actual gasification is carried out in a manner known in the art in a suitable gasification unit.

The method according to the invention can be carried out in a number of ways. According to a first variant, the gas stream from the gasification is split into a synthesis or fuel gas stream and a gas stream containing the sulfur compounds. The latter gas stream is then purified in a known manner, by oxidation of the oxidizable sulfur compounds to elemental sulfur, which is subsequently separated by condensation. Residual gaseous sulfur and sulfur compounds are hydrogenated to h2S. The sulfur compounds present are then taken up, if desired after oxidation, by a solid or liquid ad- or absorbent (hereinafter referred to as sorbent). The sorbent thus loaded is finally fed to the gasification feed.

The splitting of the gas stream from the gasification into a synthesis or fuel gas stream and a gas stream containing the sulfur compounds can take place in a conventional manner, for example in one of the ways discussed in the introduction.

According to another embodiment of the invention, the total gas stream is subjected to a selective oxidation of the h2s, which oxidation is carried out such that most of the hydrogen sulfide present is oxidized to elemental sulfur, which is then separated. The gas stream is then treated in the manner described above: hydrogenation, sorption and addition of the charged sorbent to the gasification feed.

The core of the invention lies in the manner in which the last residues h2S are removed from the largely purified gas. Surprisingly, it has been found that by ad- or absorption of the latter residues of H2S using a material that is supplied after loading to the feed of the gasification, there is no or virtually no residual H2S in the synthesis, combustion or off-gas behind remains. The sorbent is used once for the removal of very small amounts of sulfur from very large gas flows. This is in contrast to the known methods where the complete purification of the gas stream is carried out with the solid, while according to the present invention only the last residues of sulfur are removed. The inventive, specific combination of measures avoids the environmental concerns and the economic disadvantages of the known methods.

The solid or liquid sorbent can be any substance that does not adversely affect the gasification process. A number of substances, including carbon, are known in the art which, by themselves, are suitable for the adsorption or absorption of hydrogen sulfide (Advances in Petroleum Chemistry Refining vol 6, Chapter 7, Interscience Publishers, 1962). Taking into account various process conditions, such as the occurrence of slag formation, whether or not desired, the choice of the most suitable agent is within the reach of the skilled person. The sorbent can be solid or liquid.

Liquid sorbents include, for example, oils such as sponge oil or waste oil, but also mineral oil, vegetable oil or an alkaline reacting aqueous solution, such as a solution of sodium, potassium and / or calcium hydroxide, or lime milk.

As solid sorbent, use can advantageously be made of iron oxide, copper oxide, calcium oxide and / or manganese oxide, activated carbon, or activated or not activated coal, or brown coal. When using solid sorbents, the process can be carried out in such a way that the H2S obtained after the hydrogenation are oxidized with oxygen at a temperature of less than 120 ° C to elemental sulfur, which is deposited on the sorbent, after which the loaded sorbent is fed to the power supply of the gasification. This can be done in particular when using activated carbon, whether or not activated coal, or brown coal. When iron oxide, copper oxide, calcium oxide and / or manganese oxide are used, there will rather be a conversion of the sorbent into the corresponding sulfide, which is fed to the feed of the gasification.

It is to be noted that European patent application 91 551 describes a process in which hydrogen sulphide-containing gases are subjected to direct catalytic oxidation in a tubular reactor. Hydrogen sulfide is thereby oxidized to elemental sulfur, which is separated in a condensation step. The reaction gas obtained after the catalytic oxidation and sulfur separation still contains 5-10% of sulfur compounds which have not been removed.

In order to effect a further reduction of the sulfur content in the reaction gas, this publication proposes, inter alia, to subject the obtained reaction gas to a catalytic Claus reaction, whereby the total hydrogen sulfide conversion can be increased to 98%. It is also proposed to add hydrogen gas to the gas and subsequently hydrogenate the sulfur compounds at an elevated temperature to hydrogen sulfide using a nickel and / or cobalt and molybdenum-containing catalyst. The hydrogen sulfide can then be washed out of the gas using a solvent. After regeneration, this hydrogen sulfide can be recycled to the tube reactor.

Also, in said publication, it is proposed to remove the hydrogen sulfide from the gas by contacting the gas with an oxygen-containing gas and ammonia gas and then passing over activated carbon, oxidation of hydrogen sulfide adsorbing to the activated carbon, occurs. For complete sulfur regeneration, a hot gas, such as carbon dioxide or nitrogen, is passed over the activated carbon, while the sulfur present on the activated carbon can further be extracted with, for example, polyammonium sulfide caustic. There is therefore no question of the loaded sorbent being fed to the feed to be gasified.

In a preferred embodiment of the present invention, the method is characterized in that the sorbent is the medium to be gasified, and in particular coal. surprisingly, it has been found that when oxidative adsorption is used, i.e. when the adsorption is carried out in an oxygen-containing medium, for instance by adding an amount of air to the gas to be adsorbed, about one to a maximum of about thirty percent of the total amount of coal to be gassed is required.

In addition to the medium to be gasified, the sorbent can advantageously contain active carbon, dolomite, lime, iron compounds and / or siderite.

The synthesis or fuel gas from the gasification will usually contain COS, CS2, CO2, HCN and NH3 in addition to CO, H2 and H2S. Such a gas is highly reducing.

According to the first embodiment of the method according to the invention, the gas stream to be treated is split into a purified synthesis or fuel gas stream and a sulfur-containing gas stream.

This is done by largely removing the sulfur present in the synthesis or fuel gas using a known gas purification, for example by chemical, physical, or chemical-physical gas purification, in combination with a sulfur recovery method. The sulfur compounds are thereby oxidized as much as possible to elemental sulfur which is subsequently condensed. The remaining sulfur and sulfur compounds are catalytically hydrogenated and removed from the gas stream. The latter takes place according to the invention by adsorption or absorption and feeding the thus obtained charged sorbent to the feed of the gasification. If desired, immediately after the hydrogenation, eu uööi vein uö H.20 can refer uöiu wuiueu unuui uutipeiaajLiiy from a known method, for example a SCOT process.

According to a second embodiment of the method according to the invention, first the majority of the sulfur compounds present in the synthesis or fuel gas are converted into elemental sulfur by selective oxidation, which is subsequently condensed. The remaining sulfur and sulfur compounds are catalytically hydrogenated and removed from the gas stream. The latter takes place according to the invention by adsorption or absorption and feeding the thus obtained charged sorbent to the feed of the gasification. If desired, part of the H 2 S can be removed immediately after the hydrogenation using a known method, for example a SCOT process.

In the selective oxidation step, which is carried out optionally after separation of the synthesis or fuel gas, H2S is converted into elemental sulfur via a suitable selective oxidation catalyst according to the reaction H2S + 1/02 O 2 + S + H 2 O.

Preferably, the selective oxidation catalysts are used as described in European patent applications 242,920 and 242,006 and in European patent application 409,353, because they give a conversion efficiency of more than 80%. The contents of these patent applications are incorporated herein by reference. It is surprising that the conversion percentages obtained are achieved with these catalysts upon oxidation in the presence of highly reducing gases as in the present case.

The catalyst of European Patent Applications 242,920 and 242,006 contains a support whose surface which can come into contact with the gas phase under the reaction conditions does not exhibit alkaline properties, while a catalytically active material is applied to this surface. Furthermore, the specific surface area of this catalyst is less than 20 m2 / g and less than 10% of the total pore volume in this catalyst has a pore radius between 5 and 500 A.

The catalyst of European patent application 409,353 has a specific surface area of more than 20 m2 / g and an average pore radius of at least 25 Å, while under the reaction conditions this catalyst has substantially no activity for the Claus reaction.

However, the process of the invention can also be carried out using other oxidation catalysts, such as, for example, the Rhone Poulenc CRS-31 catalyst, a TiO2 catalyst described in European patent applications 38741 and 60741; the so-called Selectox catalyst described in U.S. Pat. Nos. 4,123,507, 4,243,647 and 4,311,683; the catalyst described in U.S. Patent 4,197,277; the catalyst described in U.S. Patent 4,519,992; the catalyst described in European patent application 91,551; and the catalyst described in European patent application 84200720.5.

However, these catalysts have a lower conversion efficiency, because they are sensitive to water, so that the reverse Claus reaction takes place depending on the water concentration in the gas, namely | sn + 2 H2O - »SO2 + 2 H2S.

The SO2 formed here will consume more H2 on hydrogenation, which is economically unattractive. In addition, much more hydrogen sulfide must be removed in the last step, increasing the amount of sorbent required and thereby making the process more expensive.

The selective oxidation reaction proceeds best in the temperature range between 180 ° C and 300 ° C with a slight excess of atmospheric oxygen. The oxygen / hydrogen sulfide molar ratio is preferably set between 0.5 and 2.0, especially between 0.5 and 1.0. It is practically inevitable that a small amount of SO2 is produced by side reactions, for example by gas phase oxidation of sulfur vapor. Importantly, the temperature in the selective oxidation bed is kept above the dew point of sulfur to prevent condensation of the sulfur formed in the catalyst bed.

The selective oxidation of hydrogen sulfide takes place with the aid of a suitable catalyst. In this selective oxidation, most of the hydrogen sulfide, preferably more than 50%, present in the gas stream is converted and recovered as elemental sulfur. Subsequently, all sulfur compounds and oxygen residues resulting from recovery side reactions are converted to hydrogen sulphide and water by hydrogenation.

Preferably, the selective oxidation of hydrogen sulfide is performed with a slight stoichiometric excess of oxygen over the hydrogen sulfide.

The gas mixture from the selective oxidation reactor is cooled to 125-160 ° C, condensing the sulfur. After condensation of the sulfur, the gas mixture consists of sulfur components in the form of H2S, SO2, sulfur vapor and sulfur mist and a small amount of oxygen.

In the process of the invention, these sulfur components are converted using a catalyst with hydrogenating properties. S02 and elemental sulfur in the form of vapor and entrained small mist droplets are converted to hydrogen sulfide with hydrogen, and oxygen is converted to water with hydrogen according to the reactions S02 + 3H2 - * H2S + 2H20 + heat S8 + 8H2 - * 8H2S 1/2 02 + h2 - * h20 + heat

In the embodiment of the method according to the invention, in which the sulfur compounds are primarily not separated, the required hydrogen is already present in the gas mixture. In the other embodiment of the process according to the invention, in which the sulfur compounds are initially separated from the synthesis or fuel gas, a small amount of the purified synthesis or fuel gas is preferably supplied to the feed of the catalytic hydrogenation reactor.

In carrying out this hydrogenation, the gas stream is heated from the condensation temperature of 125-160 ° C to a temperature level of about 200 ° C or higher, depending on the properties of the selected hydrogenation catalyst. Preferably, the gas flow is heated to 250-300 ° C. Catalysts that have the desired hydrogenating properties and are additionally sulfur-resistant are known to those skilled in the art and are often supported alumina catalysts containing Co-Mo as described in Catal. Rev.-Sci.Eng. 2X, (2), 275-318 (1980).

When CO2 is also present in the gas stream in addition to H2S, the CO2 will not interfere with the selective oxidation, hydrogenation and absorption or adsorption.

When the gas stream also contains COS and / or CS2, it is preferred to hydrolyze COS and / or CS2 in or after the hydrogenation reactor, because the gas stream there is already at the desired temperature level and the H2S concentration is lowest there.

when the gas stream contains HCN and NH3, the gas is preferably washed or HCN and NH3 are converted to completely remove these components, removal by gas scrubbing or conversion will preferably take place before the selective oxidation step.

if the gas stream contains a lot of CO, the water content will have to be controlled to control the reaction co + h 2 O -> co 2 + H 2 + heat in the hydrogenation step. This method is described in European patent application 324,526, the contents of which are incorporated herein by reference.

In the process of the invention, the gas stream is then purified from the residual H 2 S by absorbing or adsorbing it preferably to coal gasified or oil residues to be gasified and then to feed the gasification in adsorbed or absorbed form.

When the gas stream to be purified is the synthesis or combustion gas and has an elevated pressure, for example 20 bar, the solid or liquid sorbent must also be brought to that pressure. Systems for supplying solids under pressure are known. So-called lockhoppers are used for coal gasification. These are parallel sluice vessels that work discontinuously; when one is discharged, the other is filled. The solid is introduced into the sluice vessel at atmospheric pressure, after which it is closed. The vessel is then brought to a pressure of at least 20 bar with a suitable gas, for example nitrogen, then the content is introduced via a dosing device, for example a cell wheel sluice, into a pipe for pneumatic transport, or directly into the adsorber or absorber. The pneumatic transport can take place with an inert gas such as nitrogen, but also with the synthesis or fuel gas itself to be purified.

Intensive contact between the gas to be purified and the sorbent is effected in the absorber. Air is optionally and preferably added to the gas to promote oxidative adsorption.

in general, the contact time of the gas to be purified with the sorbent is not critical, although, depending on the type of sorbent and the nature and amount of the hydrogen sulfide to be removed from the gas, an optimum contact time is in principle given for each sorbent. This can easily be found experimentally. Depending on the type of sorbent, a different but maximum loading will apply, so that it loses its activity after a certain residence time. It is therefore recommended to pass the sorbent through the adsorber in such a way that the spread in residence time remains limited.

The contact of the gas with the sorbent can proceed in co-current, counter current, cross flow or a combination of these flow patterns. Cross-flow has proven to be the most suitable for activating the sorbent with hydrogen sulphide-containing gas, because it ensures a relatively long contact between the sorbent and the gas with the highest hydrogen sulphide concentration. In this case, the ab or adsorber has an activation portion and an ab or adsorption portion. In the activation section, the unactivated sorbent is contacted with the crude gas, after which, in the ab or adsorption section, the gas flowing out of the activation section is purified countercurrent with activated sorbent to the desired level. It is also possible to design the absorber or adsorber as a cascade of contact devices, in order to limit the residence time spread of the solid and to achieve the desired contact pattern of gas and solid.

In the method according to the invention, the selection of a suitable contact device is not critical. The optimal choice will be determined, inter alia, depending on the size of the sorbent particles.

When the sorbent consists of a fine powder, for example, pulverized coal as it is fed to the gasifier, the use of a fluidized or circulating bed is most suitable. These beds are known per se, for example in catalytic cracking and fluidized bed combustion. because of the spread in particle size, a part of the solid can be carried along with the gas stream. A gas-solids separator returns the solids to the bed. In principle, cyclones, whether or not combined with a filter, have proved suitable. In order to keep the adsorber compact while still creating a large surface area, due to limitations in gas velocity, the use of a tray column has proven suitable. This also provides a stepped flow of the sorbent.

If the sorbent is coarser in texture, a packed bed may suitably be used. Preferably, this bed is continuously changed (moving bed), for example by using a transport lock in the bottom. Such a principle is known in the so-called storey furnaces. A packed bed with coarse sorbent has the advantage over the fluidized bed that the gas velocity, based on the ad or absorber diameter, can be higher without the solid being blown away or an excessive pressure drop being created.

The use of a cyclone, optionally together with cloth, ceramic or electrostatic filters, has proved suitable for the separation of entrained sorbent from the purified gas stream. A cyclone with a ceramic candle filter behind it is known per se.

After the sorbent is loaded, it is sent to the gasifier. A suitable method for this is to introduce the loaded sorbent into a pneumatic conveying system, for example using a cell wheel sluice, and then directly to gasify it, when a coarse sorbent is used it is recommended to grind it first. In the case of coal gasification, it can then be mixed with the coal in the transport chain to the lockhoppers feeding the gasifier.

To obtain good hydrogen sulfide adsorption to coal, some types of coal must undergo thermal pretreatment.

It is also possible to use liquid sorbents. Sponge oil is known, in which H2S is absorbed from the gas stream to be purified by absorption in the oil. Waste oil can also be used for this purpose.

The oil can be brought into contact with the oil in a column provided with gas / liquid contact trays or with a packing material in co-current or countercurrent.

Optionally, air and / or a solid sorbent such as activated carbon, pulverized coal or brown coal can be added to the oil to obtain a more complete absorption.

In addition to coal and / or oil residues, other sorbents can be used, such as activated carbon, dolomite or lime (CaO), iron oxide, iron ore, siderite and the like. When H2S is absorbed on dolomite or iron oxide, CaS and FeS are formed, respectively. When returned to the gasification plant, h2S, COS and CS2 are formed again on combustion, which are converted back into elemental sulfur in the process according to the invention. Because the amount of the sorbent is relatively small, this has an effect on the quality of any slag formed. no influence.

The use of coal, oil, waste and residual gasification is economically justified compared to a direct fired installation, if the emission is lower and the yield is higher.

The process according to the invention will contribute to this, because the addition of sulfur-loaded sorbents to the medium to be gasified gives a total sulfur recovery efficiency of more than 99.9%.

Figure 1 gives a schematic overview of a method according to the invention.

An amount of coal or oil residue to be gasified is fed via line 1 to the gasification installation 2. The synthesis or fuel gas produced is fed via line 3 to the selective oxidation reactor 5. The slag formed is discharged from the gasification installation via line 4.

The gas is brought to the desired temperature in line 3. The amount of oxygen or air required for the oxidation is supplied via line 6. The elemental sulfur produced in reactor 5 is discharged via line 7 after condensation.

In line 8, the gas is brought to the desired hydrogenation temperature before being introduced into the hydrogenation reactor 9. All SO2, residual O2, and sulfur vapor and sulfur mist droplets are converted to H2S and H2O. The gas from the hydrogenation reactor 9, after cooling, is led via line 10 to an absorber or adsorber 11.

The H2S still present in the main stream 10 is either absorbed or adsorbed in the ad or absorber 11.

The loaded sorbent is supplied via line 12 to the gasification installation 2. The desulfurized synthesis or fuel gas leaves the installation via line 13.

Figure 2 gives a schematic overview of another method according to the invention.

An amount of coal or oil residue to be gasified is fed via line 1 to the gasification installation 2. The synthesis or fuel gas produced is fed via line 3 to a gas purification 14. The slag formed is discharged from the gasification installation via line 4. The desulfurized synthesis or fuel gas leaves the installation via line 13.

The sulfur-containing inert gas stream is supplied via line 15 to the Claus plant 16, in which the majority of the sulfur compounds are converted into elemental sulfur which is removed via line 17. The gas is fed via line 18 to a selective oxidation reactor 5.

The gas is brought to the desired temperature in line 18. The amount of oxygen or air required for the oxidation is supplied via line 6. The elemental sulfur produced in reactor 5 is discharged via line 7 after condensation.

in line 8, the gas is brought to the desired hydrogenation temperature before being introduced into the hydrogenation reactor 9. All SO2, remaining 02, sulfur vapor and sulfur mist droplets are converted to H2S and h20. The gas from the hydrogenation reactor 9, after cooling, is led via line 10 to an absorber or adsorber 11.

The H2S still present in the gas stream 10 is absorbed or adsorbed in the ad or absorber 11.

The loaded sorbent is supplied via line 12 to the gasification installation 2. The desulphurised inert gas leaves the installation via line 19.

The invention is further illustrated by the following examples.

example 1

In a coal gasification plant, 2155 t / d Drayton carbon with 2.28% sulfur, corresponding to 49 t / d sulfur, was mixed with 865 t / d Drayton carbon from a sulfur adsorption step with a total of 36.7 t / d sulfur. This total amount of 3000 t / d Drayton coal with 85.7 t / d sulfur was supplied to the gasifier along with 3000 t / d oxygen and 400 t / d steam.

The pulverized coal was gasified at a temperature of 1500 ° C and a pressure of 25 bar abs. The coal gas was cooled to 250 ° C by recirculation gas cooling and a synthesis or fuel gas cooler, after which the gas was de-dusted by dry gas filters and a wet dust trap. This produced an acidic slurry that was fed to a stripper. In the wet dust collector, the gas further cooled to 120 ° C. The gas was then warmed to 180 ° C and passed through a reactor filled with a titanium oxide catalyst to convert HCN to NH 3 and CO2.

In a second reactor, at the same temperature of 180 ° C, the COS was hydrolyzed over a Cr 2 O 3 on alumina catalyst to CO2 and H 2 S. The gas was then cooled to 40 ° C. The condensing water vapor thereby was discharged to an acid water stripper. The gas amount of 5618 t / d (250,000 Nm3 / h) thus obtained had the following composition at a temperature of 40 ° C and a pressure of 23 bar abs.

1.0 vol.% H2S 1.8 vol.% CH4

7.8 vol.% CO2 0.02 vol.% COS

30.0 vol.% H2 traces CS2 59.0 VOl.% CO 0.38 vol.% H20

The gas was then heated to 200 ° C using a heat exchanger. 2000 Nm3 / h oxygen was supplied to the gas mixture. The oxygen / H2S molar ratio was adjusted to 0.8. The gas mixture was then passed through a selective oxidation reactor containing a catalyst based on iron oxide applied to silicon dioxide.

More than 80% of the H2S present in the gas was converted into elemental sulfur. The outlet temperature of the selective oxidation reactor was 285eC. The gas was then passed to the sulfur condenser where 68.6 t / d sulfur was condensed at a temperature of 130 ° C. The gas was then heated to 285 ° C to convert all sulfur components and residue O 2 in a hydrogenation reactor containing a Co-Mo on alumina catalyst to H 2 S and H 2 O using the H 2 contained in the gas. The outlet temperature of the hydrogenation reactor was 320 ° C. Then the gas was cooled to 50 ° C.

The gas mixture was fed 350 Nm3 / h oxygen resulting in an oxygen / H2S molar ratio of 0.7. Then, this total gas mixture was contacted in an adsorber with 36,000 kg / h (865 t / d) Drayton coal. The 0.2 vol.% H 2 S still present in the gas was oxidized to sulfur and adsorbed on the carbon.

A loading of 2 wt.% Sulfur on the Drayton coal was achieved. Then, the coal loaded with 36.7 t / d sulfur was ground and mixed with the 2155 t / d pulverized coal used to feed the coal gasification plant.

The product gas contained 2 ppm volume of H 2 S, so that the desulfurization efficiency was 99.98%.

EXAMPLE 2

In a refinery, 150 t / d fuel oil (Bunker C grade) containing 0.63 t / d sulfur was gassed in an oil gasification plant with 177 t / d O2 and 69.1 t / d steam. In an intensive mixer, the fuel oil was mixed with 3 t / d soot from a soot separator and 9 t / d brown coal loaded with 0.27 t / d sulfur. Carbon black and brown coal were finely ground and added to the fuel oil in dispersed form.

This mixture was fed to the gasifier burner and atomized. This mixture was gasified at 1550 ° C and 20 bar abs.

In a waste gas boiler (waste heat boiler) the gas was cooled to 300 ° C, whereby 495 t / d high-pressure steam of 40 bar abs was generated.

The partially cooled gas was passed through a soot separator where the carbon black formed in the gasifier was separated with water. The product gas was then washed in a water washer to remove the last traces of soot.

The carbon black slurry was treated with naphtha to separate water and carbon black. The carbon black was, as mentioned, mixed with the fuel oil. The amount of synthesis gas was 477,900 Nm3 / d and had the following composition at 17 bar abs and 40 ° C: 0.13 vol.% H2S 0.2 vol.% CH4 48 VOl.% CO 0.72 vol.% N2 46 vol. % H2 0.45% by volume H2O 4.5% by volume CO2

This gas was heated to 240 ° C using a gas-fired indirect heater. 380 Nm3 / d (0.54 t / d) 02 was added to the gas, resulting in an oxygen / H2S molar ratio of 0.6.

The gas mixture was fed to a selective oxidation reactor containing a titanium-containing catalyst. More than 70% of the H2S present in the gas was converted to elemental sulfur. The reactor outlet temperature was 250 ° C. The gas was then passed to a sulfur condenser where 0.63 t / d sulfur was condensed at a temperature of 135 ° C.

The gas was then heated to 285 ° C to convert all sulfur component and in a hydrogenation reactor to H 2 S and h 2 O using the h 2 contained in the gas. The hydrogenation reactor contained a Co-Mo catalyst, the support material of which was alumina.

Then the gas was cooled to 50 ° C. 130 Nm3 / d (0.2 t / d) oxygen was added to the gas mixture (oxygen / h2S molar ratio 0.7).

in an adsorber this gas mixture was contacted with 9 t / d brown coal. The 0.04 vol.% H 2 S still present was oxidized to sulfur and adsorbed on the carbon.

A loading of 3% by weight was achieved. The brown coal loaded with 0.27 t / d sulfur was then ground and mixed with the fuel oil.

The product gas contained 3 ppm volume of H 2 S so that the desulfurization efficiency was 99.97%.

example 3

In a coal gasification plant, 2000 t / d of coal was gasified with 1% sulfur.

The amount of fuel gas that became available after cooling by steam generation, after dust removal and after hydrolysis of HCN and COS was 160,000 Nm3 / h. The gas had a pressure of 25 bar abs, a temperature of 40 ° C and had the following composition: 0.4% by volume H2S 0.2% by volume CH4

2.5% by volume CO2 0.01% by volume COS

31 VOl.% H2 3.59 vol.% N2 + Ar 62 vol.% CO 0.3 vol.% H20

This gas was then contacted in a gas purifier absorber with a mono-diethanolamine solution to absorb the H 2 S and part of the CO 2.

The product gas contained 4 ppm H2S. After desorption in a regenerator, the acidic H2S / CO2 gas mixture was fed to a sulfur recovery plant.

The sulfur recovery plant consisted of a thermal stage, two Claus reactor stages and a selective oxidation reactor stage.

The amount of acid gas was 2410 Nm3 / h and had the following composition at 40 ° C and a pressure of 1.8 bar abs 26.6 vol.% H2S 66.4 vol.% CO2

1.0 vol.% H2 1.8 vol.% CO

4.2% by volume H 2 O

321 Nm3 / h oxygen was fed to the burner of the thermal stage, so that after the second Claus reactor stage 1.1 vol.% H2S and 0.05 vol.% SO2 were present in the process gas. 95 Nm3 / h air was supplied to this gas.

The oxygen / H2S molar ratio was set at 0.8. The inlet temperature of the selective oxidation reactor was 210 ° C and the outlet temperature was 270 ° C. The selective oxidation reactor was charged with an iron / chromium catalyst on cc alumina.

The sulfur formed in the sulfur recovery plant was condensed and discharged after each stage. The amount was 935 kg / h. To the remaining inert gas, the composition of which was as follows:

0.01 vol.% H2S 0.15 vol.% S02 0.22 vol.% COS / CS2 0.05 vol.% S

1.3 VOl.% CO 60.9 vol.% C02 0.11 vol.% 02 0.46 vol.% H2 6.3 vol.% N2 30.5 vol.% H20 185 Nm3 / h purified fuel gas was added, required for the next step, the hydrogenation of all remaining sulfur components and oxygen to H2S and water. The inert gas was then warmed to. 2 85 ° C and passed to the hydrogenation reactor containing a Co-Mo catalyst.

The leaving gas temperature was 325 ° C. The inert gas was then passed directly at this temperature over an absorber containing dehydrated iron spike. The remaining 0.8% by volume H 2 S was absorbed in the form of iron sulfide. The leaving inert gas contained less than 100 ppm volume of H2S. the inert gas was fed to the chimney via afterburning.

The iron oxide was loaded with sulfur to 8%. The required amount of iron oxide was 425 kg / h.

The sulfur-loaded sorbent was ground and mixed with the coal and passed into the gasifier together.

The iron sulfide completely decomposed in the gasifier. The added iron oxide eventually left the gasifier with the slag. The total desulfurization efficiency was 99.86%.

Example 4

In a residue gasification, 100 t / d residue was gassed containing 4.83 t / d sulfur together with 1.7 t / d activated carbon charged with 0.084 t / d sulfur, and 2 t / d carbon black from a soot separator.

The synthesis gas obtained during the gasification had a pressure of 15 bar abs and a temperature of 35 ° C. The amount was 260,000 Nm3 / d and had the following composition.

1.3 vol.% H2S 0.3 vol.% CH4 51.0 vol.% CO 0.4 vol.% N2

41.0 vol.% H2 0.1 vol.% COS

5.5 vol.% CO2 0.4 vol.% H 2 O

This gas was contacted in a scrubber with a physical solvent in which the H2S, the COS were completely absorbed and the CO2 was partially absorbed. The purified gas contained 10 ppm (vol) H 2 S.

The absorbed H 2 S, COS and CO 2 gas after desorption was passed to a sulfur extraction plant (as described in Example 3) where H 2 S and COS were converted to elemental sulfur.

To the inert gas of this installation, the amount of which was 13,965 Nm3 / d with the following composition: 0.01 vol.% H2s 0.15 vol.% SO2 0.21 vol.% COS / CS2

0.05% by volume S

1.2 vol.% CO 61.28 vol.% CO2 0.1 VOl.% O2 0.4 vol.% H2 6.6 vol.% N2 30.0 vol.% H20 610 Nm3 / d purified synthesis gas was added for hydrogenation of sulfur components and oxygen to H2S and water. The inert gas was then warmed to 290 ° C and passed over a hydrogenation reactor containing a Co-Mo catalyst.

The leaving gas temperature was 320 ° C. The inert gas was then cooled to 40 ° C with 2.8 t / d of water condensing, which was discharged from the system.

210 Nm3 / d air was supplied to the inert gas. This gas mixture containing 0.53% by volume H 2 S was contacted with 1.7 t / d activated carbon in an absorber. The H2S was converted by oxygen to 0.084 t / d elemental sulfur that deposited on the activated carbon.

The sulfur-loaded activated carbon was added to the gasifier's feed.

The leaving inert gas amount was 11190 Nm3 / d and contained 3 ppm H2S and was then fed to a chimney. The total desulfurization efficiency was 99.92%.

Claims (15)

Method for the treatment of synthesis or fuel gas obtained by coal gasification, residue gasification, waste gasification or oil gasification, wherein the gas stream obtained by gasification, which contains reducing and optionally inert gases, is treated, if appropriate after separation of the desired product synthesis or fuel gas to remove sulfur, then hydrogenated, the sulfur compounds still present in the gas stream being converted to hydrogen sulfide, the hydrogen sulfide being removed from the gas stream by adsorption or absorption on a solid or liquid sorbent and the loading sorbent on the coal to be gasified, residues , waste or oil is supplied. Method according to claim 1, characterized in that the sorbent consists wholly or partly of the medium to be gasified. A method according to claim 1 or 2, wherein active sorbent, activated or otherwise activated coal, or brown coal is used as sorbent. The process according to claims 1-3, wherein the H 2 S obtained after the hydrogenation is oxidized with oxygen at a temperature of less than 120 ° C to elemental sulfur, which is deposited on the sorbent. The process according to claim 1, wherein a petroleum fraction, such as residue, is used as sorbent. A method according to claim 1, wherein as sorbent use is made of iron oxide, copper oxide, calcium oxide and / or manganese oxide. The method according to claim 1, wherein a liquid sorbent is used, selected from the group consisting of mineral oil, vegetable oil and an alkaline reacting aqueous solution, such as a solution of sodium, potassium and / or calcium hydroxide, or lime milk. A method according to claims 1-7, wherein said sulfur removal treatment comprises at least a selective oxidation, which is carried out such that most of the hydrogen sulfide present is oxidized to elemental sulfur, which is separated. A method according to claims 1-7, wherein the sulfur compounds are separated from the synthesis gas, after which these sulfur compounds are converted into elemental sulfur in a conventional manner. A method according to claim 9, wherein the majority of the sulfur compounds are first converted into elemental sulfur in a Claus plant and then the remaining sulfur compounds are subjected to a selective oxidation to elemental sulfur. Process according to claims 8 or 10, characterized in that the selective oxidation of the hydrogen sulfide is carried out using a catalyst as described in European patent application 242.920, 242.006 and / or 409.353. A method according to claims 8-n, characterized in that the selective oxidation of hydrogen sulfide is performed using a small stoichiometric excess of oxygen over the hydrogen sulfide. 13. Process according to claims 1-12, characterized in that when appreciable amounts of HCN and / or NH3 are present in the synthesis gas, they are washed and / or converted prior to the selective oxidation. Process according to Claims 1 to 13, characterized in that when appreciable amounts of COS and / or CS2 are present in the synthesis gas, they are hydrolysed before and / or after hydrogenation. Synthesis or fuel gas obtained using the method according to one or more of claims 1 to 14.