ENHANCED GASIFICATION SYSTEM AND METHOD
20240140793 ยท 2024-05-02
Assignee
Inventors
Cpc classification
C01B2203/0255
CHEMISTRY; METALLURGY
C01B2203/062
CHEMISTRY; METALLURGY
C01B3/34
CHEMISTRY; METALLURGY
C01B2203/0283
CHEMISTRY; METALLURGY
International classification
Abstract
Method and apparatus for converting waste solid sustainable carbon material to chemical products is described herein. The methods add hydrocarbon derived from fossil sources to gas derived from gasifying waste solid sustainable carbon material to enhance hydrogen availability, and in some cases carbon availability, for production of the chemical products. Biomass is used to provide energy to dry solid sustainable carbon material to form dry sustainable carbon material to gasify. Carbon dioxide made by the process is at least partially sequestered to yield a chemical manufacturing process with environmental burden substantially less than conventional processes. Use of the hydrocarbon boosts yield of final products.
Claims
1. A process for making chemical products from solid sustainable carbon materials, the process comprising: converting a first solid sustainable carbon to energy and an exhaust comprising CO.sub.2 in connection with drying a second solid sustainable carbon material to produce a dried solid sustainable carbon material; sequestering at least a portion of CO.sub.2 from the exhaust in a sequestration facility; gasifying the dried solid sustainable carbon material to produce a first stream comprising CO, H.sub.2, CO.sub.2, and a mixture of organic compounds; providing a second stream comprising hydrocarbon derived from a fossil source; converting the organic compounds in the first stream and the hydrocarbon in the second stream into CO, H.sub.2, and CO.sub.2, to form one or more gas streams comprising CO, H.sub.2, and CO.sub.2; converting at least a portion of CO in the one or more gas streams to CO.sub.2 to increase H.sub.2 in the one or more gas streams and to form one or more converted streams; separating CO.sub.2 from the one or more converted streams to form a conversion feed; sequestering at least a portion of the separated CO.sub.2 in the sequestration facility; and producing one or more chemical products from the conversion feed.
2. The process of claim 1, wherein converting the organic compounds in the first stream comprises partially oxidizing the organic compounds and converting the hydrocarbon in the second stream comprises partially oxidizing the hydrocarbon.
3. The process of claim 1, further comprising using a portion of the CO.sub.2 of the exhaust in gasifying the dried sustainable carbon material.
4. The process of claim 1, wherein the first stream has a first flow rate, the second stream has a second flow rate, and the second flow rate is at least about 20% of the first flow rate.
5. The process of claim 4, wherein the second flow rate is selected to provide a finished product with GHG LCA no more than zero.
6. The process of claim 1, wherein at least one of the one or more converted streams has a volumetric ratio of H.sub.2 to CO that is at least 2.0.
7. The process of claim 1, wherein the chemical products are free of fossil-derived carbon.
8. The process of claim 7, further comprising using a portion of the separated CO.sub.2, a portion of the CO.sub.2 of the exhaust, or both in gasifying the dried solid sustainable carbon material, converting the organic compounds in the first stream, converting the hydrocarbons in the second stream, or any combination thereof.
9. The process of claim 1, wherein the converting the organic compounds in the first stream forms a first gas stream of the one or more gas streams, converting the hydrocarbon in the second stream forms a second gas stream of the one or more gas streams, converting CO in the first gas stream to CO.sub.2 forms a first converted stream of the one or more converted streams, and converting CO in the second gas stream to CO.sub.2 forms a second converted stream of the one or more converted streams.
10. The process of claim 9, wherein separating CO.sub.2 from the first converted stream forms a first conversion feed, separating CO.sub.2 from the second converted stream forms a second conversion feed, and the first and second conversion feeds are combined.
11. An apparatus for making organic chemical products, the apparatus comprising: a solid sustainable carbon material processing unit configured to reduce moisture in a second solid sustainable carbon material and comprising an energy conversion unit and a drying unit, wherein, the energy conversion is configured to convert a first solid sustainable carbon material into energy and an exhaust containing CO.sub.2; and, the drying unit is configured to apply the energy produced by the energy conversion unit to form a dried solid sustainable carbon material from the second solid sustainable carbon material; a gasification stage comprising a gasifier coupled to the solid sustainable carbon material processing unit to receive the dried solid sustainable carbon material to form CO, H.sub.2, CO.sub.2, and organic molecules from the dried solid sustainable carbon material, and a converter to convert the organic molecules to CO, H.sub.2, and CO.sub.2; a source of fossil-derived hydrocarbon coupled to the converter; a CO converter to convert CO to H.sub.2 and CO.sub.2; a first CO.sub.2 removal unit to remove CO.sub.2 and form a conversion feed; a second CO.sub.2 removal unit to remove CO.sub.2 from the exhaust of the energy conversion unit; a conduit to route removed CO.sub.2 to a sequestration facility; and a conversion stage to produce a chemical product from the conversion feed.
12. The apparatus of claim 11, wherein the converter is a partial oxidation reactor.
13. The apparatus of claim 11, wherein the CO converter is a water-gas shift reactor.
14. The apparatus of claim 11, further comprising a purification unit to remove impurities from the conversion feed.
15. The apparatus of claim 11, further comprising a CO.sub.2 conduit coupled from the solid sustainable carbon material processing unit to the gasification stage.
16. The apparatus of claim 11, wherein the apparatus has a nominal throughput of the dry sustainable carbon material to the gasification stage of 1928 dry mt/day or less.
17. A process for making chemical products containing carbon from solid sustainable carbon materials, the process comprising: converting a first solid sustainable carbon to energy and an exhaust comprising CO.sub.2 in connection with drying a second solid sustainable carbon material to produce a dried solid sustainable carbon material; sequestering at least a portion of CO.sub.2 from the exhaust in a sequestration facility; gasifying the dried solid sustainable carbon material to produce a first stream comprising CO, H.sub.2, CO.sub.2, and a mixture of organic compounds; providing a second stream comprising hydrocarbon derived from a fossil source; converting the organic compounds in the first stream and the hydrocarbon in the second stream into CO, H.sub.2, and CO.sub.2, to form one or more gas streams comprising CO, H.sub.2, and CO.sub.2; converting at least a portion of CO in the one or more gas streams to CO.sub.2 to increase H.sub.2 in the one or more gas streams and to form one or more converted streams; separating CO.sub.2 from the one or more converted streams to form a conversion feed; controlling an amount of fossil-derived carbon in the conversion feed; sequestering at least a portion of the separated CO.sub.2 in the sequestration facility; and producing one or more chemical products from the conversion feed.
18. The process of claim 17, wherein less than 25% of the carbon in the chemical products is fossil-derived.
19. The process of claim 17, further comprising using a portion of the CO.sub.2 of the exhaust in gasifying the dried sustainable carbon material.
20. The process of claim 17, further comprising using a portion of the separated CO.sub.2, a portion of the CO.sub.2 of the exhaust, or both in gasifying the dried solid sustainable carbon material, converting the organic compounds in the first stream, converting the hydrocarbons in the second stream, or any combination thereof.
Description
BRIEF DESCRIPTION OF THE DRAWINGS
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DETAILED DESCRIPTION
[0035] It has been discovered that fossil-derived hydrocarbons from a suitable source, such as a natural gas source, a light hydrocarbon stream from an LPG plant, which may process natural gas or refinery gas into LPG and by-product light hydrocarbons, or another gaseous hydrocarbon stream can be integrated with a solid sustainable carbon material gasification process using CCS to boost syngas and/or H.sub.2 output, and thus boost production of chemical products derived from such solid sustainable carbon material, while still maintaining a low environmental burden when measured via the GHG LCA of the produced product. It is possible in the same facility to: (a) convert fossil-derived hydrocarbons into a syngas that can be incorporated into the solid sustainable carbon material gasification to chemicals process, where the incorporation of fossil-derived hydrocarbons into the process generally will contribute to increasing the GHG LCA of the resulting product; and also (b) capture and sequester some (or all) of the biogenic CO.sub.2 (CO.sub.2 resulting from gasification of solid sustainable carbon material) produced by the gasification process, which generally will contribute to decreasing the GHG LCA of the resulting product. Through innovative integration of these two activities in such a facility it is possible to achieve higher plant productivity with a desired GHG LCA, including an approximately zero GHG LCA (yielding what is sometimes referred to as a net zero product). Such integration takes advantage of: (a) the sharing of equipment between the combined processes of solid sustainable carbon material gasification, hydrocarbon conversion, and chemical product synthesis; and (b) sequestration of biogenic CO.sub.2 to remove GHGs from the surface environment, and thus to provide a negative GHG LCA contribution that can be used to offset positive GHG LCA contributions in other parts of the process. It is believed that, currently, ways to create net zero chemical products in a process that utilizes a significant amount of fossil-derived hydrocarbon are unknown. It has now been discovered that this challenge can be addressed by offsetting, in a single integrated process and facility, the positive GHG LCA contribution from the use of such fossil-derived hydrocarbon with the sequestration of the biogenic CO.sub.2 produced in biogenic material gasification.
[0036] The processes described herein take advantage of CO.sub.2 sequestration and natural gas supplementation to achieve attractive economic return for relatively small throughput of biomass. For example, biomass conversion facilities having nominal biomass throughput of 1000 short tons (st)/day (corresponding to 771 dry mt/day) to 3000 st/day (corresponding to 2313 dry mt/day) at the gasifier can be used to make fuels with attractive costs that can return economic benefits. Economically advantageous versions of the processes described herein can have nominal biomass gasifier throughput rates of up to 1000 st/day (corresponding to 771 dry mt/day), 1500 st/day (corresponding to 1157 dry mt/day), 2000 st/day (corresponding to 1542 dry mt/day), 2500 st/day (corresponding to 1928 dry mt/day), or 3000 st/day (corresponding to 2313 dry mt/day). The ability to incorporate large amounts of natural gas while maintaining GHGLCA below that of conventionally-produced fuels derived from fossil fuels drives positive economic outcomes for facilities having relatively low throughput of biomass.
[0037]
[0038] The solid sustainable carbon material conversion process 200A uses a gasification stage 204, refining stage 212 and conversion stage 226, similar to the corresponding stages 104, 112, and 126 in the process 100 of
[0039] To accommodate the extra flow volume of the hydrocarbon material 206, the converter 210 has expanded capacity relative to the tar converter 110, which would be used solely to convert the tars in the stream produced by gasifier 106. In an example embodiment, the converter 210 is a POX reactor. The process resulting from converting the stream produced by the gasifier 106 and the fossil-derived hydrocarbon material 206 in the converter 210 is a gasification stage effluent 211. Operation of the POX process of the converter 210, in the embodiment described above, can be controlled such that processing of the added hydrocarbon material 206 yields primarily CO and H.sub.2, with some CO.sub.2 and H.sub.2O produced as by-products.
[0040] The gasification stage effluent 211 is routed to a refining stage 212 that uses a CO converter 213, a CO.sub.2 removal unit 214, and an optional purification unit 217 that are similar to those of the process 100 of
[0041] Examples of the process 200A are presented below, compared with an example of the conventional process 100. In the Examples presented below: [0042] A. the solid sustainable carbon material is softwood (e.g. pine) forestry residues collected in the southeastern United States, which is assumed to be suitably sized and dried (to 15% by weight moisture) before feeding to the gasifier; [0043] B. the gasification stages 104 and 204 are provided with an input of 1000 short tons per day (st/d) of such softwood (e.g. pine) forestry residues and 135 metric tonnes per day (mt/d) of CO.sub.2; [0044] i. Note that such 1000 stpd solid sustainable carbon material feed represents a feed of 771 dry-mt/d, after converting from short tons (st) to metric tonnes (mt) and accounting for the 15% moisture; [0045] ii. Note that such 771 dry-mt/d feed represents an atomic carbon feed rate of 369 mt/d using a typical value of 50% by mass for the carbon content in softwood; [0046] C. the gasification stage 104 of the conventional process 100 is simulated using the following performance characteristics for the case of 1000 stpd input of such softwood (e.g. pine) forestry residues and 135 mt/d of CO.sub.2: [0047] i. CO.sub.2 leakage into the atmosphere=46 mt/d; [0048] ii. carbon (from the solid sustainable carbon material) converted to ash=31 mt/d; [0049] iii. tar converter 110 is a POX reactor; and [0050] iv. the gasification stage effluent 111 has a composition by volume that is 40% CO, 30% CO.sub.2, and 30% H.sub.2, yielding approximately 505 mt/d CO, 595 mt/d CO.sub.2, and 27 mt/d H.sub.2, and only trace amounts of other species; [0051] D. the gasification stage 204 of the process 200A is simulated using the following performance characteristics for the case that it is provided with an input of 1000 stpd of such softwood (e.g. pine) forestry residues and 135 mt/d of CO.sub.2 plus an additional fossil-derived natural gas feed into the converter 210: [0052] i. CO.sub.2 leakage into atmosphere=46 mt/d; [0053] ii. carbon (from the solid sustainable carbon material) converted to ash=31 mt/d; [0054] iii. the converter 210 is a POX reactor; [0055] iv. a first portion of the gasification stage effluent 211 derived from the solid sustainable carbon material input to the gasification stage 204 is equal in rate and composition to the effluent 111 of the gasification stage 104, which is to say that the first portion of the gasification stage effluent 211 derived from the solid sustainable carbon material input has a composition by volume that is 40% CO, 30% CO.sub.2, and 30% H.sub.2, yielding approximately 505 mt/d CO, 595 mt/d CO.sub.2, and 27 mt/d H.sub.2, and only trace amounts of other species; and [0056] v. a second portion of the gasification stage effluent 211 derived from the fossil-derived natural gas converted in the converter 210 has flow rate and composition computed assuming: [0057] 1. the second portion consists of CO, CO.sub.2, and H.sub.2, and only trace amounts of other species; [0058] 2. 75% of the carbon in the fossil-derived natural gas is converted into CO, and the remaining 25% is converted into CO.sub.2; and [0059] 3. a volumetric ratio of H.sub.2:CO in the second portion is equal to 2; [0060] E. the CO converters 113 and 213 are both WGS units that convert 100% of input CO into H.sub.2 and CO.sub.2 via reaction with water; [0061] F. the CO.sub.2 removal units 114 and 214 are both AGR units that remove 100% of input CO.sub.2 but also leak 5% of that removed CO.sub.2 into the atmosphere; [0062] G. in cases where the conversion stage 126 or 226 produces methanol: [0063] i. each of the conversion feeds 124 and 224 contains 2.05 moles of H.sub.2 for each mole of CO, and 3.05 moles of H.sub.2 for each mole of CO.sub.2; [0064] ii. there is no nitrogen source 142 or 242; [0065] iii. each of the conversion units 126 and 226 converts 96% of the carbon in the respective conversion feeds 124 and 224 into methanol product, with the remaining 4% of the carbon converted into CO.sub.2 and emitted into the atmosphere; and [0066] iv. each of the purification units 117 and 217 includes sulfur removal via a catalytic, chemisorption, and/or physisorption process that does not otherwise change the mass flow rates, so that with respect to CO, CO.sub.2, and H.sub.2, refining stage effluent 120 is the same as precursor 132 and refining stage effluent 220 is the same as precursor 232; [0067] H. in cases where the conversion stage 126 or 226 produces FT hydrocarbons: [0068] i. each of the conversion feeds 124 and 224 contains 2.20 moles of H.sub.2 for each mole of CO, and 3.20 moles of H.sub.2 for each mole of CO.sub.2; [0069] ii. there is no nitrogen source 142 or 242; [0070] iii. each of the conversion units 126 and 226 converts 96% of the carbon in the respective conversion feeds 124 and 224 into FT hydrocarbon product, with the remaining 4% of the carbon converted into CO.sub.2 and emitted into the atmosphere; [0071] iv. each of the purification units 117 and 217 includes sulfur removal via a catalytic, chemisorption, and/or physisorption process that does not otherwise change the mass flow rates, so that with respect to CO, CO.sub.2, and H.sub.2, refining stage effluent 120 is the same as precursor 132 and refining stage effluent 220 is the same as precursor 232; and [0072] v. the fuel gas 229 consists of hydrocarbon and syngas; while it is not shown in the Examples, such fuel gas 229 may be routed to the gasification stage 204 as an additional energy source, for example, as an additional contribution to the hydrocarbon material 206 or as a separate stream. [0073] I. in cases where the conversion stage 126 or 226 produces ammonia: [0074] i. each of the conversion feeds 124 and 224 contains high purity H.sub.2; [0075] ii. the nitrogen source 142 or 242 contains approximately 3 moles of high purity N.sub.2 for each mole of high purity H.sub.2 supplied in the respective conversion feeds 124 and 224, and the N.sub.2 may be supplied, for example, by an ASU, which may further supply oxygen for the gasification stages 104 and 204 as oxygen source 108; [0076] iii. each of the conversion stages 126 and 226 converts 96% of the hydrogen in the respective conversion feeds 124 and 224 into an ammonia product, with the remaining 4% converted into H.sub.2O and emitted into the atmosphere; and [0077] iv. each of the purification units 117 and 217 includes a PSA that produces a high purity H.sub.2 stream, in which process 20% of H.sub.2 in the stream is removed as tail gas; while it is not shown in the Examples, such tail gas may be recycled for power/energy elsewhere in the facility; [0078] J. the monitoring unit 122 is either not present or does not change the mass flow rates in the input and output streams, such that refining stage effluent 120 is the same as conversion feed 124 and refining stage effluent 220 is the same as conversion feed 224; and [0079] K. for the purpose of calculating the GHG LCA contributions, the LCA is assumed to be a well-to-wake type that includes the upstream contributions for any feedstock or utility inputs to the production facility, the production process itself, and any downstream end-product transportation, distribution, and use, and reference values and calculation methodologies consistent with the 2022 version of the GREET model provided by the Argonne National Laboratory (accessible at https://greet.es.anl.gov/greet.models as of Dec. 23, 2022) are used, yielding the following GHG LCA contribution metrics in terms of equivalent CO.sub.2 emissions (CO.sub.2e): [0080] i. for collection/transport of the 1000 st/d of such softwood (e.g. pine) forestry residues=55.7 mt/d; [0081] ii. for electricity supply (assuming 95% renewable power and 5% grid power); [0082] a. methanol and FT hydrocarbon cases=24.1 mt/d, where all cases are simulated as nominally needing 40 MW of power; [0083] b. ammonia cases=42.2 mt/d, where all cases are simulated as nominally needing 80 MW of power; [0084] iii. for natural gas supply=0.61 mt/mt of NG supplied; [0085] iv. for downstream product transport and distribution; [0086] 1. for Methanol cases=0.022 mt/mt of product; [0087] 2. for FT hydrocarbon cases=0.012 mt/mt of product, based on available data for transportation of diesel fuel; [0088] 3. for ammonia cases=0.026 mt/mt of product; [0089] v. for downstream use, combustion is assumed, with 100% of the carbon contained in the product converted to CO.sub.2 and emitted into the atmosphere; and [0090] vi. for the corresponding baseline GHG LCA for a conventional fossil-derived product; [0091] 1. for methanol cases=1.72 mt/mt of product; [0092] 2. for FT hydrocarbon cases=3.58 mt/mt of product, based on available data for diesel fuel; [0093] 3. for ammonia cases=2.60 mt/mt of product.
[0094] The process 200A includes optional use of CO.sub.2 in the gasification stage 104 for the gasifier 106, the converter 210, or both. The CO.sub.2 recycle line from the CO.sub.2 removal unit to the gasification stage 106 can optionally be used, or an external source of CO.sub.2 260 can provide CO.sub.2 to the gasification stage 104 (gasifier 106 and/or converter 210) through an external CO.sub.2 conduit 218. Each source of CO.sub.2 can be used in any suitable ratio or mixture, or only one of the CO.sub.2 sources can be used, or none can be used, depending on the embodiment.
[0095]
[0096] It is noteworthy that the current marketplace places relatively high value on chemical product GHG LCA reductions, relative to a baseline for production and use for an equivalent product made from fossil-derived raw materials (fossil baseline), down to zero, but relatively low value on further reductions below zero, because reductions below zero must be credited as offsets against other unrelated emissions, increasing emissions tracking overhead and making it more difficult to perform audits and ensure regulatory compliance. As a result, the incremental economic benefits of GHG LCA reductions below zero are much less than those above zero. At the same time, there is a tradeoff between increasing productivity and lowering GHG LCA. For a given project the most economically optimal operating point balances these two factors, and utilizing the inventive embodiments described herein to produce chemical products that have net zero GHG LCA (or values that are modestly above or below zero) provides a means to optimize the GHG LCA reduction value while still achieving a much higher yield relative to a conventional process.
[0097] Methanol products with a negative GHG LCA may also be produced via an embodiment of the process 200A. Some embodiments produce methanol products with a GHG LCA that is between ?100% and 0% of the equivalent fossil baseline, by supplying a lower amount of natural gas than in CASE 3B at the cost of reduced plant productivity. Alternately, Methanol products with a slightly positive GHG LCA may be produced.
[0098] Some embodiments of the process 200A produce methanol products with a GHG LCA that is 20% of the fossil baseline, as in the embodiment labeled CASE 3C referring to an embodiment of the process 200A in which 350 mt/d of natural gas is supplied to the converter 210 via hydrocarbon material 206, and the total methanol output increases to 814 mt/d (about 2.56 times the output of the conventional process 100). In the process defined by CASE 3C, 23% of the gasification stage effluent 211 is routed to the CO converter 213 (to increase the proportion of H.sub.2 in the stream relative to CO), a proportion less than in CASE 3A by 20% and less than CASE 3B by 4%, and 100% of the stream 230 is routed to the CO.sub.2 removal unit 214. Methanol products can also be produced with GHG LCA between 0 and 20% of the fossil baseline by supplying a natural gas feed that is between the amount supplied in CASE 3B and CASE 3C, with resulting productivities that are between these two cases, respectively.
[0099] Some embodiments of the process 200A produce methanol products with a GHG LCA that is ?50% of the fossil baseline, as in the embodiment labeled CASE 3D referring to an embodiment of the process 200A in which 101 mt/d of natural gas is supplied to the converter 210 via hydrocarbon material 206, and the total methanol output is 461 mt/d (about 1.45 times the output of the conventional process 100). In the process defined by CASE 3D, 34% of the gasification stage effluent 211 is routed to the CO converter 213 (to increase the proportion of H.sub.2 in the stream relative to CO), and 100% of the stream 230 is routed to the CO.sub.2 removal unit 214. Methanol products can also be produced with GHG LCA between 0% and ?50% of the fossil baseline by supplying a natural gas feed that is between the amount supplied in CASE 3A and CASE 3D, with resulting productivities that are between these two cases, respectively. Additionally, methanol products can be produced with GHG LCA greater than 20% of the fossil baseline by supplying a natural gas feed that is greater than what is supplied in CASE 3C, resulting, for example, in GHG LCA up to 30%, 40% or 50% of the fossil baseline.
[0100] It is noteworthy that in the three embodiments of the process 200A of
[0101] A number of useful metrics may be computed with respect to various external inputs into the process compared to the product output. External inputs into the process herein refers to net material inputs into the process, and accordingly excludes materials that are used solely outside of the process as well as internal recycle streams. For example, if the gasifier 106 or tar converter 110 or 210 utilizes a stream of externally supplied natural gas to fire a combustor to externally heat a reactor chamber, such natural gas feed would not be an external input into the process (because such natural gas remains physically outside the process). Similarly, CO.sub.2 recycle 118 is not an external input into the process (because it is an internal recycle stream), whereas the externally supplied CO.sub.2 through CO.sub.2 conduit 218 discussed below is an external input into the process. It is useful to then introduce the following three metrics: [0102] A. the % of net atomic carbon input into the process from fossil sources, defined herein as the percentage of fossil-derived carbon atoms averaged over all of the external inputs into the process; [0103] B. the product atomic carbon yield per sustainable atomic carbon input into the process, defined herein as the mass flow of carbon atoms in the product output divided by the mass flow carbon atoms summed over the solid sustainable carbon material input into the process plus any other sustainable carbon external inputs into the process; and [0104] C. the product yield per dry solid sustainable carbon material input into the process, defined herein as the mass flow of product output divided by the dry mass flow of solid sustainable carbon material input into the process.
[0105] Embodiments of
[0106] Similarly, the embodiments of
[0107]
[0108] In contrast, in the embodiment labeled CASE 4B, referring to an embodiment of the process 200A, 268 mt/d of natural gas is supplied to the converter 210 via the hydrocarbon material 206, and the total FT hydrocarbon product output increases to 293 mt/d (about 2.19 times the output of the conventional process 100). In the process defined by CASE 4B, 29% of the gasification stage effluent 211 is routed to the CO converter 213 (to increase the proportion of H.sub.2 in the stream relative to CO), a proportion less than in CASE 4A by about 16%, and 100% of the stream 230 is routed to the CO.sub.2 removal unit 214. In CASE 4B, the GHG LCA of the FT hydrocarbon product is approximately zero. Just as with the embodiments of the process 200A shown in
[0109] FT hydrocarbon products with a slightly negative GHG LCA may also be produced via an embodiment of the process 200A. Some embodiments produce hydrocarbon products with a GHG LCA that is between ?100% and 0% of the fossil baseline, by supplying a lower amount of natural gas than in CASE 4B at the cost of reduced plant productivity. Alternately, FT hydrocarbon products with a slightly positive GHG LCA may be produced. Some embodiments of the process 200A produce hydrocarbon products with a GHG LCA that is 20% of the fossil baseline, as in the embodiment labeled CASE 4C referring to an embodiment of the process 200A. In CASE 4C, 376 mt/d of natural gas is supplied to the converter 210 via the hydrocarbon material 206, and the total hydrocarbon product output increases to 357 mt/d (about 2.67 times the output of the conventional process 100). In CASE 4C, 26% of the gasification stage effluent 211 is routed to the CO converter 213 (to increase the proportion of H.sub.2 in the stream relative to CO) a proportion less than in CASE 4A by about 19% and less than in CASE 4B by about 3%, and 100% of the stream 230 is routed to the CO.sub.2 removal unit 214. Hydrocarbon products can also be produced with between 0 and 20% of the fossil baseline GHG LCA by supplying a natural gas feed that is between the amount supplied in CASE 4B and CASE 4C, with resulting productivities that are between these two cases, respectively. Alternately, hydrocarbon products can be produced with GHG LCA greater than 20% of the fossil baseline by supplying a natural gas feed that is greater than that supplied in CASE 4C, resulting, for example, in GHG LCA up to 30%, 40% or 50% of the fossil baseline. Some embodiments of the process 200A produce hydrocarbon products with a GHG LCA that is ?50% of the fossil baseline, as in the embodiment labeled CASE 4D referring to an embodiment of the process 200A in which 117 mt/d of natural gas is supplied to the converter 210 via hydrocarbon material 206, and the total hydrocarbon output is 203 mt/d (about 1.52 times the output of the conventional process 100). In the process defined by CASE 3D, 36% of the gasification stage effluent 211 is routed to the CO converter 213 (to increase the proportion of H.sub.2 in the stream relative to CO), and 100% of the stream 230 is routed to the CO.sub.2 removal unit 214. Hydrocarbon products can also be produced with GHG LCA between 0% and ?50% of the fossil baseline by supplying a natural gas feed that is between the amount supplied in CASE 4A and CASE 4D, with resulting productivities that are between these two cases, respectively.
[0110] It is noteworthy that in the three embodiments of the process 200A simulated in
[0111] Embodiments of
[0112]
[0113] In contrast, in the embodiment labeled CASE 5B referring to an embodiment of the process 200A, 1400 mt/d of natural gas is supplied to the converter 210 via the hydrocarbon material 206, and the total ammonia output increases to 1988 mt/d (about 7.24 times the output of the conventional process 100). In the process defined by CASE 5B, 100% of the gasification stage effluent 211 is routed to the CO converter 213 to convert substantially all of the CO into CO.sub.2 to maximize the production of H.sub.2, and 100% of the stream 230 is routed to the CO.sub.2 removal unit 214, to remove substantially all of the CO.sub.2. As shown in
[0114] Ammonia products with a slightly negative GHG LCA may also be produced via an embodiment of the process 200A. Some embodiments produce ammonia products with a GHG LCA that is between ?100% and 0% of the fossil baseline by supplying a lower amount of natural gas than in CASE 5B at the cost of reduced plant productivity. Alternately, ammonia products with a slightly positive GHG LCA may be produced. Some embodiments of the process 200A produce ammonia products with a GHG LCA that is 10% of the fossil baseline, as in the embodiment labeled CASE 5C referring to an embodiment of the process 200A in which 2600 mt/d of natural gas is supplied to the converter 210 via the hydrocarbon material 206, and the total ammonia product output increases to 3457 mt/d (about 12.58 times the output of the conventional process 100). Ammonia products can also be produced with a GHG LCA that is between 0 and 10% of the fossil baseline by supplying an amount of natural gas to the converter 210 that is in between the amount supplied in CASE 5B and CASE 5C, with resulting productivities that are between these two cases respectively. Or ammonia products can be produced with GHG LCA greater than 10% of the fossil baseline by supplying an amount of natural gas to the converter 210 that is greater than what is supplied in CASE 5C. Some embodiments of the process 200A produce ammonia products with a GHG LCA that is ?50% of the fossil baseline, as in the embodiment labeled CASE 5D referring to an embodiment of the process 200A in which 315 mt/d of natural gas is supplied to the converter 210 via hydrocarbon material 206, and the total ammonia output is 660 mt/d (about 2.40 times the output of the conventional process 100). Ammonia products can also be produced with GHG LCA between 0% and ?50% of the fossil baseline by supplying a natural gas feed that is between the amount supplied in CASE 5A and CASE 5D, with resulting productivities that are between these two cases, respectively. One noteworthy simplification in the production of ammonia relative to methanol and FT hydrocarbons is that the end product does not contain carbon, avoiding any need (as encountered above in the context of methanol and FT hydrocarbons) to modify the process so the end product contains no fossil-derived carbon as a way to maximize product value in certain markets.
[0115] The inventive embodiments in
[0116] In general the processes 100 and 200A may be operated to produce hydrogen as an end product through appropriate plant configuration where no conversion stage 126 or 226 is included. For example, the ammonia unit can be omitted and the rest of the process 200A operated as shown in
[0121] Typically the GHG LCA for a hydrogen end product application is calculated well-to-gate instead of well-to-wake as here with methanol, hydrocarbons, and ammonia. The difference is that in the well-to-gate case, emission contributions from transportation, distribution, and use are not included. Since the downstream contributions from ammonia are small, it is readily observed that the net zero GHG LCA CASE 5B should produce approximately net zero hydrogen when adapted to produce hydrogen as an end product. And similarly one would expect that the 10% of fossil GHG LCA CASE 5C should produce modestly positive GHG LCA hydrogen and the ?50% fossil GHG LCA CASE 5D should produce moderately negative GHG LCA hydrogen
[0122] In the embodiments of
[0123]
[0124] In process 200B, the gasification stage 104 that uses sized and dried solid sustainable carbon material 102 contains a gasification unit 106 and tar converter 110, and produces a gasification stage effluent 111 containing CO, H.sub.2, and CO.sub.2, and may use oxygen source 108 and steam source 109, just as in the conventional process 100. Additionally, just as in process 100, there is a refining stage, here 212B, that contains a CO converter 113 (and bypass) for selectively routing a portion of the gasification stage effluent 111 for CO conversion to increase the H.sub.2 content of the gasification stage effluent 111 relative to CO. The process 200B also has the CO.sub.2 removal unit 114 (and bypass) for removing CO.sub.2 from intermediate stream 230, wherein the CO.sub.2 removal unit 114 yields a stream of removed CO.sub.2 which may be directed, in part or wholly, into CO.sub.2 recycle 118 for recycling back into gasification stage 104 and into by-product 116, in part or wholly, for sequestration. Unlike the conventional process 100, a hydrocarbon processing stage effluent 256, product of the hydrocarbon processing stage 250, is combined with precursor 132 downstream of the CO.sub.2 removal unit 114. This combined stream may then be directed through purification unit 217, if further purification is required, similar to the process 200A of
[0125] The process 200B has a fossil hydrocarbon processing stage 250 to produce the hydrocarbon processing stage effluent 256. The hydrocarbon processing stage 250 includes the hydrocarbon converter 210B which uses a reactor or reaction facility configured to convert the hydrocarbon material 206 into syngas. Such facilities are known, and include steam methane reforming (SMR) facilities, auto-thermal reforming (ATR) facilities, and POX facilities. The hydrocarbon material 206, derived from fossil sources, is introduced into the process 200B as an input to the hydrocarbon converter 210B within the hydrocarbon processing stage 250. The hydrocarbon material 206 used with the process 200B can have the same source and composition as any of the hydrocarbon streams described above in connection with the process 200A. In some embodiments, the hydrocarbon converter 210B is sized to convert a hydrocarbon stream with a mass flow rate of atomic carbon that is at least 15% of the net mass flow rate of atomic carbon input to the overall process. That is to say, in some embodiments, the hydrocarbon converter 210B handles at least 15% of atomic carbon input to the process.
[0126] The hydrocarbon converter 210B produces an effluent 252 containing substantially syngas and CO.sub.2, which is then routed to a second CO converter 213B, which may be a WGS unit, to produce an intermediate 254 that is substantially H.sub.2 and CO.sub.2. Intermediate 254, which is a second converted stream, is then routed to a second CO.sub.2 removal unit 214B, which may be an AGR unit, to produce the hydrocarbon processing stage effluent 256. The second CO.sub.2 removal unit 214B produces a stream of CO.sub.2 that can be entirely routed for sequestration, either combined with by-product 116 or separately. A second purification unit (not shown) may be used immediately after the second CO.sub.2 removal unit 214B, which may be a PSA or methanation unit, if further purification of the hydrocarbon processing stage effluent 256 is desired. As before, where the purification unit 217 and the monitoring unit 122 are omitted, the hydrocarbon processing stage effluent 256 can be a second conversion feed, that is mixed with the precursor 132 (under such circumstances a first conversion feed) to produce the conversion feed 224 that is provided to the conversion stage 226.
[0127] Routing the CO.sub.2 produced by the hydrocarbon processing stage entirely to sequestration 116 results in finished products derived from the conversion stage 226 that have little or substantially no fossil-derived carbon in them. In the process 200B, fossil-derived CO.sub.2 258 can be routed from the second CO.sub.2 removal unit 214B to the hydrocarbon processing stage effluent 256 to control the amount of fossil-derived carbon that appears in the conversion feed 224 and in the final products from the conversion stage 226. A flow controller 260 can be used to control flow of the fossil-derived CO.sub.2 258 to the hydrocarbon processing stage effluent 256 to withdraw a desired amount of fossil-derived CO.sub.2 from sequestration and route a controlled amount of fossil-derived carbon into the conversion feed 224 and thus into the final conversion stage 226 products. In this way, an arbitrary amount of fossil-derived carbon up to the entire amount of carbon available from the hydrocarbon stream 206, modulated by CO.sub.2 conversion to final products in the conversion stage 226, can be included in the final products.
[0128] In the process 200B, substantially all the fossil-derived carbon from the hydrocarbon material 206 is converted to CO.sub.2 and sequestered. Whereas embodiments of process 200A and 200B may be engineered to have similar inputs, outputs, and GHG LCA product values, the process 200B inherently has a lower degree of system integration, since the process 200A has a single conversion unit 210, whereas in 200B the tar converter 110 and the hydrocarbon converter 210B are separate. Similarly, in the process 200A, there is a single CO converter 213 and a single CO.sub.2 removal unit 214, whereas in the process 200B there are two CO converters, a first CO converter 113 and a second CO converter 213B, and two CO.sub.2 removal units, a first CO.sub.2 removal unit 114 and a second CO.sub.2 removal unit 214B. However, in both processes 200A and 200B the same facility infrastructure, including utilities, may be efficiently shared by building an integrated process and facility in a single location, and the downstream modules from 217 onward may be shared.
[0129]
[0130] The process 200C produces a carbon containing product that has little to substantially no fossil carbon, but with fewer processing units. Relative to process 200B, in process 200C, the CO.sub.2 recycle 118 has been removed, the two CO removal units 114 and 214B have been replaced by the single unit 214 (similar to the unit in the process 200A), and the intermediate 254 of the process 200B is instead routed directly to the CO.sub.2 removal unit 214 along with the portion of stream 130 diverted for CO.sub.2 removal, so as to produce a precursor 232 that is substantially free of fossil carbon (provided, as noted below, the added CO.sub.2 stream 218 is itself substantially free of fossil-derived carbon). It can be readily observed that since intermediate 254 contains substantially H.sub.2 and fossil-derived CO.sub.2, and substantially all of the CO.sub.2 in intermediate 254 is removed by the CO.sub.2 removal unit 214 without recycling any of the removed CO.sub.2 back into the process through recycle 118, then the precursor 232 is substantially free of fossil-derived carbon, and products resulting from the precursor 232 are also substantially free of fossil-derived carbon.
[0131] A source of CO.sub.2 260 can be provided to supply CO.sub.2 to the gasification stage 104 using a CO.sub.2 conduit 218, if needed. If not needed, the CO.sub.2 source 260 and CO.sub.2 conduit 218 may be omitted, ensuring that no fossil-derived CO.sub.2 enters the gasification stage 104. The CO.sub.2 source 260 may be, or may include, any or all of a CO.sub.2 pipeline, a CO.sub.2 capture system that captures CO.sub.2 from another industrial process, or a direct air capture (DAC) facility that removes CO.sub.2 directly from the atmosphere. In the case that the CO.sub.2 delivered using the conduit 218 is substantially biogenic, there can be substantially no fossil-derived CO.sub.2 entering the gasification stage 104. If instead the CO.sub.2 delivered using conduit 218 contains fossil-derived CO.sub.2, then the CO.sub.2 conduit 218 will add fossil-derived CO.sub.2 to the precursor 232 and downstream products. With respect to producing a carbon containing product such as methanol or hydrocarbon that is substantially free of fossil-derived carbon, use of a CO.sub.2 source that is biogenic, such as a DAC process or CO.sub.2 captured an industrial process that produced biogenic CO.sub.2, in the process 200C, may be superior to the process 200B in cases where such biogenic CO.sub.2 source 260 can be secured economically.
[0132] Example embodiments of the processes 200B and 200C are simulated below. The parameters and assumptions introduced above apply to the simulated processes 200B and 200C, below, with the following additions: [0133] A. the hydrocarbon conversion unit 210B is a POX reactor in which: [0134] 1. the output stream 252 is mostly CO, CO.sub.2, and H.sub.2, and only trace amounts of other species; [0135] 2. the hydrocarbon material 206 is a natural gas stream, and 75% of the carbon in the hydrocarbon material 206 is converted into CO, and the remaining 25% is converted into CO.sub.2; and, [0136] 3. a volumetric ratio of H.sub.2:CO in the output stream 252 is equal to 2; [0137] B. the CO converter 213B is a WGS unit that converts 100% of the input CO into H.sub.2 and CO.sub.2 via reaction with water; and [0138] C. the CO.sub.2 removal unit 214B is an AGR unit that removes 100% of the input CO.sub.2 from the process and in so doing leaks 5% of that removed CO.sub.2 into the atmosphere.
[0139]
[0140] It is noted that the natural gas input, methanol product, and GHG LCA in CASE 8B are approximately the same as in corresponding CASE 3B, indicating that process 200B (simulated in CASE 8B) and process 200A (simulated in CASE 3B) have approximately the same overall process performance. Similarly, in both CASE 8B and CASE 3B, the % of net atomic carbon input into process from natural gas is 29%, and total sequestered CO.sub.2 is approximately 920 mt/d. In CASE 8B, 0% of the carbon in the methanol product is fossil-derived carbon, whereas in CASE 3B 40% of the carbon in the methanol product is fossil-derived carbon. CASE 8B results in more fossil-derived carbon being routed to by-product 116 for sequestration and more biogenic carbon retained in the main process (by reducing, as noted above, the portion of gasification stage effluent 111 that flows into CO converter 113 and the portion of stream 130 that flows into CO.sub.2 removal unit 114 compared to the corresponding values in CASE 3B). The increase in fossil-derived CO.sub.2 directed to sequestration in CASE 8B, relative to CASE 3B, is observed in the proportion of CO.sub.2 by-product 116 that is fossil-derived CO.sub.2, which is 31% in CASE 3B and 70% CASE 8B.
[0141] CASE 8C reflects a similar relationship to CASE 3C as described above for CASE 8B and CASE 3B. In both cases the input natural gas (and share of fossil-derived carbon in the input carbon streams), output methanol product, and GHG LCA are all approximately the same, while the proportion of fossil-derived carbon in the methanol product is 0% for CASE 8C and 48% for CASE 3C. Methanol free of fossil-derived carbon is achieved in CASE 8C by increasing the amount of fossil-derived CO.sub.2 routed to sequestration and retaining an equal amount of biogenic carbon in the main process by reducing the portion of gasification stage effluent 111 that flows into CO converter 113 and the portion of stream 130 that flows into CO.sub.2 removal unit 114 compared to the corresponding values in CASE 3C.
[0142] CASE 8D is a modified version of CASE 8C in which additional natural gas is supplied (here 390 mt/d vs 350 mt/d in CASE 8C) so that there is sufficient hydrogen available to fully consume all of the available biogenic carbon and maximize the production of 100% biogenic methanol, with a yield of 870 mt/d (approximately 2.74 times the conventional CASE 3A, process 100, value.) In this case, no biogenic CO.sub.2 is sequestered, as reflected by the fact that 100% of the CO.sub.2 by-product 116 is fossil-derived CO.sub.2. It is not possible to further increase the methanol output in this process 200B with further increases in natural gas input as there are no more biogenic carbon atoms to divert to the conversion stage 226 for conversion to product and none of the fossil-derived carbon from the natural gas input reaches the conversion stage 226. This contrasts with process 200A, in which increasing natural gas supplies adds carbon to the conversion stage 226, driving increased output (with a correspondingly higher GHG LCA product that also has a correspondingly higher share of fossil atomic carbon.) The GHG LCA of the methanol produced in CASE 8D is about 26% of the fossil baselinea modest increase over the CASE 8C value of 20%. For CASE 8D, the % of net atomic carbon input to the process from natural gas is 43%, the product atomic carbon yield per sustainable atomic carbon input into the process is 0.85, and the product yield per dry solid sustainable carbon material input into the process is 1.13.
[0143] As noted above, the process 200B can be used to direct an arbitrary amount of fossil-derived CO.sub.2 to the final products available from the conversion stage 226. Thus, while all cases in
[0144]
[0145] The GHG LCA of the hydrocarbon product is approximately zero in CASE 9B. It is notable that the natural gas input, hydrocarbon product, and GHG LCA in CASE 9B are approximately the same as in corresponding CASE 4B, indicating that process 200B (simulated in CASE 9B) and process 200A (simulated in CASE 4B) have approximately the same overall process performance. Similarly, in both CASE 9B and CASE 4B the % of net atomic carbon input into process from natural gas is 31%, and total sequestered CO.sub.2 is approximately 978 mt/d. In CASE 9B, however, 0% of the carbon in the hydrocarbon product is fossil-derived carbon, whereas in CASE 9B 41% of the carbon in the hydrocarbon product is fossil-derived carbon. CASE 9B results in more fossil-derived carbon being routed to the CO.sub.2 by-product 116 while retaining an equal amount of additional biogenic carbon in the main process (by reducing, as noted above, the portion of the gasification stage effluent 111 that flows into the CO converter 113 and the portion of stream 130 that flows into the first CO.sub.2 removal unit 114 compared to CASE 4B. The increase in fossil-derived CO.sub.2 directed to sequestration is observed in the proportion of the CO.sub.2 by-product 116 that is fossil-derived CO.sub.2, which is 25% in CASE 9B and 70% in CASE 9B.
[0146] CASE 9C reflects a similar relationship to CASE 4C as described above for CASE 9B and CASE 4B. In both cases (CASE 9C and CASE 4C) the input natural gas (and proportion of fossil-derived carbon in the input carbon streams), output hydrocarbon product, and GHG LCA are all approximately the same, while the proportion of fossil-derived carbon the methanol product is 0% for CASE 9C and 49% for CASE 4C. CASE 9C also results in more fossil-derived carbon directed to sequestration while retaining an equal amount of additional solid sustainable carbon in the main process by reducing the portion of the gasification stage effluent 111 that flows into the CO converter 113 and the portion of stream 130 that flows into the first CO.sub.2 conversion unit 114 compared to CASE 4C.
[0147] CASE 9D is a modified version of CASE 9C in which additional natural gas is supplied (here 420 mt/d vs 375 mt/d in CASE 9C) so that there is sufficient hydrogen available to fully consume all of the available biogenic carbon and maximize the production of 100% biogenic hydrocarbons, with a yield of 384 mt/d (approximately 2.87 times the conventional CASE 4A, process 100, value.) In this case, no biogenic CO.sub.2 is sequestered, as reflected by the fact that 100% of the CO.sub.2 by-product 116 is fossil-derived CO.sub.2. It is not possible to further increase the hydrocarbon output in this process 200B with further increases in natural gas input as there are no more biogenic carbon atoms to route to the conversion stage 226 for conversion to product and none of the fossil-derived carbon from the natural gas input reaches the conversion stage 226. This contrasts with process 200A, in which increasing natural gas adds carbon to the conversion stage 226, driving increased output (with a correspondingly higher GHG LCA product that also has a correspondingly higher share of fossil atomic carbon.). The GHG LCA of the hydrocarbons produced in CASE 9D is about 27% of the fossil baselinea small increase over the CASE 9C value of 20%. For CASE 9D the % of net atomic carbon input into the process from natural gas is 45%, the product atomic carbon yield per sustainable atomic carbon input into the process is 0.85, and the product yield per dry solid sustainable carbon material input into the process is 0.50.
[0148]
[0149] In the embodiment labeled CASE 10C referring to an embodiment of process 200B, 3000 mt/d of natural gas is supplied to the hydrocarbon converter 210B via the hydrocarbon material 206, and the total ammonia product output increases to 3457 mt/d. The process performance and process metrics of CASE 10C are approximately the same as in CASE 5C, corresponding to process 200A. This finding that process 200B and 200A have approximately the same performance and metrics is consistent with the understanding that process 200B is functionally equivalent to process 200A but without routing any fossil-derived carbon into the conversion feeds 124 and 224. Since each of the conversion feeds 124 and 224 entering the respective conversion stages 126 and 226 is pure hydrogen in the case of ammonia production, there is no practical difference between the two processes, except, as discussed above, in the degree of module integration. Accordingly, other things being equal, it would be normally expected that process 200A would be less costly to operate than process 200B (or 200C).
[0150] As in process 200C, it is possible to configure versions of each of CASE 8B, 8C, 8D, 9B, 9C, 9D, 10B, and 10C in which the CO.sub.2 recycle 118 is omitted, and CO.sub.2 is supplied to the gasification stage 104 from the biogenic CO.sub.2 source 260 at the simulated rate of 135 mt/d. As previously noted, the biogenic CO.sub.2 source 260 may be a direct air capture system or a carbon capture system configured to remove biogenic CO.sub.2 from an industrial process.
[0151] The improved integration offered by process 200C over 200B (via the use of a single CO.sub.2 removal unit 214 in process 200C rather than two CO.sub.2 removal units 114 and 214B in process 200B) would be expected to reduce total plant capital cost and operating cost. In most cases it would be expected that providing biogenic CO.sub.2 source 260 and CO.sub.2 conduit 218 would be more expensive than providing CO.sub.2 recycle 118, but the higher integration of process 200C may offset the higher cost of employing process 200B so as to ensure fossil/biogenic carbon segregation. It is also noteworthy that in process 200C, the net total amount of sustainable atomic carbon input can be increased for the same size gasifier and the same solid sustainable carbon material input due to the additional biogenic CO.sub.2 input, offering an opportunity (when producing carbon containing products like methanol and hydrocarbons) to increase the total amount of 100% biogenic carbon product output.
[0152]
[0153]
[0154]
[0155] The solid sustainable carbon material conversion processes described herein use hydrocarbons derived from conventional sources to supplement carbon and hydrogen in the syngas produced by solid sustainable carbon material gasification. Such supplementation can boost yield of products from solid sustainable carbon material conversion processes, and where biogenic CO.sub.2 formed from solid sustainable carbon material gasification is sequestered, still yield low, or even zero or negative GHG LCA products.
[0156] In general, the solid sustainable carbon material conversion processes described herein may be operated with a % of net atomic carbon input into the process from fossil-derived hydrocarbons of between 15% and 50% so as to produce carbon containing chemicals, for example methanol and hydrocarbons, with GHG LCA that ranges from modestly negative to modestly positive, including zero. Some processes described herein can use fossil-derived hydrocarbon to make hydrogen for an ammonia plant that uses solid sustainable carbon material as a feedstock. In general, the solid sustainable carbon material conversion processes described herein may be operated with a % of net atomic carbon input into the process from fossil-derived hydrocarbons of between 35% and 90% so as to produce carbon free chemicals, for example hydrogen or ammonia, with GHG LCA that ranges from modestly negative to modestly positive, including zero.
[0157] In general, each of the biomass conversion processes described herein may be operated as a single integrated facility that produces carbon-containing products with well-to-wake GHG LCA less than 20%, less than 10%, or less than 5% of the corresponding fossil baseline GHG LCA (based on reference values and a GHG LCA methodology consistent with the 2022 GREET model). These processes can be operated to produce a product atomic carbon yield per sustainable atomic carbon input into the process that is at least 0.45, at least 0.50, at least 0.60, at least 0.70, or at least 0.80. To calculate these values in the simulations of the processes 200B and 200C herein, the biogenic input carbon mass flow rate is 369 mt/d, the output carbon mass flow rate for methanol is equal to the methanol production rate multiplied by 12/32, and the output carbon mass flow rate for FT hydrocarbons is equal to the hydrocarbon production rate multiplied by 0.85 (utilizing the approximation that such hydrocarbons comprise about 85% carbon by weight.) In contrast to the above higher values, the product atomic carbon yield per sustainable atomic carbon input into the process of CASE 3A is just 0.31, reflecting the conventional solid sustainable carbon material conversion to methanol process. Similarly for FT hydrocarbons, the CASE 4A value is just 0.29. Thus the embodiments shown herein demonstrate that, contrary to conventional wisdom, it is possible to substantially boost carbon containing product yield through integration of fossil-derived natural gas conversion and solid sustainable carbon material gasification while also producing a very low, zero, or even negative GHG LCA product.
[0158] In general, each of the biomass conversion processes described herein may be operated as a single integrated facility that produces ammonia with GHG LCA less than 10%, less than 5%, or less than 2% of the corresponding fossil baseline GHG LCA (based on reference values and a GHG LCA methodology consistent with the 2022 GREET model). These processes can be operated to have a product yield per dry solid sustainable carbon material input into the process of 1.0, at least 2.0, at least 3.0, or at least 4.0. In contrast, the product yield per dry solid sustainable carbon material input into the process for CASE 5A is just 0.36, reflecting the conventional solid sustainable carbon material conversion to ammonia process. Thus the embodiments shown herein demonstrate that contrary to conventional wisdom, it is possible to substantially boost ammonia product yield through integration of fossil-derived natural gas conversion and solid sustainable carbon material gasification while also producing a very low, zero, or even negative GHG LCA product.
[0159] The processes disclosed herein for converting waste solid sustainable carbon materials into chemical products generally use an amount of additional hydrocarbon, such as natural gas, sourced from fossil sources to boost output of the chemical products for little additional capital cost. CO.sub.2 produced by the conversion of raw materials into useable chemical precursors is sequestered or otherwise consumed to make the final products, so the GHG LCA of the produced final products can be much lower than similar products made in conventional ways, and the increased output of final products provides economy of scale to make such processes more attractive. In general, these processes use hydrocarbon at a mass flow rate that is at least about 15% of the dry weight mass flow rate of waste solid sustainable carbon material used. Where the final products are carbon-containing products, hydrocarbon conversion to CO and hydrogen is balanced with conversion of CO from biomass gasification into hydrogen and CO.sub.2 to yield a syngas material, as a precursor to chemical production, that has a volumetric ratio of hydrogen to CO that is at least 2.0, and may be higher, for example 2.2, 2.5, or 3.0.
[0160] CO.sub.2 produced by hydrocarbon and biomass conversion is mostly sequestered, for example in a subterranean facility (or any suitable facility), but some can be recycled and used to enhance gasification of the solid sustainable carbon material. In some cases, the hydrocarbon can be converted entirely to hydrogen and CO.sub.2 and the waste solid sustainable carbon material can be converted entirely to hydrogen and CO.sub.2, and the hydrogen can be used to make ammonia. In some cases, carbon from the hydrocarbon can be segregated from biogenic carbon so that the final chemical products contain only biogenic carbon. Where carbon from fossil sources is segregated from biogenic carbon, biogenic CO.sub.2 can be used to enhance gasification, rather than recycling CO.sub.2 that might contain fossil-derived carbon, so the final chemical products can remain free of fossil-derived carbon. Generally speaking, sequestering more CO.sub.2 decreases environmental burden of all the processes described herein. In particular sequestering CO.sub.2 from the fossil-derived hydrocarbon added to the processes is beneficial. For example, the processes described herein can be operated to sequester at least 90%, or at least 95%, or at least 99% of the carbon from the fossil-derived hydrocarbon material 206 as captured and sequestered CO.sub.2. In some embodiments for producing carbon containing materials, at least 5%, but not more than 40%, of sustainable atomic carbon input from waste carbon containing material (e.g. waste solid biomass, waste solid sustainable carbon material) is sequestered in a sequestration facility.
[0161] As the various examples described herein show, in some embodiments sequestered CO.sub.2 has a first component from sustainable carbon input and a second component from fossil-derived hydrocarbon. In some embodiments, the first component has a mass flow rate of CO.sub.2 that is 44/12 times 90% of the mass flow rate of atomic carbon from the input fossil-derived hydrocarbon and the second component has a mass flow rate of CO.sub.2 that is 44/12 times 5% of the mass flow rate of atomic carbon from the input solid sustainable carbon material. These components may flow separately to sequestration, or may be combined at any suitable point in a particular embodiment.
[0162] Frequently biomass has a high moisture content in its initial (or green) state that is much higher than the optimal moisture level for feeding into a gasifier reactor as described herein. For example, forestry residues often have a moisture content of 40% to 50% by weight, whereas it is typical for the biomass fed into a gasifier to have a moisture content of between 5% and 25% by weight. The same biomass mass flow rate into a gasifier yields a higher carbon flow rate when the moisture level is lower, which boosts plant output for the same size gasifier. It is also easier to control the amount of steam in the gasifier reactor when using a biomass with a low moisture level by selectively adding steam into the process, whereas using biomass with higher moisture content can add unpredictable amounts of steam to the process. However, drying costs and the risk of feedstock combustion in the feeding system both increase as the biomass moisture content is reduced, and in balancing these considerations it is typically found that the range of 5% to 25% moisture content by weight is the most economical. Thus to produce the dried and sized biomass 102 that is fed into the gasification island 104, 204, and 270, the green state biomass usually must be dried.
[0163]
[0164]
[0165] Returning to
[0166] The conversion of biomass 1480 into the energy using the biomass processing unit 1410 produces flue exhaust stream 1420 that contains biogenic CO.sub.2. Typically the CO.sub.2 produced by the conversion of biomass 1480 would be exhausted into the atmosphere, since that is the lowest cost way to handle such CO.sub.2. Such CO.sub.2 is also biogenic, and therefore does not contribute any net GHG LCA (since there is no net addition of CO.sub.2 into the environment compared to allowing the biomass to simply aerobically decompose into CO.sub.2). However, in the process 300A, the biogenic CO.sub.2 in exhaust stream 1420 is captured by CO.sub.2 removal unit 1460 to produce captured biogenic CO.sub.2 stream 1450 and residual exhaust stream 1440. Biogenic CO.sub.2 stream 1450 is then directed to one or more of: (a) the gasification and tar conversion units to satisfy the CO.sub.2 demand of such units, if any; (b) sequestration so as to further reduce the GHG LCA of the end product; and (c) downstream processing units so as to provide additional biogenic CO.sub.2 for conversion in chemicals, such as methanol and FT hydrocarbons.
[0167] Prior art process 100 may be upgraded in this manner to use biogenic CO.sub.2 1450 (a) in gasification stage 104 to satisfy the CO.sub.2 demand, if any, of gasifier 106 and converter 110, eliminating the need for CO.sub.2 recycle stream 118; (b) in sequestration stream 116; and/or (c) in process stream 132, 120 or 124. Process 200A can also utilize the biogenic CO.sub.2 stream 1450 (a) in gasification stage 204 to satisfy the CO.sub.2 demand, if any, of gasifier 106 and converter 210, eliminating the need for CO.sub.2 recycle stream 118 and/or separate CO.sub.2 stream 218 (and CO.sub.2 source 260); (b) in sequestration stream 116; and (c) in process stream 232, 220 or 224. Process 200B can also utilize the biogenic CO.sub.2 stream 1450 (a) in gasification stage 104 to satisfy the CO.sub.2 demand, if any, of gasifier 106 and converter 110, eliminating the need for CO.sub.2 recycle stream 118; (b) in sequestration stream 116; and (c) in process stream 132, 220 or 224. Process 200C can also utilize the biogenic CO.sub.2 stream 1450 (a) in gasification stage 104 to satisfy the CO.sub.2 demand, if any, of gasifier 106 and converter 110, eliminating the need for separate CO.sub.2 stream 218 (and CO.sub.2 source 260); (b) in sequestration stream 116; and (c) in process stream 232, 220 or 224. Process 200D can also utilize the biogenic CO.sub.2 stream 1450 (a) in gasification stage 270 to satisfy the CO.sub.2 demand, if any, of gasifier 106, converter 110, and converter 210B, eliminating the need for CO.sub.2 recycle stream 118 and/or separate CO.sub.2 stream 218 (and CO.sub.2 source 260); (b) in sequestration stream 116; and (c) in process stream 232, 220 or 224.
[0168] In many embodiments, as in the case where biomass 1480 is directly combusted in air and in the case where biomass 1480 is gasified in an air-blown gasifier, flue exhaust stream 1450 is mostly air and a relatively low amount of CO.sub.2, e.g. <5%, <10%, or <20% by volume CO.sub.2. The removal by unit 1460 of CO.sub.2 from such a stream is conventionally viewed as uneconomical because CO.sub.2 removal from streams with relatively low CO.sub.2 concentration demands relatively larger equipment and the processing of relatively larger gas volumes to remove a given amount of CO.sub.2, when compared to CO.sub.2 removal from streams with relatively high CO.sub.2 concentrations (e.g. >20%, >30%, >50% by volume). The conventional practice therefore is not to utilize carbon removal with such low CO.sub.2 concentration streams due to this high cost. The processes described herein, however, integrate such a carbon capture system within a sustainable chemical production facility, leading to a substantial increase in the overall yield of the facility, thus providing economic incentive to use CO.sub.2 removal even with dilute streams. Stated differently, the incremental value of an additional biogenic CO.sub.2 supply is high enough that unit 1460 can be economically introduced, even though it would be conventionally uneconomical when viewed as a stand-alone unit. In 1460 the percentage of the CO.sub.2 in stream 1420 captured (or equivalently, removed) and delivered into stream 1450 (i.e. the capture rate) may be selected during design engineering to optimize the project economics to provide a capture rate of >50%, >80%, >90%, and >95%. Since the leakage of biogenic CO.sub.2 into the atmosphere does not contribute any net GHG LCA, and so does not negatively impact the project's sustainability, the analysis can be optimized primarily in terms of these economics.
[0169] In the illustrative embodiments provided in
[0174] The biomass fuel stream amount of 318 dry-mt/d of bark wood was selected to provide sufficient energy to a biomass boiler to support drying 771 dry-mt/d of softwood forestry residues from a typical green moisture level of 50% by weight down to the 15% moisture by weight level in stream 102 in our illustrative embodiments. It is readily understood that different amounts of biomass fuel would be required for different biomass types and different processing conditions, including different starting and ending moisture levels.
[0175]
[0176]
[0177] The picture is similar for FT hydrocarbon production.
[0178] While the foregoing is directed to embodiments of one or more inventions, other embodiments of such inventions not specifically described in the present disclosure may be devised without departing from the basic scope thereof, which is determined by the claims that follow.