KR900003646B1 - Process for self-hydrogenation - Google Patents

Abstract

A process for self-hydrogenation of petroleum refining gas contg. olefin 6-15 vol.% from fluid catalyst cracking (FCC) and delayed coking comprises (a) sepg. gas stream (GS) A in a liq. separator (1) to obtain GS-B (for fuel gas) and GS-C(for ammonia feed); (b) passing the GS-C through an incurrent drum (2), compressing by a compressor (3), mixing with satd. recircn. gas, and removing portion of exo-heat from a hydrogenator (5); (c) compressing the gas mixt. at 100-713 psi (7-50Kg/Cm2) to form stream D; (d) recovering heat from (5) by an exchanger (4) and passing the feed gas through a (5) filled with Co- Mo oxides or Ni-Mo catalyst; (e) removing sulfidric acid with ZnS; and (f) cooling to 150 deg. C and sepg..

Description

Self hydrogenation method

1 is a simple flowchart of the method of the present invention.

* Explanation of symbols for main parts of the drawings

(1): liquid separation tank (2): compressor suction drum

(3): compressor (4): heat exchanger

(5): Hydrogenation reactor (6): Zinc oxide fixed bed reactor

(7): heat exchanger (8): separation tank

The present invention relates to a method for self-hydrogenation of olefins present in refinery gas.

More particularly, the present invention relates to a process for self-hydrogenation of olefins present in the refinery gas to be steam reformed to produce hydrogen later. The hydrogen thus obtained can be mixed with air nitrogen under pressure, for example, to produce ammonia syngas. It is also used for the production of other petrochemicals or for the treatment of petroleum fractions.

Ammonia is one of the most important chemicals and is used intensively as a fertilizer or as an intermediate in the manufacture of other fertilizers such as urea, ammonium nitrate and ammonium sulfate.

Since 1913, the synthesis of ammonia from its constituent elements, hydrogen and nitrogen, has been developed to produce ammonia by reacting syngas consisting mainly of hydrogen and nitrogen. In this reaction, the source of nitrogen is always air, while the source of hydrogen has changed in view of the procurement possibilities and economic aspects of the raw materials.

Thus, coal and coke have already been used as raw materials for hydrogen production. For example, the Winkler process allows the recovery of various hydrocarbons as by-products using crack coal over fluidization with nearly pure oxygen. In recent years, natural gas and petroleum fractions have become available, making new developments in the production of syngas:

Non-catalytic partial oxidation method:

Methane or naphtha steam reforming.

The first method is interesting in that it allows feed of different hydrocarbon compositions, from natural gas to heavy fuel oil, but requires additional building of the air plant.

A more commonly used method is steam reforming of methane under the action of a catalyst. This process proceeds in two catalysis steps. In a first reforming of the first stage, a partially reformed gas containing about 10% by volume methane (dry basis) is obtained and the gas does not exceed 0.3-1.0% by volume of methane required for syngas production in the second reformer. Treat to low methane levels.

CH ₄ , H ₂ O, CO, CO ₂ and H ₂ are produced depending on the vacancy conditions of the natural gas and steam reaction. An important condition is that the catalyst does not produce carbon that inhibits the activity of the catalyst. Moreover, since the reforming catalyst is reactive to sulfur present in the hydrocarbon feed, this feed is usually desulfurized prior to steam reforming.

The basic reaction of reforming can be expressed as:

CH ₄ + H ₂ → CO + 3H ₂

This reaction is highly fusible and therefore preferably proceeds at high temperatures and high steam levels. Typically at the outlet of the primary reformer it reaches a temperature of 821 ° C. (1510 ° F.), a pressure of 33.4 kg / cm 2 (475 psia) and the effluent of the secondary reformer has a temperature of 999 ° C. (1830 ° F).

The gas produced in the reforming reactor contains three types of carbon: methane, CO and CO ₂ , the next step is to apply a shift reaction to the carbon monoxide, where CO reacts with steam under the action of an iron-based catalyst to dissipate heat as CO ₂ And to generate H ₂ :

CO + H ₂ O → CO ₂ + H ₂

Carbon dioxide is removed in contact with 30% monoethanolamine solution (MEA) or high silver carbonate and the residual CO level is about 0.5% (dry basis). CO and CO ₂ need to convert small amounts of residual CO and CO ₂ to methane before the ammonia synthesis step because of the linearization effect on the catalyst (generally nickel) used in the ammonia synthesis. Methanation reactions lower these oxide levels to less than 10 ppm. These exothermic reactions can be expressed as:

CO + 3H ₂ → CH ₄ + H ₂ O

CO ₂ + 4H ₂ → CH ₄ + 2H ₂ O

Since the production of ammonia from its components is a well-known method, various aspects of the production of hydrogen, such as sources of this material (coal, heavy residues, novel hydrocarbons such as naphtha), catalysts used in reforming, purification examples For example, there is a wealth of technical literature on information on the desulfurization of gases to be steam reformed.

In other respects, the problem of producing syngas or hydrogen for amdonia from a hydrocarbon source that is cheaper than the new petroleum fraction is quite long. Thus, US Pat. No. 1,864,717 describes the use of refinery waste or by-products for the production of ammonia. According to this patent, air is blown into heavy oil heated to 400-500 ° C. to obtain various products by oxidation reaction and nitrogen (present in air) is bound to these reaction products.

The hydrogen-nitrogen mixture is converted to ammonia.

U. S. Patent No. 1,429, 331 mentions the possibility of producing hydrogen-rich gas for the purpose of producing synthetic natural gas as a combination of a hydrocatalyst cracking plant where heavy hydrocarbons are cracked; Decomposition products containing olefins (naphtha) pass through a hydrogenation plant to saturate the olefins and aromatics to produce saturated naphtha fractions, which react with steam in a reformer to produce syngas. Nevertheless, the specification lacks a clear explanation of rectified gas hydrogenation.

In Brazil, the production of hydrogen by reforming natural gas or naphtha due to the oil crisis has caused problems in the country due to the rareness of natural gas and the high cost of naphtha. Another hydrocarbon source used in the reforming process may be refinery gas. Typical compositions of this gas are shown in Table 1.

Table 1

As can be seen in Table 1, the refinery gas is not suitable for steam reforming in the presence of unsaturated hydrocarbons (about 13%) in its composition. This olefin causes a large coke deposit on the reforming catalyst and the maximum allowable concentration in the feed is about 1% by weight.

Observing Table 1 results from the fact that the hydrogen concentration of the refinery gas is higher than the stoichiometric concentration required to saturate the olefins present in the gas, leading to the conclusion that the catalyst autohydrogenation is possible according to the following reaction:

C _n H _2n + H ₂ → C _n H _2n + ₂

The reaction is exothermic.

The refinery gas is therefore not suitable for steam reforming on its own due to the presence of relatively high levels of olefins of about 13% by volume, but its high hydrogen level-about 22% by volume-saturates the olefins using the hydrogen itself contained in the refinery gas. And a product suitable for forming the reaction of the syngas.

A drawback of this method is the tendency of coke formation in the hydrogenated catalysts to rapidly deactivate the catalysts. Indeed, British Patent No. 1,430,121 addresses this problem and provides another method for enabling steam reforming of gases containing about 15% of olefins using a steam reforming catalyst containing silver in its composition.

Another problem with refinery gas hydrogenation is the possibility of methanation reactions on the carbon oxides normally present in these streams. These reactions can dissipate large amounts of heat and cause temperature rises to unacceptable levels.

Furthermore, refinery gas, a gaseous mixture that flows from treatment facilities with diethanol amines (DEAs) from fluid catalytic cracking, delayed coking and catalytic reforming plants, is generally characterized by carbonyl sulphide (COS) with large concentration variations and about 100%. It may contain a ppm ppm sulfide gas, which requires additional treatment to remove sulfur to an acceptable level (about 0.5 ppm by weight) for the reforming process.

In other respects, it is very important to have knowledge of the secondary reactions occurring in the presence of hydrogenated catalysts in order to choose an economical method of sulfur removal.

From the study of the above drawbacks, the Applicant has now described, based on experiments conducted in a pilot plant, an economical method of refinery gas catalyst hydrogenation that makes it suitable for steam reforming while allowing the use of conventional catalysts in reforming. Developed. Thus, the present invention provides an alternative to the natural gas or naphtha used to date as a raw material for steam reforming for hydrogen generating facilities near refineries. In fact, the applicant has increased the size of the hydrogen pile plant to build a refinery gas hydrogenation plant, which is 8 km away from the refinery and supplies to a 454 tonnes / day ammonia manufacturing facility. Previously, raw materials were naphtha. In addition to savings, there are additional savings from reduced raw material consumption and fuel.

It is therefore an object of the present invention to provide a rectified gas catalyst hydrogenation method that can be used for steam reforming in the production of syngas.

It is still another object of the present invention to provide an oil refinery gas hydrogenation method in which a gas after hydrogenation can be treated for sulfur removal and immediately introduced into a steam reforming process while maintaining excellent activity without excessive coke deposition on the catalyst. .

A simple flow diagram of the method of the present invention is shown in Figure 1.

Refining gas containing 6 to 15% by volume of olefins produced by single or mixture of gases produced in fluid catalyst cracking facilities (FCC) and delayed coking to be a source of hydrocarbons to supply hydrogen for ammonia synthesis. The hydrogenation method of the present invention is characterized in that it consists of the following steps: a) In the liquid separation tank 1, the liquid stream is separated from the refinery gas stream A so that the liquid-free gas stream is divided into two streams; Flow B is fed to the fuel gas system and the other flow C constitutes the ammonia plant feed: b) Flow C from step a) is passed through compressor intake drum 2 and is compressed under pressure control in compressor 3 and saturated Intermediate suction of cooling gas recirculation mixes the gas with the feed and removes part of the reaction fumes from the hydrogenation reactor 5: c) The feed-recirculation gas mixture from step b) is 100-713 psi (7) in compressor 3. Compress under a pressure in the range of -50 kg / cm ² ) or above, preferably 385-713 psi (27-50 kg / cm ² ) to form flow D, with compressor 3 cracking heavy gas oil and high levels of nickel A low density gas with a high concentration of hydrogen from the vacuum residue can be received: d) recovering heat from the recirculation effluent from the hydrogenation reactor 5 and returning flow D from step c). Heated in heat exchanger 4 and feed-recirculated gas mixture E is passed through hydrogenation reactor 5, where the temperature of reactor 5 feed-recycles to maintain coke deposits to a minimum without reducing the rate of hydrogenation reaction. The gas ratio is controlled, and the hydrogenation reactor 5 is charged with a fixed bed catalyst made of cobalt-molybdenum nitride or nickel molybdenum, so that the space velocity resulting from the passage of the gas is substantially free of olefins, i.e. The reactor is designed so that the product contains less than 0.3% by weight of olefins at the end of the campaign, the campaign life of the active catalyst reaches over 12 months, and at the same time sulfur compounds such as carbonyl sulfide (COS) are hydrogenated Becomes dredic acid, and this acid is further removed on zinc oxide; e) removing a portion of the hydrogenated gas flowing out from the hydrogenation reactor 5, i.e., flow G in step d), through the zinc oxide fixed-bed reactor 6 in the refinery gas, or the sulfidic acid produced in step d) as zinc sulfide And introduce the hydrogenated sulfur-free refinery gas-flow K- into the steam reformer: f) return the partial-flow H- of the hydrogenated gas flowing out of the hydrogenation reactor 5 to the heat exchanger 4 to return this gas. After cooling and supplying heat to the feed, this gas-flow I- is cooled in a heat exchanger 7 to a temperature in the range of 170 to 140 ° C., preferably 150 ° C., with water, optionally boiler water, and the resulting liquid is separated. After separation in bath 8 this gas-flow J- is introduced in the intermediate stage of compressor 3.

In the reaction stage occurring in hydrogenation reactor 5, a series of variables of pressure, temperature and space velocity should be such that the methanation reaction of the carbon oxides present in the refinery gas can be controlled under controlled conditions. Thus the pressure is 100-713 psi (7-50 kg / cm ² ) preferably 543 psi (38 kg / cm ² ) and the temperature is 250-400 ° C., preferably 360 ° C. and the hourly space velocity is 700-2500 h ⁻¹ 1250h ^-1 . Sulfur compounds, such as carbonyl sulfide (COS), which are usually present in the gas from a fluid catalyst cracking facility (FCC), are hydrogenated to produce sulfidroic acid, which is removed on zinc oxide.

Another reaction that occurs is a shift reaction in which carbon monoxide in the refinery gas reacts with the ballast water in the refinery gas to form carbon dioxide. The amount of CO ₂ produced is such that the caustic process for sulfur removal becomes uneconomical.

Moreover, since the change in the composition of the refinery gas is largely related to the olefin level in the reaction stage, this method avoids greatly accelerating the coke deposition on the catalyst due to the excess of temperature at any point in the phase at any moment. Appropriate instruments are included in the reactor. Ammonia plants during CoMo or NiMo catalyst regeneration procedures, such as the passage of air through roasted deposited carbon by connecting a pre-reactor of the same size as the main reactor in parallel to the main reactor, even if coke deposition on the catalyst is low It is good practice to ensure that the continuity of operations is guaranteed.

The present invention is also characterized by obtaining the heat required for the hydrogenation reactions from the reactions and all the required hydrogen is originally present in the refinery gas itself and therefore does not require the introduction of additional hydrogen.

The method can control the rate of coke deposition reaction on the catalyst, contrary to some literature claims regarding the difficulty of controlling coke deposition on the catalyst.

After all, this is an industrial method that has already been shown to be efficient and economical in pilot plants, which were mainly responsible for the expansion of the 454 ton / day ammonia plant in operation. The device replaces naphtha with refinery gas, which saves US $ 9 million a year in foreign currency and pays back capital in less than one year.

Another advantage of replacing naphtha with refined gas is that in an industrial facility, the present invention provides an overall saving of about 10% of raw materials and fuel compared to when operating with naphtha.

Claims (7)

A method of self-hydrogenation of petroleum refining gas from a fluid catalyst cracking plant (FCC) and a delayed coking plant containing 6-15% by volume of olefins, characterized by the following: a) from liquid separation tank 1 to refinery gas flow A The liquid stream is separated from the liquid stream, and the liquid-free gas stream is divided into two streams: stream B is supplied to the fuel gas system and the other stream C constitutes the ammonia plant feed: b) Compressor C from step a) Pass through suction drum 2 and compress this flow under pressure control in compressor 3, medium suction of saturated cooling gas recirculation to mix the gas with feed and remove some of the reaction exotherm from hydrogenation reactor 5: c) step b) of the feedback from the - scope of the recycle gas mixture 100~713psi (7~50kg / cm ²⁾ from the compressor 3 or more, preferably a pressure of 385~713psi (27~50kg / cm2) To form flow D, which can accommodate low density gases with high concentrations of hydrogen from heavy gas oil cracking and high levels of nickel vacuum residues: d) Hydrogenation reactor 5 The heat D from step c) is recovered by recirculation from circulating and heated in heat exchanger 4 and the feed-recirculation gas mixture E is passed through a hydrogenation reactor 5, the temperature of which is the rate of hydrogenation reaction. The feed-recirculation gas ratio is adjusted to maintain coke deposition at the minimum level without reducing the catalyst, and the hydrogenation reactor 5 is charged with a fixed bed catalyst made of cobalt-molybdenum oxide or nickel-molybdenum and obtained by passage of the gas. The space velocity is hydrogenated product, i.e. substantially free of olefins in flow F, i.e. this product 0.3% by weight of olefins at the end of the campaign. The reactor is designed to contain less than 12 months, and the lifetime of the campaign of active catalysts reaches 12 months or more, while at the same time sulfur compounds such as carbonyl sulfide (COS) are hydrogenated to sulfidic acid, which is further removed on zinc oxide: e) a portion of the hydrogenated gas flowing out of the hydrogenation reactor 5, i.e., flow G, in step d) is passed through a zinc oxide fixed bed reactor 6 to remove the sulfidic acid produced in step d) as zinc sulfide and The hydrogenated sulfur-free refinery gas-flow K- is introduced into the steam reformer: f) The partial-flow H- of the hydrogenated gas flowing out of the hydrogenation reactor 5 is returned to the soft exchanger 4 to cool the gas and supply heat to the feed. The gas-flow I- is then cooled in a heat exchanger 7 with water, optionally boiler water, to a temperature range of 170 to 140 ° C., preferably to 150 ° C., and produced. After separating the liquid in separation tank 8, this gas-flow J- is introduced in the intermediate stage of compressor 3. The process of self-hydrogenation of a refinery gas from a fluid catalyst cracking plant (FCC) and delayed coking comprising 6-15 vol.% Of olefins, wherein the pressure is 100 psi in the reaction stage occurring in the hydrogenation reactor 5. ^{(7kg / cm 2) ~713psi (} 50kg / cm 2), the temperature is from 360 ℃ supposed preferably 250~400 ℃, hourly space velocity is 700h ^-1 ~2500h ^-1 preferably is 1250h ^-1, the pressure Under conditions of temperature and space velocity per hour, the olefin is fully hydrogenated and the carbon monoxide shifts to carbon dioxide as well as the high exothermic methanation reactions of carbon oxides present in the refinery gas. The process of self-hydrogenation of a refinery gas from a fluid catalyst cracking plant (FCC) and delayed coking containing 6-15 vol.% Of olefins, wherein the sulfur compounds such as carbonyl sulfide (COS) A hydrogenation reaction takes place and furthermore the sulfide is removed as zinc sulfide on zinc oxide together with sulfidroic acid originally present in the refinery gas. The method for self-hydrogenation of a refined gas from a fluid catalyst cracking chamber (FCC) and delayed coking containing 6 to 15% by volume of olefin, wherein the shift reaction of carbon monoxide present in the refinery gas is described above. Carbon dioxide is produced by reacting the ballast water present in the above with the monoxide. 2. The method of self-hydrogenation of petroleum refining gas from a fluid catalyst cracking facility (FCC) containing 6-15% by volume of olefins and delayed coking, wherein the olefin level of the petroleum refining gas is largely changed at any time. Appropriate instruments are installed in the hydrogenation reactor 5 so as to avoid greatly accelerating the coke deposition reaction on the catalyst at any point in the bed. 2. The method of self-hydrogenation of a refined gas from a fluid catalyst cracking plant (FCC) containing delayed coking and delayed coking comprising all the heat required for the hydrogenation reactions from the hydrogenation reactions. All the hydrogen required and obtained is originally present in the refinery gas itself and therefore does not require the introduction of additional hydrogen from an external source. 2. The method of self-hydrogenation of a refinery gas from a fluid catalyst cracking plant (FCC) and delayed coking comprising 6-15 vol% of olefins, characterized in that the rate of coke deposition on the catalyst is controlled. How to.

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