The method of purification of natural gas

 

(57) Abstract:

The invention relates to a method of purification of natural gas and bring it to compliance with requirements, marketable gas, which consists in the fact that the gas has a dew point between 0 and -18oC and the content of H2below 4 million-1in volume. H2and water are removed from natural gas at the same time in absorbtsionnoi column, where the gas is in contact with a solution of amine-glycol. Glycolic solution is then heated, evaporated and then brought into contact with the drying gas for exemption from the H2S and water, then drying gas containing a deletion of H2S and water, is burned with air, due to which H2S turns into SO2, which subsequently absorbed in the contact apparatus is supplied to the sea water and is brought into contact with exhaust gas from the combustion apparatus. The absorption solution is preferably a mixture of primary and/or secondary alkanolamines in mono-, di - and/or triethylene glycol. Technical problem - an integrated method for the simultaneous removal of H2S and water and the deposition gas of the sulfur compounds with the requirements of low cost. 7 C.p. f-crystals, 3 ill.

The present subramaniyapuram. This implies that the dew point temperature of the gas in the water must be between 0 and 18oC and volumetric content of H2S must be less than 4 million-1< / BR>
In particular, the invention relates to natural gas, in which the content of H2S amounts to several hundred million-1or less. This is typical of gas produced during oil production, when the collector is supplied sea water to enhance oil recovery.

Improved methods for purification of natural gas in respect of the H2's recently become increasingly important. This is partly explained by the fact that the gas in many new fields contains more H2S than of old, and the fact that for enhanced oil recovery in oil fields used water injection. Pumped water may contain bacteria that cause/increase the formation of H2S in associated gas.

From the book nick and Riesenfeld "Clean gas" it is known that the removal of H2's possible in various ways. Can be used progressive absorption-desorption system on the basis of various solutions using amines, but such plants are large and expensive, and they do not solve the problem of the final content of H2S or prestadoras, if you want to convert only small amounts of H2S and the concentration is low. You may also direct oxidation of H2S to S using iron complexes, as for example in the process of Stratford, but these settings are also large and expensive and therefore unsuitable for installation in conditions offshore. H2S can also precipitate on activated carbon or zinc oxide. Such installation will be less than those already mentioned, but require a heating gas to facilitate conversion to the sulfide, and in the end they require a large amount of used adsorbent, which raises the problem of disposal.

Next, from the same book "Clean gas" is also known a process for the removal of acid gases using water glycolamine as absorbent solution water-glycolamine. It was first described in the patent Hutchinson (US 2.177.068), but this process uses too much water in a poor solution to dry the gas before the temperature of the dew point is below 0oC. Next Kuliev and others in the Soviet patent S-822856-B it was noted that some solvents, and among them some glycols, was added to aqueous solutions of amine to improve the absorption of H2S and CO2but oksanarent T-023739, discuss the improvement of selectivity to H2S through the use of amine and nonaqueous solution, but this process is specifically designed for removal of acid gas to remove water attention is not given.

From the literature it is also known ("Purge gas") that the processes of absorption, such as "Selecsol" and "Cepacol" using polyglycolide the stain without additives Amin, have some ability to remove water, but these processes are not used for drying natural gas. These processes using physical solvents, particularly suitable for mass removal of CO2and/or H2S, but uneconomical for udaleniya H2S to low levels million-1.

The main object of the present invention was to find an improved method for the removal of small amounts of H2S, and water from natural gas, particularly for offshore fields. The new method should not have the limitations and disadvantages of the above known methods.

Another object was to find a way that can precipitate sulfur extracted from the gas, which is acceptable from the point of view of ecology method.

The next object was to find an integrated method for the simultaneous is trying to combine the development of a new way with the requirements of low cost, the inventors started with assumptions about the use of the existing equipment removal from water gas. Typically, the removal is carried out using glycol. The idea was to use glycol for removal from gas H2S. One of the reasons of such attempts was that most of the equipment, such as offshore platforms for oil or gas, already has such a way of dehydration. In the case of a new installation of such equipment shall be provided in any case, and there is some freedom in the design. It soon became clear that some improvements are needed. Next were the proposed changes, which in supplements alkanolamine in triethyleneglycol (TEG) is used as a desiccant. In the regeneration plants should be used more in the drying gas. As the drying gas is in principle possible to use any gas except oxygen and air. In most cases, the preferred natural gas or methane, because they already exist. Nitrogen, if present, also the most suitable as drying gas. Used drying gas containing water and H2S, the pipe is fed into the combustion chamber, where H2's pre-Christ. absorbed and instantly turns into sodium sulfate. The sulfite, in turn, is converted into sulfate due contained in the sea water of oxygen, which is then dissipated proryvnym thread. Chemical oxygen demand is negligible compared to the oxygen content in the coastal zone and in the sea. So for the conversion of the sulfur present in the form suitable for disposal, no need extra oxygen.

However, it was found that when applying mixtures methyldiethanolamine-triethylene glycol (MDEA-TAG) as absorbent circulation rate of the absorbent increases to achieve the desired degree of removal of H2S from natural gas. Although this increase can be obtained with the current absorption column, it is more profitable to continue to improve the process.

When the existing equipment is used a new method should be limited to perhaps a smaller number of changes. In this case, the circulation rate of the absorbent limited circulation pump. This pump is small and can be replaced, in whole or in part, without the occurrence of unacceptable problems. Further increase of the velocity of this fluid may require a change of the liquid distribution in the column or pipe. TGO equipment. The more you want change, the less acceptable the new way.

First of all, the inventors have studied the possible influence on the circulation rate of substitution used in the TAG alkanolamine on monoethylamine (IEA), 2-amino-methyl-1-propanol (AMP) or diethylene glycol (deg). The use of these alkanolamines increases the absorbent capacity of the solution, however, is not enough to eliminate the need to increase the speed of circulation compared to the one in which only water is removed.

It was then investigated the change of the glycol component of the mixture and it was found that if the TAG to be replaced by diethylene glycol (deg) and to apply the same amines, it is possible to obtain a significant degree of removal of H2S from sour gas. Acceptable reduction of H2S can be obtained by using a mixture of amine-deg without increasing the rate of circulation of over one that is used in the removal of water. But even when using primary amines AMP and the IEA was impossible the complete removal of all concentrations of H2S in the raw gas without increasing the velocity of circulation, even though the needs in circulation were compared with solutions based on the TAG.

The next step in or tea (triethanolamine). The results of these studies showed that the absorbent capacity of these latter solutions is significantly higher than for systems based on the DAG or TAG, and H2S is removed from the treated gas to concentrations of 2 - 4 million-1from the initial concentration of several hundred million-1without increasing the rate of circulation.

Further, the study showed that a mixture of the above amines with MEG also applicable to obtain the desired removal of H2S. although MEG is the preferred glycol, a mixture of MEG with a number TAG and/or DAG is also acceptable. Equally amines can mix up until a sufficient number of amines are active.

Studies of the concentration of amines in the glycol for acceptable absorbent mixture showed that the use of 0.2 - 2.5 M Amin in the glycol. The preferred concentration of 0.5 - 1.5 M, However, the required amount of amine, of course, depends on the level of H2S in the treated gas.

The absorbent solution in an absorption column should be substantially free from water. Acceptable water content in the range of 3 to 0.3 wt.%, and, of course, less is better.

The degree of absorption and drying can the C, preferably 30 - 45oC. the operating temperature in the drying process must be in the range of 100 - 200oC. These temperatures will be somewhat dependent on the glycol used in the absorption solution, and then it will be shown that at low temperatures need less drained gas.

When developing a new process, the inventors have found that the most preferred absorbent is the AMP. IEA equally active, but a few degenerate, especially if H2S is co CO2. Deja less active, but even deja can be used in the process without increasing the velocity of circulation.

Scope of the invention and its particular features are described in the accompanying claims.

The invention will be hereinafter disclosed in connection with the description of the drawings and the following examples.

In Fig. 1 presents a General picture of the communication flow for the method according to the invention;

in Fig. 2 shows an alternative blocks for use in the method shown in Fig. 1;

in Fig. 3 shows another alternative blocks for use in the method shown in Fig. 1.

In Fig. 1 shows the method according to the invention, in which the raw gas enters Poveda heat in the heat exchanger 8, and then enters the column 7 in the form of stream 5. Drying gas 11 is fed to the column 7, and the purified liquid 6 out of the bottom of the column 7 and the pipe 9 is transferred to the block 8 before she would return in column 2. The cleaned gas leaves column 2 in its upper part in the form of a stream 3. The gas in the tube 12 containing deleted H2S and water, enters the combustion chamber 14 that receives the air 13. Burnt gas 15 exchanges heat with the heat exchanger 16 and is fed to the column 21 as stream 17. Sea water 22 flows into the contact block of the column 21. Cleaned the burnt gas out of the block columns 1 as stream 24, and the sea water containing absorbed SO2merging into the sea in the form of flow 23.

In Fig. 2 shows another solution for the removal of SO2of the exhaust gas 17. In this case, the contact between the salt water coming in the form of stream 22, and the exhaust gas 17 occurs in the ejector 25.

In Fig. 3 shows a further modification of the removal process SO2of the exhaust gas 17, which is provided in contact with sea water 26 in the first ejector 27, and the resulting mixed gas-liquid stream 28 is fed to the second ejector 30, where the next portion of the sea water 29.

6S m3/day of natural gas in the tube 1 at the 40oC and 70 bar, containing 100 million-1H2S-rich water enters the column 2, where it meets with the thread 10, which is a 0.5-molar solution of methyl-diethanol-amine (MDEA) TAG (32 m3per hour), which absorbs the desired amount of H2S and water in stream 4, making the flow of purified natural gas 3 is ready for transportation. Purified natural gas contains 3.5 million-1H2S and has a dew point temperature - 14oC. the Used absorbent 4 is heated in the heat exchanger 8 and is fed into the top of the closed Packed columns/vyparivaya/ 7 as stream 5. In column 7, the absorbent is in contact with 480 S m3/h dry and free from H2's drying gas 11 scheme backflow at atmospheric pressure and 200oC. Used in the drying gas can be natural gas. The regenerated liquid 6 is provided to the pressure of the absorption column and is cooled in heat exchanger 8 before it is recycled to the column 2. Used drying gas 12 is fed into the combustion chamber 14 where it mixes with the air 13 (atmospheric pressure, 15oC and 10 KMOL/h) before the transformation H2S SO2. Exhaust Potok 19 enters the contactor marine water column 21, where SO2absorbed by sea water coming in the form of thread 22. The contactor 21 is able to work according to backflow or associated flow because it requires only one stage. Sea water is at the temperature and pressure of the 18oC and 4 bar, the flux density is 100 m3/hour. The resulting stream 23 may be merged in the sea.

Example 2. This example shows another implementation of the invention, as shown in Fig. 2.

The process is the same as in Fig. 1, but with the following deviations. The contactor 21 is replaced by the ejector, using as the working environment of sea water. The flux density is approximately 500 m3per hour, and the discharge pressure is maintained at atmospheric pressure. The contactor 25 will now work according to the associated stream. The use of ejector ensures the evacuation of the threads 17, 15, 12, and 13. Dewatering column 7 will then work with 525 mm RT.article Required for the combustion air is sucked into the combustion chamber, which now operates under reduced pressure. This method of carrying out the invention improves drainage in column 7. The flux density of 11 thereby reduced to 370 S m3/hour.

The purified gas contains 3.0 million-1

The purified gas contains 3.5 million-1H2S and has a dew point of -10oC.

Example 4. This example shows the method described in any of examples 2 and 3, but the contactor 21 is divided into two parts, as shown in Fig. 3. Here is the thread 26 consumes 20 m3/h and the flow 29 consumes 500 m3/hour. This mode allows you to isolate all problems of materials related to the cooling of the hot gas and the formation of acidic condensate on the small "first ejector" 27, which thereby can be manufactured from a material with high corrosion resistance at low cost.

The purified gas contains 3.5 million-1H2S and has a dew point of -10oC.

Example 5. This example shows the process that takes place as in example 1 except that the binder was replaced with 1.0 M AMP in MEG. The circulation rate of the absorbent was reduced to 1.46 m3/hour. The flow of drying gas 11 in the column 7 is reduced to 2 is applied.

Example 6. This example shows the process that takes place as in example 5 except that as the absorbent applied 1M deja in deg. The circulation rate of the absorbent is increased to 7,95 m3per hour as a consequence of using deja/deg instead of ASM/MAG in example 5. The flow of drying gas 11 in the column 7 is increased to 120 m3/hour. The amount of seawater corresponds to the number of H2S and therefore does not change.

Example 7. This example shows the process that takes place as in example 5, except that the adsorbent used 1 M IEA in MEG. All operating parameters are essentially unchanged. The circulation rate of the absorbent amounted to 1.5 m3per hour, the flow of drying gas 11 to 22 S m3/hour. The flow of sea water has not changed.

Example 8. This example shows the process that takes place as in example 1 except that the raw gas contains 35 million-1H2S. In contrast to a 0.5 solution of MDEA in the TAG example 1 here we have used the circulating absorbent solution 1 M AMP in deg. The circulation rate was 1.5 m3/h and the gas is purified so that the treated gas contains only 3 million-1H2S.

The present invention averdo, bringing it to conformity with the requirements of marketable gas. The method can be performed with some minimal, but significant changes to existing equipment for the removal of associated water. In the integrated method used proven technology for removal of SO2of the exhaust gas received from the first conversion, H2S by burning.

The method according to the invention is acceptable from the point of view of ecology way of working with gray. It should be noted that most of the problems of sulfur occurs primarily from discarded in seawater sulphate.

New equipment - combustion chamber and the contactor sea water are relatively small pieces of equipment. We can assume the use of sea water in the form of spent cooling water on the platform. In the second example embodiment, where applied ejector, eliminated the need for combustion fan.

Another advantage of the new method is the use of well tested parts, and the parts that need to be made of expensive materials, have a relatively small size, which leads to low total cost of equipment. Costs OE required. As the burner and the ejector are small nodes in the context of gas.

1. The method of purification of natural gas to bring it to compliance with the requirements of marketable gas or gas supplied by pipeline, according to which the gas has a dew point between 0oC and -18oC and the content of H2S below 4 million-1by volume, comprising contacting the gas in the absorption column with a solution containing the amine and glycol, wherein in the absorption column from natural gas to remove H2S and water simultaneously by contacting the gas with an absorbing solution of amine-glycol, and then a solution of amine-glycol is heated, evaporated and brought into contact with the drying gas to release from the water and H2S, after which the drying gas containing deleted H2S and water, burned with air to convert H2S in the exhaust in SO2which respectively absorb in the contact block, which serves sea water and bring it into contact with exhaust gas from the combustion unit.

2. The method according to p. 1, wherein the absorption solution is a mixture of primary and/or secondary alkanolamines in mono-, di - and/or triethylene the same time, that the exhaust gas is brought into contact with the sea water in the contact block is made in the form of an ejector, in which sea water is the working environment, and the resulting vacuum is used to reduce the pressure for dehumidification solution.

4. The method according to p. 3, characterized in that the flow of drying gas or the temperature of drying is reduced through the use of vacuum formed by the ejector.

5. The method according to p. 3, characterized in that the absorption of SO2of the exhaust gas is carried out in a liquid ejector, which works as a combination of absorber and source of vacuum.

6. The method according to p. 3, characterized in that the exhaust gas is cooled between the combustion chamber and the ejector, reducing due to this, the volume of gas to be processed in the ejector.

7. The method according to p. 1, wherein the primary amine is 2-amino-2-methyl-1-propanol.

8. The method according to p. 1, wherein the absorption solution is a mixture of primary alkanolamine and monoethylene glycol and the amine concentration is 0.5 to 1.5 mol.

 

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FIELD: gas treatment.

SUBSTANCE: invention is intended for fine purification of gases with removal of carbon dioxide at elevated pressures, in particular in hydrogen or ammonia production processes. Absorbent is an aqueous solution containing N-methyldiethanolamine, piperazine, potassium carbonate, and morpholine. Invention achieves reduced equilibrium pressure and increased carbon dioxide absorption at low degrees of carbonization (as low as 0.1 mole CO2 per mole tertiary amine) without appreciable N-methyldiethanolamine degradation rate.

EFFECT: enhanced carbon dioxide absorption efficiency.

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EFFECT: the invention ensures efficient regeneration of glycol in the vacuum column and unloading of an atmospheric column - stripper.

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EFFECT: the invention ensures increased completeness and speed of interaction of the components due to use of energy of the purified stream of the waste gasses.

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EFFECT: the invention allows to reduce the over-all excessive and partial pressure of the process of gas mixtures purification from carbon dioxide and to expand the field of the ethanolamine purification application.

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EFFECT: improved method for treatment.

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