GB2154600A - Producing and purifying methane - Google Patents

Producing and purifying methane Download PDF

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Publication number
GB2154600A
GB2154600A GB08404726A GB8404726A GB2154600A GB 2154600 A GB2154600 A GB 2154600A GB 08404726 A GB08404726 A GB 08404726A GB 8404726 A GB8404726 A GB 8404726A GB 2154600 A GB2154600 A GB 2154600A
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United Kingdom
Prior art keywords
process
methane
hydrogen
stream
subjected
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Withdrawn
Application number
GB08404726A
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GB8404726D0 (en
Inventor
Terence Foley
John J Templeman
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British Gas Corp
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British Gas Corp
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Priority to GB08404726A priority Critical patent/GB2154600A/en
Publication of GB8404726D0 publication Critical patent/GB8404726D0/en
Publication of GB2154600A publication Critical patent/GB2154600A/en
Application status is Withdrawn legal-status Critical

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Classifications

    • CCHEMISTRY; METALLURGY
    • C07ORGANIC CHEMISTRY
    • C07CACYCLIC OR CARBOCYCLIC COMPOUNDS
    • C07C9/00Aliphatic saturated hydrocarbons
    • C07C9/02Aliphatic saturated hydrocarbons with one to four carbon atoms
    • C07C9/04Methane
    • CCHEMISTRY; METALLURGY
    • C07ORGANIC CHEMISTRY
    • C07CACYCLIC OR CARBOCYCLIC COMPOUNDS
    • C07C7/00Purification; Separation; Use of additives
    • C07C7/144Purification; Separation; Use of additives using membranes, e.g. selective permeation
    • YGENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02PCLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
    • Y02P20/00Technologies relating to chemical industry
    • Y02P20/50Improvements relating to the production of products other than chlorine, adipic acid, caprolactam, or chlorodifluoromethane, e.g. bulk or fine chemicals or pharmaceuticals
    • Y02P20/58Recycling
    • Y02P20/582Recycling of unreacted starting or intermediate materials

Abstract

A process for the production of methane-containing gases by the catalytic gasification of hydrocarbon feedstocks in the presence of steam and wherein the feedstock is subjected to catalytic hydrodesulphurisation prior to gasification is modified in that at least a portion of the product gas containing methane, hydrogen, carbon oxides is subjected to a separation process comprising contacting said portion of product gas with a polymeric membrane separator, said membrane having a permeation factor which is substantially greater for hydrogen than for methane, thereby to produce a methane containing non-permeate stream and a hydrogen-containing permeate stream which is recycled as reactant for the hydrodesulphurisation stage. Gases produced by this method may be employed directly as a substitute for Natural Gas.

Description

SPECIFICATION Production of methane-containing gas This invention relates to gas production processes, more particularly to the product of methane-containing gases.

Methane-containing gases which have been used as fuel gases or have been up-graded as a substitute for natural gas (SNG) can be produced by the catalytic gasification of hydrocarbons in the presence of steam.

One such catalytic process is known as the Catalytic Rich Gas (CRG) Process and the basic process is described in UK Patent Specification No. 820257, although the process has been considerably modified over the past twenty years.

A typical dry gas composition of the gas produced in the CRG process from a light naphtha feedstock is: % vlv C02 21.1 CO 0.9 H2 14.5 CH4 63.5 This gas contains the two components required for SNG production, namely methane for SNG, and hydrogen for desulphurisation of the feedstock. With heavierfeedstocks, because of the higher preheat temperatures and steam/feed ratios required to give a satisfactory catalyst performance, the proportion of hydrogen in the product gas is higher. The quantity of hydrogen produced normally falls within the range 1.25 to 5.0 scf per Ib of feedstock; the precise quantity depending on the feedstock being gasified and the CRG reactor operating conditions.

We have now found that the substitute natural gas production process can be advantageously simplified by subjecting at least a portion of the product gas to recover one of the components, viz hydrogen, which is not required in any substantial amount in the final SNG but which is required for the hydrodesulphurisation stage and, optimally, in the case of heavier feedstocks for the main gasification process.

In accordance with the present invention there is provided a process for the production of methanecontaining gases by the catalytic gasification of hydrocarbon feedstocks in the presence of steam and wherein the feedstock is subjected to catalytic hydrodesulphurisation prior to gasification characterised in that at least a portion of the product gas containing methane, hydrogen and carbon oxides is subjected to a separation process comprising contacting said portion of product gas with a polymeric membrane separator, said membrane having a permeation factor which is substantially greater for hydrogen than for methane, thereby to produce a methane containing non-permeate stream and a hydrogen-containing permeate stream which is recycled as reactant for the hydrodesulphurisation stage.

The permeate stream will typically also contain the carbon dioxide fraction of carbon oxides.

In one embodiment of the invention all of the product gas is subjected to membrane separation. Thus the non-permeate will comprise essentially methane and a minor amount of carbon monoxide. Excess water from the main gasification reaction will normally pass through the membrane as a permeate species.

In another embodiment, it is preferable that only a portion of the product stream be subjected to membrane separation, and the remainder of the product stream is subjected to at least one further catalytic methanation reaction, optionally the permeate stream is admixed with the remaining stream prior to a further methanation reaction.

Developments in gas separation based on permeation through membranes have now reached a stage where processing of large volumes of gas is possible. The relative rates of membrane permeation of the four constituents of CRG product gas (based on water vapour having a notional value of 100) are as follows: CH4 0.2 CO 0.3 CO2 6.0 H2 12.0 Thus membrane separation of CRG product gas will result in two gas streams, one consisting essentially of the CH4 and CO content (the non-permeate stream) and the other the CO2 and H2 (the permeate stream).

The degree of separation achieved depends on two factors, namely: (1 ) The installed surface area of the membrane (2) The pressure differential over the membrane.

In the ultimate limit, if complete separation were achieved, the composition of the two gas streams for the CRG gas composition quoted earlier on would be: % v/v Permeate Stream Hydrogen 40.6 Carbon Dioxide 59.4 Non-Permeate Stream Methane 98.6 Carbon Monoxide 1.4 The relative pressures of the two gas streams produced from the membrane separation of CRG product gas are those desirable for SNG production, that is, the "non-permeate" and will undergo a relatively small pressure loss, whereas the "permate" stream is produced at a relatively low pressure.

For example typical operating pressures might be: Dry CRG product gas - 850 psig Non-permeate stream - 750 psig Permeate Hydrogen/CO2 stream - 200 psig In the process the of the invention H2/C02 stream would preferably undergo a CO2 removal step, and the resultant hydrogen stream compressed. Part of it will be returned to the hydrodesulphurisation unit for feedstock purification, because this process produces a substantially pure hydrogen strea the performance of the HDS unit will benefit. The process produces more hydrogen than required for purification, for example, in the case of light distillate approximately 4 sof of H2 per lb of feedstock are produced.In the case of light distillate the "excess" hydrogen would be used as process fuel, but with heavy feedstocks it would be beneficial to add the "excess" hydrogen to the reactants entering the CRG reactor; the additional hydrogen would help to prolong the life of the catalyst since it would reduce the rate at which polymer is laid down.

The invention will be described further by reference to the accompanying drawing in which: Figure 1 is a flow diagrame for a commercially available gasification process - hereinafter called CRG-2M.

Figures 2 and 3 are flow diagrams of two embodiments of the process in accordance with the present invention.

Referring to the drawings, a hydrocarbon feedstock 1 is admixed with a hydrogen-containing stream 2, preheated in heater 3 and subjected to hydrodesulphurisation in catalytic vessel 4. The hydrodesulphurisation technique is a conventional one and utilises catalysts such as a nickel-molybdenum system. The hydrogen sulphide produced is removed by passage of the gas through catch beds (not shown) of, for example, zinc oxide. The purified gas is then admixed with steam 5 and the mixture heated to the reaction temperature in heater 6 prior to the gasification reaction in the CRG reactor 7.

According to the known CRG-2M technique the CRG product gas 8 is subjected to two methanation reactions. The first methanation is carried out in methanator 9 to give a product gas 10, which after water rejection in separation 11 is reacted in methanator 12 to yield product 13. After carbon dioxide removal and drying (not shown) a gas 14 of SNG specification is produced.

Typical process parameters for a CRG-2M process are given in Table 1.

By way of direct comparison, as shown in Figure 3, the two methanators are replaced with a single membrane separator 15, for example, a 'prism' separator. Thus stream 8 is subjected to separation to produce a permeate stream 16 and a non-permeate stream 17 which are directly suitable as SNG 18 without the need for C02 removal or drying.

The permeate stream 16 is subjected to carbon dioxide removal 19 to give a CO2 stream 20 and a hydrogen rich stream 21 which after separation of any excess hydrogen 22 is used as the hydrogen feed stream 2.

Comparable process parameters for this embodiment are also given in Table 1.

TABLE 1 UNIT FIGURESl & FIGURE 1 FIGURE3 PARAMETER 4 7 8 9 10 12 13 14 16 17 18 COz % v/v - - 11.8 - 10.9 - 20.15 - 59.4 - CO%v/v - - 0.49 - 0.02 - 0.01 0.01 - 1.4 1.4 H2%v/v - - 8.07 - 1.57 - 0.15 0.20 40.6 - CH4 % v/v - - 35.5 - 38.61 H20 % v/v - - 44.14 - 49.9 - 74.52 99.78 - 98.6 98.6 Inlet"C - 450 - 280 - 250 - Outlet"C - 516 - 358 - 276 - Pressure psia 520 520 - 500 - 480 - H2/Feedstock Ft3/lb 0.5 .5 H2/Feedstock Ib/lb - 1 .8 - It is worthwhile comparing the process of the present invention with the conventional CRG-2M; the two schemes are shown in Figures 1 and 3 respectively.In both cases the feedstock and operating conditions of the hydrodesulphurisation and CRG stages are the same. The percentage of carbon in the feedstock that appears in the final gas (as CH4 and CO) is 75.29 and 78.02 for the membrane and the CRG-2M processes respectively. The lower carbon conversion in the membrane separation process is a result of eliminating the methanation stages where hydrogen reacts with the oxides of carbon to produce more methane. However, although there is some 5 to 6% reduction in the quantity of CH4 produced per Ib of feedstock it is not an absolute loss because the hydrogen that would have reacted in the CRG-2M process, appears in the permeate gas in the membrane separation SNG process.

The advantages of the membrane separation process can be summarised as follows: (1) The amount of processing plant is reduced since the process of the invention not only replaces two methanation stages; it also replaces the plant required for the production of the recycle gas for the HDS unit.

(2) In both processes approximately the same quantity of CO2 has to be removed; in the conventional CRG-2M processes the whole of the gas stream pases through the C02 removal plant, however, in the process of the invention the CO2 is concentrated into a much smaller gas stream (approx. 60% smaller) of H2 and C02. As a result the size of the CO2 removal plant will be reduced.

(3) As a result of (1) and (2) above, the capital and operating costs of the process of the invention are likely to be lower than those for the conventional CRG-2M processes.

(4) The process of the invention will be simp!erto operate and the time required to bring it on line will be shorter than thatforthe "conventional" SNG processes.

(5) With heavy feedstocks the catalyst performance will be improved by adding the "excess hydrogen" to the CRG reactants.

The embodiment illustrated in Figure 3 is an extension of the CRG-2M process shown in Figure 1 except that a side stream 23 off stream 8 is taken. Stream 23 takes only sufficient product gas to satisfy the hydrogen demand for unit 4 and thus obviates the need for the excess take-off stream 22. Optimally a water separator 24 is incorporated between the separator 15 and the pre-heater 3. The non-permeate stream is returned to the main process train via line 25 and, optionally, line 26.

In the process as illustrated in Figure 3, the recycle gas is fed to the membrane gas separation system. The hydrogen rich permeate stream 2 is compressed (not shown) and mixed with feedstock 1. A reduced volume of gas is required for recycle, thus giving spare feedstock vapourisation capacity, which enables a greater feedstock rate. The remaining recycle offtake in the non-permeate stream 25 is fed to the SNG product stream. If this non-permeate stream 26 is fed to the SNG product stream after the final methanator, (Case B, Table 2), an increase in LPG trim is required for stream 29.If, however, the non-permeate stream 28 is fed to the SNG product stream prior to the final methanator, (Case A, Table 2), no extra LPC trim is required for stream 29. 4 This simple process modification offers several advantages: (1) The capacity of an existing plant using a CRG process to manufacture SNG, can be increased by up to 25%.

(2) The capital outlay required to increase plant capacity is small.

(3) Running costs are low and maintenance is minimal.

TABLE 2 PARAMETER CA SEA CASE B STREAM NO. 628) (26) Feedstock (Ibs/hr) Steam (Ibs/hr) 1 22772 22772 H2 Recycle 5 40974 40974 (Ib moles/hr) 2 60.00 60.00 Gas composition 29 CH4 CO 95.76 93.46 C02 0.19 0.86 H2 2.00 1.86 2.06 3.81

Claims (7)

1. A process for the production of methane-containing gases by the catalytic gasification of hydrocarbon feedstocks in the presence of steam and wherein the feedstock is subjected to catalytic hydrodesulphurisation prior to gasification, characterised in that at least a portion of the product gas containing methane, hydrogen and carbon oxides is subjected to a separation process comprising contacting said portion of product gas with a polymeric membrane separator, said membrane having a permeation factor which is substantially greater for hydrogen than for methane, thereby to produce a methane containing non-permeate stream and a hydrogen-containing permeate stream which is recycled as reactant for the hydrodesulphurisation stage.
2. A process as claimed in Claim 1 wherein the permeate stream also contains carbon dioxide.
3. A process as claimed in Claim 1 or Claim 2 wherein all of the product gas is subjected to membrane separation.
4. A process as claimed in Claim 1 or Claim 2 wherein only a portion of the product stream is subjected to membrane separation and the remainder of the product stream is subjected to at least one further catalytic methanation reaction.
5. A process as claimed in Claim 4 in which the permeate stream is admixed with the remaining product stream to a further methanation reaction.
6. A process for the production of methane-containing gases according to any one of the preceding claims and substantially as herein before described.
7. A methane-containing gas whenever prepared by the process claimed in any one of the preceding claims.
GB08404726A 1984-02-23 1984-02-23 Producing and purifying methane Withdrawn GB2154600A (en)

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Cited By (49)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP0334114A2 (en) * 1988-03-24 1989-09-27 W.R. Grace & Co.-Conn. Membrane process for hydrocarbon liquid recovery
EP0518269A2 (en) * 1991-06-14 1992-12-16 Saibu Gas Co.,Ltd. A process for making high calorie city gas
WO2009007061A1 (en) * 2007-07-10 2009-01-15 Paul Scherrer Institut Process to produce a methane rich gas mixture from gasification derived sulphur containing synthesis gases
CN101981163A (en) * 2008-04-01 2011-02-23 格雷特波因特能源公司 Processes for the separation of methane from a gas stream
US7897126B2 (en) 2007-12-28 2011-03-01 Greatpoint Energy, Inc. Catalytic gasification process with recovery of alkali metal from char
US7901644B2 (en) 2007-12-28 2011-03-08 Greatpoint Energy, Inc. Catalytic gasification process with recovery of alkali metal from char
US7922782B2 (en) 2006-06-01 2011-04-12 Greatpoint Energy, Inc. Catalytic steam gasification process with recovery and recycle of alkali metal compounds
US7926750B2 (en) 2008-02-29 2011-04-19 Greatpoint Energy, Inc. Compactor feeder
US8114176B2 (en) 2005-10-12 2012-02-14 Great Point Energy, Inc. Catalytic steam gasification of petroleum coke to methane
US8114177B2 (en) 2008-02-29 2012-02-14 Greatpoint Energy, Inc. Co-feed of biomass as source of makeup catalysts for catalytic coal gasification
US8123827B2 (en) 2007-12-28 2012-02-28 Greatpoint Energy, Inc. Processes for making syngas-derived products
US8163048B2 (en) 2007-08-02 2012-04-24 Greatpoint Energy, Inc. Catalyst-loaded coal compositions, methods of making and use
US8192716B2 (en) 2008-04-01 2012-06-05 Greatpoint Energy, Inc. Sour shift process for the removal of carbon monoxide from a gas stream
US8202913B2 (en) 2008-10-23 2012-06-19 Greatpoint Energy, Inc. Processes for gasification of a carbonaceous feedstock
US8268899B2 (en) 2009-05-13 2012-09-18 Greatpoint Energy, Inc. Processes for hydromethanation of a carbonaceous feedstock
US8286901B2 (en) 2008-02-29 2012-10-16 Greatpoint Energy, Inc. Coal compositions for catalytic gasification
US8297542B2 (en) 2008-02-29 2012-10-30 Greatpoint Energy, Inc. Coal compositions for catalytic gasification
US8328890B2 (en) 2008-09-19 2012-12-11 Greatpoint Energy, Inc. Processes for gasification of a carbonaceous feedstock
US8349039B2 (en) 2008-02-29 2013-01-08 Greatpoint Energy, Inc. Carbonaceous fines recycle
US8361428B2 (en) 2008-02-29 2013-01-29 Greatpoint Energy, Inc. Reduced carbon footprint steam generation processes
US8366795B2 (en) 2008-02-29 2013-02-05 Greatpoint Energy, Inc. Catalytic gasification particulate compositions
US8479834B2 (en) 2009-10-19 2013-07-09 Greatpoint Energy, Inc. Integrated enhanced oil recovery process
US8479833B2 (en) 2009-10-19 2013-07-09 Greatpoint Energy, Inc. Integrated enhanced oil recovery process
US8502007B2 (en) 2008-09-19 2013-08-06 Greatpoint Energy, Inc. Char methanation catalyst and its use in gasification processes
US8557878B2 (en) 2010-04-26 2013-10-15 Greatpoint Energy, Inc. Hydromethanation of a carbonaceous feedstock with vanadium recovery
US8647402B2 (en) 2008-09-19 2014-02-11 Greatpoint Energy, Inc. Processes for gasification of a carbonaceous feedstock
US8648121B2 (en) 2011-02-23 2014-02-11 Greatpoint Energy, Inc. Hydromethanation of a carbonaceous feedstock with nickel recovery
US8652222B2 (en) 2008-02-29 2014-02-18 Greatpoint Energy, Inc. Biomass compositions for catalytic gasification
US8653149B2 (en) 2010-05-28 2014-02-18 Greatpoint Energy, Inc. Conversion of liquid heavy hydrocarbon feedstocks to gaseous products
US8652696B2 (en) 2010-03-08 2014-02-18 Greatpoint Energy, Inc. Integrated hydromethanation fuel cell power generation
US8669013B2 (en) 2010-02-23 2014-03-11 Greatpoint Energy, Inc. Integrated hydromethanation fuel cell power generation
US8709113B2 (en) 2008-02-29 2014-04-29 Greatpoint Energy, Inc. Steam generation processes utilizing biomass feedstocks
US8728182B2 (en) 2009-05-13 2014-05-20 Greatpoint Energy, Inc. Processes for hydromethanation of a carbonaceous feedstock
US8728183B2 (en) 2009-05-13 2014-05-20 Greatpoint Energy, Inc. Processes for hydromethanation of a carbonaceous feedstock
US8734547B2 (en) 2008-12-30 2014-05-27 Greatpoint Energy, Inc. Processes for preparing a catalyzed carbonaceous particulate
US8734548B2 (en) 2008-12-30 2014-05-27 Greatpoint Energy, Inc. Processes for preparing a catalyzed coal particulate
US8733459B2 (en) 2009-12-17 2014-05-27 Greatpoint Energy, Inc. Integrated enhanced oil recovery process
US8748687B2 (en) 2010-08-18 2014-06-10 Greatpoint Energy, Inc. Hydromethanation of a carbonaceous feedstock
US9012524B2 (en) 2011-10-06 2015-04-21 Greatpoint Energy, Inc. Hydromethanation of a carbonaceous feedstock
US9034058B2 (en) 2012-10-01 2015-05-19 Greatpoint Energy, Inc. Agglomerated particulate low-rank coal feedstock and uses thereof
US9034061B2 (en) 2012-10-01 2015-05-19 Greatpoint Energy, Inc. Agglomerated particulate low-rank coal feedstock and uses thereof
US9127221B2 (en) 2011-06-03 2015-09-08 Greatpoint Energy, Inc. Hydromethanation of a carbonaceous feedstock
US9234149B2 (en) 2007-12-28 2016-01-12 Greatpoint Energy, Inc. Steam generating slurry gasifier for the catalytic gasification of a carbonaceous feedstock
US9273260B2 (en) 2012-10-01 2016-03-01 Greatpoint Energy, Inc. Agglomerated particulate low-rank coal feedstock and uses thereof
US9328920B2 (en) 2012-10-01 2016-05-03 Greatpoint Energy, Inc. Use of contaminated low-rank coal for combustion
US9353322B2 (en) 2010-11-01 2016-05-31 Greatpoint Energy, Inc. Hydromethanation of a carbonaceous feedstock
US10344231B1 (en) 2018-10-26 2019-07-09 Greatpoint Energy, Inc. Hydromethanation of a carbonaceous feedstock with improved carbon utilization
US10435637B1 (en) 2018-12-18 2019-10-08 Greatpoint Energy, Inc. Hydromethanation of a carbonaceous feedstock with improved carbon utilization and power generation
US10464872B1 (en) 2018-07-31 2019-11-05 Greatpoint Energy, Inc. Catalytic gasification to produce methanol

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Cited By (53)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP0334114A2 (en) * 1988-03-24 1989-09-27 W.R. Grace & Co.-Conn. Membrane process for hydrocarbon liquid recovery
EP0334114A3 (en) * 1988-03-24 1990-02-07 W.R. Grace & Co.-Conn. Membrane process for hydrocarbon liquid recovery
EP0518269A2 (en) * 1991-06-14 1992-12-16 Saibu Gas Co.,Ltd. A process for making high calorie city gas
EP0518269A3 (en) * 1991-06-14 1993-05-12 Saibu Gas Co.,Ltd. A process for making high calorie city gas
US8114176B2 (en) 2005-10-12 2012-02-14 Great Point Energy, Inc. Catalytic steam gasification of petroleum coke to methane
US7922782B2 (en) 2006-06-01 2011-04-12 Greatpoint Energy, Inc. Catalytic steam gasification process with recovery and recycle of alkali metal compounds
WO2009007061A1 (en) * 2007-07-10 2009-01-15 Paul Scherrer Institut Process to produce a methane rich gas mixture from gasification derived sulphur containing synthesis gases
US8163048B2 (en) 2007-08-02 2012-04-24 Greatpoint Energy, Inc. Catalyst-loaded coal compositions, methods of making and use
US9234149B2 (en) 2007-12-28 2016-01-12 Greatpoint Energy, Inc. Steam generating slurry gasifier for the catalytic gasification of a carbonaceous feedstock
US8123827B2 (en) 2007-12-28 2012-02-28 Greatpoint Energy, Inc. Processes for making syngas-derived products
US7901644B2 (en) 2007-12-28 2011-03-08 Greatpoint Energy, Inc. Catalytic gasification process with recovery of alkali metal from char
US7897126B2 (en) 2007-12-28 2011-03-01 Greatpoint Energy, Inc. Catalytic gasification process with recovery of alkali metal from char
US8114177B2 (en) 2008-02-29 2012-02-14 Greatpoint Energy, Inc. Co-feed of biomass as source of makeup catalysts for catalytic coal gasification
US7926750B2 (en) 2008-02-29 2011-04-19 Greatpoint Energy, Inc. Compactor feeder
US8349039B2 (en) 2008-02-29 2013-01-08 Greatpoint Energy, Inc. Carbonaceous fines recycle
US8652222B2 (en) 2008-02-29 2014-02-18 Greatpoint Energy, Inc. Biomass compositions for catalytic gasification
US8709113B2 (en) 2008-02-29 2014-04-29 Greatpoint Energy, Inc. Steam generation processes utilizing biomass feedstocks
US8286901B2 (en) 2008-02-29 2012-10-16 Greatpoint Energy, Inc. Coal compositions for catalytic gasification
US8297542B2 (en) 2008-02-29 2012-10-30 Greatpoint Energy, Inc. Coal compositions for catalytic gasification
US8361428B2 (en) 2008-02-29 2013-01-29 Greatpoint Energy, Inc. Reduced carbon footprint steam generation processes
US8366795B2 (en) 2008-02-29 2013-02-05 Greatpoint Energy, Inc. Catalytic gasification particulate compositions
CN101981163A (en) * 2008-04-01 2011-02-23 格雷特波因特能源公司 Processes for the separation of methane from a gas stream
US8192716B2 (en) 2008-04-01 2012-06-05 Greatpoint Energy, Inc. Sour shift process for the removal of carbon monoxide from a gas stream
CN101981163B (en) * 2008-04-01 2014-04-16 格雷特波因特能源公司 Processes for the separation of methane from a gas stream
US8999020B2 (en) 2008-04-01 2015-04-07 Greatpoint Energy, Inc. Processes for the separation of methane from a gas stream
US8502007B2 (en) 2008-09-19 2013-08-06 Greatpoint Energy, Inc. Char methanation catalyst and its use in gasification processes
US8647402B2 (en) 2008-09-19 2014-02-11 Greatpoint Energy, Inc. Processes for gasification of a carbonaceous feedstock
US8328890B2 (en) 2008-09-19 2012-12-11 Greatpoint Energy, Inc. Processes for gasification of a carbonaceous feedstock
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