System and method for producing liquefied natural gas (LNG) with co2 capture

Abstract

The present invention relates to a system and method for producing liquefied natural gas (LNG) with CO2 capture, comprising: - a steam generation boiler (300) for combustion with air (4) of the vapourised natural gas (3) generated in an expansion and separation step (106), - means for capturing the CO2 (200) contained in the exhaust gases (5) from the steam generation boiler (300) which comprise absorption (201) and compression (202) steps. The liquefying and subcooling step comprises a refrigerant compressor (103, 105) and a counterpressure steam turbine (501, 502). The absorption step (201) comprises a low-pressure water vapour supply (10, 11) from the counter-pressure steam turbines (501, 502). The steam generation boiler (300) generates high-pressure steam (6) which supplies the counter-pressure steam turbines (501, 502).

Description

[0001] DESCRIPTION

[0002] System and method for producing liquefied natural gas (LNG) with CO2 capture

[0003] Technology sector

[0004] The present invention pertains to the field of technology 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 integrates a CO2 capture unit.

[0005] Background of the invention

[0006] Liquefied natural gas (LNG) is natural gas that has been processed for transport in a liquid state. The natural gas is transported in this liquid state at atmospheric pressure and at a temperature range of approximately -150°C to -170°C.

[0007] To convert natural gas into 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.

[0008] In the liquefaction process, refrigerant gases are compressed, producing cold liquids such as propane, ethane / ethylene, methane, nitrogen, or mixtures thereof. These liquids then evaporate 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 liquefied, the gas is expanded to allow for storage at atmospheric pressure. The liquefied natural gas (LNG) produced is stored in special tanks for later transfer to specialized transport tankers.

[0009] A key aspect of these types of plants is to reduce their environmental footprint and increase their competitiveness and sustainability.

[0010] Summary of the invention

[0011] The present invention relates to a liquefied natural gas (LNG) production system with CO2 capture. The system comprises a stream adapted for the circulation of natural gas, and is adapted for cooling and / or expanding the natural gas stream to low temperatures of -140°C to -170°C in cooling and / or expansion stages to produce LNG at atmospheric pressure. The system comprises means for a liquefaction stage, which in turn comprise:

[0012] - means for a pre-cooling stage of the natural gas stream,

[0013] - means for a liquefaction and subcooling stage of the natural gas stream located downstream of the means for the precooling stage, and

[0014] - 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.

[0015] The system of the invention further comprises:

[0016] - a steam generating boiler configured for combustion with air of the vaporized natural gas generated in the means for the expansion and separation stage,

[0017] - means for capturing the CO2 contained in the exhaust gases of the steam generating boiler, comprising: either means for an absorption stage for extracting the CO2 from said exhaust gases, or 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 backpressure steam turbine mechanically coupled to the compressor, and the means for the precooling stage and the means for the absorption stage comprise a low-pressure steam feed from the backpressure steam turbines. Furthermore, the steam generating boiler is configured for the generation of high-pressure steam that feeds the backpressure steam turbines.

[0018] The present invention has, therefore, as its object the liquefaction of a natural gas stream, more specifically pressurized and free of contaminants such as CO2, H2O, H2S, in a liquefaction unit, also integrating a unit for capturing the CO2 generated by combustion with air in a steam boiler of the vaporized natural gas produced in the liquefaction unit.

[0019] 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 amount of vaporized natural gas that is used as fuel for the plant and a liquefied natural gas product.

[0020] The proposed system presents several advantages when considering the integration of CO2 capture in natural gas liquefaction plants, a critical aspect to reduce the plant's environmental footprint and increase the competitiveness and sustainability of this energy vector in the coming decades.

[0021] A method for producing liquefied natural gas (LNG) with CO2 capture is also an object of the present invention. 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 to low temperatures of -140°C to -170°C in cooling and / or expansion stages to produce liquefied natural gas (LNG) at atmospheric pressure, wherein the method comprises a liquefaction stage comprising the following steps:

[0022] - a pre-cooling stage of the natural gas stream,

[0023] - a liquefaction and subcooling stage of the natural gas stream located downstream of the precooling stage,

[0024] - an expansion and separation stage of the liquefied natural gas (LNG) product located after the liquefaction and subcooling stage that results in the liquefied natural gas (LNG) product and vaporized natural gas.

[0025] The method comprises:

[0026] - a steam generation stage using a boiler for combustion with air of the vaporized natural gas generated in the expansion and separation stage,

[0027] - a stage for capturing the CO2 contained in the exhaust gases from the steam generation stage, comprising in turn: either an absorption stage for extracting CO2 from said exhaust gases, or a compression stage located after the absorption stage.

[0028] The liquefaction and subcooling stage comprises at least one refrigerant compressor and a backpressure steam turbine mechanically coupled to the compressor, and the precooling and absorption stages comprise a low-pressure steam feed from the backpressure steam turbines, the steam generation stage generating high-pressure steam that feeds the backpressure steam turbines.

[0029] Brief description of the drawings

[0030] To complement the description being made and to help 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:

[0031] Figure 1. Shows a schematic of a first example of the embodiment of the liquefied natural gas production system that is the subject of the invention.

[0032] Figure 2. Shows a schematic of a second example of the embodiment of the liquefied natural gas production system that is the subject of the invention.

[0033] Figure 3. Shows a schematic of a third example of the embodiment of the liquefied natural gas production system that is the subject of the invention.

[0034] Examples of realization of the invention

[0035] The present invention relates to the liquefaction of a natural gas stream (1), particularly pressurized and free of contaminants such as CO2, H2O and H2S in a liquefaction unit (100) according, for example, to Figure 1, also integrating a CO2 capture unit (200) generated by combustion with air (4) in a steam boiler (300) of the vaporized natural gas (3) produced in the liquefaction unit (100).

[0036] Figures 1 and 2 depict two exemplary embodiments disclosing a liquefied natural gas (LNG) production system with CO2 capture, comprising a stream adapted for natural gas circulation (1). The system is adapted for cooling and / or expanding the natural gas stream to low temperatures of -140°C to -170°C in cooling and / or expansion stages to produce LNG at atmospheric pressure. 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).

[0037] - Means for a liquefaction and subcooling stage of the natural gas stream (1) located downstream of the means for the precooling stage (101). The means for a liquefaction and subcooling stage may consist of separate stages for liquefaction (102) and subcooling (104) or are integrated into a single liquefaction and subcooling stage (107, 108) duplicated and operating in parallel.

[0038] - Means for an expansion and separation stage (106) 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 (2) and vaporized natural gas (3).

[0039] The system also includes:

[0040] - 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),

[0041] - means for capturing the CO2 (200) contained in the exhaust gases (5) of the steam generating boiler (300) comprising in turn: either means for an absorption stage (201) for extracting CO2 from said exhaust gases (5), or means for a compression stage (202) located downstream of the means for the absorption stage (201).

[0042] In one embodiment, the CO2 concentration in the exhaust gases (5) fed to the absorption stage media (201), prior to extraction in the absorption stage media (201), is approximately 10 mol%, achieving a CO2 capture rate of approximately 90% in the exhaust gases (5). The air (4) used for combustion in the steam generation boiler (300) is approximately 5% to 10% in excess of the stoichiometric amount.

[0043] In one embodiment of the means for a compression stage (202), a purified CO2 stream (9) is produced at a high pressure, between 110 and 150 bar. In another embodiment, a CO2 stream (8) removed from the natural gas stream (1) prior to the liquefaction unit (100), not shown in Figures 1 and 2, is also fed, which may be present in said natural gas stream (1).

[0044] The liquefaction unit (100) consists of means for liquefying and subcooling the natural gas stream (1), which are composed of refrigerant compression and expansion refrigeration cycles.

[0045] In the exemplary embodiments shown, the means for liquefaction and subcooling comprise at least one refrigerant compressor (103, 105) and one backpressure steam turbine (501, 502). The backpressure steam turbine (501, 502) is mechanically coupled to the compressor (103, 105). Furthermore, the means for the precooling 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 backpressure steam turbines (501, 502). In addition, the steam generating boiler (300) is configured for the generation of high-pressure steam (6) that feeds the backpressure steam turbines (501, 502).

[0046] When it is stated that the turbine operates under back pressure, it means that the steam outlet pressure is higher than atmospheric pressure, as opposed to condensing turbines, which expand the steam to vacuum pressures.

[0047] 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).

[0048] In one embodiment, the power of the pre-cooling stage means (101) to generate the refrigerant is provided by a low-pressure water vapor stream (10) between 1 bar and 6 bar.

[0049] Therefore, the low-pressure steam (10) fed to the pre-cooling stage (101) provides the cooling power for that stage. The low-pressure steam (11) fed to the absorption stage (201) allows the solvent used to capture CO2 to be regenerated.

[0050] In one embodiment, the system comprises means for selecting the high-pressure level and temperature of the steam at the inlet of the backpressure steam turbines (501, 502) to achieve saturated or slightly superheated steam conditions after expansion in said backpressure steam turbines (501, 502). This indicates that the high-pressure steam-generating boiler (300) has a highly flexible design, and that the outlet pressure of the backpressure steam turbine (501, 502) is such that the low-pressure steam can be efficiently integrated into the means for the precooling stage (101) and the means for the absorption stage (201).

[0051] Both the precooling 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 the backpressure steam turbines (501, 502), which are used instead of conventional gas turbines to drive the refrigeration compressors of the liquefaction / subcooling stages.

[0052] In both embodiments shown in Figures 1 and 2, the means for the precooling stage (101) employ ammonia as a refrigerant to reduce the temperature of the natural gas stream (1) to approximately -30°C. Therefore, the liquefaction unit (100) comprises the precooling stage (101) that uses ammonia to reduce the temperature of the natural gas stream (1) to approximately -30°C, as indicated above. The power for the precooling stage (101) to generate the ammonia refrigerant is provided by the low-pressure steam stream (10) between 1 bar and 6 bar.

[0053] Additionally, when CO2 capture is integrated, the power production in backpressure steam turbines (501, 502) through the combustion of vaporized natural gas (3) in the steam boiler (300) with an amount 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 obtaining a single exhaust gas stream (5) with all the generated CO2 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 to each gas turbine through which to generate the steam for the regeneration of the absorbent of the CO2 capture unit, whose pressure loss would also decrease the power provided by the gas turbine, reducing the production of liquefied natural gas LNG.

[0054] In one embodiment, the steam generating boiler (300) is configured for combustion with air (4) of the vaporized natural gas fraction (3) at a rate between 5% and 10% higher than the stoichiometric amount. This results in a higher concentration of CO2 in the exhaust gases (5) from the steam boiler (300), in contrast to the gas turbines, which operate with large excess air. Therefore, the exhaust gases from the gas turbines, with a more dilute CO2 concentration of approximately 3.0 to 3.5 mol%, require a larger absorption unit for the same amount of CO2 sequestered: larger direct-mix heat exchangers and a larger diameter and height of the absorption column are needed to process a higher volumetric flow rate with less concentrated CO2.These additional elements introduced when implementing CO2 capture result in a substantial increase in the plant's required surface area, which can be reduced with the proposed scheme for the reasons described. All of this leads to a lower CO2 avoidance cost compared to technologies that implement CO2 capture from gas turbine exhaust gases, allowing for greater LNG production in the liquefaction unit (100) before reaching the design limits of the absorption unit (200).

[0055] Technologies that use propane or mixed refrigerants for precooling employ electrical power supplied to the refrigeration compressors, rather than thermal power. Driving refrigeration compressors with steam turbines in conventional plants without heat capture was common in the past, but the low efficiency of converting steam to electricity, the costly water treatment systems, boilers, and steam condensers (since the turbines expand to vacuum pressures to achieve 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 offer certain advantages:

[0056] • Backpressure steam turbines (501, 502) can be designed in any power size, unlike gas turbines which are available for discrete fixed power outputs. This allows for greater flexibility in designing and selecting the size of the liquefaction unit (100), as well as distributing power between the liquefaction and subcooling stages. Similarly, the steam boiler (300) can be built for any power output and steam pressures / temperatures, with sizes exceeding 800 MW of thermal power being common in power generation plants that use coal as fuel.

[0057] • The vaporized natural gas (3) fed to the steam boiler (300) does not require pressurization, thus avoiding a costly gas fuel compressor, auxiliary power generation, and an associated electric motor. In plants using gas turbines, the fuel must be compressed to the turbine's operating pressure ratio, which can reach approximately 50. Furthermore, using steam cycles with the heat generated in the boiler, i.e., an external combustion engine, virtually eliminates the influence of ambient conditions—air temperature, humidity, atmospheric pressure, etc.—on the plant's liquefied natural gas (LNG) production, making it stable over time. The steam turbines (501, 502) have fewer rotating components than gas turbines, no compressor, and operate at lower temperatures, allowing for high availability, reliability, and easy maintenance.

[0058] • Additionally, the proposed liquefaction technology eliminates the need for bulky and expensive vacuum condensers to condense the expanded steam from the power cycle. Furthermore, it allows for a smaller outlet section of the backpressure steam turbine (501, 502) by eliminating the low-pressure stages, resulting in fewer components and reduced capital costs. Heat rejection from the power cycle occurs in the natural gas precooling stage (101) and the CC absorption stage (201) at pressures between 1 and 6 bar, further reducing the cycle's investment cost.Since the precooling stage technology (101) substantially reduces the electrical power demand by increasing the thermal demand, the low efficiency of the steam cycle in converting fuel to electrical energy is not critical, as the waste heat is effectively integrated for various uses within the plant, achieving a high net thermal efficiency, defined as the ratio of the product of the flow rate and the calorific value of the liquefied natural gas (LNG) to that of the gas fed to the plant. Furthermore, the steam boiler (300) offers considerable regulatory flexibility to meet steam demands as required. It should be noted that if the backpressure steam turbine coupling system (501, 502) were used in conventional liquefaction technologies without the precooling stage (101), a large amount of residual steam would be wasted.This would lead to lower net thermal efficiency, resulting in a system that would not be competitive.

[0059] The vaporized natural gas stream (3) is sent to the steam generating 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 combustion with an amount of air (4) close to the required stoichiometric amount. Both the air stream (4) and the vaporized natural gas fuel (3) can be equipped with a blower to overcome downstream pressure losses, 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, e.g., the CO2 compression stage (202).

[0060] The means for the CO2 compression stage (202) can be driven directly by a separate and independent backpressure turbine from the backpressure steam turbines (501, 502) that drive the refrigeration compressors of the liquefaction unit (100).

[0061] In one embodiment, the auxiliary power unit (400) may comprise a backpressure steam turbine configured for the mechanical drive of the means for the compression stage (202) and for supplying low-pressure steam from the turbine to the means for the precooling stage (101) of the stream adapted for natural gas circulation (1). Or, in other words, the drive of the CO2 compression stage (202) and the partial supply of low-pressure steam (10) to the precooling stage (101) may be carried out by the auxiliary power unit (400) comprising a backpressure steam turbine.Therefore, the mechanical drive of the CO2 compression stage (202) is carried out by means of a back-pressure steam turbine included in the auxiliary power unit (400), which feeds the low-pressure steam exiting the turbine to the pre-cooling stage (101) of the stream adapted for the circulation of natural gas (1).

[0062] In one embodiment, the auxiliary power unit (400) comprises said backpressure steam turbine that mechanically drives the means for the CO2 compression stage (202). In another embodiment, the means for the CO2 compression stage (202) can be driven by an electric motor powered by energy from and generated in the auxiliary power unit (400).

[0063] Therefore, the low-pressure steam from the back-pressure turbine driving the means for the CO2 compression stage (202) can be fed to the means for the pre-cooling stage (101) to generate the ammonia refrigerant in the liquefaction stage (100).

[0064] The low-pressure steam feed stream (10) fed to the pre-cooling stage (101) is partially made up of the low-pressure steam exiting the back-pressure steam turbine that drives the means for the compression (202) of CO2.

[0065] The figures show how the low-pressure steam from the turbines (501, 502) and the auxiliary power unit (400) is distributed between the low-pressure steam feed (10) to the pre-cooling stage (101) and the low-pressure steam feed (11) to the absorption stage (201).

[0066] Therefore, the backpressure steam turbine outlet in the auxiliary power unit (400), which drives the means for the CO2 compression stage (202), can be fed entirely to the pre-cooling stage (101) of the liquefaction stage (100). The low-temperature exhaust gases (5), approximately 130°C, from the steam boiler (300) are fed to the CO2 capture unit (200). This unit consists of a first absorption stage (201) where the gas is cooled by direct-contact heat exchangers with cooling water to near-ambient temperature, or lower if auxiliary cooling is provided. This process condenses some of the water present as a combustion product, and the pressure is slightly increased by a blower to overcome pressure losses in the downstream absorber. The gas, with a molar concentration of CO2 close to 10%, is then introduced into an absorption column or absorber.That is, first there is a direct mix exchanger to lower the temperature and condense some of the water present in the exhaust gases (5) and then an absorption column.

[0067] The concentration of CO2 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 rate entering the absorber of approximately 2 / 3, according to the proposed scheme.

[0068] In one embodiment, the means of the absorption stage (201) for extracting CO2 from the exhaust gases (5) employ a solvent and low-pressure steam (11) from the back-pressure steam turbines (501, 502) for the regeneration of said solvent.

[0069] Absorption can be carried out using monoethanolamine (MEA) or other commercially available solvents / absorption systems. In one embodiment, absorption can be performed using methyldiethanolamine (MDEA) as the solvent. Although MDEA is more expensive, it has a lower regeneration heat demand than MEA. For example, CO2 absorption can also be performed using an aqueous ammonia solution, which is the refrigerant used in the precooling stage (101). The gases exiting (7) from the absorption stage (201) at ambient pressure are vented to the atmosphere, achieving approximately 90% capture of the CO2 present in the feed stream, i.e., the exhaust gases (5) from the steam generator boiler (300).The absorbent is regenerated in a stripper using thermal power supplied by a low-pressure steam stream (11) from the backpressure steam turbines (501, 502) that drive the refrigeration compressors (103, 105) and / or the auxiliary power unit (400). According to the scientific literature, a thermal power of 3.7 MJ / kg CO2 captured is required for the absorbent, which consists of a 30 wt% MEA solution. The feedwater (12) to the steam generator boiler (300), from the precooling stage (101) and the absorption stage (201), after the condensation of the low-pressure steam streams (10, 11), is reintroduced into the steam generator boiler (300) to repeat the cycle.If necessary, the steam generating boiler (300) could have low pressure steam production directly to partially supply the pre-cooling (101) and absorption (201) stages.

[0070] The CO2 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 removed and it is compressed to supercritical pressures in the purified CO2 stream (9), between 110 and 150 bar, for subsequent transport and storage. A CO2 stream (8) removed from the natural gas stream (1) in a pretreatment stage, not shown in the figure, which may be present in the natural gas, is also fed into the compression unit.

[0071] Currently, the size of the post-combustion capture unit required for a liquefaction train of ~4.6 mtpa corresponds to the sizes of currently operating commercial capture plants for electricity generation, which are approaching the limits of achievable construction, particularly for the cross-section of the absorber. Therefore, the present invention eliminates a critical bottleneck for implementing CO2 capture in liquefied natural gas (LNG) plants by reducing the volumetric flow of gases that need to be treated, making such capture competitive for comparatively lower CO2 prices, and also achieving higher production in each liquefaction train that integrates capture.

[0072] Alternatively to the proposed scheme with CO2 capture, a plant could be designed with the same coupling system of refrigerant compressors (103, 105) and backpressure steam turbines (501, 502), feeding the precooling stage (101) with the steam from the turbine outlets, but lacking the CO2 capture unit (200). Such a plant would achieve specific CO2 emissions comparable to those produced by plants using conventional technologies and industrial gas turbines without CO2 capture.

[0073] In the first embodiment shown in Figure 1, the means for the liquefaction stage (102) of the natural gas stream (1) are located downstream of the precooling stage (101), and the means for the subcooling 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 subcooling stage (104) comprise at least one refrigerant compressor (103, 105) and a backpressure steam turbine (501, 502) mechanically coupled to the compressor (103, 105).

[0074] The liquefaction (102) and subcooling (104) stages can be thermally coupled to the precooling stage (101), understanding as thermally coupled that streams of matter belonging to each stage exchange heat respectively with each other.

[0075] In the embodiment example of Figure 1, when the refrigerant used in the liquefaction stage (102) is pure ethylene or ethane, which is condensed in the precooling 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 / ton LNG, excluding auxiliary plant consumption, while the thermal demand, low-pressure steam consumption, of the precooling stage (101) and the CO2 absorption stage (201) is approximately 570 kWh / ton LNG, when a 30% by weight MEA solution is used for CO2 capture, achieving a thermal efficiency greater than 94%, for a heat rejection temperature of 20°C.Alternatively, according to the first embodiment example, both the liquefaction stage (102) and the subcooling stage (104) can each employ a mixed refrigerant, a mixture of hydrocarbons, operating in series.

[0076] The embodiment corresponding to Figure 1 may have a mixed refrigerant for the liquefaction stage (102) and a different 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).

[0077] 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, duplicated liquefaction and subcooling stage (107, 108), both of which are located downstream of the precooling stage (101) and operate in parallel with each other. 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). Furthermore, the refrigeration compressors (103, 105) corresponding to each integrated liquefaction and subcooling stage are identical.

[0078] Therefore, the liquefaction and subcooling of the natural gas stream (1) can be integrated into a single duplicate liquefaction and subcooling stage (107, 108) operating in parallel so as to share the same means of the precooling unit (101), with their respective refrigeration compressors (103, 105) driven in turn by the backpressure steam turbines (501, 502).

[0079] The expansion and separation stage (106) of the liquefied natural gas (LNG) (2) and vaporized natural gas (3) products of the plant may be common. The liquefaction and subcooling stages (107, 108) are thermally coupled; that is, 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) using ammonia as the refrigerant. This 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 shown in Figure 2, such as the mixed refrigerant used in the C3MR liquefaction technology.

[0080] The second embodiment presents the possibility of integrating two natural gas liquefaction trains that share the same precooling stage (101). In the embodiment shown in Figure 2, where a mixed refrigerant as previously described is used, which is partially condensed with ammonia in the precooling unit (101) and subsequently used for the liquefaction and subcooling of the natural gas stream (1) in two parallel stages, the specific electrical consumption for the liquefaction unit (100) is approximately 150 kWh / ton of LNG, while the thermal demand reached in the precooling stage (101) and the CO2 absorption stage (201) is approximately 470 kWh / ton of LNG, when a 30 wt% MEA solution is used as the absorbent in the CO2 absorption stage (201), and a temperature of 20°C is achieved after heat rejection.

[0081] This arrangement allows, similarly to the embodiment example in Figure 1, the simultaneous satisfaction of the thermal and electrical demands of the liquefaction stage (100) and the CO2 capture stage (200), by means of the steam cycle with high-pressure steam generation (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 LNG (2) by its calorific value with respect to that of the feed gas, similar to that of liquefaction plants with industrial turbines without CO2 capture, which turns out to be approximately 95% when considering a heat rejection temperature of 20°C for the process fluid.

[0082] According to the second embodiment, the thermal demand is reduced, thus increasing overall thermal efficiency and plant availability by operating in parallel compared to the first embodiment. However, this comes at the cost of increasing the number of pieces of equipment: a cryogenic heat exchanger in the integrated liquefaction and subcooling stage (107, 108). Furthermore, it requires the presence of heavier and more flammable hydrocarbons such as propane and butane in the mixed refrigerant, resulting in higher investment costs and more complex operation, respectively. Finally, the use of two parallel trains for liquefaction and subcooling could allow for higher production rates than the series configurations corresponding to the embodiment in Figure 1, maximizing the benefits of economies of scale.

[0083] In one embodiment, shown in Figure 3, the natural gas feed stream (1) to the means for the liquefaction stage (100) is pre-treated in the absorption stage (201), to remove the CO2 contained in the natural gas fed to the plant.

[0084] For this purpose, the means for the absorption stage (201) for extracting CO2 from the exhaust gases (5) are also configured for extracting CO2 from the stream adapted for natural gas circulation (1) before it passes through the means for the pre-cooling stage (101). Therefore, in the absorption stage (201) for extracting CO2 from the exhaust gases (5), a CO2 extraction stage is also performed on the stream adapted for natural gas circulation (1) before it passes through the pre-cooling stage (101).

[0085] The extraction of CO2 contained in the exhaust gases (5) and in the stream adapted for the circulation of natural gas (1) prior to its feeding to the pre-cooling stage (100) is carried out in two different absorption columns.

[0086] The solvent used in these CO2 capture media of the absorption stage (201) is preferably activated methyldiethanolamine (MDEA), or any other amine.

[0087] By employing a single solvent in the means for the absorption stage (201) for the extraction of CO2 from the exhaust gases (5) and the CO2 contained in the adapted stream of natural gas (1) prior to its feeding to the liquefaction unit (100), the means for the absorption stage (201) comprise a single solvent regeneration column.

[0088] In one embodiment, in the absorption stage (201), the means for extracting CO2 from the exhaust gases (5) use the same solvent as the CO2 capture means of the stream adapted for natural gas circulation (1) prior to its feed to the means for the liquefaction stage (100). The use of the same solvent facilitates the integration of the CO2 removal means of both streams, so that they share the same solvent regeneration column or "stripper," reducing investment costs.

Claims

CLAIMS 1. A liquefied natural gas (LNG) production system with CO2 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) to low temperatures of -140 °C to -170 °C in cooling and / or expansion stages to produce liquefied natural gas (LNG) at atmospheric pressure, wherein the system comprises means for a liquefaction stage (100) comprising in turn: - means for a pre-cooling stage (101) of the natural gas stream (1) using ammonia as a refrigerant, - means for a liquefaction and subcooling stage of the natural gas stream (1) located downstream of the means for the precooling stage (101), - means for an expansion and separation stage (106) 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 (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 CO2 (200) contained in the exhaust gases (5) of the steam generating boiler (300) comprising in turn: or means for an absorption stage (201) for extracting the CO2 from said exhaust gases (5), and or means for a compression stage (202) located downstream of the means for the absorption stage (201), wherein the means for the liquefaction and subcooling stage comprise at least one refrigerant compressor (103, 105) and a backpressure steam turbine (501, 502) mechanically coupled to the compressor (103, 105) and the means for the precooling stage (101) and the means for the absorption stage (201) comprise a low-pressure steam feed (10, 11) from the backpressure steam turbines (501, 502), the steam generating boiler (300) being configured for the generation of high-pressure steam (6) that feeds the backpressure steam turbines (501, 502).

2. A liquefied natural gas (LNG) production system with CO2 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), wherein 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), wherein 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 turbine counterpressure steam (501, 502) mechanically coupled to the compressor (103, 105). 3.- Liquefied natural gas (LNG) production system with CO2 capture, according to claim 1, characterized in that the means for a liquefaction and subcooling stage of the natural gas stream (1) are integrated into a single liquefaction and subcooling stage (107, 108), duplicated and operating in parallel with each other, both located downstream of the means for the precooling stage (101), wherein each stage (107, 108) duplicated 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 CO2 capture, according to any one of the preceding claims, characterized in that the power of the means of the pre-cooling stage (101) is provided by a low-pressure water vapor stream (10) between 1 bar and 6 bar. 5.- Liquefied natural gas (LNG) production system with CO2 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. 6.- Liquefied natural gas (LNG) production system with CO2 capture, according to any one of the preceding claims, characterized in that the means for a compression stage (202) is also fed by a CO2 stream (8) removed from the natural gas stream (1) prior to the liquefaction unit (100). 7.- Liquefied natural gas (LNG) production system with CO2 capture, according to any one of the preceding claims, characterized in that the means for the absorption stage (201) for extracting CO2 from the exhaust gases (5) are also configured for extracting CO2 from the stream adapted for the circulation of natural gas (1) before its passage through the means for the pre-cooling stage (101). 8.- Liquefied natural gas (LNG) production system with CO2 capture, according to any one of the preceding claims, characterized in that it comprises an auxiliary power unit (400) comprising a backpressure steam turbine configured for the mechanical drive of the means for the CO2 compression stage (202) and for the low pressure steam feed from the turbine to the means for the pre-cooling stage (101) of the stream adapted for natural gas circulation (1).

9. A method for producing liquefied natural gas (LNG) with CO2 capture, according to the production system of claim 1, 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) to low temperatures of -140°C to -170°C in cooling and / or expansion stages to produce liquefied natural gas (LNG) at atmospheric pressure, wherein the method comprises a liquefaction stage (100) comprising the following stages: - a pre-cooling stage (101) of the natural gas stream (1), - a liquefaction and subcooling stage of the natural gas stream (1) located downstream of the precooling stage (101), - an expansion and separation stage (106) of the liquefied natural gas (LNG) product located downstream of the liquefaction and subcooling stage resulting in the liquefied natural gas (LNG) product (2) and vaporized natural gas (3), characterized in that the method comprises: - a steam generation stage (300) by means of a boiler for combustion with air (4) of the vaporized natural gas (3) generated in the expansion and separation stage (106), - a CO2 capture stage (200) contained in the exhaust gases (5) from the steam generation stage (300), comprising in turn: or an absorption stage (201) for extracting CO2 from said exhaust gases (5), and or 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 backpressure steam turbine (501, 502) mechanically coupled to the compressor (103, 105) and the precooling stage (101) and the absorption stage (201) comprise a low-pressure steam feed (10, 11) from the backpressure steam turbines (501, 502), the steam generation stage (300) generating high-pressure steam (6) that feeds the backpressure steam turbines (501, 502). 10.- Method of producing liquefied natural gas LNG with CO2 capture, according to claim 9, characterized in that the absorption stage (201) for the extraction of CO2 from the exhaust gases (5) employs a solvent and low pressure steam (11) from the back-pressure steam turbines (501, 502) for the regeneration of said solvent. 11.- Method of producing liquefied natural gas LNG with CO2 capture, according to claim 10, characterized in that the solvent is monoethanolamine (MEA), methyldiethanolamine (MDEA) or an aqueous solution of ammonia. 12.- Method of producing liquefied natural gas LNG with CO2 capture, according to any one of claims 9 to 11, characterized in that the pre-cooling stage (101) uses ammonia as a refrigerant to reduce the temperature of the natural gas stream (1) to approximately -30°C. 13.- Method of producing liquefied natural gas LNG with CO2 capture, according to any one of claims 9 to 12, characterized in that the compression stage (202) is configured for the production of a purified CO2 stream (9) at a pressure between 110 and 150 bar. 14.- Method of producing liquefied natural gas LNG with CO2 capture, according to any one of claims 9 to 13, characterized in that in the absorption stage (201) for the extraction of CO2 from the exhaust gases (5) a CO2 extraction stage is also carried out from the stream adapted for the circulation of natural gas (1) before its passage through the pre-cooling stage (101). 15.- Method of producing liquefied natural gas LNG with CO2 capture, according to any one of claims 9 to 14, characterized in that the mechanical drive of the CO2 compression stage (202) is carried out by means of a back-pressure steam turbine included in the auxiliary power unit (400), which feeds the low-pressure steam exiting the turbine to the pre-cooling stage (101) of the stream adapted for the circulation of natural gas (1).

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