EP0026670B1

EP0026670B1 - Process for the production of coke and a liquid product

Info

Publication number: EP0026670B1
Application number: EP19800303445
Authority: EP
Inventors: Harvey Edwin Alford; Edgar Lucian Mohundro; Robert A. Rightmire
Original assignee: Standard Oil Co
Current assignee: Standard Oil Co
Priority date: 1979-10-01
Filing date: 1980-09-30
Publication date: 1984-05-16
Also published as: BR8006280A; EP0026670A3; EP0026670A2; AU544773B2; AU6276080A; DE3067865D1

Description

The present invention relates to a novel process for producing coke and coke by-products, e.g. liquids such as kerosene and naphta.
In the course of operating a conventional refinery, heavy petroleum streams i.e. petroleum streams having high boiling ranges, are produced as a result of various refinery processes. One of the uses of such material is to form coke, which is a solid carbonaceous material having a number of different uses.
In conventional coking, the heavy refinery stream is heated to elevated temperature, e.g. 468°C (875°F), in the substantial absence of oxygen. As a result, the components of the heavy refinery stream undergo thermal decomposition thereby producing coke and a number of lighter components such as naphtha, kerosene and the like.
Recently, much interest has been focused on the feasibility of producing liquid petroleum products from shale oil, which is an organic semi-solid material similar to crude petroleum and derived from the destructive distillation of the organic matter in oil shale. In order to recover liquid petroleum products from shale oil, the shale oil, like crude petroleum, must be refined. As in the case of refining crude petroleum, refining of shale oil produces a heavy residuum by-product which can if desired be subjected to coking in the same way as heavy petroleum refinery streams.
As appreciated by those skilled in the art of coking, the liquid products produced by the coking operation are normally more valuable than the coke itself. Accordingly, it is desirable to carry-out coking in such a way that the production of liquid products such as naphtha and kerosene is maximised.
It is therefore an object of the present invention to provide a novel coking technique which produces a greater than expected amount of liquid product as compared with conventional coking operation.
We have found, unexpectedly, that the amount of liquid coking product produced is greater than expected if the coking feed is composed of a mixture of a petroleum residuum and a shale oil residuum.
Accordingly, the present invention provides a process for the production of coke and a liquid product by heating in the substantial absence of oxygen a feed material comprising a shale oil residuum, characterised in that the feed material comprises a mixture of the shale oil residuum which shale oil residuum is composed of no more than the bottom 60 weight percent of shale oil, and a petroleum residuum which has a boiling range such that a minimum of 80% of said petroleum residuum boils about 315°C (600°F). An improved yield of liquid products is obtained if the feed material contains a hydrogen catalyst. An even greater improved yield of liquid products can be obtained if the hydrogen catalyst is a hydrocracking catalyst and hydrogen is supplied to the coking operation.
In carrying out the present invention, a mixture of a shale oil residuum and a petroleum residuum are subjected to coking to produce coke and liquid products, the liquid products being produced in amounts greater than would have been expected.

Coking Procedure

In accordance with the present invention, the coking operation is accomplished in the same way under the same conditions as conventional prior art coking procedures. Thus, in commercial operation the process is normally conducted in a semi-batch mode with the feed stream being continuously fed to the coker and liquid products continuously withdrawn from the coker. Coking of the feed continuously occurs in the coker until the coker is substantially full of coke, at which time the operation is terminated and coke is than removed from the coker.
The operating conditions for the coking operation, as indicated above, are conventional. For example, coking can be conducted at any conventional temperature such as from 315°C (600°F) to 537°C (1,000°F), preferably about 468°C (875°F). Also, conventional pressures, e.g. atmospheric pressure, can be used. Moreover, the feed stream can be heated while in the coker, although it is preferable to supply all the heat necessary for coking by preheating the feed stream in a furnace of other suitable device prior to entry of the feed stream into the coker.

Shale Oil Material

A shale oil residuum is used as the shale oil material used in the inventive process. Crude shale oil as indicated above is normally obtained in the form of a solid or semi-solid material. This material, when heated to a temperature high enough to become liquid, could itself be used as the shale oil material.
However, since it is easier and more economic to recover the light products from shale oil (be it crude shale oil or hydrocracked shale oil) prior to coking, we use as shale oil material, according to the invention, a shale oil residuum, which is composed of no more than the bottom 60 weight percent of shale oil, i.e. the bottom or lower end of the shale oil.
In other words, it is contemplated that in the normal course of refining shale oil, be it crude shale oil or hydrocracked shale oil, most of the light ends of the shale oil will be removed by conventional refining techniques. The remaining fraction of the shale oil, the shale oil residuum, which will normally represent the bottom 60%, preferably 50%, of the shale oil, is used as the shale oil material in accordance with the present invention. For example, it has been found most convenient to use a 371 °C+ (700°F+) fraction of shale oil, which represents the bottom 54% by weight of the shale oil, as the shale oil material in accordance with the present invention.

Petroleum Residuum

As the petroleum residuum useful in accordance with the present invention, any petroleum derived refinery stream capable of undergoing any significant coking can be used. Such materials are petroleum-derived refinery streams in which a minimum of 80% by weight boils above 315°C (600°F). Preferred petroleum residua are those in which a minimum of 80% boils above 371°C (700°F), most preferably 537°C (1,000°F).
For example, a preferred petroleum residuum is the distillation residue recovered as the bottom stream from a conventional vacuum distillation column. This material, commonly known as vacuum tower bottoms, has a boiling range such that a minimum of 80% boils above 537°C (1,000°F). Another petroleum refinery stream that can be used as the petroleum residuum is the bottoms products of an atmospheric distillation column, which is normally characterised as having 80% boiling above 371°C (700°F). Still another petroleum refinery stream which is ideally suited as the petroleum residuum in accordance with the present invention is a decanted oil which is the bottoms products produced by distilling the effluent of a fluid catalytic cracker. As is well known, decanted oil is a highly aromatic material having a low API gravity and a boiling range such that 80% boils above 315°C (600°F), preferably 371°C (700°F), and is ideally suited for use as a coker feed.

Relative Proportions

In accordance with the present invention, it has been found that an unexpected increase in the amount of liquid product produced by coking will be realized when a shale oil residuum and a petroleum residuum are mixed in any proportions. Preferably, however, the amount of shale oil residuum in the feed mixture is 5 to 85 weight percent based on the total weight of the feed mixture, with shale oil concentrations in the amounts of 15 to 50% and more particularly 20 to 30% being especially preferred.

Use of Hydrogen Catalyst

In a preferred embodiment of this invention, a suitable catalyst is included in the feed introduced into the coker. As suitable catalysts, any material which will catalyze the reaction of hydrogen (be it molecular, atomic or combined) with free radical organic compounds and/or unsaturated organic compounds can be used. Such catalysts are referred to herein as "hydrogen catalysts".
Many types of hydrogen catalysts are known. One well known type of hydrogen catalyst is referred to in the art as a hydrogen transfer catalyst. Hydrogen transfer catalysts are known to catalyze the addition of molecular or combined hydrogen to a free radical organic compound, usually a hydrocarbon. Such catalysts are normally used in co-liquefaction when combined hydrogen from one organic compound is transferred to another free radical organic compound. Examples of known hydrogen transfer catalysts are iron pyrite and alkaline iron oxide.
The second type of hydrogen catalysts that can be employed in the inventive process is known in the art as a "hydrogenation catalyst". Such catalysts are normally used to add molecular hydrogen across an unsaturated double bond, although they can also be used for hydrogenating aromatically unsaturated compounds. Well known examples of this type of catalysts are metallic nickel, platinum and palladium.
A third and preferred type of hydrogen catalyst useful in the inventive process is known as a "hydrocracking catalyst." Such catalysts are normally used in petroleum refining and function both to cleave a large organic molecule into smaller organic molecules and at the same time to add hydrogen to each of the sites where the break occurred. Examples of well known hydrocracking catalysts are NiMo, CoMo, NiW and CoW. Preferred hydrocracking catalysts are NiW and NiMo. Such catalysts are usually supported on alumina supports.
It has also been found that the sulfur and nitrogen contents of process feed materials are usually reduced when a catalyst is used in accordance with the present invention.
The amount of catalyst employed in this embodiment is not critical and can vary between wide limits. From an economic feasibility standpoint, the amount of catalyst should probably be no more than 10 weight percent based on the weight of coker feed, and consequently the amount of catalyst in the feed material will normally be between greater than 0 to 10 percent by weight. The preferred amount of catalyst is 0.01 to 5 weight percent with the most preferred amount of catalyst being 0.05 to 1 weight percent.
It is preferred that the coking operation be carried out so that the catalyst is at least partially mixed with the feed material undergoing coking. In this regard, it has been noticed in using a laboratory scale batch coker that the catalysts will normally settle to the bottom of the coker if the liquid therein is quiescent. Thus, if coking is accomplished in a strictly batch operation, it is preferable to mix the liquid in the coker during the coking operaion so that the catalysts will be distributed throughout the mass of liquid undergoing coking. Mixing can be accomplished by any conventional means such as using a mechanical mixer or passing an inert gas through the liquid.
Commercially, coking is usually accomplished in a semi-batch operation wherein liquid feed is continuously fed to the "delayed coker" and liquid products continuously removed from the coker. The liquid fed in the coker during the coking operation continues to be converted to coke and liquid product until the coker substantially fills with solid coke at which time the coking operation is terminated. In such an operation, feeding the liquid feed to the coker inherently causes enough mixing to provide reasonable distribution of the catalyst in the liquid feed being coked.
In accordance with one feature of this embodiment, catalysts which have been previously used in the inventive process can be recycled for reuse. This can be accomplished in two ways. In accordance with one technique, coke product containing the catalyst therein after suitable comminution can itself be returned to the coker with fresh feed. In accordance with the other technique, coke product containing the catalyst therein is subjected to combustion, thereby freeing the catalyst in the form of an ash by-product. The ash by-product can then be returned to the coker with fresh feed. Recycling of catalyst has the obvious advantage of reducing the total amount of catalyst required.

Use of Hydrocracking Catalyst and Hydrogen

In another, more preferred embodiment of this invention, the yield of liquid products can be enhanced by using as the hydrogen catalyst, a hydrocracking catalyst and by supplying hydrogen to the coking operation, i.e. supplying hydrogen to the feed material while the feed material is being heated. The hydrocracking catalysts here used have been described earlier. Hydrogen transfer catalysts as well as hydrogenation catalysts, which were also described earlier, can be included in the coking operation, i.e. reaction system, but even in this event, it is still necessary to include a hydrocracking catalyst in the coking operation to be within the description of this preferred embodiment. Examples of hydrocracking catalysts which have been found to be especially useful in accordance with the present invention are NiMo, NiW, CoMo and CoW. Such catalysts are usually supported on alumina. Of these catalysts NiMo and NiW supported on alumina are especially preferred.
The amount of hydrocracking catalyst to be included in the reaction system can vary widely. Broadly, the amount of hydrocracking catalyst can be between greater than 0 to 10 weight percent. More preferably, the amount of cracking catalyst is between 0.01 to 5 weight percent with amounts on the order of 0.05 to 1 weight percent being most preferred.
Coking is accomplished in a conventional manner in accordance with this embodiment with the exception that hydrogen is supplied to the reaction system during the coking operation.
Hydrogen can be supplied to the reaction system in any convenient manner. Most conveniently, suitable inlet orifices will be provided in the coking apparatus for the advent of the hydrogen. Since it is preferable that the hydrocracking catalyst be reasonably well mixed in the reaction system during the coking operation, it is preferred that the hydrogen be introduced so as to cause turbulence of the liquid reaction system, thereby causing significant mixing. The hydrogen can be introduced in other ways, of course, in which case it is preferable to provide other means, e.g. mechanical stirrer, for causing mixing of the liquid reaction system. Hydrogen may also be produced in situ in the reactor by feeding steam thereto, the steam reacting with the coke and/or light hydrocarbons in the system to generate hydrogen.
The amount of hydrogen fed to the reaction system can also vary over wide limits. Broadly, the total amount of hydrogen supplied during a particular coking operation can be 2 to 30 SCF/lbs liquid feed (125 to 1970 cm³/g). Preferably, the amount of hydrogen fed is 5 to 15, (312 to 936 cm³/g) most preferably 12 to 15 SCF/lbs (748 to 936 cm³/g) liquid feed.
Although this embodiment can be carried out at widely varying pressures, it is preferred to 'operate at conventional coking pressures, i.e. greater than 0 to about 7 Bar gauge (100 psig). Such pressures it will be noted are much less than occurring in conventional petroleum hydrocracker units wherein the pressure is on the order of 140 Bar gauge (2,000 psig). Preferred operating pressures in the inventive process are on the order of 1.75-6.3 Bar gauge (25 to 90 psig). If desired, inert gases such as nitrogen can also be included in the reaction system.

Working Examples

In order to more thoroughly describe the present invention, the following working examples are presented.
In these examples, coking was accomplished in a batch operation using a laboratory scale coker (mini-coker) composed of a carbon steel reaction vessel defining a cylindrical reaction compartment having a diameter of 10 cms (4 inches) and an internal height of 53 cms (21 inches). A feedline was connected to the bottom of the mini-coker for the introduction of feed material and an exit line was attached to the top of the mini-coker for withdrawal of gaseous and liquid products during the coking operation. In order to prevent condensation of the liquid product in the outlet line, the outlet line was heated to a temperature of 343°C (650°F) during the coking operation. In each example, 2,000 grams of feed was charged into the mini-coker and the pressure in the mini-coker maintained at 6.3 Bar gauge (90 psig) and the mini-coker heated using a 48 hour thermal cycle shown in the following Table I. In each example, the liquid product obtained consisted predominantly of kerosene and naphtha.
The feed materials employed were a decanted oil, a vacuum tower bottoms, and a 371°C+ (700°F+) fraction of shale oil, which represents the bottom 54% of whole shale oil. The following Table II shows the properties of these materials.

Examples 1 to 3 and Comparative Examples A and B

In Examples 1 to 3, mixtures of the above-described shale oil residuum and the above-described decanted oil were subjected to coking. In addition, for the purposes of comparison a feed comprising all shale oil residuum and a feed comprising all decanted oil were also coked. The composition of the feed materials plus the results obtained are set forth in the following Table III. Unless otherwise indicated, all numbers in this and following table are in weight percent.
From the foregoing, it can be seen that the amount of liquid product yields realized when a mixture of a shale oil residuum and decanted oil are employed as the feed is significantly greater than would have been expected based on the amount of liquid product obtained when only shale oil residuum and only decanted oil are coked. Moreover, it will be noticed that the amount of coke produced is less than would have been expected, although not as much less as the unexpected increase in the amount of liquid product yields. Inasmuch as liquid products of the coking operation are more valuable than the coke, this is a significant commercial advantage.

Example 4 and Comparative Examples C and D

The procedures used in Examples 1 to 3, Comparative Example A and Comparative Example B were repeated except that a vacuum tower bottoms was used in place of the decanted oil as the petroleum residuum. The composition of the feed as well as the results obtained are set forth in the following Table IV.
From the foregoing, it can be seen that an unexpected increase in liquid product yields is also realized when the petroleum residuum is a vacuum tower bottoms.

Claims

1. A process for the production of coke and a liquid product by heating in the substantial absence of oxygen a feed material comprising a shale oil residuum, characterised in that the feed material comprises a mixture of the shale oil residuum which shale oil residuum represents no more than the bottom 60 weight percent of whole shale oil, and a petroleum residuum which has a boiling range such that a minimum of 80% of said petroleum residuum boils above 315°C (600°F).

2. A process as claimed in claim 1 characterised in that the feed material comprises 5 to 85% shale oil residuum.

3. A process as claimed in claim 1 or claim 2 characterised in that the feed material contains a hydrogen catalyst.

4. A process as claimed in claim 3 characterised in that the feed material contains up to 10 weight % hydrogen catalyst.

5. A process as claimed in claim 3 or claim 4 characterised in that the hydrogen catalyst is a hydrogen transfer catalyst.

6. A process as claimed in claim 5 characterised in that the hydrogen transfer catalyst is iron pyrite.

7. A process as claimed in claim 3 or claim 4 characterised in that the hydrogen catalyst is a hydrogenation catalyst.

8. A process as claimed in claim 7 characterised in that the hydrogenation catalyst is selected from metallic nickel, platinum and palladium.

9. A process as claimed in claim 3 or claim 4 characterised in that the hydrogen catalyst is a hydrocracking catalyst.

10. A process as claimed in claim 9 characterised in that the hydrocracking catalyst is selected from NiMo, CoMo, NiW and CoW.

11. A process as claimed in claim 10 characterised in that the hydrocracking catalyst includes an alumina support.

12. A process as claimed in any of claims 3 to 11 characterised in that said hydrogen catalyst is at. least partially mixed with the feed material undergoing coking.

13. A process as claimed in any of claims 3 to 12 characterised in that it includes the further step of withdrawing coke from the reaction zone wherein coking has occurred, mixing the hydrogen catalyst contained in said coke with additional feed material and subjecting said additional feed material to coking.

14. A process as claimed in any of claims 1 to 4 characterised in that the feed material contains hydrocracking catalyst and hydrogen is supplied to the feed material while the feed material is being heated.

1 5. A process as claimed in claim 14 characterised in that the feed material contains up to 10 weight percent hydrocracking catalyst.