DK144485B - PROCEDURE FOR GENERATING ENERGY USING A GAS TURBINE - Google Patents

Description

(19) DENMARK

Wj (12) PRESENTATION SCRIPTURE αυ 1 ί + ί + ί + 85 Β

DIRECTORATE OF PATENT- 0 <3 TRADE MARKET

(21) Application No. 6802/74 (51) | nt.CI.3 F 02 C 3/14 (22) Filing Date 23 Dec. 1974 (24) Race day 23 dec. 1974 (41) Aim. available Jun 28 1975 (44) Submitted Mar 15 1982 (86) International Application No. - (86) International Filing Day - * (85) Continuation Day - (62) Master Application No. -

(30) Priority 27-Dec. 1973, 428980, US Dec 27 1973, 428981, US

(71) Applicant TEXACO DEVELOPMENT CORPORATION, New York, US.

(72) Inventor Charles Parker Marlon, US: Warren Gleason iichlinger, US: Albert Brent, US: James Robert Muenger, US.

(74) Clerk Th. Ostenfeld Patentbureau A / S.

(54) Process for generating energy by means of a gas turbine.

The present invention relates to a process for generating energy by means of a gas turbine during combustion of pure fuel gas. This clean fuel gas is produced from ash and sulfur-containing carbon fuels, and the resulting fuel gas is used in the gas turbines to produce mechanical and electrical energy without any significant environmental pollution associated with it.

A conventional gas turbine of the simplest type acts large qj in that air is compressed by means of a centrifugal or axial compressor, after which a fuel is combusted with the compressed air in a combustion chamber and the heat generated by the combustion

-J

*

Q

J gases pass through an expansion turbine. Some of the turbine energy can be used to operate a compressor that may be too connected to the turbine shaft. The remainder of the turbine energy 2 144485 is generally transferred to a generator for generating electrical energy.

While, as known in the art, it may be economically desirable to burn low-quality coal and residual oil fuels directly in a gas turbine's combustion chamber, this has not proved practical when the fuels contain large amounts of ash or sulfur. Such high ash solid fuels generally release solid abrasive and corrosive particles. When such particles are carried by the flue gas passed through an expansion turbine, they are deposited on the turbine blades and erode the surface of the blades. When this occurs, the blade shape is destroyed and the gas passage in the turbine is inhibited. Furthermore, the fine particles can settle on heat exchanger surfaces on the outlet side, whereby the resulting insulation will degrade the thermal efficiency. Similar problems arise with the combustion of ash-forming liquid petroleum products. Such ashes include mineral compounds of the kind found in crude oil. These compounds are concentrated in the residue by the refining process and supplemented with silica, iron and sodium compounds which are taken up during shipping and processing. Vanadium, nickel, sodium, sulfur and oxygen are the main constituents of the ash. After combustion, these constituents appear as metal oxides, sulfates, vanadates and sodium silicates. These compounds appear to erode the protective oxide film on high temperature alloys. The oxidation is thereby accelerated, especially at temperatures in excess of ca. 649 ° C. Furthermore, SO2 in the flue gas exhaust from the expansion turbine pollutes the atmosphere. Prior art methods in which the flue gas is purified prior to introduction into the gas turbine are either impractical, extremely costly, or both.

The above problems are avoided by the highly efficient process of the invention, whereby the gas turbine is combined with a partially oxidizing fuel gas generator to generate energy without polluting the atmosphere.

The present invention thus relates to a method for generating energy (mechanical and electrical) by means of a gas turbine with a combustion chamber and an expansion turbine, which is characterized by the characterizing part of claim 1. The fuel gas can be generated by non-catalytic partial oxidation of a low-sulfur hydrocarbon fuel with high sulfur content and ash content. The improved fuel gas formed is in the presence of a combustion heat in the range of approx. 667 to approx.

3 3 3115 kcal / m, and preferably in the range of 667 to 890 kcal / m, and having a mole ratio (CO / m 0.30. Essentially, no pollution of the surroundings is associated with combustion in the gas turbine.

The process according to the invention consists essentially of the following steps: (1) reacting a hydrocarbon-containing fuel with a free oxygen-containing gas by partial oxidation in the presence of a temperature moderator in the reaction zone of a non-catalytic free-flow gas generator at an autogenous temperature in the range from approx. 816 to approx. 1927 ° C and at a pressure in the range of approx. 10 to approx. 180 ata for producing a waste gas stream comprising mixtures of, CO, CO 2 and H 2 O and one or more constituents in the form of CH 2, COS, 1 S and Ar as well as particulate carbon in which the exhaust gas stream molar ratio (CO / H2) is at least 0 , 30; (2) cooling the exhaust gas stream from (1) and introducing the cooled gas into a gas purification zone from which the following streams are separately obtained: (A) a pure fuel gas stream comprising a mixture of H2 and CO which also contains one or more constituents in the form of N 2, CH 2, CO 2 and H 2 O; (B) a CO 2 rich gas stream; (C) a slurry stream comprising particulate carbon in a liquid carrier; and (D) a gas stream rich in H2S and COS; (3) introducing and combusting the stream of pure fuel gas from (2) into the combustion chamber of a gas turbine with a gaseous oxidizing stream formed at a later stage in the process of producing a stream of pure flue gas; and (4) using the stream of pure flue gas from (3) as a working medium passed through an expansion turbine to generate energy during the development of a clean exhaust flue gas, at least part of which is mixed with air to form the gaseous oxidizing agent. current under (3).

Preferably, the free heat of at least a portion of the clean exhaust flue gas from the expansion turbine under step (4) can be used to preheat the clean fuel gas introduced into the combustion chamber. Another portion of the exhaust flue gas may be used to preheat a compressed gaseous oxidizing stream consisting of air and a portion of the exhaust flue gas. This preheated oxidizing stream is introduced into the combustion chamber of the gas turbine. Conveniently, a portion of the gaseous oxidizing stream can be introduced into the fuel gas generator. The gaseous oxidizing stream can be compressed by a compressor coupled to the expansion turbine.

If desired, the molar ratio (CO / H2) in the fuel gas stream can be increased by mixing an additional CO gas conversion at a temperature of at least 816 ° C.

According to the present invention, there is thus provided an improved continuous process for producing thermal, electrical and mechanical energy by means of a gas turbine. Hydrocarbon-containing materials including liquid and solid fuels containing a relatively high content of ash and sulfur can be used to provide, under partial oxidation, a fuel gas in a separate, non-catalytic, free-flow synthesis gas generator. If desired, the mole ratio (C0 / H2) in the fuel gas can be increased by reverse thermal conversion.

The quality of the fuel gas can be further improved for combustion in the off-site gas turbine, using such steps as cooling by indirect heat exchange with water in a waste heat boiler to produce steam and purification to remove solid suspended components and sulfur compounds. The resulting improved fuel gas is then combusted with a gaseous oxidant in the combustion chamber of the gas turbine to produce pure flue gas. As further described below, the pure flue gas is fed into an expansion turbine as a working medium and energy is generated. The above gaseous oxidizing stream comprises a mixture of air and a portion of the exhaust flue gas from the expansion turbine. The power obtained from the turbine shaft can be used to operate an electric generator, to compress the gaseous oxidant for introduction into the combustion chamber of the gas turbine and to compress CO 2 for the non-catalytic thermal shift. The free heat of the clean flue gas exhaust from the gas turbine is preferably used to preheat the clean fuel gas and the gaseous oxidizing stream prior to its introduction into the combustion chamber. After heat exchange, the exhaust gas from the gas turbine can be discharged into the atmosphere practically without the associated pollution of the surroundings. This can be done, preferably after the exhaust gas is further expanded through an energy generating turbine. Suitably, part of the exhaust flue gas from the gas turbine, with or without mixing with air, can be introduced into the gas generator. Keeping the 5 U4485 fuel value of the improved fuel gas in the range of approx.

ISLAND

667 to approx. 3115 kcal / m can be the amount of nitrogen oxides (NO)

X

in the flue gas is kept below 10 parts per million.

In the process of the invention, by partial oxidation, a continuous stream of fuel gas is first produced in the refractory lined reaction zone by a separate, unpacked, non-catalytic free-stream gas generator. The gas generator is preferably designed as a vertical steel pressure vessel, as shown in the drawing and disclosed in the specification of U.S. Patent No. 2,992,906.

A large number of different combustible carbonaceous organic materials can be reacted in the gas generator with a free oxygen-containing gas in the presence of a temperature moderating gas to produce the fuel gas.

The term "hydrocarbonaceous" used herein to describe various suitable feed materials is intended to include gaseous, liquid and solid hydrocarbons, hydrocarbonaceous materials and mixtures thereof. In fact, virtually any combustible carbonaceous organic material or slurry thereof falls within the definition of the term "hydrocarbonaceous". Eg. may be obtained (1) slurries of solid carbonaceous fuels which can be pumped, such as coal, particulate carbon, petroleum coke, concentrated sewage sludge, and mixtures thereof, (2) gas-solid suspensions such as finely ground solid carbonaceous fuels dispersed in either a temperature moderating gas or in a gaseous hydrocarbon; and (3) gas-liquid-solid dispersions such as finely atomized liquid hydrocarbon fuels or water and particulate carbon dispersed in a temperature moderating gas. The hydrocarbon-containing fuels may have a sulfur content in the range of approx.

0 to approx. 10% by weight and an ash content in the range of approx.

0 to approx. 15% by weight.

The term "liquid hydrocarbon" as used herein to describe suitable liquid feed materials is intended to include various materials such as liquid petroleum gas, petroleum distillates and residues, gasoline, naphtha, petroleum, crude oil, asphalt, gas oil, residual oil. , tar sand and shale oil, coal oil, aromatic hydrocarbons (such as benzene, toluene and xylene fractions), coal tar, circulating gas oils from fluid catalytic cracking operations, furfural extracts of coking gas oil, and mixtures thereof. Suitable gaseous hydrocarbon fuels for gaseous feedstocks include methane, 6 UU85 ethane, propane, butane, pentane, natural gas, water gas, coke oven gas, refinery gas, acetylene residual gas, ethylene off gas, synthesis gas, and mixtures thereof. Both gaseous and liquid feed materials can be mixed and used simultaneously and may contain paraffinic, olefinic, naphthenic and aromatic compounds in any ratio.

The term "hydrocarbonaceous" also includes oxygenated hydrocarbonaceous organic materials such as hydrocarbons, cellulose materials, aldehydes, organic acids, alcohols, ketones, oxygenated fuel oils, waste liquids and by-products of chemical processes containing oxygenated hydrocarbonaceous organic materials and mixtures thereof.

The hydrocarbon-containing feed may be at room temperature or may be preheated to a temperature in the range of from about. 316 to approx. 649 ° C, but preferably below the cracking temperature thereof. The hydrocarbon-containing feed may be introduced into the liquid phase burner or into a vapor mixture with a temperature moderator. Suitable temperature moderators may be mentioned H2O, CC2-rich gas, a portion of the cooled clean exhaust gas from the exhaust side gas turbine of the invention used with or without admixture of air, nitrogen by-product of the air separation plant which will be further described, and mixtures of the aforementioned temperature moderators.

The use of a temperature moderator to moderate the temperature in the reaction zone generally depends on the carbon-to-hydrogen ratio of the feed material as well as the oxygen content of the oxidant stream.

A temperature moderator need not be required for some gaseous hydrocarbon fuels, but generally a temperature moderator is used for liquid hydrocarbon fuels and for practically pure oxygen. When a CO 2 containing gas stream with e.g. at least approx. 3 mole% CC 2 (dry basis) is used as a temperature moderator, the mole ratio (CO / H2) in the resulting exhaust gas stream can be increased. As mentioned above, the temperature moderator can be introduced in admixture with one or both reactant streams. Alternatively, the temperature moderator may be introduced into the reaction zone of the gas generator via a separate line in the burner.

In accordance with the present invention, the mole ratio (CO / H2) of the exhaust gas used as fuel in the gas turbine can be increased if desired. This means that a higher pressure ratio per turbine steps can be obtained and a smaller number of steps are therefore needed. The size of the turbine decreases and its thermodynamic efficiency is increased. It is preferred according to the invention that the temperature moderator consists of at least a portion of the CO 2 rich stream from step (2), at least a portion of the exhaust gas from step (4), water or mixtures thereof. When a CO 2 containing temperature moderating gas stream, e.g. a gas stream consisting essentially of pure CO 2 (at least 95 mole% CO 2 on a dry basis) recycled from the gas purification zone to be described below is used, or when part of the clean flue gas exhaust from the gas turbine to be described in the following, is used, diminished, or preferably the use of an additional amount of H 2 O is omitted. It is further preferred that a portion of the CO 2 rich gas stream from step (2) is mixed with the exhaust gas stream from step (1) and that the mixture is subjected to a non-catalytic reverse thermal water-gas conversion to increase the molar ratio (CO / H2 ) in the fuel gas flow to a value greater than 0.3. Thus, the CO 2 produced in the system can advantageously be used as a temperature moderator in the gas generator, or the CO 2 produced can be used in the reverse thermal conversion described further below, or the CO 2 formed can be used in both places.

As a temperature moderator, a gaseous stream comprising more than 3 mole% CO 2 at a temperature in the range of approx. room temperature to approx. 538 ° C and a pressure slightly above the generator pressure are introduced into the reaction zone, with the weight ratio of CC> 2 to fuel being in the range of approx. 0.3 to approx. 1.0.

When relatively small amounts of H2 O are introduced into the reaction zone, e.g. Through the burner for cooling the burner tip, the particular H2 O may be mixed with either the hydrocarbon-containing feed, the free oxygen-containing gas, the temperature moderator or combinations thereof. The weight ratio of water to the hydrocarbonaceous feedstock can range from approx. 0.0 to approx. 1.0, and preferably from ca. 0.0 to less than 0.2.

The term "free oxygen-containing gas" as used herein is intended to include air, oxygen-enriched air, ie. air containing more than 21 mole% oxygen, and substantially pure oxygen, i. more than 95 mole% oxygen (the remainder comprising N2 and noble gases). Pri oxygen-containing gas can be introduced into the burner at a temperature in the range of approx. room temperature to approx.

982 ° C. The ratio of free oxygen in the oxidant to carbon in the feed material (0 / C, atom / atom) is preferably in the range of from approx. 0.7 to approx. 1.5.

ø 144485 The feed streams are introduced into the reaction zone of the fuel gas generator by means of a burner. Suitably, an annular type burner described in U.S. Patent No. 2,928,460 can be used.

The feed streams are reacted by partial oxidation without catalyst in the reaction zone of a free stream gas generator at an autogenous temperature in the range of about 816 to approx. 1927 ° C and at a pressure in the range of approx. 10 to approx. 180 ata. The reaction time in the fuel gas generator is from approx. 1 to approx. 10 seconds. The fuel gas leaving the gas generator may have the following composition (mole% on a dry basis) assuming the amount of noble gases to be vanishing: C0 = 15-57, 1 ^ = 70-10, 002 = 1.5-5 , CH2 = 0.0-20, N2 = 0-75, H2S = 0-2.0 and COS = 0-0.1. Unreacted particulate carbon (on the basis of the weight of carbon in the feed) is from approx. 0.2 to approx. 20% by weight using liquid feed materials, but are usually vanishing using gaseous hydrocarbon feed materials. The dry molar ratio (CO / H2) in the exhaust gas from the generator is usually at least 0.30 and preferably in the range of 0.30 to 1.5.

The flow of hot exhaust gas from the gas generator is introduced into a separate refractory lined steel chamber, preferably at a temperature in the range of from approx. 816 to approx. 1927 ° C, i.e. a temperature such as that produced in the gas generator, and approx. at the gas generator pressure, e.g. a pressure of 10 to 180 ata, and preferably 15 to 60 ata. Eg. For example, a spherical chamber 12 such as that shown in the drawing and disclosed in U.S. Patent No. 3,565,588 may be used. The spherical chamber is unpacked and contains no obstructions to the gas flow therein. Part of the solid which may be entrained in the exhaust gas flow stream is separated and can be removed via a discharge located in the bottom of the spherical chamber leading to a sluice chamber (see the flanged discharge 13 shown in the drawing).

When it is desired to further increase the mole ratio (CO / h 2) in the exhaust gas stream, the following non-catalytic, thermal, reverse water-gas conversion steps may be used. A stream of supplemental CO 2 rich gas, which is subsequently extracted by the process, is simultaneously introduced into the spherical chamber at a temperature in the range of approx. 260 to approx. 816 ° C and at a pressure slightly higher than the gas generator pressure.

In this case, on a dry basis, approx. 0.1 - 2.5 moles of supplemental CC> 2 in the spherical chamber per moles of exhaust gas from the gas generator.

9 144485

The gases are mixed and, by non-catalytic, thermal, reverse water-gas conversion at a temperature of at least 816 ° C, and preferably in the range of from approx. 816 to approx. 1538 ° C, the relevant CO 2 is reacted with a portion of the hydrogen in the exhaust gas stream from the generator to generate additional CO and H2 O. The dry molar ratio (CO / H2) in the exhaust gas from the gas generator can be increased at this stage by approx.

10 - 200%, and suitably 15 - 50%. Thus, the exhaust gas stream may leave the thermal conversion zone with a dry base molar ratio (CO / H2) ranging from above 0.3 to 6.0, and preferably in the range of from about. 0.4 to approx. 4.5 and advantageously more than 1.5. Thus, it is preferred that the CO 2 rich gas stream from step (2) is compressed to a pressure which is above the pressure of the gas generator in step (1) by a compressor driven by the expansion turbine of step (4), and that the temperature of the water-gas conversion is kept at least 816 ° C, and that the CO / H2 molar ratio is increased to a value (dry basis) in the range from above 0.3 to 6.0.

The aforementioned adiabatic, non-catalytic, thermal, reverse high temperature water-gas conversion begins in the isolated spherical chamber and continues in the isolated conduit connecting the spherical chamber side discharge to the flanged conduit at the bottom of a waste heat boiler. In this connection, reference is made to U.S. Patent No. 3,723,344. Thus, the exhaust stream of fuel gas is thermally converted without catalyst at the passage between the process steps. The residence time in the water-gas conversion zone ranges from approx. 0.1 to approx. 5 seconds.

The aforementioned non-catalytic, thermal, reverse conversion reaction takes place in a preferably adiabatic, unpackaged free-flow reaction zone separate from the fuel gas generator. Preferably, the temperature and pressure conditions at which the reverse thermal conversion takes place are practically the same as in the fuel gas generator, except for usual pressure drop in the conduit and any cooling due to the free heat of the supplemental CO 2 flow and the endothermic reaction heat. . Increasing the C0 / H2 ratio in the fuel gas will increase its combustion heat per day. mole and increase its molecular weight. Thus, at 298 ° K: CO + ^ 2 ^ CO 2 + 67.64 kg.cal / g mole 44 molar weight H2 + ^ 2 ^ H2 O (gas) + 57.80 kg.cal / g mol 18 mol weight U4485 10

Advantageously, this improves the thermal efficiency of the exhaust gas on the exhaust side and allows the use of smaller gas turbines. In addition, the need for excess air required for good combustion in the combustion chamber of the gas turbine in the semi-closed-cycle gas turbine used in the process of the invention is less than approx. half the amount required for an open-cycle gas turbine.

The exhaust flow of fuel gas is then passed through a series-connected waste heat boiler, where indirect heat exchange with water takes place. The fuel gas stream is thereby cooled to a temperature in the range of approx. 260 to approx. 393 ° C. Hereby a by-product vapor having a temperature in the range of approx. 232 to approx. 371 ° C for use elsewhere in the process. Eg. said steam can be used as a working medium in an expansion turbine for energy production, e.g. for operating the compressor in a conventional air separation plant. If desired, the vapor can be superheated to a temperature in the range of approx. 399 to approx. 649 ° C and the superheated steam can be used as a working medium in a steam turbine. For example, the overheating may occur. This is done by indirect heat exchange with pure flue gas leaving the gas turbine or in a furnace, preferably fired with the clean fuel gas, to avoid pollution of the surroundings.

Thus, it is a preferred embodiment of the process according to the invention that the cooling of the exhaust gas from step (1) is effected by indirect heat exchange with water to produce steam and that part of the steam is heated by indirect heat exchange with the exhaust flue gas from the expansion turbine in step (4). , after which at least a portion of the superheated steam is passed as a working medium through a steam turbine operating a compressor or electric generator.

The partially cooled fuel gas flow leaving the waste heat boiler is conducted into a gas purification zone where particulate carbon and other entrained solids can be removed therefrom. Particulate carbon slurries in a liquid hydrocarbon fuel can be prepared in the purification zone and can be recycled to the fuel gas generator where it serves as at least part of the feedstock. Any conventional suitable way of removing suspended solids from a gas stream can be used. In one embodiment of the process of the invention, the fuel gas stream is introduced into a gas liquid scrubbing zone where it is scrubbed with a scrubbing fluid such as liquid hydrocarbon or water. A suitable tray-type liquid-gas column is described in Perry's Chemical Engineers' Handbook, 4th Edition, McGraw-Hill 1963, pages 18-3 to 5.

U4485

Thus, by directing the flow of fuel gas through a scrubbing column in direct contact and countercurrent with a suitable scrubbing fluid or with dilute mixtures of particulate carbon and scrubbing fluid flowing through the column, the particulate carbon can be removed from the fuel gas. A slurry of particulate carbon and scrubbing fluid is removed from the bottom of the column and sent to a carbon separation zone or concentration zone. This can be done in any suitable conventional manner, e.g. by filtration, centrifugation, sedimentation or by liquid hydrocarbon extraction, such as in the process described in U.S. Patent No. 2,992,906. Pure scrubbing fluid or diluted mixtures of scrubbing fluid and particulate carbon are recycled to the top of the column for scrubbing more fuel gas.

Other suitable conventional gas cooling and purification methods may be used in combination with or in place of the above scrubbing column. Eg. For example, the flow of fuel gas may be introduced below the surface of a quenching and scrubbing fluid basin by means of a dip tube assembly. The fuel gas stream may also be passed through a number of scrubbing steps comprising a scrubber / such as a venturi or nozzle scrubber, as shown e.g. in Perry's Chemical Engineers' Handbook, 4th Edition, McGraw-Hill 1963, pages 18-54 to 56.

Substantially no particulate carbon is formed from gaseous hydrocarbon-containing fuels such as natural gas or methane.

In such a case, the aforementioned gas scrubbing step need not be necessary.

In a further gas purification zone, CC> 2 / S, COS, O 0, NH 2 and other gaseous impurities can be removed from the cooled and purified gas stream leaving the gas purification zone to remove solid particulate impurities. Suitable conventional methods can be used for this further purification and as examples can be mentioned freezing and physical or chemical absorption with solvents such as methanol, n-methylpyrrolidone, triethanolamine, propylene carbonate, or alternatively with amines or hot potassium carbonate.

In the solvent absorption process, most of the CO2 absorbed in the solvent can be released by simple lightning evaporation. The residue can be removed by stripping. This can be done economically with nitrogen. Nitrogen can be obtained as an inexpensive by-product when a conventional air separation plant is used to produce practically pure oxygen (95 mol% O 2 or more) for use as the oxygen-rich gas in the fuel gas generator. The regenerated solvent is then recycled to the absorption column for recycling. If necessary, the final purification can be done by passing the process gas through iron oxide, zinc oxide or activated carbon to remove residual traces of H2 S or organic sulfide. If desired, a stream of CC₂-rich gas containing CO 25 to 100 mole%, and preferably in an amount greater than 98.5%, are prepared for use in the above non-catalytic, thermal, reverse water-gas conversion steps in the process. If desired, a recovered stream of CO 2 can be recycled to the fuel gas generator for use as the temperature moderating gas or a portion thereof. In such a case, small amounts of H2S and COS may be in the CO2 stream.

Similarly, the H2S and COS-containing solvent can be regenerated by flash evaporation and stripping with nitrogen or alternatively by heating and refluxing at reduced pressure without using an inert gas. H2S and COS are then converted to sulfur appropriately. Eg. For example, the Claus process can be used to produce elemental sulfur from E ^ S as described in the Kirk-Othmer Encyclopedia of Chemical Technology, 2nd Edition, Volume 19, John Wiley, 1969, page 353. Excess SO2 in the residual gases from the Claus plant can is removed and removed in chemical combination with limestone or by an appropriate commercial extraction process. In general, the composition of the pure fuel gas in mole% (dry basis) is as follows: H2 = 10 to 60, CO = 15 to 60, CH4 = 0.0 to 25, CO2 = 0.0 to 5 and N2 = 0 , 0 to 75. The calorific value in kcal / m 2 is at least 623, and suitably 668-3115, and preferably between 668 and 1335, e.g. ca. 800th

The flow of pure fuel gas from the gas purification zone is at a temperature in the range of approx. 33 to approx. 427 ° C ° g at a pressure in the range of approx. 10 to approx. 180 ata, and preferably between 15 and 60 ata. It is preferred that the pressure of the fuel gas at this location be practically the same as the pressure generated in the fuel gas generator, except for usual conduction loss. Preferably, the flow of fuel gas is preheated to a temperature in the range of from about. 204 to approx. 427 ° C by indirect heat exchange with part of the hot exhaust flue gas flow from the main expansion turbine on the process's departure side, before introducing the fuel gas into the gas turbine's combustion chamber. At the same time, approx. 1.0-3.0 volumes of one gaseous oxidizing stream per volume of pure fuel gas. The gaseous oxidizing stream comprises a free oxygen-containing gas (preferably air) in admixture with a portion of the exhaust flue gas 144485 13 from the expansion turbine described below. The volume ratio of free oxygen-containing gas to flue gas ranges from approx.

0.20 to approx. 2.0, and preferably in the range of 0.4 to 1.2. The pre-heated stream of pure fuel gas is then combusted with the gaseous oxidizing stream in the combustion chamber of the gas turbine.

When the gaseous oxidizing stream is introduced into the combustion chamber of the gas turbine at a temperature in the range of approx. 204 to approx. 427 ° C and at practically the same pressure as the fuel gas, has the pure flue gas leaving the combustion chamber at a temperature in the range of about 760 to approx. 1649 ° C, and usually 871 to 1149 ° C, and at an overpressure in the range of about 3.5 to approx. 70 kp / cm 2 or more, and preferably at 7 to 28 kp / cm 2 or more, the following typical composition in mole%: CC> 2 = 4-10, H 2 O = 3-6, N 2 = 75-85 and O 2 = 5 -10. Only a very small concentration of nitrogen oxides (NO) can be found in the flue gas. This is due to the relatively low temperature prevailing in the combustion chamber, which is primarily a result of the improved fuel gas's relatively low adiabatic flame temperature. Furthermore, the SO 2 content of the flue gas is 0 and the amount of particulate matter entailed is immaterial.

The clean flue gas leaving the combustion chamber is passed through at least one energy-generating expansion turbine as a working medium.

At least one electric generator and at least one turbo compressor can be connected via a variable speed power transmission e.g. turbine shaft. The gaseous oxidizing stream can be compressed before introduction into the combustion chamber of the gas turbine, and the carbon dioxide from the gas purification zone can be compressed before recirculation to the fuel gas generator or to the above-mentioned spherical mixing chamber by the appropriate turbo compressors for an appropriate pressure, e.g. to over 10 - 190 ata.

The clean exhaust flue gas leaves the main expansion turbine at a temperature in the range of approx. 427 to approx. 649 ° C and at a pressure in the range of approx. 1.0 to 7.0 ata. From approx. 0 to approx. As described above, about 50% by volume of this stream can, if desired, be separated and passed through an indirect heat exchange heat exchanger with its pure fuel gas on its way to the gas turbine combustion chamber. After heat exchange, the cooled clean exhaust flue gas can be discharged into the atmosphere via a chimney. There is virtually no atmospheric contamination since the gaseous impurities have been removed beforehand. Preferably, the flow of heat exchanged exhaust flue gas is discharged after further expansion in a power generating turbine.

14 144485

The remaining portion of the clean exhaust flue gas flow from the main expansion turbine is passed through an indirect heat exchange heat exchanger with the above compressed gaseous oxidizing stream. In this way, the gaseous oxidizing stream can be preheated to a temperature in the range of about 149 to approx. 427 ° C before being introduced into the combustion chamber of the gas turbine. From approx. 20 to approx. 70% by volume of the exhaust flue gas stream cooled by the above indirect heat exchange to a temperature in the range of approx. 38 to approx.

149 ° C, preferably after further expansion in an energy-generating turbine, can be discharged into the atmosphere without causing pollution. The remaining portion of the cooled exhaust flue gas stream is mixed with a free oxygen-containing gas to produce the gaseous oxidizing stream. The free oxygen-containing gas can be selected from the group consisting of air, oxygen-enriched air (containing more than 21 mole% O 2) and substantially pure oxygen (containing more than 95 mole% O 2.

Thus, preferably at normal pressure and room temperature, air can be introduced into the system by means of a feed compressor coupled to the shaft of the main expansion turbine. The mixture of air and exhaust flue gas is referred to above as the gaseous oxidizing stream, and this stream exhibits the following typical analysis in mole%: CO 2 = 3.0 to 5.0, H 2 O = 1.0 to 4.0, N 2 = 75 to 35, 02 = 10 to 20 and Ar = 0.9 to 1.5.

The gaseous oxidizing stream is compressed to the desired pressure in the range of approx. 5 to approx. 65 ata in at least one compressor preferably coupled to the shaft of the main expansion turbine. Usually, the gas flow is cooled before and between compressors. The gaseous oxidizing stream is then preheated and introduced into the combustion chamber as described above. If desired, from approx. 0 to approx. 20% by volume of the gaseous oxidizing stream is introduced into the gas generator as at least part of the temperature moderating gas.

If desired, the fuel gas formed and cooled in the waste heat boiler formed in the process in the gas generator can be used as the working medium in a series-connected energy-developing expansion turbine, which e.g. is located after the waste heat boiler and suitably after the gas purification zone to remove particulate impurities or after the additional gas purification zone to remove gaseous impurities. In particular, it is preferred that the exhaust gas stream from step (1) after cooling at a pressure substantially equal to the gas generator pressure, except for usual conduction pressure drop, be passed through an expansion turbine located on the supply side of the gas turbine combustion chamber.

14448B

Alternatively, extraction of the free heat in the pure flue gas leaving the expansion turbine at a temperature in the range of from ca. 427 to approx. 649 ° C and at a pressure in the range of approx.

1.0 to approx. 7.0 ata, is effected by heat exchange with the steam formed in the waste heat boiler on the exhaust side of the gas generator. This allows superheated steam to be formed at a temperature in the range of approx. 399 to approx. 649 ° C. The superheated steam can be used as a working medium in an expansion turbine. The shaft of the steam turbine can e.g. via a variable power transmission is connected to the shaft of a turbocharger or to an electric generator or to both. The pure flue gas can then be compressed in the turbocharger to a pressure in the range of more than 10 to 180 ata, and preferably at a temperature in the range of approx. 204 to approx. 316 ° C. The pure flue gas can then be recycled to the fuel gas generator for use as a temperature moderating gas or a portion thereof. Alternatively, the pure fuel gas can be discharged into the atmosphere without causing pollution. Alternatively, the free heat in the flue gas leaving the expansion turbine can be recovered by preheating the air introduced into the combustion chamber of the gas turbine, by forming additional high pressure steam or by preheating the boiler feed water.

The process according to the invention is illustrated in the following by means of the schematic drawing which illustrates a preferred embodiment of the method according to the invention.

Referring to the drawing, a non-catalytic, refractory lined free flow fuel gas generator 1 as described above is provided with an axially arranged and flanged supply port 2 at the inlet side and flanged outlet port 3 on the outlet side. annular type, wherein the center passage 5 is arranged axially with the axis of the gas generator 1 located in the inlet port 2. The passage 5 has an inlet end 6 and a conical shaped outlet end 7. A concentric coaxial annular passage 8 with an inlet side 9 and a conical shaped outlet opening 10 on the departure side is also provided.

To the outlet opening 3 of the gas generator 1 is connected a refractory liner spherically shaped free-flow chamber 12 via a flanged supply opening 11. The chamber 12 has a flange-provided and normally closed ash discharge opening 13, a laterally provided and flanged. inlet port 14 and a refractory liner side discharge pipe 15 whose end on the outlet side is connected to the waste heat boiler 17. For example.

Water in conduit 18 is passed through the pipe system 19 within the boiler 17 in indirect heat exchange with hot gases passing on the outside of the pipe system. The water evaporates and leaves the waste heat boiler as steam via line 20. Other suitable boilers or heat exchangers can be used.

In addition, as previously described, hydrocarbon-containing liquid or vaporized food can be introduced into the system via line 25, valve 26 and lines 27 and 34. In addition, concentrated slurries of particulate carbon in water or liquid hydrocarbon fuels can be pumped through the pump 28 from the carbon separation zone 29 through the lines. 30 and 31, valve 32, conduit 33 and into conduit 34 where mixing of the feed streams can take place. The feed mixture is then preferably preheated in the heat exchanger 220 and introduced into the reaction zone 35 of the gas generator via line 221, line 9 and the annular passage 8 or burner 4.

A portion of the steam formed in the waste heat boiler 17 can be fed into the reaction zone 35 as a temperature-moderating fluid via line 20, lines 36-38, valve 39, lines 40 and 41, and center passage 5 of burner 4. Another portion of steam from boiler 17 may used as a working medium in a steam turbine. Eg. the steam can be passed through lines 20, 36, 37, 45 and 46, valve 47 and line 48 into the expansion turbine 49. The exhaust steam leaves the turbine via line 50. The expansion turbine 49 drives the turbo compressor 51 which compresses the air supplied through line 52 and exits the compressor. via conduit 53. The compressed air can then be introduced into the reaction zone 35 of gas generator 1 via conduit 53, valve 55, conduits 56 and 57, valve 58 and conduits 59 and 41, and center passage 5 of burner 4.

If desired, all the air or part of the air from the turbo compressor 51 to the gas generator 1 can be replaced by substantially pure oxygen. Oxygen and nitrogen can be produced in an associated conventional air separation plant ASU 42, where the substantially pure oxygen outlet line is designated 63 and the nitrogen outlet line 64. Nitrogen can be used later in the process in the gas purification zone 65. Part of the in the waste heat boiler. 17 steam can be used to drive a turbine 69. In this case, the steam is passed through lines 20, 36, 37, 45 and 66, valve 67, line 68 and through steam turbine 69 as working medium, after which it leaves the steam turbine via line 70. Air is fed into the coupled turbo compressor 71 via line 72. The air is then compressed and fed into the air separation system 42 via line 73. Oxygen in line 63 is compressed by steam-driven piston or centrifugal compressor 74 and then passed through line 75, valve 76, lines 77 and 78, valve 79, lines 80 and 41 into the center passage of burner 4 5. Steam to drive compressor 74 can be obtained from boiler 17 via line 20 , 36 and 85, valve 86 and conduit 87. The energy requirements of the air separation system can be reduced by producing a free oxygen-containing gas containing 60 -80 mol% 02- Instead of or together with steam, the temperature-moderating gas introduced into the reaction zone 35 may suitably be a CO2-containing gas, e.g. a mixture of air and turbine exhaust gas formed later in the process from line 187, or a CO 2 -g stream without or with a small amount and COS from line 91 or a mixture thereof.

The CO 2 rich stream can be obtained later in the process from the gas purification zone 65 during purification of the exhaust gas stream from the gas generator 1. Thus, the CO 2 rich stream exiting the gas purification zone 65 via line 91 can be compressed in turbo compressor 92 and then fed into the gas zone 1 reaction zone via line 93 and 94, valve 95, conduits 96 and 57, valve 58, conduits 59 and 41 and the burner 4 center passage 5. Preferably, a portion of the CO 14 is introduced into the spherical mixing chamber 12 where the reverse non-catalytic thermal water-gas exchange reaction takes place with a portion of the hydrogen in the exhaust gas from the gas generator 1, thereby increasing the molar ratio (CO / H2) in the fuel gas stream.

A compressed gaseous oxidizing stream formed later in the process can be introduced via line 187, if desired, into the reaction zone 35 of the gas generator 1 as a temperature moderator. Eg. For example, this flow can be introduced via line 101, valve 102, lines 103 and 78, valve 79, lines 80 and 41, and the center passage 5 of the burner 4.

Substantially pure oxygen from line 77 may be mixed with the stream of oxidizing gas in line 78. Alternatively, a portion of the gaseous oxidizing stream may be introduced into the reaction zone in admixture with the hydrocarbon-containing feedstock.

The exhaust gas formed in the reaction zone 35 of the gas generator 1 is mixed, if desired, with CO 2 in the spherical chamber 12 to obtain a thermal shift reaction therein and also in the discharge pipe 15, whereupon the gas stream is cooled in the waste heat boiler 17. The cooled fuel gas stream is fed into a conventional gas purification zone 110. 111 and 112, valve 113, conduits 114 and 115, and 18 the flanged conduit 116. If desired, all or part of the partially cooled exhaust gas stream can be used as a working medium in one or more expansion turbines located in different locations of the system, e.g. before or after the gas purification zone 110 or the gas purification zone 65. For example. For example, the exhaust stream of raw fuel gas in line 111 can be passed through line 117, valve 118 and line 119 into the expansion turbine 120. The fuel gas leaving the turbine 120 is passed through line 121, valve 122, line 123 and 115 and the flange supply 116. Turbo compressors 124 and 125 are driven by expansion turbine 120 and can be used to compress other fluids in the system. Eg. For example, nitrogen may be introduced into compressor 124 via line 126 and leave the compressor via line 127. Air may be introduced into compressor 125 via line 128 and leave the compressor via line 129.

The raw exhaust gas fuel partially cooled in the waste heat boiler 17 from the fuel generator 1 is further cooled and purified in the gas purification zone 110 by being brought into direct contact and scrubbed with clean scrubbing fluid or a recycled and diluted slurry of particulate carbon and scrubbing fluid.

The clean scrubbing fluid can be introduced into the gas purification zone via conduit 134, valve 135 and conduits 136 and 137. The gas purification zone may e.g. be a vertical scrubbing column with a number of horizontal trays. In this case, as it passes up through the tower, the gas is brought into contact with a scrubbing fluid on each tray, e.g. water or liquid hydrocarbon that flows down the tower as a result of gravity. Particulate carbon is thereby removed from the fuel gas. The fuel gas becomes cleaner and cleaner as it passes up through the scrubbing column, while the concentration of particulate carbon in the scrubbing fluid in question becomes greater and greater as it passes down the column. The particulate carbon slurry and scrubbing fluid slurry is discharged from the bottom of the scrubbing column 110 and into a carbon separation zone 29 via line 138.

In the carbon separation zone 29, the slurry of particulate carbon and scrubbing fluid can be worked up in conventional manner as described above to form a stream of pure scrubbing fluid and a separate slurry stream of particulate carbon in a liquid carrier. Thus, a slurry coming from gas purification zone 110 via conduit 138 comprising approx. 2% by weight of particulate carbon in water with naphtha and introduced into a decanter (not shown) in the carbon separation zone 29. A dispersion of particulate 19 UA485 carbon and naphtha is formed and pure water is removed from the decanter and recycled as at least part of the scrubbing fluid to gas purification zone 110 via line 140, pump 139 and lines 141 and 137. Fresh liquid heavy hydrocarbon fuel oil from line 43 is introduced into a distillation column (not shown) in carbon separation zone 29 together with the dispersion of particulate carbon in naphtha from the decanter. Naphtha is removed from the top of the distillation column and recycled to extract more particulate carbon from the slurry of particulate carbon in water. By means of pump 28, a preheated slurry of particulate carbon in liquid heavy hydrocarbon fuel oil from the bottom of the distillation column can be pumped through lines 30 and 31, valve 32, lines 33 and 34, preheater 220, line 221, line 9 and annular passage 8 into the gas generator. 1 reaction zone 35 as previously described.

The stream of pure fuel gas exiting gas purification zone 110 is introduced into a conventional additional gas purification zone 65 via conduit 142. H2S and COS are removed from the fuel gas and leaving separation zone 65 via conduit 143. In the Claus plant 144, H2S is fired with air from conduit 145 to form solid sulfur removed via line 146 and water removed via line 147. Excess nitrogen and other non-polluting gaseous impurities can be vented via line 148.

The flow of pure fuel gas in line 149 is preheated in heat exchanger 150 and introduced into the gas turbine combustion chamber 152 via line 151. The temperature of the clean fuel gas can be increased in heat exchanger 150 by indirect heat exchange with a portion of the exhaust gas from the main turbine 153 before this exhaust gas is discharged into the exhaust gas. an energy-generating expansion turbine 159. For example. part of the exhaust gas is passed through line 155, valve 156, line 157, heat exchanger 150, line 158, turbine 159 and line 160 to the chimney.

At the same time, another portion of the exhaust gas from turbine 153 is passed through line 165, heat exchanger 166, lines 167, 168 and 169, where it is mixed with air supplied to the system via line 170, turbo compressor 171 and line 172. The air which forms a free oxygen containing gas, is compressed in compressor 171, driven by expansion turbine 153, to a pressure in the range of approx. 10 to approx. 180 ata. The mixture of air and clean exhaust flue gas in line 169, hereinafter referred to as gaseous oxidizing stream, is cooled in heat exchanger 173 and passed via line 174, turbo compressor 175, intermediate cooler 176, turbo compressor 177, line 178, heat exchanger 166, lines 179 and 20 144485 180 and into the combustion chamber 152. In heat exchanger 166, the gaseous oxidizing stream is preheated by indirect heat exchange with a portion of the exhaust flue gas from expansion turbine 153. Conveniently, a portion of the preheated gaseous oxidizing stream in line 179 may be introduced into the fuel gas generator 1 via line 185, valve 186 lines 187 and 101, which are part of the temperature moderator.

The pure fuel gas is combusted in combustion chamber 152 to form pure flue gas leaving the chamber via line 188. The flue gas is then passed as working medium through the main expansion turbine 153. Turbo compressors 92, 175, 177 and 171 as well as electric generator 189 are driven by the expansion turbines 153 and 159. units can be connected to the same shaft or connected e.g. with a fluid coupling, i.e. 190

As mentioned above, the pure hot exhaust flue gas exits the main expansion turbine 153 via line 154 and is suitably divided into two streams, viz. lines 155 and 165. The volume of gas in each stream can be determined by conventional heat and weight balances. If desired, a portion of the exhaust gas from turbine 153 can be removed before or after heat exchanger 166 and discharged into the atmosphere via an energy-generating expansion turbine 159. For example. For example, the exhaust gas can be passed through conduit 195, valve 196, conduit 197, turbine 159 and conduit 160. The pure exhaust flue gas in conduit 160 can be discharged into the atmosphere via a chimney without causing pollution, preferably via the energy-generating expansion turbine 159. part of the clean exhaust gas in line 160 is introduced into the gas generator in the first part of the system via line 101.

Alternatively, the relatively small amount of heat that can be recovered from the gas turbine cycle, e.g. from the exhaust gas stream in line 154, is used as an energy source for absorption cooling. This cooling can then be used for air separation and removal of CO2 by condensation or by absorption in a low temperature solvent. The aforementioned exhaust gas can also be used for preheating. of the gas generator feed streams, preheating scrubbing fluid to the gas purification zone, or steam generation.

The relevant low temperature heat may also be used for the regeneration of liquid absorbents for CO 2 such as MEA and K 2 CO 3 solutions.

The turbine-powered electric generator 189 can provide electrical energy for operating essential mechanical and electrical appliances and instruments in the method of the invention including the gas generation and the air separation systems. The rest of the electrical energy is carried away. This design has the essential practical advantage that the operation of the plant is independent of external sources of electrical energy. Alternatively, mechanical energy at coupling 190 may be carried away.

Example This example illustrates a preferred embodiment of the process according to the invention and relates in particular to the production of an improved fuel gas and the combustion of this fuel gas in a gas turbine included in the system. It should be noted that the method according to the invention is not limited to the particular embodiment of the example. In this embodiment, the process of the invention is continuous and flow rates for all 3 material streams are given on an hourly basis. 426,352 standard m of fuel gas is formed by partial oxidation of a hydrocarbon-containing fuel with air in a conventional vertical, non-catalytic, refractory lined free-flow fuel gas generator. A portion of the exhaust flue gas from the gas turbine located on the outlet side of the gas generator is introduced in admixture with air in the reaction zone to moderate the temperature therein. The fuel gas is generated in the generator at an autogenous temperature of approx. 1193 ° C and a pressure of approx. 27 ata. The average residence time in the gas generator is approx. Two seconds. The fuel gas leaving the generator has the following composition in mole%: CO = 15.51, H 2 = 10.17, CO 2 = 4.55, H 2 O = 5.12, N 2 = 63.71, CH 4 = 0.00, Ar = 0.80, H2 S = 0.15 and COS = 0.01. Ca. 2177 kg of unconverted particulate carbon is fed into the exhaust stream of fuel gas. The molecular weight of dry fuel gas after removal of H 2 O, solid particles, CO 2 and H2 S in an exhaust gas purification zone is 25.17 and the net combustion or lower combustion heat is 735 kcal / m.

The above fuel gas is formed by partial oxidation with continuous introduction of a hydrocarbon-containing fuel consisting of 47,538 kg of a slurry which can be pumped and which is later formed in the process in a fuel gas generator via an annular type burner. The slurry is preheated to a temperature of approx. 260 ° C and comprises 2179 kg of particulate carbon and 45,359 kg of crude oil-derived distillation with the following elemental analysis (wt%): C = 86, 1%, H2 = 11.0%, S = 2.0%, N 2 = 0.8% and ash 0.01%. This residual oil has an API density of 10.9, a combustion heat of 10,145 kcal / kg and a viscosity of 822 Saybolt seconds (Furol) at 50 ° C. Furthermore, a mixture of approx. 193,300 p./m. air and 141,200 p.s. flue gas at a temperature of 260 ° C in the reaction zone of the gas generator using the burner.

22 t44485

All the hot fuel gas exiting the gas generator is passed through a refractory lined spherical free flow chamber located on the outlet side of the fuel gas generator. Part of the entrained solids is deposited by the flow of fuel gas and removed via an aperture located at the bottom of the spherical chamber. Using a waste heat boiler and indirect heat exchange with water as a coolant, the flow of fuel gas is cooled to a temperature of approx. 427 ° C while steam at a temperature of approx. 427 ° C is formed in the waste heat boiler. If desired, a portion of the steam may be used to drive compressors in a conventional air separation plant to produce substantially pure oxygen and nitrogen. If desired, the oxygen thus formed may be introduced into the gas generator and the nitrogen may be introduced into a gas purification zone later in the process for use in separating gaseous impurities.

Practically all of the particulate carbon and other residual solids are removed from the fuel gas stream in a conventional gas-liquid scrubbing column. A slurry of particulate carbon and crude oil is formed and introduced into the gas generator as feed material as previously described. CO2, H2S, COS, and, if desired, H2O, are removed from the fuel gas stream in a gas purification zone and a stream of improved pure fuel gas of substantially the following composition (on a dry basis) in mole%: H2 = II, 37, CO = 17, 34, N 2 = 70.39 and Ar = 0.90. The flow of approx. 381,200 pcs of pure fuel gas are introduced into the combustion chamber in a gas turbine at a temperature of approx. 427 ° C and a pressure of approx. 20 ata. At the same time, approx. 11,481 kg of a gaseous oxidizing stream comprising a mixture of 57.79 vol.% Air and 42.21 vol.% Exhaust flue gas from an expansion turbine described below at practically the same temperature and pressure as the pure fuel gas, and if desired H 2 O, in the combustion chamber where the fuel gas is combusted. 1,262,300 st.m3 of pure flue gas at a temperature of approx. 1093 ° C and a pressure of approx. 15 ata and consisting of (mol%) N 2 = 79.17, CO 2 = 7.79, H 2 O = 4.99, Ar = 1015 and C> 2 = 6784 are formed. The clean flue gas is passed through an expansion turbine that develops approx. 338,900 HP. An electrical generator is coupled to the turbine shaft and driven therefrom and also at least one compressor for compressing the gaseous oxidizing stream and delivering at least a portion thereof to the combustion chamber of the gas turbine.

The exhaust flue gas emitted from the expansion turbine at a temperature of approx. 507 ° C and at a pressure of approx. 1.5 ata, 3 is advantageously divided into two streams. 732,500 ppm of the flue gas is passed through a heat exchanger 150 for indirect heat exchange with the pure fuel gas en route to the combustion chamber. After this heat exchange, the exhaust flue gas is passed through a turbine at a temperature of 316 ° C into the atmosphere without causing pollution. This turbine will develop approx. 15,600 HP.

The remainder of the exhaust flue gas flow from the main expansion turbine is passed through a heat exchanger 166 for indirect heat exchange with the gaseous oxidizing stream comprising 740,000 p.m 3 of air and 548,000 p.m of the exhaust flue gas. Prior to this heat exchange, the gaseous oxidizing stream is compressed by means of at least one compressor, preferably driven by the main expansion turbine, to a pressure slightly above the pressure of the fuel gas generator. As mentioned above, at least a portion of the gaseous oxidizing stream is preheated to a temperature of approx.

427 ° C in the gas turbine combustion chamber.

In one embodiment of the process according to the invention, in which a portion of the CO2 recovered in the gas purification zone is utilized to improve the composition of the fuel gas by increasing its 3 molecular weight and combustion heat, approx. 53,700 cc CC-rich gas containing more than 95 mole% CO2 from the gas purification zone by means of a turbocharger driven by the main gas turbine to a pressure slightly above the pressure in the fuel gas generator. At a temperature of approx. At 427 ° C, the compressed CC2 stream is introduced into a refractory lined free-flow container, such as the spherical container 12 of the drawing, and mixed therein with approx. 426,100 ppm of exhaust gas from the gas generator at a temperature of approx. 1193 ° C. At a temperature above 816 ° C, non-catalytic, adiabatic, thermal reverse water-gas conversion takes place between CC> 2 and H2 in the refractory liner 12 and tube 15 to increase the mole ratio (CO / H2) in brændstofgasgasstrømmen. An improved fuel gas of the following composition is produced in mole%: CO = 16.61, 2 = 6.23, CC> 2 = 13.25, H 2 O = 7.05, N 2 = 56.00, CH 4 = 0.00 , Ar = 0.72, H2 S = 0.13 and COS = 0.01.

The molecular weight of the thermally converted dry fuel gas after removal of CO2 is increased to 26.09, and the net combustion heat or lower combustion heat per mole increases to 786 3 kcal / m. When this fuel gas is combusted in the combustion chamber, the expansion is increased compared to the expansion obtained when the fuel gas formed in the aforementioned embodiment is combusted. For efficient combustion, the process according to the invention requires further less than 1/10 - h of the amount of excess air which

Claims (9)

24 1U485 is required by an open cycle process in which all exhaust flue gas from the expansion turbine is discharged directly into the atmosphere. The particular compositions of hydrocarbon feed materials and scrubbing fluids disclosed in the general and exemplified description of the process according to the invention serve only to clarify and illustrate the invention. A process for generating energy by means of a gas turbine with a combustion chamber and an expansion turbine, characterized in that (1) react a hydrocarbon fuel with a free oxygen-containing gas by partial oxidation in the presence of a temperature moderator in the reaction zone of a non-catalytic free-flow gas generator at an autogenous temperature in the range of approx. 816 to approx. 1927 ° C ° 9 at a pressure in the range of approx. 10 to approx. 180 ata to form a waste gas stream comprising a mixture of H 2 CO, CO 2 and H 2 O as well as one or more constituents in the form of CH4, COS, S and Ar as well as particulate carbon, the molar ratio (CO / H2) of the exhaust gas from the generator is at least 0.30 on a dry basis, (2) the exhaust gas is cooled from (1) and introduces the cooled gas into a gas purification zone and therefrom separately the following streams are obtained: (A) a pure fuel gas stream comprising a mixture of and CO, which also contains one or more constituents in the form of N₂, CH₂, CO₂ and H₂O; (B) a CO 2 ~ rich gas flow? (C) a slurry stream comprising particulate carbon in a liquid carrier; and (D) a gas stream rich in I3 and COS, (3) introduces and combines the pure fuel gas stream from (2) into a gas turbine combustion chamber with a gaseous oxidizing stream formed at a later stage in the process to form a stream of pure flue gas, and (4) uses the stream of pure flue gas from (3) as a working medium passed through an expansion turbine to generate energy during the development of clean exhaust flue gas, at least part of which is mixed with a free oxygen-containing gas for forming the gaseous oxidizing stream under (3). Process according to claim 1, characterized in that the temperature moderator consists of at least part of the CC1-rich stream from step (2), at least part of the exhaust gas from step (4), water or mixtures thereof. 144485 25 Process according to claim 1 or 2, characterized in that the gaseous oxidizing stream is preheated by indirect heat exchange with at least part of the exhaust flue gas leaving the expansion turbine in step (4) before introducing at least part of the gaseous oxidizing stream into the combustion chamber in step (3). Process according to any one of the preceding claims, characterized in that the pure fuel gas is preheated before combustion during step (3) by indirect heat exchange with a portion of the pure flue gas emanating from step (4) which is simultaneously cooled. Process according to claim 3 or 4, characterized in that the clean exhaust flue gas cooled after the heat exchange steps is discharged into the atmosphere via an energy-generating expansion turbine. Process according to claim 1, characterized in that the exhaust gas stream from step (1) after cooling at a pressure substantially corresponding to the gas generator pressure, except for usual conduction pressure drop, is passed through an expansion turbine located on the inlet side of the gas turbine combustion chamber. Process according to claim 1, characterized in that part of the CC1-rich gas stream from step (2) is mixed with the exhaust gas stream from step (1) and the mixture is subjected to a non-catalytic reverse thermal water-gas conversion to increasing the mole ratio (CO / H2) in the fuel gas stream to a value greater than 0.3. Process according to claim 7, characterized in that the CC1-rich gas stream from step (2) is compressed to a pressure which is above the pressure in the gas generator in step (1) by means of a compressor driven by the expansion turbine in step (4), keeping the temperature of the water-gas conversion at least 816 ° C, and increasing the CO / H2 molar ratio to a value (dry basis) in the range of above 0.3 to 6.0. Process according to claim 1 or 2, characterized in that the cooling of the exhaust gas from step (1) is effected by indirect heat exchange with water to produce steam, and that part of the steam is heated by indirect heat exchange with exhaust.