PROCESS

Abstract

A process for the manufacture of a useful product from carbonaceous feedstock of fluctuating compositional characteristics, the process comprising the steps of: continuously providing the carbonaceous feedstock of fluctuating compositional characteristics to a gasification zone; gasifying the carbonaceous feedstock in the gasification zone to obtain raw synthesis gas; sequentially removing ammoniacal, sulphurous and carbon dioxide impurities from the raw synthesis gas to form desulphurised gas and recovering carbon dioxide in substantially pure form; converting at least a portion of the desulphurised synthesis gas to a useful product. Despite having selected a more energy intensive sub-process i.e. physical absorption for removal of acid gas impurities, the overall power requirement of the facility is lower on account of lower steam requirements and thereby leading to a decrease in the carbon intensity score for the facility.

Claims

1. A process for the manufacture of a synthetic fuel comprising: a. gasifying a carbonaceous feedstock comprising waste materials and/or biomass to generate a raw synthesis gas comprising H.sub.2, CO, CO.sub.2, at least one other carbonaceous material comprising at least CH.sub.4 and tars, and contaminants comprising particulates, ammonia or HCI, and sulphurous gas; b. supplying at least a portion of the raw synthesis gas to a primary clean-up zone supplied with an aqueous stream at least partially to wash particulates and ammonia or HCI out of raw synthesis gas, the aqueous stream being selected to be a neutral or acidic aqueous stream when ammonia is a contaminant in the raw synthesis gas and being selected to comprise a basic aqueous stream when HCI is a contaminant in the raw synthesis gas, to provide an aqueous-washed raw synthesis gas comprising H.sub.2, CO, CO.sub.2 and contaminants comprising sulphurous gas; c. supplying at least a portion of the aqueous-washed raw synthesis gas to a secondary clean-up zone; d. contacting the aqueous-washed raw synthesis gas in the secondary clean-up zone with a physical solvent for sulphurous materials effective at least partially to absorb sulphurous materials from the aqueous-washed raw synthesis gas and recovering from the secondary clean-up zone an at least partially desulphurised, de-tarred aqueous-washed raw synthesis gas comprising H.sub.2, CO and CO.sub.2; e. supplying the at least partially desulphurised, de-tarred aqueous-washed raw synthesis gas to a tertiary clean-up zone; f. contacting the at least partially desulphurised, de-tarred aqueous-washed raw synthesis gas in the tertiary clean-up zone with a physical solvent for CO.sub.2 effective at least partially to absorb CO.sub.2 from the at least partially desulphurised, de-tarred aqueous-washed raw synthesis gas, and recovering from the tertiary clean-up zone a first stream comprising the physical solvent for CO.sub.2 and absorbed CO.sub.2, and a second stream comprising clean synthesis gas comprising H.sub.2, CO and optionally remaining contaminants; g. removing at least part of the absorbed CO.sub.2 from the first stream in a solvent regeneration stage to recover regenerated solvent and separately CO.sub.2 in a form sufficiently pure for sequestration or other use; h. supplying the clean synthesis gas of the second stream, optionally after passage through one or more guard beds and/or alternative clean-up stages at least partially to remove any remaining contaminants, to a further reaction train to generate a synthetic fuel.

2. A process according to claim 1 comprising partially oxidising the raw synthesis gas from step a) to provide a partially oxidised raw synthesis gas comprising H.sub.2, CO, CO.sub.2 and contaminants comprising particulates, ammonia or HCI, and sulphurous gas; and supplying at least a portion of the partially oxidised raw synthesis gas to the primary clean-up zone in step b).

3. A process according to claim 2 comprising supplying at least a first part of the raw synthesis gas from step b) to a shift reaction or adjustment zone and shifting the H.sub.2 to CO ratio of the raw synthesis gas to a selected ratio to provide a shifted raw synthesis gas comprising H.sub.2, CO, and CO.sub.2 and contaminants comprising sulphurous gas; and supplying the shifted raw synthesis gas on in the process to the secondary clean-up zone in step c).

4. A process according to claim 3 comprising recombining the shifted raw synthesis gas with a second part of the raw synthesis gas from step b) before supplying the combined stream on in the process to the secondary clean-up zone in step c).

5. A process according to claim 2 comprising supplying at least a first part of the raw synthesis gas from step d) to a shift reaction or adjustment zone and shifting the H.sub.2 to CO ratio of the raw synthesis gas to a selected ratio to provide a shifted raw synthesis gas comprising H.sub.2, CO and CO.sub.2; and supplying the shifted raw synthesis gas on in the process to the tertiary clean-up zone in step e).

6. A process according to claim 5 comprising recombining the shifted raw synthesis gas with a second part of the raw synthesis gas from step d) before supplying the combined stream on in the process to the tertiary clean-up zone in step e).

7. The process according to claim 1 wherein the carbonaceous feedstock comprises at least one of woody biomass, municipal solid waste and/or commercial and industrial waste or a combination of these and the moisture content of the feedstock is reduced to below 20% w/w prior to gasification by drying with at least a portion of steam gained from downstream processes.

8. The process according to claim 7 wherein the process further comprises using a biomass or waste boiler to produce high-pressure steam and power.

9. The process according to claim 1 wherein the removal of ammoniacal, sulphurous and/or carbon dioxide impurities is a low-steam physical absorption process.

10. The process according to claim 9 wherein the process further comprises using at least a portion of the steam gained from the low-steam physical absorption process for use in upstream and/or downstream processes.

11. The process according to claim 10 wherein the upstream process comprises drying the carbonaceous feedstock.

12. The process according to claim 1 wherein at least a part of the recovered pure carbon dioxide is sequestered or is used off site or on site is upstream and/or downstream processes.

13. The process according to claim 1 wherein the pure carbon dioxide is at least about 60%, at least about 70%, at least about 80%, at least about 85% pure.

14. The process according to claim 1 wherein at least part of the desulphurised gas undergoes a water gas shift reaction to produce shifted synthesis gas.

15. The process according to claim 14 wherein the shifted synthesis is recombined with non-shifted gas to produce a synthesis gas having a hydrogen to carbon monoxide ratio of 2.00 ± 0.4.

16. The process according to claim 1 wherein the synthetic fuel is produced by subjecting at least part of the desulphurised or shifted synthesis gas to Fischer-Tropsch reaction conditions in a Fischer-Tropsch synthesis unit.

17. The process according to claim 16 wherein the Fischer-Tropsch synthesis unit converts the desulphurised or shifted synthesis gas into liquid hydrocarbons.

18. The process according to claim 17 wherein the liquid hydrocarbons are upgraded into the synthetic fuel.

19. The process according to claim 18 wherein at least a part of the liquid hydrocarbons is upgraded by at least one of hydro-processing, product fractionation, hydrocracking and/or isomerisation to produce the synthetic fuel.

20. The process according to claim 1 wherein the synthetic fuel comprises synthetic paraffinic kerosene and/or diesel and/or naphtha.

21. The process according to claim 20 wherein the synthetic paraffinic kerosene and/or diesel and/or naphtha is used for transportation fuel.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

[0288] FIG. 1 depicts a schematic diagram of a process for undertaking FT synthesis from a biomass and/or waste feedstock. The schematic diagram depicts both the conventional teaching in the prior art (chemical absorption secondary gas clean-up route) and a process according to the present invention (physical absorption secondary gas clean-up route). Also illustrated are two aspects of the inventive process both with and without a partial oxidation zone.

[0289] Referring to FIG. 1, prior art processes conventionally involve an amine-based gas removal solvent system to remove CO.sub.2, a Merichem™ redox process to remove sulphur and a hydrolysis step to hydrolyse hydrogen cyanide and COS.

[0290] Comparing the amine-based clean-up route to the physical absorption route according to the present invention, there are fewer stages that are required, thus simplifying the overall process and providing a process with a reduced number of stages. The reduced number of stages stems from the ability of the physical absorption process to effectively remove HCN, COS and other mercaptans which would have needed an additional hydrolysis step per the conventional route.

[0291] Preferred embodiments of the invention will now be more specifically described with reference to the following non-limiting examples.

EXAMPLES

[0292] A woody biomass feedstock was selected.

Process

[0293] The selected feedstock is treated as follows:

[0294] The feedstock is initially processed by comminuting it to the required size and drying to a desired moisture content (in this case 10%) to obtain dried biomass feedstock.

[0295] The dried biomass feedstock is supplied continuously to a fluidised bed gasification unit operated at a temperature of <800° C., a pressure of 2.2 barg and supplied with superheated steam to effect the gasification and produce approximately 5-10 or 1-2 lbmols/hr of raw synthesis gas per short ton of feed per day (STPD).

[0296] In one route the raw synthesis gas exits the gasifier and is supplied to an oxygen-fired partial oxidation reactor maintained at a temperature of approximately 1,250° C. and supplied with all of the raw synthesis gas generated from the gasification step described above while adjusting the oxygen rate to achieve a target temperature. The partial oxidation reaction converts residual methane and other hydrocarbons into synthesis gas.

[0297] The resulting hot equilibrated synthesis gas is cooled (by generating superheated and saturated high-pressure steam) to a temperature below 200° C. and is then routed through a primary gas cleanup unit where it passes through a venturi scrubber to knock-out water and particulates (such as soot and ash), after which it is caustic-washed to remove ammonia, halides (eg HC1), nitrous oxides and any remaining particulates.

[0298] In an alternative route, the raw synthesis gas that exits the gasifier is supplied straight to primary gas clean-up, bypassing the oxygen-fired partial oxidation reactor.

[0299] The synthesis gas is then compressed and routed through a secondary gas cleanup and compression system in which acid gas (H.sub.2S and CO.sub.2) removal is effected by the Rectisol™ process using a methanol solvent which “sweetens” the synthesis gas. This approach is used in Examples 1 and 2 discussed below. Example A depicts the conventional prior art involving an amine-based CO.sub.2 removal step followed by a sulphur removal step using Merichem™ redox process and a hydrolysis step to hydrolyse hydrogen cyanide and COS.

[0300] Approximately 2.2 lbmol/hr/STPD of acid gas is sent to the battery limit for CO.sub.2 capture. The acid gas stream comprises small quantities of H.sub.2 (<0.5 mol%), CO (<0.5 mol%), H.sub.2O (<5%) and N2 (-10%). The quantity of CO.sub.2 removed is about 1.5 lbmol/hr/STPD.

[0301] A portion of synthesis gas is extracted and recycled as fuel for the gasifier.

[0302] A portion of the synthesis gas stream is passed through a Water Gas Shift (WGS) unit to adjust the hydrogen to carbon monoxide (H.sub.2:CO) ratio in the total feed stream as it recombines.

[0303] A portion of the water gas shifted-synthesis gas is sent to a hydrogen recovery unit to produce high purity hydrogen for use in downstream units. The high purity hydrogen is sent downstream and the tail gas is routed to fuel gas.

[0304] Throughout the secondary gas cleanup process various guard beds are positioned to remove materials such as mercury, arsenic and phosphorus.

[0305] The sweetened and shifted synthesis gas is passed through a final Fischer-Tropsch (FT) inlet guard bed before being sent to the FT Synthesis Unit.

[0306] Purified synthesis gas is sent to the FT microchannel reactors where, in the presence of a cobalt catalyst supported on a silica/titania support, it is converted into synthetic liquid hydrocarbons.

[0307] Purged/excess tailgas is sent to the POx and the fuel gas system.

[0308] The FT reaction water is sent to the wastewater treatment unit where it is fractionated into a distillate containing alcohols and a bottoms fraction containing organic acids.

[0309] The bottom stream is then upgraded biologically for reuse in the facility.

[0310] The synthetic FT liquids are hydrocracked, hydroisomerised and then hydrotreated. Subsequently the diesel fuel is obtained from the upgrading unit.

[0311] Wastewater recovered from different process units is sent to a Wastewater Treatment unit before disposal or possible reuse.

Results

[0312] Table 1 outlines both individual stages and outcomes that are present in the process for undertaking FT synthesis from the selected feedstock.

TABLE-US-00001 Example A Example 1 Example 2 Biomass dry (STPD) 1,000 1X 1X Amount of syngas produced from gasification (Ibmol/h/stpd) ~ 8 1X 1X O.sub.2 usage from gasification + POx (Ib/h/stpd) ~ 50 0.35X 1X Syngas compression power/duty (MW) ~ 10 0.80X 1X Amount of syngas to FT synthesis (lbmol/h/stpd) ~5 0.75X 1X BTX product, BPD (relative to FT C5+ in base case) 0 0.06X 0 FT C5+ product (BPD) ~ 1500 0.65X 1X Total C5+ product (BPD) ~ 1500 0.71X 1X Power import (MW) ~ 24 0.84X 0.95X Natural gas import (MMSCFD) ~ 6 0 0.85X C1 score of overall process (g(CO.sub.2- eq)/MJ) X 0.50X 0.85X CO.sub.2 removed (Ibmol/hr/STPD) 1.5 1.0 1.6

Key to Table 1

[0313] Example A Comparative example using a conventional chemical absorption process for gas clean-up. [0314] Example 1 Example according to the present invention using a physical absorption process for gas clean-up without the use of a POx reactor. [0315] Example 2 Example according to the present invention using a physical absorption process for gas clean-up and including the use of a POx reactor.

[0316] The values of Examples 1 and 2 in Table 1 are reported relative to comparative Example A. For example, the O.sub.2 usage of comparative Example A is ~ 50 lb/h/stpd. Example 1 is 0.35X the value of Example A, thus having an O.sub.2 usage of ~ 17.5 lb/h/stpd.

[0317] It will be seen in comparing Examples 1 and 2 according to the present invention to comparative Example A that power import and natural gas import in the process are significantly reduced (and thus improved C1) when the physical absorption process (Rectisol™) is used in accordance with the present invention in replacement of the conventional chemical absorption process (amine).

[0318] Additionally, the use of a physical absorption process in accordance with the present invention does not require an auxiliary boiler to generate low pressure steam, like in conventional methods such as used in comparative Example A. The Rectisol process of Examples 1 and 2 according to the invention utilizes saved steam from downstream processes and utilizes the steam for use in upstream processes, such as drying the biomass, therefore reducing the natural gas import. The Examples according to the present invention therefore provide a more environmentally friendly method compared to comparative Example A.

[0319] In the case of the absence of a POx zone, additional energy efficiency is gained from the lower O.sub.2 utilization (only needed in gasification stage) and results in a smaller ASU and ancillary equipment. Although some tars can be recovered as BTX and used as a blendstock for fuel, the net C5+ hydrocarbon production ex-FT unit is also lower since there is no POx to convert the tars and methane to syngas. This impacts the facility economics via the value of saleable products recovered. Although, the C1 reduction is the highest in this case, economics may dictate the viability of this option.

[0320] It can also be seen from the results that the C1 score is significantly reduced in Examples 1 and 2 when compared to comparative Example A. The reduction in C1 is a result of several factors, including, but not limited to, the reduction in natural gas import, O.sub.2 usage and power import. The reduction in C1 is advantageous and demonstrates that the processes according to the present invention are more environmentally friendly than conventional methods.

[0321] It should also be noted that the C1 score indicated in the table is without incorporating CO.sub.2 sequestration, which would be expected to be used in accordance with the present invention. The inclusion of CO.sub.2 sequestration would reduce the values in the table further.