Process for producing a synthesis gas

Abstract

Process for manufacturing a hydrogen-containing synthesis gas from a natural gas feedstock, comprising the conversion of said natural gas into a raw product gas and purification of said product gas, the process having a heat input provided by combustion of a fuel; said process comprises a step of conversion of a carbonaceous feedstock, and at least a portion of said fuel is a gaseous fuel obtained by said step of conversion of said carbonaceous feedstock, and the Wobbe Index of said fuel is increased by a step of carbon dioxide removal or methanation.

Claims

1. A process for manufacturing a hydrogen-containing synthesis gas from a natural gas feedstock including a stage of converting said natural gas feedstock into a raw product gas and purifying said raw product gas, said process includes providing heat input by combustion of a fuel, wherein said process includes producing a gaseous fuel and combusting said gaseous fuel to provide at least part of said heat input to the stage of converting, said process for producing said gaseous fuel comprising: a) gasifying a solid or liquid carbonaceous feedstock into a first gaseous product; and b) treating said first gaseous product to obtain said gaseous fuel which is not used as a process gas, said treating including at least one of: b1) removing carbon dioxide with a purity of at least 90% molar; or b2) methanation; wherein said gaseous fuel has an upper Wobbe Index of at least 14 MJ/Nm.sup.3.

2. The process of claim 1, wherein the purity is at least 95%.

3. The process of claim 1, wherein the purity is at least 98%.

4. The process of claim 1, wherein said step b1) of removing carbon dioxide includes removing a fraction of the carbon dioxide content of a processed gas, said fraction is not greater than 90%, thereby leaving a corresponding residual carbon dioxide in said gaseous fuel.

5. The process of claim 4, wherein the fraction is not greater than 75%.

6. The process of claim 1, wherein said step b1) is carried out by adsorption of carbon dioxide on a regenerable solid adsorbent.

7. The process of claim 6, wherein said adsorption includes regenerable pressure swing adsorption.

8. The process of claim 1, wherein said step b2) of methanation is carried out after said step b1) of removing carbon dioxide.

9. The process of claim 8, further comprising recovering heat from said step b2) of methanation by generation of steam.

10. The process of claim 1, wherein the upper Wobbe Index of said gaseous fuel is at least 19 MJ/Nm.sup.3.

11. The process of claim 1, wherein the upper Wobbe Index of said gaseous fuel is at least 24 MJ/Nm.sup.3.

12. The process of claim 1, wherein said step a) of gasifying is carried out in a fluidized bed.

13. The process of claim 12, wherein ash and/or fine particulate matter produced during said step a) of gasifying is subject to a further combustion in a separate boiler.

14. The process of claim 13, wherein said separate boiler includes a circulating fluid bed coal boiler.

15. The process of claim 14, wherein said separate boiler produces steam and said steam is used in said step a) and/or in said stage of converting said natural gas feedstock and/or in said purification of said raw product gas.

16. The process of claim 12, wherein said step a) of gasifying includes moderating a gasification temperature with a moderator, and wherein said moderator is other than water.

17. The process of claim 16, wherein said moderator includes nitrogen.

18. The process of claim 16, wherein said moderator includes nitrogen, and wherein the moderator is admitted to the gasification process either: i) by a dedicated feed of nitrogen, or ii) together with oxygen by a feed of air or oxygen-enriched air.

19. The process of claim 1, wherein the step b) of treating includes: i) a step of catalytic hydrolysis of the carbonyl sulfide (COS), thereby producing a gas with a reduced content of carbonyl sulfide and an increased content of hydrogen sulfide (H.sub.2S); ii) a step of H.sub.2S separation by via a wash with a liquid solution with affinity to capture H.sub.2S that produces a sour H.sub.2S-rich stream and a gas stream with reduced H.sub.2S content; and iii) feeding the gas stream with reduced H.sub.2S content to any of step b1 or step b2.

20. The process of claim 19, wherein said step of H.sub.2S separation by via a wash with a liquid solution with affinity to capture H.sub.2S includes an MDEA wash selective for H.sub.2S over CO.sub.2.

21. The process of claim 1, wherein said carbonaceous feedstock includes at least one of coal, lignite, coal-derived coke, petroleum coke, or heavy fuel oil; and wherein said step of conversion into gaseous fuel is a gasification process.

Description

BRIEF DESCRIPTION OF THE FIGURES

(1) FIG. 1 is an illustrative scheme of the process for the production of hydrogen-containing synthesis gas according to an embodiment of the invention.

(2) FIG. 2 is a scheme of the front-end section of an ammonia plant according to a first embodiment.

(3) FIG. 3 is a scheme of the front-end section of an ammonia plant according to a second embodiment.

(4) FIG. 4 is a scheme of an embodiment of the invention for ammonia-urea process.

DETAILED DESCRIPTION

(5) FIG. 1 illustrates a block scheme of a process for producing a hydrogen-containing synthesis gas according to an embodiment of the invention.

(6) The process is carried out in a plant comprising basically: a reforming section 300; a coal gasification section 400; a gas purification section 500.

(7) The reforming section 300 converts a natural gas feedstock 301 into a gas mixture 302, which is purified in the purification section 500 to obtain a product gas 303. Said product gas 303 for example is a makeup gas for the synthesis of ammonia.

(8) The purification section 500 preferably comprises a shift section, a CO.sub.2 removal section and optionally a methanation section.

(9) The coal gasification section 400 comprises a section 410 which includes a fluid-bed gasifier suitable to convert a solid feedstock, for example coal, into a raw gas, and equipment for the treatment of said raw gas, for example to remove solid matter and sulphur compounds. Further to said section 410, the coal gasification section 400 comprises a CO.sub.2 removal unit 430, a methanator 420, a coal-fired boiler 440.

(10) A coal feedstock 401, with an oxidant 402 such as air or oxygen and water or steam 403, is converted into a first gas product 404. After a passage through the methanator 420 and CO.sub.2 removal unit 430, a gaseous fuel 405 with a greater Wobbe Index is obtained.

(11) Ash and particulate matter 406 discharged from the gasifier of the section 410 are further combusted in the coal-fired boiler 440, to produce steam 407 for the gasification process and/or steam 408 for the reforming process.

(12) The coal boiler 440 may produce steam for the purification section 500 and it may also produce steam for other plant sections not shown in the figure, such as e.g. steam turbines or the ammonia synthesis section.

(13) The gaseous fuel 405 provides at least part of the total amount of fuel directed to the reforming section 300. Accordingly, the total amount of the feedstock 301 required for a given production rate of ammonia is reduced. Alternatively, a larger amount of the feedstock 301 is available for the process, namely for generation of the product gas 303, hence the production of ammonia may be increased.

(14) Optionally, a portion of the fuel to the reforming section 300 may be still taken from the natural gas feed 301. Said portion (also called fuel fraction) is represented with a dotted line 304 in FIG. 1.

(15) The section 400 may optionally comprise a shift reactor upstream the CO.sub.2 removal section 420 to convert carbon monoxide into carbon dioxide.

(16) FIG. 2 shows the front-end section of an ammonia plant, according to an exemplary embodiment of the invention.

(17) A front-end 100 of an ammonia plant comprises a first section 101 for the production of a reformed gas 8 from a natural gas feedstock 1, and a second section 102 for the gasification of a coal feedstock 21 and generation of a gaseous fuel 35a.

(18) Said first section 101 comprises a primary reformer 103. Said primary reformer 103 includes a radiant section 104 and a convective section 105.

(19) The section 101 also includes a pre-heater 106 and a desulfurizer 107 upstream said primary reformer 103.

(20) The natural gas 1 enters the pre-heater 106, where it is heated to a first temperature, e.g. around 350° C. The heated natural gas 3 is subsequently directed to said desulfurizer 107, resulting in a desulfurized natural gas 4.

(21) Said gas 4 is mixed with superheated steam 5 to obtain a process gas 6.

(22) Said process gas 6 is fed to the convective section 105 of the primary reformer 103 and it is further heated e.g. around 500° C. in a heat exchange coil 108.

(23) The heated process gas 7 is subsequently fed to the radiant section 104 of the primary reformer 103, containing an array of tubes filled with catalyst for conversion into a hydrogen-containing synthesis gas. The radiant section 104 is provided with a series of burners 201 generating the reforming heat for the aforementioned conversion.

(24) The convective section 105 of the primary reformer 103 substantially recovers heat from the flue gas generated by said burners, which leaves the reformer 103 at line 210. In particular, due to the high temperatures of said flue gas, the convective section 105 is mainly used to superheat the steam and to heat the process air feed to a secondary reformer (not shown in the figure). For these reasons, the convective section 105 comprises the aforementioned heat exchange coil 108, at least one steam superheater coil 109 and a heat exchange coil 110 for the process air.

(25) FIG. 2 also shows an auxiliary boiler 111 separated from the reforming section 103 and producing additional steam. It should be noted that this setup is purely illustrative and several variants are possible.

(26) A gaseous fuel 35 is generated in the second section 102 by gasification of the coal feedstock 21.

(27) More in detail, said second section 102 comprises a gasifier 112 and a series of purification equipment for removing undesirable impurities, e.g. a cyclone or gas filter 114 and hydrogen sulphide adsorber 117.

(28) The coal feedstock 21, an oxidant stream 22 and steam or water 23 are fed to said gasifier 112, where they react at a high temperature (typically around 1000° C. or higher) and deliver a gaseous product 25 containing hydrogen, carbon monoxide and impurities like sulphur, nitrogen and mineral matter.

(29) A continuous stream 24 of ash that may contain unconverted carbon is discharged from the bottom of said gasifier 112 to prevent the accumulation of solids in the gasifier 112 itself. Said stream 24 can be further combusted in a separate boiler such as the boiler 440 of FIG. 1, for example a coal-fired circulating fluid bed boiler.

(30) The gaseous product 25 free of most solid particles leaves the gasifier 112 from the top and is passed through a heat recovery unit 113. The resulting cooled synthesis gas 26 flows through said cyclone or gas filter 114, which removes fine particulate matter 27. The resulting clean synthesis gas 28 leaves the cyclone 114 and flows to an arrangement of heat exchangers 115, where it is cooled with an optional heat recovery to near ambient temperature and condensed unreacted steam 30 is removed in a separator 116.

(31) Subsequently, the cooled gas 31 leaving the separator 116 enters said absorber 117, in which it is scrubbed with a solvent 32 in order to remove hydrogen sulphide. The lean solvent 32 is typically an amine solution. Elemental sulphur may be recovered from this hydrogen sulphide by a suitable catalytic sulphur removal process (not shown in the figure). The loaded solvent is removed as stream 33 for external regeneration.

(32) Said removal of hydrogen sulphide in the absorber 117 may optionally be carried out by means of a biological process.

(33) The scrubbed gas 34 mainly containing CO and H.sub.2, leaving the top of the absorber 117, is optionally reheated in a heat exchanger 118 resulting in the gaseous fuel 35.

(34) Said fuel 35 is further treated to increase its Wobbe Index, for example in a PSA CO.sub.2 removal unit 119, resulting in the fuel gas 35a which has a greater Wobbe Index.

(35) Said fuel gas 35a fuels the burners 201 of the radiant section 104 and, if present, the burners 200 of the desulfurizer preheater 106, the burners 202, 203 of the convective section 105 and the burners 204 of the auxiliary steam generator 111.

(36) FIG. 2 illustrates an embodiment where the fuel gas 35a is split into portions from 10 to 14, each supplying one of the aforementioned burners. In particular: portion 10 fuels the burner 200 of the desulphurizer preheater 106; portion 11 fuels the burner 201 of the radiant section 104; portion 12 fuels the burner 202, provided to control the temperature of the stream 6 fed to the convective section 105; portion 13 fuels the burner 203, provided to control the temperature of the superheated steam generated in the coil 110 of the convective section 105; portion 14 fuels the burner 204 of the auxiliary steam generator 111.

(37) FIG. 3 shows another embodiment of the present invention where items similar to those of FIG. 2 are indicated by the same reference numbers.

(38) The gasifier 112 is additionally supplied with a stream 36 of sulphur sorbent, typically limestone, in order to remove most of the sulphur present in the coal feedstock 21.

(39) The spent sorbent is discharged from the bottom of the gasifier 112 together with ash and unconverted carbon in stream 24.

(40) After passing through a heat recovery unit 113, a cyclone 114, a synthesis gas 28 substantially free of sulphur and solid particles is obtained. Here, said gas 28 passes through the CO.sub.2 removal unit 119 to increase the Wobbe Index.

(41) Other embodiments comprise a methanator in addition to, or instead of, said CO.sub.2 removal unit 119.

(42) FIG. 4 discloses an embodiment of the invention for implementation in an ammonia-urea plant. Items similar to FIG. 1 have the same reference number.

(43) The syngas 303 is a make-up gas for synthesis of ammonia which is converted into ammonia 601 in an ammonia synthesis section 600. At least some or all of the ammonia 601 is used in a urea section 602 for the synthesis of urea 603 with a carbon dioxide feed 604.

(44) A first portion 605 of the total CO2 requirement 604 for conversion of the ammonia into urea comes from the CO2 removal unit 502, typically comprising an aMDEA or potassium carbonate washing unit, forming part of the purification section 500 of the reformed gas 302.

(45) A second portion 606 of carbon dioxide is obtained from the bulk carbon dioxide separation unit 420. Said second portion 606 is a more substantial part of the total CO.sub.2 requirement 604 when the reforming section 300 only comprises a primary steam reformer and most or all the ammonia is converted to urea.

(46) The effluent 404 of the section 410, already desulphurized and before entering the CO.sub.2 removal section 420, is directed to a shift reactor 450 to convert the carbon monoxide contained therein into carbon dioxide.

Example 1

(47) An integrated ammonia/urea plant based entirely on natural gas as feed and fuel produces 2200 tonnes/day of ammonia of which approximately 85% is converted into urea, of which the production is accordingly 3300 tonnes/day. Total energy requirement for the integrated plant, which is completely supplied in the form of natural gas, amounts to 5.2 Gcal LHV basis per tonne of urea product, amounting in total to 715 Gcal/h. Of this total natural gas import, 3.1 Gcal/tonne (426 Gcal/h) is required as process feed for the steam reforming process, with the balance of 2.1 Gcal/t (289 Gcal/h) used as fuel in the steam reformer and for the generation and superheating of high pressure steam. The fuel gas of the steam reformer is a mix of a natural gas stream used as fuel, and a synthesis loop purge gas stream which is a by-product of the natural gas conversion to ammonia. The fuel gas of the steam reformer has the following typical properties: Wobbe Index (WI)=40 MJ/m.sup.3.

(48) The whole natural gas consumption as fuel can be replaced with a fuel gas generated from coal in a gasification facility as described herein. It is assumed that due to miscellaneous losses the total LHV heating value required would be 10% higher (318 Gcal/h) after conversion from all natural gas firing to all coal-derived fuel gas. A fuel gas stream having a total LHV heating value of 318 Gcal/h can be produced by gasification of 75 tonnes/h of bituminous coal (dry ash-free basis) at 10 bar/1000° C. in a fluidized bed gasifier requiring around 45 tonnes/h of 95% purity oxygen. The gas from the gasifier is cooled for heat recovery in a waste heat boiler and boiler feed water heater; it is scrubbed with water to produce a water saturated gas stream at 180° C.; it undergoes a COS catalytic hydrolysis step to convert substantially all the COS with water to CO.sub.2 and H.sub.2S; it undergoes a step of H.sub.2S removal by chemical wash with a selective MDEA solution. The gas so produced has WI=10 MJ/m.sup.3 (i.e. only 25% of typical value) and a residual CO.sub.2 concentration of about 23% mol, dry basis.

(49) According to the present invention, before mixing with the loop purge and use as fuel, the gas is treated in a CO.sub.2 PSA for bulk removal of more than 50% of its CO.sub.2 content, achieving a WI>15 MJ/m.sup.3 (i.e. 38% of typical value); preferably, the PSA separates 75% of its CO.sub.2 content; the gas has then a WI=17 MJ/m.sup.3 (43% of the typical value) and a residual CO.sub.2 concentration of less than 10% mol. Hence, the gas produced by the invention has significantly better chances to be used as replacement of the typical reformer fuel. Moreover, it achieves a substantial reduction of the CO.sub.2 that would have otherwise been emitted to the atmosphere.

Example 2

(50) An even better result is achieved by combining methanation and bulk CO.sub.2 removal, according to another aspect of the invention. The effluent gas from the MDEA desulphurization of Example 1 undergoes a treatment that includes at least a methanation step. The effluent from this treatment has a CH.sub.4 concentration of 29% mol, dry basis, and a CO.sub.2 concentration of 49% mol, dry basis. After cooling to 40° C. and water condensate separation, the stream is treated in a CO.sub.2 PSA for bulk removal of 50% of its CO.sub.2 content, achieving a WI=19 MJ/m.sup.3 (i.e. 50% of typical value); preferably, the PSA separates 75% of its CO.sub.2 content; the gas has then a WI=25 MJ/m.sup.3 (63% of the typical value).

(51) According to another embodiment, the treatment of PSA for bulk CO.sub.2 removal could be positioned upstream of the methanation step. In this case, separation of 75% of the CO.sub.2 upstream the methanation yields a gas with WI=20 MJ/m.sup.3 (50% of the typical value) after cooling to 40° C. and water condensate separation.

Example 3

(52) The plant of example 1 requires a total heat input of 300 Gcal/h. In the conventional ammonia urea complex of example 1, half of the heat (i.e. 150 Gcal/h) is needed for the reformer and half (i.e. 150 Gcal/h) is required for steam generation. As known by those skilled in the art, a typical value of cold gas efficiency of a gasification process is 70%, i.e. the heat value of the gas produced by the gasification is 70% of the heat value of the coal feed.

(53) The efficiency of a typical gas fired heater (such as a steam reformer or a boiler) is 95%. The efficiency of a typical coal fired boiler is 85%.

(54) According to another embodiment of the invention, all the heat is provided by combustion of the gas from the gasifier. In this case, the total coal feed is:
coal feed=(total heat input)/(gasifier cold gas efficiency)×(gas fired heater efficiency)=(300)/(0.7×0.95)=450 Gcal/h.

(55) According to another, preferred embodiment of the invention, the gas produced in the gasifier is only used as reformer fuel, and all the steam consumed by the complex (i.e. by the ammonia, urea, utilities and the gasification plants) is produced in a coal boiler. The ash from the gasifier still containing 5% of the coal feed heat value is fed to the coal boiler. In this case, the coal feed required is calculated as:
coal feed=[(reformer heat input)/(gasifier cold gas efficiency)×(gas fired heater efficiency)+(steam heat input−heat value of ash)/(coal boiler efficiency)]=[150/(0.7×0.95)+(150−8)/0.85]=393 Gcal/h.

(56) The second embodiment is significantly more efficient than the first.