GB2076012A - Conversion of Shale Oil and Shale Oil Rock - Google Patents

Abstract

Conversion of shale oil, shale oil rock, sandstone or limestone with encapsulated kerogens or other precursors of like kind, as source materials thereof, yield low viscosity, hydrogenated products, and allow ammonia, sulfur, and metal value recovery from these source materials; these source materials are reacted in the presence of an alkali metal hydrosulfide or alkali metal sulfide or polysulfide reagent and steam, water or an alkanol, optionally with hydrogen sulfide.

Description

SPECIFICATION Hydrocarbon, Ammonia and Metal Value Recovery from Conversion of Shale Oil Rock This invention relates to a process for producing valuable hydrocarbon materials from a crushed or comminuted rock material which contains carbonaceous values; more particularly, this invention relates to an economically attractive process for production of various hydrocarbon materials such as gases and distillates to obtain valuable fuelstock, feedstock, or starting materials from sources heretofore believed to be prohibitively expensive and unattractive for various economic or environmental reasons, These carbonaceous source materials are often classified under different names but are in general, intended to encompass those which have carbon present in one form or another, i.e., as mixtures of inorganic carbon and organic carbon with various hydrocarbon forms, including nitrogen, oxygen, sulfur, etc., dispersed or distributed in an inorganic rock matrix. Typically these are shale oil rock, gilsonite, kukersite, sandstone or limestone containing encapsulated kerogens of various forms or any other derivatives thereof including the retorted or extracted products of such rock formations, ("the shale oil rock" hereafter) and the "shale oil".

As a result of the novel process, it is now possible to remove these hydrocarbon values from the rock formation in excellent yields, at low expenditure of energy, without retorting the rock (and thereby losing a large fraction of the total heat value from the hydrocarbon values in the rock). Moreover, according to the present process, it is readily possible to convert, by a combination of process steps, and appropriate use of selectively chosen reagents, this source of carbonaceous material to a number of products. Additionally valuable by-products such as ammonia are obtained in good yields.

Background for the Invention In my copending U.K. Patent Application No. 8024908 filed 30th July 1980 and my copending UK Patent Application Nos. 8111836 and 8111859 filed today, I have disclosed various processes for treating coal or heavy hydrocarbon values to obtain lighter values thereof such as gases, light distillates, or distillates. In my two recently issued U.S. Patent Nos. 4,248,693 and 4,248,659, other hydrocarbon value treatment processes have been disclosed.

The present process represents a further advance inasmuch as the extraction of hydrocarbons or carbonaceous values, or work-up of the products thereof, by the herein disclosed process, has to my knowledge not been disclosed as relating to shale oil rock. Moreover, the outstanding yields make possible, for the first time, an economic utilization of the plentifully available materials, based both on the organic and inorganic carbon present in these source materials. Further, a combined hydrocarbon, ammonia and additional metal value recovery from the shale oil rock makes this process more attractive for more complete utilization of this type of hydrocarbon source material. Hence, a number of countries which are dependant on energy imports may now be able to satisfy their energy needs, while at the same time, obtain valuable by-products from these source materials.

Brief Description of the Invention The present process in its salient features, comprises treatment of a rock containing carbonaceous values. The present process further relates to the upgrading of heavy retort products from these rocks. As one of the preferred embodimentes, shale oil rock in comminuted or crushed from is treated with an alkali metal hydrosulfides, sulfide, polysulfide, or hydrated forms thereof, mixtures of these sulfides, (including the hydrates), and mixtures of each of the alkali metal sulfide species with other alkali metal hydrosulfide, sulfides or polysulfides (including the hydrates thereof), in molten or liquid form, in the presence of water, or steam and most advantageously in the presence of these and also hydrogen sulfide-whereby the obtained product is recovered in a product form, such as, a gas, a light distillate, or a distillate.These hydrocarbon products have increased hydrogen content as compared to the carbonaceous source material and as a result of the smaller molecule, are readily driven off from the rock matrix at low temperatures and at atmospheric pressure. Moreover, the advantages of the present invention are equally applicable to present day low quality retorted products from these source materials.

In distinction from tar sands, shale oil rock contains on an average from about 5% to about 60% by weight, and higher, of bitumens and kerogens associated with a number of other components, such as iron in various forms of iron salts, calcium salts, e.g. calcium carbonates, magnesium salts; e.g.

magnesium sulfates, carbonates, etc. Compositions of rock and these salts are adequately set forth in books, such as by T. F. Yen et al., Oil Shale, Elsevier Publ., Co., New York, N.Y. 1976, and T. F. Yen Science and Technology of Oil Shale, Ann Arbor Science Publishers, Inc., Ann Arbor, Mich. 1976, and incorporated by reference herein. The carbonate portion of the shale oil rock is defined as inorganic carbon and may encompass up to 10% by weight of shale oil rock. An unknown portion of this carbon may also be converted into hydrocarbons. A bitumen portion of the shale rock is fairly small. Yields are based on all carbon present. This inference is warranted from the yields obtainable when practicing my invention, as the yields indicate a 100% plus kerogen conversion to hydrocarbons.Inasmuch as a severe attack on the shale oil rock also causes an attack by the reagent on the oxides and carbonates in the shale oil rock, it is important to conduct the initial reaction, i.e. pretreatment and first stage, in such a manner so as to minimize the attack on non-hydrocarbon producing components in the shale rock by either the potassium or sodium hydroxide, hydrosulfide or sulfide. At the same time, it is desired to recover any valuable components in the shale oil rock such as heavy metals, e.g. V, Ni, Mo, U, etc.

which are obtained as e.g. water soluble complexes of molybdenum (in most forms), and vanadium.

Most of iron, cobalt and nickel will precipitate as hydroxides as a flocculent by the reaction with the reagent Inasmuch as the complex components of the shale oil rock are different for each shale oil rock obtained at different locations throughout the world, by necessity, some adjustments are needed for each rock treatment, these will be further discussed herein.

These and other aspects of the shale oil rock reactions have required a number of considerations which have made it necessary to consider shale oil rock recovery as an entity to make the herein disclosed process a success when applied to a material in which the hydrocarbon values are encapsulated or distributed in a matrix of other materials in a "diluted" form, and where the matrix components reactions must be considered as an important aspect to make the total process a success.

In order to illustrate the invention, drawings have been enclosed wherein: Figure 1 illustrates a schematic reaction train for a single stage process for upgrading retorted shale oil; Figure 2 illustrates a schematic reaction train for a multi-stage process for upgrading retorted shale oil, including recovery of reagent; Figure 3 illustrates a schematic reaction train for recovering hydrocarbon values from shale oil rock, including by-product value recovery, and reagent recycling, as practiced in a reaction sequence in a number of different reactors; and Figure 4 illustrates a schematic reaction train for recovering hydrogen sulfide.

Detailed Description of the Invention and Embodiments Thereof With reference to the drawings herein which will serve to describe the process, Figure 1 shows a removal of ammonia and sulfur and a pretreatment stage for the work-up of retorted shale oil. As an example, shale oil contains about 1.2 to 1.5% of nitrogen by weight and from 5 to 7% sulfur, by weight.

In this pretreatment step, shale oil is merely admixed with the reagent, e.g., comprised of KHS, K2S5 in alcohol (with some water present). At ambient conditions, but typically at below 600C, the admixed reagent and shale oil is mechanically agitated. If heat input is necessary, it is by means of heating coils shown in Figure 1. At this temperature below 600 C, copious amounts of ammonia are given off but only as long as the temperature is kept below about 600C. Ammonia is recovered in a manner well known in the art, e.g., in water. Ammonia removal also seems to increase the API number but the increase may also be due to sulfur removal. Sodium reagents expel less ammonia, whereas potassium reagent will reduce ammonia from 1.5% to about 0.1 to 0.1 5% by weight, for sodium it is 0.6 to 0.7% by weight.

Potassium hydrosulfide does not acquire sulfur in aqueous solution. Some elemental sulfur is obtained from the organic sulfur species, apparently as a result of denitrogenation. This sulfur is separated by a liquid-solid separation, as a result of a slow stirring (about 20 r.p.m.), and the reaction at this temperature. As a result of this, sulfur in an elemental form will accumulate on the top of the stirred liquid. Ammonia production is by drawing a vacuum in the reaction vessel, such as by aspiration. Elementai sulfur forming is during ammonia production, but may cease sooner. Mechanical skimming means may be used to remove the formed elemental sulfur. The ammonia removal reaction is fairly slow and if not desired, may be dispensed with as additional ammonia and sulfur will be removed during the hydrotreating reaction.Sulfur, so recovered, may be used to reconstitute the reagent as further explained herein. Approximately 1/6 to 2/3 of the sulfur content is removed by this step, of the about 5 to 7% sulfur present in a retorted shale oil. Reactor 11 is emptied from the bottom thereof and the admixed shale oil and reagent are introduced in reactor 12. Of course, in a batch operation, the reaction mass may be kept in a single vessel, e.g. vessel 11, and the stagewise reactions carried out in one vessel, but for sake of illustrating the various facets of the invention, the various reaction stages have been shown separately. Reactor 12 may be operated at a set temperature or the temperature increased step-wise.

Supplementary reagent may also be introduced which consists of, e.g., KHS, K2S2, and K2S . xH 20, etc., dissolved in alcohol or water or dry, is being added as steam or sparged in as liquid water and H2S being added to steam or water streams. Typically, water or hydrogen sulfide is added at about 1 700C. K2S . xH2O, where x is 5, or 2, i.e. various hydrates, is a very active reagent, and does tend to produce mostly gaseous hydrocarbons. At temperatures above 1350C--1500C, the reagent is essentially a melt of K2S or Na2S and their hydrates (in a melted form).

Typicai temperatures at which reactor 12 may be operated are as follows: 220 to 2400C; 280 to 3200C and 360 to 3900C. At these temperature ranges most of the products are obtained, at the higher temperature, it is believed the bitumen fraction is the one yielding the distillate. These reaction temperatures may also be achieved starting at 100 to 1 200C and may be up to 1 350C. At the lower temperature, generally an alcohol solution of the reagent is introduced. The light ends are distilled off from initial temperature to 1 350C, and these consist of gases, and/or light liquid distillates, and an azeotrope of water and the alcohol being used for the formation of the reagent. To keep the ammonia reacting in this condensate, a slight amount of KOH or NaOH is added to the solution, i.e.in an amount effective to drive off ammonia. Ammonia is collected in an additional vessel.

These products are collected in vessel 14 as gases, and a two layered liquid, the top being the light hydrocarbon distillates, if present, the bottom being a water-alcohol mixture. Alcohol-water is used as a starting material for subsequent formation of the reagent.

The gases and light distillates are used in a distillation column-reactor 18 where these are introduced at the bottom of the distillation column part of the reactor column 1 8.

Distillation reactor column 1 8 is held at a temperature from 220 to 2400C. The reagent is introduced at the bottom of column 1 8. However, as it is well known, the reagent, which may act as a catalyst in subsequent distillation, may be in many forms for the contact with gases and/or liquids.

In order to provide hydrogen for the hydrogenation of the shale oil constituents, water, and to a much lesser degree, hydrogen sulfide are introduced with the reagent (or separately from it), at the bottom of the reactors 1 2 and 1 8. As the shale oil becomes hydrogenated, it becomes lighter and rises in the column and is recovered as top distillates in single or multiple cooling column(s) shown as 19 and 20 in Figure 1. As the reagent builds up, if it is properly selected, it is recovered in liquid or solid form at the bottom of column 1 8 and recovered for further use as will be explained herein. The gases recovered with light distillates from vessel 14 may be recovered after condensation and introduced in the column 1 8 through a fritted disk 17, or a screen.In Figure 4, further discussed herein, the gas separation is illustrated, and for sake of convenience, in Figure 1 the separation is shown schematically.

When gases are reacted in the reactor 18, a competing hydrogenation-dehydrogenation reaction also takes place, such as when some K2S5 is being used at that temperature. By appropriately adjusting the temperature at which the bottoms in column 1 8 are held, the water content in column 18, and the H2S content in column 18, the desired end product cuts are obtained as will be further shown herein.

In general, it has been found, e.g., that a 16,200 BTU/lb shale oil may be upgraded to about a 19,000 BTU/lb.

Energy-wise, however, the thermal shale oil retorting process is wasteful: it may be necessary, if the shale oil rock process as disclosed herein is not feasible.

Feasibility is affected by the shale oil rock constituents which may consume undue amounts of reagent. However, the major merit of this invention is in the treatment of the shale oil rock, and to this end, the various discoveries disclosed herein are used to minimize the reagent consumption and/or increase product yield.

With reference to Figure 2, it illustrates a multi-stage shale oil treatment process, including a reagent recovery so as to provide, for a fully continuous process, predetermined product streams from the shale oil starting material.

In accordance with the process as shown in Figure 2, in the pretreatment vessel or reactor 11 0, the same process is carried out as described with reference to pretreatment reactor 1.1 of Figure 1, hence, the description will not be repeated. Similarly, in reactor 11 2, the same reactions take place as in reactor 12 of Figure 1, but the supplementary reagent is supplied from the reagent recovery train as will be further described herein. From reactor 112, the bottom products are sent to a second reactor 11 6. The top fraction from reactor 112, is separated into two layers, the light hydrocarbon distillates and a mixture of water and alcohol, the light distillates and gases, if any are recovered, in the same manner as described with reference to the Figure 1 process.The bottoms of reactor 112, i.e., shale oil and reagent are in a proportion of about 3 gr of reagent to 1000 gr of retorted shale oil to 20 gr reagent to 1000 gr of shale oil. The reagent is substantially free from admixed alcohol. Hydrogen for hydrogenation in reactor 11 6 is supplied by water at an approximate rate of 1 5% to 100% (as liquid), of the amount of hydrocarbon condensate removed as liquid by volume and the difference between the hydrogen content of the initial and obtained product (on a 100 gr basis), converted back into the amount of water reacted, i.e. x9 (amount of water necessary for obtaining hydrogen which reacted).

These two values are added together and give the total amount of water used. Efficiency of water introduction, i.e. for purposes of reacting, determines the percent of water needed, the lower percent indicates higher efficiency. The primary purpose for the use of hydrogen sulfide is to minimize amount of reagent used and to keep the reagent in stable and active condition.

Inasmuch as the temperature in the reactor 11 6 is considerably higher then in vessel 112, heating may be supplied as needed through internal or external heating coils. The reactions in the vessel 112 are either endo or exo-thermic, based on the catalyst used. Hence, the heat balance may be readily maintained by means of the heating/cooling coils, adjustment of reagent composition or the selection of appropriate temperature levels.

Bottom products from reactor 11 6 are introduced into a still further reaction vessel 11 8 for additional hydrogenation and recovery of the reactants.

The top fraction of reactor 11 6 is refluxed in reflux column 11 7 with the top product from reflux column 117 being withdrawn at, e.g. 225 OC. This 22 5 OC boiling point fraction may also be worked up as shown in Figure 2. All of the liquid distillate from reactors 112, 11 6 and 11 8 may be introduced into reactor 121.

In reactor 118, the shale oil product and reagent are heated in the range from 3600C to 4000C with the reagent being recycled from the bottom of the reactor to meet the upcoming reaction product, typically the higher temperatures produce lighter fractions including gases, but the end product depends on the reagent type and the alkali metal to sulfur ratio. At a higher sulfur content ratio for the reagent, the tendency is to dehydrogenate and reform the lighter ends to form heavier fractions.

However, it will depend on the amount of water being added. Hence, if more water is being added, the competing hydrogenation reaction will have a more pronounced effect, Further, the reagent will be maintained in its more hydrogenation active form. As the reagent builds up in reactor 11 8, it is withdrawn, e.g., by a three-way valve 120.

Returning now to a work-up of the reflux fraction recovered from column 117, it may be reacted in a further column 121 as further described herein. The reagent in column 121 for that purpose is predominantly K2S and KHS in alcohol. As is well known, from the overhead product, the alcohol fraction may be readily separated, e.g. see Figure 4. In the reaction column 121, water is added at the above explained rate. This allows sufficient hydrogenation to obtain a product via reflux column 123, which is at a boiling point of about 1 600C but a range of products may be obtained. A spent reagent system is joined with the reagent from reactor 11 8 and returned for reconstituting and recycling of the reagent as follows.

In reactor 123, the hot reagent, e.g. at 39O0C, is cooled with cold water. After cooling, water is added in an amount of about 1 to 2:1 water to reagent. The reaction with water reconstitutes the reagent by forming an alkali hydroxide and alkali sulfide. When the solution is cooled, other metal values precipitate, except that vanadium (molybdenum remains, under some conditions, soluble) is soluble and is removed by electrowinning when sufficiently concentrated in the solution. Generally up to two mols of water/per one mol of the alkali (on elemental basis of the alkali) may be used; the lesser amounts are preferred.

The recovery of the heavy metals offers one of the benefits of the process and allows this process to be cost effective.

The reagent product stream from reactor 123 is withdrawn and filtered in filter 124 to remove contaminants and suspended flocculents of heavy metals, or any suspended particles. In reagent reconstitution vessel 125, the reagent is further cooled when the same is admixed with a cold alcoholwater azeotrope solution and hydrogen sulfide. The reagent has a certain solubility in the alkanols, (which decreases with increasing carbon atom content in the alkanol). Hence, as has been described by me before, the preferred alkanols are methanol and ethanol. That part of the reagent which has been taken up by the alkanol is the part used for the reaction, but the water content (needed in the hydrogenation and for hydrate formation), may also be augmented with a mixture of alcohol-reagentwater.A small portion of water is necessary so thatthe alkali sulfides form the hydrates in the alkanol.

In general the ratio of the alkanol to water is the lower boiling point, azeotropic mixture boiling water at about 880C (methanol-water).

As can well be appreciated, the reagent recovery is readily accomplished, especially since hydrogen sulfide is plentifully available, from reactor 123 on heating, or as recovered as shown in Figure 4. Hydrogen sulfide introduced in the reactor 125 then reacts with the alkali hydroxide to form the respective sulfides. This must be done under cooling conditions. As the sulfide reaction in alkanol is temperature, concentration, and solvent dependent, many species of the alkali sulfides, e.g., potassium sulfides may form if the temperature is not properly maintained.

As the reagents represent mixtures in vessel 125, it may be used as such for reactor 110 and may be diluted with alcohol. But individually prepared alkali metal sulfide species may also be prepared or reconstituted for reactions such as in reactors 116,118 or 121, with the reagent then being a selection of a narrower mixture. It has been the practice for the above-described process to use reagents of a certain alkali metal to sulfide ratio. This will be elaborated later on in this disclosure.

With reference to Figure 3, it illustrates a process whereby shale oil is obtained directly from rock, either from organic and/or inorganic carbon species, by means of the herein disclosed reagent. In accordance with this aspect of my invention, shale oil rock comminuted to about 1/4 inch particles and less are fed into a hopper 210 and via an auger feeder 211, admixed with reagent. The reaction, however, is independent of the rock size. The reagent is in liquid form and coats the rock particles. As a practical matter, the reagent is introduced through a port 21 5 in the auger feed barrel in metered quantities such that from about 5.0 grams to 30.0 grams of reagent such as KHS, (or converted to KHS basis), is added per 1000 gr of rock. Generally up to about 8 grams of KHS per 1000 gr of rock amply suffices.It has also been found that shale oil rock my perhaps be equally, if not more economically, treated with sodium sulfide species. It also seems that the reaction of reagent and water and H2S with shale oil rock is exothermic for some of the shale oil rock-reagent species, as shown by the examples herein. Hence, the coil(s) 213 may be used for heating or cooling as the situation demands.

As long as the process is carried out in a batchwise manner, temperature levels and further temperature increases may be used to achieve the same effect as with shale oil and as previously described above. In that event, steam and H2S are introduced in a predetermined sequence, (after alcohol distillation) if alcohol is used to dissolve the reagent. However, if the temperature is kept high in the reactor 212, then the recovery is only of the formed products, H2Sand water and minimal amounts of ammonia are expelled, except if certain steps are observed.

It has been found advantageous to introduce the reagent admixed with the shale oil rock particles so as to coat the rock particles. As shown in Figure 3, it may be readily accomplished by metering the reagent during feeding of the rock particles. In the reaction vessel 212, which during continuous operation is held at the chosen temperature levels, e.g., 280 to 39O0C, the rock may be agitated by pump(s) 21 7 circulating part of the reactants, be these liquids or gases, to a lower conical portion of the reactor 212 through a plurality of opening ports 218, thereby keeping part of the rock in suspension or using any other stirring means. Similarly, steam and hydrogen sulfide may also be introduced below the rock levels.As the rock is heavier than the reagent and recovered hydrocarbons, the rock falls to the bottom of the conical reactor.

Through an appropriate valve-pump 216, the settled contents of the reactor are withdrawn and discharged or introduced into a scrubber vessel 219. The scrubb water is used in meager amounts as it provides leached out values of reagent precursors or heavy metal values which may be precipitated from the leach solution by the water. The rock residue is pumped out via the valve-pump 216, and then filtered such as on a drum-filter 220 discharging the rock residue as a filter cake. The rock is fairly well pulverized at that point The top products of the reactor 212 pass through a screen, e.g. a York screen 21 2a and consist of ammonia, hydrogen sulfide, gas, distillates, depending on the operating temperature and reagent used, and are worked-up as shown follows.The product gases condensable at cold water temperature are introduced into a second reactor 223 and reacted therein with a supported reagent acting as a catalyst.

For sake of illustrating a number of embodiments, two reactors 223 and 230.

In connection with conventional operation of the process as a two stage operation, the process stream 221 is introduced in a reactor 223 depicted as a plate column where the catalyst is supported on trays, at the bottom thereof. It may be a reactor placed on top of reactor 212, but for sake of easy representation, is shown adjacent to reactor 212. The stream 221 is introduced at the bottom of column 223, i.e. it is introduced co-currently with additional water, as illustrated in Figure 3. A reflux column 224 may be used. It operates in a conventional fashion to remove the desired product cut. If reactor 212 and column 223 are operated in a once-through fashion, then the product streams are recovered from the top of reactor 223, such as by a reflux column 224 and a gas work-up, especially H2S work-up, may be practiced as shown in Figure 4.Ammonia is separated as follows, if the vessel in which water is found, e.g. 430, as a bottom layer with hydrocarbons on top (when no alcohol is used or after the alcohol has been driven off). A slight amount of KOH or NaOH is added to the condensed water, ammonia is expelled therefrom and is then absorbed in another vessel (not shown in which water is formed). Hydrogen sulfide is very slightly soluble in water and therefore passes. Thereafter, hydrogen sulfide is worked up as shown in Figure 4, i.e. beginning with 431.

However, as shown in the dashed section A-l of Figure 3, if the reactor is operated with little if any liquid distillates, but instead the reaction is carried out at a high temperature such as only gaseous top products and/or highly volatile distillates are withdrawn from reactor 212 via line.221, then the reaction products from reactor 212 may be worked-up as follows.

Reactor 230 has therein a reagent in the form of a catalyst. The same as in reactor 223. The reagent is of the type herein described as the catalyst and is a supported catalyst where the support is such as a high surface alumina or potassium aluminum silicate, spinel, or a similar support system typically used in the petroleum industry for reforming catalysts. Although the catalyst has been described with reference to the "reagent", it does function in this instance as a typical catalyst because of the large surface area. Thus, the reactions whereby hydrogen is supplied readily, takes place as aided by the reagent acting as a catalyst. A typical reagent for the first stage is KHS (dry); and for the second stage are K2S and/or K2S2, the last two reagents are in a solid form at the reaction conditions.Other reagent systems are NaHS (liquid bulb), at process conditions in reactor 212, preferably NaHS plus 1/10 mole of Na2S . xH2O (as technical flakes), in second stage K2S, K2S2 and K2S5 or mixtures thereof with K2S predominant. A fairly typical amount of a reagent catalyst is 20 gr/25O ml of carrier in the form of 3/168 spheres of potassium alumina silicate type. The second reactor catalyst has a very long life. Hydrogen sulfide and water are also present, the last as steam. When treating in the second stage, the first stage reaction products sulfur may be reduced to below 3%, e.g. 2% and the products may be in the 40 range of API numbers.

Referring now to Figure 3 again, although the catalyst is suspended in a basket 232, the reaction may be equally well carried out in any column, tower, or reactor in which supported catalysts are distributed. More than one column may be used in parallel or in series, or alternate columns may be employed. As shown in Figure 3, the basket is removable and rests on a rim 234 the brim 235 of the basket 232 being used as a funnel. In the reactor 230, water is augmented. A further reactor, the same as 224 is operated at a temperature between 1 350C and 1 500C and treats the entire gas stream.

However all condensate are separated and are hydrocarbons. The reagent is a hydrated melt of K25. 5H2O and the gases are bubbled through this melt. The liquid hydrocarbons will build up above the melt and tapped at an appropriate level. Similarly, two previously described reactor 230 may be used alternatively one at one time and the other while the catalyst or reagent is changed and/or removed and finally reconstituted for the other.

In Figure 4, a schematic illustration of a hydrogen sulfide gas recovery is provided. A reactor 422, typically at 3200C to 3900C has been charged with shale oil rock, a reagent in liquid or solid form, water, in the form of steam, and hydrogen sulfide gas are treated and/orreacted as previously described. Thereafter these gases are cooled in a condenser, e.g. 426. A cooling jacket 424, surrounding the condenser 426 facilitates the cooling of the reaction gases. The initial and heavier products are recovered from condenser bottoms 427. The gaseous products are sent on to vessel 430 in which water or alkanol (typically methanol or ethanol) are held as a KOH solution. 1 mole of KOH and 1 mole water at 400C is held there. Alcohol solubility is such as 1 mole of KOH in 123 ml of methanol or 190 of ethanol.The selected solution in vessel 430 is kept cold, thus, the lighter gases pass through such as the C, to C5 including hydrogen sulfide. If alcohol is used C3 is is absorbed and C4 and C5 are soluble, therefor, water solution is preferred.

In vessel 431 the contents are cooled to about -350C at which temperature liquid C4 and C5 are removed. While most of C4 and C5 fractions are removed in vessel 431, some still are carried over to vessel 432 where these are removed at -300C with the C3 fraction in ethanol or methanol. A fritted glass disk 433 removes any residual mist of these components. At this state substantially only H2S and C and C2 fractions are present in the gas stream which is then introduced into vessel 435 containing KOH and alcohol, typically ethanol or methanol in water solution. Hydrogen sulfide therein reconstitutes the reagent, which is recovered as a precipitate while the light fraction gases predominantly C1 and C2 pass.At up to about 97% conversion of KOH to KHS, no H2S passes and is thus recovered as a reagent component and may be reused (or used in system if KHS is converted to K2S5, by dissolving sulfur, equal molar amounts are formed). If necessary, more than one scrubbing vessel 435 may be used to remove hydrogen sulfide. No H2S is vented to air. The alcohol-water fraction from vessel 430, obtained during start up, is used to replenish the alcohol dragged out from vessel 435. However, this mixture must be cooled in heat exchanger 436.

While the recovery of alcohol and water has been shown in Figure 4, equally applicable is the recovery scheme if the reagent is used in a "dry" form, i.e. without alcohol dilution. In that case, alcohol is present only in vessel 435 in which the reagent is reconstituted, and only water is present in 430.

Vessel 435 may be operated without alcohol below 4O0C while cooling the exothermic reaction and while water content is kept at or slightly below 2 moles per mole of KOH.

It is to be understood that the foregoing hydrogen sulfide recovery is applicable to the processes as described with reference to Figures 1, 2 and 3.

It is also for that reason that in connection with the process, as described in Figure 3, the reagent is introduced into the reactor vessel 2 2 via auger 211 as a substantially dry reagent, i.e., a product which is in a concentrated from from which alcohol and water have been removed.

The alkali metal hydroxide, such as potassium hydroxide is obtained from the spent reagent reconstituted as shown in Figure 2 or leached out of the rock by water addition, such as shown in Figure 3, where the sodium and potassium as hydroxide is recovered from the spent reagent.

The reagents used herein are the empirical hydrates of the hydrosulfides, monosulfides, and polysulfides of the Group 1 A elements of the Periodic Table other than hydrogen. For various reasons, the francium and cesium compounds are not generally used. Thus, the sodium, potassium, lithium, and rubidium compounds will more often be used. The potassium, rubidium, and sodium compounds are preferred. Rubidium, however, is not cost advantageous. Sodium, such as NaHS is most cost advantageous, although potassium is most desirable, e.g. KHS treated product will be about 3 to 50 API lighter due to the more effective ammonia and sulfur removal. For shale oil rock initially treated, sodium hydrosulfide is cost advantageous because of being a melt at process conditions and it is more stable at these conditions with water.Hence, in the first reaction 212, the NaHS species contact best the kerogen fraction due to the lower melting points at the process temperature.

During reaction, in the second reactor, e.g. 223, the reagent is actually a mixture of the empirical hydrates of the hydrosulfide and sulfides (mono and poly) of each alkali metal employed, and during reaction there is an interconversion of these sulfur-containing forms. (As the reaction temperature rises, some of these forms disappear because their decomposition temperatures have been exceeded as further explained herein). Accordingly, the reagent may be charged initially to the reaction zone as the hydrosulfide empirical hydrate or as one or more of the sulfur hydrates or as a mixture of the hydrosulfide and sulfide empirical hydrates.The empirical hydrate reagents may also be made in situ, but preferably they are charged in their empirical hydrate form, but preferably at the higher hydrogen sulfide content, e.g. the hydrosulfide as hydrogen sulfide is being lost at higher temperatures, e.g. at 2000C to 22O0C. Each of the alkali metal hydrosulfides and mono- and polysulfides may have more than one empirical hydrate, but unless otherwise noted, the term "hydrate" is meant to include all the hydrates.

The amount of reagent employed must be sufficient to provide adequate contact with the feedstock and the desired rate of reaction. The maximum amount of shale oil rock that can be processed with a given amount of reagent is different for each shale oil rock formation and can be established with the prescriptions set our further herein.

As it is well appreciated, if the cost of the reagent, such as sodium hydrosulfide is of lesser consequence because of its availability, the reagent recovery is avoidable. Then the eiimination or retention of that step is a separate consideration.

It has been found that if a reaction with shale oil rock is conducted with a certain minimum amount of reagent present, then the reaction gives better yields, all other conditions being equal. For this purpose, the reagent stabilization with hydrogen sulfate being present is best accomplished based on the highest volume fraction of hydrogen sulfide in the reactor which does not impede the reaction. If large amounts of reagent are present, the hydrogen sulfide, as a fraction of the total reactor volume in gas form, cannot stabilize the reagent. On the other hand, if large volume fraction of the reactor is taken up by hydrogen sulfide, the reaction cannot proceed due to the absence of hydrogen from water.

Excess reagent not only attacks the unwanted components in shale oil rock, such as iron in its various forms, but also becomes destabilized, i.e. converts to alkali hydroxides, sulfates, and the reagent, without attacking the carbon components and, in case of alkali hydroxides attacking, e.g. iron component in the matrix. By failing to remove the oxygen, sulfur and any residual nitrogen atoms for the kerogen fraction of the shale oil rock, the wasted reagent can turn the process into an undesirable reaction sequence. These competing considerations are further affected by the components in the various shale oil rock species. These competing considerations are solved or minimized in part by the following. A proper selection of a reagent, e.g. if cheap reagen is available, such as NaHS (an industrial commodity), it may be preferentially used, recovery of the reagent then is not critical.Hydrogen sulfide should be employed in an amount not impeding the reaction (which is best monitored by the rate at which the products are recovered). Steam or water, if sparged in the reactors as a fine mist, is used in relation to the product recovered, e.g. as a rough rule of thumb at about 130% by weight, as based on the amount of hydrocarbon recovered, but the actual rates are as previously explained. This will also take into account any water of hydration or water present in the shale oil rock.

In general, the hydrogen sulfide addition will be on a space time velocity basis and will be typically in a range from 40 to 1 20 ml/min/gal (about 10 ml/min/liter to 30 ml/min/liter) of reactor space with about 20 ml/min/liter being typical. Expressed on another basis, one half (.5) gram mole, and less of H2S is added for 1000 ml of water removed by the hydrogenation reaction.

The reasons for the hydrogen sulfide addition follow from the illustrated reactions.

1. 4KOH+4H2S 4KHS+4H20 When shale oil derived sulfur is present then 2. 4S+6KOH K2S203+2K2S+3H20 in turn 3. K2S203+3H2S K2S6+3H20 the decomposition of K2S2 is as follows: 4. 4K2S2+8H20 4KOH+4KHS+4S+4H20 Hence, if H2S is present, KOH is converted to KHS and if any KOH forms the thiosulfate, then the thiosulfate is converted to K2Ss. Inasmuch as KOH attacks, e.g. iron salts in the gangue, the apparently, preferential, or at least favorably competing, reaction with hydrogen sulfide minimizes the side reactions and makes the process attractive.

Further reactions are as follows: 5. K2S5 K2S4+S (above 3O00C) 6. K2S4 K2S3+S (above 46O0C) 7. KHS+K2S+3H20 3KOH+2H2S 8. K2S+H20 KOH+KHS 9. KHS+H20 H2S+KOH 10. KHS+KOH K2S . xH2O (x can be, e.g., 2, 5, etc., depending on temperature). Hence, enough H2S should be present to keep the reactions, by mass action, in a state, where the reagent is stable, i.e., sulfur is taken up either when freed from shale oil or shale oil rock or from the reagent, and hydrogen sulfide keeps the reagent from hydrolyzing and minimizes free potassium hydroxide formation. Moreover, the thiosulfate generated by the oxygen present in shale oil rock is regenerated during the reaction to the desired K2Ss sulfate. Thus, the reagent is kept in the desired hydrolysis level by H2S.

Of the various reagents, the following are useful because of stability and/or sulfur acquisition ability, KHS, NaHS, K2S, K2S2, K2S3; and of these, the order of preference is as follows: NaHS (because of price and availability); KHS, K2S2, K2S and then K2S3. The other sulfides display instability at their melting points, e.g., Na2S2 at 4450C, Na2S4 at 2750C; or give off sulfur at 760 mm, e.g., K2S5 at 3000C yields K2S4+S; K2S4at 4600C yields K2S3+S; and K2S3 yields K2S2+S at 7800C.Melting points of the alkali sulfides illustrated above are as follows: for K2S at 948 OC; K2S2 at 4700C; K2S3 at 2790C (solidification point); K2S4 at 1 450C; K2 S6 at 2060C; K2S6 at 1900C. Melting points for mixtures of the sulfides (pure or eutectic mixtures) are as follows: for K2S-K2S2 it is 3500C; for K2S2-K2S3 it is 2250C; for K2S3-K2S4 it is about 11 00C; for K2S4-K2S5 it is 1830C. Based on the various illustrations above, appropriate temperature-stability conditions are selected as dictated by decomposition and/or melting point characteristics so as to allow the use of a solid reagent, or a stable liquid reagent. Of course, the various hydrates of the alkali sulfides have various melting and/or decomposition points which, also holds true for the eutectic mixtures. These temperature points may be readily established thermographically as it is well known to those skilled in the art.

Hence, at peak operating temperature e.g., 4000C, K2S5 will yield sulfur, (which is a useful phenomenon as has been explained herein in connection with dehydrogenation of further process streams). Inasmuch as the decomposition temperatures are lowered at lower pressures, the shale oil rock conversion at atmospheric pressure is entirely feasible, although some benefit is gained by operating at elevated pressures, e.g. above 5 atm., the added cost and other expenditures make this merely a less desired method of operating the shale oil rock conversion process. Hence, for practical purposes the variation of the pressure conditions can be from about T atmosphere to about 5 atmospheres, but the ambient atmospheric pressure is preferred.In describing the various sulfides and their decomposition temperatures including the reactions, my U.S. Patent 4,210,526 issued July 1, 1980 is relevant.

It should be understood that there are many competing reactions and the alkali metal sulfide chemistry is very complex. While every attempt has been made to explain the process as it is understood, the basic criterion has been the workability of the process as applied to shale oil and preferentially to shale oil rock. This has been demonstrated herein such as by the examples.

In the case of the potassium reagents, heating to a temperature of 105-11 00C under a water atmosphere will leave an empirical hydrate melt containing approximately 35% (by weight) bound water. The melt is then dissolved in just enough low-boiling alcohol (preferably methanol or ethanol) to form a saturated solution. (More dilute solutions may be used but require additional energy to vaporize the surplus alcohol). In the case of the potassium reagents, at ambient temperature, approximately 150 milliliters of methanol or somewhat more of ethanol are required to dissolve 1 gram-mole of KHS.

Hydrogen sulfide is bubbled through the solution at a temerature not over 600C, resulting in a solution of reagent in alcohol.

Inasmuch as the above-depicted embodiments have been described with reference to the drawings herein, for ease of understanding of the same and in further support of these, various aspects of these processes are presented in the following examples, which are in no manner intended to limit the invention.

Example 1 200 grams of shale oil was obtained by retorting shale oil rock treated in a first-stage reactor.

Hydrogen sulfide was not fed into the reactor which contained fifty milliliters of a methanol solution of potassium hydrosulfide empirical dihydrate (0.38 grams KHS/ml solution). The first reaction stage was a vertical, cylindrical vessel with a total volume of approximately 1 liter and equipped with a heating mantel. Analyses of the shale oil, products, and residue in the reactor are given below.

Analysis Material Amount Hydrogen Nitrogen Sulfur Shale Oil 200 g 9.90% 1.45% 6.23% Below 2800C Cut 22g 10.33% 1.16% 6.85% 280--3000C Cut 35 g 10.59% 0.95% 6.80% Residue 100 g 8.33% 1.47% 5.76% By difference, uncondensed volatiles total approximately 43 grams. Metals content are given below (unless otherwise noted, figures in parts per million; "N/D" indicate non detectable).

Analysis Material Na V K Fe Ni Ca Shale Oil 11 124 64 106 86 1223 Below 2800C 1.2 5 5 N/D 20 280--3000C 0.61 19 4.6 N/D N/D - Residue 21 56 2.89% 34 565 The heavy metals, e.g. vanadium, molybdenum and nickel are recovered as previously explained.

Another batch of the untreated shale oil identified in Example I, was reacted. Its analysis was as follows.

H2 C S C:H API N2 Untreated Shale Oil 10.00% 78.65% 6.27% 1 C:1 .53H 1.8 1.37% Boillng Point Range OF 1096 20% 30% 40% 50% 60% 70% 287 491 547 600 623 641 665 667 80% 90% End Point (669=21.6% residue).

An analysis of first 12% of distillate from a shale oil of the above analysis, treated in a manner as set out above in a single reactor with K2S . xH2O formed from KHS charged in the reactor, showed the product to be as follows: Degrees API @60 F 25.4 Specific Gravity @600F 0.9021 Sulfur % 6.74 BTU per pound 17517 BUT per gallon 131 553 NETBTU 16484 Ash Less than 0.001 Carbon 80.15 Hydrogen 11.32 Sulfur 6.74 Nitrogen 0.68 Oxygen+Undetermined 1.11 Sodium 1.2 PPM Potassium 1.1 PPM Example II Shale Oil as distilled from Shale Oil Rock.

The 2 runs were made with shale oil rock found in Israel. Insufficient oil was obtained from a single run to give a distillation range. The 2 runs were combined to make sufficient oil for the distillation range.

Run No. 1: About 60 ml of the below described reagent solution was reacted with 1900 grams of shale oil rock by merely admixing the rock and reagent solution. A two layer reagent was used of the following composition. To 6 moles of KOH dissolved in 12 moles of water, is added 108 ml absolute EtOH plus moles 4 S dissolved therein. When this solution is made (the exothermic reaction of dissolving KOH in water supplied the heat necessary), a further 2 moles of S in 108 ml of absolute EtOH were added to make an empirical K2S203+2K2S2+3H2O. This reagent forms a two layer solution. 1/3 of the solution with the amounts of the solution taken in the ratios in which the two layers are to each other, are added to an equimolar amount (on basis of K), of a reagent made as follows.KOH+2H2O, with the solution saturated at cold conditions with H2S; another mole of KOH is then dissolved in the solution.

The solution melts at 600C. The reagent is then K2S. .5H2O.

The rock was treated in the reactor with mechanical agitation, steam and H2S @ 80 ml/minute.

The shale oil rock was from Israel.

The reaction proceeded well but at 3200C (approximately) the reaction became exothermic and rose to 4400C. The heat had been turned off at 3200C but the exothermic reaction had begun below 3200 C. Steam was stopped at 3800C but the exothermic reaction proceeded until a peak temperature of 4400C was observed. There were 59 liters of gas produced. Hydrogen made up 69% of the gas, CO2 made up 6% (principally derived from the carbonates of the shale rock), the remainder was hydrocarbon with a carbon content between 1 and 6. 77 ml of condensate were obtained having an API of 29 and a sulfur content of 7.1%.

Run No. 2: About 60 ml of solution of the following reagent was mixed with 2200 grams of Israel shale oil rock. The reagent was as described in Run No. 1 except that KOH+2H2O was saturated at cold conditions with H2S, a further addition of one mole of KH0 was made and a solution obtained. The solution was heated above 1800 C, then .83 moles of sulfur was reacted with this solution. The other catalyst was the same as the above Run No.1, except that no further sulfur was added (vis-a-vis the two moles previously). Equal amounts of solutions on K basis, were added. The reactor for this, as well as the previous run, was a round steel reactor of about one gallon capacity and heated and stirred mechanically. The oil distilled from the rock principally at 220-2400C and at 280-3200C, in the presence of steam and hydrogen sulfide, the last at 80 ml/minute.

The Israel shale oil rock contains 5% hydrocarbon+25% (of the 5%). The sulfur content of the rock is 2.5%.

The hydrocarbon condensate contained 6.25% sulfur, had an API of 31 and the collected liquid volume was about 71 ml. There was an uncondensed distillate consisting of 37 liters of gas which contained 66% hydrogen, 2% carbon dioxide, 1% carbon monoxide, and 28% hydrocarbon which had carbon contents between 1 and 6. Part of the condensate was lost when an excess steam surge blew some of the rock into the condensation vessel.

The distillates from the two runs were combined and 100 ml was subjected to a boiling point determination. The boiling point range determination showed an initial boiling point (1 6O0F) and the end point of 5850F with a 1.7% (by weight) residue. The 1.7% residue contained 3.7% sulfur. The sulfur content of the 0-50% boiling point range product was 7.25%, the sulfur content of the 50% to end point product was 4. 19/0. Thus, the sulfur content of the Israel shale oil extracted from the rock, according to this invention, is greatest in the lower boiling point fraction. The nitrogen content was reduced to 0.1 %. The product as a greenish brown and was clear.

As shown above, a milder reagent, which will cause an exothermic reaction at a higher temperature, e.g. 3600C, was obtained by combining K2S2 . xH2O (obtained by heating K2S . 2H2O at 1 000C in presence of sulfur) with a two layer reagent prepared as above, except that no additional two moles of sulfur were introduced. Again, equimolar amounts of the two reagents were used, based on the amount of potassium (on elemental basis). From the two layer reagent described above, the solution was taken in the ratios in which the two layers are to each other.

As it is evident from this example, mixtures of sulfides of the alkali series may be used, as well as mixtures of the sulfides of the alkali species such as potassium.

Example ill 453 grams of the shale oil rock, as in example II, were reacted with potassium hydrosulfide, KHS, in hydrate form, and in the presence of water. The amount of reagent used was 60 ml of solution of .4 grams of KHS. The potassium hydrosulfide used was an alkanoic solution (methanol and ethanol) of the potassium hydrosulfide and was removed by elevating the temperature to about 1 350C. At that time some of the hydrosulfide had formed a potassium sulfide hydrate K2S xH2O (x is typically 5 at those conditions). Some of the reaction product, which was collected in two condensers in series, was carried over with the distillate. At about 1 6O0C the potassium sulfide hydrate decomposed giving off copious amounts of gas.

Substantial amounts of liquid hydrocarbon condensate from the rock were obtained at between 230 to 2500C, again at 320 to 3500C and at 37O0C, and finally at the peak temperature of 4000 C.

However, at the end of the run at 4009C, there was little condensate. No provisions were made for collecting gases. A total of 25 ml of oil product of a specific gravity of 0.89 and an API Number of 26 were collected as a condensate. Inasmuch as this shale oil rock sample was believed to contain 5% hydrocarbon, the recovery was almost complete, i.e., about 98.2%.

Example IV 453 grams of the same shale oil rock was run with NaHS flakes (technical grade). The amount of reagent was 100 gr. These flakes melt at 11 20C. The melt state is extended by use of inert atmosphere and in presence of water vapor.

The hydrate melting at 11 20C decomposes at a higher temperature with accompanying liberation of water into lower hydrate which is a solid. Water was introduced into the reactor at rate of about 6 ml/minute. During the run described in Example Ill, as well as in this example, no hydrogen sulfide was added. 24.5 ml of the product was obtained in the same manner as in Example lil, and this condensate also had a specific gravity of 0.89 and an API (America Petroleum Institute) number of 26. A second run also gave a product with an API number of 26.

A water wash of the rock gave a green color solution, in fact, a very deep green. This signified the presence of alkaline iron species including other mineral complexes.

When hydrogen sulfide was used, the formation of these complexes (presumably ferrite-ferrate complexes), was reduced considerably and so was reagent consumption.

From the above two examples, it is evident that there is no appreciable difference between the quality and quantity of the hydrocarbon product obtained when sodium hydrosulfide (technical grade in flake form) was used wtih the dripping of water into the reaction vessel and when alkanoic solutions of potassium hydrosulfide and steam were used as the reagents in the process.

However, in later runs it was found that appreciably smaller amounts of reagent could be used when hydrogen sulfide was used in the reaction vessel (thereby improving the economics of the process).

Based on the above illustrations, when practicing a single stage reaction, the API number for the condensate may range such as between about 20 to 32 with the range of about 25 to 30 fairly achievable, with the yields of the product being about 100% and higher, based on the amount of organic carbon present in shale oil rock. For these results to be obtained, hydrogen sulfide presence is highly desired.

For a two stage reaction, with supported catalysts, the API numbers may range in the 40'so Example V 466 grams of shale oil of the type given in Example I was treated with 18.6 grams of reagent in a first reaction vessel and with 1 2.4, grams of reagent in a second reaction vessel.

The reagents were as follows: KHS and K2S . xH2O in the first reaction vessel as well as the second.

The reaction in the second reaction vessel was in a gas phase. The temperatures were in first reaction vessel 3900C peak; in second reaction vessel 2200C.

Analysis of the intial distillate from the second vessel was as follows: Degrees API (B60 F 22.6 Specific Gravity (Bb60 F 0.9180 Sulfur % 5.94 BTU per pound 17411 BTU per gallon 133125 Ash 0.008 Carbon 80.48 Hydrogen 10.66 Sulfur 5.94 Nitrogen 1.05 Oxygen 1.86 Sodium 0.32 PPM Vanadium N/D Potassium N/D Iron N/D Analysis of the final distillation faction:: Degrees API @600F 19.5 Specific Gravity @600F 0.9371 Sulfur% 6.19 BTU per pound 17571 BTU per gallon 137124 NETBTU 16470 Viscosity @ 1000F 41.9 SSU Ash 0.007 Carbon 80.51 Hydrogen 12.04 Sulfur 6.19 Nitrogen 0.96 Oxygen 0.29 Sodium 0.42 PPM Vanadium N/D Potassium N/D Iron N/D Nickel N/D It is noted that while the API number decreased (as it should for the last distillates), the hydrogen content, nevertheless was increased. The above reactions were without the benefit of hydrogen sulfide addition. Addition of hydrogen sulfide does increase the product quality.

In subsequent runs, it was found that decreasing the amount of reagent did not impair the yield as long as hydrogen sulfide was present. As little as 7.5 ml of reagent (KHS basis) could be used to treat 500 gr of oil. The same holds true for shale oil rock, i.e. about 7.5 ml (KHS basis) of reagent will treated 1100 gr of rock, although the quantity necessary to coat the rock effectively, for practical reasons, in an important consideration for assuring a thorough reaction with the rock. The optimum efficiency level is established for each type of shale rock by a necessary series of runs with progressively decreasing reagent amounts and the appropriate use of hydrogen sulfide at the desired space, time, velocity basis, previously discussed.

Some of the potassium hydrosulfide is decomposed following hydrolysis into potassium hydroxide and hydrogen sulfide. At the higher temperature hydrogen sulfide is then recovered by appropriate work-up of the gas or reconversion, such as shown in Figure 4. Potassium hydroxide provides a medium at temperatures of 3600C and higher whereby the calcium carbonate of the limestone residue of the shale oil rock reacts with the potassium sulfate of the reagent residue to form calcium sulfate and a mixture of potassium hydroxide and potassium carbonate. The potassium and sodium content of the shale oil rock residue is also extracted into hydroxide form at this time, i.e. by leaching and is worked up to be resued.

Steam as shown above is employed at a temperature at which the reaction is sought to be conducted, i.e., depending on the type of shale oil rock and the decomposition levels of it constituents, as well as the desired product. For sodium hydrosulfide and sulfide series or reactions, water may be sparged into the reactors. Similarly, for the exothermic reactions, sparging of water helps to control the reaction.

Although the reaction mass of shale oil rock and reagent may be appropriately stirred, it is best to precoat the rock with a reagent in the absence of oxygen, as oxygen has a tendency to destroy the reagent.

For this reason, it has also been found useful to employ a liquid or a dissolved reagent. Liquid, yet stable reagents may be employed for coating the shale oil rock at or above the appropriate melting point of the selected reagent or the liquid eutectic mixture of these.

As illustrated above, the process may employ as a reagent or "catalyst" the alkali hydrosulfides, alkali sulfides and hydrosulfide hydrates. Mixtures of alkali with one another and mixtures of sulfides of each and each other are within the scope of this invention. Of course, the same considerations apply to each alkali metal sulfide hydrate species. From a practical standpoint, sodium and potassium sulfides, and hydrates and mixtures of each of these in their respective series and mixtures of each other in the series are contemplated. Moreover, as further illustrated above, a specific sulfide and hydrates thereof may likewise be employed, especially for the second and further stage treatment of initial reaction products such as when these are subjected to the reaction temperatures above 135 OC.

It is also contemplated that the other alkali compounds in the alkali metal series can be used, but costwise, these are not advantageous although rubidium sulfides are highly active and may in fact, in special circumstances, be usefully employed such as a supported catalyst, e.g., in alumina etc. Cesium sulfides are another species in the alkali metal series which are less useful and also not desirable costwise.

Generally, the number of mols of water of hydration is determined thermographically plotting temperature versus time and observing distinct temperature-time levels, as well as the expelling of water in the form of gas. These temperature levels then indicate the reagent stability.

In addition to the above-mentioned carriers, for the above "catalysts", the following carriers have also been contemplated: spinel, potassium, aluminum silicates in particular, fired bentonite clay, etc.

A reagent attack on the source material, as well as product cut, are also dependent on the chemical composition of the reagent In particular, sulfur content of the alkali metal sulfides governs the severity of the attack, all other conditions being equal. In particular, it is noted that in shale oil rock, the hydrosulfides have the'ability to extract the oil from the rock without inordinate amount of gas production. Hence, this represents, according to my belief the preferred mode to extract kerogen based hydrocarbon values from rock. Thereafter, these values may be hydrogenated by the above described sulfide reagents carried on a catalyst support acting then as catalysts, in the gaseous phase.

In addition, different hydrates of the same alkali sulfides cause different reagent formations, all other conditions being equal. Of course, the hydrates of the above sulfides must be stable at the reaction conditions for the above to apply. The severity of the reaction can be modified by an inclusion of hydrogen sulfide in the reaction vessel. Hydrogen suflide modifies the reaction and stabilizes the reagent as it provides for additional sulfur being present when the hydrogen portion of water or hydrogen sulfide is given up for hydrogen substitution or insertion into the hydrocarbon molecule containing nitrogen, sulfur or oxygen. Mixtures of sulfides with different sulfur content also provide for a predetermined severity of attack. Hydrogen sulfide is also added to make up for loss of reagent.

Of course, addition of water (steam) also provides hydrogen substitution or insertion into the hydrocarbon molecule.

If more severe bond scission of the source material molecules is desired, such as for heavy ends of shale oil or more complex molecules in the shale oil rock, the catalyst composition, the amount of water, and hydrogen sulfide-all of them must be adjusted accordingly.

As it is also well recognized, and explained- above, subsequent treatment of the scission products from the initial phase are best treated in gas phase reactions, i.e., gas phase-solid phase (supported catalyst) reactions so as to produce by the above prescriptions, the desired product.

From the above examples and descriptions, the surprising, nonobvious process discovery when treating shale oil rock is the observed decrease in the amount of reagent used, when the reagent is properly stabilized with hydrogen sulfide. Unfavorable reactions, due to the attack of reagent on the rock matrix, masked the true reaction conditions which, in fact, are far more favorable than could have been anticipated when considering the dilution factor of carbon in the rock and rock constituents in general.

Moreover, the bitumen fraction of the shale oil is readily attacked by the same reagent which attacks the kerogens; hence, the co-production of hydrocarbons from these two sources is also very helpful in the overall economy of the process.

Additionally, as the kergons contain mineral values, such as vanadium nickel, molybdenum, etc., the recovery of these as illustrated still further aid the overall economy of the process.

Besides the above, the presence of inorganic carbon, the possibly leachable constituents in the shale oil rock, e.g. sodium and potassium, etc., make the present process eminently superior to the present day thermal, i.e. retorting processes.

As a result of the above illustrations, and detailed explanations, selective production of saturated and partially unsaturated compounds may be accomplished from the above shale oil or shale oil rock starting material thus satisfying a variety of needs by the energy and chemical industry. Hence, a large reserve of source materials have become readily and economically available for assuring continuous supply of hydrocarbon values.

Claims (29)

Claims

1. A process for the production of hydrogenated hydrocarbon values from a starting source material of shale oil, shale oil rock, and the like, including recovery of valuable component values of said starting source, comprising: a) reacting said starting source material with an alkali metal hydrosulfide, alkali metal sulfide, alkali metal polysulfide or alkali metal sulfide hydrate of each of the foregoing, mixtures of each of these or mixtures of each with the others as a reagent therefor, in presence of water and or alcohol so as to expel ammonia and elemental sulfur and recover the same; b) reacting further at an elevated temperature between 1 000C to 4000C said hydrocarbon values in presence of said reagent so as to obtain a hydrocarbon material of selected properties and;; c) recovering said hydrocarbon values of selected properties including by-products from said reaction as defined in step (b).

2. A process as defined in claim 1, wherein in step b) the hydrocarbon values obtained from step a) are further hydrogenated in the presence of water and hydrogen sulfide and a predetermined reagent so as to obtain further reaction products.

3. The process as defined in claim 1, wherein in step b), the hydrocarbon values obtained from step a) are further hydrogenated with a predetermined reagent in the presence of water and hydrogen sulfide so as to obtain further reaction products and (2) said further reaction products are then dehydrogenated with a preselected reagent in the presence of water and hydrogen sulfide so as to obtain a preselected hydrocarbon composition.

4. The process as defined in claims 1, 2 or 3, wherein the starting source material isshab oil.

5. The process as defined in claims 1, 2 or 3 wherein the starting material is shale oil rock.

6. The process as defined in claims 1,2 or 3, wherein the starting source material is inorganic bitumen carbon containing shale oil rock.

7. The process as defined in claim 3, wherein in step b) (2), the reagent is supported and is a potassium polysulfide.

8. The process as defined in claim 7, wherein the potassium to sulfur ratio for the supported reagent is from KHS to K2S4, or mixtures thereof and mixtures of same with hydrates thereof, said reaction being conducted at a temperature from 1800 to 4000C in the presence of hydrogen sulfide and steam.

9. The process as defined in any preceding claim, wherein during pretreatment ammonia values and elemental sulfur values are recovered and the elemental sulfur values are converted into hydrogen sulfide for use in said process.

10. The process as defined in claim 3, wherein a plurality of steps b) (1) are employed followed by a plurality of steps b) (2), in which steps is produced, in the presence of a preselected reagent a certain hydrocarbon cut, said reagent being preselected for a specific temperature reaction, wherein the reaction is in presence of water and/or hydrogen sulfide addition.

11. A process for producing hydrocarbon values from shale oil rock starting material comprising the steps of: a) pre-treating ground shale oil rock at a temperature of less than 720C with a reagent of an alkali metal hydrosuflide, an alkali metal sulfide, an alkali metal sulfide hydrate, or mixtures of same, in the presence of an alkali hydroxide and an alkanol, removing ammonia under vacuum; while stirring said mixture, removing elemental sulfur formed during said stirring; increasing the temperature up to about 1 350C and distilling a mixture of an alkanol and water and recovering light hydrocarbon distillates and hydrogen sulfide; further heating said reaction product freed from alcohol and water in a reaction zone at a temperature above 2500C and in the presence of a reagent, hydrogen sulfide and water, thereby further hydrogenating hydrocarbon values and increasing the volatility of same; further pre-selectively treating said hydrocarbon values previously having been increased in volatility to hydrogenate selectively and/or dehydrogenate in presence of a pre-selected reagent, water and/or hydrogen sulfide and recovering said reagent for reuse in said process, recovering associated metal values and recovering said hydrocarbon values.

1 2. A process for the production of hydrogenated hydrocarbon values from starting source material of shale oil rock and the like, containing kerogens and other organic and inorganic carbon components capable of being hydrogenated, and other mineral values, comprising: a) reacting in at least one stage, said source material with a reagent comprising sodium hydrosulfide, sulfide, polysulfide, mixtures thereof or mixtures of the hydrates thereof, in presence of water and/or steam and hydrogen suflide; and b) recovering said hydrocarbon values including mineral values.

1 3. The process as defined in claim 12, wherein the reagent further includes other alkali metal hydrosulfides, sulfides, polysulfides, mixtures thereof or mixtures of hydrates thereof.

14. The process as defined in claim 13, wherein the sulfides of said other alkali metals are the hydrosulfides, sulfides or polysulfides of potassium.

15. The process as defined in claim 12, wherein said hydrocarbon values are further reacted, before the recovery of the same, in a further reaction zone in presence of a reagent on a support, steam, and/or water and hydrogen sulfide, and wherein said reagent is a hydrogen sulfide, sulfide, polysulfide, hydrates thereof and mixtures of same, of an alkali metal.

1 6. The process as defined in claim 1 5, wherein, in the further reaction zone for said hydrocarbon values, a temperature is lower than in a first reaction zone, wherein said shale oil rock is reacted.

17. The process as defined in claim 15, wherein the reaction is exothermic in said first reaction zone.

18. The process as defined in claim 15, wherein the reaction is of shale oil rock of at least 5% organic carbon content.

19. The process as defined in claim 15, wherein the metal values associated with shale oil rock are recovered by leaching said shale oil rock to recover at least one reagent precursor and thereafter separating said metal values from said reagent precursor.

20. The process as defined in claim 15 wherein the metal value recovery is from said leached reagent.

21. A process for the production of hydrogenated hydrocarbon values from starting source materials of shale oil rock and the like, containing kerogens and other organic and inorganic carbon components capable of being hydrogenated, and other mineral values, comprising: a) reacting in a first stage said source material with a reagent comprising an alkali hydrosulfide, sulfide, polysulfide, mixtures of same and mixtures of hydrates of same, in presence of steam and/or water and hydrogen sulfide; and - b) reacting further said hydrocarbon values in at least one reaction zone in presence of a reagent as defined in a) above; c) recovering hydrocarbon values; d) recovering hydrogen sulfide; and e) recovering reagent values and associated metal values.

22. The process as defined in claim 21, wherein the reagent in (b) is a supported reagent.

23. The process as defined in claim 22, wherein the reagent is a supported reagent of a potassium hydrosulfide, sulfide, polysulfide, mixtures thereof or mixtures of hydrates thereof.

24. The process as defined in any of claims 21 to 23, wherein hydrogen sulfide admixed with hydrocarbon values is used to reconstitute said reagent.

25. The process as defined in any of claims 21 to 24, wherein the process in said first stage is at exothermic conditions at a temperature of about 3200 C.

26. The process as defined in claim 25, wherein the process in said first stage is at exothermic conditions at a temperature of about 3600C.

27. The process as defined in any of claims 21 to 26, wherein the metal values recovered are vanadium, cobalt, molybdenum or nickel metal values.

28. A process according to any one of claims 1, 11, 12 and 21 and substantially as hereinbefore described.

29. Hydrogenated hydrocarbon values whenever produced by a process according to any preceding claim.