KR102232149B1 - Membrane-based Process for Sequestering Carbon Dioxide from Gas Mixture Containing Low-concentration Carbon Dioxide - Google Patents

Abstract

In the present disclosure, in separating (or trapping) carbon dioxide contained in a gas mixture containing a low concentration of carbon dioxide, such as exhaust gas generated from a natural gas combined cycle power plant (NGCC), the gas mixture is liquefied as energy required to cool the gas mixture to a low temperature. A separation membrane-based process capable of improving the efficiency of the separation membrane process by utilizing the cooling energy released during the regasification process of natural gas (LNG) and further including a method of recirculating a part of the exhaust gas is described.

Description

Membrane-based Process for Sequestering Carbon Dioxide from Gas Mixture Containing Low-concentration Carbon Dioxide}

The present disclosure relates to a membrane-based process for separating _{carbon dioxide (CO 2} ) from a gas mixture containing a low concentration of carbon dioxide. More specifically, the present disclosure provides for separating (or trapping) carbon dioxide contained in a gas mixture containing a low concentration of carbon dioxide, such as an exhaust gas generated from a natural gas combined cycle power plant (NGCC), to cool the gas mixture to a low temperature. Regarding the separation membrane-based process that can improve the efficiency of the separation membrane process by using the cooling energy released during the regasification process of liquefied natural gas (LNG) as necessary energy, and further including a method of recirculating a part of the exhaust gas. will be.

In response to the occurrence of climate change due to global warming, efforts to create new growth engines and preoccupy the global market are being made based on securing measures to reduce greenhouse gases worldwide.

In general, as technical measures to cope with climate change, (i) energy efficiency improvement, (ii) substitution with low-carbon fuels such as nuclear and renewable energy, and (iii) carbon dioxide capture and storage technologies have been used.

Carbon dioxide absorbs some of the infrared radiation emitted from the surface and causes a greenhouse effect, which is a major factor in global warming. As industrialization progresses, _{the annual emission of CO 2} has increased significantly, and carbon dioxide in the atmosphere is continuously accumulating. Carbon dioxide accumulated in the atmosphere in this way affects the energy balance of the atmospheric system and raises the global average temperature. Energy supply from fossil fuels accounts for more than 86% of energy demand worldwide. In particular, in the United States, more than 36% of carbon dioxide emissions come from thermal power generation. As such, it is important to develop and secure carbon dioxide reduction technologies, as carbon dioxide emissions are expected to increase to 37 to 40 Gt by 2030 if no active regulations on carbon dioxide emissions are enforced.

The carbon dioxide separation process is largely divided into a pre-treatment method, a post-treatment method, and a pure oxygen combustion method. Among these, the post-treatment process can be directly applied to an existing power plant, and the power generation and removal processes operate independently, so in case of emergency Even if the carbon dioxide removal process is stopped, it has the advantage that electricity can be continuously produced.

In this post-treatment process, as a representative low-temperature separation membrane process is in the spotlight, in order to supply cooling heat necessary for efficient separation membrane operation, the present inventors have proposed a method of introducing an external cooling cycle as shown in FIG. There is a bar (Korean Patent No. 1906917).

Referring to FIG. 1, exhaust gas discharged by combustion of fuel and air from a gas turbine 101 passes through a heat recovery steam generator (HRSG) 102 to additionally generate electricity. The exhaust gas is compressed to a low pressure (for example, about 2.3 bara) through the compressor 103, and the compressed air removes all moisture present in the exhaust gas in the dryer 104.

The dried exhaust gas is cooled by passing through the heat exchanger 105, and selective separation (mainly carbon dioxide) is performed through the separation membrane 106 through a pressure ratio with the vacuum pump 109. At this time, some of the gas that has not passed through the separation membrane is injected into the permeable portion of the separation membrane, and is configured to further improve separation efficiency. Other gases pass through the expander 108, recover some of the electricity therefrom, and contribute to cooling in the heat exchanger 105 before being discharged into the flue.

The gases that have passed through the separation membrane are pressurized by the compressor 110 and then passed through the heat exchanger 111 to be cooled in advance. The flow passing through the heat exchanger 105 is cooled and gas/liquid phase separation occurs. This flow passes through the distillation column 112, separates liquid carbon dioxide having high purity (for example, about 99.9% purity), and can be subsequently stored or transported in a supercritical state by the pump 113.

At this time, the gas that has not been liquefied in the distillation column 112 passes through the heat exchanger 111, cools the flow 142, recovers some electricity through the expander 114, and passes through the heat exchanger 105. Contributes to cooling. Then, the expander 115 and the valve 116 are sequentially passed, and the operating conditions are corrected to have a temperature and pressure similar to the flow 136 injected into the separator.

In the illustrated example, the compressor 117, the pump 118, and the valve 119 are devices required to operate the external cooling cycle, and the refrigerant may be a propane gas or a mixed gas such as ethane, propane, butane, or the like.

Since the above-described process is configured to supply cooling heat through a separate cooling cycle using a refrigerant, the refrigerant can be freely changed according to the optimum operating temperature of the separation membrane. The above process is a technology that can be effectively applied to the separation and capture of carbon dioxide in a gas mixture containing a relatively high concentration (about 10 to 15 mol%) of carbon dioxide, such as exhaust gas discharged from a coal-fired power plant, but a lower carbon dioxide concentration. In the case of flue gas generated from a natural gas combined cycle power plant (NGCC) having, in order to achieve a concentration suitable for transport and storage of carbon dioxide (eg, about 99% or more) and a recovery rate (eg, about 90%) at the same time Requires a large amount of electrical energy.

Meanwhile, in order to use liquefied natural gas (LNG), a process of converting into gaseous natural gas (room temperature) by providing external heat is performed, which is referred to as regasification. In general, such vaporization facilities, such as ORV (Open Rack Vaporizer), IFV (Intermediate Fluid Vaporizer), AAV (Ambient Air Vaporizer), STV (Shell and Tube Vaporizer), SCV (Submerged Combustion Vaporizer), etc. The air in the liquefied natural gas recovers the cooling heat generated during the regasification process and discharges it into the gas phase.

As such, most of the cooling energy emitted from the regasification of the liquefied natural gas is discarded as a heat sink with low or no usefulness. In particular, SCV evaporates natural gas by replenishing required heat energy by burning fossil fuels (typically natural gas) with heat required for the gasification process. In this case, since additional carbon dioxide is emitted, greenhouse gas management becomes more difficult.

In this regard, to utilize the regasification energy of liquefied natural gas in the air separation industry performed as a refrigeration process in the low temperature region, or to liquefy the cycle fluid in the steam cycle or organic solvent cycle (typically Rankine cycle) of a power plant. Attempts have been made. However, there has been no report on a method in which the separation membrane process and the regasification of liquefied natural gas are combined using cooling heat directly.

Therefore, it is possible to efficiently separate or capture carbon dioxide for a gas mixture containing low-concentration carbon dioxide, such as exhaust gas discharged from a natural gas combined cycle power plant, compared to a conventional separation process based on a separation membrane. There is a need for effective utilization of the regasification heat of insignificant liquefied natural gas.

In one embodiment of the present disclosure, to provide a solution for overcoming inefficiencies caused when a conventional separation technique based on a separation membrane is applied to a process of separating (isolating) or trapping carbon dioxide in a low-concentration carbon dioxide-containing gas mixture. do.

In addition, according to another embodiment of the present disclosure, it is intended to provide a method for efficiently separating or trapping carbon dioxide in a gas mixture so that the regasification cooling energy of liquefied natural gas, which has a low utilization in the prior art, has higher usefulness.

According to the first aspect of this disclosure,

As a membrane-based process for separating and capturing carbon dioxide in a gas mixture,

(a) providing a carbon dioxide-containing gas mixture produced by combustion of a fuel and an oxygen-containing gas in the gas turbine and discharged from the gas turbine;

(b) separating a portion of the carbon dioxide-containing gas mixture and recirculating it to the gas turbine, while compressing the remaining unrecirculated;

(c) cooling the compressed gas mixture by transferring it to a heat exchanger;

(d) transferring the cooled gas mixture to a separation membrane module having selective permeability to carbon dioxide to form a CO ₂ -lean first retention stream and a CO ₂ -rich first permeate stream;

(e) compressing the first permeate flow, transferring it to the heat exchanger in a pressurized state, and cooling it by heat exchange;

(f) transferring the cooled first permeate stream to a distillation column and separating the cooled first permeate stream into a high-purity CO ₂ liquid stream as a bottom stream and a low-purity CO ₂ -containing gaseous mixture as a top stream by gas/liquid separation;

(g) recovering the high purity CO ₂ liquid stream;

Including,

Here, the carbon dioxide-containing gas mixture discharged from the gas turbine in step (a) has a carbon dioxide concentration of less than 5 mol% when some of the carbon dioxide-containing gas mixture is not recycled in step (b), In the case of recycling a portion of the carbon dioxide-containing gas mixture, the carbon dioxide concentration is increased by 0.1 to 20 mol% compared to the case of not being recycled, and

In order to provide cooling required for the process through heat exchange in the heat exchanger, a separation membrane-based process configured to supply cooling heat according to regasification of liquefied natural gas (LNG) is provided.

According to the second aspect of this disclosure,

As a membrane-based process for separating and capturing carbon dioxide in a gas mixture,

(a1) providing a carbon dioxide-containing gas mixture produced by combustion of a fuel and an oxygen-containing gas in a gas turbine and discharged from the gas turbine;

(b1) separating a portion of the carbon dioxide-containing gas mixture and recirculating it to the gas turbine, while compressing the remaining unrecirculated;

(c1) cooling the compressed gas mixture by transferring it to a heat exchanger;

(d1) transferring the cooled gas mixture to a first separation membrane module having selective permeability to carbon dioxide to form a CO ₂ -lean first retention stream and a CO ₂ -rich first permeate stream;

(e1) compressing the first permeate stream and transferring it to a second separation membrane module in a pressurized state to form a CO ₂ -lean second retention stream and a CO ₂ -rich second permeate stream;

(f1) compressing the second permeate flow, transferring it to the heat exchanger in a pressurized state, and cooling it by heat exchange;

(g1) transferring the cooled second permeate stream to a distillation column and separating the cooled second permeate stream into a high-purity CO ₂ liquid stream as a bottom stream and a low-purity CO ₂ -containing gaseous mixture as a top stream by gas/liquid separation; And

(h1) recovering the high purity CO ₂ liquid stream;

Including,

Here, the carbon dioxide-containing gas mixture discharged from the gas turbine in step (a1) has a carbon dioxide concentration of less than 5 mol% when some of the carbon dioxide-containing gas mixture is not recycled in step (b1), In the case of recycling a portion of the carbon dioxide-containing gas mixture, the carbon dioxide concentration is increased by 0.1 to 20 mol% compared to the case of not being recycled, and

In order to provide cooling required for the process through heat exchange in the heat exchanger, a separation membrane-based process configured to supply cooling heat according to regasification of liquefied natural gas (LNG) is provided.

According to the third aspect of this disclosure,

As a membrane-based process for separating and capturing carbon dioxide in a gas mixture,

(a2) providing a carbon dioxide-containing gas mixture produced by combustion of a fuel and an oxygen-containing gas in the gas turbine and discharged from the gas turbine;

(b2) separating a part of the carbon dioxide-containing gas mixture and recirculating it to the gas turbine, while compressing the remaining unrecirculated;

(c2) cooling the compressed gas mixture by transferring it to a heat exchanger;

(d2) transferring the cooled gas mixture to a first separation membrane module having selective permeability to carbon dioxide to form a CO ₂ -lean first retention stream and a CO ₂ -rich first permeate stream;

(e2) at least a portion of the first retention flow is transferred to a subsequent separation membrane module to have a retention flow of a subsequent separation membrane module having a lower carbon dioxide concentration than the first retention flow, and a carbon dioxide concentration higher than that of the rear separation membrane module. Forming a permeate flow of a rear-stage separation membrane module;

(f2) recirculating the permeate flow of the downstream membrane module to the gas turbine together with some of the carbon dioxide-containing gas mixture recycled in step (b2);

(g2) compressing the first permeate flow, transferring it to the heat exchanger in a pressurized state, and cooling it by heat exchange;

(h2) transferring the cooled first permeate stream to a distillation column and separating the cooled first permeate stream into a high-purity CO ₂ liquid stream as a bottom stream and a low-purity CO ₂ -containing gaseous mixture as a top stream by gas/liquid separation; And

(i2) recovering the high purity CO ₂ liquid stream;

Including,

Here, the carbon dioxide-containing gas mixture discharged from the gas turbine in step (a2) does not recycle some of the carbon dioxide-containing gas mixture in step (b2) and the permeate flow of the subsequent separation membrane module in step (f2). In this case, the carbon dioxide concentration is less than 5 mol%, whereas in the case of recycling a part of the carbon dioxide-containing gas mixture and the permeate flow of the downstream separation membrane module, the carbon dioxide concentration is increased by 0.1 to 25 mol% compared to the case of not being recycled, And

In order to provide cooling required for the process through heat exchange in the heat exchanger, a separation membrane-based process configured to supply cooling heat according to regasification of liquefied natural gas (LNG) is provided.

According to the fourth aspect of this disclosure,

As a membrane-based process for separating and capturing carbon dioxide in a gas mixture,

(a3) providing a carbon dioxide-containing gas mixture produced by combustion of a fuel and an oxygen-containing gas in the gas turbine and discharged from the gas turbine;

(b3) separating part of the carbon dioxide-containing gas mixture and recirculating it to the gas turbine, while compressing the remaining unrecirculated;

(c3) cooling the compressed gas mixture by transferring it to a heat exchanger;

(d3) transferring the cooled gas mixture to a first separation membrane module having selective permeability to carbon dioxide to form a CO ₂ -lean first retention stream and a CO ₂ -rich first permeate stream;

(e3) Transferring at least a portion of the first retention flow to a subsequent separation membrane module to have a retention flow of a rear separation membrane module having a lower carbon dioxide concentration than the first retention flow, and a carbon dioxide concentration higher than the retention flow of the rear separation membrane module Forming a permeate flow of a rear-stage separation membrane module;

(f3) recirculating the permeate flow of the downstream membrane module to the gas turbine together with a portion of the carbon dioxide-containing gas mixture recycled in step (b3);

(g3) compressing the first permeate stream and transferring it to a second separation membrane module in a pressurized state to form a CO ₂ -lean second retention stream and a CO ₂ -rich second permeate stream;

(h3) compressing the second permeate flow, transferring it to the heat exchanger in a pressurized state, and cooling it by heat exchange;

(i3) transferring the cooled second permeate stream to a distillation column and separating the cooled second permeate stream into a high-purity CO ₂ liquid stream as a bottom stream and a low-purity CO ₂ -containing gaseous mixture as a top stream by gas/liquid separation; And

(j3) recovering the high purity CO ₂ liquid stream;

Including,

Here, the carbon dioxide-containing gas mixture discharged from the gas turbine in step (a3) does not recycle some of the carbon dioxide-containing gas mixture in step (b3) and the permeate flow of the downstream membrane module in step (f3). In this case, the carbon dioxide concentration is less than 5 mol%, whereas in the case of recycling a part of the carbon dioxide-containing gas mixture and the permeate flow of the downstream separation membrane module, the carbon dioxide concentration is increased by 0.1 to 25 mol% compared to the case of not being recycled, And

In order to provide cooling required for the process through heat exchange in the heat exchanger, a separation membrane-based process configured to supply cooling heat according to regasification of liquefied natural gas (LNG) is provided.

The process according to a specific embodiment of the present disclosure is a low temperature for the purpose of enhancing separation efficiency when capturing carbon dioxide based on a separation membrane from an exhaust gas (gas mixture) generated from a combustion process (specifically, a gas turbine combustion process), especially a gas mixture having a low carbon dioxide concentration. In order to provide the cooling required to operate the separation membrane process, it is easy to control the temperature of the gas mixture and design and control the heat exchanger by utilizing the low-cost cooling heat generated in the regasification process of the liquefied natural gas, which is not used in the past. Can be implemented. In particular, natural gas regasified to provide cooling heat provides an additional advantage that can be supplied as fuel for natural gas combined power plants.

At the same time, before introducing the exhaust gas discharged from the gas turbine into the heat exchanger, a part of it is recycled to the gas turbine of the combustion process, and further, the first retained flow generated in the first separation membrane module is treated with a subsequent separation membrane module, from which By configuring the generated permeate flow to recirculate to the gas turbine (i.e., selective recirculation), the low-concentration carbon dioxide-containing gas mixture has a higher carbon dioxide concentration when flowing into the membrane module, thereby reducing the inefficiency of the existing membrane-based technology. It provides an advantage that can be effectively overcome.

In addition, it is possible to provide an effect of additionally reducing electrical energy required for the operation of the entire process by configuring to increase the concentration of carbon dioxide before being injected into the distillation column through a multi-stage separation membrane method.

1 is a process diagram showing a separation membrane-based process (Comparative Example 1) for separating carbon dioxide in a conventional exhaust gas (gas mixture);
2 is a process diagram showing an example of a single separation membrane module-based process for separating carbon dioxide in a gas mixture in which cooling heat by regasification of liquefied natural gas and recirculation of exhaust gas are combined;
3 is a process diagram showing another example of a multi-stage separation membrane module-based process for separating carbon dioxide in a gas mixture in which cooling heat by regasification of liquefied natural gas and recirculation of exhaust gas are combined;
4 shows an example of a single separation membrane module-based process for separating carbon dioxide in a gas mixture in which cooling heat provided by regasification of liquefied natural gas, exhaust gas recirculation, and selective exhaust gas recirculation using a downstream membrane module are combined. Is a process chart;
5 is a diagram showing an example of a multi-stage separation membrane module-based process for separating carbon dioxide in a gas mixture in which cooling heat by regasification of liquefied natural gas is provided, exhaust gas recirculation, and selective exhaust gas recirculation using a subsequent separation membrane module are combined. Is a process chart;
6 is a process diagram showing an example (Comparative Example 2) of a single separation membrane module-based process for separating carbon dioxide in a gas mixture in which cooling heat by regasification of liquefied natural gas is introduced; And
7 is a process diagram showing an example (Comparative Example 3) of a multi-stage membrane module-based process for separating carbon dioxide in a gas mixture, in which cooling heat by regasification of liquefied natural gas is introduced.

The present invention can all be achieved by the following description. The following description should be understood as describing preferred embodiments of the present invention, and the present invention is not necessarily limited thereto. In addition, the accompanying drawings are provided to aid understanding, and the present invention is not limited thereto, and details of individual configurations may be appropriately understood by the specific purpose of the related description to be described later.

의 단위를 갖는다.In the present specification, "transmittance" is expressed as a gas permeation unit (GPU), and the GPU value is

Has a unit of

In the present specification, when a certain component is "included", it means that other components and/or steps may be further included unless otherwise stated.

In one embodiment, the carbon dioxide (CO ₂ )-containing gas mixture is a low-concentration carbon dioxide-containing gas mixture, more typically a natural gas mixture, typically emitted from a fossil fuel combustion process (e.g., a combustion process such as a power plant). Combustion of the flue gas from gas combined cycle power plants, the flue gas discharged after combustion of natural gas or diesel used as fuel for ship flue gas, and natural gas combustion used in the Submerged Combustion Vaporizer (SCV) used for LNG regasification It may be after exhaust gas.

The carbon dioxide-containing gas mixture applicable to the process according to one embodiment typically contains carbon dioxide and moisture generated by the combustion reaction of hydrocarbons by default, and nitrogen in the case of providing air as an oxygen-containing gas or oxidizing agent, and It may further contain unused oxygen. In addition, the gas mixture (specifically, the exhaust gas) applicable to the process according to the embodiment is a gas component resulting from impurities in the raw material of the combustion process, such as hydrogen sulfide, sulfur oxide (for example, SO ₂ ), nitrogen oxide ( For example, _{impurities such as NO 2} ), hydrochloric acid, and mercury may also be contained, but when a clean fuel such as natural gas is used, such impurities may be present in trace amounts or may not be substantially contained.

Table 1 below shows the composition of the combustion exhaust gas normally discharged from a natural gas combined cycle power plant.

ingredient Content (mol%) CO ₂ 4 N ₂ 75.9 O ₂ 12.3 H ₂ O 7.7 Other ingredients balance

The composition of the combustion gas described in the above table is illustrative and it should be understood that it may be variously changed according to the raw material composition, properties, process principle and characteristics of the natural gas combustion process.

FIG. 2 is a process diagram illustrating an example of a single separation membrane module-based process for separating carbon dioxide in a gas mixture in which cooling heat by regasification of liquefied natural gas and recirculation of exhaust gas are combined.

Referring to the drawing, fuel 231 (for example, natural gas) is introduced into the gas turbine 201 and an oxygen-containing gas (specifically air; may be introduced together with a recirculated exhaust gas flow as described below). A carbon dioxide-containing gas is generated by a combustion reaction with and is discharged from the gas turbine 201. Illustratively, the fuel introduced into the gas turbine 201 may typically be in a compressed state, for example in the range of about 10 to 50 bara, specifically about 15 to 40 bara, and more specifically about 25 to 35 bara.

Since the exhaust gas 233 discharged from the gas turbine is still in a high temperature state (for example, about 200 to 1100°C, specifically about 600 to 700°C), it selectively passes through the heat recovery boiler 202 (HRSG). Can be configured to generate additional electricity. The gas mixture passed through the heat recovery boiler 202 is, for example, a temperature of about 30 to 90°C (specifically about 35 to 70°C, more specifically about 45 to 60°C), and, for example, about 1 to 1.5 bara (specifically, about 1.01 to 1.2 bara, more specifically, normal pressure (about 1.013 bara)).

In the illustrated embodiment, the gas mixture 234 that has passed through the heat recovery boiler 202 is divided by a splitter 218, some of which is transferred to the gas turbine 201 while forming a recirculation stream 235. At this time, as an oxygen source required for combustion in the gas turbine 201, an oxygen-containing gas, specifically, combustion air 232 is supplied together and mixed with the gas mixture recycled in the mixer or mixer 219. A stream 255 is then formed and introduced into the gas turbine 201.

According to an exemplary embodiment, the volume ratio of the recycled gas mixture stream 235/non-recirculated gas mixture stream 236 is, for example, about 0.2 to 1, specifically about 0.4 to 0.8, more specifically about 0.6. It can be adjusted within the range of 0.7. In this regard, if the amount of exhaust gas to be recycled is too large or too small, it may be advantageous to control within the above-described range as it may cause an incomplete combustion phenomenon due to a change in the oxygen concentration of the combustion air, but it is not necessarily limited thereto. It can be changed according to other process conditions and characteristics of exhaust gas.

Further, the oxygen-containing gas introduced along stream 232 may contain a sufficient amount of oxygen to burn fuel 231. As an example, the ratio of oxygen to the fuel (on a molar basis) may be, for example, about 100 to 300%, specifically about 150 to 250%. 2 shows only the flow 232 combined with the exhaust gas recycled as an oxygen source in the combustion process for good combustion, but the oxygen-containing gas is directly supplied to the gas turbine 201 or gas through a plurality of inlets. It can also be introduced into the turbine 201.

When a part of the exhaust gas is recycled to the gas turbine 201 as described above, the exhaust gas discharged from the gas turbine has the following composition characteristics.

In the embodiment shown in FIG. 1, when the combustion reaction is performed under the same process conditions except that the recirculation of the exhaust gas is not involved, the exhaust gas discharged from the gas turbine 201 is, for example, less than about 5 mol%, specifically As a result, the composition has a low carbon dioxide concentration of about 1 to less than 4.5 mol%, more specifically about 2 to 4.2 mol%, which corresponds to the typical characteristics of the exhaust gas discharged from the natural gas combined cycle power plant. As described above, when a low-concentration carbon dioxide-containing gas mixture is processed in the separation membrane module, the efficiency of the entire process decreases due to a decrease in separation capacity and an increase in processing capacity by the separation membrane, and therefore, excessive input of operating energy is inevitable. However, as in the illustrated embodiment, as part of the exhaust gas is recycled to the gas turbine 201, the concentration of carbon dioxide in the exhaust gas (gas mixture) increases, and the gas flow rate processed by the separation membrane may be additionally decreased.

In this regard, the exhaust gas discharged from the gas turbine 201 is, for example, about 0.1 to 20 mol%, specifically about 5 to 7 mol%, and more specifically, compared to the case where recirculation is involved and not recirculated. The carbon dioxide concentration may be increased by about 1 to 3 mol%. As an example, the concentration of carbon dioxide in the flow 233 may range from, for example, about 5.5 to 8 mol%, specifically about 5.8 to 7.5 mol%, and more specifically about 6 to 7 mol%.

Accordingly, when the exhaust gas is treated by the subsequent separation membrane module, the gas mixture having an increased carbon dioxide concentration is separated, which has an advantageous effect on improving the selective separation efficiency for carbon dioxide.

Meanwhile, the exhaust gas 236 that has not been recycled after being separated by the splitter 218 is pressurized by the compressor 203, and is specifically pressurized to a low pressure. Exemplarily, the pressure of the pressurized exhaust gas 237 may range from, for example, about 1.5 to 4 bara, specifically about 1.7 to 3 bara, and more specifically about 1.9 to 2.5 bara.

Thereafter, since the pressurized gas mixture 237 may contain moisture generated by combustion, it may be selectively transferred to the dryer 204 to remove moisture to remove moisture in the exhaust gas. After the drying step, the moisture content in the exhaust gas 238 may be reduced to, for example, about 50 ppmv or less, specifically about 30 ppmv or less, and more specifically about 10 ppmv or less. In particular, the exhaust gas 238 may not substantially contain moisture.

The pressurized gas mixture (optionally subjected to a drying (moisture removal) step; 238) is transferred to a heat exchanger 205. In this regard, the gas mixture in the heat exchanger 205 is a temperature range in which low temperature operation is possible in the separator module disposed on the downstream side through heat exchange with other inlet flows in the system, for example, about 0° C. or less, specifically It may be cooled to about -50 to -10 °C, more specifically about -40 to -30 °C. In this case, the pressure of the flow during the cooling process in the heat exchanger 205 may not substantially change (that is, the pressures of each of the heat exchanger inlet flow and discharge flow may be the same). In addition, in the case of the heat exchanger 205, the minimum temperature difference between fluids to be heat-exchanged may be adjusted to, for example, about 15°C or less, specifically about 10°C or less, and more specifically about 7°C or less.

The heat-exchanged gas mixture is transferred to the separation membrane module 206, and selective separation (mainly carbon dioxide) is performed through a pressure ratio with the vacuum pump 209. According to an exemplary embodiment, the gas mixture 239 cooled by the heat exchanger 205 is not liquefied in the distillation column 212 and is discharged from the upper end thereof, as described later, so that the heat exchanger 211 and the expander 214 And the heat exchanger 205 and the carbon dioxide-containing mixed gas 251 transferred through the expander 215, and this combined flow may be transferred to the first separation membrane module 206. In this case, the carbon dioxide concentration in the combined flow may increase, for example, to about 7 to 12 mol%, specifically about 9 to 11 mol%, but this may be understood as an exemplary meaning.

Thus, the gas mixture 239 and cooled as it passes through the heat exchanger 205 is transferred to a first membrane module (206) comprising a membrane having selective permeability to carbon dioxide CO ₂ - lean (CO ₂ -depleted) the rich (CO ₂ -enriched) a first transmission form (isolate) the (permeate) flow - a first holding (retentate) flow and CO _2.

In this regard, the separation method of the separation membrane used in the separation membrane module 206 is, for example, counter-current, co-current, cross-flow, or sweep-flow. It can be a way. In the case of the sweep-flow method, a method of using a portion of the gas flow that has passed or did not pass through the separation membrane module as a sweep gas may be exemplified, and as another example, air or other gas supplied from the outside (e.g., nitrogen gas ) Using a sweep method (eg, air-sweep using air) can be applied. In addition, the separator module may be a hollow fiber, a plate-and-frame, a spiral wound, a tubular, or the like.

)은 유지하면서, 가스 선택도(selectivity), 즉 CO₂/N₂ 선택도(

)가 상승하는 특성을 나타내는 종류를 사용하는 것이 유리할 수 있다. In one embodiment, the permeation of gas, that is, carbon dioxide using the membrane module 206 is generally accomplished through a dissolution-diffusion mechanism. In this regard, the permeance of the membrane may mean a value obtained by dividing the permeability by the thickness of the membrane, and is intended to indicate the permeability characteristic of such a separator, and its unit is expressed as a gas permeation unit (GPU). . The separation membrane that can be used in the above embodiments is specifically, CO ₂ permeability at low temperature (

) While maintaining the gas selectivity, i.e. CO ₂ /N ₂ selectivity (

It may be advantageous to use a kind where) exhibits an ascending characteristic.

In order to recover carbon dioxide in the gas mixture, the material of the separation membrane is an organic (for example, polymer) separator, an inorganic (for example, alumina, titania, silicon carbide, zirconia, zeolite, etc.) separator known in the art. Can be used.

According to an exemplary embodiment, MEDAL ^TM (polyimide-based membrane) developed and commercialized by Air Liquide can be applied, and the separator maintains carbon dioxide permeability at low temperatures (around -40 to -30°C). In, CO ₂ /N ₂ It is known to have the property of increasing selectivity. In addition, a separator made of a polyimide-based or polysulfone-based polymer material developed by Airrane may also be used. In the case of such a separator, a carbon dioxide permeability value may be 900 GPU, and a CO ₂ /N ₂ selectivity may be 35 or more. Another polyimide material, Matrimid ^?? , Ultem ^?? , P84 ^?? , Separators such as BPDA-ppODA, and TM-NPSF and HF-NPSF made of polysulfone-based materials can also be applied.

Further, in the case of a zeolite-based separation membrane, CHA type zeolite, MFI type zeolite, or the like can be used. In addition, various separator materials can be applied, such as a composite separator using organic/inorganic materials.

In consideration of the above, according to an exemplary embodiment, the permeability of the separator, in particular the polymer separator, is, for example, of at least about 100 GPUs (specifically about 500 to 5000 GPUs, more specifically about 2000 to 4000 GPUs). _{Transmittance, and a CO 2} /N ₂ selectivity (based on room temperature) of at least about 15 (specifically about 30 to 250, more specifically about 35 to 120) can be used. In addition, the pressure ratio in the separation membrane may be, for example, in the range of about 2 to 30, specifically about 4 to 15, and more specifically about 5 to 10.

According to the illustrated embodiment, some 242 of the gas (first retention flow) that has not passed through the separation membrane may be injected into the permeable portion of the separation membrane, and may be configured to further improve separation efficiency. The remainder 240 of the first holding stream passes through the expander 208, recovers some of the electricity therefrom, and contributes to cooling in the heat exchanger 205 before being discharged into the flue.

Specifically, the gas not permeated by the first separation membrane module 206, that is, the CO ₂ -lean first retained flow may be discharged from the first separation membrane module 206 and pass through the expander 208 to reduce pressure. At this time, the pressure of the first holding flow passing through the expander 208 may range from, for example, about 1 to 2 bara, specifically about 1.05 to 1.5 bara, and more specifically about 1.1 to 1.2 bara. In this way, the expanded holding stream is transferred to the heat exchanger 205 and used to lower the temperature of other gas streams requiring cooling to be heated (for example, about 10 to 40°C, specifically about 20 to 30°C). Can be discharged as. Thereafter, the heated gas flow 241 may be discharged to the outside through the flue.

According to the illustrated embodiment, some of the CO ₂ -lean first retention flows 242 that have not passed through the separation membrane are divided by the splitter 207, of which the main flow 240 is an expander ( 208) and heat exchanger 205 in that order. On the other hand, some of the flows 242 divided from the splitter 207 flow back into the separation membrane module 206, specifically, to the permeable portion of the separation membrane, and are used as a sweep gas. At this time, when the carbon dioxide concentration in the first permeate flow is maintained substantially the same, the area of the separation membrane required for separation is reduced to, for example, about 20 to 50%, specifically about 30 to 40%. CO ₂ is recycled toward the permeate side of the split and a first membrane module (206) as described above - by combining a part 242 of the first holding lean stream to the first permeate stream can improve the separation efficiency. That is, since nitrogen is contained in the sweep gas to reduce the carbon dioxide concentration in the first permeate stream, the difference in partial pressure of carbon dioxide across the separation membrane increases, and as a result, carbon dioxide can more rapidly penetrate the separation membrane. Therefore, it is possible to reduce the area of the separation membrane required for separation.

According to an exemplary embodiment, the volume ratio between the two flows divided by the splitter 207, i.e., the volume ratio of the flow 240 in the direction of the expander to the recycled flow 242 is, for example, about 10 to 30 , Specifically about 15 to 25, more specifically about 17 to 22 may be in the range.

In the illustrated embodiment, it is further noted that, as described above, the amount (volume) of the gas mixture to be treated in the first separation membrane module can be reduced to a significant level by recirculation of a part of the exhaust gas 235, which is the total separation. It is that process efficiency can be improved. Illustratively, when recirculation is involved, the amount (molar basis) of the gas mixture introduced into the separation membrane module is, for example, about 10 to 50%, specifically about 30 to 40%, as compared to the case where it is not recycled. Specifically, it may be about 33 to 37% lower.

Meanwhile, the pressure ratio required to implement the separation membrane process may be provided by compressing the gas mixture flowing into the first separation membrane module 206 or applying a vacuum to the permeate flow. For example, as shown in FIG. 2, by disposing the vacuum pump 209 in the direction of the transmission surface of the first separation membrane module 206 (that is, disposing the vacuum pump on the downstream side of the first permeate flow), separation It is possible to form the required pressure ratio. Accordingly, in order to secure or increase the pressure ratio required for separation, a larger compressor may be used for the supplied gas mixture, or a larger vacuum pump may be disposed on the permeate side.

According to the illustrated embodiment, the first permeate flow discharged from the first separation membrane module 206 is, for example, about 20 to 70 mol%, specifically about 35 to 55 mol%, and more specifically about 45 to 50 mol%. It can represent the concentration of carbon dioxide in %. Thereafter, the first permeate flow is transferred by the vacuum pump 209, at this time, the pressure of the gas mixture flowing into the first separation membrane module 206 and cooled by heat exchange is not high, thereby forming a pressure ratio in the separation membrane. In order to do so, it may be configured to suck at a reduced pressure of about 0.1 to 0.5 bara, more specifically about 0.15 to 0.3 bara, and more specifically about 0.2 to 0.25 bara.

Referring to FIG. 2, since the first permeate stream 243 is transferred to the compressor 210, a pressurized state may be required to liquefy carbon dioxide in a subsequent process. At this time, the flow 243 may be pressurized by a single compression method or a multi-stage compression method in the compressor 210, for example, about 20 to 50 bara, specifically about 25 to 45 bara, more specifically about 30 to 40 It can be pressurized to pressures in the bara range. Illustratively, in the case of pressurization in a multi-stage compression method, by intermediate cooling using cooling water in the process, for example, about 50°C or less, specifically about 10 to 40°C, and more specifically about 25 to 35°C. Can be.

In this way, the pressurized first permeate stream 244 passes through the heat exchanger 211, and may be pre-cooled by heat exchange with a low-temperature mixed gas that has not been liquefied in the distillation column 212 to be described later. As it passes through the heat exchanger 205 to a lower temperature, that is, a temperature suitable for gas/liquid separation of carbon dioxide in the distillation column 212 at the downstream, for example, about -35°C or less, specifically about -70 to -40°C , More specifically, it may be cooled to about -60 to -50°C. In this case, the pressure in the gas flow before and after passing through the heat exchanger 211 may be substantially the same.

In the illustrated embodiment, the gas stream 245 cooled through heat exchange is transferred to the distillation column 212, and CO ₂ gas/liquid separation in the stream may be performed. In this case, the distillation column 212 may include, for example, about 2 to 20 trays, specifically about 7 to 13, particularly about 10 or more trays based on the number of stages in consideration of the desired separation efficiency. In addition, the temperature and pressure of the top of the distillation column 212 are, for example, about -65 to -30 °C (specifically about -55 to -45 °C) and about 10 to 40 bara (specifically about 20 to 30 bara). And, the temperature and pressure at the bottom of the distillation column 212 are, for example, in the range of about -15 to 0 °C (specifically about -10 to -5 °C) and about 10 to 40 bara (specifically about 20 to 30 bara). Can be set to However, the operating conditions of the distillation column 212 should be understood in an exemplary sense, and may be changed in consideration of desired separation efficiency.

According to an exemplary embodiment, the carbon dioxide concentration (molar basis) in the bottom stream 246 of the distillation column 212 may be, for example, at least about 99%, specifically at least about 99.5%, and more specifically at least about 99.9%. have. On the other hand, the gaseous carbon dioxide mixed gas is discharged to the top stream 248 of the distillation column 212, at this time, the carbon dioxide concentration can be variously changed according to the temperature, pressure, flow rate, etc. of the gaseous stream 248 discharged from the top of the distillation column. have. As an example. The carbon dioxide concentration (molar basis) in the top stream 248 may be in the range of, for example, about 5 to 70%, specifically about 10 to 40%, and more specifically about 20 to 30%, but it should be understood to be illustrative. do.

The temperature and pressure of the high-concentration carbon dioxide bottom stream 246 discharged from the bottom of the distillation column 212 to the liquid phase through gas/liquid separation are, for example, about -15 to 0 °C (specifically, about -10 to -5 °C ) And about 10 to 40 bara (specifically, about 20 to 30 bara), and the liquid carbon dioxide may be transferred to the pump 213 to be pressurized (compressed) to a pressure that is easy for transportation and storage. At this time, the pressure of the pressurized high-concentration carbon dioxide bottom stream 247 may be, for example, about 120 to 200 bara, specifically about 150 to 180 bara, but this should be understood as an exemplary meaning.

Meanwhile, a mixed gas 248 having a low temperature and a relatively high pressure is discharged from the upper end of the distillation column 212, and the temperature and pressure thereof are, for example, about -65 to -30°C (specifically, about -55 to- 45° C.) and about 20 to 60 bara (specifically, about 25 to 35 bara). Thereafter, the low-temperature mixed gas 248 passes through the heat exchanger 211 to cool the flow 244 and then is transferred to the expander 214 in the heated flow 249 to recover some electricity therefrom. It is introduced into the exchanger 205 and can be used to lower the temperature of another gas stream by heat exchange. As described above, the mixed gas passing through the heat exchanger 205 is reduced to the pressure required for the first separation membrane module 206 as it passes through the expander 215, and is transferred to the first separation membrane module 206 by operating the valve 216. It may be combined (mixed) with the incoming gas mixture 239.

In the illustrated embodiment, it is notable to generate cooling heat according to the regasification of liquefied natural gas (LNG), and it is connected (integrated) to the heat exchanger 205 to provide a cooling effect on the flows flowing into the heat exchanger. I can provide.

Referring to FIG. 2, the liquefied natural gas 252 is provided in a low temperature state for maintaining the liquid phase, for example, about -160°C or less, specifically -200 to -150°C, more specifically about -180 to It may be -160°C, particularly, about -163°C (based on atmospheric pressure). The introduced liquefied natural gas 252 forms a pressurized flow 253 by the operation of the pump 217, wherein the pressure of the pressurized liquefied natural gas is, for example, about 15 to 100 bara, specifically about It can be controlled by the pump 217 within the range of 20 to 80 bara, more specifically about 25 to 75 bara.

As the low-temperature pressurized liquefied natural gas passes through the heat exchanger 205, the temperature of the natural gas 254 passes through the heat exchanger is changed to a gas phase by increasing its temperature while providing cooling heat to another flow. For example, it may be about 10 to 40°C, specifically about 15 to 30°C, more specifically about 20 to 25°C, particularly room temperature. In addition, the natural gas 254 may represent a state controlled by the pump 217 in consideration of its use (eg, for fuel in a combustion process or for pipe distribution). For example, for combustion fuel use, the pressure is about 20 to 40 bara (more specifically, about 25 to 30 bara), and for pipe distribution, the pressure is about 50 to 80 bara (more specifically, about 60 to 75 bara). Can be.

As described above, the cooling heat generated in the regasification process of the liquefied natural gas acts to cool other flows in the heat exchanger 205 and is combined with the above-described exhaust gas recirculation mode to produce carbon dioxide from a low concentration of carbon dioxide-containing flue gas or gas mixture. It may contribute to reducing the amount of energy (specifically, electrical energy) input to the low-temperature separation membrane process for separating and capturing. In particular, natural gas converted from liquid to gaseous by regasification can be transferred to the gas turbine 201 as fuel 231 of a natural gas combined cycle power plant. It is noteworthy that the cooling heat generated in the process of regasification of liquid natural gas, which inevitably accompanies the operation of the process, can be used for higher value-added purposes.

3 shows another example of a process based on a multistage membrane module for separating carbon dioxide in a gas mixture in which cooling heat by regasification of liquefied natural gas and recirculation of exhaust gas are combined.

In this regard, reference numerals 301 to 319 of the main units constituting the process shown in FIG. 3 correspond to the reference numbers 201 to 219 of the process shown in FIG. 2. Reference numerals and details thereof that are not mentioned in addition to the above can be understood with reference to FIG. 2, and thus, overlapping descriptions will be omitted.

In the illustrated embodiment, a second separation membrane module 322 is additionally introduced into the process according to FIG. 2, and the first separation membrane module 306 is based on the CO ₂ -rich first permeate flow discharged from the first separation membrane module 306. ) And the second separation membrane module 322 are connected (series connected) two-stage separation membrane process is applied. In this regard, the basic process configuration and operation method are similar to those in FIG. 2, but the concentration of carbon dioxide in the gas mixture is additionally introduced by introducing the first permeate flow separated by the first separation membrane module 306 to the second separation membrane module 322. By increasing, the amount of liquid carbon dioxide generated in the distillation column 312 can be increased, and as a result, electrical energy required for the entire process can be reduced.

However, the heat exchanger 321, which is an added unit in the illustrated embodiment, may be arranged in the form of an independent unit, but may alternatively be equivalent to the heat exchanger 305, so that the first permeate flow is used as the second unit. In order to lower the temperature suitable for the low-temperature separation membrane process in the separation membrane module 322, cooling heat generated during the regasification process of the liquefied natural gas may be used. In this case, the gas mixture (ie, the first permeate flow) introduced into the second separation membrane module 322 is, for example, about -20°C or less, specifically about -50 to -20°C, more specifically about -40. It may be a carbon dioxide-concentrated exhaust gas (gas mixture) of -30 °C. According to the addition of the second separator module 322, a compressor 320, a splitter 323, an expander 324, a vacuum pump 325, and the like may be additionally disposed.

In this regard, the pressure of the flow 343 pressurized by the compressor 320 and cooled by heat exchange is, for example, about 2 to 3 bara, specifically about 2.1 to 2.5 bara, more specifically about 2.2 to 2.4. bara range, for example, about 0.2 to 0.7 bara, specifically about 0.3 to 0.6 bara higher pressure level than the exhaust gas or gas mixture 337 pressurized by the compressor 303 depending on the process design. I can. In addition, the vacuum pump 309 and the vacuum pump 325 may be configured to suck at substantially the same reduced pressure with each other (for example, about 0.1 to 0.5 bara).

By introducing the separation process by the two-stage separation membrane module as described above, compared to the one-stage separation membrane module-based process shown in FIG. 2, for example, about 10 to 30%, specifically about 15 to 25% of the required electricity Energy saving effect can be achieved.

According to the illustrated embodiment, the first permeate flow formed in the first separation membrane module 306 is transferred to the second separation membrane module 322 through the compressor 320, and CO ₂ -lean in the second separation membrane module 322 A second retention stream and a CO ₂ -rich second permeate stream are formed. Separation conditions in the first separation membrane module 306 may be the same as described with respect to FIG. 2, and in some cases, at least one of the separation conditions may be changed.

According to an exemplary embodiment, the carbon dioxide concentration in the first permeate stream may range from, for example, about 20 to 55 mole%, specifically about 30 to 45 mole%, more specifically about 35 to 40 mole%, and also The concentration of carbon dioxide in the second permeate stream may be, for example, in the range of about 50 to 90 mol%, specifically about 70 to 85 mol%, and more specifically about 75 to 80 mol%.

According to an exemplary embodiment, the material of the separation membrane or membrane usable in the second separation membrane module 322 may be the same as or different from that of the first separation membrane module 306. The permeability of the separator is, for example, a permeability of at least about 100 GPUs (specifically about 500 to 5000 GPUs, more specifically about 2000 to 4000 GPUs), and at least about 15 (specifically about 30 to 250, more specifically about 35 to 120) CO ₂ /N ₂ selectivity (at room temperature) can be expressed. In this regard, the pressure ratio in the separation membrane of the second separation membrane module 322 may be appropriately selected within the range described with respect to the first separation membrane module 306, but is not necessarily the same.

According to an exemplary embodiment, as described in FIG. 2, a gas flow that is not permeated in the first separation membrane module 306, that is, a part 342 of the first retention flow is recycled to be used as a sweep gas, and the main part It is also possible to operate in a manner in which the 340 is transferred to the expander 308, but in some cases, at least a portion of the first retained gas flow (for example, about 5 to 60% by volume, specifically about about 5 to 60% by volume) to increase the recovery rate of _{CO 2} 20 to 30% by volume) may be connected to supply to the second separation membrane module 322 (not shown).

Referring to FIG. 3, a part of the second retention flow in the second separation membrane module 322 may be recycled as a sweep gas and supplied to the permeable surface of the separation membrane. However, when the effect of the recycling of the sweep gas is insignificant during process design, it may be omitted.

In addition, in the illustrated example, of the two flows formed by dividing the first holding flow by the splitter 307, the flow 340 that is not recycled and the second holding flow of the second separation membrane module 322 are divided and formed. The flow 344 that is not recycled in the flow may be introduced into the heat exchanger 305 after being expanded through the expanders 308 and 324, respectively, and then may be heated while passing through the heat exchanger 305. As a result, the two heated holding streams 341 and 345 can each be conveyed to the flue. Alternatively, expanders 308 and 324 may be incorporated to expand the two retaining streams together and then introduce them to the heat exchanger 305.

In addition, although a process including the two-stage separation membrane modules 306 and 322 is illustrated in FIG. 3, the separation membrane may be implemented in a multi-stage method of three or more stages (not shown). Even in this case, as long as the performance of the separation membrane process can be improved, the splitter can be connected to all separation membrane modules.For example, in the case of a three-stage separation membrane module, a separate splitter at the rear end of each separation membrane module, specifically provided. One splitter, a second splitter, and a third splitter may be provided, respectively.

Meanwhile, as described above, both the first separation membrane module 306 and the second separation membrane module 322 may be operated at a low temperature, but in an alternative embodiment, only one of the separation membrane modules may be configured to be operated at a low temperature. have. Furthermore, this operation method can be applied equally to the case of implementing the separation membrane module in a multi-stage method of three or four stages or more. In this regard, depending on the performance characteristics of the separation membrane (e.g., CO ₂ permeability vs. CO ₂ /N ₂ selectivity), the permeability or selectivity is determined by the multi-stage separation membrane process, each separation membrane module Different processes can be configured. In addition, even in a low-temperature separation membrane process, it is not necessary to operate a specific separation membrane module at a low temperature in order to improve selectivity. For example, in a two-stage separator module-based process, the first separator module 306 operates at a low temperature, while the second separator module 322 can operate at room temperature, and vice versa. In addition, if the selectivity data of the separation membrane for each temperature is secured, a separation membrane process configured with a partially suitable temperature may be configured. In addition, gas that has not passed through the separation membrane may be discharged directly into the atmosphere.

Through such a flexible process operation, it is possible to increase the concentration of carbon dioxide in the exhaust gas, and in some cases, when the flow rate of the flow decreases, energy required for cooling can be reduced.

FIG. 4 shows an example of a single separation membrane module-based process for separating carbon dioxide in a gas mixture in which cooling heat provided by regasification of liquefied natural gas, exhaust gas recirculation, and selective exhaust gas recirculation using a downstream membrane module are combined. .

In the drawing, the reference numbers 401 to 417 of the main units constituting the process correspond to the reference numbers 201 to 217 of the process shown in FIG. 2, and each of the splitter 419 and the mixer or mixer 420 is shown in FIG. In 2, it corresponds to member numbers 218 and 219. In the case where it is clear that a point corresponding to FIG. 2 is clear, a description of a member number not mentioned other than that is omitted in order to avoid redundancy.

_{In the case of the illustrated process, CO 2} discharged from the first separation membrane module 406 with the step of recirculating a part of the exhaust gas by the splitter 419 similar to the embodiment shown in FIG. 2 -lean first retention flow As a reference, a downstream separation membrane module 418 is additionally disposed (connected) to recirculate the permeate flow generated therefrom to the gas turbine 401.

According to the illustrated embodiment, the first retention flow is divided by the splitter 407 and the main portion 440 that is not recycled in the direction of the transmission surface of the first separation membrane module 406 is different from the embodiment shown in FIG. It is introduced into the downstream membrane module 418. At this time, the first retention flow 440 introduced into the rear separation membrane module 418 is the retention flow of the rear separation membrane module having a lower carbon dioxide concentration than the first retention flow through the separation process by the separation membrane, and the retention flow of the rear separation membrane module. It forms a permeate flow of the downstream membrane module having a higher carbon dioxide concentration.

In the case of the first retention flow 440 flowing into the rear separation membrane module 418, the bar still contains carbon dioxide that has not been permeated by the first separation membrane module 406, and its concentration is, for example, about 1 to 20 moles. %, specifically about 4 to 8 mol%, more specifically about 5 to 7 mol%.

According to the illustrated embodiment, the permeate flow generated by the rear separation membrane module 418 formed as described above is diluted by the oxygen-containing gas introduced to the permeate side, specifically air 444, and the rear separation membrane module ( It can be discharged from 418 and recycled to stream 445.

At this time, the oxygen-containing gas 444 functions as a sweep gas, and since the concentration of carbon dioxide is very low, the permeation flow of the subsequent separation membrane module 418 is increased by increasing the driving force generated by the partial pressure of carbon dioxide between the holding surface and the transmission surface of the membrane. It can contribute to increasing the concentration of carbon dioxide in mine. This oxygen-containing gas 444 may be mixed with the permeate flow of the downstream membrane module 418 and recycled, thereby forming an oxygen source or a part thereof of the combustion process in the gas turbine 401. However, since the oxygen-containing gas 432 can be introduced even in the exhaust gas recirculation mode, the oxygen-containing gas 444 may be omitted in some cases.

According to an exemplary embodiment, the concentration of carbon dioxide in the diluted permeate stream 445 is, for example, in the range of about 1 to 9 mol%, specifically about 2 to 7 mol%, more specifically about 4 to 6 mol%. Can be set in. On the other hand, the concentration of carbon dioxide in the holding flow of the rear separation membrane module 418 may be, for example, about 0.3 to 0.9 mol%, specifically about 0.5 to 0.8 mol%, more specifically about 0.6 to 0.7 mol%, It is not limited thereto.

In this embodiment, the case of recycling some of the permeate flows of the downstream membrane module is not excluded, but it is advantageous to recycle all of them in order to improve the efficiency of the entire separation process.

The permeate stream 445 of the downstream membrane module mixed (diluted) with the oxygen-containing gas is a portion 435 of the exhaust gas (carbon dioxide-containing gas mixture) and the oxygen-containing gas 432 in the mixer or mixer 420. It is introduced into the gas turbine 401 along the flow 458 in a combined or mixed state. Alternatively, when the amount of oxygen in the diluted permeate stream 445 is present in an amount sufficient for the combustion reaction in the gas turbine, the oxygen-containing gas 432 may be omitted. At this time, the total amount of the oxygen-containing gases 432 and 444 is not particularly limited as long as it can contain a sufficient amount of oxygen to burn the fuel 431 in the gas turbine 401, and the ratio of oxygen to the fuel Is as described above.

In the illustrated embodiment, the flow 437 pressurized by the compressor 403 may be in a state of lower pressure compared to the process shown in FIG. 2, for example, about 1 to 1.5 bara, more specifically about 1.1 to 1.45 bara, more specifically it may be determined within the range of about 1.2 to 1.4 bara. This means that since the compressor 403 can operate at a lower pressure compared to the specific example shown in FIG. 2, the input energy for achieving the pressure required for carbon dioxide separation in the first separation membrane module can be reduced.

In addition, the pressure of the flow 440 divided from the holding flow of the first separation membrane module 406, that is, the pressure of the first holding flow introduced to the subsequent separation membrane module 418, is exhaust gas or gas introduced into the first separation membrane module 406. Compared to the pressure of the mixture 439, it may be, for example, about 0.05 to 0.3 bara, specifically about 0.08 to 0.2 bara, and more specifically about 0.1 to 0.15 bara. This is due to a pressure drop occurring during the operation of the separator. For example, when the pressure of the flow 439 is about 1.3 bara, the pressure of the flow 440 may be set to about 1.2 bara.

In the case of the embodiment shown in FIG. 4, the separation and capture efficiency of a gas mixture containing a low concentration of carbon dioxide, such as the combustion exhaust gas of natural gas, can be further improved by combining recirculation of part of the exhaust gas and recycling of the permeate flow of the downstream separation membrane module. I can.

Specifically, the concentration of carbon dioxide in the exhaust gas when the recycle mode is not involved is, for example, less than about 5 mol% (specifically, less than about 1 to 4.5 mol%, more specifically about 2 to 4.2 mol%), but 2 By introducing the eggplant recycling mode, compared to the case where it is not recycled, for example, about 0.1 to 25 mol%, specifically about 5 to 15 mol%, more specifically about 8 to 10 mol% more increased carbon dioxide concentration may be exhibited. .

As an example, the concentration of carbon dioxide in the flow 433 may range from, for example, about 9.5 to 12 mol%, specifically about 10 to 11.5 mol%, and more specifically about 10.5 to 11 mol%. In this way, the carbon dioxide concentration of the gas mixture 439 introduced into the first separation membrane module 406 is higher than that shown in FIG. 1, and even compared to the specific example shown in FIG. 2 (which involves only exhaust gas recirculation). It can be at a high level (eg, about 2 to 5 mole percent, specifically about 3 to 4 mole percent higher). Thus, separation of the gas mixture with increased carbon dioxide concentration is performed, which can improve the selective separation efficiency for carbon dioxide.

In addition, it is possible to reduce the throughput (volume) of the gas mixture in the first separation membrane module 406 by the two recycle modes. In comparison, the amount (molar basis) of the gas mixture introduced into the first separation membrane module 406 is, for example, about 10 to 50%, specifically about 30 to 40%, and more specifically about 33 to 37% lower. I can.

As a result, the carbon dioxide concentration of the first permeate stream 446 discharged from the first separation membrane module 406 and transferred through the vacuum pump 409 is, for example, about 20 to 75 mol%, specifically about 40 to 65 mol. %, more specifically, may range from about 50 to 60 mol%, which is a higher level compared to the case where the recirculation mode is not involved (see Fig. 1) or only the exhaust gas recirculation mode is introduced (see Fig. 2), and the subsequent distillation column It is advantageous in separating and capturing carbon dioxide in liquid form during the gas/liquid separation process of (412). On the other hand, in the illustrated embodiment _{, the carbon dioxide concentration of the CO 2} -lean first holding stream 440, 441 is, for example, about 1 to 10 mol%, specifically about 3 to 8 mol%, more specifically about It may range from 5 to 7 mol%.

FIG. 5 shows an example of a process based on a multistage membrane module for separating carbon dioxide in a gas mixture in which cooling heat provided by regasification of liquefied natural gas, exhaust gas recirculation, and selective exhaust gas recirculation using a downstream membrane module are combined. .

In the illustrated embodiment, the second separation membrane module 523 is added to the process shown in FIG. 4, and the first separation membrane module based on the CO ₂ -rich first permeate flow discharged from the first separation membrane module 506 A two-stage separation membrane process in which 506 and the second separation membrane module 523 are connected (series connected) is applied. _{In addition, the CO 2} discharged from the first separation membrane module 506-selective recirculation, that is, the first retention flow 540 discharged from the first separation membrane module through the rear-stage separation membrane module 518 connected to the lean first retention flow. The permeate flow generated by treatment with a separation membrane is recycled to the gas turbine 501.

Each of the member numbers 521 to 526 of the added unit corresponds to the member numbers 320 to 325 in FIG. 3, and each of the splitter 519 and the mixer or mixer 520 is the member numbers 419 and 420 in FIG. 4 Corresponds to. Reference numerals and details thereof that are not mentioned in addition to the above may be understood with reference to FIGS. 3 and 4, and redundant descriptions will be omitted.

In the illustrated embodiment, the flow 537 pressurized by the compressor 503 may exhibit a relatively low pressure state similar to that in the embodiment according to FIG. 4, for example about 1 to 1.5 bara, More specifically, it may be determined within the range of about 1.1 to 1.45 bara, more specifically about 1.2 to 1.4 bara. In particular, since it can be pressurized to a lower pressure level (for example, about 0.05 to 0.2 bara, specifically about 0.08 to 0.12 bara lower pressure) than the case of adopting the one-stage separation membrane process shown in FIG. 4, it is possible to drive the compressor. Accordingly, the amount of energy input can be further reduced. In addition, the carbon dioxide concentration of the exhaust gas or gas mixture flow 539 introduced into the first separation membrane module 506 is, for example, about 4.1 to 30 mol%, specifically about 8 to 15 mol%, more specifically about 10 to It may be in the range of 12 mol%. This is a high level even compared to the case where the exhaust gas recirculation mode and the two-stage separation membrane process are combined (see FIG. 3).

As described in FIG. 4, the pressure of the first retained flow introduced into the subsequent separation membrane module 518 is lower than the pressure of the exhaust gas or gas mixture 539 introduced into the first separation membrane module 506 due to a pressure drop. Can be set to. In addition, the first permeate flow introduced into the second separation membrane module 523 is, by the compressor 521, about 1.4 to 2 bara, specifically about 1.5 to 1.9 bara, and more specifically about 1.6 to 1.8 bara. The bar can be pressurized, which is at a lower level compared to the corresponding pressure (for example, about 2 to 3 bara) in the two-stage separation membrane process shown in FIG. 3. In addition, the concentration of the second permeate stream 550 discharged from the second separation membrane module 523 is, for example, about 50 to 95 mol%, specifically about 75 to 90 mol%, and more specifically about 82 to 86 mol. % Range, which is higher than the carbon dioxide concentration in the second permeate stream, which is comparable in FIG. 3.

In this way, by combining a multi-stage (i.e., two-stage) separation membrane process with two recycle modes (i.e., hybrid recycle mode), compared to the hybrid recycle and one-stage separation membrane module-based process shown in FIG. 4, for example It is possible to achieve the required electrical energy reduction effect of about 10 to 25%, specifically about 15 to 20%.

On the other hand, in the specific example shown in Figs. 2 to 5, the natural gas that is regasified and discharged in a heated state can be directly utilized as a fuel for a natural gas combined cycle power plant, alternatively for pipe distribution. It can also be supplied. In this case, the required pressure of the discharged natural gas may be different depending on the purpose of use.For example, approximately 30 bar is required for natural gas combined cycle power plants, while approximately 70 bar may be required for pipe distribution applications. have. In particular, unlike the external cooling cycle shown in FIG. 1, the liquefied natural gas regasification unit has the advantage of being able to easily adjust the state (pressure) of the natural gas discharged by the operation of a pump.

In consideration of this, a plurality of liquefied natural gas regasification units operated under different pressure conditions in the processes shown in each of FIGS. 2 to 5 may be installed in parallel to adjust the pressure of the pumps connected to each of them. Therefore, it is possible to configure a plurality of natural gases generated after regasification to be applied directly to the desired application (e.g., one of the two natural gas streams discharged from the process is a combined cycle gas turbine, and the other is pipe distribution. Can be).

In another embodiment, the natural gas regasification unit and the external cooling cycle shown in FIG. 1 are arranged in parallel in the process, and the process may be operated even during a period in which the regasification of liquefied natural gas is not sufficiently utilized (for example, , A plurality of natural gas flows using each of the two cooling heat supply units (liquid natural gas regasification unit and external cooling cycle) are discharged, or controlled to suit the desired use by combination cooling by two cooling heat supply units. Natural gas streams (for example, can form a single natural gas stream).

Furthermore, in addition to the above-described cooling heat supply source, various cooling energies may be introduced in combination with the regasification unit of the liquefied natural gas.

The present invention may be more clearly understood by the following examples, and the following examples are for illustrative purposes only and are not intended to limit the scope of the invention.

Examples and Comparative Examples

Based on the combustion exhaust gas discharged from the natural gas combined cycle power plant (555 MW), the composition of the exhaust gas is 4,380 kmol/h, the flow rate of natural gas, which is the fuel injected into the gas turbine, and the composition is methane (CH ₄ ). It consists of 93.1%, ethane (C ₂ H ₆ ) 3.2%, propane (C ₃ H ₈ ) 0.7%, butane (C ₄ H ₁₀ ) 0.4%, carbon dioxide (CO ₂ ) 1%, nitrogen (N ₂ ) 1.6% have. In addition, the initial temperature and pressure of the liquefied natural gas for providing cooling heat in Examples and Comparative Examples (Comparative Examples 2 and 3) were set to -163°C and 1.3 bara, respectively. The amount of air injected into the process is 109,348 kmol/h, and its composition is assumed to consist of _{21% of oxygen (O 2} ) and 79% of nitrogen (N _{2 ).}

Meanwhile, the exhaust gas generated by combustion in a natural gas combined cycle power plant contains 4.0%, 75.9%, and 12.4% _{of carbon dioxide (CO 2} ), nitrogen (N ₂ ), oxygen (O ₂ ), and water (H _{2 O), respectively.} It consists of 7.7%, and its flow rate was ^{assumed to be 113,855 kmol/h (2,552,000 Nm 3} /h), a temperature of 106°C, and a pressure of 1.1 bara.

In addition, it is assumed that the selectivity of the separator (Polaris 2nd generation membrane, Membrane Technology and Research, MTR) is improved by 2 times under low temperature operation conditions. At room temperature, the main gas permeability performance (Permeance) is CO ₂ 2,500 GPU, N ₂ 50 GPU and O ₂ 50 GPU, and in the low temperature region (-45 to -30 ℃) CO ₂ 2,500 GPU, N ₂ 25 GPU and O ₂ 25 It was assumed to be GPU (1 GPU=10 ^-6 cm ³ (STP)/(cm ² ·s·cmHg). The gas selectivity of the membrane material can be expressed as two performance ratios, typically CO ₂ /N ₂ ) The degree is 50 at room temperature, and it is assumed to be 100 at low temperature.

Simulations were performed for the processes shown in Figs. 2 to 5 (Examples 1 to 4), and Figs. 1, 6 and 7 (Comparative Examples 1 to 3) based on the above-described exhaust gas. In this regard, in the case of FIG. 6, in the example shown in FIG. 1, instead of cooling heat using an external cooling cycle, cooling heat generated in the regasification process of liquefied natural gas (LNG) is provided, and 7 is a configuration of the first-stage separation membrane process shown in FIG. 6 as a second-stage separation membrane process.

In the case of the simulation programs used in Examples and Comparative Examples, an in-house model using ^{MATLAB ®} was applied for the separation membrane process, and for other devices, computational simulation was performed in conjunction with the ^{Unisim ® program.}

In addition, in Examples and Comparative Examples, the same separator performance was assumed to compare performance under equivalent conditions. In the case of the separator, the CO ₂ permeability was set to 2,500 GPU. In addition, the gas selectivity in the separation membrane module can be expressed as a performance ratio for two types of gases, and the CO ₂ /N ₂ selectivity was set to 100 during low temperature operation. In addition, the efficiency of each of the compressor, expander, vacuum pump, and pump in the process was assumed to be 80%.

Example 1

The operating conditions of the main devices in Example 1 are shown in Table 2 below.

division unit Condition Remark compressor
(203) pressure Entrance bar(a) 1.014 exit bar(a) 2.2 Temperature Entrance 57 exit 50 efficiency % 80 dryer
(204) flux Entrance kmol/h 72,868 exit kmol/h 66,758 Separation Moisture removal in flue gas ppmv 50 ppmv or less Assume 0ppmv heat exchanger
(205) Total heat exchange heat MW 59.7 Number of heat exchange fluids ea 5 LMTD 8.4 Minimum temperature difference between heat exchange fluids 5 Separator
module
(206) Membrane area m ² 841,000 Membrane module Hollow fiber Membrane structure Countercurrent Separation _{CO 2 in the} inlet stream mol% 10.0 _{CO 2 in the} permeate flow mol% 47.2 Splitter
(207) Split ratio Flow (240) 0.95 Flow(242) 0.05 Vacuum pump
(209) pressure Entrance bar(a) 0.2 exit bar(a) 1.1 efficiency % 80 Distillation tower
(212) Temperature Top -50 lower -6 pressure Top bar(a) 29.8 lower bar(a) 29.9 Separation Upper CO ₂ concentration mol% 28.6 Bottom CO ₂ concentration mol% 99.9 CO ₂ 99.9 mol% tray Number of trays ea 10 Criteria for ideal number of stages

Temperature, pressure, flow rate, and composition for each major flow in the process according to Example 1 are shown in Tables 3 to 5 below.

Stream# 234 238 239 241 243 245 247 248 251 Temperature (℃) 57 30 -35 25 30 -50 6 -50 -36 Pressure (Bar) 1.01 2.2 2.2 1.1 1.1 30 153 29.8 2.2 Flow (Nm ³ /s) 698 415 488 390 98 98 26 72 72 Furtherance


CO ₂ 6.3 6.8 10.0 0.7 47.2 47.2 99.9 28.5 28.5 N ₂ 77.1 84.2 81.3 89.7 47.7 47.7 0.0 64.6 64.6 O ₂ 8.2 9.0 8.7 9.6 5.1 5.1 0.1 6.9 6.9 H ₂ O 8.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Stream# 252 254 Temperature (℃) -163 25 Pressure (Bar) 1.3 30 Flow rate (Nm ³ /s) 10.6 10.6 Furtherance





CH ₄ 93.1 93.1 C ₂ H ₆ 3.2 3.2 C ₃ H ₈ 0.7 0.7 C ₄ H ₁₀ 0.4 0.4 CO ₂ 1.0 1.0 N ₂ 1.6 1.6

Stream# 231 232 255 Temperature (℃) 38 15 15 Pressure (Bar) 30 1.03 1.03 Flow rate (Nm ³ /s) 27.3 442 670 Furtherance







CH ₄ 93.1 0 0 C ₂ H ₆ 3.2 0 0 C ₃ H ₈ 0.7 0 0 C ₄ H ₁₀ 0.4 0 0 CO ₂ 1.0 0 2.3 N ₂ 1.6 79 80.3 O ₂ 0 21 16.9 H ₂ O 0 0 1.7

Example 2

The operating conditions of the main devices in Example 2 are shown in Tables 6 and 7 below.

division unit Condition Remark compressor
(303) pressure Entrance bar(a) 1.014 exit bar(a) 2.0 Temperature Entrance 57 exit 50 efficiency % 80 dryer
(304) flux Entrance kmol/h 72,866 exit kmol/h 66,762 Separation Moisture removal in flue gas ppmv 50 ppmv or less Assume 0ppmv heat exchanger
(305) Total heat exchange heat MW 63.6 Number of heat exchange fluids ea 7 LMTD 14.9 Minimum temperature difference between heat exchange fluids 5 First separation membrane
module
(306) Membrane area m ² 891,000 Membrane module Hollow fiber Membrane structure Countercurrent Separation _{CO 2 in the} inlet stream mol% 7.4 _{CO 2 in the} permeate flow mol% 38.0 Splitter
(307) Split ratio Flow (340) 0.95 Flow(342) 0.05 Vacuum pump
(309) pressure Entrance bar(a) 0.2 exit bar(a) 1.1 efficiency % 80 Distillation tower
(312) Temperature Top -50 lower -6 pressure Top bar(a) 29.8 lower bar(a) 29.9 Separation Upper CO ₂ concentration mol% 28.5 Bottom CO ₂ concentration mol% 99.9 CO ₂ 99.9 mol% tray Number of trays ea 10 Criteria for ideal number of stages

division unit Condition Remark compressor
(320) pressure Entrance bar(a) 1.014 exit bar(a) 2.4 Temperature Entrance 57 exit 30 efficiency % 80 2nd separator
module
(322) Membrane area m ² 211,000 Membrane module Hollow fiber Membrane structure Countercurrent Separation _{CO 2 in the} inlet stream mol% 38.0 _{CO 2 in the} permeate flow mol% 78.1 Other Split using the splitter 323 is not applied because the sweep effect is relatively insignificant.

Temperature, pressure, flow rate, and composition for each main flow in the process according to Example 2 are shown in Tables 8 to 10 below.

Stream# 334 338 339 341 343 345 347 349 351 352 355 Temperature (℃) 57 30 -35 25 -35 25 30 -50 6 -50 -36 Pressure (Bar) 1.01 2.0 2.0 1.1 2.4 1.1 1.1 30 153 29.8 2.0 Flow (Nm ³ /s) 698 415 427 350 77 40 37 37 26 11 11 Furtherance


CO ₂ 6.3 6.8 7.4 0.7 38.0 0.9 78.1 78.1 78.1 28.6 28.6 N ₂ 77.1 84.2 83.7 89.7 56.0 89.6 19.8 19.8 19.8 64.7 64.7 O ₂ 8.2 9.0 8.9 9.6 6.0 9.6 2.1 2.1 2.1 6.7 6.7 H ₂ O 8.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Stream# 356 358 Temperature (℃) -163 25 Pressure (Bar) 1.3 30 Flow rate (Nm ³ /s) 42.2 42.2 Furtherance





CH ₄ 93.1 93.1 C ₂ H ₆ 3.2 3.2 C ₃ H ₈ 0.7 0.7 C ₄ H ₁₀ 0.4 0.4 CO ₂ 1.0 1.0 N ₂ 1.6 1.6

Stream# 331 332 359 Temperature (℃) 38 15 15 Pressure (Bar) 30 1.03 1.03 Flow rate (Nm ³ /s) 27.3 442 670 Furtherance







CH ₄ 93.1 0 0 C ₂ H ₆ 3.2 0 0 C ₃ H ₈ 0.7 0 0 C ₄ H ₁₀ 0.4 0 0 CO ₂ 1.0 0 2.3 N ₂ 1.6 79 80.3 O ₂ 0 21 16.9 H ₂ O 0 0 0.6

Example 3

The operating conditions of the main devices in Example 3 are shown in Tables 11 and 12 below.

division unit Condition Remark compressor
(403) pressure Entrance bar(a) 1.014 exit bar(a) 1.3 Temperature Entrance 57 exit 50 efficiency % 80 dryer
(404) flux Entrance kmol/h 75,355 exit kmol/h 69,237 Separation Moisture removal in flue gas ppmv 50 ppmv or less Assume 0ppmv heat exchanger
(405) Total heat exchange heat MW 60.7 Number of heat exchange fluids ea 5 LMTD 13.0 Minimum temperature difference between heat exchange fluids 5 Separator
module
(406) Membrane area m ² 426,000 Membrane module Hollow fiber Membrane structure Countercurrent Separation _{CO 2 in the} inlet stream mol% 13.1 _{CO 2 in the} permeate flow mol% 56.4 Splitter
(407) Split ratio Flow(440) 0.95 Flow(441) 0.05

division unit Condition Remark Vacuum pump
(409) pressure Entrance bar(a) 0.2 exit bar(a) 1.1 efficiency % 80 Distillation tower
(412) Temperature Top -50 lower -6 pressure Top bar(a) 29.8 lower bar(a) 29.9 Separation Upper CO ₂ concentration mol% 28.5 Bottom CO ₂ concentration mol% 99.9 CO ₂ 99.9 mol% Number of trays ea 10 Rear separator
module
(418) Membrane area m ² 808,000 Membrane module Hollow fiber Membrane structure Countercurrent Separation _{CO 2 in the} inlet stream mol% 6.1 _{CO 2 in the} permeate flow mol% 4.8

Temperature, pressure, flow rate, and composition for each major flow in the process according to Example 3 are shown in Tables 13 to 15 below.

Stream# 434 438 439 440 443 446 448 450 451 454 Temperature (℃) 57 30 -35 -35 25 30 -50 6 -50 -37 Pressure (Bar) 1.01 1.3 1.3 1.2 1.1 1.1 30 153 29.8 1.3 Flow (Nm ³ /s) 721 431 471 406 380 66 66 26 40 40 Furtherance


CO ₂ 10.7 11.7 13.1 6.1 0.7 56.4 56.4 99.9 28.5 28.5 N ₂ 73.9 80.5 79.2 85.5 90.0 39.7 39.7 0.0 65.1 65.1 O ₂ 7.2 7.9 7.7 8.4 9.3 3.9 3.9 0.1 6.3 6.3 H ₂ O 8.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Stream# 455 456 457 Temperature (℃) -163 -161 25 Pressure (Bar) 1.3 30 30 Flow rate (Nm ³ /s) 39.1 39.1 39.1 Furtherance





CH ₄ 93.1 93.1 93.1 C ₂ H ₆ 3.2 3.2 3.2 C ₃ H ₈ 0.7 0.7 0.7 C ₄ H ₁₀ 0.4 0.4 0.4 CO ₂ 1.0 1.0 1.0 N ₂ 1.6 1.6 1.6

Stream# 431 444 445 458 Temperature (℃) 38 15 15 15 Pressure (Bar) 30 1.03 1.03 1.03 Flow rate (Nm ³ /s) 27.3 433 458 694 Furtherance







CH ₄ 93.1 0 0 0 C ₂ H ₆ 3.2 0 0 0 C ₃ H ₈ 0.7 0 0 0 C ₄ H ₁₀ 0.4 0 0 0 CO ₂ 1.0 0 4.8 7.1 N ₂ 1.6 79 75.7 76.9 O ₂ 0 21 19.5 15.5 H ₂ O 0 0 0 0.6

Example 4

The operating conditions of the main devices in Example 4 are shown in Tables 16 to 18 below.

division unit Condition Remark compressor
(503) pressure Entrance bar(a) 1.014 exit bar(a) 1.2 Temperature Entrance 57 exit 50 efficiency % 80 dryer
(504) flux Entrance kmol/h 75,962 exit kmol/h 69,840 Separation Moisture removal in flue gas ppmv 50 ppmv or less Assume 0ppmv heat exchanger
(505) Total heat exchange heat MW 63.8 Number of heat exchange fluids ea 7 LMTD 14.0 Minimum temperature difference between heat exchange fluids 5 1st separation membrane module
(506) Membrane area m ² 512,000 Membrane module Hollow fiber Membrane structure Countercurrent Separation _{CO 2 in the} inlet stream mol% 10.8 _{CO 2 in the} permeate flow mol% 49.1

division unit Condition Remark Splitter
(507) Split ratio Flow (540) 0.95 Flow(541) 0.05 Vacuum pump
(509) pressure Entrance bar(a) 0.2 exit bar(a) 1.1 efficiency % 80 Distillation tower
(512) Temperature Top -50 lower -6 pressure Top bar(a) 29.8 lower bar(a) 29.9 Separation Upper CO ₂ concentration mol% 28.5 Bottom CO ₂ concentration mol% 99.9 CO ₂ 99.9 mol% Number of trays ea 10 Rear separator
module
(518) Membrane area m ² 772,000 Membrane module Hollow fiber Membrane structure Countercurrent Separation _{CO 2 in the} inlet stream mol% 5.2 _{CO 2 in the} permeate flow mol% 3.8

division unit Condition Remark compressor
(521) pressure Entrance bar(a) 1.014 exit bar(a) 1.6 Temperature Entrance 57 exit 50 efficiency % 80 2nd separator
module
(523) Membrane area m ² 198,000 Membrane module Hollow fiber Membrane structure Countercurrent Separation _{CO 2 in the} inlet stream mol% 49.1 _{CO 2 in the} permeate flow mol% 84.5 Vacuum pump
(526) pressure Entrance bar(a) 0.2 exit bar(a) 1.1 efficiency % 80 Other Splitting using the splitter 524 is not applied because the sweep effect is relatively insignificant.

Temperature, pressure, flow rate, and composition for each major flow in the process according to Example 4 are shown in Tables 19 to 21 below.

Stream# 534 538 539 540 543 546 548 550 552 554 555 558 Temperature (℃) 57 30 -35 -35 25 -35 25 30 -50 6 -50 -37 Pressure (Bar) 1.01 1.2 1.2 1.1 1.03 1.6 1.1 1.1 30 153 29.8 1.2 Flow (Nm ³ /s) 727 434 442 385 366 57 24 33 33 26 7 7 Furtherance


CO ₂ 9.7 10.5 10.8 5.2 0.07 49.1 0.9 84.5 84.5 99.9 28.7 28.7 N ₂ 74.6 81.2 80.9 86.0 89.7 46.2 89.9 14.1 14.1 0.0 65.0 65.0 O ₂ 7.6 8.3 8.2 8.8 9.6 4.7 9.1 1.4 1.4 0.1 6.3 6.3 H ₂ O 8.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Stream# 559 561 Temperature (℃) -163 25 Pressure (Bar) 1.3 30 Flow rate (Nm ³ /s) 47.4 47.4 Furtherance





CH ₄ 93.1 93.1 C ₂ H ₆ 3.2 3.2 C ₃ H ₈ 0.7 0.7 C ₄ H ₁₀ 0.4 0.4 CO ₂ 1.0 1.0 N ₂ 1.6 1.6

Stream# 531 544 545 562 Temperature (℃) 38 15 15 15 Pressure (Bar) 30 1.03 1.03 1.03 Flow rate (Nm ³ /s) 27.3 442 461 699 Furtherance







CH ₄ 93.1 0 0 0 C ₂ H ₆ 3.2 0 0 0 C ₃ H ₈ 0.7 0 0 0 C ₄ H ₁₀ 0.4 0 0 0 CO ₂ 1.0 0 3.8 6.0 N ₂ 1.6 79 76.4 77.6 O ₂ 0 21 19.8 15.8 H ₂ O 0 0 0 0.6

Comparative Example 1

The operating conditions of the main devices in Comparative Example 1 are shown in Table 22 below.

division unit Condition Remark compressor
(103) pressure Entrance bar(a) 1.014 exit bar(a) 2.3 Temperature Entrance 57 exit 50 efficiency % 80 dryer
(104) flux Entrance kmol/h 113,855 exit kmol/h 105,069 Separation Moisture removal in flue gas ppmv 50 ppmv or less Assume 0ppmv heat exchanger
(105) Total heat exchange heat MW 83.5 Number of heat exchange fluids ea 5 LMTD 12.7 Minimum temperature difference between heat exchange fluids 5 Separator
module
(106) Membrane area m ² 1,395,000 Membrane module Hollow fiber Membrane structure Countercurrent Separation _{CO 2 in the} inlet stream mol% 8.2 _{CO 2 in the} permeate flow mol% 40.7 Splitter
(107) Split ratio Flow(138) 0.95 Flow (140) 0.05 Vacuum pump
(109) pressure Entrance bar(a) 0.2 exit bar(a) 1.1 efficiency % 80 Distillation tower
(112) Temperature Top -50 lower -6 pressure Top bar(a) 29.8 lower bar(a) 29.9 Separation Upper CO ₂ concentration mol% 28.5 Bottom CO ₂ concentration mol% 99.9 CO ₂ 99.9 mol% tray Number of trays ea 10 Criteria for ideal number of stages

Temperature, pressure, flow rate, and composition for each main flow in the process according to Comparative Example 1 are shown in Tables 23 to 25 below.

Stream# 134 136 137 139 141 143 145 146 149 Temperature (℃) 57 30 -35 10 30 -50 6 -50 -37 Pressure (Bar) 1.01 2.3 2.3 1.1 1.1 30.0 153 29.8 2.3 Flow (Nm ³ /s) 709 654 778 628 149 149 26 123 123 Furtherance


CO ₂ 4.0 4.3 8.2 0.5 40.7 40.7 99.9 28.5 28.5 N ₂ 75.9 82.3 79.0 85.6 51.0 51.0 0.0 61.5 61.5 O ₂ 12.3 13.4 12.8 13.9 8.3 8.3 0.1 10.0 10.0 H ₂ O 7.7 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Stream# 150 151 152 Temperature (℃) 25 25 -9 Pressure (Bar) 2.0 6.4 2.0 Flow rate (Nm ³ /s) 46 46 46 Furtherance


C ₂ H ₆ 17.2 17.2 17.2 C ₃ H ₈ 37.6 37.6 37.6 C ₄ H ₁₀ 45.1 45.1 45.1 - - - -

Stream# 131 132 Temperature (℃) 38 15 Pressure (Bar) 30 1.03 Flow rate (Nm ³ /s) 27.3 680 Furtherance






CH ₄ 93.1 0 C ₂ H ₆ 3.2 0 C ₃ H ₈ 0.7 0 C ₄ H ₁₀ 0.4 0 CO ₂ 1.0 0 N ₂ 1.6 79 O ₂ 21

Comparative Example 2

In Comparative Example 2, the operating conditions of the main device were substantially the same as those of Comparative Example 1, except that the method of providing cooling heat through an external cooling cycle was replaced with a method of providing cooling heat by regasification of liquefied natural gas.

Temperature, pressure, flow rate, and composition for each main flow in the process according to Comparative Example 2 are shown in Tables 26 to 28 below.

Stream# 634 636 637 639 641 643 645 646 649 Temperature (℃) 57 30 -35 25 30 -50 6 -50 -37 Pressure (Bar) 1.01 2.3 2.3 1.1 1.1 30.0 153 29.8 2.3 Flow (Nm ³ /s) 709 654 778 628 149 149 26 123 123 Furtherance


CO ₂ 4.0 4.3 8.2 0.5 40.7 40.7 99.9 28.5 28.5 N ₂ 75.9 82.3 79.0 85.6 51.0 51.0 0.0 61.5 61.5 O ₂ 12.3 13.4 12.8 13.9 8.3 8.3 0.1 10.0 10.0 H ₂ O 7.7 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Stream# 650 652 Temperature (℃) -163 25 Pressure (Bar) 1.3 30 Flow rate (Nm ³ /s) 5 5 Furtherance





CH ₄ 93.1 93.1 C ₂ H ₆ 3.2 3.2 C ₃ H ₈ 0.7 0.7 C ₄ H ₁₀ 0.4 0.4 CO ₂ 1.0 1.0 N ₂ 1.6 1.6

Stream# 631 632 Temperature (℃) 38 15 Pressure (Bar) 30 1.03 Flow rate (Nm ³ /s) 27.3 680 Furtherance





CH ₄ 93.1 0 C ₂ H ₆ 3.2 0 C ₃ H ₈ 0.7 0 C ₄ H ₁₀ 0.4 0 CO ₂ 1.0 0 N ₂ 1.6 79 O ₂ 21

Comparative Example 3

The operating conditions of the main devices in Comparative Example 2 are shown in Tables 29 and 30 below.

division unit Condition Remark compressor
(703) pressure Entrance bar(a) 1.014 exit bar(a) 2.3 Temperature Entrance 57 exit 50 efficiency % 80 dryer
(704) flux Entrance kmol/h 113,830 exit kmol/h 105,043 Separation Moisture removal in flue gas ppmv 50 ppmv or less Assume 0ppmv heat exchanger
(705) Total heat exchange heat MW 86.6 Number of heat exchange fluids ea 8 LMTD 29.7 Minimum temperature difference between heat exchange fluids 5 First separation membrane
module
(706) Membrane area m ² 1,132,000 Membrane module Hollow fiber Membrane structure Countercurrent Separation _{CO 2 in the} inlet stream mol% 4.9 _{CO 2 in the} permeate flow mol% 29.3 Splitter
(707) Split ratio Flow(738) 0.95 Flow(740) 0.05 Vacuum pump
(709) pressure Entrance bar(a) 0.2 exit bar(a) 1.1 efficiency % 80 Distillation tower
(712) Temperature Top -50 lower -6 pressure Top bar(a) 29.8 lower bar(a) 29.9 Separation Upper CO ₂ concentration mol% 28.5 Bottom CO ₂ concentration mol% 99.9 CO ₂ 99.9 mol% tray Number of trays ea 10 Criteria for ideal number of stages

division unit Condition Remark compressor
(718) pressure Entrance bar(a) 1.014 exit bar(a) 1.9 Temperature Entrance 57 exit 30 efficiency % 80 2nd separator
module
(720) Membrane area m ² 356,000 Membrane module Hollow fiber Membrane structure Countercurrent Separation _{CO 2 in the} inlet stream mol% 29.3 _{CO 2 in the} permeate flow mol% 72.5 Vacuum pump
(723) pressure Entrance bar(a) 0.2 exit bar(a) 1.1 efficiency % 80 Other Splitting using the splitter 721 is not applied because the sweep effect is relatively insignificant.

Temperature, pressure, flow rate, and composition for each main flow in the process according to Comparative Example 3 are shown in Tables 31 to 33 below.

Stream# 734 736 737 739 741 743 745 747 749 750 753 Temperature (℃) 57 30 -35 25 -35 25 30 -50 6 -50 -37 Pressure (Bar) 1.01 2.3 2.3 1.1 2.0 1.9 1.1 30 153 29.8 2.3 Flow (Nm ³ /s) 709 654 670 566 104 63 42 42 26 16 16 Furtherance


CO ₂ 4.0 4.3 4.9 0.4 29.3 0.7 72.5 72.5 99.9 28.6 28.6 N ₂ 75.9 82.3 81.8 85.7 60.8 85.4 23.7 23.7 0 61.6 61.6 O ₂ 12.3 13.4 13.3 13.9 9.9 13.9 3.8 3.8 0.1 9.8 9.8 H ₂ O 7.7 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Stream# 754 756 Temperature (℃) -163 25 Pressure (Bar) 1.3 30 Flow rate (Nm ³ /s) 29 29 Furtherance





CH ₄ 93.1 93.1 C ₂ H ₆ 3.2 3.2 C ₃ H ₈ 0.7 0.7 C ₄ H ₁₀ 0.4 0.4 CO ₂ 1.0 1.0 N ₂ 1.6 1.6

Stream# 731 732 Temperature (℃) 38 15 Pressure (Bar) 30 1.03 Flow rate (Nm ³ /s) 27.3 680 Furtherance






CH ₄ 93.1 0 C ₂ H ₆ 3.2 0 C ₃ H ₈ 0.7 0 C ₄ H ₁₀ 0.4 0 CO ₂ 1.0 0 N ₂ 1.6 79 O ₂ 21

Examples 1 to 4, and Comparative Examples 1 to 3 The results of calculating the area of electricity and the separator used in the processes according to each are shown in Table 34 below.

Comparative Example 1 Comparative Example 2 Comparative Example 3 Example 1 Example 2 Example 3 Example 4 Electricity [MW] 183 173.7 134 109.9 87.4 64.2 54.8 Total Membrane [Millon m ² ] 1.40 1.40 1.49 0.84 1.1 1.23 1.49 Cooling
system External cooling cycle LNG regasification

In general, since the membrane-based process operates with a pressure based on the membrane module as a driving force, it is an important consideration to minimize the electrical energy of devices for controlling the pressure of the gas. In this regard, when compared to the process using the method of providing cooling heat by the external cooling cycle shown in FIG. 1 (Comparative Example 1), the low-temperature process according to Examples 1 to 4 uses a significantly reduced amount of electrical energy. can confirm.

In addition, in the case of providing cooling heat by regasification of liquefied natural gas (Comparative Examples 2 and 3), in the first-stage separation membrane process (Comparative Example 2), the cooling heat due to regasification of the liquefied natural gas is highly added. Except for the point, no significant improvement was drawn in the amount of electric energy and the total area of use of the separator. However, when the multi-stage separation membrane process was introduced as in Comparative Example 3, the basic process configuration and operation method were similar to Comparative Example 2, but the exhaust gas separated from the first separation membrane module was additionally concentrated in the second separation membrane module, and thus the distillation column. As a result of an increase in the amount of carbon dioxide treated as a liquid, the electric energy required for the process is improved by about 23% (134 MW).

On the other hand, in the case of Example 1, a process that does not involve recirculation of the concentration of carbon dioxide in the exhaust gas stream 238 injected into the separation membrane process by recycling some (about 35%) of the exhaust gas discharged from the gas turbine (Comparative Example 2) And 3) from about 4.3% to 6.8%, and the flue gas flow rate was decreased from 105,068 kmol/h to 66,758 kmol/h. In addition, the pressure of the compressor is 2.2 bara, and the pressure of the vacuum pump is 0.2 bara, which is lower than that of the comparative example.

In Example 2, the compressor 303 was operated at 2.0 bara and the compressor 320 was operated at 2.4 bara, while the vacuum pumps 309 and 325 were both operated at 0.2 bara. Compared to the process of, a 20% improvement (87.4 MW) in the amount of required electric energy was obtained.

In the case of Example 3, as a result of introducing a combination of exhaust gas recirculation and selective recirculation using a downstream membrane module, the carbon dioxide concentration of the exhaust gas flow 438 introduced to the separation membrane module was 11.7%, and the flow rate was 69,237 kmol/h. In addition, the pressure of the compressor 403 was 1.3 bara, and the pressure of the exhaust gas injected into the downstream membrane module was 1.2 bara. As described above, the amount of electric energy required for the entire process was 64.2 MW, such as significantly reducing the operating pressure of the compressor compared to the comparative example.

Example 4 is a process in which the second separation membrane module was added in Example 3, and the pressure of the compressor 503 injected into the first separation membrane module was 1.2 bara, and the vacuum pump was operated at 0.2 bara. In addition, the pressure of the exhaust gas (first retention flow) 540 injected into the downstream membrane module 518 was set to 1.1 bara. In addition, the pressure of the compressor 521 connected to the second separation membrane module 523 was set to 1.6 bara, and the vacuum pump 526 was set to 0.2 bara. As a result, the electric energy saving effect of about 15% was achieved (54.8 MW).

As described above, in a specific example according to the present disclosure _{, in order to separate and capture carbon dioxide at a low temperature for a CO 2} -containing gas mixture, specifically, a low-concentration carbon dioxide-containing exhaust gas discharged after combustion, By using the cooling heat according to regasification, it is possible to realize high addition of the regasification cooling heat at low cost, and furthermore, through the exhaust gas recirculation mode or the hybrid recirculation mode (combination of the exhaust gas recirculation mode and the selective recirculation mode using the downstream membrane module) The economics of the entire process can be remarkably improved.

Furthermore, by combining the recycle mode and the multi-stage separation membrane process, the amount of electric energy required for the operation of the entire process can be further reduced by increasing carbon dioxide in the gas introduced into the distillation column. In fact, it is noteworthy that in the case of Example 4 in which the two recycle modes and the multi-stage separation membrane process are combined, the amount of electricity used is reduced by about 70% compared to Comparative Example 1.

All simple modifications to changes of the present invention belong to the scope of the present invention, and the specific scope of protection of the present invention will be made clear by the appended claims.

Claims (19)

As a membrane-based process for separating and capturing carbon dioxide in a gas mixture,
(a2) providing a carbon dioxide-containing gas mixture produced by combustion of a fuel and an oxygen-containing gas in the gas turbine and discharged from the gas turbine;
(b2) separating part of the carbon dioxide-containing gas mixture and recirculating it to the gas turbine, while compressing the remaining unrecirculated;
(c2) cooling the compressed gas mixture by transferring it to a heat exchanger;
(d2) transferring the cooled gas mixture to a first separation membrane module having selective permeability to carbon dioxide to form a CO ₂ -lean first retention stream and a CO ₂ -rich first permeate stream;
(e2) transferring at least a portion of the first retention flow to a downstream separation membrane module to have a retention flow of a rear separation membrane module having a lower carbon dioxide concentration than the first retention flow, and a carbon dioxide concentration higher than the retention flow of the rear separation membrane module Forming a permeate flow of the rear-end separation membrane module;
(f2) recirculating the permeate flow of the downstream membrane module to the gas turbine together with some of the carbon dioxide-containing gas mixture recycled in step (b2);
(g2) compressing the first permeate flow, transferring it to the heat exchanger in a pressurized state, and cooling it by heat exchange;
(h2) transferring the cooled first permeate stream to a distillation column and separating the cooled first permeate stream into a high-purity CO ₂ liquid stream as a bottom stream and a low-purity CO ₂ -containing gaseous mixture as a top stream by gas/liquid separation; And
(i2) recovering the high purity CO ₂ liquid stream;
Including,
Here, the carbon dioxide-containing gas mixture discharged from the gas turbine in step (a2) does not recycle some of the carbon dioxide-containing gas mixture in step (b2) and the permeate flow of the downstream membrane module in step (f2). In this case, it has a carbon dioxide concentration of less than 5 mol%, whereas in the case of recycling a part of the carbon dioxide-containing gas mixture and the permeate flow of the downstream separation membrane module, the carbon dioxide concentration is increased by 0.1 to 25 mol% compared to the case of not being recycled,
At least one of a portion of the recycled carbon dioxide-containing gas mixture and the permeate flow of the recycled downstream separation membrane module is mixed or diluted with an oxygen-containing gas and transferred to a gas turbine, and
A separation membrane-based process configured to supply cooling heat according to regasification of liquefied natural gas (LNG) in order to provide cooling required for the process through heat exchange in the heat exchanger. As a membrane-based process for separating and capturing carbon dioxide in a gas mixture,
(a3) providing a carbon dioxide-containing gas mixture produced by combustion of a fuel and an oxygen-containing gas in the gas turbine and discharged from the gas turbine;
(b3) separating a portion of the carbon dioxide-containing gas mixture and recirculating it to the gas turbine, while compressing the remaining unrecycled;
(c3) cooling the compressed gas mixture by transferring it to a heat exchanger;
(d3) transferring the cooled gas mixture to a first separation membrane module having selective permeability to carbon dioxide to form a CO ₂ -lean first retention stream and a CO ₂ -rich first permeate stream;
(e3) Transferring at least a portion of the first retention flow to a subsequent separation membrane module to have a retention flow of a rear separation membrane module having a lower carbon dioxide concentration than the first retention flow, and a carbon dioxide concentration higher than the retention flow of the rear separation membrane module Forming a permeate flow of the rear-end separation membrane module;
(f3) recirculating the permeate flow of the downstream membrane module to the gas turbine together with a portion of the carbon dioxide-containing gas mixture recycled in step (b3);
(g3) compressing the first permeate stream and transferring it to a second separation membrane module in a pressurized state to form a CO ₂ -lean second retention stream and a CO ₂ -rich second permeate stream;
(h3) compressing the second permeate flow, transferring it to the heat exchanger in a pressurized state, and cooling it by heat exchange;
(i3) transferring the cooled second permeate stream to a distillation column and separating the cooled second permeate stream into a high-purity CO ₂ liquid stream as a bottom stream and a low-purity CO ₂ -containing gaseous mixture as a top stream by gas/liquid separation; And
(j3) recovering the high purity CO ₂ liquid stream;
Including,
Here, the carbon dioxide-containing gas mixture discharged from the gas turbine in step (a3) does not recycle some of the carbon dioxide-containing gas mixture in step (b3) and the permeate flow of the downstream membrane module in step (f3). In this case, it has a carbon dioxide concentration of less than 5 mol%, whereas in the case of recycling a part of the carbon dioxide-containing gas mixture and the permeate flow of the downstream separation membrane module, the carbon dioxide concentration is increased by 0.1 to 25 mol% compared to the case of not being recycled,
At least one of a portion of the recycled carbon dioxide-containing gas mixture and the permeate flow of the recycled downstream separation membrane module is mixed or diluted with an oxygen-containing gas and transferred to a gas turbine, and
A separation membrane-based process configured to supply cooling heat according to regasification of liquefied natural gas (LNG) in order to provide cooling required for the process through heat exchange in the heat exchanger. The process according to claim 1 or 2, wherein the carbon dioxide concentration in the carbon dioxide-containing gas mixture discharged from the gas turbine is in the range of 9.5 to 12 mol%. The method of claim 1, wherein the CO ₂ -rich carbon dioxide concentration in the first permeate stream formed in step (d2) is 20 to 75 mol%, and the CO ₂ -carbon dioxide concentration in the lean first retention stream is 1 to 10 mol%. Process characterized in that. The process according to claim 1 or 2, wherein the remainder of the carbon dioxide-containing gas mixture that is not recycled is compressed to a pressure of 1 to 1.5 bara. Process according to claim 1 or 2, characterized in that the volume ratio of the gas mixture recycled to the gas turbine/gas mixture not recycled is in the range of 0.2-1. The method of claim 1 or 2, wherein the liquefied natural gas is supplied at a temperature of -160°C or less (based on normal pressure), and the natural gas converted to gaseous phase by regasification thereof is at a temperature of 10 to 40°C and 15 to Process characterized by a pressure range of 100 bara. The process according to claim 2, wherein the CO ₂ -rich second permeate stream formed in step (g3) has a carbon dioxide concentration of 50 to 95 mol%. The method of claim 1 or 2, wherein a pressure ratio between the holding surface and the transmission surface of the separation membrane required for separation is formed by a vacuum pump disposed on the downstream side of the first separation membrane module,
At this time, the process characterized in that the vacuum pump is configured to suck at a reduced pressure of 0.1 to 0.5 bara. 8. The process according to claim 7, wherein natural gas converted to gaseous phase by regasification is provided as fuel introduced into the gas turbine. The process according to claim 1, wherein the retained flow of the downstream membrane module is transferred to the heat exchanger in a reduced pressure state by an expander and discharged after being heated by heat exchange. The process according to claim 2, wherein the holding flow and the second holding flow of the rear-stage separation membrane module are each or together transferred to the heat exchanger in a reduced pressure state by expansion and heated up, and then discharged. delete delete delete delete delete delete delete

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