ES2983357A1 - System and method for producing liquefied natural gas (LNG) with CO2 capture - Google Patents

Abstract

1. System and method for producing liquefied natural gas (LNG) with CO2 capture comprising: - a steam generating boiler (300) for the combustion with air (4) of the vaporized natural gas (3) generated in an expansion and separation stage (106), - means for capturing the CO2 (200) contained in the exhaust gases (5) of the steam generating boiler (300) comprising absorption (201) and compression (202) stages. The liquefaction and subcooling stage comprises a refrigerant compressor (103, 105) and a back pressure steam turbine (501, 502). The absorption stage (201) comprises a low pressure steam feed (10, 11) from the back pressure steam turbines (501, 502). The steam generating boiler (300) generates high pressure steam (6) which feeds the back pressure steam turbines (501, 502).

Description

DESCRIPTION

System and method of producing liquefied natural gas (LNG) with CO2 capture

Technical sector

The present invention belongs to the technical sector relating to liquefied natural gas (LNG) production systems. More specifically, the invention relates to a system and method for liquefying a natural gas stream that also includes a CO<2> capture unit.

Background of the invention

Liquefied natural gas (LNG) is natural gas that has been processed for transport in a liquid state. Natural gas is transported in this liquid state at atmospheric pressure and in a temperature range of approximately -150 °C to - 170 °C.

To convert natural gas into a liquid, the treated gas is cooled to approximately -162°C, which is the temperature at which methane, its main component, changes phase to a liquid state at atmospheric pressure.

In the liquefaction process, refrigerant gases are compressed to produce cold liquids, such as propane, ethane/ethylene, methane, nitrogen or mixtures of these, which are then evaporated as they exchange heat with the natural gas stream. In this way, the natural gas is cooled to the point where it becomes a liquid. Once the gas has been liquefied, it undergoes expansion so that it can be stored at atmospheric pressure. The liquefied natural gas (LNG) produced is stored in special tanks to be later transferred to special transport tankers.

A relevant aspect of this type of plants is to reduce their environmental footprint and increase their competitiveness and sustainability.

Summary of the invention

The present invention relates to a liquefied natural gas (LNG) production system with CO<2> capture. The system comprises a stream adapted for the circulation of natural gas, the system being adapted for cooling and/or expanding the natural gas stream at low temperatures of -140°C to -170°C in cooling and/or expansion stages to produce liquefied natural gas (LNG) at atmospheric pressure. The system comprises means for a liquefaction stage which in turn comprise:

- means for a pre-cooling stage of the natural gas stream,

- means for a stage of liquefaction and subcooling of the natural gas stream located downstream of the means for the precooling stage, and

- means for an expansion and separation stage of the liquefied natural gas (LNG) product located downstream of the means for the liquefaction and subcooling stage resulting in the liquefied natural gas (LNG) product and vaporized natural gas.

The system of the invention further comprises:

- a steam generating boiler configured for combustion with air of the vaporized natural gas generated in the media for the expansion and separation stage,

- means for capturing the CO<2> contained in the exhaust gases from the steam generating boiler, which in turn comprise:

<o>means for an absorption stage for the extraction of CO<2>from said exhaust gases, and

<o>means for a compression stage located downstream of the means for the absorption stage.

The means for the liquefaction and subcooling stage comprise at least one refrigerant compressor and a back-pressure steam turbine mechanically coupled to the compressor and the means for the pre-cooling stage and the means for the absorption stage comprise a low-pressure steam feed from the back-pressure steam turbines. In addition, the steam generating boiler is configured for the generation of high-pressure steam feeding the back-pressure steam turbines.

The present invention therefore has as its object the liquefaction of a natural gas stream, more specifically pressurized and free of contaminants such as CO<2>, H<2>O, H<2>S, in a liquefaction unit, also integrating a unit for capturing the CO<2> generated by combustion with air in a steam boiler of the vaporized natural gas produced in the liquefaction unit.

As previously mentioned, the natural gas stream after the subcooling stage is expanded to ambient pressure and introduced into a "flash" separation chamber, separating a certain quantity of vaporized natural gas that is used as fuel for the plant and a liquefied natural gas product.

The proposed system presents several advantages when considering the integration of CO2 capture in natural gas liquefaction plants, a critical aspect to reduce the environmental footprint of the plant and increase the competitiveness and sustainability of this energy vector in the coming decades.

The present invention also relates to a method for producing liquefied natural gas (LNG) with CO<2> capture. The method comprises a stream adapted for the circulation of natural gas, the system being adapted for cooling and/or expanding the natural gas stream at low temperatures of -140°C to -170°C in cooling and/or expansion stages to produce liquefied natural gas (LNG) at atmospheric pressure, where the method comprises a liquefaction stage comprising the following stages:

- a pre-cooling stage of the natural gas stream,

- a natural gas stream liquefaction and subcooling stage located downstream of the pre-cooling stage, - a liquefied natural gas (LNG) product expansion and separation stage located downstream of the liquefaction and subcooling stage resulting in the liquefied natural gas (LNG) product and vaporized natural gas.

The method comprises:

- a steam generation stage using a boiler for combustion with air of the vaporized natural gas generated in the expansion and separation stage,

- a stage of capturing the CO<2> contained in the exhaust gases from the steam generation stage, which in turn comprises:

<o>an absorption stage for the extraction of CO<2>from said exhaust gases, and

<o>a compression stage located after the absorption stage.

The liquefaction and subcooling stage comprises at least one refrigerant compressor and a back-pressure steam turbine mechanically coupled to the compressor and the pre-cooling stage and the absorption stage comprise a low-pressure steam feed from the back-pressure steam turbines, the steam generation stage generating high-pressure steam which feeds the back-pressure steam turbines.

Brief description of the drawings

To complement the description being made and in order to assist in a better understanding of the characteristics of the invention, a drawing is included as an integral part of said description, in which, for illustrative and non-limiting purposes, the following has been represented:

Figure 1. Shows a diagram of a first embodiment of the liquefied natural gas production system object of the invention.

Figure 2. Shows a diagram of a second embodiment of the liquefied natural gas production system object of the invention.

Examples of embodiments of the invention

The present invention relates to the liquefaction of a natural gas stream (1), particularly pressurized and free of contaminants such as CO<2>, H<2>O and H<2>S in a liquefaction unit (100) according to, for example, figure 1, also integrating a capture unit for the CO<2>(200) generated by combustion with air (4) in a steam boiler (300) of the vaporized natural gas (3) produced in the liquefaction unit (100).

Figures 1 and 2 show two embodiments that disclose a liquefied natural gas LNG production system with CO<2> capture, comprising a stream adapted for the circulation of natural gas (1). The system is adapted for cooling and/or expanding the natural gas stream at low temperatures of -140°C to -170°C in cooling and/or expansion stages to produce liquefied natural gas LNG at atmospheric pressure. The system comprises means for a liquefaction stage (100) that in turn comprise:

- Means for a pre-cooling stage (101) of the natural gas stream (1).

- Means for a stage of liquefaction and subcooling of the natural gas stream (1) located downstream of the means for the pre-cooling stage (101). The means for a stage of liquefaction and subcooling may consist of separate stages for liquefaction (102) and subcooling (104) or may be integrated into a single stage of liquefaction and subcooling (107, 108) duplicated and operating in parallel.

- Means for an expansion and separation stage (106) of the liquefied natural gas product LNG located downstream of the means for the liquefaction and subcooling stage resulting in the liquefied natural gas product LNG (2) and vaporized natural gas (3).

The system also includes:

- a steam generating boiler (300) configured for combustion with air (4) of the vaporized natural gas (3) generated in the means for the expansion and separation stage (106),

- means for capturing the CO<2>(200) contained in the exhaust gases (5) of the steam generating boiler (300) which in turn comprise:

<o>means for an absorption stage (201) for extracting CO<2> from said exhaust gases (5), and

<o>means for a compression stage (202) located downstream of the means for the absorption stage (201).

In one embodiment, the concentration of CO<2> in the exhaust gases (5) fed to the means for the absorption stage (201), prior to their extraction in the means of the absorption stage (201), is approximately 10% mol, achieving a capture of the CO<2> contained in the exhaust gases (5) of approximately 90%. The air (4) used in the combustion in the steam generation boiler (300) is approximately between 5% and 10% in excess of the stoichiometric.

In an exemplary embodiment, a stream of purified CO (9) is produced at a high pressure of between 110 and 150 bar in the means for a compression stage (202). In another exemplary embodiment, a stream of CO (8) removed from the natural gas stream (1) is also fed to the liquefaction unit (100), not shown in the figure, which could be present in said natural gas stream (1).

The liquefaction unit (100) consists of means for liquefying and subcooling the natural gas stream (1), which consist of compression and expansion refrigeration cycles of a refrigerant.

In the exemplary embodiments shown, the means for liquefaction and subcooling comprise at least one refrigerant compressor (103, 105) and a back-pressure steam turbine (501, 502). The back-pressure steam turbine (501, 502) is mechanically coupled to the compressor (103, 105). Furthermore, the means for the pre-cooling stage (101) of the liquefaction unit (100) and the means for the absorption stage (201) of the capture unit (200) comprise a low-pressure steam feed (10, 11) from the back-pressure steam turbines (501, 502). Furthermore, the steam generating boiler (300) is configured for the generation of high-pressure steam (6) feeding the back-pressure steam turbines (501, 502).

When it is indicated that the turbine operates at back pressure, it refers to the fact that the steam outlet pressure is higher than atmospheric pressure, as opposed to condensation turbines, which expand the steam to vacuum pressures.

According to the above, the power supplied to the refrigeration compressors (103, 105) is carried out by mechanical coupling with counter-pressure steam turbines (501, 502), for example, with an outlet pressure for the expanded steam between the values used in the steam fed to the pre-cooling stage (101).

In an exemplary embodiment, the power of the pre-cooling stage means (101) for generating the coolant is provided by a low-pressure water vapor stream (10) between 1 bar and 6 bar.

Therefore, the low pressure steam (10) fed to the pre-cooling stage (101) provides the cooling power of that stage. The low pressure steam (11) fed to the absorption stage (201) allows to regenerate the solvent used to capture the CO<2>.

In one exemplary embodiment, the system comprises means for selecting the high pressure level and the temperature of the steam at the inlet to the back pressure steam turbines (501, 502) to achieve saturated or slightly superheated steam conditions after expansion in said back pressure steam turbines (501, 502). This indicates that the high pressure steam generating boiler (300) has a very flexible design, and that the outlet pressure of the back pressure steam turbine (501, 502) is such that the low pressure steam can be efficiently integrated into the pre-cooling stage means (101) and the absorption stage means (201).

Both the pre-cooling stage (101) and the absorption unit (201) have a high thermal demand in the form of low-pressure steam (10, 11). This low-pressure steam demand can be met by means of counter-pressure steam turbines (501, 502), which are used instead of conventional gas turbines to drive the refrigeration compressors of the liquefaction/subcooling stages.

In both embodiments shown in Figures 1 and 2, the means for the pre-cooling stage (101) employ ammonia as a refrigerant to reduce the temperature of the natural gas stream (1) to about -30°C. Therefore, the liquefaction unit (100) comprises the pre-cooling stage (101) employing ammonia to reduce the temperature of the natural gas stream (1) to, as indicated above, about -30°C. The power of the pre-cooling stage (101) to generate the ammonia refrigerant is provided by the low pressure steam stream (10) comprised between 1 bar and 6 bar.

Additionally, when CO<2> capture is integrated, the production of power in back-pressure steam turbines (501, 502) through the combustion of vaporized natural gas (3) in the steam boiler (300) with a quantity of air (4) close to stoichiometric, as opposed to several gas turbines in the liquefaction unit (100) and in an auxiliary power plant that in turn employs more gas turbines, allows to obtain a single stream of exhaust gases (5) with all the generated CO<2> present at a high concentration, of approximately 10% mol. prior to the absorption column, avoiding the numerous ducts, pipes and connections of the exhaust gases of each gas turbine, as well as heat recovery boilers specific for each gas turbine through which to generate the steam for the regeneration of the absorbent of the CO<2> capture unit, whose pressure loss would also decrease the power provided by the gas turbine, reducing the production of liquefied natural gas LNG.

In one embodiment, the steam generating boiler (300) is configured for combustion with air (4) of the vaporized natural gas fraction (3) in an amount between 5% and 10% higher than the stoichiometric. This allows the CO<2> to be more concentrated in the exhaust gases (5) of the steam boiler (300), as opposed to gas turbines, which operate with large excesses of air. Therefore, the exhaust gases of gas turbines, with a more diluted CO<2> concentration, approximately 3.0 to 3.5% mol, require a larger absorption unit for the same amount of sequestered CO<2>: larger direct mixing exchangers and greater diameter and height of the absorption column due to having to treat a greater volumetric flow and with less concentrated CO<2>. These additional elements introduced when implementing CO<2> capture cause a substantial increase in the surface area required by the plant, which can be reduced with the proposed scheme for the reasons described. All this results in a lower cost of avoiding CO<2> compared to technologies that implement CO<2> capture from gas turbine exhaust gases, allowing greater LNG production in the liquefaction unit (100), before reaching the construction limits of the absorption unit (200).

Technologies using propane or mixed refrigerants for pre-cooling use electrical power supplied to refrigeration compressors, rather than thermal power. Steam turbines were used to drive refrigeration compressors in conventional technology plants without capture in the past, but the low efficiency of conversion to electricity, the expensive water treatment systems, boilers and steam condensers, since the turbines expand to vacuum pressures to reach acceptable efficiencies, requiring very bulky equipment, led to their gradual replacement by more efficient gas turbines, industrial turbines and, more recently, aeroderivative turbines. Nevertheless, steam cycles have certain advantages:

• Back pressure steam turbines (501, 502) can be designed in any power size, as opposed to gas turbines which are available for discrete fixed powers, allowing greater flexibility in designing and selecting the size of the liquefaction unit (100) as well as allocating the powers between the liquefaction and subcooling stages. Similarly, the steam boiler (300) can be built for any power and steam pressures/temperatures, with sizes greater than 800 MW of thermal power being common in coal-fired power plants.

• The vaporized natural gas (3) fed to the steam boiler (300) does not need to be pressurized, avoiding an expensive gaseous fuel compressor, auxiliary power generation and an associated electric motor. In plants that use gas turbines, the fuel must be compressed to the operating pressure ratio of the turbine, which can be around 50. On the other hand, using steam cycles with the heat generated in the boiler, i.e., an external combustion engine, practically eliminates the influence of ambient conditions, air temperature, humidity, atmospheric pressure, etc., on the production of liquefied natural gas (LNG) in the plant, making it stable over time. Steam turbines (501, 502) consist of less rotating equipment than gas turbines, there is no compressor, and they operate at a lower temperature, allowing high availability, reliability and easy maintenance.

• Additionally, with the proposed liquefaction technology, bulky and expensive vacuum condensers for condensing the expanded steam of the power cycle are avoided, in addition to allowing a smaller outlet section of the backpressure steam turbine (501, 502) by eliminating the low pressure stages, with a lower number of components and a reduction in capital cost. Heat rejection from the power cycle is carried out in the natural gas pre-cooling stage (101) and in the CO<2> absorption stage (201) at a pressure between 1 and 6 bar, reducing the investment cost of the cycle. Since the technology of the pre-cooling stage (101) allows to substantially reduce the demand for electrical power by increasing the thermal demand, it is not critical that the steam cycle has a low efficiency of conversion of fuel to electrical energy, since the waste heat is effectively integrated for various uses in the plant, achieving a high net thermal efficiency, defined as the ratio of the product of flow by the calorific value of the liquefied natural gas (LNG) product between that of the gas fed to the plant. Also, the steam boiler (300) has great flexibility of regulation to satisfy the demands of steam as required. It is noted that, if the back-pressure steam turbine coupling system (501, 502) were used in conventional liquefaction technologies, without the pre-cooling stage (101), there would be a large remainder of steam that would be wasted. This would lead to a lower net thermal efficiency, resulting in a system that would not be competitive.

The vaporized natural gas stream (3) is sent to the steam generation boiler (300) after cold recovery, not shown in the figures, where high pressure steam (6) is produced and fed to the back pressure steam turbines (501, 502), by carrying out the combustion with a quantity of air (4) close to the stoichiometric amount required. Both the air stream (4) and the vaporized natural gas fuel (3) can have a blower to overcome the pressure losses downstream, respectively. Additionally, high pressure steam (6) is also produced to be supplied to other back pressure steam turbines that generate the auxiliary power required by the liquefaction plant in an auxiliary power unit (400), and from this auxiliary power unit (400) additional low pressure steam is provided to the pre-cooling stage (101) and the absorption stage (201), in addition to electrical power for other uses of the plant, for example, the CO<2> compression stage (202).

The low temperature exhaust gases (5), approximately 130°C, leaving the steam boiler (300) are taken to the CO<2> capture unit (200), which consists of a first absorption stage (201) where the gas is cooled by direct contact exchangers with cooling water, to a temperature close to ambient, or lower, if auxiliary cooling is provided, condensing part of the water present as a combustion product, and the pressure is raised slightly by means of a blower to overcome the pressure losses of the downstream absorber. The gas, with a molar concentration of CO<2> close to 10%, is introduced into an absorption column or absorber. That is, first there is a direct mixture exchanger to lower the temperature and condense part of the water present in the exhaust gases (5) and then an absorption column.

The concentration of CO<2> in the exhaust gases of industrial gas turbines is at this point in the process around 3.0-3.5% mol, which implies a reduction of the volumetric flow entering the absorber by approximately 2/3, according to the proposed scheme.

In one exemplary embodiment, the means of the absorption stage (201) for the extraction of CO<2> from the exhaust gases (5) use a solvent and low pressure steam (11) from the counter-pressure steam turbines (501, 502) for the regeneration of said solvent.

Absorption may be carried out with monoethanolamine (MEA) or with other commercial absorption solvents/systems. For example, CO<2> absorption may be carried out with an aqueous solution of ammonia, which is the refrigerant used in the pre-cooling stage (101). The exhaust gases (7) from the absorption stage media (201) at ambient pressure are vented to the atmosphere, achieving approximately 90% capture of CO<2> present in the feed stream, i.e. in the exhaust gases (5) of the steam generating boiler (300). The absorbent is regenerated in a stripper through the thermal power supplied by a low pressure steam stream (11) coming from the back pressure steam turbines (501, 502) driving the refrigeration compressors (103, 105) and/or the auxiliary power unit (400). For the absorbent consisting of a 30% by weight MEA solution, a thermal power of 3.7 MJ/kg CO<2> captured is required, according to scientific literature. The feed water (12) to the steam generation boiler (300) coming from the pre-cooling stage (101) and the absorption stage (201), after condensation of the low pressure steam streams (10, 11), is reintroduced into the steam generation boiler (300) to repeat the cycle. If necessary, the steam generation boiler (300) could have low pressure steam production directly to partially supply the pre-cooling (101) and absorption stages (201).

The CO<2> produced in the condenser of the desorption column or "stripper" of the absorption stage (201) is sent to the compression stage (202) where traces of water are eliminated and it is compressed until reaching supercritical pressures in the purified CO<2> stream (9), of between 110 and 150 bar, for its subsequent transport and storage. A stream of CO<2>(8) removed from the natural gas stream (1) in a previous treatment stage, not shown in the figure, which could be present in the natural gas, is also fed into the compression unit.

Currently, the size of the post-combustion capture unit that would be required by a ~4.6 mtpa liquefaction train corresponds to the sizes of currently operating commercial capture plants for electric power generation, which are close to the achievable construction limits, particularly for the absorber cross section, so the present invention eliminates a critical bottleneck for implementing CO<2> capture in liquefied natural gas (LNG) plants by reducing the volumetric flow of gases to be treated, making said capture competitive for comparatively lower CO<2> prices, and also being able to achieve higher productions in each liquefaction train that integrates capture.

As an alternative to the proposed scheme with CO<2> capture, a plant could be proposed with the same coupling system of refrigerant compressors (103, 105) and back-pressure steam turbines (501, 502), feeding the steam at the outlet of these to the pre-cooling stage (101), but lacking the CO<2> capture unit (200). Such a plant would achieve specific CO<2> emissions comparable to those produced in plants that use conventional technologies and industrial gas turbines without CO<2> capture.

In the first exemplary embodiment shown in Figure 1 the means for the liquefaction stage (102) of the natural gas stream (1) are located downstream of the pre-cooling stage (101) and the means for the sub-cooling stage (104) of the natural gas stream (1) are located downstream of the liquefaction stage (102). Both the means for the liquefaction stage (102) and the means for the sub-cooling stage (104) comprise at least one refrigerant compressor (103, 105) and a back-pressure steam turbine (501, 502) mechanically coupled to the compressor (103, 105).

The liquefaction (102) and subcooling (104) stages may be thermally coupled to the precooling stage (101), thermally coupled being understood as the fact that streams of matter belonging to each stage exchange heat with each other respectively.

In the exemplary embodiment of Figure 1, when the refrigerant used in the liquefaction stage (102) is pure ethylene or ethane, which is condensed in the pre-cooling stage (101), and a mixed refrigerant, a mixture of nitrogen, methane and ethylene, or nitrogen, methane and ethane, is used in the subcooling stage (104), the electrical demand of the liquefaction stage (100) is around 140 kWh/tonne LNG, excluding auxiliary consumption of the plant, while the thermal demand, low pressure steam consumption, of the pre-cooling stage (101) and the CO<2> absorption stage (201) is approximately 570 kWh/tonne LNG, when a 30% by weight MEA solution is used for CO<2> capture, achieving a thermal efficiency greater than 94%, for a heat rejection temperature of 20°C. Alternatively, according to the first exemplary embodiment, both the liquefaction stage (102) and the subcooling stage (104) may each employ a mixed refrigerant, hydrocarbon mixture, operating in series.

The embodiment corresponding to Figure 1 may have a mixed refrigerant for the liquefaction stage (102) and another refrigerant of different composition for the subcooling stage (104). Or, alternatively, as indicated for the numerical results provided in this embodiment, a pure refrigerant for the liquefaction stage (102) and a mixed refrigerant for the subcooling stage (104).

In the second embodiment corresponding to Figure 2, both the means for liquefying and the means for subcooling the natural gas stream (1) are integrated into a single liquefaction and subcooling stage (107, 108), which is duplicated, and both are located downstream of the precooling stage (101), operating in parallel to each other. Each duplicated stage (107, 108) comprises at least one refrigerant compressor (103, 105) and a back-pressure steam turbine (501, 502), mechanically coupled to the compressor (103, 105). Furthermore, the refrigeration compressors (103, 105) corresponding to each stage integrating liquefaction and subcooling are identical.

Therefore, the liquefaction and subcooling of the natural gas stream (1) can be integrated into a single liquefaction and subcooling stage (107, 108) duplicated by operating in parallel so that they share the same means of the pre-cooling unit (101), with respective refrigeration compressors (103, 105) driven in turn by the back-pressure steam turbines (501, 502).

The expansion and separation stage (106) of the liquefied natural gas product LNG (2) and vaporized natural gas (3) of the plant may be common. The liquefaction and subcooling stages (107, 108) are thermally coupled, i.e. the refrigerant used for the liquefaction and subcooling of the natural gas stream (1) is cooled by condensing it totally or partially in the precooling stage (101), by means of the ammonia refrigerant. Said refrigerant, which carries out the liquefaction and subcooling in the duplicated liquefaction and subcooling stages (107, 108), may be a mixed refrigerant consisting of a mixture of hydrocarbons such as butane, propane, ethane, methane and nitrogen, a stream not indicated in Figure 2, such as the mixed refrigerant used in the C3MR liquefaction technology.

The second implementation example raises the possibility of integrating two natural gas liquefaction trains that share the same pre-cooling stage (101). In the exemplary embodiment of Figure 2 where a mixed refrigerant as described above is used, which is partially condensed with ammonia in the pre-cooling unit (101) and is subsequently used for the liquefaction and sub-cooling of the natural gas stream (1) in two stages arranged in parallel, the specific electrical consumption for the liquefaction unit (100) is approximately 150 kWh/tonne of LNG, while the thermal demand reached in the pre-cooling stage (101) and the CO<2> absorption stage (201) is approximately 470 kWh/tonne of LNG, when a 30% by weight MEA solution is used as an absorbent in the CO<2> absorption stage (201), and a temperature of 20°C, after heat rejection.

This arrangement allows, in a similar way to the exemplary embodiment of figure 1, to simultaneously satisfy the thermal and electrical demands of the liquefaction stage (100) and the CO<2> capture stage (200), by means of the steam cycle with generation of high pressure steam (6) in the boiler (300), achieving a high net thermal efficiency, defined as the ratio of the product of the flow rate of liquefied natural gas product LNG (2) by its calorific value with respect to that of the feed gas, similar to that of liquefaction plants with industrial turbines without CO<2> capture, which turns out to be approximately 95% when considering a heat rejection temperature of 20°C for the process fluid.

According to the second embodiment, the thermal demand is reduced, thus increasing the overall thermal efficiency and increasing the availability of the plant by operating in parallel with respect to the first embodiment, but at the cost of increasing the number of equipment: cryogenic heat exchanger in the integrated liquefaction and subcooling stage (107, 108), also requiring the presence of heavier and more flammable hydrocarbons such as propane and butane in the mixed refrigerant, which results in higher investment costs and a more complex operation, respectively. Finally, the use of two trains in parallel for liquefaction and subcooling could allow higher productions to be achieved than series schemes corresponding to the embodiment in figure 1, maximizing the benefits from economies of scale.

Claims (12)

1.- Liquefied natural gas LNG production system with CO<2> capture, comprising a stream adapted for the circulation of natural gas (1), the system being adapted for the cooling and/or expansion of the natural gas stream (1) at low temperatures of -140 °C to -170 °C in cooling and/or expansion stages to produce liquefied natural gas LNG at atmospheric pressure, where the system comprises means for a liquefaction stage (100) which in turn comprise: - means for a pre-cooling stage (101) of the natural gas stream (1), - means for a stage of liquefaction and subcooling of the natural gas stream (1) located downstream of the means for the pre-cooling stage (101), - means for an expansion and separation stage (106) of the liquefied natural gas product LNG located downstream of the means for the liquefaction and subcooling stage resulting in the liquefied natural gas product LNG (2) and vaporized natural gas (3), characterized in that the system comprises: - a steam generating boiler (300) configured for combustion with air (4) of the vaporized natural gas (3) generated in the means for the expansion and separation stage (106), - means for capturing the CO<2>(200) contained in the exhaust gases (5) of the steam generating boiler (300) which in turn comprise: <o>means for an absorption stage (201) for extracting CO<2> from said exhaust gases (5), and <o>means for a compression stage (202) located downstream of the means for the absorption stage (201), where the means for the liquefaction and subcooling stage comprise at least one refrigerant compressor (103, 105) and a back-pressure steam turbine (501, 502) mechanically coupled to the compressor (103, 105) and the means for the pre-cooling stage (101) and the means for the absorption stage (201) comprise a low-pressure steam feed (10, 11) from the back-pressure steam turbines (501, 502), the steam generating boiler (300) being configured for the generation of high-pressure steam (6) feeding the back-pressure steam turbines (501, 502). 2. - Liquefied natural gas LNG production system with CO<2> capture, according to claim 1, characterized in that the means for a liquefaction and subcooling stage of the natural gas stream (1) comprise means for a liquefaction stage (102) of the natural gas stream (1) and means for a subcooling stage (104) of the natural gas stream (1) where the means for the liquefaction stage (102) of the natural gas stream (1) are located downstream of the means for the precooling stage (101) and the means for the subcooling stage (104) of the natural gas stream (1) are located downstream of the means for the liquefaction stage (102) where both the means for the liquefaction stage (102) and the means for the subcooling stage (104) comprise at least one refrigerant compressor (103, 105) and a back pressure steam turbine (501, 502) mechanically coupled to the compressor (103, 105). 3. - Liquefied natural gas production system LNG with CO<2> capture, according to claim 1, characterized in that the means for a stage of liquefaction and subcooling of the natural gas stream (1) are integrated in a single stage of liquefaction and subcooling (107, 108), duplicated operating in parallel to each other, both located after the means for the precooling stage (101), where each duplicated stage (107, 108) comprises at least one refrigerant compressor (103, 105) and a backpressure steam turbine (501, 502), mechanically coupled to the compressor (103, 105). 4. - Liquefied natural gas LNG production system with CO<2> capture, according to any one of the preceding claims, characterized in that the means of the absorption stage (201) for the extraction of CO<2> from the exhaust gases (5) use a solvent and low pressure steam (11) from the counter-pressure steam turbines (501, 502) for the regeneration of said solvent. 5. - Liquefied natural gas LNG production system with CO<2> capture, according to claim 4, characterized in that the solvent is monoethanolamine (MEA) or an aqueous solution of ammonia. 6. - Liquefied natural gas LNG production system with CO2 capture, according to any one of the preceding claims, characterized in that the concentration of CO2 in the exhaust gases (5) is approximately 10% mol prior to its extraction in the means of the absorption stage (201), achieving a capture of the CO<2> contained in the exhaust gases (5) of approximately 90%. 7. - Liquefied natural gas LNG production system with CO<2> capture, according to any one of the preceding claims, characterized in that the means for the pre-cooling stage (101) use ammonia as a refrigerant to reduce the temperature of the natural gas stream (1) to approximately -30°C. 8. - Liquefied natural gas (LNG) production system with CO<2> capture, according to any one of the preceding claims, characterized in that the power of the means of the pre-cooling stage (101) to generate the refrigerant is provided by a low pressure water vapor stream (10) between 1 bar and 6 bar. 9. - Liquefied natural gas LNG production system with CO<2> capture, according to any one of the preceding claims, characterized in that the steam generation boiler (300) is configured for combustion with air (4) of the vaporized natural gas fraction (3) in an amount between 5% and 10% higher than the stoichiometric amount. 10. - Liquefied natural gas LNG production system with CO<2> capture, according to any one of the preceding claims, characterized in that the means for a compression stage (202) are configured for the production of a purified CO2 stream (9) at a pressure between 110 and 150 bar. 11. - Liquefied natural gas LNG production system with CO<2> capture, according to any one of the preceding claims, characterized in that the means for a compression stage (202) are also fed with a stream of CO<2>(8) removed from the natural gas stream (1) prior to the liquefaction unit (100). 12. - Method for producing liquefied natural gas LNG with CO<2> capture, comprising a stream adapted for the circulation of natural gas (1), the system being adapted for cooling and/or expanding the natural gas stream (1) at low temperatures of -140 °C to -170 °C in cooling and/or expansion stages to produce liquefied natural gas LNG at atmospheric pressure, where the method comprises a liquefaction stage (100) comprising the following stages: - a pre-cooling stage (101) of the natural gas stream (1), - a stage of liquefaction and subcooling of the natural gas stream (1) located after the pre-cooling stage (101), - an expansion and separation stage (106) of the liquefied natural gas product LNG located following the liquefaction and subcooling stage resulting in the liquefied natural gas product LNG (2) and vaporized natural gas (3), characterized in that the method comprises: - a steam generation stage (300) by means of a boiler for the combustion with air (4) of the vaporized natural gas (3) generated in the expansion and separation stage (106), - a stage of capturing the CO<2>(200) contained in the exhaust gases (5) of the steam generation stage (300), which in turn comprise: <o>an absorption stage (201) for extracting CO<2>from said exhaust gases (5), and <o>a compression stage (202) located after the absorption stage (201), wherein the liquefaction and subcooling stage comprises at least one refrigerant compressor (103, 105) and a back pressure steam turbine (501, 502) mechanically coupled to the compressor (103, 105) and the pre-cooling stage (101) and the absorption stage (201) comprise a low pressure steam feed (10, 11) from the back pressure steam turbines (501, 502), the steam generation stage (300) generating high pressure steam (6) which feeds the back pressure steam turbines (501, 502).