FR3058713A1 - STEAM IMPLEMENTATION OF SYNTHESIS GAS PRODUCTION PROCESS FOR REHEATING NATURAL GAS VAPORS. - Google Patents

Abstract

Process for the liquefaction of natural gas in combination with a synthesis gas production process, characterized in that the water vapor from the synthesis gas production process is used as a heat source for heating the natural gas vapors generated at the final expansion at the outlet of the natural gas liquefier and / or of said liquefied natural gas storage and / or of said liquefied natural gas charge.

Description

Holder (s): AIR LIQUIDE, ANONYMOUS COMPANY FOR THE STUDY AND EXPLOITATION OF GEORGES CLAUDE PROCESSES Société anonyme.

Extension request (s)

Agent (s): AIR LIQUIDE.

STEAM IMPLEMENTATION OF A SYNTHESIS GAS PRODUCTION PROCESS FOR HEATING NATURAL GAS VAPORS

FR 3 058 713 - A1

Method for liquefying natural gas in combination with a method for producing syngas, characterized in that the water vapor from the method for producing syngas is used as a heat source to heat the vapors of natural gas generated at the level of the final expansion at the outlet of the natural gas liquefier and / or of said storage of liquefied natural gas and / or of said loading of liquefied natural gas.

The present invention relates to a process for liquefying a stream of hydrocarbons such as natural gas in combination with a process for producing synthesis gas.

The invention relates to the integration of a process for liquefying natural gas in a process for producing synthesis gas by reforming with superheated steam, partial oxidation or autothermal reforming.

These syngas production technologies sometimes require the use of large quantities of natural gas used as a feed stream but also as a process heating source.

It is also desirable to liquefy natural gas for a number of reasons.

For example, natural gas can be stored and transported over long distances more easily in liquid state than in gaseous form, because it occupies a smaller volume for a given mass and does not need to be stored at high pressure.

Synthesis gas generation processes generally have hydrogen, carbon monoxide or a mixture of the two as end products (called “oxogas”, or even an H2 / CO / CO2 mixture (production of methanol) or an N mixture. ₂ / H ₂ (production of ammonia) Each of these processes also co-generates more or less superheated steam.

After a counting unit and possibly compression or decompression, the production of synthesis gas generally includes the following stages:

• A hot desulphurization step: after preheating (350-400 ° C), all the sulfur derivatives contained in natural gas are transformed into H ₂ S by catalysis in a hydrogenation reactor (CoMox). Then the H ₂ S is removed by catalysis (on a ZnO bed for example).

• A possible pre-reforming step (step mainly present in steam reforming units): at high temperature (500-550 ° C approximately) with excess steam. Then in the presence of a catalyst: conversion of the hydrocarbon chains containing at least two carbon atoms into methane with co-production of carbon monoxide, carbon dioxide (CO ₂ ) and hydrogen.

• Reforming step which consists of reacting the hydrocarbons at high temperature (850-950 ° C) with water vapor to produce hydrogen, CO and CO2.

Downstream of the synthesis gas production units, the products generally valued are carbon monoxide (CO), hydrogen (H ₂ ) or an H ₂ / CO mixture

If necessary, the last step of the synthesis gas production process can also be a:

• Partial oxidation step on a catalytic bed (autothermal reformer) which consists in reacting oxygen with hydrocarbons at high temperature (800-1200 ° C) to produce more CO;

• A step of converting CO into H ₂ in a catalytic reactor in the case of advanced hydrogen production;

The purification of the synthesis gas produced can then be done either by:

• Implementation of a PSA to purify the flow rich in hydrogen produced; or • An amine wash to extract CO ₂ from synthesis gas in the case of CO or oxogas production; and • Purification in a cold box of the flow rich in CO produced; or • The passage of the gas produced through a membrane to adjust the H ₂ / CO ratio required for the quality of the oxogas to be produced.

Furthermore, in general, the natural gas liquefaction units make it possible to implement a liquefaction process generally comprising the following three steps:

• A “pretreatment” which eliminates natural gas to liquefy impurities liable to freeze (H ₂ 0, CO2, sulfur derivatives, mercury, etc.);

• Extraction of heavy hydrocarbons and aromatic derivatives which can freeze during liquefaction. This step can take place upstream or in parallel with the liquefaction;

• Liquefaction by cooling natural gas to a cryogenic temperature (typically -160 ° C) thanks to a refrigerant cycle and possibly also accompanied by removal of heavy hydrocarbons / aromatic derivatives liable to freeze.

The inventors of the present invention have developed a solution allowing recovery of the vapor produced and available in excess in the processes for generating synthesis gas within the liquefaction process for natural gas. This integration between the two processes has many synergy advantages.

The subject of the present invention is a process for liquefying natural gas in combination with a process for producing synthesis gas, the liquefaction process comprising the following steps:

Step a): pretreatment of a natural feed gas in order to remove the impurities liable to freeze during the liquefaction process;

Step b): extraction, from the gas stream from step a), of a stream enriched in hydrocarbons having more than two carbon atoms;

Step c): liquefaction of the gas stream depleted in hydrocarbons having more than two carbon atoms resulting from step b);

Stage d): introduction, after expansion, of the liquefied natural gas resulting from stage c), into a storage and / or loading means; the process for producing syngas comprising the following steps:

Step a ’): desulfurization at a temperature above 350 ° C of a natural gas feed stream;

Step b ’): optional pre-reforming, at a temperature above 500 ° C in order to convert the hydrocarbon chains containing at least two carbon atoms from the gas stream from step a’) to methane;

Step c '): reforming consisting in reacting at a temperature above 800 ° C the gas stream from step a') or b ') with steam to produce hydrogen, carbon dioxide carbon and carbon monoxide; characterized in that the steam from the synthesis gas production process is used as a heat source to heat the natural gas vapors generated at the final expansion of step d) at the outlet of the gas liquefier natural gas and / or said storage of liquefied natural gas and / or said loading of liquefied natural gas.

According to other embodiments, the invention also relates to:

A method as defined above, characterized in that step a) consists of a pretreatment by adsorption by means of an adsorption system comprising between two and five containers of at least one layer of adsorbent and at least one device for heating and / or cooling an adsorption and / or regeneration current flowing in said adsorption system.

A method as defined above, characterized in that step a) consists of a pretreatment by washing with amines by means of a device comprising at least one adsorption column and at least one regeneration column.

A process as defined above, characterized in that during step a '), all the sulfur derivatives contained in the feed gas are transformed into H ₂ S by catalysis in a reactor.

A process as defined above, characterized in that the H ₂ S product is extracted by catalysis.

A process as defined above, characterized in that the impurities liable to freeze during the liquefaction process removed during step a) include water, carbon dioxide and the sulfur derivatives contained in the gas. feeding implemented during step a)

A process as defined above, characterized in that during step c), the stream of natural gas depleted in hydrocarbons having more than two carbon atoms resulting from step b) is liquefied at a temperature below -140 ° C by means of a natural gas liquefaction unit comprising at least one main heat exchanger and a refrigeration production system.

A method as defined above, characterized in that the natural gas feed stream used in step a) and the natural gas feed stream used in step a ') come from the same natural gas supply stream.

The stream of hydrocarbons to be liquefied is generally a stream of natural gas obtained from a domestic gas network distributed via pipelines.

The expression natural gas as used in the present application relates to any composition containing hydrocarbons including at least methane. This includes a "crude" composition (prior to any treatment or washing), as well as any composition that has been partially, substantially or entirely treated for the reduction and / or elimination of one or more compounds, including, but not limited to limit, sulfur, carbon dioxide, water, mercury and some heavy and aromatic hydrocarbons.

The heat exchanger can be any heat exchanger, any unit or other arrangement adapted to allow the passage of a certain number of flows, and thus allow a direct or indirect heat exchange between one or more lines of refrigerant, and a or more feed streams.

Usually, the flow of natural gas is mainly composed of methane. Preferably, the feed stream comprises at least 80 mol% of methane. Depending on the source, natural gas contains quantities of heavier hydrocarbons than methane, such as for example ethane, propane, butane and pentane as well as certain aromatic hydrocarbons. The natural gas stream also contains non-hydrocarbon products such as nitrogen (variable content but of the order of 5% mol for example) or other impurities H ₂ O, CO2, H ₂ S and others sulfur compounds, mercury and others (0.5% to 5% mol approximately).

The feed stream containing natural gas is therefore pretreated before being introduced into the heat exchanger. This pretreatment includes the reduction and / or elimination of undesirable components such as generally CO ₂ and H ₂ O but also H ₂ S and other sulfur compounds or mercury.

In order to avoid freezing of the latter during the liquefaction of natural gas and / or the risk of damage to the equipment located downstream (by corrosion phenomena for example), it should be removed.

One way of removing CO ₂ from the natural gas stream is, for example, an amine wash located upstream of a liquefaction cycle.

The amine washing separates the CO ₂ from the feed gas by washing the natural gas stream with an amine solution in an absorption column. The amine solution enriched in CO ₂ is recovered in the tank of this absorption column and is regenerated at low pressure in an amine regeneration column (or stripping in English).

An alternative to the amine washing treatment may be adsorption by pressure and / or temperature inversion. The advantages of such a method are described below.

This separation process exploits the fact that under certain conditions of pressure and temperature certain constituents of the gas (CO2, H ₂ O in particular) have particular affinities with respect to a solid material, the adsorbent (sieves molecular for example).

Adsorption is a reversible process and it is possible to regenerate the adsorbent by lowering the pressure and / or raising the temperature of the adsorbent to release the constituents of the adsorbed gas.

Thus, in practice, an adsorption separation system consists of several (between two and five) "bottles" containing one or more layers of adsorbents as well as devices dedicated to heating / cooling the adsorption stream and / or regeneration.

Compared to a conventional amine wash, pre-treatment has a number of advantages:

• its cost;

• its simplicity of operation;

• the possibility of avoiding a certain number of utilities (topping up with amine or demineralized water).

These advantages are particularly important for small natural gas liquefaction units (for example producing less than 50,000 tonnes of liquefied natural gas per year).

Its main drawback is to find the current necessary for regeneration (approximately 15% of the flow treated). Thanks to the integration with the hydrogen production unit, it is possible to regenerate the cylinders with the stream of treated gas and return it to the hydrogen production unit (fuel system or feed stream). ).

This option would not have been possible without integration because it would have meant a significant loss of natural gas.

An example of implementation is illustrated by the following example.

A steam reforming unit with a nominal hydrogen production capacity of approximately 130,000 Nm ³ / h is implemented.

This unit, powered by natural gas, exports steam at two pressure levels:

A. 55 tonnes per hour of superheated steam at high pressure (around 45 bara) for a temperature of the order of 300 ° C (resulting from the reforming step of synthesis gas).

B. 35 tonnes per hour of medium pressure steam (approximately 12 bara) (from the pre-reforming stage of synthesis gas).

Usually the steam generated is returned to a dedicated network (s) for various users.

By placing a small liquefied natural gas production unit with a capacity of 40,000 tonnes of liquefied natural gas produced per year near the hydrogen production unit, it is possible to recover all or part of the steam to high pressure in this unit and then return the steam used in the medium pressure network

In this case, for example:

About 6 tonnes per hour of steam as a heating source for the pretreatment of natural gas (adsorption for example), located upstream of the liquefier;

Around 45 tonnes per hour to drive the compressors in the frigories production cycle via back-pressure steam turbines.

The residual vapor is used to vaporize the heavy hydrocarbons extracted from the natural gas liquefier (quantity of steam required less than 1 ton per hour) or to heat the natural gas vapors generated in the storage of liquefied natural gas and / or the loading bay (quantity of steam required less than 1 ton per hour) before they are sent to the fuel network.

This integration makes it possible to limit the number of equipment necessary for the natural gas liquefaction unit (and therefore to gain competitiveness). In cases where the exported steam is poorly valued, the gain on electric energy saved by replacing electric motors with steam turbines can be estimated at several million euros on the electric energy thus saved per year.

In addition, the pressure and temperature level (s) of available steam vary from one production unit to another.

It is possible to adjust the quantities of steam generated by the hydrogen production unit by modifying the operating conditions or to condense the exported steam to recover energy which can, for example, make it possible to produce electricity in a turbine. .

It is then possible that the syngas production and natural gas liquefaction units have in common all of the site amenities in particular:

Connection to the natural gas network;

The counting station and possibly expansion / compression;

A network of hot torches and possibly cold liquids; All of the site's utilities (electricity, cooling circuit, air instrumentation, nitrogen ...);

The power network.

In addition, in the case where the synthesis gas production unit produces hydrogen, it is sometimes asked to liquefy all or part of the hydrogen to facilitate its transport or storage, for example. In this case, it is possible to "pre-cool" the hydrogen produced in the natural gas liquefier to a temperature of -160 ° C for example, then to complete the liquefaction in a dedicated unit.

Claims (9)

1. Method for liquefying natural gas in combination with a method for producing synthesis gas, the liquefaction method comprising the following steps: Step a): pretreatment of a natural feed gas in order to remove the impurities liable to freeze during the liquefaction process; Step b): extraction, from the gas stream from step a), of a stream enriched in hydrocarbons having more than two carbon atoms; Step c): liquefaction of the gas stream depleted in hydrocarbons having more than two carbon atoms resulting from step b); Stage d): introduction, after expansion, of the liquefied natural gas resulting from stage c), into a storage and / or loading means; the process for producing syngas comprising the following steps: Step a ’): desulfurization at a temperature above 350 ° C of a natural gas feed stream; Step b ’): optional pre-reforming, at a temperature above 500 ° C in order to convert the hydrocarbon chains containing at least two carbon atoms from the gas stream from step a’) to methane; Step c '): reforming consisting in reacting at a temperature above 800 ° C the gas stream from step a') or b ') with steam to produce hydrogen, carbon dioxide carbon and carbon monoxide; characterized in that the steam from the synthesis gas production process is used as a heat source to heat the natural gas vapors generated at the final expansion of step d) at the outlet of the gas liquefier natural gas and / or said storage of liquefied natural gas and / or said loading of liquefied natural gas. 2. Method according to the preceding claim characterized in that step a) consists of a pretreatment by adsorption by means of an adsorption system comprising between two and five containers of at least one layer of adsorbent and at least one device for heating and / or cooling an adsorption and / or regeneration current flowing in said adsorption system. 3. Method according to claim 1, characterized in that step a) consists of a pretreatment by washing with amines by means of a device comprising at least one adsorption column and at least one regeneration column. 4. Method according to one of the preceding claims, characterized in that during step a '), all the sulfur derivatives contained in the feed gas are transformed into H ₂ S by catalysis in a reactor. 5. Method according to claim 4, characterized in that the H ₂ S product is extracted by catalysis. 6. Method according to one of the preceding claims, characterized in that the impurities liable to freeze during the liquefaction process eliminated during step a) include water, carbon dioxide and the sulfur derivatives contained in the feed gas used during step a). 7. Method according to one of the preceding claims, characterized in that during step c), the stream of natural gas depleted in hydrocarbons having more than two carbon atoms from step b) is liquefied at a temperature below -140 ° C by means of a natural gas liquefaction unit comprising at least one main heat exchanger and a refrigeration production system. 8. Method according to one of the preceding claims, characterized in that the natural gas feed stream used in step a) and the natural gas feed stream used in step a ' ) come from the same natural gas supply stream. 9. Method according to one of the preceding claims, characterized in that the synthesis gas production unit is a hydrogen production unit by steam reforming for a hydrogen production capacity of at least 20,000 Nm ³ / h.