NO161326B - PROCEDURE FOR TREATING A CARBON MATERIAL. - Google Patents

Description

The present invention relates to a method thereof

species specified in claim l's preamble.

Many methods are known for treating petroleum oils and the like with alkali metal compounds or sulphides.

For example, US Patent No. 3,252,774 shows a method for cracking liquid hydrocarbons to form hydrogen-containing gases by contacting the feed material with a melt of an alkali metal compound (for example, the sulfides) at a temperature in the range of 427 and 982°C in the presence of steam.

US Patent No. 3,617,529 shows the removal of elemental sulfur from petroleum oils by contacting the oil at room temperature with an aqueous solution containing sodium hydrogen sulphide alone or in combination with sodium hydroxide and ammonium hydroxide. The aqueous solution and oil are separated and the aqueous solution is treated to liberate sulfur from polysulfides formed during contact

the step.

US patents no. 3,787,315 and 3,788,978 show methods for the desulphurisation of petroleum oil. The oil is brought into contact with an alkali metal or alloy in the presence of hydrogen to produce a sulphide after which the oil is desulphurised. The sulphide is separated from the oil by treatment with hydrogen sulphide and

the separated monosulfide is treated with sodium polysulfide

to give a polysulphide with a lower sulfur content which is then electrolysed to give sodium.

US Patent No. 3,816,298 discloses a two-step process

for upgrading (partial desulphurisation, hydrogenation and hydrocracking) of heavy hydrocarbons, (for example a vacuum residue) to liquid hydrocarbon products and a hydrogen-containing gas. In the first step, the hydrocarbon feed material is

alet brought into contact with a gas containing hydrogen and carbon monoxide in the presence of many catalysts, including alkali metal sulfides and hydrogen sulfides. The pressure must be above 10.5 kp/cm 2 and the average temperature in the range 370 - 590°C. An example shows the feed of steam (as well as hydrogen and carbon oxides) to a first stage with K 2 CO 3 catalyst at 24 kp/cm 2 and 488°C. A by-product, namely a solid carbonaceous material, is deposited on the catalyst and part of the catalyst is sent to another, reaction step in which it is brought into contact with steam at a pressure above 10.5 kp/cm<2> at an average temperature above 650 °C.

US patent no. 4,003,823 shows another method for upgrading heavy hydrocarbons by contacting these with alkali metal hydroxides at hydrogen pressures in the range 35 - 350 kp/cm<2> and temperatures in the range 260 - 1100°C. Hydrogen sulfide can be added to the products extracted from the reaction zone to convert formed alkali metal sulfides in the reactor to hydrogen sulfides as a first step in the regeneration of the alkali metal hydroxides.

US Patent No. 4,018,572 discloses a process for desulfurizing fossil fuels by contacting such material with aqueous solutions or melts of alkali metal polysulfides to yield higher sulfur salts which are then decomposed to regenerate the polysulfides with down- set sulfur content.

Finally, US patent no. 4,119,528 shows another method for treating heavy carbonaceous feed materials using potassium sulphide and hydrogen pressure in the range 35 - 350 kp/cm 2 at temperatures in the range 260 - 1100° C. The products are desulphurised, low-boiling oils and potassium hydrogen sulphide, which can be converted back to potassium sulphide. The potassium sulfide can be fed to the reactor as such or formed in situ by reacting various potassium compounds with sulfur compounds, such as hydrogen sulfides. Potassium sulfides can also be formed by reducing potassium compounds, such as hydrogen sulfide or polysulfides with reducing agents such as hydrogen. The sulphide can also be formed by high-temperature evaporation of potassium hydrogen sulphide. Preferably, a mixture of potassium and sodium sulfides is used because sodium sulfide acts as a "catcher" for hydrogen sulfide formed during reaction, which would otherwise react with potassium sulfide to form "inactive" potassium hydrogen sulfide.

The following US patents show methods for treating petroleum oils and the like with alkali metal compounds or sulfides: 1,300,816, 1,413,005, 1,729,943, 1,938,672, 1,974,724, 2,145,657, 2,950,245, 3,112,257, 3,185,641, 3,368,875, 3,354,081, 3,382,168, 3,483,119, 3,553,279, 3,565,792, 3,663,431, 3,745,109 and 4,007,109.

A problem with the known methods, including those mentioned above, are the harsh manufacturing conditions, for example high temperature and/or pressure, which are necessary to give useful products in high yields. The present invention is aimed at a solution to the above-mentioned problems.

It has now surprisingly been found that by using an empirical hydrate reagent, discussed in more detail below, the yield of useful products will be much higher than for the previously known hydrotreatment techniques, including those discussed above even under relatively mild manufacturing conditions. For example, the reaction temperature does not need

co o present method a be higher than approx. 410 C and the pressure need not be above atmospheric pressure. Also because the conversion efficiency and yield of useful products is surprisingly high with the present method and requires less expensive manufacturing conditions, a reduction in the consumer's costs is expected.

More particularly, according to the present invention, a method for the hydrotreatment of carbonaceous material is provided, which is characterized by what is stated in the characterizing part of claim 1, namely: that the reaction mixture is introduced to steam, preferably after the reaction sheet has been heated to a predetermined temperature, in which temperature, pressure and other reaction conditions are maintained so that essentially no liquid water is present during the treatment. Further features appear in requirements 2-6.

None of the above-mentioned US patents disclose or suggest the use of empirical hydrates of alkali metal hydrogen sulfides, sulfides, or polysulfides for hydrotreating (ie, hydrogenation and hydrocracking) of carbonaceous materials.

In what follows, the term "carbonaceous material" is intended to include oils, shale, tar sands and the like, but not coal. The term "carbonaceous material" thus includes crude oils, atmospheric residues (cracked and non-cracked) and vacuum residues ("vis and non-vis broken") and non-petroleum oils. "Hydrotreating" includes hydrogenation and hydrocracking. The term "empirical hydrates" is used because the reactants used according to the invention appear to be hydrates in that they contain bound or associated water which is released at certain temperatures when the reactants are heated.

The use of steam in the present process is necessary because it retains the reactants in their empirically hydrated (highly active) forms.

The new method provides many advantages. Alongside the advantages previously mentioned, denitrogenation and demetallisation will take place at the same time as the hydrotreatment. In addition, depending on the treatment conditions and which reactants are used, desulphurisation can also take place, for example US patent no. 4,160,721 which shows a desulphurisation method.

The efficiency and degree of achievable hydrotreatment is

also very high. E.g. in a preferred embodiment in which hydrogen sulphide is simultaneously fed into the reaction zone in which a residue with an initial boiling point of 343°C is treated in a pass, essentially all of the resulting products will boil at temperatures below 34 3°C. This shows the high degree of cracking achievable by relatively

mild conditions when carrying out the present method.

Other advantages of the present method will be apparent from the following description.

In general, the method will include bringing the carbonaceous material into contact with the reactant. The carbonaceous material will be used in liquid phase, but a preliminary investigation indicates that vapor phase contact can also be used. The steam is passed through the reaction mixture to maintain the reactant in its empirically hydrated (highly active) form.

(For carbonaceous materials with a high content of naphthenic acids, the flow of steam is kept to a minimum because water tends to decompose these materials. In these cases, hydrogen can advantageously be introduced simultaneously). Water in liquid form causes the reactants to decompose and thus the reaction conditions should be chosen so that the presence of significant amounts of water is prevented. Preferably, the conditions are chosen so that there is essentially no free-flowing water in the reaction zone.

The reaction mixture is heated to evaporate the treated product and the steam and product are drawn off from the reaction zone, cooled and separated. If desired, the product can be taken out as a series of distillation fractions and the heavier (higher boiling point) fractions recycled for further treatment. Steam and evaporated products do not need to be extracted continuously or not overhead, however, without periodic extractions of the product, the pressure will rise and cause the steam to condense. This, in turn, will split the reactant and slow down the reaction. Accordingly, it is preferred that there is at least one periodic steam removal and continuous removal is most preferred.

Treatments can be performed in almost any type of equipment. E.g. a tank reactor can be used. A bonded, column reactor which allows product fractions to be taken off as top fraction and side fractions can also be used. The method can be carried out continuously or in batches with one or more reaction steps. A tank reactor will usually be operated in batches, while a bonded column is suitable for continuous operation.

In a preferred embodiment, hydrogen sulphide is also fed into the reaction zone and brought into contact with the reaction mixture. This will regenerate part of the reactant and lead to a higher productivity. As explained in the following, hydrogen sulphide will be produced during the treatment and drawn off with the steam and the evaporated product. Accordingly, it is most advantageous if the withdrawn hydrogen sulphide is recycled to the reaction zone.

The reaction temperatures are relatively low, generally in the range 40 - 410°C. For certain materials (for example vacuum residues) essentially no reaction will take place until the temperature is relatively high (for example 370°C). The pressures need not be above atmospheric pressure, but construction considerations may require that higher pressures be used, for example to reduce the diameter (and costs) of a column-type reactor. Whatever conditions are used, they should not lead to the condensation of significant amounts of steam and preferably the steam is not condensed.

The reactants used are empirical hydrates of hydrogen sulphides, monosulphides and polysulphides of group IA elements in the periodic table, except for hydrogen. Francium and cesium compounds are generally not used. Thus, sodium, potassium, lithium and rubidium compounds will be used more often. Potassium, rubidium and sodium compounds are preferred and potassium compounds are most preferred. (However, in certain cases, for example for Heavy Canadian Crude Oil, sodium reactants have proven better than their potassium equivalents). A reactant comprising empirical hydrates of 3 hydrogen sulfides equivalent to 14% rubidium hydroxide, 29% potassium hydroxide, and the remainder sodium hydroxide (based on the total of the two hydroxides and one hydrosulfide) is found to be most effective.

During the reaction at low temperatures the reactant is actually a mixture of the empirical hydrates of the hydrogen sulphide and sulphides (mono and poly) of each alkali metal used and during the reaction there is a mutual conversion of these sulphur-containing forms. (As the reaction temperature rises, some of these forms will disappear because their decomposition temperature has been exceeded.) Accordingly, the reactant may initially collect in the reaction zone as the hydrogen sulfide empirical hydrate or as one or more of the sulfide hydrates or as mixtures of the hydrogen sulfide and sulfide empirical hydrates. The empirical hydrate reactant can also be formed in situ, but it is preferred that they collect in their empirical hydrate form. (Each of the alkali metal hydrogen sulfides and mono-

and the polysulfides may have one or more empirical hydrates unless otherwise indicated, and the term "empirical hydrate" is intended to include all hydrates).

More specifically, if you take the potassium series as an example, there are six sulphides of potassium, I^S, K2S2, K-^S-^, I^S^, K2S^, and K2S6 and one hydrogen sulphide, namely KHS. The molecule containing the largest number of sulfur atoms can be thought of as being "saturated" with respect to sulfur (ie K2Sg) and those containing fewer as being relatively unsaturated with respect to

sight to sulphur.

If one considers, for example, potassium monosulphide (K2S) will

it crystallizes as an empirical pentahydrate. Under the reaction conditions, at 162°C the empirical pentahydrate will split into an empirical dihydrate with a strong and observable release of 3 mol of water per mol K.>S. At 265 - 270°C a further cleavage will take place to a lower empirical hydrate with release of water. Some of the water in the empirical hydrate will probably remain up to or below the melting point of 948°C. The release of the water at certain temperatures is clear evidence of the presence of bound or associated water analogous to water of hydration.

The present method denitrogenates and demetallises when the process causes hydrogenation and hydrocracking. Nitrogen leaves the system as ammonia vapor. The removed metals include vanadium, nickel, cobalt and cadmium and remain in the reactant which is returned to the reaction zone. Furthermore, if H^S is fed in at the same time or if the less sulfur-saturated reactants are used, the process will also cause desulphurisation.

Increasing the total sulfur to alkali metal ratio in the reaction zone (including sulfur in the carbonaceous material) will tend to decrease the severity of cracking that occurs and to decrease desulphurization. Lower sulfur to alkali metal ratios tend to increase the degree of cracking and increase desulfurization. If hydrogen sulphide is fed in at the same time, the timing of its addition will also affect the severity of the cracking. Commencement of addition before removal of all water in liquid form (at approx. 110 - 135°C) reduces the degree of severity, commencement of addition after removal of water increases the degree of severity.

For potassium reactants, overall ratios of 0.5/1 (equivalent to 100% K2S) to 2.5/1 (equivalent to 10C% ^ 2S5^ can be used. However, the most useful range for most carbonaceous materials will be 0.55/1 to 1.5/1 and the preferred range is 0.75/1 to 1/1 The limits of the preferred range can be thought of as corresponding to K^S^

(0.75/1) and ^ 2S2 ' The preferred range for the sodium series is 0.55/1 to 1/1. Lower conditions may be necessary when the materials being treated are more difficult to crack, for example vacuum residues. If the sulfur to alkali metal ratio of the combined reactant and the carbonaceous material is too low, elemental sulfur can be added, and if it is too high, additional unsaturated reactant can be added.

The amount of reactant used must be sufficient to provide a suitable contact with the introduced material and the desired reaction rate. The maximum amount of raw material that can be treated with a given amount of catalyst is not known, but as much as 500 g of vacuum residue has been treated with 9.5 g of KHS (as empirical hydrate).

The reactants can be prepared in many ways. Preparation of preferred potassium reactants will be exemplified. First, sulfur in a 15% excess can be added to potassium in a liquid ammonia medium. This gives potassium sulphide hydrate (empirical hydrate). Part of the hydrate is then added with additional sulfur to give the pentasulfide empirical hydrate. The two hydrates are combined and used.

Another method is to dissolve potassium hydroxide in water and add just enough of a low boiling alcohol (eg ethanol, propanol-1) to cause 2 layers to form. For example, 1 g-mol of KOH is dissolved in 2 g-mol of water. Sufficient alcohol (eg ethanol or higher) is added to give 2 layers (the total volume will be 160 ml or less) and then elemental sulfur is added to give the S/K ratio the desired value.

This second method gives almost exclusively empirical hydrates of sulphides and none of the hydrogen sulphide. The little hydrogen sulphide that is formed remains in the alcohol layer and the water layer contains only sulphides. The sulphides in the water layer have been successfully used in hydrotreatment experiments. This underpins the suitability of the sulphide reactants.

A third (and preferred method) involves dissolution

of potassium hydroxide in an alcohol in which KOH is soluble and then bringing the solution into contact with hydrogen sulphide. The alcohol will usually be a primary alcohol and methanol and ethanol are preferred because KOH is more soluble in these than in higher alcohols. The resulting mixture contains potassium hydrogen sulphide empirical hydrates. (This method can also be used for the preparation of rubidium reactants. The sodium hydrogen sulphide reactants are not prepared in this way, instead commercially available flakes of NaHS empirical hydrate can be introduced directly into the reaction zone.)

Preparation of potassium hydrogen sulphide empirical hydrate reactant

according to the preferred method is illustrated as follows. 2 1-liter measuring cylinders are each filled with slightly less than 600 ml of ethanol and 3 g-mol of potassium hydroxide are dissolved in each. A hydrogen sulfide source is connected to the first cylinder to introduce H 2 S near the bottom of the KOH-ethanol solution. The steam passing over from the first cylinder is introduced into a tube in the second cylinder near the bottom of the solution in it. The following overall reaction takes place

This reaction occurs so quickly that if the E^S flow is too slow, the solution in each cylinder will be drawn up into the respective steam supply pipes. The gas flow to the first cylinder is stopped as soon as H2S passes freely to the second cylinder and any precipitate in the first cylinder has dissolved and the temperature in this cylinder has dropped below 22°C. At this point, the first cylinder contains a high-grade reactant (potassium hydrogen sulfide empirical di-: hydrate (KHS.2H2O) in ethanol) and should be removed from the system and stored.

A typical batch procedure for treating carbonaceous material according to the invention using the preferred potassium reactant prepared according to the preferred method is as follows (petroleum oil being the carbonaceous material). The oil is introduced into a reaction vessel and nitrogen (or other inert gas) is continuously flushed through the oil to agitate it as it is heated. (Mechanical means such as a magnetic stirrer can be used instead of gas stirring). If elemental sulfur is needed to raise the sulfur to alkali metal ratio, the sulfur can be added to the oil at this point. The reactant mixture (potassium hydrogen sulphide empirical dihydrate in ethanol) is then

sat. (Alternatively, additional sulfur can be added to the reactant mixture rather than to the oil). The temperature is raised to approx. 13 0°C and steam flushing is started. The steam flow need not be greater than it causes bubbles to be

visible on the surface of the oil. If the steam provides sufficient agitation, the nitrogen purge can be stopped.

The outgoing steam is drawn off continuously and contains varying amounts of alcohol and water from the reactant mixture, steam, hydrogen sulphide from the reaction, as well as both evaporated and non-condensable hydrocarbon products from the treatment (assuming that the reaction entry temperature has been reached). The leaving steam is cooled with cooling water and the resulting condensate is fed to a liquid-liquid separator. The uncondensed steam can be fed to a cold trap (eg at -50°C) to recover additional hydrocarbon products.

When the temperature in the oil in the reactor rises, various outgoing products will be recovered in the condensation system. The nitrogen flushed into the oil will begin to strip alcohol and water associated with the reactant almost as soon as it is added (at 40°C). At 90°C, the first drops of separated hydrocarbon layers will be visible in the liquid-liquid separator. Before this, however, light hydrocarbon compounds, for example three-, four-, five- and six-carbon atom compounds) will have already gone over and at least part of these have dissolved in the alcohol in the separator.

At 135°C, distillation of alcohol and water from the reactant mixture will be essentially complete. The water-alcohol layer in the separator is preferably drawn off and recycled to the steam generator which provides the flushing steam. This will eventually lead the lighter hydrocarbons back to the reaction vessel and will tend to suppress further formation of these. Alternatively, water and alcohol can be separated and only the water recycled to the steam generator. This will prevent "boiling" in the reaction vessel caused by re-evaporation of recycled alcohol.

The temperature of the oil can be raised continuously or kept at one or more temperatures (after the steam supply has started at approx. 130°C) Maintaining a low temperature for an extended period of time promotes the production of lighter products but also leads to steam stripping of the heavier supply material from the reaction zone.

In the following Table I are indicated the cumulative amounts of the products recovered in the liquid-liquid separator when treating a light crude oil containing 11.75% by weight of hydrogen using a potassium empirical hydrate with an S/K ratio = 1/1 and where the oil was held at each of the indicated temperatures above 140°C for fifteen minutes.

The residue in the reaction vessel was less than 2% by weight of the added oil. During the experiment, approx. 4.7 g of the product again

won in cold trap at -50 C.

It has been found that, except for those oils which have a high naphthenic acid content, whatever light petroleum oil is treated in a batch system without the addition of hydrogen sulphide, the hydrogen, nitrogen and sulfur contents for the different product fractions will lie within certain ranges. Table II below indicates these expected values.

("Below 140°C fraction" is the hydrocarbon material that is recovered when the oil temperature is below 14 0°C. "14 0 - 170°C fraction" is the material that is recovered when the oil temperature is in the range 140 - 170°C, etc.)

Many variations in the treatment sequence are possible. One or more of the product fractions can be recycled to the reactor for further cracking. For example, it is possible to recycle all of the product fractions recovered at an oil temperature above 140°C and thus essentially only produce a 140°C net product. Another variation is regeneration of the empirical hydrate reagent. This involves recovering hydrogen sulphide in the steam stream withdrawn from the reactor and treating the potassium compounds that are left back in the reactor. To recover t^S in the steam stream, the steam from the reactor can be passed through a water-cooled cooler, as previously indicated, and uncondensed material is passed there through an alcohol washing device to remove lighter hydrocarbons because these will prevent the recovery of hydrogen sulphide in the next step. (The alcohol wash solution can be recycled to the steam generator.) The remaining gas stream containing I^S is fed to an alkali metal hydroxide-in-alcohol solution which removes the hydrogen sulfide in the gas stream by forming regenerated empirical hydrate of the alkali metal hydrosulfide or sulfide in a manner similar to the preferred method of preparation of new reactant.

Preferably, a multi-stage I^S scrubber is used and the steam effluent from the last stage will essentially not contain any hydrogen sulphide.

In order to recover potassium in the reactor (if a potassium reactant is used) and regenerate the reactant, the solids in the reactor, including polysulphides and metal compounds formed during the reaction, are drawn off, and approx. 3 moles of water per moles of potassium are added to give an aqueous solution. Optionally, a volume of alcohol can be added in an amount equal to or less than the volume of an aqueous solution. The alcohol stabilizes the course of reactants during the subsequent processing. The mixture is then cooled to below 22°C which leads to the formation of some alkali metal hydroxide after which hydrogen sulphide, which may be recycled E^S from the main reactor, is bubbled through the blading during cooling to maintain the temperature below 22°C. This causes sulfur to precipitate and the liquid to separate from the solids. The liquid is then heated to drive off most of the water and alcohol (if any was used) and a melt of the empirical potassium hydrate is obtained.

In the case of potassium reactants, heating to a temperature of 105-110°C under a water atmosphere will give an empirical hydrate melt containing approx. 35% by weight bound water. The melt is then dissolved in just enough low-boiling alcohol (preferably methanol or ethanol) to give a saturated solution. (More dilute solutions can be used but will require additional energy to evaporate excess alcohol). In the case of potassium reactants, at room temperature approx. 150 ml of methanol or somewhat more ethanol may be necessary to dissolve 1 g-mol of KHS. Hydrogen sulphide is bubbled through the solution at a temperature above 60°C which leads to a dissolution of the empirical hydrate reactant in alcohol. The solution is then ready for use in the hydrotreatment reactor. However, it is desirable that the solution is first used to wash the hydrocarbon products. This clears the distillates, removes free sulfur therein and tends to improve the efficiency of the reactant.

In a further preferred embodiment, hydrogen sulphide is fed into the reactor. The added E 2 S tends to suppress cleavage or deactivation of the reactant and as noted above depending on when the flow-through is started will vary the degree of cracking so that this either increases or decreases. The minimum and maximum amount of hydrogen sulphide that can be used with advantage is not currently known.

The following examples illustrate the invention.

EXAMPLE 1

164.5 g of Texas crude oil, 2 g of elemental sulfur and 40 ml of methanol solution containing 15.2 g of KHS and 7.6 g of water bound in an empirical dihydrate were introduced into a flask and the contents were stirred by nitrogen introduced below the surface of the liquid near the bottom of the bottle. The bottle was heated using a heating mantle and a steam generator injected steam into the liquid in the bottle. The steam flows were started when the liquid temperature in the bottle was approx. 120°C.

Leaving overhead vapors were introduced into a water-cooled condenser and the condensate was collected in a bottle. During operation, the methanol-water condensates from the water-cooled condenser were periodically returned to the steam generator. The hydrocarbon condensates for different oil temperatures (fractions) were periodically removed and analyzed. The non-condensed vapor was passed through a solution of 0.5 mol KOH in 100 ml of methanol (where essentially all H 2 S was removed) then again through a water scrubber (to remove methanol) and then through an isopropanol-solid CO 2 ~ bath, to remove lighter hydrocarbons. Analysis of the crude oil and the product fractions is shown below.

There was no carbonaceous residue in the reaction flask and the condensate from the cold trap amounted to 22 ml.

The data shown indicate that the present method hydrogenates, denitrogenates and desulphurises. All the product fractions contain (in the weight fractions) more bound hydrogen, less bound nitrogen and less bound sulfur than the crude oil (The distillate from the cooling trap was not analyzed but obviously the fraction contains a larger proportion of bound hydrogen than the crude oil).

EXAMPLE II

200g of Alaska crude oil? was treated using the method of Example I except that introduction of the steam stream was started at 135°C and that a cooled trap was not used. Analysis of the crude oil and products is shown below (there was essentially no oil residue in the bottle).

EXAMPLE III

175 g of Trinidad crude oil was treated with 30 ml of a methanol reactant solution containing 11.4 g of KHS and 5.7 g of bound water in the empirical hydrate. Due to its high content of naphthenic acid, this oil will be easily degraded by water. Thus, a minimal amount of steam was used (the steam generator was kept at 99°C at sea level) and gaseous hydrogen was also flushed in. Analysis of the crude oil and products is shown below.

Due to the apparatus construction, hydrogen could not be introduced close enough to the bottom of the reaction flask to contact the material closest to the bottom, which is the reason for the 20% residue.

EXAMPLE IV

150 g of a light Arabian crude oil, 2 g of elemental sulfur, 40 ml of methanol solution containing 15.6 g of KHS and 7.8 g of bound water in the empirical hydrate were introduced into a reaction flask and the experiment carried out as in Example I, except that the steam flow was started at 130°C. Analysis of the crude oil and the recovered products is shown below.

EXAMPLE V

A "straight-run" vacuum residue (prepared at an initial boiling point under vacuum at 593°C) and a methanol solution of KHS (0.47 g KHS/ml solution) were introduced into a reaction flask. Heating was started and the contents of the reactor were stirred with nitrogen from room temperature to 170°C, at which temperature the nitrogen flow was stopped and the steam flow started.

o o o The experiment was stopped when the residual temperature reached 4 00 C at which temperature the residual remaining in the bottle was 51% of that originally introduced. Analysis of the residual straw material and two distillates is as shown below.

EXAMPLE VI

The starting material according to example V was again treated with the KHS reactant, but this time hydrogen was used for it

to stir the system from room temperature to 24 0°C. Steam inflow was started at 170°C. The experiment was stopped at 425°C at which temperature the coked material back in the reactor constituted 9% of the original raw material introduced into the bottle. Analysis of the raw material, of the two collected distillates and the rest in the bottle is shown below.

Chromatographic analysis of the uncondensed gas stream indicated that it contained 30.52% hydrocarbons, broken down as follows:

The rest of the gas flow (69.48%) is assumed to be air in the gas chromatography tube. The condensed distillates were very light and none were heavier than #2 fuel oil or diesel oil. Further absence of precipitate in the offgas scrubber containing an alcoholic solution of KOH indicated that little or no carbon dioxide was formed in the reactor.

EXAMPLE VII

150 ml of another vacuum residue and 22 ml of a methanol solution containing an empirical hydrate of KHS (0.477 g of KHS per ml of solution) were introduced into a reaction vessel and heated. Nitrogen stirring was used from room temperature up to 190°C after which the nitrogen flow was stopped and the introduction of steam (superheated to 140°C) was started. A single distillate was collected and held at 100°C to drive off the water. The hydrocarbons that did not distill over with the water are designated the "100 - 4 25°C fraction" and those that distilled over were designated the "below 100°C fraction". Analysis of the residue, the two hydrocarbon products and the remaining residue in the bottle is shown below:

EXAMPLE VIII

Example VII was repeated only with the change that hydrogen was used instead of nitrogen from room temperature up to the final temperature of 4-25°C. At the end of the experiment, the same amount of residue (20 g) remained in the bottle. Analysis of the starting material and the one distillate is shown in the following:

EXAMPLE IX

160 ml of the vacuum residue used in Examples VII and VIII and 25 g of dry, commercially available NaHS flakes (technical grade) were introduced into a reaction flask. This material is itself in an empirical hydrate form. Methanol was added to the steam generator. Hydrogen stirring was used throughout the experiment while steam flow was initiated at 220°C. Analysis of the raw material used and the single distillate is shown in the following:

EXAMPLE X

A cracked residue and an alcoholic solution of the empirical hydrate of KHS (0.47 g KHS per ml of solution) were introduced into a reaction bottle. Nitrogen stirring was used from room temperature up to 190°C, at which temperature the nitrogen flow was stopped and steam inflow started. At the end of the experiment, 13.3% of the original residue (in an uncoked state) remained in the bottle. The one distillate was kept at 100°C to evaporate condensed water. Hydrocarbons that evaporated with the water were recovered and dried and designated the "Below 100°C fraction". Analysis of the starting material and the two products obtained is shown below.

EXAMPLE XI

Example X was repeated except that hydrogen and not nitrogen was used from room temperature to the final end temperature of 450°C along with minimal amounts of steam. Analysis of the starting material and the 3 distillates is shown in the following:

EXAMPLE XII

Example XI was repeated except that commercially available NaHS flakes (technical grade) were directly introduced into the reactor and methanol was added to the steam generator, instead of using the alkanol solution of KHS. The NaHS flakes are themselves in the empirical hydrate form. Analysis of the starting material and the two distillates is shown in the following.

EXAMPLE XIII

125 ml of a cracked, desulphurised residue, 1.8 g elemental sulphur-

el and 25 ml of an ethanol solution of the empirical hydrate

of KHS (0.24 g KHS per ml solution) was introduced into a flat-bottomed flask which was placed on a hot plate containing a magnetic stirrer. The contents of the bottle were quickly stirred and heated to 120°C to drive off ethanol and water from the reaction mixture and heating continued. Introduction of a steam stream was started at 130°C and brought to a final temperature of 325°C. Analysis of the starting material, the two distillates and the residue in the bottle is shown below.

EXAMPLE XIV

In this experiment, hydrogen sulphide was simultaneously fed to a two-stage reactor to treat a vacuum residue. 50 ml of a methanol solution of potassium hydrogen sulphide empirical dihydrate (0.38 g KHS/ml solution) was introduced into the first reaction step, namely a vertical, cylindrical vessel with a total volume of approx. 1 1 and provided with a heating jacket. 25 ml of the reactant solution was introduced into the second reaction vessel, namely a round bottle fitted with a heating jacket. The H 2 S gas fed to the first stage was introduced below the surface of the liquid near the bottom of the vessel by means of a purge tube. Similarly, steam passing over from the first stage was fed into the second stage below the surface of the liquid therein by means of a flush pipe. Steam from the second stage was cooled and partially condensed in a water-cooled unit.

At the start of the experiment, several hundred grams of the vacuum residual output material were heated (so that the material would flow) and placed in a further vessel directly above the first stage reactor. Some of the starting material was introduced into this reactor and both reactors heated. At the same time, the flow of steam, nitrogen and hydrogen sulphide into the first stage reactor was started. The I^S flow could not be measured but was assumed to be 3 g mol/h. As the temperature rose in the first stage, the methanol and water in the added empirical hydrate distilled over and into the second stage which was held at 110°C to prevent condensation of water therein. The reaction in the first step began at approx. 370°C. During this experiment the temperature rose in the first stage from 370 - 390°C and in the second stage from 110°C to 270°C. A total amount of 286 g of residual starting material was added to the first step during the experiment and less than 10 g remained in the first step at the end of the experiment. Analysis of the vacuum residual feedstock, the product remaining in the second reaction step, and the product collected therefrom. cooled unit is given in the following:

The final product had an initial boiling point of 23°C and a peak distillation temperature of 118°C. Non-condensed product steam was assumed to be approx. 35 g. The second stage and final products were 17.4 and 50.4 degrees API at 18°C, respectively, compared to 6.0 for the vacuum residue feedstock. The metal content is given below, given in ppm, "N/D" indicates not detectable.

EXAMPLE XV

Shale oil was treated in the first stage reactor of Example XIV using a methanol solution of the empirical hydrate of KHS, steam and nitrogen, but not H2S. Analysis of the shale oil, the products and the reactor residue is given below.

In contrast, non-condensable volatiles amounted to 43 g. Metal contents are given below in ppm unless otherwise indicated, "N/D" indicates non-detectable amounts.

EXAMPLE XVI

A heavy crude oil of 10.5 degrees API at 18°C was treated with the reactant, steam and hydrogen sulfide using the apparatus and procedure of Example XIV, except that the second stage reactor was not used and 100 ml of the reactant solution was used. A single product was obtained at 370-390°C. Analysis of the crude oil and the product is given below. At the end of the trial, less than 2% remained

of the original crude oil in the reactor.

The product was 24.3 degrees API at 18°C and had an initial boiling point of 110°C and a final boiling point (97% recovery) of 360°C. The metal contents are given below in ppm, "N/D" indicates no detectable amounts.

Claims (6)

1. Process for hydrotreating, hydrocracking, denitrification or demetallisation of carbonaceous material, except for coal, to give essentially normal liquid hydrocarbon products with increased hydrogen content, compared to the carbonaceous starting material, by treating this in a reaction chamber with a reactant comprising an empirical hydrate of the sulfur-containing compound, comprising alkali metal hydrosulfides, alkali metal monosulfides, alkali metal polysulfides or mixtures thereof, optionally in the presence of hydrogen, characterized in that the reaction mixture is supplied with steam, preferably after the reaction mixture has been heated to a predetermined temperature, in which temperature, pressure and other reaction conditions are maintained so that essentially no liquid water is present during the treatment. 2. Method according to claim 1, characterized in that hydrogen sulphide is also fed into the reaction chamber. 3. Method according to claims 1 or 2, characterized in that hydrogen sulphide formed in the reaction vessel is recovered and recycled to it. 4. Method according to any of the preceding claims, characterized in that the bulk temperature in the carbonaceous material in the reaction vessel is kept at 40 - 140°C and that the pressure in the vessel is kept at approx. atmospheric pressure. 5. Method according to claim 1, characterized in that potassium hydrosulfide and/or sodium hydrosulfide are used as metal hydrosulfide and that elemental sulfur is optionally added to adjust the sulfur to alkali metal content to be in the range of 0.55/1 to 1.5/1. 6. Method according to any one of the preceding claims, characterized in that vapors containing hydrogen sulfide and hydrocarbon are withdrawn from the reaction vessel and that the hydrocarbon is recovered from the vapors.