PRODUCTION OF PIPELINE GAS FROM SULFUR CONTAINING RAW OR SYNTHESIS GAS

Abstract: Described is a process for producing methane-rich, pipeline-quality gas from raw gas produced by gasifying car­ bonaceous materials. Following any needed adjustment of its H₂/CO ratio, which can be by a preconditioning water gas shift reaction or its reverse, the raw gas is fed to a direct methana­ tion reaction (2H₂ + 2CO⇄ CH₄ + CO₂) which does not require substantial addition of steam. If needed, the intermediate product gas from the direct methanation reaction can be pas­ sed over a water gas shift catalyst to control its H₂/CO ratio so that after removal of acid gases its methane content can be raised further over a nickel catalyst. This enables production of a very high heating value pipeline gas with only one acid gas removal step in the entire process sequence. In the alter­ native, the intermediate product gas can be subjected to cryogenic methane separation, with the separated H₂ and CO fed back to the direct methanation and the separated methane used as SLNG. A preliminary direct methanation step can be carried out prior to any needed preconditioning step.

Description: PRODUCTION OF PIPELINE GAS FROM SULFUR CONTAINING RAW OR SYNTHESIS GAS FIELD OF INVENTION This invention relates to the conversion of coal and carbonaceous materials to natural gas substitutes, and particularly to processes in which raw gas or synthesis gas produced by primary gasification is converted into methane-rich, pipeline-quality gas. DESCRIPTION OF PRIOR ART A number of processes are known for the production of methane-rich gas by the gasification and subsequent methanation of coal or other carbonaceous materials. Some examples of gasificatia processes for coal are known as the dry bottom Lurgi, slagging Lurgi and HYGAS processes. The H2/CO ratio in the synthesis gas produced by these processes varies from about 0.4 to 2.2. The Lurgi process has been selected by a number of firms for construction of the first commercial gasification units in the United States because it has been operated for a long time on a commercial scale. It is based on the steam-oxygen gasification under pressure of sized coal particles in a mechanically stirred fuel bed. The effluent gases from the gasifier are quenched to remove tars and oils, and the resulting gases are then passed through a carbon monoxide shift converter where part of the carbon monoxide reacts with steam to produce hydrogen and carbon dioxide by the so-called water gas shift reaction. The next stage consists of the removal of acid gases and residual sulfur compounds followed by passage through iron oxide boxes. The slagging Lurgi process is similar to the commercial Lurgi process described above except that the gasifier is modified to accept caking coals and operates at a higher temperature. Coal is crushed, screened to remove fines and then fed to the gasifier through coal locks. The bottom half of the gasifier is different from the conventional Lurgi gasifier. According to a British Gas Corporation development, steam and oxygen are injected through tuyeres into the high tempereature reaction zone. Ash is removed in the form of liquid slag through a tap and dropped into a quench vessel where it is removed as a glasslike frit. Operating conditions of the gasifier are 400-600 psi and about 23000F. Shift conversion and purification steps similar to those of the conventional Lurgi process are employed in further processing. The HYGAS process of the Illinois Institute of Gas Technology in Chicago is based on the hydrogenation of a fluidized bed of specially prepared coal. The latter is introduced as a slurry into the top layer of three superposed fluidized beds. Hot hydrogen enters the bottom bed and fluidizes all three beds, evaporating at the same time the oil from the slurry that was injected into the top. The fluid bed gasifier is maintained at a pressure of 75-90 atm and this is conducive to the formation of methane during the gasification process. The ungasified portion of the coal is obtained in the form of a reasonably reactive char which is withdrawn from the bottom of the bed and transferred to a hydrogen generator. The latter is normally operated by injecting a steam/oxygen mixture into the fluidized char, but can in the absence of oxygen operate on steam alone, provided the bed is electrically heated. A third possible method of hydrogen production, based on the steam-iron reaction and a subsequent reduction of the iron by means of char, has also been proposed. This process also-involves the employment of a raw gas purifier. Usually one finds that in the above and similar gasification processes, apart from methane, two low calorific value gases are produced simultaneously. Oxygenation and steam reforming both produce carbon monoxide, the calorific value of which is about 300 Btu/cu ft, and hydrogen, which also has a heating value of around 300 Btu/cu ft. In order to convert these low calorific gases into methane, the carbon monoxide can be reacted with hydrogen. In the usual methanation process using nickel catalyst, a H2/CO ratio f about 3 is used. This means that either extra hydrogen must be introduced or that there will remain an excess of surplus carbon monoxide. Carbon dioxide can also react with hydrogen to produce methane, but since production of hydrogen usually involves the conversion of carbon monoxide to carbon dioxide by the shift reaction, this reaction is not usually advantageous. Carbon dioxide typically is removed by absorption in alkaline absorbents and this constitutes one of the major costs in obtaining high heating value gases. In all processes described above, if the aim is to produce synthetic natural gas, the carbon monoxide is hydrogenated. Methanation, as an industrial process, has been known for many years since it is an essential gas purification step in the synthesis of ammonia from hydrogen and nitrogen. Nickel has generally been the active component in the production of synthetic natural gas (SNG) from synthesis gas produced by primary gasification processes such as those described above. Although nickel is a very active catalyst it possesses a number of disadvantages. It is deactivated irreversibly by the presence of very small proportions of sulfur compounds in the feed gas. Another problem in the employment of nickel methanation catalysts is the loss in activity due to carbon deposition. Carbon formation is favored at the high methane concentrations required for production of methane, in part due to the reaction: EMI3.1 This reaction, if it occurs, again irreversibly poisons the nickel catalyst. Generally it is necessary to employ feed gas with high ratios of H2/CO, equal to at least about 3 (on a molar or volumetric basis), to avoid this possibility. Generally, operating conditions involve temperatures below 400 C and pressures up to 1000 psi. Under these conditions the predominent reaction for methane formation over nickel catalysts is: EMI3.2 The hydrogen for the high H2/CO ratio needed for reaction (2) can be supplied by the water shift reaction: EMI3.3 One way to avoid the necessity of using a separate water gas shift reaction step (reaction (3)) is to conduct the methanation in the presence of a large excess of steam (Roberts, F.F.S., Hibden, D., Brooks, C.T., Sudburg, J.D., Paper IGU/Bz-79, 14th World Gas Conference, Toronto, International Gas Union, Paris, 1979). If such large excess of steam is supplied, it is then possible to apparently promote direct formation of methane (by a combination of reactions (2) and (3) in the known prior art): EMI4.1 Reaction (4) does not involve water at all. To avoid water formation with nickel catalysts it is therefore necessary for a large concentration of steam to be maintained so that water formed by reaction (2) is consumed by reaction (3). This introduction of steam also serves to suppress carbon formation with these catalysts. There has also been considerable effort devoted to the attempt to reduce sulfur sensitivity of nickel catalysts and/or substitute other catalysts which would be less affected by sulfur. One proposal is discussed in U.S. Patent 3,g28,000 (Child, et al.). The proposal involves gasifying a high-sulfur carbonaceous fuel by partial oxidation to obtain a process gas stream which is cooled, cleaned and subjected to catalytic methanation. In the methanation step synthesis gases are to be reacted without any preliminary water gas shift, though water is to be employed in the primary partial oxidation step, thereby affording some increase in the H2/CO ratio. The methanation catalyst is a typical Co/Mo/Al hydrodesulfurization catalyst, available commercially. The feed to the methanation reactor (Example I of the Child et al. patent) is said to have a H2fCO ratio equal to 1.76, which is still substantially higher than would correspond to the H2/CO = 1/1 ratio for the direct methanation reaction, Equation (4). Operation at 98 atmospheres (1440 psi) is said to result in a product stream which is scrubbed to remove the gases CO2, H2S, COS and H20. This product is said to contain 3.8 vol. % of CO. It is next to be processed (Example II of the Child et al. patent) by addition of 11.4 vol. g of steam and passing over a fixed bed conventional water-gas shift catalyst consisting of a mixture of copper and zinc oxides. This is said to reduce the CO content to 1.88 vol. % with simultaneous production of hydrogen, so that the hydrogen content of the exit gases from the shift converter was 5.63 vol. %, corresponding to a H2/CO ratio of 3/1. After removal of H20 and C02 the process gas was to be introduced into a conventional adiabatic catalytic methanation zone using a nickel containing catalyst. C02 was said to be again removed from the product through this methanation reaction to obtain the final product SNG. Thus, the processing sequence proposed by Child et al. uses three acid gas removal steps. Acid gas removal is one of the most expensive operations, costing far more than the catalytic processing steps themselves. Also, the use of additional steam both in the original gasification and the subsequent water gas shift adds considerable cost to the process. Another attempt to produce pipeline quality gas economically by so-called combined shift and methanation had been proposed earlier, in U.S. Patent No. 3,904,386 (Grabowski, et al.). In this case the synthesis gas feed is said to be derived from a coal gasifier. The cooled synthesis gas is to be introduced into a combined shift and methanation system where the mixture comes in contact with a catalyst at a temperature between 5000F and 10500F and a pressure between 500 psig and 2000 psig. The catalyst employed is said to be based on molybdenum and alumina, although addition of cobalt and other promoters are mentioned, so that the catalyst employed seems to be similar to that specified in the Child et al. patent. Finally, as in the Child et al. patent, the sulfur-free gas is to be treated to produce a gas of SNG pipeline quality through conventional fixed bed methanation using a nickel catalyst. In the Grabowski et al. proposal, a much lower ratio of H2/CO in feed gas to the combined shift and methanation reaction is to be employed than in the Child et al. patent, namely H2/CO = 0.66 (from Table II of U.S. Patent No. 3,994,386). Thus, there is not enough hydrogen present in this case for direct methanation, as in reaction (4). In order to supply sufficient hydrogen, 0.5 vol. of steam must be fed to the combined shift-methanation reactor for each volume of dry gas. In order to avoid deactivating the catalyst by this large addition of steam, it is necessary to recycle a portion of dry product gas from the shift-methanation reactor back to the feed. This feature is believed to be an essential part of the process and, of course, adds substantially to the cost of that process. SUMMARY OF THE INVENTION The invention is in the field of conversion of carbonaceous materials or products thereof into natural gas substitutes, and is useful for a final product gas which is rich in methane and has a sufficiently low content of carbon monoxide and hydrogen sulfide to be useful as pipeline quality gas either directly or when blended with other gases. In an exemplary and nonlimiting example of a process embodying the invention, the synthesis gas for direct methanation contains hydrogen and carbon monoxide in the ratio of about 0.3-1.7, and preferably in the ratio of about 0.9-1.3, and also sulfur containing gas and up to about 30 vol. S carbon dioxide on water-free basis, and preferably but not necessarily some methane. Hydrogen and carbon monoxide in the synthesis gas react in the presence of a direct methanation catalyst to produce methane and carbon dioxide, to thereby convert the synthesis gas to a methane-rich intermediate product gas which contains residual amounts of hydrogen and carbon monoxide, as well as carbon dioxide and sulfur containing gas. This intermediate product gas is scrubbed to remove acid gases, such as carbon dioxide and hydrogen sulfide, and the scrubbed gas is polished by methanation over a catalyst such as nickel, in which the residual hydrogen and carbon monoxide react to produce methane and water and thereby convert the scrubbed gas into a finiA product gas which is methane-rich, in that it contains at least 5 vol. % methane, and is suitable for direct pipeline use or for blendizs into pipeline gas because its carbon monoxide content is no more thaa about 0.1 vol, % and its sulfur content is no more than about 5 ppm. If synthesis gas having the desired H2/CO ratio (about 0.9,1.3) ii not available, it can be produced by preconditioning raw gas from processes such as certain types of coal gasification. If the raw gas has too high a ratio of hydrogen to carbon monoxide, e.g. a ratio greater than about 1.3, it can be converted to synthesis gas having the preferred range of about 0.9rl.3 by a reverse water gas shift reaction in the presence of a sulfur-insensitive catalyst, in which hydrogen and carbon dioxide in the raw gas react to produce carbon monoxide and water until the hydrogen to carbon monoxide ratio drops to the preferred range and preferably to about one. Conversely, if the raw gas hydrogen to carbon monoxide ratio is less than the preferred range of about 0.91.3, it can be subjected to a water gas shift reaction over a sulfur-insensitive catalyst with the addition of steam, in which carbon monoxide and water react to produce hydrogen and carbon dioxide, to thereby raise the H2/CO ratio to the preferred range, and preferably to about one. If the intermediate product gas from the direct methanation reaction has residual hydrogen to carbon monoxide ratio of less than about 3, i.e., has insufficient hydrogen content for efficient polishing methanation over a catalyst such as Ni, its ratio can be raised prior to the acid gas scrubbing step by subjecting it to a postconditioning step involving a water gas shift reaction over a sulfur-insensitive catalyst, in which residual carbon monoxide reacts with steam to produce hydrogen and carbon dioxide until the H2/CO ratio increases to at least about 3. The scrubbed gas is polished by a final methanation reaction, e.g., reaction (2) over a Ni catalyst, to produce the methane-rich final product gas which can be used as a pipeline gas either directly or in a blend. In the alternative, the above steps following direct methanation can be replaced by cryogenic separation which involves feeding C02 and H2 separated from the intermediate product gas back to the direct methanation step and supplying separated methane in the form of, e.g., liquid (synthetic) natural gas. As another alternative, a preliminary direct methanation of the raw gas can be added, for partial methanation prior to any needed preconditioning step preceding the main direct methanation step. This invention makes use of the discovery that oxysulfide catalysts based on the transition elements W, Mo, and V have much higher activity for direct methanation reaction (4) than nickel catalysts while being relatively less active for the water gas shift reaction. Direct methanation is the predominant reaction over these catalysts even in the presence of substantial concentrations of water and carbon dioxide. A process sequence employing the reaction takes advantage of this discovery. If a gas contains approximately equal proportions of H2 and CO, the occurrence of the direct methanation reaction, Equation (4), is favored Actually a slight excess of H2 is preferable because the reaction shown by Equation (2) occurs to minor extent. For gases such as those produced by the HYGAS process after the usual quench it is possible and economical to pass the raw gas containing the acid gases H2S and CO2 directly through a reactor system containing catalysts such as those described in our Patents Nos. 4,151,191 and 4,320,030. The direct methanation reaction converts to methane up to 95; of the CO in the feed gas from the-HYGAS quench. It is then only necessary to adjust the H2/CO ratio of the intermediate product so that a final clean-up (polishing) operation can be conducted to reduce the CO content to the drastic pipeline gas specification of less than 0.1% vol. A convenient way to accomplish this is to drop the temperatures of the effluent from the methanation step and pass it over a sulfur-insensitive water gas shift catalyst. Several such catalysts are available including the formulation given in our Patent 4,151,191. No or little addition of water is necessary with active catalysts which can bring the reaction close to equilibrium at 3000C. The gas then should have a H2/CO ratio of greater than 3/1. Following this the C02 produced both in the vast step and the previous methanation is removed along with sulfur containing gases by scrubbing with an alkaline solvent. The effluent gas is methanated in a clean-up operation using a conventional nickel catalyst to produce a high Btu synthetic natural gas. This gas is produced by addition of very minor proportions of process steam and involves only one acid gas removal step. If the raw gas contains a higher ratio of H2/CO, such as for example that produced by the dry bottom Lurgi gasifier which has a H2/CO ratio equal to about 2, it can be preconditioned (prior to the direct methanation step) by C02 methanation. For preconditioning, the raw gas is passed oyer a sulfur-insensitive water gas shift catalyst at an elevated temperature (600 ) at which the water gas shift equilibrium constant is small. The H2/CO ratio is thus reduced to a lower value and the resulting synthesis gas (H2/CO Z O.9rl.3) can be processed as previously described. An alternative scheme is to immediately use the raw gas in the direct methanation reaction. The conversion of CO is high but excess hydrogen is produced. In the subsequent acid gas removal step, some C02 is left in the product gases. These gases are passed to a nickel catalyst step in which not only CO but also CO2 methanation (4H2 + CO2 " CH4 * 2H20) is conducted so as to use up the excess hydrogen. In both cases only one acid gas removal step is required. If the H2/CO ratio is low (e.g., below about 0.9), such as in the raw gas produced by the slagging Lurgi gasifier, which has a H2/CO equal to about 0.4, after the usual quench the gas is passed at a low temperature (about 3000C) over a water gas shift catalyst in order to raise the hydrogen/carbon monoxide ratios It is then subsequently processed as previously described. THE DRAWING The sole Figure is a flowchart of processes embodying aspects of the invention. DESCRIPTION OF PREFERRED EMBODIMENTS The term "raw gas" used in this specification refers to a mixture which includes carbon monoxide, hydrogen and preferably some methane gases. Examples of raw gases are the effluents of the primary gasification steps in processes such as the dry bottom Lurgi, slagging Lurgi, HYGAS, or other similar processes. The raw gas can contain from about 0.4 to 2.2 volumes of hydrogen for volume of carbon monoxide, and up to about 3 vol. % of H2S. It can calso contain C02 and/or water1 along with smaller quantities of nitrogen, aromatic hydrocarbons and phenols derived from the carbon source. The term "synthesis gas" is used herein to mean a raw gas in which the H2/CO ratio is, or has been adjusted to, a figure in the range of about 0.3-1.7, and preferably about 0.9-1.3. The term "intermediate product gas" refers herein to the product of the direct methanation step. Referring to the flow diagram, source 10 of raw gas can be a conventional gasifier process such as HYGAS, slagging Lurgi, dry bottom Lurgi, etc., which includes the conventional "quencher" step, at a quenching temperature dictated by the desired quality of the raw gas and H2 to CO ratio of the stream, and a contentional water and oil scrubbing EMI10.1 EMI10.2 operation to remove tar, outs, phenol" and otner coal by-products. Depending on the H2 to CO ratio of the raw gas, a preconditioning step can be used to adjust this ratio to around O.9,to 1.3 for more effectively employing direct methanation of CO ahd H2 to produce CH4 and CO2 without employing steam. If the H2 to CO ratio in the raw gas stream from step 10 is lower than about 0.9, as in the case of the slagging Lurgi coal gasification process, a gas water shift reaction (3) is used at step 12 to shift some of the CO in the raw gas to H2 to bring the ratio up to within about Q.9 1.3, and preferably to around 1.0. If the H2 to CO ratio is greater than about 1.3, as in the case of dry bottom Lurgi coal gasification process, at step 14 CO2 in the raw gas is reacted with hydrogen to form CO and water by the reverse of the water gas shift reaction (3) to bring the ratio down to within about 0-9rl-3 and preferably to about I. These reactions occur readily over commercially available water gas shift catalysts that are insensitive to sulfur compounds. A commercially available unit for either of these preconditioning steps 12 and 14 can be operated at a range of space velocities from 1,000 to 15,000 V/V/HR(STP) and compatable temperatures and pressures in a manner known in the art. The output of the preconditioning step (12 or 14) is "synthesis gas, as the term is used in this specification. Of course, if the raw gas has an H2/CO ratio in the range specified for synthesis gas, no preconditioning is needed, although some scrubbing to remove tars, oils, ammonia liquid and other coal by-products can still be carried out if desired. The synthesis gas enters at step 16 a reactor system that promotes a direct methanation reaction in which the bulk of the methanation occurs. The direct methanator reactor system can take various forms. It can use a series of plug flow reactors arranged and engineered in a configuration for effective heat removal, or a combination of fluidized and fixed bed reactors. The direct methanation process can be conducted at temperatures in the range of about 4500F to 12000F and at pressures in the range of 150 to 2,000 psig and at space velocities in the range of 1,000 to 25,000 V/V/HR (STP). Since the final product gas is typically delivered to the pipeline at 1,000 psig, it can be advantageous to operate the direct methanation reactor at step 16 at high pressures in order to deliver the final product gas at pipeline specification without additional compression. The specific operation of the reactor depends on the activity of the catalysts employed. The synthesis gas fed to the direct methanation system at step 16 can contain up to about 30 vol. % of C02 on a water free basis, depending on the basic gasification (and any preconditioning) system which supplies it. For conversion of the synthesis gas to methane, the gas entering the direct methanation reactor at step 16 does not need a H2 to CO ratio greater than about 1, which is the requirement for direct methanation. Higher ratios of H2/CO in the feed to step 16 typically result in an increase in the H2 to CO ratio in the product of that step. It has been found possible in accordance with this invention to operate with H2/CO ratios below 1 to 1, down to 0.8 to 1, and in some cases even as low as 0.3 to 1, without carbon formation. However, generally best results are obtained by supplying step 16 with synthesis gas having H2/CO ratios between about 0.9 and 1.3, depending on catalyst activity, temperature, and pressure of operation and space velocity. The catalyst employed in the direct methanation system at step 16 is preferably a sulfided catalyst, based on one or more elements of the group consisting of tungsten, molybdenum and vanadium and being supported and/or promoted by one or more selected from the group Al, Si, B, Ce, Ti, Zr. A particularly effective catalyst is described in our co-pending patent application S.N. 431,192, entitled High Activity Transition Metal Catalysts and Methods for Making Them, and filed on September 30, 1982. The intermediate product gases leaving the direct methanator contain some small amount of H2 and CO, the ratio depending on the ratio of the H2 and CO in the feed to step 16. A postconditioning reactor can be used, if needed, to adjust the H2 to CO ratio to a level suitable for a polishing methanation reaction at step 22. The reaction at step 22 can be, for example1 over a nickel catalyst, which is most effective at ratios of H2 to CO somewhat in excess of 3 to 1. The specific ratio depends on the desired heating value of the product gas. If the highest heating value is to be obtained, a ratio slightly greater than 3 is desired. If postconditioning is needed or desired, to bring up the H2/CO ratio, a postconditioning reactor is used at step 18 in which some of the CO in the intermediate product gas is shifted, by a conventional water gas shift reaction preferably over a sulfur-insensitive catalyst, to produce additional hydrogen, and preferably at low temperatures. If needed for this reaction, water can be added at this point. Such H20 addition is a function of the degree of conversion that is necessary and the activity of the catalyst employed. Whether a postconditioning reactor is employed or not, the gases next are passed to a solvent treater system used at step 20 to remove acid gases. Step 20 involves the use of conventional processes for sulfur compounds such as H2S and C02 removal. Such known processes can involve refrigeration and physical or chemical absorption with solvents such as methyl alcohol, n-methyl pyrolidone, monoethanol amine, diethanolamine, triethanol amine, or hot potassium carbonate. After absorption the solvent is regenerated by stripping the acid gases. In addition to selective solvent step for the removal of sulfur compounds such as H2S and CO2, it can be advantageous to pass the gases through zinc oxide boxes for final removal of H2S down to approximately 0.2 ppm (parts per million by volume) using known processes. Indeed, this can be desirable to avoid catalyst poisoning should a nickel catalyst be employed in the final polishing step 22. However, if sulfur tolerant catalysts are used in the final polishing step 22, such zinc oxide guard is not needed. Following conventional scrubbing of acid gases at step 20, the scrubbed intermediate product gas stream entering the final polishing step 22 typically contains from about 75 vol. % of methane up to about 96 vol. % of methane. It can contain up to about 5 vol. % of CO and up to 20 vol. % H2. The specific ratios and amounts depend on the H2/CO ratio of the raw gas and the degree of any pre- and postconditioning that may be required. The composition of the gas entering the polishing reactor at step 22 should be such as to ensure that a single pass adiabatic operation is feasible without excessive temperature rise. The C02 content will normally be less than 1 vol. %. Following the polishing conversion at step 22 (e.g., by Åa known methanation reaction over Ni catalyst) the final product gas is now of pipeline quality. It typically contains about 90 vol. % CH, less than 10 vol. % H2, small amounts of CO2 and other gases which can be introduced in the original raw or synthesis gas (such as N2), and small proportions of other hydrocarbons present in the synthesis gas and also produced during methanation. The sulfur content is typically less than about 0.1 ppm, and the CO content is typically less than about 0.1 vol. %. As an alternative to steps 18, 20 and 22, the intermediate product gas produced in the direct methanation step 16 can be subjected to cryogenic methane separation at step 24. The separated products of the cryogenic methane separation step 24 are carbon monoxide and hydrogen (which can be recirculated back into the direct methanation step 16), pipeline-quality final product gas in the form of liquid synthetic natural gas, and acid gases. The advantages of using cryogenic methane separation in the invented process include avoidance of the need for use of zinc oxide boxes for hydrogen sulfide reduction below 1 ppm, as can be required in connection with nickel methanation as in step 22, elimination of the need for methanation as in step 22 and the fact that the methane from step 24 can be used directly for LSNG and in any event it need not be heated again for polishing methanation. As another alternative, a preliminary direct methanation, similar to that in step 16, can be carried out at step 26, prior to the preconditioning step 14, to effect partial methanation of the raw gas from a process such as dry bottom Lurgi gasification. EXAMPLES The following Examples should assist for a better understanding of the invention, but it should be clear that the invention is not limited to these examples but encompasses all others which are within the scope of the appended claims. Example 1 This example demonstrates the application of the direct methanation chemistry to process a raw gas that is produced from a HYGAS-type gasifier. See Table 1. A simulated HYGAS raw gas similar to that reported in a Final Report for the Department of Energy &num;FE-1772-l1 prepared by Dravo Corp. for the Institute of Gas Technology gasifying a Bituminous Pittsburgh &num;8 coal was used in the laboratory to demonstrate the production of pipeline-quality final product gas. The quenched raw gas (1), which is a synthesis gas in this example because its H2/CO ratio is within about 0.9-1.3, enters the direct methanation process of step 16, where about 92; CO conversion and 57.6% CO selectivity to CH4 is achieved. The effluent (2) from the direct methanation step 16 enters at step 18 a conventional postconditioning shift reactor carrying out step 18, where about 43% of the CO is shifted with additional water to form H2. The acid gases from the product (4) of the postconditioning step 18 are then removed at step 20 in a conventional scrubbing operation to the desired specifications to produce feed (5) to be further methanated in a conventional reaction over a nickel catalyst at step. The product of step 22 after being dried is rich in CH41 has a high caloric value, and meets the specifications of pipeline-quality gas. Table 1 Direct Methanation of a HYGAS Synthesis Gas Stream No. (1) (2) (3) (4) (5) (6) Stream Name Quenched Direct Methanation Feed to Post Prod. from Post Feed to Pipeline* Component Raw Gas Product From Conditioning Conditioning Polish Gas (Product from To Step 16 Step 16 Step 18 (Feed to Step 20) Step 22 Step 22) H2 lb. moles/hr 12,616 1,434 1,434 1,725 1,725 614 CO 8,827 675 675 384 384 13 CO2 9,950 13,504 13,504 13,795 138 138 CH4 7,876 12,492 12,492 12,492 12,492 12,863 C2H6 276 276 276 276 276 276 H2O - 1,043 1,882 1,591 - -COS + H2S 477 477 477 477 - *Caloric Value, 987 BTU/SC.FT. (60 , 1 atm, HHV) Example 2 This example demonstrates the application of the direct methanation chemistry to process a raw gas that is produced from a slagging Lurgi gasifier. See Table 2. A simulated slagging Lurgi raw gas similar to one reported by CONOCO in their report to the Department of Energy, FE -25 40-10 (Vol. 1) was used to demonstrate the production of pipeline gas. Since the H2 to CO ratio is low, at about 0.4, some preconditioning of this gas (as in step 12) is desired to bring the H2 to CO ratio to about 1.0. This requires about 16 volume S water in the gas to the precondition reactor. Thus, the raw gas is quenched to a temperature to retain sufficient water in the gas as required for shifting the CO to produce. H2 in the preconditioning reactor. Having achieved the desired composition of the quenched gas (1), about 26% of the CO is converted to H2 by shifting with water in the preconditioning reactor at step 12. The resulting synthesis gas (2) then enters the direct methanation process at step 16, where about 9O; CO conversion and 50S CO selectivity to CH4 is achieved. The effluent (4) from the direct methanation section enters a postconditioning shift reactor at step 18, where about 63% of CO is shifted with additional water to form H2. The acid gases are then removed at step 20 from the product (6) of step 18 to the desired specification to enable the gas (7) to be further processed at step 22 in a conventional nickel polishing methanation reactor. The final product gas from step 22 after being dried is rich in CH4 and has a high caloric value and is of pipeline quality. Table 2 Direct Methanation of a Slagging Lurgi Synthesis Gas Stream No. 1 2 3 4 5 6 7 8 Stream Name Feed to Product from Feed to Product from Feed to Product from Feed to Pipeline * Component Pre-Condi- Direct Direct Metha- Post Con- Post Condition- Polishing Gas ditioning tioning Methanation Methanation ditioning ing Reactor Reactor Reactor Reactor Reactor CO lb. moles/hr 56411.7 41556.9 41556.9 4159.1 4159.1 1289.3 1289.3 25.8 CO2 6208.0 21062.7 21062.7 39761.5 39761.5 42831.3 213.2 213.2 H2 29764.5 39619.3 39619.3 2221.4 2221.4 5091.2 5091.2 1300.7 CH4 5870.6 5870.6 5870.6 24569.4 24569.4 24569.4 24569.4 25832.8 C2+ 482.0 482.0 482.0482.0 482.0 482.0 482.0 482.0 H2S+COS 1976.1 1976.1 1976.1 1976.1 1976.1 1976.1 684.4 684.4 N2 684.4 684.4 684.4 684.4 684.4 684.4 H2O 15406.5 552.0 552.0 552.0 7494.6 4624.9 * Caloric Value about 962 BTU/SCF (HHV, 60 F, 1 atm) Example 3 This example demonstrates the application of the direct methanation chemistry to process a raw gas that is produced from a dry bottom Lurgi gasifier option &num;1 (C02 Methanation). See Table 3. A simulated dry bottom Lurgi raw gas was used to demonstrate the production of pipeline gas. The raw gas composition was taken from the El Paso study conducted by Stearns-Roger Co. in which a New Mexico sub-bituminous coal was gasified in a dry bottom Lurgi gasifier. The raw synthesis gas is first quenched to remove the oils, tars and most of the water and produce quenched raw gas (1). The gas then enters, as feed (2), the direct methanation processing unit at step 16, where about 87% CO conversion and around 50% CO selectiveity to CH4 is achieved and gas (3) is produced. The acid gas removal system removes at step 20 from gas (3) substantially all of the sulfur compounds, but only about 90% of the CO2, to produce feed (4) to step 22. This feed (h) enters a conventional nickel type methanation reactor at step 22, where substantially all of the CO and the CO2 are methanated, consuming the majority of the excess H2. The final product gas from step 22 after being dried is rich in CH4 and has a high caloric value. Table 3 Direct Methanation of a Dry Bottom Lurgi Synthesis Gas Option #1 (CO2-Methanation) Stream # 1 2 3 4 5 Stream Name Quenched Feed to Product from Feed to 2nd Pipeline* Component Raw Gas Direct Metha- Direct Methanation Methanator Gas nation H2 1b. moles/hr 38860 38860 22523 22523 1972 CO 18675 18675 2338 2338 29 CH4 10814 10814 18983 18983 24698 CO2 25939 25939 34107 3416 34 C2+ 943 943 943 943 943 H2S+COS 375 375 375 H2O 568 568 568 * Caloric Value 989.7 BTU/SCF (60 F, 1 atm, HHV) Example 4 This example demonstrates the application of the direct methanat ion chemistry to process a raw gas that is produced from a dry bottom Lurgi gasifier option &num;2 (Feed Preconditioning). See Table 4. A simulated dry bottom Lurgi raw gas was used. The raw gas composition was taken from the El Paso study conducted by Stearns-Roger Co. in which a New Mexico sub-bituminous coal was gasified in a dry bottom Lurgi gasifier. The raw gas is first quenched to remove the oil and tars and most of the water and produce quenched raw gas (1) which becomes feed (2) to a preliminary direct methanation step 24 which operates similarly to step 16 to effect partial methanation of the raw gas. The product (3) from step 24 is feed (4) to preconditioning step 14, whose product (5) is feed (6) to direct methanation step 16, which effects a high degree of conversion. The product (7) of step 16 already has a high enough H2/CO ratio, so there is no need for post-conditioning at step 18. Instead, product (7) from the direct methanation step 16 is directly supplied to scrubbing step 20, to remove acid gases to a degree allowing effective conventional Ni polishing methanation, and the product of step 20 is feed (8) to polishing step 20, whose product (9) is methane-rich, pipeline-quality gas of high caloric value. Table 4 Direct Methanation of a Dry Bottom Lurgi Synthesis Gas Option #2 (Feed Pre-Conditioning) Stream # 1 2 3 4 5 6 7 8 9 Stream Name Quenched Feed to 1st Product from 1st Feed to Pre- Product from Feed to 2nd Product from Feed to Pipeline* Component Raw Gas Dir. Methanat. Dir. Methanation Condition. Conditioning Direct Metha- 2nd Direct Polish. Gas H2 1b. moles/hr 39047 39047 29872 29872 21005 26005 6235 6235 551 CO 18764 18764 12200 12200 16067 16067 1924 1924 29 CH4 10895 10895 14830 14830 14830 14830 23308 23308 25703 CO2 26063 26063 28693 28693 24826 24826 30491 309 309 C2+ 947 947 947 947 947 947 947 947 947 H2O 570 570 1875 1875 5742 5742 8556 H2S+COS 377 377 377 377 377 377 377 * Caloric Value 1013.6 BTU/SCU (HHV, 60 F, 1 atm)

Claims: What we claim is: 1. A process of converting synthesis gas containing (i) hydrogen and carbon monoxide in the ratio of about 0.9-1.3 and (ii) sulfur containing gas to methane-rich, pipeline-quality final product gas comprising: reacting synthesis gas hydrogen and carbon monoxide in the presence of a first catalyst and in the presence of said sulfur containing gas in a direct methanation reaction without substan tial addition of steam to produce intermediate product gas rich in methane and containing residual hydrogen and carbon monoxide as well as acid gases; scrubbing acid gases from the intermediate product gas; and reacting residual hydrogen and carbon monoxide in the scrubbed gas in the presence of a second catalyst to increase the methane content of the scrubbed gas and to reduce its carbon monoxide content to no more than about 0.1 vol. % and thereby convert it to methane-rich, pipeline-quality final product gas. 2. A process as in claim 1 including gasifying raw material to produce said synthesis gas. 3. A process as in claim 2 in which said gasifying step produces raw gas containing hydrogen and carbon monoxide in a ratio outside the range of about 0.9-1.3, and including preconditioning the raw gas by adjusting the hydrogen to carbon monoxide ratio therein to produce said synthesis gas. 4. A process as in claim 3 in which the raw gas contains hydrogen and carbon monoxide in a ratio greater than about 1.3, as well as carbon dioxide, and the preconditioning step comprises reacting the raw gas hydrogen and carbon dioxide in the presence of sulfur insensitive catalyst, in a reverse water gas shift reaction, to reduce the hydrogen content and increase the carbon monoxide content sufficiently to convert the raw gas to said synthesis gas. 5. A process as in claim 3 in which the raw gas contains hydrogen and carbon monoxide in a ratio of less than about 0.9, as well as water, and in which the preconditioning step comprises reacting the raw gas carbon monoxide and water in the presence of a sulfur insensitive catalyst, in a water gas shift reaction, to reduce the carbon monoxide content and increase the hydrogen content sufficiently to convert raw gas to said synthesis gas. 6. A process as in claim 3 including reacting raw gas hydrogen and carbon monoxide in the presence of a sulfur-insensitive catalyst in a preliminary direct methanation reaction without substantial addition of water to effect partial methanation of the raw gas and feeding the resulting gas to said preconditioning step. 7. A process as in claim 1 in which said intermediate product gas contains residual hydrogen and carbon monoxide in the ratio of less than about 3, as well as water, and including the postconditioning step of reacting the product gas water and carbon monoxide in the presence of a sulfur-insensitive catalyst, in a water gas shift reaction, to raise the hydrogen to carbon monoxide ratio therein to at least about 3 prior to feeding the product gas to the acid gas scrubbing step. 8. A process as in claim 2 in which said intermediate product gas contains residual hydrogen and carbon monoxide in the ratio of less than about 3, as well as water, and including the postconditioning step of reacting the prodict gas water and carbon monoxide in the presence of a sulfur-insensitivj catalyst, in a water gas shift reaction, to raise the hydrogen to carbon monoxide ratio therein to at least about 3 prior to feeding the product gas to the acid gas scrubbing step. 9. A process as in claim 3 in which said intermediate product gas contains residuaL hydrogen and carbon monoxide in the ratio of less than about 3, as well as water, and including the postconditioning step of reacting the product gas water and carbon monoxide in the presence of a sulfur-insensitive catalyst, in a water gas shift reaction, to raise the hydrogen to carbon monoxide ratio therein to at least about 3 prior to feeding the product gas to the acid gas scrubbing step. 10. A process of converting synthesis gas containing hydrogen and carbon monoxide into methane-rich pipeline-quality final product gas comprising: reacting synthesis gas hydrogen and carbon monoxide in the presence of a sulfur-insensitive catalyst and in the presence of said sulfur-containing gas in a direct methanation reaction without substantial addition of steam to produce intermediate product gas rich in methane and containing residual hydrogen and carbon monoxide as well as acid gases; and subjecting the intermediate product gas to cryogenic methane separation producing separated carbon monoxide and hydrogen fed back to the direct methanation step, separated acid gases and separated methane-rich, piepline-quality final product gas. 11. A process as in claim 10 in which said separated final product gas is substantially liquefied

Inventors: BAJARS, LAIMONIS, HAPPEL, JOHN, HNATOW, MIGUEL A.
Applicants: GAS RESEARCH INSTITUTE
Application year: 1984
Main classification: C07C1
IPC codes: C10K3, C10K1, C07C1