Field of the Invention The invention relates to a process for producing liquid biofuel from solid biomass. In the process, raw synthesis gas is produced by gasifying the solid biomass and the raw synthesis gas is post processed to produce biofuel.

Background of the Invention

Liquid fuels are commonly used in many areas of human life including heating, transportation, and producing electricity. Liquid fuels are often made of fossile oil containing substances by distillation and cracking. However, sustainable energy sources have received a lot of interest in recent years due to mid- to long-term supply security and environmental changes — observed or predicted — such as global warming. One possibility to use liquid fuels and answer the environmental issues is to produce liquid fuels from biomass. Gasification is a promising process for converting solid biomass to gaseous or liquid fuel. In gasification, solid biomass is first converted to a raw synthesis gas, which can be further processed to produce liquid fuel or gaseous fuel or both liquid and gaseous fuels. The gasification is done at an elevated temperature, e.g. 850 °C. The synthesis gas thus produced typically comprises tars and methane. Both tars and methane influence the possibilities of utilizing the synthesis gas, and therefore, their content may be reduced by reforming. In reforming the (raw) synthesis gas, oxygen, steam, and (raw) synthesis gas are reacted at elevated temperature. In the process, the synthesis gas may be further conditioned, and conveyed to a Fischer- Tropsch (FT) synthesis process to produce liquid biofuel.

The biomass feedstock may be heterogeneous, thus the chemical composition of the feedstock may vary with both, the plant location and time. This may be taken into account by choosing catalysts used in the process according to the type of the biomass used in a given location. In addition, some chemicals may be added to the process to take into account the type of the biomass. These aspects diminish the versatility of the process. Moreover, adding chemical to the process may need some kind of dosing system, which on the other hand increases the investment costs and may also increase the complexity of process operation.

Summary of the Invention

A method for producing liquid fuel from solid biomass is disclosed. In the method, raw synthesis gas is produced from biomass by gasification. The process is simplified and provides more versatility towards erratically changing sulfur content of biomass feedstock by removing at least part of sulfur comprised in the synthesis gas before conveying the synthesis gas to gas shift, wherein in the gas shift the ratio of hydrogen to carbon monoxide is adjusted. The ratio of hydrogen to carbon monoxide is adjusted by dividing the synthesis gas to two parts, wherein the first part is allowed to react in presence of catalysts thereby adjusting the hydrogen to carbon monoxide ratio towards an equilibrium, and letting a second part to bypass the reactions. An embodiment of the method for producing liquid biofuel from biomass comprises gasifying the biomass at an elevated temperature to produce raw synthesis gas and post processing at least part of the raw synthesis gas to the liquid biofuel. The embodiment further comprises removing at least part of sulfur from synthesis gas to produce treated synthesis gas. The embodi- ment further comprises converting carbon monoxide (CO) of at least part of treated synthesis gas and steam to hydrogen (H ₂ ) and carbon dioxide (CO ₂ ) to produce shifted synthesis gas with an adjusted molar ratio of hydrogen (H2) to carbon monoxide (CO). In an embodiment, the sulfur content of the feedstock varies in time. In an embodiment, the sulfur is at most 140 ppmwt at a first instance of time and at least 350 ppmwt at a second instance of time.

Due to the feedstock, in an embodiment, the sulfur content of the raw synthesis gas varies in time. In an embodiment, the sulfur content of the raw synthesis gas at a fourth instance of time is at least three times the sulfur content of the raw synthesis gas at a third instance of time

Because of the sulfur removal, even if the sulfur content of the feedstock and/or the raw synthesis gas varies in time, in an embodiment, the sulfur content of the treated synthesis gas is at least essentially constant in time.

In an embodiment, a catalyst selected from the group of high temperature water gas shift catalysts, the group of high temperature water gas shift catalysts comprising Fe3O ₄ and Cr ₂ O3, is used. Furthermore, in the embodiment, the sulfur content of the treated synthesis gas is at most 100 ppmv. In the embodiment, the gas hourly space velocity (GHSV) may be is at least 1000 h ^~1 . In an embodiment, a catalyst selected from the group of low temperature water gas shift catalysts, the group of low temperature water gas shift catalysts comprising the group of low temperature water gas shift catalysts comprising CuO and ZnO, is used. Furthermore, in the embodiment, the sulfur content of the treated synthesis gas is at most 1 ppmv. In the embodi- ment, the gas hourly space velocity (GHSV) may be is at least 3000 h ^~1 .

In an embodiment, methanol is used to remove at least part of sulfur from synthesis gas. These and other features of the method are disclosed in the appended claims 1 -17.

A system for producing liquid biofuel from biomass, is also disclosed. An embodiment of the system comprises a gasification reactor for gasifying biomass at an elevated temperature to produce raw synthesis gas and a post processing system arranged to produce the liquid biofuel from the raw synthesis gas. The embodiment further comprise a sulfur removal unit, a gas shifter, and means for conveying at least part of treated synthesis gas from the sulfur removal unit to the gas shifter. This and other features of the system are disclosed in the appended claims 18-31 .

Description of the Drawings

Figure 1 a shows a process for producing biofuel from biomass,

Figure 1 b shows more details of the process of Fig. 1 a, Figure 2a shows phases of the conditioning process of Fig. 1 b, wherein a clean reformer is used,

Figure 2b shows phases of the conditioning process of Fig. 1 b, wherein a dirty reformer is used,

Figure 3a shows a process of gasifying biomass to produce raw synthesis gas in a process for producing liquid biofuel from solid biomass,

Figure 3b shows quenching, filtration, reforming, and cooling of synthesis gas or raw synthesis gas in a process for producing liquid biofuel from solid biomass,

Figure 3c shows compression, sulfur removal, synthesis gas shifting, CO2 removal, and subsequent process steps in a process for producing liquid biofuel from solid biomass, wherein a physical wash is used,

Figure 3d shows sulfur removal, synthesis gas shifting, compression, CO2 removal, and subsequent process steps in a process for producing liquid biofuel from solid biomass, wherein a chemical wash is used,

Figures 4a-4c

show utilizing pressurized steam in a process for producing liquid biofuel from solid biomass, Figure 5 shows two gasification plants, each comprising a gasifier, and each gasification plant using a common post-processing plant to upgrade scrubbed synthesis gas from both gasification plants.

Detailed Description of the Invention

Gasification is a promising process for converting solid biomass to liquid and/or gaseous fuel. In gasification, solid biomass is converted to raw synthesis gas, which can be further processed to produce liquid fuel or gaseous fuel or both liquid and gaseous fuels.

The term "biomass material" refers to plant biomass that is composed of cellulose and hemicellulose, and lignin. Biomass comes in many different types, which may be grouped into four main categories: wood and wood residues, including sawmill and paper mill discards, municipal paper waste, agricultural residues, including corn stover (stalks and straw) and sugarcane bagasse, and dedicated energy crops, which are mostly composed of tall, woody grasses.

The biomass is typically selected from virgin and waste materials of plant, animal and/or fish origin, such as municipal waste, industrial waste or byproducts, agricultural waste or by-products (including also dung), virgin wood, waste, residues or by-products of the wood-processing industry, waste or by- products of the food industry, and combinations thereof. The biomass material is preferably selected from non-edible resources such as non-edible wastes and non-edible plant materials. A preferred biomass material comprises waste and by products of the wood-processing industry such as slash, urban wood waste, lumber waste, wood chips, wood waste, sawdust, straw, firewood, wood materials, paper, by-products of the papermaking or timber processes, etc.

Referring to Fig. 1 a, the process comprises gasifying solid biomass to raw synthesis gas and post processing the raw synthesis gas to biofuel. Referring to Fig. 1 b, the post processing comprises conditioning the raw synthesis gas to a product gas, Fischer-Tropsch processing the product gas to product fluid, and upgrading the product fluid to biofuel.

For the Fischer-Tropsch synthesis the molar ratio of hydrogen (H ₂ ) to carbon monoxide (CO), H ₂ :CO ratio, should be in a specified range. The H ₂ :CO ratio of synthesis gas derived from biomass by gasification is usually too low in hydrogen with respect to the requirements dictated by the Fischer-Tropsch synthesis. For that, the H ₂ :CO ratio is usually modified by applying a gas shift. In addition to the gas shift, part of the synthesis gas may bypass the gas shift to control the H ₂ :CO ratio. Gas shift is done by allowing the synthesis gas (or a part thereof) to react in presence of catalyst and at an elevated temperature and pressure (more details to be given later). These catalyst are sensitive to sulfur; some catalysts do not work in the presence of sulfur, some need a specific amount of sulfur to be functional.

The sulfur content of the biomass feedstock depends on the type of biomass. The sulfur content of the biomass feedstock may range from 100-600 mg/kg for wood and on dry basis. Generally the unit mg/kg in dry basis is referred to as ppmwt db, i.e. parts per million in weight on dry basis. Sulfur content on dry basis, on the other hand, here means the sulfur content of the biomass, wherein water has been removed from the biomass.

Examples of sulfur content of some typical wooden feedstock materials include approximately 100 ppmwt db for stumps; 200 ppmwt db low sulfur forest residues; 200 ppmwt db for softwood; 380 ppmwt db for brown logging residues, 400 ppmwt db for hardwood; 400 ppmwt db for bark; and 510 ppmwt db for some green logging residues. For some other materials the sulfur content may be 1400 ppmwt db for sunflower stover; 1650 ppmwt db for straw, and 2700 ppmwt db for rapeseed stover. These values are approximate values, an may be used as guidelines for desing.

The sulfur level in woody biomass derived raw synthesis gas can vary between 10 ppmv (parts per million by volume) and 300 ppmv. As the volume of gaseous compounds is related to the molar amount, in gases ppmv also describes the molar fraction of a compound. The sensitivity of the catalysts to sulfur is taken into account in the process. In an embodiment, the sensitivity of the catalysts to sulfur is taken into account by removing at least part of the sulfur comprised in the synthesis gas before the gas shift. Preferably, the sulfur content of the synthesis gas is reduced a to a great extent before the gas shift. Typical values for the sulfur reduction will be given below. In an embodiment, the sulfur content of synthesis gas after sulfur removal is in the range from 1 ppbv (parts per billion, 10 ^"9 by volume) to 1 ppmv.ln another embodiment, the sulfur content of synthesis gas after sulfur removal is at most 100 ppmv. In another embodiment, the sulfur content of synthesis gas after sulfur removal is at most 1 ppmv.

As discussed above, the sulfur content of the biomass feedstock may vary. This means that an embodiment of the method comprises gasifying the biomass 100 to produce raw synthesis gas 200 at two instances of time, wherein at the first instance of time, the sulfur content of the biomass equals a first sulfur content, and at the second instance of time, the sulfur content of the biomass equals a second sulfur content, wherein the second sulfur content is different from the first sulfur content. Without loss of generality, the instances of time may be ordered such that the first sulfur content is smaller than the second sulfur content.

Depending on the feedstock, the first sulfur content may be at most one of:

- 140 ppmwt db, e.g. when the feedstock comprises stumps;

- 250 ppmwt db, e.g. when the feedstock comprises at least one of stumps, low sulfur forest residues, and softwood;

- 440 ppmwt db, e.g. when the feedstock comprises at least one of stumps, brown logging residues, softwood, hardwood, and bark; and

- 550 ppmwt db, e.g. when the feedstock comprises at least one of stumps, forest residues, softwood, hardwood, bark, and green logging residues. Depending on the feedstock, the second sulfur content may be at least one of:

- 1300 ppmwt db, e.g. when the feedstock comprises at least one of sunflower stover, straw, and rapeseed stover;

- 460 ppmwt db, when the feedstock comprises at least one of sunflower stover, straw, rapeseed stover, and green logging residues, - 350 ppmwt db, when the feedstock comprises at least one of sunflower stover, straw, rapeseed stover, bark, hardwood, and brown logging residues;

- 160 ppmwt db, when the feedstock comprises at least one of sunflower stover, straw, rapeseed stover, bark, hardwood, softwood, and forest residues.

In an embodiment, the feedstock comprises stumps and at least one of forest residues and softwood, whereby the first sulfur content is at most 140 ppmwt db and the second sulfur content is at least 160 ppmwt db.

In an embodiment, the feedstock comprises stumps and at least one of hardwood and bark, whereby the first sulfur content is at most 140 ppmwt db and the second sulfur content is at least 350 ppmwt db.

As discussed above, the sulfur content of the biomass feedstock may vary, whereby the sulfur level in biomass derived raw synthesis gas may also vary. In an embodiment, the process is a continuous process, whereby the process is carried out at (at least) two instances of time. At the first instance of time, the sulfur level in biomass derived raw synthesis gas may equal a first sulfur content. At the second instance of time, the sulfur level in biomass derived raw synthesis gas may equal a second sulfur content, wherein the second sulfur content is different from the first sulfur content. The instances may be selected such that the second sulfur content is greater than the first sulfur content. The process is applicable even if the second sulfur content differs a lot from the first sulfur content. The ratio of the second sulfur content of the raw synthesis gas to the first sulfur content of the raw synthesis gas may depend on the sulfur content of the feedstock. In case the feedstock consists of wood-based biomass, the first and the second sulfur contents may be e.g. one of the following

(50 ppmv, 150 ppmv), respectively, whereby the ratio is 3;

(40 ppmv, 180 ppmv), respectively, whereby the ratio is 4.5;

(40 ppmv, 200 ppmv), respectively, whereby the ratio is 5; and

(30 ppmv, 210 ppmv), respectively, whereby the ratio is 7. The method is applicable in all these cases. Moreover, the method is applicable even if the feedstock comprises sulfur rich components (e.g. stover or straw as discussed above). In this case, the first and second sulfur contents may be e.g. one of the following

(40 ppmv, 1000 ppmv), respectively, whereby the ratio is 25; and

(30 ppmv, 1000 ppmv), respectively, whereby the ratio is 33;

The ratio of the second sulfur content of the raw synthesis gas to the first sulfur content of the raw synthesis gas may thus be at least 3. The ratio may be e.g. from 3 to 33. Preferably, wood is used as the feedstock, whereby the ratio is from 3 to 7. Even more preferably the sulfur content of the raw synthesis gas may vary between about 40 ppmv and about 180 ppmv; whereby the ratio may be from 4 to 5. In the embodiments shown in Figs. 2a and 2b, at least part of sulfur is removed from the synthesis gas before the water gas shift. Synthesis gas after the sulfur removal is referred to as "treated synthesis gas", in contrast to "sour synthesis gas", wherein sulfur makes the synthesis gas sour. Figs. 2a and 2b show embodiments of the phase "conditioning", as shown in Fig. 1 b. Raw synthesis gas is produced by gasification, in a gasifier, at an elevated temperature. As for the terminology, in the text and the claims, the term "raw synthesis gas" refers to the raw synthesis gas as produced by gasification. The term "synthesis gas" may refer to the raw synthesis gas or processed synthesis gas, i.e. the intermediate product having been produced by applying at least one process step to the raw synthesis gas. Other related terms such as "scrubbed synthesis gas" or "reformed synthesis gas" refer to the synthesis gas after a specific process step. The step "compressing", shown in Figs. 2a and 2b, has some beneficial effects, as will be discussed later.

The conditioning of the synthesis gas comprises

- removing at least part of sulfur from synthesis gas to produce treated synthesis gas, and

- allowing at least part of the treated synthesis gas to react in the presence of catalysts, at an elevated temperature and elevated pressure, thereby adjusting the molar ratio of hydrogen (H ₂ ) to carbon monoxide (CO) of the treated synthesis gas, to produce shifted synthesis gas.

The conditioning may further comprise at least one of

- reforming synthesis gas (possibly raw synthesis gas) to decrease the amount of tars and methane in the synthesis gas,

- compressing the synthesis gas to increase the pressure of the synthesis gas before removing sulfur,

- dividing treated synthesis gas to two parts, converting in a shift reactor carbon monoxide (CO) of only the first part of the treated synthesis gas and steam to hydrogen (H ₂ ) and carbon dioxide (CO ₂ ), letting the second part to bypass the shift reactor, and combining the first and the second parts to produce shifted synthesis gas with an adjusted molar ratio of hydrogen (H ₂ ) to carbon monoxide (CO),

- removing carbon dioxide from shifted synthesis gas, and

- producing intermediate pressure steam and utilizing intermediate pressure steam in adjusting the molar ratio of hydrogen (H ₂ ) to carbon monoxide (CO) of the treated synthesis gas. The whole post processing, as depicted in Fig. 1 a, may thus comprise

- the conditioning phase, wherein product gas is produced,

- Fischer-Tropsch (FT) processing of the product gas to produce a product fluid, and

- upgrading the product fluid to produce the biofuel, e.g. by means of at least one of hydroprocessing and fractionating.

The process for producing liquid biofuel from biomass will be described in more detail with reference to Figs. 3a-3d. Referring to Fig. 3a, biomass 100, e.g. wood based biomass is stored in a container 102. The container is located in normal atmosphere and therefore the container 102 contains typically air and the biomass 100. Air on the other hand comprises nitrogen. From the container 102 biomass is fed using a lock hopper mechanism to another container 108. The lock hopper mechanism is used to remove nitrogen from the biomass-air mixture, since the presence of nitrogen has some disadvantages in the later process steps. The lock hopper mechanism comprises two air lock valves 104 and a third container 106. Biomass-air mixture is first fed to the container 106. At least some air is removed from the container by feeding carbon dioxide (CO ₂ ) 120 to the container 106. Carbon dioxide replaces at least some of the air in the container 106 and may also be used to pressurize the container 106. The biomass-air-CO ₂ mixture is then fed to the container 108. Carbon dioxide 120 may be used also in the container 108 for pressurization and to remove air from the container 108 From the container 108 biomass 100 is fed with a feeding screw 135 to a gasification reactor 150. The gasification reactor is a fluidized bed reactor. In addition to biomass 100, bed material 130 is fed to the gasification reactor 150. Bed material 130 is fed to the process from a container 132 using the feeding screw 135. The bed material 130 may comprise at least one of kaolin and dolomite. Preferably the bed material 130 comprises dolomite, since this reduces the tar content of the raw synthesis gas 200. More preferable the bed material consists essentially of dolomite.

The gasification reactor 150 is a fluidized bed reactor. The fluidized bed reactor comprises means for forming a fluidized bed of biomass 100 and bed material 130. The means may comprise nozzles through which fluidizing gases are fed to the reactor from below. Biomass 100 and bed material 130 are arranged in a fluidized state by feeding oxygen 140 and steam 142 to the gasification reactor 150. Oxygen is fed to the reactor in order to facilitate burning of some of the biomass. Burning releases energy from the biomass 100 and thus heats the gasification reactor 150 and the material in the reactor. The temperature in the gasification reactor 150 may be e.g. about 850 °C. The gasification reactor may be pressurized. The (absolute) pressure in the gasification reactor may be e.g. 10 bar. Steam 142 (H ₂ O) is fed to the process to increase the hydrogen (H ₂ ) content in the gasification reactor and for later process steps. As the raw synthesis gas 200 will be conveyed later to a reformer 240 and eventually fed into a FT -process, the hydrogen (H ₂ ) and carbon monoxide (CO) content of the raw synthesis gas 200 is increased already in the gasification reactor 150 by fluidizing the bed material 130 and the biomass 100 in the reactor 150 using both steam 142 and oxygen 140 as the fluidizing medium. Only small amounts of oxygen is used on one hand to facilitate burning and on the other hand to facilitate the formation of raw synthesis gas 200.

Bottom ash 155 is removed from the gasification reactor 150. Bottom ash 155 comprises ash (burned biomass), impurities (such as stones or metal pieces), and bed material 130. Raw synthesis gas 200 is led from the gasification reactor 150 through a cyclone 160. Cyclone 160 separates raw synthesis gas 200 from solid materials such as bed material, ash (burned biomass), and biomass. Solid material is fed back to the gasification reactor through the channel 165. Raw synthesis gas 200 is conveyed to subsequent process steps. Solid material is removed from the raw synthesis gas in the cyclone 160 to clean the raw synthesis gas 200 before filtration, at least to some degree. As described in Figs. 2a and 2b, the raw synthesis gas may be cleaned from solid particles before or after reforming the synthesis gas. If the raw synthesis gas is not cleaned before reforming, as shown in Fig. 2b, the reforming is referred to as "dirty reforming". If the raw synthesis gas is cleaned before reforming, as shown in Fig. 2a, the reforming is referred to as "clean reforming". In the following, only an embodiment comprising clean reforming will be presented in detail. Based on this description, an embodiment comprising dirty reforming is obvious to a person skilled in the art

The embodiment comprising clean reforming is depicted in Fig. 3b. In Fig. 3b raw synthesis gas 200 is filtered in a filtration unit 220 and reformed in a (clean) reformer 240. As the temperature of the raw synthesis gas 200 after the gasification reactor 150 is relatively high, e.g. 850 °C, the raw synthesis gas 200 may be cooled before filtration. Raw synthesis gas is cooled in a cooling device 218. In the embodiment of Fig. 3b, the cooling device 218 comprises a quencher 210. In the quencher 210, the synthesis gas is cooled by spraying quenching liquid 215, such as water, onto the raw synthesis gas. In the embodiment, quenched synthesis gas is cooled also by mixing recycled gas 205 to the quenched synthesis gas in the gas mixer 212. The recycled gas 205 comprises only scrubbed synthesis gases (360, 364, Fig 3c) or at least one of: a part 364 of scrubbed synthesis gas 360 (Fig. 3c), tail gas 387 of a CO2 removal phase (Fig. 3c), FT tail gas 395 (Fig. 3c), and off gas 410 (Fig. 3c), as will be discussed in more detail later. The temperature of the recycled gas 205 is much lower than the temperature of the synthesis gas. E.g. the temperature of scrubbed synthesis gas may be in the range of 30 - 150 °C. Even if not depicted in Fig. 3b, recycled gas 205 may be mixed with synthesis gas (raw or quenched) before or after the quencher 210. Synthesis gas may be cooled only by mixing recycled gas, only by quenching, or both by quenching and mixing recycled gas, the last option shown in Fig. 3b. In one embodiment the recycled gas comprises 205 only scrubbed synthesis gas 364; and recycled FT tail gas 395 is introduced into the gasifier 150. In another embodiment the synthesis gas is cooled only by water quenching and recycled FT tail gas 395 is introduced into the gasifier 150.

In case a dirty reformer is used, the raw synthesis gas 200 is conveyed from a gasifier 150 to a reformer without filtering, cooling, cleaning, or quenching.

From the filtration unit 220 the filtered synthesis gas is led to a reformer 240. After the filtration unit 220, the temperature of the filtered synthesis gas may be below 800 °C and as an example 700 °C. However, reforming of synthesis gas is performed at a higher temperature. For example the temperature in the reformer 240 may be between 900 - 950°C. To increase the temperature of the filtered synthesis gas in the reformer 240, part of the synthesis gas is burned in the reformer 240. To facilitate burning, oxygen 230 (O ₂ ), is fed to the reformer 240. Moreover, to increase the hydrogen content in the reformed synthesis gas and to prevent carbon formation on the reformer catalyst and thus facilitate the reforming process, steam 232 (H ₂ O) is fed to the reformer 240. Filtered synthesis gas is reformed in the reformer 240 to decrease the amount of tars and methane in the filtered synthesis gas. Furthermore, the filtered synthesis gas is reformed to reformed synthesis gas. It is noted, that at elevated temperatures steam (H ₂ O) and carbon monoxide (CO) may react to produce carbon dioxide (CO ₂ ) and hydrogen (H ₂ ). Still further, in the reformer 240, the tar and methane of the synthesis gas will catalytically react with steam to produce carbon monoxide and hydrogen. From the reformer 240 the reformed synthesis gas is led to a heat exchanger 250. In the heat exchanger 250, the reformed synthesis gas is cooled, and the heat of the reformed synthesis gas is recovered to a fluid. The fluid may comprise at least one of water and steam. As an example, in Fig. 3b water 252 is fed to the heat exchanger 250, and in the heat exchanger 250, the water 252 is evaporated to produce steam 254. Steam 254 is used for at least one of generating electric power and adjusting the molar ratio of hydrogen (H ₂ ) to carbon monoxide (CO) of a treated synthesis gas. Steam 254 may be superheated i.e. heated above the saturation temperature. The pressure of the steam 254 may be in the range 20 - 120 bar. In the heat exchanger 250, the reformed synthesis gas is cooled to cooled synthesis gas 300. The temperature of the cooled synthesis gas may be e.g. 150 - 350 °C.

The steam 254 from the heat exchanger 250 may have a high pressure or an intermediate pressure. The terms for pressures generally used in connection with steam boilers are:

- high pressure steam (from 80 bar to 120 bar),

- medium pressure steam (from 12 bar to 20 bar), and

- low pressure steam (at most about 12 bar).

In addition, in some embodiments of the invention, intermediate pressure steam is used. The intermediate pressure steam has a pressure from 20 bar to 80 bar. The high pressure steam is commonly utilized to produce electricity.

Referring to Fib. 2b, in case the conditioning comprises dirty reforming, after the dirty reforming the reformed synthesis gas is cooled, cleaned, and scrubbed. As in case of a clean reformer, the "cleaning" may refer to filtering of synthesis gas. In contrast to clean reforming, a quenching step is not needed in dirty reforming, since the synthesis gases are cleaned or filtered only after cooling.

Referring to Fig. 3c, the cooled synthesis gas 300 is conveyed to a scrubber 320. The scrubber 320 comprises two scrubbing stages, a first stage 330 and a second stage 340. In the first stage 330, a (first) scrubbing solution (331 , 332) is circulated. The scrubbing solution 331 is led from the first stage 330 to a heat exchanger 335, after which the cooled scrubbing solution 332 is led to the first stage 330. The circulation of the scrubbing solution may be enabled with a pump (not shown in the figure). The cooled scrubbing solution 332 is sprayed onto the cooled synthesis gas to scrub and further cool down the cooled synthesis gas. In the scrubber 320, the scrubbing solution is essentially in liquid form to ensure scrubbing.

The (first) scrubbing solution (331 , 332) comprises water. The scrubbing solution may consist of water or it may consist essentially of water. As the scrubbing solution is cooled in the heat exchanger 335, heat is recovered from the scrubbing solution. A cool heat transfer medium 336 is fed to the heat exchanger 335 where it heats to a heated heat transfer medium 337. The heat transfer medium may comprise water. The recovered heat may be used to dry biomass 100. To dry biomass, the heated heat transfer medium 337 may be conveyed to the container 102 (Fig. 3a), where the biomass is stored. Respectively, the cooled heat transfer medium 336 may be conveyed from the container 102 (Fig. 3a) to the heat exchanger 335. Even if not shown in Fig. 3c, the system may comprise means for conveying the heated heat transfer medium 337 from the heat exchanger 335 to a dryer 550 (cf. Fig. 4a) to dry the biomass. Even if not shown in Fig. 3c, the system may comprise means for conveying the cooled heat transfer medium 336 from a dryer 550 (cf. Fig. 4a) to the heat exchanger 335. The container 102 may receive dried biomass. The dryer 550 may be located near the container 102. Alternatively, the container 102 may be used as the dryer 550 for biomass. Alternatively, The system may comprise means for conveying the dried biomass from the dryer 550 to the container 102.

In the second stage 340 of the scrubber 320, a second scrubbing solution (341 , 342) is circulated. The second scrubbing solution 341 is led from the second stage 340 to a heat exchanger 345, after which the cooled second scrubbing solution 342 is led to the second stage 340. The second scrubbing solution is sprayed onto the synthesis gas to scrub the synthesis gas. In the scrubber 320, the second scrubbing solution is essentially in liquid form to ensure scrubbing. The circulation of the second scrubbing solution may be enabled with a pump (not shown in the figure). The second scrubbing solution comprises water. The second scrubbing solution may consist of water or it may consist essentially of water. The first scrubbing solution may be used as the second scrubbing solution. As the second scrubbing solution is cooled in the heat exchanger 345, heat is recovered from the second scrubbing solution. A cool heat transfer medium 346 is fed to the heat exchanger 345 where it heats to a heated heat transfer medium 347. The heat transfer medium may comprise water. The temperature of the heated heat transfer medium 347 may be e.g. 60 °C. From the scrubber 320 condensed scrubbing solution, i.e. condensate 350, is led out. Condensate 350 is treated as liquid waste and fed to a waste water treatment plant. In the scrubber 320 cooled synthesis gas 300 is scrubbed to scrubbed synthesis gas 360. In the scrubber 320, dust, gaseous metals (e.g. alkali), NH ₃ and HCI are mostly removed from the synthesis gas.

After the scrubber 320, at least part of the scrubbed synthesis gas 360 is conveyed to phases that may be performed under an intermediate pressure, e.g. a pressure in the range from 30 to 40 bar. To increase the pressure, the scrubbed synthesis gas 360 may be conveyed to a compressor 450. It is noted that the pressure before the compressor may be in the range from 1 to 15 bar, e.g. about 10 bar. Furthermore, the location of the compressor 450 may depend on the subsequent steps, as will be discussed in more detail with reference to Figs. 3c and 3d. From the compressor 450 (Fig. 3c), or the scrubber (Fig. 3d), the scrubbed synthesis gas is conveyed to a sulfur removal unit 460. The sulfur removal unit may be e.g. a physical wash unit or a chemical wash unit or sulfur may be removed via a solid adsorbent. In the sulfur removal unit 460, at least part of sulfur is removed from the synthesis gas whereby treated synthesis gas 470 is produced. The process produces also a sulfur rich side product 462. In a physical wash, the side product 462 may comprise sulfur in the form of hydrogen sulfide (H ₂ S) or carbonyl sulfide (COS). In addition, the side product may comprise carbon dioxide (CO ₂ ). In a chemical wash, the side product 462 may comprise sulfur in the form of at least one of hyrdrogen sulfide (H ₂ S), carbonyl sulfide (COS). If a solid adsorbent is used, the side product may comprise at least one of zinc sulfide (ZnS), nickel sulfide (NiS), and a mixture or compound of zinc sulfide and copper sulfide (ZnS/CuS). The sulfur rich side product 462 may be conveyed to an adjacent burner 463 such as a boiler. The side product 462 may incinerated in the burner 463. Sulfur may be removed selectively (by removing sulfur and not removing simultaneously carbon dioxide) or sulfur may be removed non-selectively (by removing sulfur and simultaneously removing also carbon dioxide). The selectivity will be discussed in more detail later.

Sulfur removal may be achieved using at least one of the following

- a physical wash process, known e.g. by the trade names Rectisol®, Purisol®, and Selexol®,

- an adsorbent bed arranged to adsorb sulfur from the synthesis gas.

The adsorbent may comprise at least one of zinc oxide (ZnO), copper and zinc oxide (Cu/ZnO), nickel (Ni) containing adsorbents and activate charcoal, and

- a chemical wash process (amine gas treating using e.g. MEA, DEA, MDEA, D I PA or DGA®).

In case a physical wash is used, the compressor 450 is located before the physical wash (Fig. 3c). The physical wash process removes sulfur, but also other typical synthesis gas impurities. The physical wash process uses a solvent to separate acid gases such as hydrogen sulfide (H ₂ S) from synthesis gas. In the process, cold solvent at a low temperature dissolves (i.e. absorbs) the acid gases from the synthesis gas at relatively high pressure. The rich solvent containing the acid gases is then let down in pressure to release and recover the acid gases, such as hydrogen sulfide. In the rectisol® process, methanol is used as the solvent. The low temperature in the absorber may be e.g. from -70 °C to 0 °C, preferably from -40 °C to -30 °C. In the selexol® process, the solvent is a mixture of the dimethyl ethers of polyethylene glycol (DEPG). Absorber temperatures from -18 °C to 10 °C may be applicable, while the pressure may be in the range from 20 to 140 bar. Typically the solvent is refrigerated to e.g. 0 to 10 °C, whereby the solubility of sulfur is increased. In the purisol® process, N-Methyl-2- Pyrrolidone (NMP), is used as the solvent. In the purisol® process the temperature may be from -15 °C to ambient. Typical pressures for the purisol® process are in the range from 30 to 70 bar. Also other solvents for physical acid gas removal, e.g. propylene carbonate solvent JOFFSOL® for the fluor solvent™ process, and dimethyl ethers of polyethylene glycol, such as Coastal agr® and Genosorb®, may be applied. A methanol-based process is also known as Ifpexol®. In an embodiment, the pressure in the physical wash is preferably in the range of the operating pressure of the Fischer-Tropsch unit, i.e. from 20 bar to 40 bar.

In an adsorbent bed, sulfur is adsorbed to the adsorbent material. Adsorbents for the purpose can be molecular sieves. As adsorbents, at least one of activated carbon, zinc oxide (ZnO), copper and zinc oxide Cu/ZnO and nickel based adsorbents can be used. Cu/ZnO may be used for deep H ₂ S removal, since a lower H ₂ S level in the purified gas can be obtained with Cu/ZnO rather than with ZnO. In case a chemical wash is used, the compressor 450 may be located after the chemical wash. In principle, the compressor could be located either before the gas shifter 310 or after it. However, compression energy is saved if the compressor is located after the gas shifter 310. In this case, the compressor 450 may be arranged to compress the shifted synthesis gas 478 (l,e. both the first part 472 and the second part 474), as depicted in Fig. 3d. In the chemical wash process, a chemical such as monoethanolamine (MEA), diethanolamine (DEA), methyldiethanolamine (MDEA), diisopropyl- amine (DIPA), or aminoethoxyethanol (Diglycolamine®, DGA®), is used for treating synthesis gas. The chemical wash, like the physical wash, is able to remove sour gases, such as hydrogen sulfide, from the synthesis gas. Carbonyl sulfide (COS) and carbon disulfide (CS ₂ ) are known to degrade MEA. Synthesis gas may comprise carbonyl sulfide or carbon disulfide. DEA and DGA are resistant against carbonyl sulfide and carbon disulfide. DIPA may be used to selectively remove H ₂ S in the presence of CO ₂ . DIPA removes also COS and CS ₂ if the synthesis gas comprises these sulfides. MDEA can be used to remove both H ₂ S and CO ₂ . A chemical wash may require a sulfur guard bed downstream to protect the shift catalyst.

Hydrogen sulfide (H ₂ S) can be removed either - selectively, wherein only sulfides (particularly H ₂ S, but also COS and/or CS2) are removed, while essentially no carbon dioxide is removed, or

- in a simultaneous removal of sulfides (particularly H ₂ S, but also COS and/or CS2) and carbon dioxide. The simultaneous removal may be referred to as non-selective removal.

Selective removal may be performed, for example, with an adsorbent bed or a chemical wash with DIPA. A simultaneous removal of H ₂ S and CO2 can obtained, for example, in a physical was or in a chemical wash using MEA, DEA, or MDEA.

Of the selective and non-selective sulfur removal, the non-selective sulfur removal, wherein both H ₂ S and CO2 are removed simultaneously may be preferred. For example, if also CO2 is removed, less heating is required before the gas shifter 310 and less cooling is required after the gas shifter 310 (cf. Figs. 3c and 3d, heater 471 and cooler 479). Moreover, the equilibrium composition in the gas shifter 310 may be more favorable, if the first part 472 comprises also CO2.

The cleaning capacity of the sulfur removal unit 460 should be designed so that a subsequent gas shift process (gas shifter 310) can be operated, independent of the biomass feed mix used in the gasification plant. The tolerable sulfur level of the treated gas depends on the catalyst used in the subsequent process, and will be discussed later.

The sulfur removal unit 460 may comprise a pre-wash unit arranged to wash the synthesis gas before the sulfur removal processes described above. The sulfur removal unit 460 may comprise a pre-wash/sulfur absorption tower. In the absorption tower, sulfur compounds such as H ₂ S, mercaptanes, HCN, NH ₃ , carbonyls, and higher hydrocarbons (e.g. BTX) are removed. After the sulfur removal unit 460, the sulfur content of the treated synthesis gas is relatively low, e.g. 100 ppmv or less. The sulfur content may be even lower, e.g. 1 ppmv (parts per million by volume) or less. Typically the sulfur content after sulfur removal is in the range from below 100 ppbv (parts per billion by volume) to 50 ppmv . In Fig. 3c, the treated synthesis gas flow 470 is divided into a first part 472 and a second part 474. The first part 472 is led to a gas shifter 310. The second part 474 is conveyed to a bypass 475, thereby bypassing the gas shifter 310, and is led to subsequent process steps without gas shifting. The mass ratio of the first part 472 and the second part 474 may be controlled e.g. with a valve 476. The system may also comprise a controller (not shown in the figures) arranged to control the valve, and thereby arranged to control the amount of bypassed treated synthesis gas. The amount of the first part 472 may be e.g. around 20% of the synthesis gas flow 470, whereby the amount of the second part 474 may be e.g. around 80% of the synthesis gas flow 470. These values depend e.g. on the H ₂ :CO molar ratio of the treated synthesis gas 470 and on the target ratio of the shifted synthesis gas 478. From the sulfur removal unit 460, the first part 472 of the treated synthesis is conveyed to the gas shifter 310. However, the temperature of the treated synthesis 470 gas leaving the sulfur removal unit 460 is e.g. from 0 °C to ambient temperature (20 °C), as discussed above. This temperature is relatively low as compared to the temperature in the gas shifter 310, where the required inlet temperature may be in the range from 180 °C to 400 °C, depending e.g. on the catalyst used in the gas shifter, as will be discussed later. Therefore, a heater 471 is used to heat the first part 472 of the treated synthesis gas. Furthermore, subsequent process steps, such as carbon dioxide removal 385 may need a lower temperature, e.g. in the range from minus 60 °C to ambient temperature (20 °C). Therefore, the system may comprise a cooler 479 arranged to cool the first part of the treated synthesis gas after gas shifter 310. The heater 471 could be used to heat all the treated synthesis gas 470 prior to dividing the flow to the parts 472 and 474, but this may not be energetically favorable. Moreover, the cooler 479 could be used to cool all the treated synthesis gas 478, i.e. shifted synthesis gas after mixing the first part 472 and the second part 474 of the treated synthesis gas. The point of mixing is denoted with the reference number 477 in Fig. 3c, and as discussed, the cooler 479 may be located after the point 477 in the direction of the synthesis gas flow. The preferable location for the cooler 479 depends on the temperatures in the process and the equipment used to heat and cool the gases. A heat exchanger 473 may be applied to transfer heat from the cooler 479 to the heater 471 .

In the gas shifter 310, the ratio of hydrogen (H ₂ ) to carbon monoxide (CO) is modified to optimize the performance of the subsequent Fischer-Tropsch synthesis (FT). In the gas shifter 310, the first part 472 of the treated synthesis gas is allowed to react with steam 259 (intermediate pressure steam) in the presence of a catalyst, under an intermediate pressure. The pressure in the gas shifter 310 is essentially the same as in the sulfur removal unit 460 (cf. above). The steam 259 may comprise the steam 254 obtainable from the heat exchanger 250 (Fig. 3b). In case the steam 254 is under high pressure, high pressure steam 254 may be expanded to an intermediate pressure steam 259. A pressure regulator may be used to decrease the pressure of the steam 254 to produce intermediate pressure steam 259. The system may comprise means for conveying the steam 254 from the heat exchanger 250 to the pressure regulator, and means for conveying the intermediate pressure steam 259 from the pressure regulator to the gas shifter 310. As steam is water, the gas shift may also be referred to as water-gas-shift. In the gas shifter 310, the carbon monoxide comprised in the synthesis gas reacts with water thereby producing carbon dioxide and hydrogen according to the reaction equation CO + H ₂ O = CO ₂ + H ₂ . The reaction is reversible, and is driven towards an equilibrium in the gas shifter. As the water gas shift is performed to a synthesis gas, from which at least part of sulfides (i.e. sour gases) are removed, the gas shift may be referred to as sweet gas shift.

Two types of catalysts applicable for the sweet gas shift are:

- low temperature shift (LTS) catalysts and

- high temperature shift (HTS) catalysts.

The LTS catalyst is applicable to treated synthesis gas, i.e. synthesis gas not containing sulfur or containing only a small amount of sulfur. The LTS catalyst may be a copper-based catalyst. The group of low temperature water gas shift catalysts may comprise e.g. CuO and ZnO on an AI2O3 support, referred to as CuO/ZnO/AI ₂ O3. The removal of sulfur before water gas shift enables the use of low a temperature catalyst. The catalyst is rapidly poisoned by sulfur or halides. The LTS catalyst may operate with treated synthesis gas, wherein the sulfur content of the treated synthesis gas 470 is at most 1 ppmv. The sulfur content refers to the content of sulfur comprised in sulfur-containing compounds e.g. H ₂ S, COS. As for the unit ppmv, one mole of elemental sulfur is regarded to correspond to one mole of sulfur in gaseous form. Moreover, the sulfur content is not necessarily constant, whereby the sulfur content refers to the time average of the sulfur content. The LTS catalyst operates typically with treated synthesis gas comprising sulfur less than 0.1 ppmv. The operating temperature of a LTS catalyst may be in the range from 180 °C to 270 °C. Moreover, the sulfur content of the treated synthesis gas 470 is at least essentially constant in time. The term "at least essentially constant in time" refers to a measured time series of the sulfur content, wherein

- the time scale of measurements is at least 1 hour and

- the standard deviation of the sulfur content divided by the average sulfur content is at most 50 %; preferably at most 10 %.

From the values given above, it is evident, that "at least essentially constant in time" for the LTS process refers also to the case, wherein the standard deviation of the sulfur content is at most 0.5 ppmv; preferably at most 0.1 ppmv.

Generally the space-time-efficiency of the water gas shift may be measured with the parameter gas hourly space velocity (GHSV) at a conversion level close to equilibrium conversion and at a given concentration of the reactants in the feed gas. GHSV is defined as a ratio of a volumetric gas flow at normal conditions (Tn=273.15°K, pn=1013 mbar) to the volume of the catalyst bed. The unit of volumetric flow is m ³ /h and the unit of the volume of the catalyst bed in m ³ . Thus the unit of GHSV is h ^~1 . More precisely, the volumetric flow is the volumetric flow of dry synthesis gas, in particular dry first part 472, or if the treated synthesis gas 470 is not divided to two parts, the dry treated synthesis gas 470. The term "dry" refers to the gas excluding the water content. A high GHSV value means that a large throughput can be obtained from the process with a small (in volume) catalyst bed. Generally the GHSV value for a LTS catalyst is larger than the GHSV value of a HTS catalyst. The GHSV value for a low temperature catalyst bed in the gas shifter 310 may be at least 3000 h ^~1 . Preferably, the GHSV value for a low temperature catalyst bed in the gas shifter 310 is greater than 3600 h ^~1 . Moreover, preferably the GHSV value for a low temperature catalyst bed in the gas shifter 310 is at most 4000 h ^~1 . This ensures that the result of the WGS process is determined by the equilibrium of the shift reaction, and enables a controlled throughput.

The low temperature shift may comprise only one shift stage. However, the low temperature shift may comprise at least two sequential stages. Between the stages the intermediate product may be cooled, such as quenched with water and/or steam. The gas shift is an exothermal reaction and an upper limit temperature in the catalyst bed must not be exceeded to avoid catalyst sintering. In case a lot of CO2 is converted in the gas shifter 310, the exothermal reaction may increase the temperature a lot, if the intermediate product is not cooled.

In case the treated synthesis gas 470 is not divided to two parts, the GHSV value, as defined above, is calculated using the volumetric flow of the dry treated synthesis gas 470. In case the treated synthesis gas 470 is divided to two parts, the GHSV value, as defined above, is calculated using the volumetric flow of the dry first part 472. In both cases the gas conveyed to the catalyst bed in the gas shifter 310 may be referred to as shiftable synthesis gas. All shiftable synthesis gas is conveyed to the catalyst bed. In the corresponding system, the gas shifter 310 comprises a catalyst, the catalyst being selected from the group of low temperature water gas shift catalysts. In the corresponding system, the volume of the catalyst bed is selected such that that GHSV, as defined above, is within the limit discussed above. The volumetric flow may be selected accordingly.

In the system and the method, the GHSV is defined as discussed above. The shiftable synthesis gas (i.e. the treated synthesis gas 470 or the first part 472 of it) is conveyed to the gas shifter 310 through a duct. When the cross- sectional area of the duct is A and the flow velocity through the duct is v, the volumetric flow at conditions in the duct (T,p) to the gas shifter is A*v. The volumetric flow at normal conditions (Tn=273.15°K,pn=1013 mbar) to the gas shifter is A*vn with vn = v ^* Tn/T ^* p/pn, assuming ideal gas behaviour. Moreover, when the volume of the catalyst bed in the gas shifter 310 is V, the GHSV, as defined above, equals A*vn/V. The system may thus be arranged to shift gas in the gas shifter with the GHSV values as defined above by selecting the flow velocity vn, cross sectional area A of the duct, and the volume V of the catalyst bed accordingly.

The high temperature water gas shift (HTS) catalyst is applicable to treated synthesis gas, i.e. synthesis gas not containing sulfur or containing only a small amount of sulfur. The group high temperature water gas shift catalysts comprise metal oxides e.g. Fe3O ₄ and Cr ₂ O3. The HTS catalyst may be an iron-chromium-based catalyst. When operative, the iron operates in the form of its magnetide Fe3O ₄ . The operating temperature for the HTS catalyst is from 320 °C to 500 °C. The HTS catalyst loses about 50% of its activity if sulfided. Therefore, for increased activity and thus smaller catalyst inventory, the HTS catalyst is preferably used only to treated synthesis gas. As a limit, a sulfur content of 100 ppmv may be considered to be a limit, above which the activity of the HTS catalyst starts to decrease. As a rule of thumb, the activity of a sulphided HTS catalyst is approximately half of the activity of an unsulphided HTS catalyst. In case HTS catalysts would be applied to an untreated synthesis gas, variations in the sulfur level would have the effect that the activity of the HTS catalyst was unknown, since the sulfur content of the untreated synthesis gas varies erratically thus affecting the activity of the HTS catalyst. Therefore, In case HTS catalysts would be applied to an untreated synthesis gas the systems should be designed with a relatively low GHSV value. This would imply a large HTS catalyst bed and large investment costs. Referring to the rule of thumb, discussed above, the volume of the catalyst bed may have to be doubled if one designs the systems for varying, possibly large, sulfur content. The GHSV value can in this case slightly be increased by taking into account the activity decrement with a temperature controller. The reaction rate over the HTS catalyst depends also on temperature, and by controlling temperature, also the losses in activity can be compensated.

In contrast, when the HTS catalyst is used to the treated synthesis gas 470 or 472, a much higher GHSV value can be used in the process, since

- the sulfur content is relatively low, as discussed above, and - the sulfur content at least essentially constant in time.

In an embodiment, the sulfur content of the treated synthesis gas is at most 100 pprnv. The sulfur content is not necessarily constant in time, whereby in an embodiment, the time average of the treated synthesis gas is at most 100 pprnv. In an embodiment, the deviation of the sulfur content and the value of the sulfur content are controlled such that the sulfur content of the treated synthesis gas is at most 100 pprnv. The sulfur content is controlled by the sulfur removal (Figs. 2a and 2b; Figs. 3c and 3d, sulfur removal unit 460).

The term "at least essentially constant in time" refers to a measured time series of the sulfur content, wherein

- the time scale of measurements is at least 1 hour and

- the standard deviation of the sulfur content divided by the average sulfur content is at most 50 %; preferably at most 10 %.

From the values given above, it is evident, that at least essentially constant in time for the HTS process refers also to the case, wherein the standard deviation of the sulfur content is at most 50 pprnv; preferably at most 10 pprnv.

These conditions enable a larger GHSV value in the HTS process, as compared to the case, wherein an un-treated synthesis gas would be converted in a gas shifter 310. For example, the gas hourly space velocity (GHSV), calculated as the ratio of hourly volume of dry first part 472 at normal conditions to the volume of catalyst bed, may be at least 1000 h ^~1 . Preferably GHSV is greater than 1200 h ^"1 . Moreover, preferably the GHSV value for a high temperature catalyst bed in the gas shifter 310 is at most 2000 h ^~1 . This ensures that the result of the WGS process is determined by the equilibrium of the shift reaction, and enables a controlled throughput.

Moreover, these conditions enable a larger GHSV value in the HTS process, as compared to the case, wherein an un-treated synthesis gas would be converted in a gas shifter 310, even without controlling the temperature of the of the gas shifter 310 to compensate activity changes due to sulfidation and desulfidation of the HTS catalyst. In an embodiment, the synthesis gas is shifted in the gas shifter 310 without controlling the temperature of the synthesis gas in the gas shifter 310.

Furthermore, water gas shifting of non-treated synthesis gas, which comprises a varying and relatively large amount of sulfur, poses some additional problems. First, a LTS catalyst cannot be used at all, since it becomes poisoned (inactive) in the presence of sulfur at the levels encountered in the non-treated gas. As discussed above, a higher GHSV value can be used with LTS catalysts than with HTS catalyst. Therefore, gas shifting of treated synthesis gas (470, 472) implies smaller catalyst beds and therefore also lower pressure drop. Second, when a HTS catalyst is used for water gas shifting of non-treated synthesis gas, the varying sulfur content continuously sulfides and de-sulfides the HTS catalyst. This in known to weaken the physical strength and to shorten the lifetime of the HTS catalyst. A short lifetime means more frequent maintenance and large overall costs. In contrast, when the sulfur content is at least essentially constant in time, the lifetime of the HTS catalyst is extended.

As discussed, the chemical reactions in the gas shifter 310 are driven towards an equilibrium CO + H ₂ O = CO2 + H ₂ . In the case sulfides and carbon dioxide are simultaneously removed before the gas shifter 310, the reaction in the gas shifter 310 will produce more hydrogen than in the case where sulfides are selectively removed. In the embodiments of Figs. 3c and 3d, also carbon dioxide is conveyed from the sulfur removal unit 460 to the gas shifter 310 thereby decreasing the amount of hydrogen produced in the gas shifter 310. As the reactions in the gas shifter produce CO2, and since all CO2 is not necessarily removed at the sulfur removal unit, carbon dioxide is removed later. After the gas shifter 310, the first part 472 and the second part 474 of the treated synthesis gas 474 are mixed, e.g. at the point 477 of Fig. 3c. The mixture is referred to as shifted synthesis gas 478. The molar ratio of H ₂ to CO in the shifted synthesis gas 478 is between 2.5 to 1 and 1 .0 to 1 . Preferably the molar ratio of H ₂ to CO in the shifted synthesis gas 478 is between 2.2 to 1 and 1 .8 to 1 . The first part 472 and the second part 474 of the treated synthesis gas 474 are mixed, because the equilibrium of the above reaction: CO + H ₂ O = CO2 + H ₂ does not necessarily correspond to an optimal molar ratio of H ₂ to CO, the optimal ratio, as given above, being determined by the Fischer-Tropsch synthesis located downstream. The equilibrium molar ratio in the gas shifter 310 depends e.g. on the temperature and the composition of the synthesis gas, which further depends e.g. on the feedstock, gasification process parameters, and reformation process parameters.

After the gas shifter 310 (and the cooler 479, and the point of mixing 477), the shifted synthesis gas 478 is conveyed to a carbon dioxide (CO2) removal unit 385. In the carbon dioxide (CO2) removal unit 385 carbon dioxide is at least partly removed from the shifted synthesis gas 478. The shifted synthesis gas 478 comprises carbon dioxide, since (1 ) the treated synthesis gas 470 may comprise CO2, if not removed by non-selective absorbtion together with H ₂ S in the sulfur removal unit 460, due to gasification, (2) CO2 is formed by the chemical reactions in the reformer 240, and (3) CO2 is formed by the gas shift reaction (cf. above) in the gas shifter 310. For these reasons it is beneficial that the carbon dioxide (CO2) removal unit 385 is located after the gas shifter 310.

The carbon dioxide removal step may comprise one of

- a physical wash process, known e.g. by the trade names Rectisol®, Purisol®, and Selexol®, and

- a chemical wash process (amine gas treating using e.g. MEA, DEA, MDEA, DIPA or DGA®; or using an aqueous solution of KOH/KCO3 or

NaOH/NaCOs).

Carbon dioxide is removed at least from the first part 472 since CO2 is produced in the shift reaction. Carbon dioxide is removed also from the second part 474 of the treated synthesis gas, since the sulfur removal unit 460 does not necessarily remove CO2. Therefore, the first part 472 and the second part 474 are mixed before the carbon dioxide removal unit 385.

Carbon dioxide removal unit 385 produces the product gas 400 (cf. Fig. 1 b) and a tail gas 387. The tail gas 387 comprises CO2. In an embodiment, the tail gas 387 consists essentially of CO2. The tail gas 387 may be used as the carbon dioxide 120 in the preceding process steps (cf. Fig. 3a). The tail gas may also be recycled to gasifier 150 or used as the recycled gas 205. The system may therefore comprise means for conveying gas (CO ₂ ) from the carbon dioxide removal unit 385 to at least one of a container for biomass (102, 106, 108), a dryer 550, the gasifier 150, and the gas cooler 218 (Figs. 4a-4c)

In the embodiments of Figs. 3b, 3c, and 3d, a part of the scrubbed synthesis gas is recycled in the process to cool the synthesis gas 200. However, this gas recycling is not necessary, particularly in case of a dirty reformer. Also, in case of a clean reformer, sufficient cooling may be achieved by quenching. However, part of the scrubbed synthesis gas 360 may be recycled to cool synthesis gas. In Fig. 3c, the scrubbed synthesis gas is divided to two parts: a first part and a second part 364. The first part is conveyed to the compressor 450 and used produce liquid biofuel. The second part 364 is recycled to the gas cooler 218. The system may thus comprise a gas cooler 218, means for dividing the scrubbed synthesis gas 360 to two parts, and means for conveying the second part 364 of the scrubbed synthesis gas 360 to the gas cooler 218.

From the CO ₂ removal unit 385 the product gas 400 is further conveyed to a Fischer-Tropsch processing unit 390 for producing product fluid 396 and FT tail gas 395 from the product gas 400. The product fluid 396 comprises hydrocarbon oils and waxes, and is used for producing biofuel. The FT tail gas 395 may comprise carbon monoxide (CO), carbon dioxide (CO ₂ ), hydrogen (H ₂ ), nitrogen (N ₂ ) and light hydrocarbons, e.g. methane. The FT tail gas 395 may be recycled to the process, as the recycled gas 205 or to the gasifier 150. The system may comprise means for conveying gas (the FT tail gas 395) from the FT processing unit 390 to the gas mixer 212, to the reformer 240, or to the gasifier 150. The system may comprise means for conveying gas (the FT tail gas 395) from the FT processing unit 390 to the burner 463 (cf. Fig. 3c) to produce heat and electricity.

Heat is recovered from FT processing unit 390 with a heat exchanger 397. The heat exchanger 397 is arranged to cool the FT processing unit 390, and is arranged to recover heat from the FT processing unit 390. The heat is recovered to a heat transfer liquid, such as water 398, which is fed to the heat exchanger 397. As a result, the water evaporates to steam 399 in the heat exchanger 397. The steam 399 may be used in preceding process steps. The steam 399 may be used in at least one of following: the gasification reactor 150 as the steam 142, the reformer 240 as the steam 232.

The product fluid 396, from the FT, is upgraded to produce biofuel, naphtha and off gas 410. The upgrading process comprises hydrocracking of product fluid 396 and fractionated distillation to obtain liquid biofuels such as at least one of biodiesel and kerosene. The formed waxy-compounds, i.e. FT-wax are hydrocracked into middle distillates. The hydrocracking process produces also light end hydrocarbons which are considered as the off gas 410, which also contains unconverted hydrogen. The off gas 410 may also be recycled to the process as the recycled gas 205 and /or to the gasifier 150 (not shown in the figure 3c). The off gas 410 may be combined with the FT tail gas 395 before or during conveying these gases to the gas mixer 212, the gasifier 150, or the burner 463. Fig. 4a shows some parts of a process for producing liquid fuel from biomass 100. In the process, the biomass is conveyed to a dryer 550. The dryer 550 uses low value heat from the scrubber 320 to dry the biomass. In addition, or alternatively, low value heat from the Fischer-Tropsch processing unit 390 is used to dry the biomass in the dryer 550. Low value heat is conveyed to the dryer from the scrubber within the heated heat transfer medium 337, and the cooled heat transfer medium 336 is returned to the scrubber 320. Low value heat may be supplied from the FT unit 390 to the dyer 550 with another heat transfer medium. From the dryer 550 the dry biomass is conveyed to a container 102. From the container 102 the dry biomass in conveyed to the lock hopper, i.e. containers 106 and 108. Carbon dioxide is fed to at least one of the container 106, 108, and the carbon dioxide 120 is obtained from the carbon dioxide removal unit 385 as the tail gas 387. Biomass 100 is gasified in the gasifier 150 producing the raw synthesis gas 200. Raw synthesis gas is cooled in a cooler 218, which may utilize recycled gas 205 to cool the synthesis gas. As discussed above, the cooler 218 may comprise at least one of a quencher 210 and a gas mixer 212. In the quencher 210, synthesis gas may be cooled or further cooled using e.g. water quenching. In cooler 218 synthesis gas may be cooled by one of the following (cf. Fig. 3b):

- water quenching in the quencher 210 only,

- water quenching in the quencher 210 and subsequent cooling by gas mixing in the gas mixer 212,

- cooling by gas mixing in the gas mixer 212 only, and

- cooling by gas mixing in the gas mixer 212 and subsequent water quenching in the quencher 210.

Recycled gas 205 may comprise scrubbed synthesis gas, as depicted in Fig. 4a. The recycled gas 205 may comprise at least one of scrubbed synthesis gas, the FT tail gas 395, the product upgrading off gas 410, and the tail gas 387 from the CO2 removal unit 385. The cooled synthesis gas is conveyed through the filtering unit 220 to the reformer 240. In the reformer, the filtered synthesis gas is allowed to react with oxygen 230 and steam 232. The steam 399 produced at the heat exchanger in connection with the FT unit 390 may be utilized as the steam 232 for the reformer. In addition or alternatively, other steam 232 (cf. Fig. 3b) may be used in the reformer.

The reformed synthesis gas is conveyed to the heat exchanger 250, wherein steam 254 is produced. The steam 254 may be utilized in the gas shifter 310. Subsequent process steps have been described in the context of Figs. 3a-3d. In particular, the tail gas 387 from the CO2 removal unit 385 may be recycled to at least one of a container 102, 106, 108, 550, the gas cooler 218, the reformer 240, and the gasification reactor 150. The tail gas 395 from the FT processing unit 390 may be recycled to at least one the gasification reactor 150, the gas cooler 218 and the reformer 240. The steam 399 produced by the FT reactor heat may be utilized e.g. in the gasifier 150. In case the compressor 450 is located after the gas shifter 310 (Fig. 3d), the steam may also be utilized in the gas shifter 310. The off gas 410 from the upgrading process may be recycled to at least one the gasification reactor 150, the gas cooler 218 and the reformer 240. The reference "UG" in the figure stands for Upgrading (cf. Fig. 3c, 3d, 4a, 4b, 4c). The off gas 410 from the upgrading process may alternatively be used as fuel gas and may be burned in a boiler or fired process burners.

Fig. 4b shows embodiments of the process and system. Synthesis gas cooling is done only by quenching. Therefore, the gas cooler (218 in Fig. 4a) is depicted only by the quencher 210. Also, no gas is recycled to the gas quencher 210. In an embodiment, the tail gases 395 from the Fischer- Tropsch unit 390 are conveyed to the gasifier 150 (dash line between FT unit 390 and gasifier 150). In another embodiment, the tail gases 395 from the Fischer-Tropsch unit 390 are conveyed to the reformer 240 (dash line between FT unit 390 and reformer 240). The off gases from the upgrading unit UG may optionally be conveyed to either the gasifier 150 or the reformer 240 (dash line between the upgrading unit UG and the FT unit 390), or alternatively be used as fuel gas.

Fig. 4c shows embodiments of the process and system. Synthesis gas cooling is done only by gas mixing. Therefore, the gas cooler (218 in Fig. 4a) is depicted only by the gas mixer 212. Also, gas from the scrubber 320 is recycled to the gas mixer 212. In an embodiment, the tail gases 395 from the Fischer-Tropsch unit 390 are conveyed to the gasifier 150 (dash line between FT unit 390 and gasifier 150). In another embodiment, the tail gases 395 from the Fischer-Tropsch unit 390 are conveyed to the reformer 240 (dash line between FT unit 390 and reformer 240). In another embodiment, the tail gases 395 from the Fischer-Tropsch unit 390 are conveyed to the gas mixer 212 (dash line between FT unit 390 and gas mixer 212). The off gases from the upgrading unit UG may optionally be conveyed to at least one of the gasifier 150, the reformer 240, and the gas mixer 212 (dash line between the upgrading unit UG and the FT unit 390) or used as fuel gas. Figures 4a-4c show the embodiments for a clean reformer. Using this description, a person skilled in the art is able to utilize the invention also with a dirty reformer. Figures 4a-4c show the embodiment with a physical wash, whereby the compressor 450 is located before the sulful removal unit 460. However, an embodiment with a chemical wash (Fig. 3d) may comprise the compressor after the gas shifter 310, e.g. before the CO2 removal unit 385. Figure 5 shows an embodiment, where the streams from two different gasification plants are combined before a common compression step (and subsequent common steps, e.g. sulfur removal). Using this figure, a person skilled in the art is able to utilize the invention also with more than two gasification plants. The three or the four or the five (etc.) gasification plants may have a common refinery as shown in the figure for two gasification plants. The gasification plants of the figure 5 use a clean reformer. Using this figure, a person skilled in the art is able to utilize the invention also with gasification plant comprising a dirty reformer. Using this figure, a person skilled in the art is able to utilize the invention also with two gasification plants, wherein the first gasification plant comprises a clean reformer and the second gasification plant comprises a dirty reformer (cf. Figs. 2a and 2b). The streams from different gasification plants may be combined e.g. between scrubbing and sulfur removal, or in case of a physical wash between scrubbing and compressing.

Referring to Fig. 1 a system with only one gasification plant may comprise a post processing system arranged to produce the liquid biofuel from the raw synthesis gas 200. This post processing system may comprise at least a sulfur removal unit 460 and a gas shifter 310. When the system comprises at least two gasification plants, the first plant may comprise a second gasification reactor for gasifying biomass 100 at an elevated temperature to produce second raw synthesis gas and means for processing the second raw synthesis gas to second synthesis gas. With reference to Fig. 5, these means may comprise means for at least one of cleaning, clean reforming, cooling, and scrubbing. The system may further comprise means for conveying the second synthesis gas to the post processing system as discussed above. With reference to Fig. 5, the (common parts of the) post processing system may comprise means for at least one of compressing, sulfur removal, water gas shifting, and CO2 removal. With reference to Figs. 4a to 4c, the (common parts of the) post processing system may further comprise a Fischer-Tropsch unit 390, and an upgrading unit UG.

From the above description it is evident that the system according to Fig. 5 comprises:

- a first gasifier, arranged to produce first raw synthesis gas from biomass, - a second gasifier, arranged to produce second raw synthesis gas from biomass,

- means for processing the first raw synthesis gas to first synthesis gas

- means for processing the second raw synthesis gas to second synthesis gas

- a compressor arranged to increase the pressure of synthesis gas,

- means for conveying the first synthesis gas to the compressor, and

- means for conveying the second synthesis gas to the compressor. It is evident, that the each gasification plant may comprise the equipment described in Figs 3a-3d, from the first container 102 to the scrubber, and means for recycling part of the scrubbed synthesis gas. It is also evident that a common refinery may comprise the equipment described in Fig 3c, from the compressor 450 to the upgrading unit. Synthesis gas from all gasification plants may be processed in the common refinery. The common refinery is schematically indicated in Fig. 5 with the dash line 500. In particular, in the water gas shift of the common refinery, all the synthesis gas may be shifted. Alternatively, the synthesis gas as received from the two gasification plants, may be divided to two parts as discussed above, and only one part of synthesis gas may be shifted. Thus, in a common shift reactor, carbon monoxide (CO) and steam of the first part is converted to hydrogen (H ₂ ) and carbon dioxide (CO2).

In a comparative method and/or system, the water gas shift is applied to a non-treated synthesis gas. The non-treated synthesis gas refers to synthesis gas before sulfur removal, e.g. the cooled synthesis gas 300 or the scrubbed synthesis gas 360. In such a process a third type of catalyst could be used, a sour shift catalyst. However, sour gas shift catalysts cannot be applied without sulfur addition to the raw gas, to prevent the catalyst from desulphidation during phases where low sulphur biomass is fed. Such dosing system increase process complexity and operational complexity, as compared to an embodiment of the present invention.

The embodiments, as described above have several advantages. (1 ) The process is not sensitive to the sulfur content of the biomass feedstock. This allows for more flexibility for the feedstock. The sulfur content of biomass depends on the type of the biomass and on the location, where the biomass has been grown. Because of the flexibility, the feedstock content can be optimized based e.g. on the price of the biomass. The price of e.g. stumps, wood residues, and bark depend on their availability. As the process itself is not sensitive to the sulfur content of the raw material, the purchasing price of raw material can be reduced with more flexibility.

(2) As the sulfur removal unit 460 is located before the gas shifter 310, the gas shifter / bypass configuration is arranged to adjust the molar ratio of H ₂ to CO of treated synthesis gas. Compared to an arrangement, where sour synthesis gas is shifted, in the embodiments the issue of maintaining a minimum sulfur level is eliminated.

Moreover, a sulfur dosing system, to maintain an acceptable sulfur level in the gas shifter, when using biomass with low sulfur level, is not needed in some embodiments. The treated synthesis gas allows for standard operation of HTS and LTS catalysts. Thus the embodiments are simpler and are expected to have smaller investment costs than the comparative system, wherein synthesis gas is shifted before sulfur removal using a sour shift catalyst such as CoMo-based catalysts.

(3) The treated gas allows for a small HTS catalyst bed, since the HTS catalyst is not sulfided. As the HTS catalyst is not sulfided, the catalyst remains in an active magnetide form (Fe3O ₄ ), whereby a smaller catalyst bed can be used, as compared to the comparative system, wherein synthesis gas is shifted before sulfur removal. This allows for a larger throughput of the process using equipment having the same size (e.g. a larger GHSV value). Moreover, this allows for a process without compensating activity changes of the HTS catalyst, caused by sulfidation / desulfidation cycles. Permanent adaption of the gas shift temperature to compensate for activity changes is therefore not required. Therefore the HTS catalyst can be operated at constant conditions. (4) In cases where an HTS catalyst is used, the process of the embodiments increases the life time of the HTS catalyst by avoiding sulfidation / desulfidation cycles, which would occur if the catalyst would be located in the raw gas section and if the biomass feed stock alternates between high and low sulfur biomass. Repeated sulfidation

/ desulfidation cycles are known to weaken the physical strength of the HTS catalyst.

(5) The gas shifter 310 is located downstream of the scrubber 320, the compressor 450 (in cases where the sulfur removal 460 is achieved by a physical wash process), and the sulfur removal unit 460. All these units remove some impurities from the synthesis gas. Therefore, the risk of poisoning of the gas shift catalyst (LTS or HTS) by unforeseen impurities is relatively low, compared to a system wherein the gas shifter 310 is located before any of the other mentioned equipment. In addition, for the specified order of the equipment, the risk of dust deposition or tar or volatile alkali condensing in the gas shifter 310 is reduced, compared to a system wherein the gas shifter 310 is located before any of the other mentioned equipment.

(6) The catalysts used in the gas shifter 310 are typically sensitive to oxygen. The catalyst may react with oxygen such that their activity ceases. Oxygen, on the other hand, is injected to the process in the reformer 240. Bearing in mind that the process will have sufficient safety measures to prevent larger quantities of oxygen from getting in contact with the shift catalyst, it can generally be said that the further away the gas shifter 310 is from the oxygen injection points (i.e. the reformer 240), the smaller the risk for oxidizing the catalysts in the gas shifter.

(7) If a physical wash process is used, the synthesis gas may be compressed before the gas shifter, whereby the gas shifter 310 is operated at an intermediate pressure (20 bar to 40 bar). Due to the nature of reaction kinetics of HTS and LTS, the size of the gas shifter 310 can be made smaller, compared to cases where a lower pressure is used. Therefore, an intermediate pressure gas shifter 310 takes up less space than a low pressure gas shifter. For the same residence time (or contact time with the catalyst) a gas shifter with a low pressure (e.g. 10 bar) should be 2 to 4 times bigger than a gas shifter with an intermediate pressure.

(8) In case the gas shifter 310 is located after the compressor 450, a smaller compressor 450 is sufficient, as compared to the case, where the compressor 450 is located between the gas shifter 310 and the CO2 removal 385. This is because the gas shift produces additional gas volume, since steam is added to the gas shifter 310. Thus the volumetric flow before gas shifter 310 is less than that after the gas shifter 310. If the gas shifter 310 is located before the synthesis gas compressor 450, each mole of H ₂ O, which has been converted in the gas shifter, generates 1 mole of gas (H ₂ ), which has to be compressed before the sulfur removal unit 460. A smaller compressor 450 implies smaller investment costs and smaller space requirements.

(9) Referring to Fig. 5, multiple gasification plants may utilize a common equipment for refining synthesis gas. More specifically multiple gasification plants may utilize a common compressor 450, sulfur removal unit 460, gas shifter 310, CO2 removal unit 385, Fischer- Tropsch synthesis unit (390, FT), and upgrading unit (cf. Figs. 3c and 5), as well as means for conveying synthesis gas from one unit to another. As compared to a system wherein each gasification plant comprises all the equipment needed to produce biofuel, the investment cost is significantly lower. Multiple gasification plants may comprise a common water gas shifter. Moreover, these multiple gasification plants may comprise a common sulfur removal unit, as shown in Fig. 5, or separate sulfur removal units (not shown). These multiple gasification plants may comprise a common compressor, as shown in Fig. 5, or separate compressors (not shown). Investment costs can be reduced by using at least one of a common gas shifter 310, a common compressor 450, and a common sulfur removal unit 460. The embodiments described above may be used for producing liquid fuel from solid biomass. The overall process yield, stability and robustness towards erratic and frequent changes in sulfur content of the biomass and the scrubbed synthesis gas is good because gas shifting is performed for a well controlled, pure and treated synthesis gas. Moreover, control of H ₂ to CO ratio is achieved by letting a part of the treated synthesis gas bypass the gas shifter.

It is apparent to a person skilled in the art that the basic idea of the embodiments can be implemented in various ways. The invention and its embodiments are therefore not restricted to the above examples, but they may vary within the scope of the claims.