DK201600005A1 - Process for production of a hydrogen rich gas - Google Patents
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- DK201600005A1 DK201600005A1 DKPA201600005A DKPA201600005A DK201600005A1 DK 201600005 A1 DK201600005 A1 DK 201600005A1 DK PA201600005 A DKPA201600005 A DK PA201600005A DK PA201600005 A DKPA201600005 A DK PA201600005A DK 201600005 A1 DK201600005 A1 DK 201600005A1
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- sulfur
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- rich
- gas
- stream rich
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- 238000000034 method Methods 0.000 title claims abstract description 94
- 239000007789 gas Substances 0.000 title claims abstract description 93
- 239000001257 hydrogen Substances 0.000 title claims abstract description 24
- 229910052739 hydrogen Inorganic materials 0.000 title claims abstract description 24
- UFHFLCQGNIYNRP-UHFFFAOYSA-N Hydrogen Chemical compound [H][H] UFHFLCQGNIYNRP-UHFFFAOYSA-N 0.000 title claims abstract description 22
- 238000004519 manufacturing process Methods 0.000 title description 6
- NINIDFKCEFEMDL-UHFFFAOYSA-N Sulfur Chemical compound [S] NINIDFKCEFEMDL-UHFFFAOYSA-N 0.000 claims abstract description 94
- 229910052717 sulfur Inorganic materials 0.000 claims abstract description 90
- 239000011593 sulfur Substances 0.000 claims abstract description 90
- 230000015572 biosynthetic process Effects 0.000 claims abstract description 26
- 238000003786 synthesis reaction Methods 0.000 claims abstract description 26
- 239000002253 acid Substances 0.000 claims abstract description 18
- 239000000463 material Substances 0.000 claims abstract description 11
- RWSOTUBLDIXVET-UHFFFAOYSA-N Dihydrogen sulfide Chemical compound S RWSOTUBLDIXVET-UHFFFAOYSA-N 0.000 claims description 22
- 238000006243 chemical reaction Methods 0.000 claims description 14
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 14
- CURLTUGMZLYLDI-UHFFFAOYSA-N Carbon dioxide Chemical compound O=C=O CURLTUGMZLYLDI-UHFFFAOYSA-N 0.000 claims description 12
- OKKJLVBELUTLKV-UHFFFAOYSA-N Methanol Chemical compound OC OKKJLVBELUTLKV-UHFFFAOYSA-N 0.000 claims description 12
- 229910002092 carbon dioxide Inorganic materials 0.000 claims description 11
- 230000002745 absorbent Effects 0.000 claims description 10
- 239000002250 absorbent Substances 0.000 claims description 10
- 229910002091 carbon monoxide Inorganic materials 0.000 claims description 8
- 238000004891 communication Methods 0.000 claims description 8
- 239000012530 fluid Substances 0.000 claims description 8
- 239000002904 solvent Substances 0.000 claims description 7
- UGFAIRIUMAVXCW-UHFFFAOYSA-N Carbon monoxide Chemical compound [O+]#[C-] UGFAIRIUMAVXCW-UHFFFAOYSA-N 0.000 claims description 6
- UCKMPCXJQFINFW-UHFFFAOYSA-N Sulphide Chemical compound [S-2] UCKMPCXJQFINFW-UHFFFAOYSA-N 0.000 claims description 6
- 239000001569 carbon dioxide Substances 0.000 claims description 6
- 239000000126 substance Substances 0.000 claims description 6
- CPLXHLVBOLITMK-UHFFFAOYSA-N Magnesium oxide Chemical compound [Mg]=O CPLXHLVBOLITMK-UHFFFAOYSA-N 0.000 claims description 4
- ZOKXTWBITQBERF-UHFFFAOYSA-N Molybdenum Chemical compound [Mo] ZOKXTWBITQBERF-UHFFFAOYSA-N 0.000 claims description 4
- GWEVSGVZZGPLCZ-UHFFFAOYSA-N Titan oxide Chemical compound O=[Ti]=O GWEVSGVZZGPLCZ-UHFFFAOYSA-N 0.000 claims description 4
- PNEYBMLMFCGWSK-UHFFFAOYSA-N aluminium oxide Inorganic materials [O-2].[O-2].[O-2].[Al+3].[Al+3] PNEYBMLMFCGWSK-UHFFFAOYSA-N 0.000 claims description 4
- 150000001412 amines Chemical class 0.000 claims description 4
- 239000010941 cobalt Substances 0.000 claims description 4
- 229910017052 cobalt Inorganic materials 0.000 claims description 4
- GUTLYIVDDKVIGB-UHFFFAOYSA-N cobalt atom Chemical compound [Co] GUTLYIVDDKVIGB-UHFFFAOYSA-N 0.000 claims description 4
- 238000001816 cooling Methods 0.000 claims description 4
- 229910052750 molybdenum Inorganic materials 0.000 claims description 4
- 239000011733 molybdenum Substances 0.000 claims description 4
- 239000002202 Polyethylene glycol Substances 0.000 claims description 3
- 238000010521 absorption reaction Methods 0.000 claims description 3
- 150000005218 dimethyl ethers Chemical class 0.000 claims description 3
- 229920001223 polyethylene glycol Polymers 0.000 claims description 3
- WFKWXMTUELFFGS-UHFFFAOYSA-N tungsten Chemical compound [W] WFKWXMTUELFFGS-UHFFFAOYSA-N 0.000 claims description 3
- 229910052721 tungsten Inorganic materials 0.000 claims description 3
- 239000010937 tungsten Substances 0.000 claims description 3
- GIAFURWZWWWBQT-UHFFFAOYSA-N 2-(2-aminoethoxy)ethanol Chemical compound NCCOCCO GIAFURWZWWWBQT-UHFFFAOYSA-N 0.000 claims description 2
- HZAXFHJVJLSVMW-UHFFFAOYSA-N 2-Aminoethan-1-ol Chemical compound NCCO HZAXFHJVJLSVMW-UHFFFAOYSA-N 0.000 claims description 2
- -1 alumina Chemical class 0.000 claims description 2
- ZBCBWPMODOFKDW-UHFFFAOYSA-N diethanolamine Chemical compound OCCNCCO ZBCBWPMODOFKDW-UHFFFAOYSA-N 0.000 claims description 2
- LVTYICIALWPMFW-UHFFFAOYSA-N diisopropanolamine Chemical compound CC(O)CNCC(C)O LVTYICIALWPMFW-UHFFFAOYSA-N 0.000 claims description 2
- 229940043276 diisopropanolamine Drugs 0.000 claims description 2
- 238000011143 downstream manufacturing Methods 0.000 claims description 2
- 239000000395 magnesium oxide Substances 0.000 claims description 2
- 229910044991 metal oxide Inorganic materials 0.000 claims description 2
- 150000004706 metal oxides Chemical class 0.000 claims description 2
- VUZPPFZMUPKLLV-UHFFFAOYSA-N methane;hydrate Chemical compound C.O VUZPPFZMUPKLLV-UHFFFAOYSA-N 0.000 claims description 2
- CRVGTESFCCXCTH-UHFFFAOYSA-N methyl diethanolamine Chemical compound OCCN(C)CCO CRVGTESFCCXCTH-UHFFFAOYSA-N 0.000 claims description 2
- 229910052596 spinel Inorganic materials 0.000 claims description 2
- 239000011029 spinel Substances 0.000 claims description 2
- 230000000694 effects Effects 0.000 abstract description 5
- 230000002708 enhancing effect Effects 0.000 abstract description 2
- 229910000037 hydrogen sulfide Inorganic materials 0.000 description 18
- 239000011149 active material Substances 0.000 description 4
- WQOXQRCZOLPYPM-UHFFFAOYSA-N dimethyl disulfide Chemical compound CSSC WQOXQRCZOLPYPM-UHFFFAOYSA-N 0.000 description 4
- 239000002028 Biomass Substances 0.000 description 3
- QMMFVYPAHWMCMS-UHFFFAOYSA-N Dimethyl sulfide Chemical compound CSC QMMFVYPAHWMCMS-UHFFFAOYSA-N 0.000 description 3
- 235000009508 confectionery Nutrition 0.000 description 3
- 238000002309 gasification Methods 0.000 description 3
- 238000000926 separation method Methods 0.000 description 3
- XEEYBQQBJWHFJM-UHFFFAOYSA-N Iron Chemical compound [Fe] XEEYBQQBJWHFJM-UHFFFAOYSA-N 0.000 description 2
- RAHZWNYVWXNFOC-UHFFFAOYSA-N Sulphur dioxide Chemical compound O=S=O RAHZWNYVWXNFOC-UHFFFAOYSA-N 0.000 description 2
- QVGXLLKOCUKJST-UHFFFAOYSA-N atomic oxygen Chemical compound [O] QVGXLLKOCUKJST-UHFFFAOYSA-N 0.000 description 2
- 239000003054 catalyst Substances 0.000 description 2
- 238000001311 chemical methods and process Methods 0.000 description 2
- 238000005516 engineering process Methods 0.000 description 2
- 150000002431 hydrogen Chemical class 0.000 description 2
- 239000007788 liquid Substances 0.000 description 2
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 description 2
- 229910052760 oxygen Inorganic materials 0.000 description 2
- 239000001301 oxygen Substances 0.000 description 2
- 239000000376 reactant Substances 0.000 description 2
- 239000002699 waste material Substances 0.000 description 2
- OKTJSMMVPCPJKN-UHFFFAOYSA-N Carbon Chemical compound [C] OKTJSMMVPCPJKN-UHFFFAOYSA-N 0.000 description 1
- 239000004215 Carbon black (E152) Substances 0.000 description 1
- 229910052799 carbon Inorganic materials 0.000 description 1
- 239000003575 carbonaceous material Substances 0.000 description 1
- 239000003245 coal Substances 0.000 description 1
- 150000001875 compounds Chemical class 0.000 description 1
- 239000000470 constituent Substances 0.000 description 1
- 230000001419 dependent effect Effects 0.000 description 1
- 239000000446 fuel Substances 0.000 description 1
- 229930195733 hydrocarbon Natural products 0.000 description 1
- 150000002430 hydrocarbons Chemical class 0.000 description 1
- 239000012535 impurity Substances 0.000 description 1
- 229910052742 iron Inorganic materials 0.000 description 1
- 230000003647 oxidation Effects 0.000 description 1
- 238000007254 oxidation reaction Methods 0.000 description 1
- 238000010791 quenching Methods 0.000 description 1
- 230000000171 quenching effect Effects 0.000 description 1
- 239000002994 raw material Substances 0.000 description 1
- 238000011084 recovery Methods 0.000 description 1
- 238000004064 recycling Methods 0.000 description 1
- 150000003464 sulfur compounds Chemical class 0.000 description 1
- 150000003568 thioethers Chemical class 0.000 description 1
- 238000011144 upstream manufacturing Methods 0.000 description 1
Landscapes
- Gas Separation By Absorption (AREA)
Abstract
The present invention relates to a process plant and a process for producing a hydrogen rich gas, said process comprising the steps of (i) combining a synthesis gas stream and a recycle stream rich in sulfur providing a sulfur rich feed stream, (ii) directing said sulfur rich feed stream to contact a material catalytically active in the sour shift process, providing a reacted stream, and (iii) separating said reacted stream in a product stream rich in hydrogen and a stream rich in sulfur by an acid gas removal process, and (iv) directing at least a portion of said stream rich in sulfur as said recycle stream rich in sulfur, with the associated benefit of such a process providing a concentration of sulfur in the a sulfur rich feed stream, which is sufficient for maintaining or even enhancing the activity in a sour shift process, while optionally also providing a sulfur rich stream for subsequent processing at increased cost effectiveness.
Description
Title: Process for production of a hydrogen rich gas
The present invention relates to a method for production of a hydrogen enriched gas from a synthesis gas, and especially production of a hydrogen enriched gas under sour conditions.
In the production of hydrogen rich gas, steam is added as a reactant to a synthesis gas comprising CO, which reacts with H20 to form H2 and C02 according to the water gas shift reaction. The typical water gas shift processes have employed a catalytically active material comprising iron and/or cupper, which are extremely sensitive to the presence of sulfur, and thus have required complete sulfur removal upstream, but the so-called sour shift process also exist, in which the catalytically active material comprises one or more of cobalt, tungsten and molybdenum, which are not only tolerant to the presence of sulfur, but actually require a certain amount of sulfur in the feed for the catalytically active material to remain active.
The concentration level of hydrogen sulfide in synthesis gas from a gasifier may vary depending on the source of feedstock. Especially gasification of biomass and waste may result in synthesis gas with low sulfur levels, but certain fossil sources of carbonaceous raw materials may also have natural low sulfur levels, which may be insufficient for the operation of sour shift process. Since the alternative sweet shift process requires absolute absence of sulfur and often a high amount of steam addition it is desirable to be able to operate the water gas shift process in sour mode in such cases.
In many process plants involving the sour water gas shift reaction, sulfur is separated from the hydrogen rich product stream in a so-called acid gas removal unit. The stream rich in sulfur obtained from the acid gas removal (AGR) unit is often utilized in a Claus unit for production of elemental sulfur. However, the stream rich in sulfur often needs to be enriched in sulfur in order to be efficiently utilized in the Claus unit. The enrichment methods may involve the use of additional absorption columns connected to the AGR unit, which requires capital investment. Furthermore, the operation of such enrichment columns adds operational expenses.
Now according to the present invention it has been identified that in such processes, the existing sulfur rich stream from the AGR unit may be configured to be used as recycle stream in order to meet the sulfur level, required for operation of the sour shift process as well as the sulfur level required for efficient operation of a Claus unit.
Definitions:
In the following the term water gas shift process shall be used for a chemical process in employing the reaction C0+H20 <=> C02+H2
In the following the term sour shift shall be used for a water gas shift process taking place in the presence of sulfur compounds employing a catalytically active material which is active in sulfided form.
In the following the concentrations are given on volumetric basis. Where the concentration of sulfur is stated, this shall be the volumetric concentration based on the assumption that all sulfur is present as H2S.
In the following the term sulfur rich is used to cover a stream comprising all forms of sulfur, including sulfides, elemental sulfur and sulfur dioxide, unless a specific chemical form of sulfur is mentioned.
In the following the term synthesis gas or syngas shall be used for a gas in which the combined concentration of CO and H2 is at least 15%.
In the following, where concentrations are stated in % this shall be understood as volumetric (molar) %, unless explicitly stated otherwise.
In the following, where reference is made to an acid gas removal (AGR) unit this shall be understood a unit which receives a process gas comprising hydrogen sulfide and carbon dioxide, and which selectively separates process gas, hydrogen sulfide and carbon dioxide in separate outlets. The AGR unit typically operates by means of a selective absorbent, either based on solvent based technology, employing physical solubility selectivity of methanol, dimethyl ethers of polyethylene glycol and other solvents, or based on chemical solvent selectivity technology, employing selective chemical re activity of e.g. amines. The typical AGR units will also provide a selective separation of C02 and H2S from the process gas.
In the following the term a Claus process shall be understood as a process converting H2S to elementary sulfur. A Claus process may involve a variety of reaction steps, but in the present context the specific reaction route shall not be considered as long as an overall conversion from H2S to elementary sulfur takes place as a main reaction.
In the following the term a Claus unit shall be understood as the process equipment in which a Claus process takes place.
In the following, where reference is made to a bed or a reactor, this may be understood as equivalent, unless otherwise indicated in the text.
In the following, where reference is made to a process stage, such a stage may be implemented in one or more reactors or reactor beds.
The present invention relates in a broad form to a process for producing a hydrogen rich gas, said process comprising the steps of (i) combining a synthesis gas stream and a recycle stream rich in sulfur providing a sulfur rich feed stream, (ii) directing said sulfur rich feed stream to contact a material catalyti-cally active in the sour shift process, providing a reacted stream, and (iii) separating said reacted stream in a product stream rich in hydrogen and a stream rich in sulfur by an acid gas removal process, and (iv) directing at least a portion of said stream rich in sulfur as said recycle stream rich in sulfur, with the associated benefit of such a process providing a concentration of sulfur in the a sulfur rich feed stream, which is sufficient for maintaining or even enhancing the activity in a sour shift process, while optionally also providing a sulfur rich stream for subsequent processing at increased cost effectiveness.
In a further embodiment the process further comprises the steps (v) directing a further portion of said stream rich in sulfur as a Claus unit feed stream rich in sulfur, (vi) directing said Claus unit feed stream rich in sulfur to a Claus unit, (vii) withdrawing a product stream comprising elemental sulfur from said Claus unit, with the associated benefit of such a process providing a concentration of sulfur in the stream rich in sulfur which is desired for cost effectiveness and high sulfur recovery of a Claus unit, contrary to a process without recycle of a stream rich in sulfur.
In a further embodiment said material catalytically active in conversion of carbon monoxide and water to carbon dioxide and hydrogen comprises 1-5% cobalt, 5-15% molybdenum or tungsten and a support comprising one or more metal oxides, such as alumina, magnesia, titania or magnesium-alumina spinel, with the associated benefit of such a material being catalytically active in sour water gas shift process.
In a further embodiment said acid gas removal process involves absorption of sulfide in a selective solvent, with the associated benefit of such a process being effective in withdrawing sulfide from a stream of process gas.
In a further embodiment said selective absorbent is an absorbent characterized by solubility selectivity, such as a methanol, dimethyl ethers of polyethylene glycol and other solvents with the associated benefit of such solvents being able to remove other impurities from the hydrogen rich gas.
In a further embodiment said selective absorbent is an absorbent characterized by chemical selectivity, such as diethanolamine, monoethanolamine, methyldiethanola-mine, diisopropanolamine, diglycolamine or other amines, with the associated benefit of the chemical characteristics of the amine making it possible to define relative selectivity towards H2S and C02 respectively.
In a further embodiment 10%, 50% or 80% of said stream rich in sulfur is directed as the recycle stream rich in sulfur, with the associated benefit of such a process providing sulfur for maintaining the activity of a material catalytically active in the so-called sour shift process as well as reduced requirements for the sulfur enrichment in the AGR unit.
In a further embodiment said stream rich in sulfur comprises at least 15%, 30% or 45% sulfur, with the associated benefit of reducing the requirements for further concentration of the sulfur. A stream rich in sulfur comprising at least 45% sulfur will be suitable for a standard Claus process in which all sulfur rich gas is combusted directly. A stream rich in sulfur comprising at least 30% sulfur will be suitable for a split flow Claus process in which some sulfide is combusted and some is oxidized catalytically, oxygen blown Claus process or support fuel assisted Claus process,. A stream rich in sulfur comprising at least 15% sulfur will be suitable for a direct oxidation Claus process in which all hydrogen sulfide is oxidized catalytically.
In a further embodiment said synthesis gas comprises less than 0.05% sulfur or less than 0.1% sulfur, with the associated benefit of such a process being suited for a synthesis gas with less than 0.05% originating from a low sulfur source such as biomass, waste or low sulfur coal while employing a material catalytically active in the shift process under sour conditions and thus low steam to carbon ratios, since the recycling of sulfur contributes to a higher presence of sulfur in the synthesis gas, or alternatively being suited for a synthesis gas with less than 0.1% which may employ a material catalytically active in the shift process under sour conditions, but at low activity, compared to the enriched level of sulfur obtained with recycle of the sulfur. A further aspect of the invention relates to a process plant comprising a sour shift stage containing a material catalytically active in the sour shift process having an inlet and an outlet, an acid gas removal unit having a process gas inlet, a purified process gas outlet and a sour gas outlet, a recycle compressor having an inlet and an outlet, in which the inlet of said sour shift stage is in fluid communication with a source of synthesis gas and the outlet of said recycle compressor, the outlet of said sour shift reaction stage is in fluid communication with the process gas inlet of said acid gas removal unit, the sour gas outlet of said acid gas removal unit is in fluid communication with the inlet of said recycle processor and the purified process gas outlet of said acid gas removal unit is in fluid communication with a downstream process, with the associated benefit of such a process plant being suited for carrying out a process according to the present disclosure.
In a further embodiment said sour shift stage comprises one, two, three or four reactors in series, with the associated benefit of distributing the reaction in separate physical spaces.
In a further embodiment the process gas is cooled between at least two of said reactors successive shifting of the equilibrium in each reactor.
In many chemical processes hydrogen is a key reactant. Hydrogen may either be required as pure hydrogen, e.g. for hydroprocessing in refineries or in combination with carbon monoxide, e.g. for synthesis of methanol, synthetic natural gas and is part of a synthesis gas provided from gasification in the presence of water of a carbonaceous material or a hydrocarbon. Often the amount of carbon monoxide in the synthesis gas is higher than desired. However, the well-known water gas shift reaction is used to partially or fully “shift” the carbon monoxide in the gas to hydrogen, in the presence of an appropriate catalyst by reaction of the carbon monoxide with water. The present disclosure will typically find use in the processes known as sour shift, which typically employ catalysts comprising cobalt and molybdenum, and which have the benefit of operating at moderate temperatures, and without requiring full sulfur removal form the synthesis gas.
The composition of the synthesis gas is dependent on a number of aspects, including the gasifier design. Some examples of the composition are given in Higman, C. and van der Burgt, M. Gasification, Elsevier Inc., 2008. Typically the synthesis gas in oxygen fired gasifiers comprises 25-50% H2 and 15-75% CO and C02 in combination, but other constituents e.g. up to 10% CH4 may also be present. If the gasifier operates on atmospheric air, the composition will naturally be dominated by N2, such that other concentrations are reduced by an approximate factor 5. In addition synthesis gas may also be provided from other processes, such that the composition may vary from the above, but the combined concentration of CO and H2 will be above 15%.
Figure 1 shows a process plant according to the invention. A feed stream 2 is directed through feed line 4 and process gas line 6 to a guard bed 8, and outlet through outlet line 10 through sour shift feed line 14 to a first reactor 16 of a downstream sour shift section, which may receive a gas at 230°C to 300°C, and provide a heated product at a temperature often above 400°C. The partially shifted gas is directed to heat exchanger 20 and typically cooled to around 220°C to 290°C, and directed to a second sour shift reactor 24 in which it is further shifted and cooled 28, before a final sour shift 32 and cooling to around 220°C to 250°C in 36. The cold product undergoes gas/liquid separation 38 into water 40 and a hydrogen rich gas 42, which is split into a stream comprising hydrogen sulfide 44 and a hydrogen rich product line 46 which is directed to acid gas removal (AGR) 48, in which a sweet hydrogen rich gas 51 is separated from a stream rich in hydrogen sulfide 52 and a stream rich in carbon dioxide 50. The stream rich in hydrogen sulfide 52 is split in a stream rich in hydrogen sulfide for recycle 58 and a stream rich in hydrogen sulfide for Claus unit 56. The stream rich in hydrogen sulfide for recycle 58 will typically have a low pressure and is directed to a compressor 60 before being combined with feed line 4.
The process temperature may also be controlled by cooling prior to the first reactor 16 and by quenching with e.g. gas, steam or process condensate either in addition to or instead of one or more of the heat exchangers 20, 28 and 36 mentioned above .
Specific embodiments of the disclosure may deviate from the layout of Figure 1, which shall not be considered limiting for the present invention. E.g. the guard bed 8 may be omitted depending on the specific composition of the synthesis gas, and similarly the number and nature of the reactors 16, 24 and 32 may vary, especially in accordance with the requirements to the product gas. Embodiments also exist in which an amount of synthesis gas by-passes the sour-shift section to define the appropriate product composition.
Figure 2 shows a process plant according to the prior art. A feed stream 2 is directed through feed line 4 to a guard bed 8, and outlet through outlet line 10 through sour shift feed line 14 to a first reactor 16 of a downstream sour shift section, which may receive a gas at 240°C, and provide a heated product at a temperature often above 400°C. The partially shifted gas is directed to heat exchanger 20 and typically cooled to around 220°C, and directed to a second sour shift reactor 24 in which it is further shifted and cooled 28, before a final sour shift 32 and cooling to around 220°C in 36. The cold product undergoes gas/liquid separation 38 into water 40 and a hydrogen rich gas 42, which is directed to acid gas removal (AGR) 48, in which a sweet hydrogen rich gas 51 is separated from a stream rich in carbon dioxide 50 and a stream rich in hydrogen sulfide 56, which typically is directed as a feed for a Claus unit.
If the sulfur level is less than required for the sour shift process, sulfur may, at an extra cost and complexity, be added to the shift section (typically to the feed 2) as any sulfur containing compound, commonly dimethyl disulfide.
Example 1
In Table 1, a feed synthesis gas is characterized together with intermediate and product gases. The feed stream corresponds to a synthesis gas from a biomass based gasifier. The feed flow rate is assumed to be 100.000 Nm3/h. The feed of Example 1 (Stream 2) contains 0.01% H2S which is increased to 0.05% by combination with recycle stream 58. The recycle stream is driven by a compressor, but the cost will be low, since the volume of the recycle stream is less than 0.1% of the total feed stream.
Table 1:
Example 2
In Table 2 the same feed gas as in Example 1 is used, but in this example the sulfur level is according to the prior art increased from 0.01% to 0.05% by addition of dimethyl disulfide stored on-site. The dimethyl sulfide is assumed to be fully converted to hydrogen sulfide.
The process of Example 2 is carried out without recycle in accordance with the layout shown in Figure 2.
Table 2:
The examples demonstrate that by the use of a recycle stream comprising a high amount of sulfide, a low sulfur feed stream may be used in shift processes requiring sour conditions.
In addition, an increase in sulfide level due to recycle could also result in the a higher sulfur concentration in the process gas directed to the AGR unit, and thus a lower requirement to the concentration carried out in the AGR.
Claims (12)
1. A process for producing a hydrogen rich gas, said process comprising the steps of (i) combining a synthesis gas stream and a recycle stream rich in sulfur providing a sulfur rich feed stream, (ii) directing said sulfur rich feed stream to contact a material catalyti-cally active in the sour shift process, providing a reacted stream, and (iii) separating said reacted stream in a product stream rich in hydrogen and a stream rich in sulfur by an acid gas removal process, and (iv) directing at least a portion of said stream rich in sulfur as said recycle stream rich in sulfur
2. A process according to claim 1 further comprising the steps (v) directing a further portion of said stream rich in sulfur as a Claus unit feed stream rich in sulfur, (vi) directing said Claus unit feed stream rich in sulfur to a Claus unit, (vii) withdrawing a product stream comprising elemental sulfur from said Claus unit.
3. A process according to claim 1 or 2 in which said material catalytically active in conversion of carbon monoxide and water to carbon dioxide and hydrogen comprises 1-5% cobalt, 5-15% molybdenum or tungsten and a support comprising one or more metal oxides, such as alumina, magnesia, titania or magnesium-alumina spinel.
4. A process according to claim 1, 2 or 3 in which said acid gas removal process involves absorption of sulfide in a selective absorbent.
5. A process according to claim 4, in which said selective absorbent is an absorbent characterized by solubility selectivity, such as a methanol, dimethyl ethers of polyethylene glycol and other solvents.
6. A process according to claim 4, in which said selective absorbent is an absorbent characterized by chemical selectivity, such as diethanolamine, monoethan-olamine, methyldiethanolamine, diisopropanolamine, diglycolamine or other amines.
7. A process according to claim 1, 2, 3, 4, 5 or 6 in which 10%, 50% or 80% of said stream rich in sulfur is directed as the recycle stream rich in sulfur.
8. A process according to claim 1, 2, 3, 4, 5, 6 or 7 in which said stream rich in sulfur comprises at least 15%, 30% or 45% sulfur.
9. A process according to claim 1, 2, 3, 4, 5, 6, 7 or 8 in which said synthesis gas comprises less than 0.05% sulfur, or less than 0.1% sulfur.
10. A process plant comprising a sour shift stage containing a material catalytically active in the sour shift process having an inlet and an outlet, an acid gas removal unit having a process gas inlet, a purified process gas outlet and a sour gas outlet, a recycle compressor having an inlet and an outlet, in which the inlet of said sour shift stage is in fluid communication with a source of synthesis gas and the outlet of said recycle compressor, the outlet of said sour shift reaction stage is in fluid communication with the process gas inlet of said acid gas removal unit, the sour gas outlet of said acid gas removal unit is in fluid communication with the inlet of said recycle processor and the purified process gas outlet of said acid gas removal unit is in fluid communication with a downstream process.
11. A process plant according to claim 10 in which said sour shift stage comprises one, two, three or four reactors in series.
12. A process plant according to claim 11 which is configured for cooling the process gas between at least two of said reactors.
Priority Applications (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| DKPA201600005A DK201600005A1 (en) | 2016-01-06 | 2016-01-06 | Process for production of a hydrogen rich gas |
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| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| DKPA201600005A DK201600005A1 (en) | 2016-01-06 | 2016-01-06 | Process for production of a hydrogen rich gas |
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| DK201600005A1 true DK201600005A1 (en) | 2016-12-19 |
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| DKPA201600005A DK201600005A1 (en) | 2016-01-06 | 2016-01-06 | Process for production of a hydrogen rich gas |
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Citations (7)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US3463611A (en) * | 1967-05-01 | 1969-08-26 | Chevron Res | Sulfur recovery |
| US4124685A (en) * | 1976-06-08 | 1978-11-07 | Tarhan Mehmet O | Method for substantially complete removal of hydrogen sulfide from sulfur bearing industrial gases |
| US4254094A (en) * | 1979-03-19 | 1981-03-03 | Air Products And Chemicals, Inc. | Process for producing hydrogen from synthesis gas containing COS |
| EP0162251A1 (en) * | 1984-04-13 | 1985-11-27 | Air Products And Chemicals, Inc. | Process for the recovery and recycle of effluent gas from the regeneration of particulate matter with oxygen and carbon dioxide |
| US20100061927A1 (en) * | 2008-09-10 | 2010-03-11 | Knudsen Kim Groen | Hydrotreatment process |
| JP2011168628A (en) * | 2010-02-16 | 2011-09-01 | Hitachi Ltd | Gas purification method and gas purification device |
| US20140147362A1 (en) * | 2012-11-28 | 2014-05-29 | Hitachi, Ltd. | Shift Catalyst, Gas Purification Method and Equipment of Coal Gasifier Plant |
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2016
- 2016-01-06 DK DKPA201600005A patent/DK201600005A1/en not_active Application Discontinuation
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| US3463611A (en) * | 1967-05-01 | 1969-08-26 | Chevron Res | Sulfur recovery |
| US4124685A (en) * | 1976-06-08 | 1978-11-07 | Tarhan Mehmet O | Method for substantially complete removal of hydrogen sulfide from sulfur bearing industrial gases |
| US4254094A (en) * | 1979-03-19 | 1981-03-03 | Air Products And Chemicals, Inc. | Process for producing hydrogen from synthesis gas containing COS |
| EP0162251A1 (en) * | 1984-04-13 | 1985-11-27 | Air Products And Chemicals, Inc. | Process for the recovery and recycle of effluent gas from the regeneration of particulate matter with oxygen and carbon dioxide |
| US20100061927A1 (en) * | 2008-09-10 | 2010-03-11 | Knudsen Kim Groen | Hydrotreatment process |
| JP2011168628A (en) * | 2010-02-16 | 2011-09-01 | Hitachi Ltd | Gas purification method and gas purification device |
| US20140147362A1 (en) * | 2012-11-28 | 2014-05-29 | Hitachi, Ltd. | Shift Catalyst, Gas Purification Method and Equipment of Coal Gasifier Plant |
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Legal Events
| Date | Code | Title | Description |
|---|---|---|---|
| PHB | Application deemed withdrawn due to non-payment or other reasons |
Effective date: 20170515 |